S-4
Table of Contents

As filed with the Securities and Exchange Commission on March 5, 2021

Registration No. 333-          

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM S-4

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

ENERGY TRANSFER LP

(Exact Name of Registrant as Specified in Its Charter)

 

 

 

Delaware   4922   30-0108820
(State of Incorporation)  

(Primary Standard Industrial

Classification Code Number)

  (IRS Employer Identification No.)

 

 

8111 Westchester Drive, Suite 600

Dallas, Texas 75225

(214) 981-0700

(Address, including Zip Code, and Telephone Number, including Area Code, of Registrant’s Principal Executive Offices)

 

 

Thomas E. Long

Co-Chief Executive Officer

Energy Transfer LP

8111 Westchester Drive, Suite 600

Dallas, Texas 75225

(214) 981-0700

(Name, Address, including Zip Code, and Telephone Number, including Area Code, of Agent for Service)

 

 

With a copy to:

William N. Finnegan IV

Kevin M. Richardson

Latham & Watkins LLP

811 Main Street, Suite 3700

Houston, Texas 77002

Phone: (713) 546-5400

 

 

Approximate date of commencement of proposed sale of the securities to the public: As soon as practicable after this registration statement is declared effective and upon consummation of the merger described in the enclosed prospectus.

If the securities being registered on this form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, please check the following box.  ☐

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act of 1933, as amended (the “Securities Act”), check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer      Accelerated filer  
Non-accelerated filer      Smaller reporting company  
     Emerging growth company  

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities Act.  ☐

If applicable, place an X in the box to designate the appropriate rule provision relied upon in conducting this transaction:

 

Exchange Act Rule 13e-4(i) (Cross-Border Issuer Tender Offer)

    

Exchange Act Rule 14d-1(d) (Cross-Border Third-Party Tender Offer)

    


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CALCULATION OF REGISTRATION FEE

 

 

Title of Each Class of

Securities to Be Registered

 

Amount

to be

Registered

 

Proposed

Maximum

Offering Price

Per Unit

 

Proposed

Maximum
Aggregate

Offering Price(1)

 

Amount of

Registration Fee(3)

6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

  950,000   N/A   $950,000,000   $103,645

6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

  550,000   N/A   $550,000,000   $60,005

7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

  18,000,000   N/A   $450,000,000   $49,095

7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

  17,800,000   N/A   $445,000,000   $48,550

7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

  32,000,000   N/A   $800,000,000   $87,280

6.750% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units

  500,000   N/A   $500,000,000   $54,550

7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units

  1,100,000   N/A   $1,100,000,000   $120,010

 

 

(1)

Represents the maximum number of 6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“ET Series A Preferred Units”), 6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“ET Series B Preferred Units”), 7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“ET Series C Preferred Units”), 7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“ET Series D Preferred Units”), 7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“ET Series E Preferred Units”), 6.750% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units (“ET Series F Preferred Units”) and 7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units (“ET Series G Preferred Units”) representing limited partner interests in Energy Transfer LP, the registrant, issuable upon completion of the merger with Energy Transfer Operating, L.P. described herein.

(2)

Pursuant to Rules 457(c), 457(f)(1) and 457(f)(3) promulgated under the Securities Act and solely for the purpose of calculating the registration fee, the proposed aggregate maximum offering price is (a) with respect to ET Series A Preferred Units, the product of (x) $1,000 (the redemption price of ET Series A Preferred Units) and (y) 950,000 ET Series A Preferred Units, (b) with respect to ET Series B Preferred Units, the product of (x) $1,000 (the redemption price of ET Series B Preferred Units) and (y) 550,000 ET Series B Preferred Units, (c) with respect to ET Series C Preferred Units, the product of (x) $25 (the redemption price of ET Series C Preferred Units) and (y) 18,000,000 ET Series C Preferred Units, (d) with respect to ET Series D Preferred Units, the product of (x) $25 (the redemption price of ET Series D Preferred Units) and (y) 17,800,000 ET Series D Preferred Units, (e) with respect to ET Series E Preferred Units, the product of (x) $25 (the redemption price of ET Series E Preferred Units) and (y) 32,000,000 ET Series E Preferred Units, (f) with respect to ET Series F Preferred Units, the product of (x) $1,000 (the redemption price of ET Series F Preferred Units) and (y) 500,000 ET Series F Preferred Units and (g) with respect to ET Series G Preferred Units, the product of (x) $1,000 (the redemption price of ET Series G Preferred Units) and (y) 1,100,000 ET Series G Preferred Units.

(3)

Calculated by multiplying the proposed maximum aggregate offering price by 0.0001091.

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

 

 

 


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The information in this prospectus may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

 

PRELIMINARY PROSPECTUS—SUBJECT TO COMPLETION—DATED MARCH 5, 2021.

 

 

LOGO

We Are Not Asking You for a Proxy and

You are Requested Not To Send Us a Proxy

On March 5, 2021, Energy Transfer LP, a Delaware limited partnership (“ET”), entered into an Agreement and Plan of Merger (the “Merger Agreement”) with ETO Merger Sub LLC, a Delaware limited liability company and a wholly owned subsidiary of ET (“Merger Sub”), and Energy Transfer Operating, L.P., a Delaware limited partnership and subsidiary of ET (“ETO”), pursuant to which Merger Sub will merge with and into ETO (the “Merger”), with ETO surviving the merger as a wholly owned subsidiary of ET. As a result of the Merger:

 

   

each 6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Unit, liquidation preference $1,000 per unit, representing a limited partner interest in ETO (the “ETO Series A Preferred Units”) issued and outstanding immediately prior to the effective time of the Merger will be converted into the right to receive one newly issued preferred unit representing a limited partner interest in ET designated as a “6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Unit” and having the same preferences, rights, powers and duties as the ETO Series A Preferred Units (other than any non-substantive differences to reflect the issuance of such securities by ET, as opposed to ETO) (the “ET Series A Preferred Units”);

 

   

each 6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Unit, liquidation preference $1,000 per unit, representing a limited partner interest in ETO (the “ETO Series B Preferred Units”) issued and outstanding immediately prior to the effective time of the Merger will be converted into the right to receive one newly issued preferred unit representing a limited partner interest in ET designated as a “6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Unit” and having the same preferences, rights, powers and duties as the ETO Series B Preferred Units (other than any non-substantive differences to reflect the issuance of such securities by ET, as opposed to ETO) (the “ET Series B Preferred Units”);

 

   

each 7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Unit, liquidation preference $25 per unit, representing a limited partner interest in ETO (the “ETO Series C Preferred Units”) issued and outstanding immediately prior to the effective time of the Merger will be converted into the right to receive one newly issued preferred unit representing a limited partner interest in ET designated as a “7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Unit” and having the same preferences, rights, powers and duties as the ETO Series C Preferred Units (other than any non-substantive differences to reflect the issuance of such securities by ET, as opposed to ETO) (the “ET Series C Preferred Units”);

 

   

each 7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Unit, liquidation preference $25 per unit, representing a limited partner interest in ETO (the “ETO Series D Preferred Units”) issued and outstanding immediately prior to the effective time of the Merger will be converted into the right to receive one newly issued preferred unit representing a limited partner interest in ET designated as a “7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Unit” and having the same preferences, rights, powers and duties as the ETO Series D Preferred Units (other than any non-substantive differences to reflect the issuance of such securities by ET, as opposed to ETO) (the “ET Series D Preferred Units”);

 

   

each 7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Unit, liquidation preference $25 per unit, representing a limited partner interest in ETO (the “ETO Series E Preferred Units” and, together with the ETO Series C Preferred Units and the ETO Series D Preferred Units, the “Retail ETO Preferred Units”) issued and outstanding immediately prior to the effective time of the Merger will be converted into the right to receive one newly issued preferred unit representing a limited partner interest in ET designated as a “7.600% Series E Fixed-to-Floating Rate Cumulative


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Redeemable Perpetual Preferred Unit” and having the same preferences, rights, powers and duties as the ETO Series E Preferred Units (other than any non-substantive differences to reflect the issuance of such securities by ET, as opposed to ETO) (the “ET Series E Preferred Units” and, together with the ET Series C Preferred Units and the ET Series D Preferred Units, the “Retail ET Preferred Units”);

 

   

each 6.750% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Unit, liquidation preference $1,000 per unit, representing a limited partner interest in ETO (the “ETO Series F Preferred Units”) issued and outstanding immediately prior to the effective time of the Merger will be converted into the right to receive one newly issued preferred unit representing a limited partner interest in ET designated as a “6.750% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Unit” and having the same preferences, rights, powers and duties as the ETO Series F Preferred Units (other than any non-substantive differences to reflect the issuance of such securities by ET, as opposed to ETO) (the “ET Series F Preferred Units”); and

 

   

each 7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Unit, liquidation preference $1,000 per unit, representing a limited partner interest in ETO (the “ETO Series G Preferred Units” and, together with the ETO Series A Preferred Units, the ETO Series B Preferred Units and the ETO Series F Preferred Units, the “Institutional ETO Preferred Units” and, together with the Retail ETO Preferred Units, the “ETO Preferred Units”) issued and outstanding immediately prior to the effective time of the Merger will be converted into the right to receive one newly issued preferred unit representing a limited partner interest in ET designated as a “7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Unit” and having the same preferences, rights, powers and duties as the ETO Series G Preferred Units (other than any non-substantive differences to reflect the issuance of such securities by ET, as opposed to ETO) (the “ET Series G Preferred Units” and, together with the ET Series A Preferred Units, the ET Series B Preferred Units and the ET Series F Preferred Units, the “Institutional ET Preferred Units” and, together with the Retail ET Preferred Units, the “ET Preferred Units”).

ET, in its capacity as the record and beneficial owner of 100% of the common units representing limited partner interests in ETO (“ETO Common Units”), which constitutes a “Unit Majority” (as defined in the Fifth Amended and Restated Agreement of Limited Partnership of ETO, dated as of October 19, 2018 (as amended to date, the “ETO Partnership Agreement”)), has approved, by written consent, the Merger Agreement and the transactions contemplated thereby, including the Merger. ETP Holdco Corporation, a Delaware corporation and wholly owned subsidiary of ETO (“ETP Holdco”), in its capacity as the record and beneficial owner of 100% of the (i) Class K Units representing limited partner interests in ETO (the “ETO Class K Units”), (ii) Class L Units representing limited partner interests in ETO (the “ETO Class L Units”), (iii) Class M Units representing limited partner interests in ETO (the “ETO Class M Units”) and (iv) Class N Units representing limited partner interests in ETO (the “ETO Class N Units” and, together with the ETO Class K Units, the ETO Class L Units and the ETO Class M Units, the “ETO Hook Units”), has approved, by written consent, the Merger Agreement and the transactions contemplated thereby, including the Merger. No further approval of the limited partners of ETO is required in connection with the Merger.

The ETO Series C Preferred Units, ETO Series D Preferred Units and ETO Series E Preferred Units currently trade on the New York Stock Exchange (the “NYSE”) under the symbols “ETPprC,” “ETPprD” and “ETPprE,” respectively. The Institutional ETO Preferred Units are not currently listed on any securities exchange.

ET plans to issue the ET Preferred Units promptly following the closing of the Merger. ET plans to apply to have the Retail ET Preferred Units listed on the NYSE. Currently, there is no public market for the Retail ET Preferred Units. ET does not intend to apply for the listing of the Institutional ET Preferred Units on any securities exchange or for the quotation of the Institutional ET Preferred Units on any automated dealer quotation system.

This represents a prospectus of ET in connection with the offering of the ET Preferred Units issuable in exchange for the ETO Preferred Units in connection with the Merger. ET and ETO encourage you to read the entire document carefully. In particular, please read the section entitled “Risk Factors” beginning on page 10 of this prospectus for a discussion of risks relevant to the Merger and the ET Preferred Units.

NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES COMMISSION HAS APPROVED OR DISAPPROVED OF THE ISSUANCE OF ET PREFERRED UNITS OR ANY OTHER TRANSACTIONS DESCRIBED IN THE ACCOMPANYING PROSPECTUS, OR PASSED UPON THE ADEQUACY OR ACCURACY OF THE DISCLOSURE IN THIS DOCUMENT. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.

This prospectus is dated                 , 2021.


Table of Contents

TABLE OF CONTENTS

 

ABOUT THIS DOCUMENT

     1  

QUESTIONS AND ANSWERS

     2  

SUMMARY

     5  

Information About the Parties

     5  

The Merger and the Merger Agreement

     5  

Required Approval of the Merger by ETO Unitholders

     6  

ET’s Ownership Interest in and Control of ETO

     6  

Reasons for the Merger

     6  

No ET Unitholder Approval Required

     6  

No Appraisal or Dissenters’ Rights

     6  

Regulatory Matters

     6  

Listing of Retail ET Preferred Units; Delisting and Deregistration of Retail ETO Preferred Units

     6  

Comparison of Unitholders’ Rights

     7  

Material U.S. Federal Income Tax Consequences of the Merger

     7  

Risk Factors

     7  

Recent Developments

     8  

Additional Information

     8  

RISK FACTORS

     10  

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

     15  

INFORMATION ABOUT THE PARTIES

     16  

Energy Transfer LP

     16  

Energy Transfer Operating, L.P.

     16  

ETO Merger Sub, LLC

     16  

THE MERGER

     17  

Transaction Structure

     17  

Reasons for the Merger

     17  

Consideration to ETO Preferred Unitholders

     17  

Treatment of Other Limited Partner Interests in ETO

     17  

Amendment No. 8 to the ET Partnership Agreement

     17  

Listing of Retail ET Preferred Units; Delisting and Deregistration of Retail ETO Preferred Units

     18  

Interests of ET in the Merger

     18  

No Appraisal or Dissenters’ Rights

     18  

No ET Unitholder Approval Required

     18  

Post-Closing Transactions

     19  

Accounting Treatment of the Merger

     19  

THE MERGER AGREEMENT

     20  

Explanatory Note Regarding the Merger Agreement

     20  

The Merger

     20  

Closing and Effective Time of the Merger

     20  

Merger Consideration

     21  

Exchange Procedures

     21  

Termination of the Exchange Fund

     21  

Lost, Stolen or Destroyed Unit Certificates

     22  

Organizational Documents

     22  

Representations and Warranties

     22  

Stock Exchange Listing and Delisting

     22  

Conditions to the Completion of the Merger

     22  

Termination

     22  

Expenses

     23  

Amendment and Waiver

     23  

 

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MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES OF THE MERGER

     24  

Assumptions Related to the U.S. Federal Income Tax Treatment of the Merger

     24  

U.S. Federal Income Tax Treatment of the Merger

     24  

Tax Consequences of the Merger to ETO

     25  

Tax Consequences of the Merger to ETO Preferred Unitholders

     25  

MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES OF ET PREFERRED UNIT OWNERSHIP

     26  

Partnership Status

     27  

Limited Partner Status

     28  

Tax Consequences of ET Preferred Unit Ownership

     29  

Tax Treatment of Operations

     31  

Disposition of ET Preferred Units

     31  

Tax-Exempt Organizations and Other Investors

     32  

Administrative Matters

     34  

Recent Legislative Developments

     36  

State, Local, Foreign and Other Tax Considerations

     37  

COMPARISON OF PREFERRED UNITHOLDERS’ RIGHTS AND DESCRIPTION OF ET PREFERRED UNITS

     38  

Series A Preferred Units

     38  

Series B Preferred Units

     43  

Series C Preferred Units

     48  

Series D Preferred Units

     53  

Series E Preferred Units

     58  

Series F Preferred Units

     62  

Series G Preferred Units

     68  

NO APPRAISAL OR DISSENTERS’ RIGHTS

     74  

BUSINESS

     75  

PROPERTY

     76  

LEGAL PROCEEDINGS

     77  

MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

     78  

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     79  

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

     80  

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     81  

LEGAL MATTERS

     82  

EXPERTS

     83  

WHERE YOU CAN FIND MORE INFORMATION

     84  

ANNEX A – MERGER AGREEMENT

  

ANNEX B – FORM OF AMENDMENT NO. 8 TO ET PARTNERSHIP AGREEMENT

  

ANNEX C – ANNUAL REPORT ON FORM 10-K OF ENERGY TRANSFER LP FOR THE YEAR ENDED DECEMBER 31, 2020

  

ANNEX D – ANNUAL REPORT ON FORM 10-K OF ENERGY TRANSFER OPERATING, L.P. FOR THE YEAR ENDED DECEMBER 31, 2020

  

 

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ABOUT THIS DOCUMENT

This document, which forms part of a registration statement on Form S-4 filed with the Securities and Exchange Commission (the “SEC”) by ET (File No. 333-             ), constitutes a prospectus of ET under Section 5 of the Securities Act of 1933, as amended (the “Securities Act”), with respect to the ET Preferred Units to be issued pursuant to the terms of the Merger Agreement. ET and ETO file annual, quarterly and current reports and other information with the SEC under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Copies of ET’s and ETO’s filings with the SEC are available to you without charge upon written or oral request. You can obtain any of these documents by requesting them in writing or by telephone from ET or ETO at: 8111 Westchester Drive, Suite 600, Dallas, TX 75225, Attention: Investor Relations, Email: InvestorRelations@energytransfer.com.

In order to receive timely delivery of the documents in advance of closing of the Merger, your request should be received no later than                     , 2021. If you request any documents, ET or ETO will mail them to you by first class mail, or another equally prompt means, within one business day after receipt of your request.

You should rely only on the information contained in this prospectus, including each of the annexes. No one has been authorized to provide you with information that is different from that contained in this prospectus, including each of the annexes. This prospectus is dated                     , 2021. The information contained in this prospectus is accurate only as of that date or, in the case of information in a document attached as an annex, as of the date of such document, unless the information specifically indicates that another date applies. Neither the mailing of this prospectus to holders of ETO Preferred Units nor the issuance by ET of ET Preferred Units pursuant to the terms of the Merger Agreement will create any implication to the contrary.

This prospectus does not constitute an offer to sell, or a solicitation of an offer to buy, any securities in any jurisdiction in which or from any person to whom it is unlawful to make any such offer or solicitation in such jurisdiction.

The information concerning ET contained in this prospectus has been provided by ET, and the information concerning ETO contained in this prospectus has been provided by ETO.

 

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QUESTIONS AND ANSWERS

The following section provides brief answers to certain questions that you may have regarding the issuance of ET Preferred Units in exchange for the ETO Preferred Units in connection with the Merger pursuant to the terms of the Merger Agreement. Please note that this section does not address all issues that may be important to you as a holder of ETO Preferred Units (“ETO Preferred Unitholder”). Accordingly, you should carefully read this entire prospectus, including each of the annexes.

 

Q:

Why am I receiving this prospectus?

 

A:

ETO Preferred Unitholders are receiving this prospectus in connection with the issuance of the ET Preferred Units in exchange for the ETO Preferred Units pursuant to the terms of the Merger Agreement.

The Merger is part of an internal reorganization that ET is undertaking, whereby each of the ETO Preferred Units will be cancelled and converted into the right to receive one newly issued preferred unit in ET, having the same preferences, rights, powers and duties as the applicable ETO Preferred Unit (other than any non-substantive differences to reflect the issuance of such securities by ET, as opposed to ETO).

 

Q:

What will happen to ETO as a result of the Merger?

 

A:

If the Merger is successfully completed, Merger Sub will be merged with and into ETO, with ETO being the surviving entity. ETO will become a wholly owned subsidiary of ET.

 

Q:

Why are the parties undertaking the Merger?

 

A:

The parties are undertaking the Merger as part of an internal reorganization to simplify the structure and capitalization of ET and its subsidiaries, including ETO.

 

Q:

What will holders of ETO Preferred Units be entitled to receive in the Merger?

 

A:

As a result of the Merger:

 

   

each ETO Series A Preferred Unit issued and outstanding immediately prior to the effective time of the Merger will be converted into the right to receive one newly issued ET Series A Preferred Unit;

 

   

each ETO Series B Preferred Unit issued and outstanding immediately prior to the effective time of the Merger will be converted into the right to receive one newly issued ET Series B Preferred Unit;

 

   

each ETO Series C Preferred Unit issued and outstanding immediately prior to the effective time of the Merger will be converted into the right to receive one newly issued ET Series C Preferred Unit;

 

   

each ETO Series D Preferred Unit issued and outstanding immediately prior to the effective time of the Merger will be converted into the right to receive one newly issued ET Series D Preferred Unit;

 

   

each ETO Series E Preferred Unit issued and outstanding immediately prior to the effective time of the Merger will be converted into the right to receive one newly issued ET Series E Preferred Unit;

 

   

each ETO Series F Preferred Unit issued and outstanding immediately prior to the effective time of the Merger will be converted into the right to receive one newly issued ET Series F Preferred Unit; and

 

   

each ETO Series G Preferred Unit issued and outstanding immediately prior to the effective time of the Merger will be converted into the right to receive one newly issued ET Series G Preferred Unit.

Each series of ET Preferred Units will have the same preferences, rights, powers and duties as the respective series of ETO Preferred Units exchanged therefor (other than any non-substantive differences to reflect the issuance of such securities by ET, as opposed to ETO).

 

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Q:

What will happen to the other partnership interests in ETO as a result of the Merger?

 

A:

As a result of the Merger, (i) the ETO Common Units, all of which are owned by ET, will be unchanged and remain outstanding, (ii) the ETO Hook Units, all of which are owned by ETP Holdco, will be converted into the right to receive 675,625,000 newly issued units representing a limited partner interest in ET designated as a “Class B Unit” (the “ET Class B Units”) in the aggregate and (iii) the General Partner Interest (as defined in the ETO Partnership Agreement), which is owned by Energy Transfer Partners GP, L.P., a Delaware limited partnership and the general partner of ETO (“ETO GP”), will be unchanged and remain outstanding.

 

Q:

Will the preferences, rights, powers and duties of the newly issued ET Preferred Units differ materially from the ETO Preferred Units for which they are exchanged?

 

A:

No, the ET Preferred Units will have the same preferences, rights, powers and duties as the ETO Preferred Units for which they are exchanged, other than any non-substantive differences to reflect the issuance of such securities by ET, as opposed to ETO.

 

Q:

Are holders of ETO Preferred Units entitled to vote on the Merger?

 

A:

No. Holders of ETO Preferred Units do not have the right to vote on or approve the Merger under applicable law, the ETO Partnership Agreement or the Merger Agreement. The only limited partner votes necessary to approve the Merger are (i) the approval by a majority of the outstanding ETO Common Units and (ii) the approval by a majority of the outstanding ETO Hook Units, each of which has already been secured.

 

Q:

Where will ETO Retail Preferred Units and ET Retail Preferred Units trade after the Merger?

 

A:

The ETO Retail Preferred Units will no longer be publicly traded following the Merger and will be delisted from the NYSE. The ET Series C Preferred Units, ET Series D Preferred Units and ET Series E Preferred Units are expected to trade on the NYSE under the symbols “            ,” “            “ and “            ,” respectively. ET does not intend to apply for the listing of the Institutional ET Preferred Units on any securities exchange or for the quotation of the Institutional ET Preferred Units on any automated dealer quotation system.

 

Q:

When will the Merger be completed?

 

A:

ET and ETO are working to complete the Merger as soon as possible. A number of conditions must be satisfied before ET and ETO can complete the Merger. ET and ETO expect to complete the Merger on or about April 1, 2021. Please read the section entitled “The Merger Agreement—Conditions to the Completion of the Merger” beginning on page 22.

 

Q:

Are holders of ETO Preferred Units entitled to appraisal or dissenters’ rights?

 

A:

No. Holders of ETO Preferred Units do not have appraisal or dissenters’ rights under applicable law or under the ETO Partnership Agreement or the Merger Agreement.

 

Q:

What are the expected U.S. federal income tax consequences to an ETO Preferred Unitholder as a result of the transactions contemplated by the Merger Agreement?

 

A:

It is anticipated that no gain or loss should be recognized by an ETO Preferred Unitholder solely as a result of the Merger. In addition, it is anticipated that no gain or loss should be recognized by ETO solely as a result of the Merger. For additional information, please see the sections entitled “Material U.S. Federal Income Tax Consequences of the Merger—Tax Consequences of the Merger to ETO and ETO Preferred Unitholders” and “Risk Factors—Risks Relating to the Merger.

 

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Q:

What are the expected U.S. federal income tax consequences for an ETO Preferred Unitholder of the ownership of ET Preferred Units after the Merger is completed?

 

A:

Distributions on the ET Preferred Units are expected to be treated as guaranteed payments for the use of capital that will generally be taxable to the holders of ET Preferred Units as ordinary income. In addition to U.S. federal income taxes, such a holder will likely be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangibles taxes that may be imposed by the various jurisdictions in which ET conducts business or owns property following the Merger, or in which the unitholder is a resident. Please read the section entitled “Material U.S. Federal Income Tax Consequences of ET Preferred Unit Ownership.

 

Q:

To whom should I direct any questions I may have?

 

A:

Holders of ETO Preferred Units may call or email ETO Investor Relations at (214) 981-0795 or InvestorRelations@energytransfer.com if they have further questions or if they would like additional copies, without charge, of this prospectus.

 

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SUMMARY

This summary highlights selected information included in this prospectus and does not contain all the information that may be important to you. To fully understand the Merger Agreement and the transactions contemplated thereby and for a more complete description of the terms of the Merger Agreement, you should read carefully this entire prospectus, including the annexes. Each item in this summary includes a page reference directing you to a more complete description of that item.

 

Information

About the Parties (page 16)

Energy Transfer LP is a publicly traded limited partnership owning and operating a diversified portfolio of energy assets. ET’s core operations include complementary natural gas midstream, intrastate and interstate transportation and storage assets; crude oil, natural gas liquids (“NGL”) and refined product transportation and terminalling assets; NGL storage and fractionation; and various acquisition and marketing assets. ET, through its ownership of ETO, also owns Lake Charles LNG Company, as well as limited partner interests and the general partner interests of publicly traded master limited partnerships Sunoco LP and USA Compression Partners, LP. The address of ET’s principal executive offices is 8111 Westchester Drive, Suite 600, Dallas, Texas 75225, and the telephone number at this address is (214) 981-0700.

Energy Transfer Operating, L.P. is a Delaware limited partnership and a subsidiary of ET. ETO is engaged in the midstream transportation and storage of natural gas, NGLs, refined products and crude oil, and terminalling services and acquisition and marketing activities, as well as NGL storage and fractionation services. ETO is managed by its general partner, ETO GP, and ETO GP is managed by its general partner, Energy Transfer Partners, L.L.C., a Delaware limited liability company (“ETO Managing GP”). ETO Managing GP is a wholly owned subsidiary of ET. The address of ETO’s principal executive offices is 8111 Westchester Drive, Suite 600, Dallas, Texas 75225, and the telephone number at this address is (214) 981-0700.

ETO Merger Sub LLC is a Delaware limited liability company and wholly owned subsidiary of ET. Merger Sub has not carried on any activities to date, other than activities incidental to its formation or undertaken in connection with the transactions contemplated by the Merger Agreement. The address of Merger Sub’s principal executive offices is 8111 Westchester Drive, Suite 600, Dallas, Texas 75225, and the telephone number at this address is (214) 981-0700.

The Merger and the Merger Agreement (pages 17 and 20)

The terms and conditions of the Merger are contained in the Merger Agreement, which is attached to this document as Annex A. You are encouraged to read the Merger Agreement carefully, as it is the legal document that governs the Merger.

The Merger Agreement provides for the merger of ETO with and into Merger Sub, a wholly owned subsidiary of ET, with ETO continuing as the surviving entity in the Merger as a wholly owned subsidiary of ET. Each ETO Preferred Unit issued and outstanding immediately prior to the effective time of the Merger will be converted into the right to receive one ET Preferred Unit with substantially equivalent preferences, rights, powers, duties and obligations as the ETO Preferred Unit for which it is exchanged.

Additionally, (i) the ETO Common Units, all of which are owned by ET, will be unchanged and remain outstanding, (ii) the ETO Hook Units, all of which are owned by ETP Holdco, will be converted into the right to receive 675,625,000 newly issued ET Class B Units in the aggregate and (iii) the General Partner Interest (as defined in the ETO Partnership Agreement), which is owned by ETO GP, will be unchanged and remain outstanding.



 

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Required

Approval of the Merger by ETO Unitholders (page 18)

The approval and adoption of the Merger Agreement and the Merger by ETO requires the affirmative vote or consent of holders of (i) at least a majority of the outstanding ETO Common Units and (ii) at least a majority of the outstanding ETO Hook Units. In connection with the execution of the Merger Agreement, (a) ET, which owns all of the outstanding ETO Common Units, and (b) ETP Holdco, which owns all of the outstanding ETO Hook Units, each delivered a written consent approving and adopting the Merger Agreement and the Merger. The delivery of the written consents by (x) ET with respect to the ETO Common Units it owns and (y) ETP Holdco with respect to the ETO Hook Units it owns is sufficient to adopt the Merger Agreement and thereby approve the Merger. The approval and adoption of the Merger Agreement and the Merger does not require the vote or consent of any other limited partners of ETO pursuant to the terms of the ETO Partnership Agreement.

 

ET’s

Ownership Interest in and Control of ETO (page 18)

ET owns ETO Managing GP, which is the general partner of ETO GP, which is the general partner of ETO, and ET controls ETO through its ownership of these two entities. ET also owns directly all of the outstanding ETO Common Units and indirectly all of the ETO Hook Units through its ownership of ETP Holdco, a wholly owned subsidiary of ETO. ET has different economic interests in the Merger than holders of ETO Preferred Units generally due to, among other things, the fact that ET is the acquiring entity in the Merger.

 

Reasons

for the Merger (page 17)

The parties are undertaking the Merger as part of an internal reorganization to simplify the structure and capitalization of ET and its subsidiaries, including ETO.

No ET Unitholder Approval Required (page 18)

The approval and adoption of the Merger Agreement and the Merger by ET does not require the affirmative vote or consent of any holder of ET units (the “ET Unitholders”).

No Appraisal or Dissenters’ Rights (page 18)

Holders of ETO Preferred Units do not have appraisal or dissenters’ rights under applicable law or contractual appraisal or dissenters’ rights under the ETO Partnership Agreement or the Merger Agreement.

Regulatory Matters (page 18)

In connection with the Merger, ET and ETO intend to make all required filings under the Securities Act and the Exchange Act, as well as any required filings or applications with the NYSE. There are no other approvals or filings applicable to the Merger.

 

Listing

of Retail ET Preferred Units; Delisting and Deregistration of Retail ETO Preferred Units (page 18)

ET expects to seek approval to list the ET Retail Preferred Units to be issued pursuant to the terms of the Merger Agreement on the NYSE. ET Series C Preferred Units, ET Series D Preferred Units and ET Series E Preferred Units are expected to trade on the NYSE under the symbols “            ,” “            “ and “            ,” respectively. ET does not intend to apply for the listing of the Institutional ET Preferred Units on any securities exchange or for the quotation of the Institutional ET Preferred Units on any automated dealer quotation system.



 

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The ETO Series C Preferred Units, ETO Series D Preferred Units and ETO Series E Preferred Units currently trade on the NYSE under the symbols “ETPprC,” “ETPprD” and “ETPprE,” respectively. After the Merger is completed, the Retail ETO Preferred Units will cease to be listed on the NYSE and will be deregistered under the Exchange Act.

 

Comparison

of Unitholders’ Rights (page 38)

Upon completion of the Merger, ETO Preferred Unitholders will become holders of ET Preferred Units (“ET Preferred Unitholders”) and their rights will be governed by the Third Amended Restated Agreement of Limited Partnership of ET, dated February 8, 2006 (as amended to date, the “ET Partnership Agreement”), as amended by Amendment No. 8 to the ET Partnership Agreement. There are certain differences between the current rights of ETO Preferred Unitholders under the ETO Partnership Agreement and the rights to which they will be entitled to as ET Preferred Unitholders under the ET Partnership Agreement. See the section entitled “Comparison of Preferred Unitholders’ Rights and Description of ET Preferred Units”beginning on page 38 for a comparison of preferred unitholder rights under the ETO Partnership Agreement and the ET Partnership Agreement.

Material U.S. Federal Income Tax Consequences of the Merger (page 24)

Tax matters associated with the Merger are complicated. The U.S. federal income tax consequences of the Merger to an ETO Preferred Unitholder will depend, in part, on such unitholder’s own personal tax situation. The tax discussions contained herein focus on the U.S. federal income tax consequences generally applicable to individuals who are residents or citizens of the United States that hold their ETO Preferred Units as capital assets, and these discussions have only limited application to other unitholders, including those subject to special tax treatment. ETO Preferred Unitholders are urged to consult their tax advisors for a full understanding of the U.S. federal, state, local and foreign tax consequences of the Merger that will be applicable to them

The expected U.S. federal income tax consequences of the Merger are dependent upon ET and ETO being treated as partnerships for U.S. federal income tax purposes at the time of the Merger. Whether each of ET and ETO will be treated as partnerships for U.S. federal income tax purposes at the time of the Merger will depend, in part, on whether at least 90% of the gross income of each of them for the calendar year that immediately proceeds the Merger and the calendar year that includes the closing date of the Merger is from sources treated as “qualifying income” within the meaning of Section 7704(d) of the Code. Assuming that each of ET and ETO is properly treated as a partnership for U.S. federal income tax purposes at the time of the Merger, it is anticipated that no gain or loss should be recognized by an ETO Preferred Unitholder solely as a result of the Merger.

Please read “Material U.S. Federal Income Tax Consequences of the Merger” for a more complete discussion of the U.S. federal income tax consequences of the Merger.

Risk Factors (page 10)

In addition to the other information contained herein, including the matters addressed in the section entitled “Cautionary Statement Regarding Forward-Looking Statements” beginning on page 15, ETO Preferred Unitholders should carefully consider the following risks. ETO Preferred Unitholders should also consider the other information in this prospectus and the other documents provided herewith, particularly the risk factors contained in ET’s Annual Report on Form 10-K for the year ended December 31, 2020, which is attached to this prospectus as Annex C, and in ETO’s Annual Report on Form 10-K for the year ended December 31, 2020, which is attached to this prospectus as Annex D. See the section entitled “Where You Can Find More Information” beginning on page 84.

 

   

The Merger Agreement may be terminated in accordance with its terms and the Merger may not be completed.



 

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The expected U.S. federal income tax consequences of the Merger are dependent upon ET and ETO being properly treated as partnerships for U.S. federal income tax purposes.

 

   

Each series of ET Preferred Units becomes redeemable by ET, at ET’s option, following a specified redemption date for each such series of ET Preferred Units; however, holders of each series of ET Preferred Units should not expect ET to exercise its redemption rights.

 

   

ET distributes all of its available cash to its limited partners and is not required to accumulate cash for the purpose of meeting its future obligations to each of the holders of the ET Preferred Units which, along with the agreements governing ET’s indebtedness, may limit the cash available to make distributions on the ET Preferred Units.

 

   

The ET Preferred Units will be subordinated to ET’s existing and future debt obligations, and holders’ interests could be diluted by the issuance by ET of additional equity interests, including ET Common Units, additional ET Preferred Units, and other classes of equity.

 

   

The ET Preferred Units will have extremely limited voting rights.

 

   

Holders’ ability to transfer the ET Preferred Units at a desired time or price may be limited by the absence of an active trading market, which may not develop.

 

   

ET’s ability to issue parity securities in the future could adversely affect the rights of holders of ET Preferred Units.

 

   

None of the ET Preferred Units will be convertible into ET Common Units at any time and will not have any protection in the event of a change of control.

 

   

Certain tax consequences of the ownership of ET Preferred Units, including treatment of distributions as guaranteed payments for the use of capital, are uncertain.

 

   

Our tax treatment of distributions on the ET Preferred Units as guaranteed payments for the use of capital means that such distributions will not be eligible for the 20% deduction for qualified business income.

 

Recent

Developments

On February 16, 2021, ET entered into an Agreement and Plan of Merger (the “Enable Merger Agreement”) with Enable Midstream Partners, LP, a Delaware limited partnership (“Enable”), and the other parties thereto, whereby Enable and its general partner will each merge with and into newly formed merger subsidiaries of ET (the “Enable Merger”). In connection with the Enable Merger, each issued and outstanding Enable common unit will be cancelled and converted into the right to receive 0.8595 ET Common Units. In addition, each outstanding Series A preferred unit representing a limited partner interest in Enable will be exchanged for 0.0265 of an ET Series G Preferred Unit, and ET will make a $10 million cash payment for Enable’s general partner. Subject to the satisfaction of certain closing conditions, ET expects to close the Enable Merger mid-year 2021. However, there is no assurance that the Enable Merger will be completed within the timeframe anticipated or at all. The Merger is not contingent on the completion of the Enable Merger, but the Enable Merger is contingent on the completion of the Merger.

 

Additional

Information

In reliance on the SEC’s amendments to Regulation S-K described in SEC Release Nos. 33-10890; 34-90459; and IC-34100 (November 19, 2020), ET has omitted from this prospectus certain historical financial information regarding ET and ETO.

ET is not required to furnish pro forma financial information with respect to the Enable Merger in this prospectus because Enable would not be considered a “significant subsidiary” under any of the financial conditions specified in Rule 1-02(w) of Regulation S-X, substituting 20% for 10% in each of those conditions in accordance with Rule 11.01(b)(1) of Regulation S-X.



 

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With respect to the Merger, ETO is already reflected as a consolidated subsidiary in ET’s consolidated financial statements. Therefore, the only significant pro forma impacts of the Merger to ET’s consolidated balance sheet and statement of operations for the year ended December 31, 2020 would be as follows:

 

   

ET’s consolidated balance sheet would reflect the reclassification of the book value of the ETO Preferred Units from noncontrolling interest to partners’ capital, with no net impact on ET’s total equity. As of December 31, 2020, the amount that would have been reclassified was $4.76 billion, representing the book value of the ETO Preferred Units on that date; and

 

   

ET’s consolidated statement of operations would reflect the reclassification of income attributable to the ETO Preferred Units from net income attributable to noncontrolling interests to net income attributable to partners, with no impact to net income, common unitholders’ interest in net income (loss), or net income (loss) per common unit. For the year ended December 31, 2020, the amount that would have been reclassified was $329 million, representing the portion of ETO’s net income allocated to the ETO Preferred Unitholders during the period.

This prospectus includes as annexes certain documents that ET and ETO have previously filed with the SEC under the Exchange Act as set forth in the table of contents of this prospectus. Any statement contained in such a document shall be deemed to be modified or superseded for purposes of this prospectus to the extent that a statement contained in this prospectus or in an annex hereto consisting of a document filed with the SEC subsequently to such document modifies or replaces such statement. The information included in the annexes hereto is incorporated into this prospectus except to the extent so modified or superseded.



 

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RISK FACTORS

In addition to the other information contained herein, including the matters addressed in the section entitled “Cautionary Statement Regarding Forward-Looking Statements” beginning on page 15, investors should carefully consider the following risks. Investors should also consider the other information in this prospectus, including the annexes, particularly the risk factors contained in ET’s Annual Report on Form 10-K for the year ended December 31, 2020, which is attached to this prospectus as Annex C, and in ETO’s Annual Report on Form 10-K for the year ended December 31, 2020, which is attached to this prospectus as Annex D. See the section entitled “Where You Can Find More Information” beginning on page 84.

Risks Relating to the Merger

The Merger Agreement may be terminated in accordance with its terms and the Merger may not be completed.

The Merger Agreement is subject to a number of conditions that must be satisfied or waived in order to complete the Merger. Those conditions include, among others: the accuracy of representations and warranties under the Merger Agreement (subject to the materiality standards set forth in the Merger Agreement) and ET’s and ETO’s performance of their respective obligations under the Merger Agreement in all material respects. These conditions to the closing of the Merger may not be fulfilled in a timely manner or at all, and, accordingly, the Merger may be delayed or may not be completed.

In addition, ET and ETO may elect to terminate the Merger Agreement in certain other circumstances. See the section entitled “The Merger Agreement—Termination” beginning on page 22.

ETO Preferred Unitholders will have different rights as ET Preferred Unitholders under the ET Partnership Agreement than they currently have as ETO Preferred Unitholders under the ETO Partnership Agreement.

Upon completion of the Merger, ETO Preferred Unitholders will become ET Preferred Unitholders and their rights will be governed by the ET Partnership Agreement. Although the ET Preferred Units will have the same preferences, rights, powers and duties as the ETO Preferred Units for which they are exchanged, there are certain differences between the current rights of ETO Preferred Unitholders under the ETO Partnership Agreement and the rights to which they will be entitled to as ET Preferred Unitholders under the ET Partnership Agreement. See the section entitled “Comparison of Preferred Unitholders’ Rights and Description of ET Preferred Units” beginning on page 38 for a comparison of unitholder rights under the ETO Partnership Agreement and the ET Partnership Agreement.

The expected U.S. federal income tax consequences of the Merger are dependent upon ET and ETO being properly treated as partnerships for U.S. federal income tax purposes.

If either ET or ETO were to be treated as a corporation for U.S. federal income tax purposes, the consequences of the Merger would be materially different. If ET were to be treated as a corporation for U.S. federal income tax purposes, the Merger would likely be a fully taxable transaction to ETO Preferred Unitholders.

Risks Relating to the ET Preferred Units

Each ET Preferred Unit will represent a perpetual equity interest in ET, and holders should not expect ET to redeem any ET Preferred Units on the date any series of ET Preferred Units become redeemable by ET, at ET’s option, or on any particular date thereafter.

Each of the ET Preferred Units will represent a perpetual equity interest in ET, and they have no maturity or mandatory redemption date and are not redeemable at the option of holders under any circumstances. As a result, none of the ET Preferred Units will give rise to a claim for payment of a principal amount at a particular date.

 

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Instead, the ET Preferred Units may be redeemed by ET at ET’s option pursuant to the terms of the applicable series of ET Preferred Units. Any decision ET makes at any time to redeem ET Preferred Units will depend upon, among other things, ET’s evaluation of its capital position and general market conditions at that time. In addition, the instruments governing ET’s outstanding indebtedness may limit ET’s ability to redeem the ET Preferred Units. As a result, each of the holders of the ET Preferred Units may be required to bear the financial risks of an investment in the ET Preferred Units for an indefinite period of time. Moreover, the ET Preferred Units will rank junior to all of ET’s existing and future indebtedness and other liabilities with respect to assets available to satisfy claims against ET.

ET distributes all of its available cash to its limited partners and is not required to accumulate cash for the purpose of meeting its future obligations to each of the holders of the ET Preferred Units which, along with the agreements governing ET’s indebtedness, may limit the cash available to make distributions on the ET Preferred Units.

Pursuant to the ET Partnership Agreement, ET distributes all of its “available cash” each quarter to its limited partners. The ET Partnership Agreement, as amended by Amendment No. 8 thereto, will define “Available Cash” to generally mean, for each fiscal quarter, all cash and cash equivalents on hand at the end of such quarter and all cash and cash equivalents on hand, less the amount of any cash reserves established by LE GP, LLC, a Delaware limited liability company and the general partner of ET, to:

 

   

provide for the proper conduct of ET’s business, including reserves for future capital expenditures and anticipated future credit needs;

 

   

comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation; or

 

   

provide funds to make distributions on the ET Common Units and the ET Preferred Units.

As a result, ET does not expect to accumulate significant amounts of cash. Depending on the timing and amount of ET’s cash distributions, these distributions could significantly reduce the cash available to ET in subsequent periods to make distributions on the ET Preferred Units.

The ET Preferred Units will be subordinated to ET’s existing and future debt obligations, and holders’ interests could be diluted by the issuance of additional units, including additional ET Preferred Units, and by other transactions.

The ET Preferred Units will be subordinated to all of ET’s and its subsidiaries’ existing and future indebtedness. As of December 31, 2020, ET’s total debt (including the debt of ET’s subsidiaries) was approximately $51.4 billion. ET may incur additional debt under existing or future debt arrangements. The payment of principal and interest on ET’s debt reduces cash available for distribution to ET’s limited partners, including the holders of the ET Preferred Units.

The issuance of any senior securities or additional parity securities would dilute the interests of each of the holders of the ET Preferred Units and could affect ET’s ability to pay distributions on, redeem, or pay the liquidation preference on the ET Preferred Units. Future issuances and sales of senior securities, parity securities or junior securities, or the perception that such issuances and sales could occur, may cause prevailing market prices for the ET Preferred Units, as applicable, to decline and may adversely affect ET’s ability to raise additional capital in the financial markets at times and prices favorable to ET.

The ET Preferred Units will have extremely limited voting rights.

The voting rights of each of the holders of the ET Preferred Units will be extremely limited. Except as set forth in the ET Partnership Agreement or as otherwise required by Delaware law, holders of the ET Preferred

 

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Units generally will have no voting rights. Although each of the holders of the ET Preferred Units will be entitled to limited protective voting rights with respect to certain matters, the ET Preferred Units will generally vote separately as a class along with each other series of ET Preferred Units and all other series of parity securities that ET may issue upon which like voting rights have been conferred and are exercisable. As a result, the voting rights of holders of ET Preferred Units may be significantly diluted, and the holders of other series of parity securities that ET may issue may be able to control or significantly influence the outcome of any vote.

Holders’ ability to transfer the ET Preferred Units at a desired time or price may be limited by the absence of an active trading market, which may not develop.

Each of the ET Preferred Units are a new class of ET’s securities and do not have an established trading market. In addition, since each of the Institutional ET Preferred Units have no stated maturity date, investors seeking liquidity will be limited to selling their Institutional ET Preferred Units in the secondary market absent redemption by ET.

Although the offer and sale of the ET Preferred Units will be registered under the Securities Act by the registration statement of which this prospectus forms a part, ET does not intend to apply for the listing of the Institutional ET Preferred Units on any securities exchange or for the quotation of either of the Institutional ET Preferred Units on any automated dealer quotation system. An active market for the Institutional ET Preferred Units may not develop or, if developed, may not continue. In the absence of active trading markets, holders of Institutional ET Preferred Units may not be able to transfer the Institutional ET Preferred Units within the time or at the prices desired.

ET intends to apply to list the Retail ET Preferred Units on the NYSE, but there can be no assurance that the NYSE will accept the Retail ET Preferred Units for listing. Even if the Retail ET Preferred Units are approved for listing by the NYSE, an active trading market on the NYSE for the Retail ET Preferred Units may not develop or, even if it develops, may not last, in which case the trading price of the Retail ET Preferred Units could be adversely affected and your ability to transfer your Retail ET Preferred Units will be limited. If an active trading market does develop on the NYSE, the Retail ET Preferred Units may trade at prices lower than the original offering price. The trading prices of the Retail ET Preferred Units would depend on many factors, including: prevailing interest rates; the market for similar securities; general economic and financial market conditions; ET’s issuance of debt or other preferred equity securities; and ET’s financial condition, results of operations and prospects.

ET’s ability to issue parity securities in the future could adversely affect the rights of holders of ET Preferred Units.

ET will be allowed to issue parity securities (including additional ET Preferred Units) without any vote of the holders of ET Preferred Units, except where the cumulative distributions on the ET Preferred Units, or any parity securities are in arrears. The issuance of any parity securities would have the effect of reducing the amounts available to each of the holders of the ET Preferred Units upon ET’s liquidation, dissolution or winding up if ET does not have sufficient funds to pay all liquidation preferences of the ET Preferred Units and parity securities in full. It also would reduce amounts available to make distributions on the ET Preferred Units if ET does not have sufficient funds to pay distributions on all outstanding ET Preferred Units and parity securities. In addition, future issuances and sales of parity securities, or the perception that such issuances and sales could occur, may cause prevailing market prices for the ET Preferred Units to decline and may adversely affect ET’s ability to raise additional capital in the financial markets at times and prices favorable to ET.

None of the ET Preferred Units will be convertible into ET Common Units at any time and will not have any protection in the event of a change of control.

None of the ET Preferred Units are convertible into ET Common Units at any time. In addition, the terms of the ET Preferred Units will not contain any provisions that protect the holders of the ET Preferred Units in the event that ET experiences a change of control.

 

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Tax Risks of Holding ET Preferred Units

Certain tax consequences of the ownership of ET Preferred Units, including treatment of distributions as guaranteed payments for the use of capital, are uncertain.

The tax treatment of distributions on ET Preferred Units is uncertain. We will treat each of the holders of the ET Preferred Units as partners for tax purposes and will treat distributions on the ET Preferred Units as guaranteed payments for the use of capital that will generally be taxable to each of the holders of the ET Preferred Units as ordinary income. Although a holder of ET Preferred Units will recognize taxable income from the accrual of such a guaranteed payment (even in the absence of a contemporaneous cash distribution), we anticipate accruing and making the guaranteed payment distributions semi-annually or quarterly, as applicable. Otherwise, except in the case of our liquidation, the holders of ET Preferred Units are generally not anticipated to share in our items of income, gain, loss or deduction, nor will we allocate any share of our nonrecourse liabilities to the holders of ET Preferred Units. See the applicable description of “Liquidation Rights” under “Comparison of Preferred Unitholders’ Rights and Description of ET Preferred Units.” If any series of the ET Preferred Units is treated as indebtedness for tax purposes, rather than as guaranteed payments for the use of capital, distributions on such series of ET Preferred Units likely would be treated as payments of interest by us to holders of such series.

A holder of ET Preferred Units will be required to recognize a gain or loss on a sale of ET Preferred Units equal to the difference between the amount realized by such holder and such holder’s tax basis in the ET Preferred Units sold. The amount realized generally will equal the sum of the cash and the fair market value of other property such holder receives in exchange for such ET Preferred Units. Subject to general rules requiring a blended basis among multiple partnership interests, the tax basis of an ET Preferred Unit will generally be equal to the tax basis in the ETO Preferred Unit exchanged therefor. Gain or loss recognized by a holder of ET Preferred Units on the sale or exchange of an ET Preferred Unit, as applicable, held for more than one year generally will be taxable as long-term capital gain or loss. Because holders of ET Preferred Units will generally not be allocated a share of our items of depreciation, depletion or amortization, it is not anticipated that such holders would be required to recharacterize any portion of their gain as ordinary income as a result of the recapture rules.

Investment in the ET Preferred Units by tax-exempt investors, such as employee benefit plans and individual retirement accounts (“IRAs”), and non-U.S. persons raises issues unique to them. The treatment of guaranteed payments for the use of capital to tax-exempt investors is not certain and such payments may be treated as unrelated business taxable income for federal income tax purposes.

Distributions to non-U.S. holders of ET Preferred Units will be subject to withholding taxes. If the amount of withholding exceeds the amount of U.S. federal income tax actually due, non-U.S. holders of ET Preferred Units may be required to file U.S. federal income tax returns in order to seek a refund of such excess. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor with respect to the consequences of owning the ET Preferred Units.

Our treatment of distributions on the ET Preferred Units as guaranteed payments for the use of capital means that such distributions will not be eligible for the 20% deduction for qualified business income.

For taxable years beginning after December 31, 2017, and ending on or before December 31, 2025, a non-corporate unitholder may be entitled to a deduction equal to 20% of its “qualified business income” attributable to its interest in a partnership, subject to certain limitations. As described above, we will treat distributions on the ET Preferred Units as guaranteed payments for the use of capital, and under the applicable Treasury Regulations, a guaranteed payment for the use of capital will not be taken into account for purposes of computing qualified business income. As a result, distributions received by the holders of the ET Preferred Units will not be eligible for the 20% deduction for qualified business income. Unitholders that receive ET Preferred Units in the Merger should consult their tax advisors regarding the availability of the deduction for qualified business income.

 

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Risks Relating to ET’s Business

You should read and consider risk factors specific to ET’s businesses that will also affect the combined partnership after the completion of the Merger. These risks are described in Part I, Item 1A of ET’s Annual Report on Form 10-K for the year ended December 31, 2020, which is attached to this prospectus as Annex C. See the section entitled “Where You Can Find More Information” beginning on page 84 for more information.

Risks Relating to ETO’s Business

You should read and consider risk factors specific to ETO’s businesses that will also affect the combined partnership after the completion of the Merger. These risks are described in Part I, Item 1A of ETO’s Annual Report on Form 10-K for the year ended December 31, 2020, which is attached to this prospectus as Annex D. See the section entitled “Where You Can Find More Information” beginning on page 84 for more information.

 

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This prospectus includes “forward-looking statements” about ET and ETO that are subject to risks and uncertainties. All statements other than statements of historical fact included in this document are forward-looking statements. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may,” “will,” or similar expressions help identify forward-looking statements. ET and ETO caution investors that any forward-looking statements are subject to risks and uncertainties that may cause actual results and future trends to differ materially from those matters expressed in or implied by such forward-looking statements. When considering forward-looking statements, investors should keep in mind the risk factors and other cautionary statements described in the section entitled “Risk Factors” beginning on page 10. Investors are cautioned not to place undue reliance on forward-looking statements. Among the risks and uncertainties that could cause actual results to differ from those described in forward-looking statements are the following:

 

   

the risk that the Merger Agreement may be terminated in accordance with its terms and that the Merger may not be completed;

 

   

the possibility that ET and ETO will incur significant transaction and other costs in connection with the Merger, which may be in excess of those anticipated by ET or ETO;

 

   

the risk that ET may fail to realize the benefits expected from the Merger;

 

   

the risk that the Enable Merger Agreement may be terminated in accordance with its terms and that the Enable Merger may not be completed;

 

   

the risk that ET may fail to realize the benefits expected from the Enable Merger; and

 

   

the risks applicable to ETO’s and ET’s operating results and businesses generally.

Such factors are difficult to predict and in many cases may be beyond the control of ET and ETO. ET’s and ETO’s forward-looking statements are based on assumptions that ET and ETO, respectively, believe to be reasonable but that may not prove to be accurate. Consequently, all of the forward-looking statements ET and ETO make in this document are qualified by the information contained herein, including, but not limited to, the information contained under this heading and the information detailed in ET’s Annual Report on Form 10-K for the year ended December 31, 2020, which is attached to this prospectus as Annex C, and in ETO’s Annual Report on Form 10-K for the year ended December 31, 2020, which is attached to this prospectus as Annex D. See the section entitled “Where You Can Find More Information” beginning on page 84.

ET and ETO undertake no obligation to update any such forward-looking statements to reflect events or circumstances that occur, or which they become aware of, except as required by applicable law or regulation. Readers are cautioned not to place undue reliance on these forward-looking statements, which are based only on information available as of the date hereof.

 

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INFORMATION ABOUT THE PARTIES

Energy Transfer LP

ET is a Delaware limited partnership whose common units are traded on the NYSE under the symbol “ET.” ET’s core operations include complementary natural gas midstream, intrastate and interstate transportation and storage assets; crude oil, NGLs and refined product transportation and terminalling assets; NGL storage and fractionation; and various acquisition and marketing assets. ET, through its ownership of ETO, also owns Lake Charles LNG Company, as well as limited partner interests and the general partner interests of publicly traded master limited partnerships Sunoco LP and USA Compression Partners, LP.

The address of ET’s principal executive offices is 8111 Westchester Drive, Suite 600, Dallas, Texas 75225, and the telephone number at this address is (214) 981-0700.

Energy Transfer Operating, L.P.

ETO is a Delaware limited partnership and a subsidiary of ET. ETO is engaged in the midstream transportation and storage of natural gas, NGLs, refined products and crude oil, and terminalling services and acquisition and marketing activities, as well as NGL storage and fractionation services. ETO is managed by its general partner, ETO GP, and ETO GP is managed by its general partner, ETO Managing GP. ETO Managing GP is a wholly owned subsidiary of ET.

The address of ETO’s principal executive offices is 8111 Westchester Drive, Suite 600, Dallas, Texas 75225, and the telephone number at this address is (214) 981-0700.

ETO Merger Sub, LLC

Merger Sub is a Delaware limited liability company and wholly owned subsidiary of ET. Merger Sub has not carried on any activities to date, other than activities incidental to its formation or undertaken in connection with the transactions contemplated by the Merger Agreement.

The address of Merger Sub’s principal executive offices is 8111 Westchester Drive, Suite 600, Dallas, Texas 75225, and the telephone number at this address is (214) 981-0700.

 

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THE MERGER

This discussion of the Merger is qualified in its entirety by reference to the Merger Agreement, which is attached to this prospectus as Annex A. You should read the entire Merger Agreement carefully as it is the legal document that governs the Merger.

Transaction Structure

At the effective time of the Merger, Merger Sub will merge with and into ETO. As a result of the Merger, the separate existence of Merger Sub will cease, and ETO will continue as the surviving entity and a wholly owned subsidiary of ET.

Reasons for the Merger

The parties are undertaking the Merger as part of internal reorganization to simplify the structure and capitalization of ET and its subsidiaries, including ETO.

Consideration to ETO Preferred Unitholders

As a result of the Merger:

 

   

each ETO Series A Preferred Unit issued and outstanding immediately prior to the effective time of the Merger will be converted into the right to receive one newly issued ET Series A Preferred Unit;

 

   

each ETO Series B Preferred Unit issued and outstanding immediately prior to the effective time of the Merger will be converted into the right to receive one newly issued ET Series B Preferred Unit;

 

   

each ETO Series C Preferred Unit issued and outstanding immediately prior to the effective time of the Merger will be converted into the right to receive one newly issued ET Series C Preferred Unit;

 

   

each ETO Series D Preferred Unit issued and outstanding immediately prior to the effective time of the Merger will be converted into the right to receive one newly issued ET Series D Preferred Unit;

 

   

each ETO Series E Preferred Unit issued and outstanding immediately prior to the effective time of the Merger will be converted into the right to receive one newly issued ET Series E Preferred Unit;

 

   

each ETO Series F Preferred Unit issued and outstanding immediately prior to the effective time of the Merger will be converted into the right to receive one newly issued ET Series F Preferred Unit; and

 

   

each ETO Series G Preferred Unit issued and outstanding immediately prior to the effective time of the Merger will be converted into the right to receive one newly issued ET Series G Preferred Unit.

By virtue of the Merger, each ETO Preferred Unit will be cancelled and cease to exist as of the effective time of the Merger.

Treatment of Other Partnership Interests in ETO

As a result of the Merger, (i) the ETO Common Units, all of which are owned by ET, will be unchanged and remain outstanding, (ii) the ETO Hook Units, all of which are owned by ETP Holdco, will be converted into the right to receive 675,625,000 newly issued ET Class B Units in the aggregate and (iii) the General Partner Interest (as defined in the ETO Partnership Agreement), which is owned by ETO GP, will be unchanged and remain outstanding.

Amendment No. 8 to the ET Partnership Agreement

The Merger Agreement provides that, prior to the closing, ET GP and ET will take all actions as are necessary and appropriate to amend the ET Partnership Agreement to allow for the creation and issuance of the

 

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ET Preferred Units. The form of Amendment No. 8 to the ET Partnership Agreement is attached to this prospectus as Annex B. You should read Amendment No. 8 to the ET Partnership Agreement because it, and not this prospectus, is the legal document that, upon its execution and delivery, will govern the rights of ET Preferred Unitholders following the effective time of the Merger. For additional information regarding the ET Partnership Agreement, see “Comparison of Preferred Unitholders’ Rights and Description of ET Preferred Units” beginning on page 38.

Listing of Retail ET Preferred Units; Delisting and Deregistration of Retail ETO Preferred Units

ET expects to seek approval to list the Retail ET Preferred Units to be issued pursuant to the terms of the Merger Agreement on the NYSE. Assuming that such approval is sought and obtained, ET expects the ET Series C Preferred Units, ET Series D Preferred Units and ET Series E Preferred Units to be quoted on the NYSE under the symbols “            ,” “            “ and “            ,” respectively. ET does not intend to apply for the listing of the Institutional ET Preferred Units on any securities exchange or for the quotation of the Institutional ET Preferred Units on any automated dealer quotation system.

The ETO Series C Preferred Units, ETO Series D Preferred Units and ETO Series E Preferred Units currently trade on the NYSE under the symbols “ETPprC,” “ETPprD” and “ETPprE,” respectively. If the Merger is completed, the Retail ETO Preferred Units will cease to be listed on the NYSE and will be deregistered under the Exchange Act.

Interests of ET in the Merger

ET owns ETO Managing GP and ETO GP, and controls ETO through its ownership of these two entities. ET also owns all of the outstanding ETO Common Units and all of the ETO Hook Units through indirect ownership of ETP Holdco, a wholly owned subsidiary of ETO. ET has different economic interests in the Merger than holders of ETO Preferred Units generally due to, among other things, the fact that ET is the acquiring entity in the Merger.

No Appraisal or Dissenters’ Rights

Holders of ETO Preferred Units do not have appraisal or dissenters’ rights under applicable law or contractual appraisal or dissenters’ rights under the ETO Partnership Agreement or the Merger Agreement.

Required Approval of the Merger by ETO Unitholders

The approval and adoption of the Merger Agreement and the Merger by ETO requires the affirmative vote or consent of holders of (i) at least a majority of the outstanding ETO Common Units and (ii) at least a majority of the outstanding ETO Hook Units. In connection with the execution of the Merger Agreement, (a) ET, which owns all of the outstanding ETO Common Units, and (b) ETP Holdco, which owns all of the outstanding ETO Hook Units, each delivered a written consent approving and adopting the Merger Agreement and the Merger. The delivery of the written consents by (x) ET with respect to the ETO Common Units it owns and (y) ETP Holdco with respect to the ETO Hook Units it owns is sufficient to adopt the Merger Agreement and thereby approve the Merger. The approval and adoption of the Merger Agreement and the Merger does not require the vote or consent of any other limited partners of ETO pursuant to the terms of the ETO Partnership Agreement.

No ET Unitholder Approval Required

The approval and adoption of the Merger Agreement and the Merger by ET does not require the affirmative vote or consent of ET Unitholders.

 

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Regulatory Matters

In connection with the Merger, ET and ETO intend to make all required filings under the Securities Act and the Exchange Act, as well as any required filings or applications with the NYSE. There are no other approvals or filings applicable to the Merger.

Post-Closing Transactions

Following the effective time of the Merger, it is anticipated that ETO GP will be dissolved and as a result of such dissolution, ETO GP will withdraw as the general partner of ETO, the General Partner Interest (as defined in the ETO Partnership Agreement) will be distributed to ETO Managing GP, and ETO Managing GP will be admitted as the successor general partner of ETO, with such admission being effective immediately prior to the withdrawal of ETO GP.

Accounting Treatment of the Merger

ET controls ETO through its ownership of ETO Managing GP and ETO GP and therefore currently consolidates the operations of ETO into ET’s financial statements. Subsequent to the Merger, ET will continue to present consolidated financial statements that reflect the historical consolidated financial statements of ETO. The Merger will be accounted for as an equity transaction and will be reflected in ET’s consolidated financial statements as ET’s acquisition of the noncontrolling interest in ETO. The carrying amounts of ET’s and ETO’s assets and liabilities will not be adjusted, nor will a gain or loss be recognized as a result of the Merger.

The ETO Hook Units are currently held by wholly owned subsidiaries of ETO and are eliminated in ET’s consolidated financial statements. Subsequent to the conversion of the ETO Hook Units, the ET Class B Units will be held by wholly owned subsidiaries and will be eliminated in ET’s consolidated financial statements. Therefore, the conversion of the ETO Hook Units will not have an impact on ET’s consolidated financial statements.

 

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THE MERGER AGREEMENT

This section describes the material terms of the Merger Agreement, which was executed on March 5, 2021. The description of the Merger Agreement in this section and elsewhere in this prospectus is qualified in its entirety by reference to the complete text of the Merger Agreement, a copy of which is attached as Annex A to this prospectus. This summary does not purport to be complete and may not contain all of the information about the Merger Agreement that is important to you. You are encouraged to read the Merger Agreement carefully and in its entirety, because it is the legal document that governs the Merger.

Explanatory Note Regarding the Merger Agreement

The Merger Agreement and this summary are included solely to provide you with information regarding the terms of the Merger Agreement. Factual disclosures about ET, ETO, or any of their respective subsidiaries or affiliates contained in this prospectus, in ET’s Annual Report on Form 10-K for the year ended December 31, 2020, which is attached to this prospectus as Annex C, or in ETO’s Annual Report on Form 10-K for the year ended December 31, 2020, which is attached to this prospectus as Annex D, update or modify the factual disclosures about ET or ETO, as applicable, contained in the Merger Agreement. The representations, warranties and covenants made in the Merger Agreement by ET, ETO and Merger Sub were made solely for the purposes of the Merger Agreement and as of specific dates and were qualified and subject to important limitations agreed to by ET, ETO and Merger Sub in connection with negotiating the terms of the Merger Agreement. In particular, in your review of the representations and warranties contained in the Merger Agreement and described in this summary, it is important to bear in mind that the representations and warranties were negotiated with the principal purposes of establishing the circumstances in which a party to the Merger Agreement may have the right not to complete the Merger if the representations and warranties of the other party prove to be untrue due to a change in circumstance or otherwise, and allocating risk between the parties to the Merger Agreement, rather than establishing matters as facts. Moreover, information concerning the subject matter of the representations and warranties, which do not purport to be accurate as of the date of this prospectus, may have changed since the date of the Merger Agreement. Investors should not rely on the Merger Agreement representations, warranties, covenants or any descriptions thereof as characterizations of the actual state of facts of ET, ETO, Merger Sub or any of their respective subsidiaries or affiliates.

The Merger

The Merger Agreement provides that, upon the terms and subject to the conditions in the Merger Agreement, and in accordance with the Delaware Revised Uniform Limited Partnership Act, as amended (“DRULPA”), and the Delaware Limited Liability Company Act, as amended, at the effective time of the Merger, Merger Sub will merge with and into ETO. As a result of the Merger, the separate existence of Merger Sub will cease, and ETO will continue as the surviving entity in the Merger and a wholly owned subsidiary of ET.

Closing and Effective Time of the Merger

Unless otherwise mutually agreed to in writing by each of the parties, the closing of the Merger will take place on the second business day after the satisfaction or waiver (to the extent permitted by applicable law) of the conditions to completion of the Merger, described in the section entitled “—Conditions to the Completion of the Merger” beginning on page 22, other than those conditions which by their nature are to be satisfied at the closing of the Merger, but subject to the satisfaction or waiver of such conditions.

Assuming timely satisfaction of the necessary closing conditions, the parties currently expect the closing of the Merger to occur on or about April 1, 2021. The Merger shall become effective at the time when the certificate of merger for the Merger has been duly filed with the secretary of state of the State of Delaware or at such later time as may be agreed by the parties in writing and specified in the certificate of merger for the Merger.

 

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Merger Consideration

As a result of the Merger:

 

   

each ETO Series A Preferred Unit issued and outstanding immediately prior to the effective time of the Merger will be converted into the right to receive one newly issued ET Series A Preferred Unit;

 

   

each ETO Series B Preferred Unit issued and outstanding immediately prior to the effective time of the Merger will be converted into the right to receive one newly issued ET Series B Preferred Unit;

 

   

each ETO Series C Preferred Unit issued and outstanding immediately prior to the effective time of the Merger will be converted into the right to receive one newly issued ET Series C Preferred Unit;

 

   

each ETO Series D Preferred Unit issued and outstanding immediately prior to the effective time of the Merger will be converted into the right to receive one newly issued ET Series D Preferred Unit;

 

   

each ETO Series E Preferred Unit issued and outstanding immediately prior to the effective time of the Merger will be converted into the right to receive one newly issued ET Series E Preferred Unit;

 

   

each ETO Series F Preferred Unit issued and outstanding immediately prior to the effective time of the Merger will be converted into the right to receive one newly issued ET Series F Preferred Unit; and

 

   

each ETO Series G Preferred Unit issued and outstanding immediately prior to the effective time of the Merger will be converted into the right to receive one newly issued ET Series G Preferred Unit.

By virtue of the Merger, each ETO Preferred Unit will be cancelled and cease to exist as of the effective time of the Merger.

In addition, under the terms of the Merger Agreement, (i) each issued and outstanding ETO Common Unit, all of which are owned by ET, will be unchanged and remain outstanding, (ii) the issued and outstanding ETO Hook Units, all of which are owned by ETP Holdco, will be cancelled and converted into the right to receive 675,625,000 ET Class B Units in the aggregate and (iii) the General Partner Interest (as defined in the ETO Partnership Agreement), which is owned by ETO GP, will be unchanged and remain outstanding.

Exchange Procedures

At or prior to the effective time of the Merger, ET will deposit with an exchange agent selected by ET and mutually agreeable to ETO to serve as the exchange agent for the benefit of the holders of the ETO Preferred Units an aggregate number of ET Preferred Units to be issued in uncertificated form or book-entry form. In addition, ET will deposit with the exchange agent, as necessary from time to time after the effective time of the Merger, any distributions, if any, to which the holders of ETO Preferred Units may be entitled.

As soon as reasonably practicable after the effective time of the Merger (and not later than the fifth business day following the effective time), ET shall cause the exchange agent to mail to each holder of ETO Preferred Units, which at the effective time were converted into the right to receive the merger consideration, (i) a letter of transmittal and (ii) instructions for use in effecting the surrender of the ETO Preferred Units in exchange for ET Preferred Units (which will be issued in book-entry form). Such holders will be issued the ET Preferred Units to which they are entitled upon the surrender to the exchange agent of such ETO Preferred Units and a duly completed and validly executed letter of transmittal and any other documents required by the exchange agent.

Termination of the Exchange Fund

Any portion of the exchange fund that remains unclaimed for one year after the effective time of the Merger will be delivered to ET. Thereafter, any holder of ETO Preferred Units will be entitled to look only to ET for delivery of the merger consideration, and payment of any distributions payable or issuable, as contemplated by the Merger Agreement, without any interest thereon. None of the surviving entity in the Merger, ET, the

 

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exchange agent or any other person will be liable to any former holder of ETO Preferred Units or ET Preferred Units for any amount properly delivered to a public official pursuant to applicable abandoned property, escheat or similar laws. Immediately before any portion of the exchange fund would otherwise escheat to or become the property of any governmental entity, such amount will, to the extent permitted by applicable law, become the property of ET free and clear of all claims or interest of any person previously entitled thereto.

Lost, Stolen or Destroyed Unit Certificates

If a certificate for ETO Preferred Units has been lost, stolen or destroyed, then before the person holding the certificate is entitled to receive the applicable merger consideration, such person will need to make an affidavit of that fact and if required by ET, post a bond, in a reasonable amount as ET may direct, as indemnity against any claim that may be made against ET or the exchange agent with respect to such certificate.

Organizational Documents

At the effective time of the Merger, the certificate of limited partnership of ETO as in effect immediately prior to the effective time of the Merger will be the certificate of limited partnership of the surviving entity in the Merger, and the partnership agreement of ETO as in effect immediately prior to the effective time of the Merger will be the partnership agreement of the surviving entity in the Merger.

Representations and Warranties

The Merger Agreement contains customary representations and warranties by each of the parties to the Merger Agreement that are subject, in some cases, to specified exceptions and qualifications contained in the Merger Agreement. These representations and warranties relate to, among other things, the organization, good standing and qualification to do business, capitalization and the power and authority relating to the execution, delivery and performance of the parties’ respective obligations under the Merger Agreement.

Stock Exchange Listing and Delisting

ET has agreed to cause the Retail ET Preferred Units to be issued in the Merger to be approved for listing on the NYSE subject to official notice of issuance, prior to the closing date of the Merger.

Conditions to the Completion of the Merger

Under the Merger Agreement, the respective obligations of ET, ETO and Merger Sub to complete the Merger are subject to the satisfaction or waiver at or prior to the closing of the following conditions:

 

   

No injunction, order or decree by any court or other governmental entity of competent jurisdiction shall have been entered and shall continue to be in effect, no law shall have been adopted or be effective, and no agreement with any governmental entity shall be in effect, in each case that prohibits, prevents or makes unlawful the consummation of the Merger or the other transactions contemplated by the Merger Agreement;

 

   

The representations and warranties of each party must be true and correct in all material respects both at and as of the date of the Merger Agreement and at and as of the closing date of the Merger as though made at and as of the closing date of the Merger.

 

   

The registration statement of which this prospectus forms a part must have become effective under the Securities Act and must not be the subject of any stop order issued by the SEC or any pending proceedings initiated or threatened by the SEC seeking such a stop order.

Termination

ET and ETO may terminate the Merger Agreement and abandon the Merger at any time prior to the effective time of the Merger by mutual written consent of ET and ETO.

 

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Expenses

Whether or not the Merger is consummated, all costs and expenses incurred in connection with the Merger Agreement will be paid by the party incurring such expenses.

Amendment and Waiver

At any time prior to the effective time of the Merger, the Merger Agreement may be modified or amended by written agreement of each of the parties or, in the case of a waiver, by the party against whom the waiver is to be effective.

 

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MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES OF THE MERGER

The following is a discussion of the material U.S. federal income tax consequences of the Merger that may be relevant to ETO Preferred Unitholders. This discussion is based upon current provisions of the Code, existing and proposed Treasury regulations promulgated under the Code (the “Treasury Regulations”) and current administrative rulings and court decisions, all of which are subject to change, possibly with retroactive effect. Changes in these authorities may cause the tax consequences to vary substantially from the consequences described below.

This discussion does not purport to be a complete discussion of all U.S. federal income tax consequences of the Merger. Moreover, the discussion focuses on ETO Preferred Unitholders who are individual citizens or residents of the United States (for U.S. federal income tax purposes) and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, employee benefit plans, foreign persons, financial institutions, insurance companies, real estate investment trusts (REITs), individual retirement accounts (IRAs), mutual funds, traders in securities that elect mark-to-market, persons who hold ETO Preferred Units (who will hold ET Preferred Units after the Merger) as part of a hedge, straddle or conversion transaction, persons who acquired ETO Preferred Units by gift, or directors and employees of ETO that received (or are deemed to receive) ETO Preferred Units as compensation or through the exercise (or deemed exercise) of options, unit appreciation rights, phantom units or restricted units granted under an ETO equity incentive plan. Also, the discussion assumes that the ETO Preferred Units are held as capital assets at the time of the Merger (generally, property held for investment).

Neither ET nor ETO has sought a ruling from the IRS with respect to any of the tax consequences discussed below, and the IRS would not be precluded from taking positions contrary to those described herein. As a result, no assurance can be given that the IRS will agree with all of the tax characterizations and the tax consequences described below. Some tax aspects of the Merger are not certain, and no assurance can be given that the statements contained herein with respect to tax matters would be sustained by a court if contested by the IRS. Furthermore, the tax treatment of the Merger may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

Accordingly, ETO strongly urges each ETO Preferred Unitholder to consult with, and depend upon, such unitholder’s own tax advisor in analyzing the U.S. federal, state, local and foreign tax consequences particular to the unitholder of the Merger.

Assumptions Related to the U.S. Federal Income Tax Treatment of the Merger

The expected U.S. federal income tax consequences of the Merger are dependent upon ET and ETO being treated as partnerships for U.S. federal income tax purposes at the time of the Merger. If ET or ETO were to be treated as a corporation for U.S. federal income tax purposes at the time of the Merger, the consequences of the merger would be materially different. If ET were to be treated as a corporation for U.S. federal income tax purposes, the Merger would likely be a fully taxable transaction to ETO Preferred Unitholders.

The discussion below assumes that each of ET and ETO will be classified as a partnership for U.S. federal income tax purposes at the time of the Merger.

U.S. Federal Income Tax Treatment of the Merger

Upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will merge with and into ETO. As a result of the Merger, the separate existence of Merger Sub will cease, and ETO will continue as the surviving entity in the Merger and a direct, wholly owned subsidiary of ET. For U.S. federal income tax purposes, the Merger is intended to be a “merger” of ET and ETO within the meaning of Treasury Regulations promulgated under Section 708 of the Code, with ET being treated as the resulting partnership and ETO being treated as the terminated partnership. As a result, each holder of ETO Preferred Units will be treated as a partner of ET for U.S. federal income tax purposes following the Merger.

 

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As a result of ET surviving the Merger for U.S. federal income tax purposes, the following transactions will be deemed to occur for U.S. federal income tax purposes: (1) ETO will be deemed to contribute its assets to ET in exchange for (i) the issuance to ETO of ET Preferred Units and ET Class B Units and (ii) the assumption of ETO’s liabilities and (2) ETO will be deemed to liquidate, distributing (i) ET Preferred Units to the ETO Preferred Unitholders in exchange for such ETO Preferred Units and (ii) ET Class B Units to ETP Holdco in exchange for ETO Hook Units (the “Assets-Over Form”).

The remainder of this discussion, except as otherwise noted, assumes that the Merger and the transactions contemplated thereby will be treated for U.S. federal income tax purposes in the manner described above.

Tax Consequences of the Merger to ETO

Under the Assets-Over Form described above, ETO will be deemed to contribute all of its assets to ET in exchange for ET Preferred Units, ET Class B Units and the assumption of ETO’s liabilities. In general, the deemed contribution of assets from ETO to ET in exchange for ET Preferred Units and ET Class B Units is not expected to result in the recognition of gain or loss by ETO.

Further, under the disguised sale rules, a contribution of cash or other property by a partner to a partnership and a transfer of property (other than an interest in such partnership) by the partnership to such partner, may, in certain circumstances, also be characterized, in whole or in part, as a “disguised sale” of property by the partnership to the partner, rather than as a non-taxable distribution of such property by the partnership. Although not contemplated, contributions of cash or other property to ETO after the date of the Merger Agreement and prior to the effective time of the Merger, if any, may be treated as part of a “disguised sale” of a portion of the ET Preferred Units received in the Merger and may result in gain to ETO. Any such taxable gain recognized by ETO as part of a “disguised sale” would be allocated pursuant to the partnership agreement of ETO.

Tax Consequences of the Merger to ETO Preferred Unitholders

Under the Assets-Over Form, ETO Preferred Unitholders will be deemed to receive distributions in liquidation of ETO consisting of ET Preferred Units. In general, the receipt of ET Preferred Units is not expected to result in the recognition of taxable gain or loss to such unitholders.

An ETO Preferred Unitholder has an initial tax basis in its ETO Preferred Units equal to the amount such ETO Preferred Unitholder paid for such ETO Preferred Units. That basis has generally not been and will not be increased or decreased by any allocation of income, gain, loss or deduction by ETO to such ETO Preferred Unitholder or by any distribution to such ETO Preferred Unitholder. As a result, an ETO Preferred Unitholder should have an initial aggregate tax basis in the ET Preferred Units that such ETO Preferred Unitholder receives in the Merger equal to the amount such ETO Preferred Unitholder paid for such ETO Preferred Units.

As a result of the Assets-Over Form, an ETO Preferred Unitholder will have a holding period in the ET Preferred Units received in the Merger that is not determined by reference to its holding period in its ETO Preferred Units exchanged therefor. Instead, such ETO Preferred Unitholder’s holding period in the ET Preferred Units received in the Merger that are attributable to ETO’s capital assets or assets used in its business as defined in Section 1231 of the Code will include ETO’s holding period in those assets. The holding period for ET Preferred Units received by an ETO Preferred Unitholder attributable to other assets of ETO, such as inventory and receivables, will begin on the day following the Merger.

 

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MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES OF ET PREFERRED UNIT OWNERSHIP

The tax consequences to you of the ownership of ET Preferred Units received in the Merger will depend in part on your own tax circumstances. This section should be read in conjunction with the risk factors included under the caption “Tax Risks to Unitholders” in ET’s Annual Report on Form 10-K for the year ended December 31, 2020, which is attached to this prospectus as Annex C, and under the caption “Tax Risks of Holding ET Preferred Units” in this prospectus. The following discussion is limited as described herein. You are urged to consult with your own tax advisor about the federal, state, local and foreign tax consequences particular to your circumstances.

This section is a summary of the material U.S. federal income tax consequences that may be relevant to individual citizens or residents of the United States owning ET Preferred Units received in the Merger and, unless otherwise noted in the following discussion, is the opinion of Latham & Watkins LLP, counsel to our general partner and us, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”), existing and proposed Treasury regulations promulgated under the Internal Revenue Code (the “Treasury Regulations”) and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Energy Transfer LP and our operating subsidiaries.

The following discussion does not comment on all federal income tax matters affecting us or holders of ET Preferred Units received in the Merger and does not describe the application of the alternative minimum tax that may be applicable to certain holders of ET Preferred Units received in the Merger. Moreover, the discussion focuses on holders of ET Preferred Units who are individual citizens or residents of the United States and has only limited application to corporations, estates, entities treated as partnerships for U.S. federal income tax purposes, trusts, nonresident aliens, U.S. expatriates and former citizens or long-term residents of the United States or other unitholders subject to specialized tax treatment, such as banks, insurance companies and other financial institutions, tax-exempt institutions, foreign persons (including, without limitation, controlled foreign corporations, passive foreign investment companies and foreign persons eligible for the benefits of an applicable income tax treaty with the United States), individual retirement accounts (IRAs), real estate investment trusts (REITs) or mutual funds, dealers in securities or currencies, traders in securities, U.S. persons whose “functional currency” is not the U.S. dollar, persons holding their ET Preferred Units as part of a “straddle,” “hedge,” “conversion transaction” or other risk reduction transaction, persons subject to special tax accounting rules as a result of any item of gross income with respect to our units being taken into account in an applicable financial statement and persons deemed to sell their ET Preferred Units under the constructive sale provisions of the Internal Revenue Code. In addition, the discussion only comments, to a limited extent, on state, local and foreign tax consequences. Accordingly, we encourage each holder of ET Preferred Units received in the Merger to consult his own tax advisor in analyzing the state, local and foreign tax consequences particular to him of the ownership or disposition of ET Preferred Units and potential changes in applicable laws.

No ruling has been requested from the Internal Revenue Service (the “IRS”) regarding our characterization as a partnership for tax purposes. Instead, we will rely on opinions of Latham & Watkins LLP. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the ET Preferred Units, including the prices at which such units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution and thus will be borne indirectly by our unitholders (including holders of the ET Preferred Units) and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

 

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All statements as to matters of U.S. federal income tax law and legal conclusions with respect thereto, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Latham & Watkins LLP and are based on the accuracy of the representations made by us and our general partner.

Notwithstanding the above, and for the reasons described below, Latham & Watkins LLP has not rendered an opinion with respect to the following specific federal income tax issues: (i) the treatment of a holder of ET Preferred Units whose ET Preferred Units are loaned to a short seller to cover a short sale of ET Preferred Units (see “—Tax Consequences of ET Preferred Unit Ownership—Treatment of Short Sales”); (ii) whether holders of ET Preferred Units will be treated as partners that receive guaranteed payments for the use of capital on their ET Preferred Units (see “—Limited Partner Status”); and (iii) whether distributions with respect to the ET Preferred Units will be treated as unrelated business taxable income (see “—Tax-Exempt Organizations and Other Investors”).

Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partnership or the partner unless the amount of cash distributed to him is in excess of the partner’s adjusted basis in his partnership interest. Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the transportation and processing of certain minerals and natural resources, including crude oil, natural gas and other products of a type that are produced in a petroleum refinery or natural gas processing plant, the retail and wholesale marketing of propane, the transportation of propane and natural gas liquids, certain related hedging activities, certain activities that are intrinsic to other qualifying activities, and our allocable share of our subsidiaries’ income from these sources. Other types of qualifying income include interest (other than from a financial business), dividends, real property rents, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 3% of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Latham & Watkins LLP is of the opinion that at least 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.

The IRS has made no determination as to our status or the status of our operating subsidiaries for federal income tax purposes. Instead, we will rely on the opinion of Latham & Watkins LLP on such matters. It is the opinion of Latham & Watkins LLP that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below that:

 

   

We will be classified as a partnership for federal income tax purposes;

 

   

Each of our operating subsidiaries will, except as otherwise identified to Latham & Watkins LLP, be disregarded as an entity separate from us or will be treated as a partnership for federal income tax purposes; and

 

   

Each commodity hedging transaction that we treat as resulting in qualifying income has been and will be appropriately identified as a hedging transaction pursuant to applicable Treasury Regulations, and has been and will be associated with oil, gas or products thereof that are held or to be held by us in activities that Latham & Watkins LLP has opined or will opine result in qualifying income.

 

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In rendering its opinion, Latham & Watkins LLP has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Latham & Watkins LLP has relied include:

 

   

Neither we nor any of our partnership or limited liability company subsidiaries, other than those identified as such to Latham & Watkins LLP, have elected or will elect to be treated as a corporation for U.S. federal income tax purposes; and

 

   

For each taxable year, more than 90% of our gross income has been and will be income of the type that Latham & Watkins LLP has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.

We believe that these representations have been true in the past, are true as of the date hereof and expect that these representations will continue to be true in the future.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we were treated as an association taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as taxable dividend income, to the extent of our current and accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his ET Preferred Units, or taxable capital gain, after the unitholder’s tax basis in his ET Preferred Units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the ET Preferred Units.

The discussion below is based on Latham & Watkins LLP’s opinion that we will be classified as a partnership for federal income tax purposes.

Limited Partner Status

The tax treatment of the ET Preferred Units is uncertain. As such, Latham & Watkins LLP is unable to opine as to the tax treatment of the ET Preferred Units. Although the IRS may disagree with this treatment, we will treat holders of ET Preferred Units as partners entitled to a guaranteed payment for the use of capital on their ET Preferred Units. If the ET Preferred Units are not partnership interests, they would likely constitute indebtedness for federal income tax purposes and distributions on the ET Preferred Units would constitute ordinary interest income to holders of ET Preferred Units. The remainder of this discussion assumes that the ET Preferred Units are partnership interests for federal income tax purposes.

A beneficial owner of ET Preferred Units whose ET Preferred Units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those ET Preferred Units for federal income tax purposes. Please read “—Tax Consequences of ET Preferred Unit Ownership—Treatment of Short Sales.”

 

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Tax Consequences of ET Preferred Unit Ownership

Treatment of Distributions on ET Preferred Units

We will treat distributions on the ET Preferred Units as guaranteed payments for the use of capital that will generally be taxable to the holders of ET Preferred Units as ordinary income and will be deductible by us. Although a holder of ET Preferred Units will recognize taxable income from the accrual of such a guaranteed payment (even in the absence of a contemporaneous cash distribution), we anticipate accruing and making the guaranteed payment distributions semi-annually or quarterly, as applicable. Except in the case of our liquidation, the holders of ET Preferred Units are generally not anticipated to share in our items of income, gain, loss or deduction, nor will we allocate any share of our nonrecourse liabilities to such holders. See the applicable description of “Liquidation Rights” under “Comparison of Preferred Unitholders’ Rights and Description of ET Preferred Units.”

If the distributions on the ET Preferred Units are not respected as guaranteed payments for the use of capital, holders of ET Preferred Units may be treated as receiving an allocable share of our gross income equal to their cash distributions, to the extent we have sufficient gross income to make such allocations of gross income. In the event there is not sufficient gross income to match such distributions, the distributions on the ET Preferred Units would reduce the capital accounts of the ET Preferred Units, requiring a subsequent allocation of income or gain to provide the ET Preferred Units with their liquidation preference, if possible.

Basis of ET Preferred Units

A former holder of ETO Preferred Units will have an initial aggregate tax basis in the ET Preferred Units received in the Merger that is determined in the manner described in “Material U.S. Federal Income Tax Consequences of the Merger—Tax Consequences of the Merger to ETO Preferred Unitholders.” The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all of those interests.

Allocation of Income, Gain, Loss and Deduction

After giving effect to special allocation provisions with respect to our other classes of units, our items of income, gain, loss and deduction generally will be allocated amongst our common unitholders and our general partner in accordance with their percentage interests in us. If the capital accounts of the common unitholders have been reduced to zero, losses will be allocated to the ET Preferred Units until the capital accounts of the ET Preferred Units are reduced to zero. If ET Preferred Units are allocated losses in any taxable period, net income or, to the extent necessary, gross income from a subsequent taxable period, if any, would be allocated to the ET Preferred Units in a manner designed to provide their liquidation preferences.

Limitations on Deductibility of Losses

Holders of ET Preferred Units will only be allocated loss once the capital accounts of the common unitholders have been reduced to zero. Please read “—Tax Consequences of ET Preferred Unit Ownership—Allocation of Income, Gain, Loss and Deduction.” Although it is not anticipated that a holder of ET Preferred Units would be allocated loss, the deductibility of any such loss allocation may be limited for various reasons. In the event that you are allocated loss as a holder of ET Preferred Units, please consult your tax advisor as to the application of any limitation to the deductibility of that loss.

Entity-Level Collections

If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any holder of ET Preferred Units, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as an advance on a guaranteed payment to the holder of ET Preferred Units on whose behalf

 

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the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Treatment of Short Sales

A unitholder whose ET Preferred Units are loaned to a “short seller” to cover a short sale of ET Preferred Units may be considered as having disposed of such units. If so, he would no longer be treated for tax purposes as a partner with respect to those ET Preferred Units during the period of the loan and may recognize gain or loss from the disposition.

Because there is no direct or indirect controlling authority on the issue relating to partnership interests, Latham & Watkins LLP has not rendered an opinion regarding the tax treatment of a unitholder whose ET Preferred Units are loaned to a short seller to cover a short sale of ET Preferred Units; therefore, holders of ET Preferred Units desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their ET Preferred Units. The IRS has previously announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read “—Disposition of ET Preferred Units—Recognition of Gain or Loss on Sale.”

Tax Rates

Currently, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 37.0% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than twelve months) of individuals is 20%. Such rates are subject to change by new legislation at any time.

In addition, a 3.8% Medicare tax (“NIIT”) is imposed on certain net investment income earned by individuals, estates and trusts. For these purposes, net investment income generally includes guaranteed payments, a unitholder’s allocable share of our income, if any, and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder’s net investment income or (ii) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if the unitholder is married and filing separately) or $200,000 (in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins for such taxable year. The U.S. Department of the Treasury and the IRS have issued Treasury Regulations that provide guidance regarding the NIIT. Unitholders that receive ET Preferred Units in the Merger are urged to consult with their tax advisors as to the impact of the NIIT on an investment in the ET Preferred Units.

For taxable years beginning after December 31, 2017, and ending on or before December 31, 2025, a non-corporate unitholder may be entitled to a deduction equal to 20% of its “qualified business income” attributable to its interest in a partnership, subject to certain limitations. As described above, we will treat distributions on the ET Preferred Units as guaranteed payments for the use of capital, and under the applicable Treasury Regulations, a guaranteed payment for the use of capital will not be taken into account for purposes of computing qualified business income. As a result, distributions received by the holders of the ET Preferred Units will not be eligible for the 20% deduction for qualified business income. Unitholders that receive ET Preferred Units in the Merger should consult their tax advisors regarding the availability of the deduction for qualified business income.

 

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Tax Treatment of Operations

Accounting Method and Taxable Year

We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each holder of ET Preferred Units will be required to include in its tax return its income from our guaranteed payments for each taxable year ending within or with its taxable year. In addition, a holder of ET Preferred Units who has a taxable year ending on a date other than December 31 and who disposes of all of his ET Preferred Units following the close of our taxable year but before the close of his taxable year will be required to include in income for his taxable year his income from more than one year of guaranteed payments.

Disposition of ET Preferred Units

Recognition of Gain or Loss on Sale

Gain or loss will be recognized on a sale of ET Preferred Units equal to the difference between the amount realized and the tax basis of the holder of ET Preferred Units for the ET Preferred Units sold. Such holder’s amount realized will be measured by the sum of the cash and the fair market value of other property received by him.

Generally, gain or loss recognized by a holder of ET Preferred Units, other than a “dealer” in ET Preferred Units, on the sale or exchange of an ET Preferred Unit will be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of ET Preferred Units held for more than twelve months will generally be taxed at the U.S. federal income tax rate applicable to long-term capital gains. Capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations. Both ordinary income and capital gain recognized on a sale of ET Preferred Units may be subject to the NIIT in certain circumstances. See “—Tax Consequences of ET Preferred Unit Ownership—Tax Rates.”

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify partnership interests transferred with an ascertainable holding period to elect to use the actual holding period of the partnership interests transferred. Thus, according to the ruling discussed above, a holder of ET Preferred Units will be unable to select high or low basis ET Preferred Units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific ET Preferred Units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of ET Preferred Units transferred must consistently use that identification method for all subsequent sales or exchanges of ET Preferred Units. A holder of ET Preferred Units considering the purchase of additional partnership interests or a sale of partnership interests purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

 

   

a short sale;

 

   

an offsetting notional principal contract; or

 

   

a futures or forward contract;

 

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in each case, with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Recognition of Gain or Loss on Redemption

The receipt by a holder of amounts in redemption of his ET Preferred Units generally will result in the recognition of taxable gain to the holder for U.S. federal income tax purposes only if and to the extent the amount of redemption proceeds received exceeds his tax basis in all the units held by him immediately before the redemption. Any such redemption of ET Preferred Units would result in the recognition of taxable loss to the holder for federal income tax purposes only if the holder does not hold any other units immediately after the redemption and the holder’s tax basis in the redeemed ET Preferred Units exceeds the amounts received by the holder in redemption thereof. Any taxable gain or loss recognized under the foregoing rules would be treated in the same manner as taxable gain or loss recognized on a sale of ET Preferred Units as described above in “Disposition of ET Preferred Units—Recognition of Gain or Loss on Sale.”

Allocations Between Transferors and Transferees

Holders of ET Preferred Units owning ET Preferred Units as of the applicable record date with respect to an applicable distribution payment date will be entitled to receive the cash distribution with respect to their ET Preferred Units on such distribution payment date. Purchasers of ET Preferred Units after such applicable record date will therefore not become entitled to receive a cash distribution on their ET Preferred Units until the next applicable record date.

Notification Requirements

A unitholder who sells any of his ET Preferred Units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker who will satisfy such requirements.

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below to a limited extent, may have substantially adverse tax consequences to them. If you are a tax-exempt entity or a foreign person, you should consult your tax advisor before investing in the ET Preferred Units.

Employee benefit plans and most other organizations exempt from federal income tax, including IRAs and other retirement plans, are subject to federal income tax on unrelated business taxable income (“UBTI”). We will treat distributions on the ET Preferred Units as guaranteed payments for the use of capital. The treatment of guaranteed payments for the use of capital to tax-exempt investors is not certain. Such payments may be treated as UBTI for federal income tax purposes, and Latham & Watkins LLP is unable to opine with respect to whether

 

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such payments constitute UBTI for federal income tax purposes. If you are a tax-exempt entity, you should consult your tax advisor with respect to the consequences of owning the ET Preferred Units received in the Merger.

Non-resident aliens and foreign corporations, trusts or estates that own units may be considered to be engaged in business in the United States because of the ownership of ET Preferred Units. As a consequence, they will be required to file federal tax returns to report their income from guaranteed payments and pay federal income tax on such income in a manner similar to a taxable U.S. holder. Moreover, under rules applicable to publicly traded partnerships, distributions to foreign unitholders are subject to withholding at the highest applicable effective tax rate. Each foreign holder of ET Preferred Units must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN, W-8BEN-E or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns ET Preferred Units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our earnings and profits, as adjusted for changes in the foreign corporation’s “U.S. net equity,” that is effectively connected with the conduct of a U.S. trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of holder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

A foreign unitholder who sells or otherwise disposes of an ET Preferred Unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Gain on the sale or disposition of an ET Preferred Unit will be treated as effectively connected with a U.S. trade or business to the extent that a foreign unitholder would recognize gain effectively connected with a U.S. trade or business upon the hypothetical sale of our assets at fair market value on the date of the sale or exchange of that ET Preferred Unit. Such gain shall be reduced by certain amounts treated as effectively connected with a U.S. trade or business attributable to certain real property interests, as set forth in the following paragraph.

Under the Foreign Investment in Real Property Tax Act, a foreign holder of ET Preferred Units (other than certain “qualified foreign pension funds” (or an entity all of the interests of which are held by such a qualified foreign pension fund), which generally are entities or arrangements that are established and regulated by foreign law to provide retirement or other pension benefits to employees, do not have a single participant or beneficiary that is entitled to more than 5% of the assets or income of the entity or arrangement and are subject to certain preferential tax treatment under the laws of the applicable foreign country), generally will be subject to U.S. federal income tax upon the sale or disposition of an ET Preferred Unit if (i) he owned (directly or constructively applying certain attribution rules) more than 5% of the applicable series of ET Preferred Units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the applicable ET Preferred Units or the five-year period ending on the date of disposition. Currently, more than 50% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future. Therefore, foreign holders of ET Preferred Units may be subject to federal income tax on gain from the sale or disposition of their units.

Upon the sale, exchange or other disposition of an ET Preferred Unit by a foreign unitholder, the transferee is generally required to withhold 10% of the amount realized on such sale, exchange or other disposition if any portion of the gain on such sale, exchange or other disposition would be treated as effectively connected with a U.S. trade or business. The U.S. Department of the Treasury and the IRS have recently issued final regulations providing guidance on the application of these rules for transfers of certain publicly traded partnership interests, including transfers of the ET Preferred Units. Under these regulations, the “amount realized” on a transfer of an

 

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ET Preferred Unit will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and such broker will generally be responsible for the relevant withholding obligations. Distributions made to a holder of an ET Preferred Unit may also be subject to withholding under these rules to the extent a portion of a distribution is attributable to an amount in excess of our cumulative net income that has not previously been distributed. The U.S. Department of the Treasury and the IRS have provided that these rules will generally not apply to transfers of, or distributions on, ET Preferred Units occurring before January 1, 2022. Foreign unitholders that receive ET Preferred Units in the Merger should consult their tax advisors regarding the impact of these rules on an investment in ET Preferred Units.

Additional withholding requirements may also affect certain foreign unitholders. Please read “—Administrative Matters—Additional Withholding Requirements.”

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Latham & Watkins LLP can assure unitholders that receive ET Preferred Units in the Merger that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the ET Preferred Units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. For taxable years beginning on or before December 31, 2017, the Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. Our partnership agreement names our general partner as our Tax Matters Partner.

The Tax Matters Partner has made and will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Pursuant to the Bipartisan Budget Act of 2015, for taxable years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it may assess and collect any taxes (including any

 

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applicable penalties and interest) resulting from such audit adjustment directly from us. Similarly, for such taxable years, if the IRS makes audit adjustments to income tax returns filed by an entity in which we are a member or partner, it may assess and collect any taxes (including penalties and interest) resulting from such audit adjustment directly from such entity. Generally, we expect to elect to have our general partner and its unitholders take any such audit adjustment into account in accordance with their interests in us during the tax year under audit, but there can be no assurance that such election will be effective in all circumstances. If we are unable to have our general partner and its unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own our units during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties, and interest, our cash available for distribution to holders of the ET Preferred Units might be substantially reduced.

Additionally, pursuant to the Bipartisan Budget Act of 2015, the Internal Revenue Code will no longer require that we designate a Tax Matters Partner. Instead, for taxable years beginning after December 31, 2017, we will be required to designate a partner, or other person, with a substantial presence in the United States as the partnership representative (“Partnership Representative”). The Partnership Representative will have the sole authority to act on our behalf for purposes of, among other things, U.S. federal income tax audits and judicial review of administrative adjustments by the IRS. If we do not make such a designation, the IRS can select any person as the Partnership Representative. We have designated our general partner as the Partnership Representative. Further, any actions taken by us or by the Partnership Representative on our behalf with respect to, among other things, U.S. federal income tax audits and judicial review of administrative adjustments by the IRS, will be binding on us and all of the unitholders.

Additional Withholding Requirements

Subject to the proposed Treasury Regulations discussed below, withholding taxes may apply to certain types of payments made to “foreign financial institutions” (as specially defined in the Internal Revenue Code) and certain other foreign entities. Specifically, a 30% withholding tax may be imposed on interest, dividends and other fixed or determinable annual or periodical gains, profits and income from sources within the United States (“FDAP Income”), or gross proceeds from the sale or other disposition of any property of a type that can produce interest or dividends from sources within the United States (“Gross Proceeds”), paid to a foreign financial institution or to a “non-financial foreign entity” (as specially defined in the Internal Revenue Code), unless (i) the foreign financial institution undertakes certain diligence and reporting, (ii) the non-financial foreign entity either certifies it does not have any substantial U.S. owners or furnishes identifying information regarding each substantial U.S. owner or (iii) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules. If the payee is a foreign financial institution and is subject to the diligence and reporting requirements in clause (i) above, it must enter into an agreement with the U.S. Department of the Treasury requiring, among other things, that it undertake to identify accounts held by certain U.S. persons or U.S.-owned foreign entities, annually report certain information about such accounts, and withhold 30% on payments to noncompliant foreign financial institutions and certain other account holders. Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing these requirements may be subject to different rules.

These rules generally apply to payments of FDAP Income currently and, while these rules generally would have applied to payments of relevant Gross Proceeds made on or after January 1, 2019, recently proposed Treasury Regulations eliminate these withholding taxes on payments of Gross Proceeds entirely. Unitholders generally may rely on these proposed Treasury Regulations until the Final Treasury Regulations are issued. Thus, to the extent we have FDAP Income that is not treated as effectively connected with a U.S. trade or business (please read “—Tax-Exempt Organizations and Other Investors”), unitholders who are foreign financial institutions or certain other foreign entities, or persons that hold their ET Preferred Units through such foreign entities, may be subject to withholding on distributions they receive from us, or their distributive share of our income, pursuant to the rules described above.

 

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Unitholders that receive ET Preferred Units in the Merger should consult their own tax advisors regarding the potential application of these withholding provisions to their investment in the ET Preferred Units.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

 

   

the name, address and taxpayer identification number of the beneficial owner and the nominee;

 

   

whether the beneficial owner is:

 

   

a person that is not a U.S. person;

 

   

a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

 

   

a tax-exempt entity;

 

   

the amount and description of units held, acquired or transferred for the beneficial owner; and

 

   

specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from dispositions.

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $280 per failure, up to a maximum of $3,426,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties

Certain penalties may be imposed on taxpayers as a result of an underpayment of tax that is attributable to one or more specified causes, including: (i) negligence or disregard of rules or regulations, (ii) substantial understatements of income tax, (iii) substantial valuation misstatements and (iv) the disallowance of claimed tax benefits by reason of a transaction lacking economic substance or failing to meet the requirements of any similar rule of law. Except with respect to the disallowance of claimed tax benefits by reason of a transaction lacking economic substance or failing to meet the requirements of any similar rule of law, however, no penalty will be imposed for any portion of any such underpayment if it is shown that there was a reasonable cause for the underpayment of that portion and that the taxpayer acted in good faith regarding the underpayment of that portion. With respect to substantial understatements of income tax, the amount of any understatement subject to penalty generally is reduced by that portion of the understatement which is attributable to a position adopted on the return (A) for which there is, or was, “substantial authority” or (B) as to which there is a reasonable basis and the relevant facts of that position are adequately disclosed on the return. If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must adequately disclose the relevant facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty.

Recent Legislative Developments

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in the ET Preferred Units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of Congress and the President propose and consider substantive changes to the existing federal income tax laws that affect the tax treatment of publicly traded partnerships. Any

 

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modification to the federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for federal income tax purposes. Please read “—Partnership Status.” We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us, and any such changes could negatively impact the value of an investment in the ET Preferred Units.

State, Local, Foreign and Other Tax Considerations

In addition to federal income taxes, you will likely be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each unitholder that receives ET Preferred Units in the Merger should consider their potential impact on his investment in us. We currently own property or do business in many states. Several of these states impose a personal income tax on individuals; certain of these states also impose an income tax on corporations and other entities. We may also own property or do business in other jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “—Tax Consequences of ET Preferred Unit Ownership—Entity-Level Collections.” Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each holder of ET Preferred Units to investigate the legal and tax consequences, under the laws of pertinent states, localities and foreign jurisdictions, of his investment in us. Accordingly, each unitholder that receives ET Preferred Units in the Merger is urged to consult his own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each holder of ET Preferred Units to file all state, local and foreign, as well as U.S. federal tax returns, that may be required of him. Latham & Watkins LLP has not rendered an opinion on the state tax, local tax, alternative minimum tax or foreign tax consequences of an investment in us.

 

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COMPARISON OF PREFERRED UNITHOLDERS’ RIGHTS AND DESCRIPTION OF ET PREFERRED UNITS

The rights of ETO Preferred Unitholders are currently governed by the ETO Partnership Agreement and the DRULPA. The rights of the ET Preferred Unitholders will be governed by the ET Partnership Agreement, as amended by Amendment No. 8 to the ET Partnership Agreement, a form of which is attached to this prospectus as Annex B, and the DRULPA. Unless the context otherwise requires, the description of the rights of ET Preferred Unitholders appearing in this section describe the rights provided for in the ET Partnership Agreement, as amended by Amendment No. 8 to the ET Partnership Agreement.

Although the preferences, rights, powers, duties and obligations of the ET Preferred Units are intended to be substantially equivalent to the preferences, rights, powers, duties and obligations of the ETO Preferred Units prior to the Merger, there are certain differences between the ET Partnership Agreement and the ETO Partnership Agreement that could affect the rights of the holders of ET Preferred Units. Certain of these differences are described below.

The following description summarizes the material rights of ETO Preferred Unitholders and ET Preferred Unitholders following the effective time of the Merger but does not purport to be a complete statement of all of the provisions of the ETO Partnership Agreement and ET Partnership Agreement relating to the ETO Preferred Units or the ET Preferred Units, or a complete description of the specific provisions referred to in this summary. The identification of specific differences is not intended to indicate that other equally significant or more significant differences do not exist. ETO Preferred Unitholders should read carefully the relevant provisions of Amendment No. 8 to the ET Partnership Agreement, a form of which is attached to this prospectus as Annex B. This summary is qualified in its entirety by reference to the DRULPA, the ETO Partnership Agreement and the ET Partnership Agreement, as amended by Amendment No. 8 to the ET Partnership Agreement. Unless context otherwise requires, references in this section to the “ET Partnership Agreement” refer to the ET Partnership Agreement, as amended by Amendment No. 8 thereto. Capitalized terms used in the table below and not otherwise defined in this prospectus are used as defined in the applicable partnership agreement. Copies of the other documents referred to in this summary may be obtained as described in the section entitled “Where You Can Find More Information” beginning on page 84.

Series A Preferred Units

 

ETO Series A Preferred Unitholders

  

ET Series A Preferred Unitholders

ISSUANCE AND DISTRIBUTIONS
In November 2017, ETO issued and sold 950,000 ETO Series A Preferred Units at a price to the public of $1,000 per unit.    By adoption of Amendment No. 8 to the ET Partnership Agreement, ET will create the ET Series A Preferred Units, which, following the effective time of the Merger, will (i) rank pari passu with the other ET Preferred Units with respect to distributions and rights upon liquidation and (ii) have substantially the same preferences, rights, powers and duties as the ETO Series A Preferred Units (other than any non-substantive differences to reflect the issuance of such securities by ET, as opposed to ETO).
Distributions on the ETO Series A Preferred Units are cumulative from the date of original issue and are payable semi-annually in arrears on the 15th day of February and August of each year up to and including    Distributions on the ET Series A Preferred Units will be cumulative                from                 , 2021 and will be payable semi-annually in arrears on the 15th day of February and August of each year up to and

 

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ET Series A Preferred Unitholders

February 15, 2023. After February 15, 2023, distributions on the ETO Series A Preferred Units will be payable quarterly in arrears on the 15th day of February, May, August and November of each year, in each case when, as, and if declared by ETO’s general partner.    including February 15, 2023. After February 15, 2023, distributions on the ET Series A Preferred Units will be payable quarterly in arrears on the 15th day of February, May, August and November of each year, in each case when, as, and if declared by ET’s general partner.
Distributions on the ETO Series A Preferred Units are payable out of amounts legally available therefor from and including the date of original issue to, but excluding February 15, 2023, at a rate of 6.250% per annum of the $1,000 liquidation preference per ETO Series A Preferred Unit (equal to $62.50 per ETO Series A Preferred Unit per annum). On and after February 15, 2023, distributions on the ETO Series A Preferred Units will accumulate for each distribution period at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR plus a spread of 4.028% per annum.    Distributions on the ET Series A Preferred Units will be payable out of amounts legally available therefor from and including the date of original issue to, but excluding February 15, 2023, at a rate of 6.250% per annum of the $1,000 liquidation preference per ET Series A Preferred Unit (equal to $62.50 per ET Series A Preferred Unit per annum). On and after February 15, 2023, distributions on the ET Series A Preferred Units will accumulate for each distribution period at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR plus a spread of 4.028% per annum.
RANKING
The ETO Series A Preferred Units, with respect to anticipated semi-annual or quarterly distributions and distributions upon the liquidation, winding-up and dissolution of ETO’s affairs, rank:    The ET Series A Preferred Units will, with respect to anticipated semi-annual or quarterly distributions and distributions upon the liquidation, winding-up and dissolution of ET’s affairs, rank:

•  senior to any junior securities (including ETO Common Units and the general partner interest);

 

•  pari passu with any parity securities (including each other series of ETO Preferred Units); and

 

•  junior to any senior securities.

  

•  senior to any junior securities (including ET Common Units and the general partner interest);

 

•  pari passu with any parity securities (including each other series of ET Preferred Units); and

 

•  junior to any senior securities.

The ETO Series A Preferred Units are subordinated to all of ETO’s and its subsidiaries’ existing and future indebtedness and other liabilities (including indebtedness outstanding under existing credit facilities, ETO’s senior notes, and any other senior securities ETO may issue in the future with respect to assets available to satisfy claims against it).    The ET Series A Preferred Units will be subordinated to all of ET’s and its subsidiaries’ existing and future indebtedness and other liabilities (including ET’s senior notes, and any other senior securities ET may issue in the future with respect to assets available to satisfy claims against it).
Under the ETO Partnership Agreement, ETO may issue junior securities from time to time in one or more series without the consent of the holders of the ETO Series A Preferred Units. ETO’s general partner has the authority to determine the designations, preferences, rights, powers, and duties of any such series before the    Under the ET Partnership Agreement, ET may issue junior securities from time to time in one or more series without the consent of the holders of the ET Series A Preferred Units. ET’s general partner has the authority to determine the designations, preferences, rights, powers, and duties of any such

 

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ETO Series A Preferred Unitholders

  

ET Series A Preferred Unitholders

issuance of any units of that series. ETO’s general partner will also determine the number of units constituting each series of securities. ETO’s ability to issue additional parity securities in certain circumstances or senior securities is limited as described below under “Voting Rights.”    series before the issuance of any units of that series. ET’s general partner will also determine the number of units constituting each series of securities. ET’s ability to issue additional parity securities in certain circumstances or senior securities is limited as described below under “Voting Rights.”
RESTRICTIONS ON DISTRIBUTIONS

ETO will not declare or pay or set aside for payment distributions on any junior securities (other than a distribution payable solely in junior securities) unless full cumulative distributions have been or contemporaneously are being paid or provided for on all outstanding ETO Series A Preferred Units and any parity securities through the most recent respective distribution periods.

 

Accumulated distributions in arrears for any past distribution period may be declared by ETO’s general partner and paid on any date fixed by ETO’s general partner, whether or not a distribution payment date, to holders of the ETO Series A Preferred Units on the record date for such payment, which may not be less than 10 days before such distribution periods.

  

ET will not declare or pay or set aside for payment distributions on any junior securities (other than a distribution payable solely in junior securities) unless full cumulative distributions have been or contemporaneously are being paid or provided for on all outstanding ET Series A Preferred Units and any parity securities through the most recent respective distribution periods.

 

Accumulated distributions in arrears for any past distribution period may be declared by ET’s general partner and paid on any date fixed by ET’s general partner, whether or not a distribution payment date, to holders of the ET Series A Preferred Units on the record date for such payment, which may not be less than 10 days before such distribution periods.

To the extent a distribution period applicable to a class of junior securities or parity securities is shorter than the distribution period applicable to the ETO Series A Preferred Units (e.g., quarterly rather than semi-annually), ETO’s general partner may declare and pay regular distributions with respect to such junior securities or parity securities so long as, at the time of declaration of such distribution, ETO’s general partner expects to have sufficient funds to pay the full distribution in respect of the ETO Series A Preferred Units on the next successive distribution payment date.    To the extent a distribution period applicable to a class of junior securities or parity securities is shorter than the distribution period applicable to the ET Series A Preferred Units (e.g., quarterly rather than semi-annually), ET’s general partner may declare and pay regular distributions with respect to such junior securities or parity securities so long as, at the time of declaration of such distribution, ET’s general partner expects to have sufficient funds to pay the full distribution in respect of the ET Series A Preferred Units on the next successive distribution payment date.
OPTIONAL REDEMPTION
At any time on or after February 15, 2023, ETO may redeem the ETO Series A Preferred Units, in whole or in part, out of amounts legally available therefor, at a redemption price of $1,000 per ETO Series A Preferred Unit plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption, whether or not declared. In addition, upon the occurrence of a Series A Rating Event (as defined below), ETO may redeem the ETO Series A Preferred Units, in whole but not in part, out of amounts    At any time on or after February 15, 2023, ET may redeem the ET Series A Preferred Units, in whole or in part, out of amounts legally available therefor, at a redemption price of $1,000 per ET Series A Preferred Unit plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption, whether or not declared. In addition, upon the occurrence of a Series A Rating Event (as defined below), ET may redeem the ET Series A Preferred Units, in whole but not in part, out

 

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ETO Series A Preferred Unitholders

  

ET Series A Preferred Unitholders

legally available therefor, at a price of $1,020 per ETO Series A Preferred Unit plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption, whether or not declared. Any such redemption would be effected only out of funds legally available for such purpose and would be subject to compliance with the provisions of the instruments governing ETO’s outstanding indebtedness. ETO must provide not less than 15 days’ and not more than 60 days’ written notice of any such redemption. ETO may undertake multiple partial redemptions.

 

“Series A Rating Event” means a change by any rating agency to the current criteria, which change results in (i) any shortening of the length of time for which the current criteria are scheduled to be in effect with respect to the ETO Series A Preferred Units, or (ii) a lower Equity Credit being given to the ETO Series A Preferred Units than the Equity Credit that would have been assigned to the ETO Series A Preferred Units by such rating agency pursuant to the current criteria. “Equity Credit” for the purposes of the ETO Series A Preferred Units means the dollar amount or percentage in relation to the stated liquidation preference amount of $1,000 per ETO Series A Preferred Unit assigned to the ETO Series A Preferred Units as equity, rather than debt, by a rating agency in evaluating the capital structure of an entity.

  

of amounts legally available therefor, at a price of $1,020 per ET Series A Preferred Unit plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption, whether or not declared. Any such redemption would be effected only out of funds legally available for such purpose and would be subject to compliance with the provisions of the instruments governing ET’s outstanding indebtedness. ET must provide not less than 15 days’ and not more than 60 days’ written notice of any such redemption. ET may undertake multiple partial redemptions.

 

“Series A Rating Event” means a change by any rating agency to the current criteria, which change results in (i) any shortening of the length of time for which the current criteria are scheduled to be in effect with respect to the ET Series A Preferred Units, or (ii) a lower Equity Credit being given to the ET Series A Preferred Units than the Equity Credit that would have been assigned to the ET Series A Preferred Units by such rating agency pursuant to the current criteria. “Equity Credit” for the purposes of the ET Series A Preferred Units means the dollar amount or percentage in relation to the stated liquidation preference amount of $1,000 per ET Series A Preferred Unit assigned to the ET Series A Preferred Units as equity, rather than debt, by a rating agency in evaluating the capital structure of an entity.

CONVERSION RIGHTS
The ETO Series A Preferred Units are not convertible into or exchangeable for any other securities or property at the option of the holder.    The ET Series A Preferred Units will not be convertible into or exchangeable for any other securities or property at the option of the holder.
LIQUIDATION RIGHTS

If necessary, the holders of outstanding ETO Series A Preferred Units will first be specially allocated items of ETO’s gross income and gain in a manner designed to cause, in the event of any liquidation, dissolution or winding up of ETO’s affairs, whether voluntary or involuntary, a liquidation preference of $1,000 per ETO Series A Preferred Unit.

 

If the amount of ETO’s gross income and gain available to be specially allocated to the ETO Series A Preferred Units is not sufficient to cause the capital account of such ETO Series A Preferred Unit to equal the

  

If necessary, the holders of outstanding ET Series A Preferred Units will first be specially allocated items of ET’s gross income and gain in a manner designed to cause, in the event of any liquidation, dissolution or winding up of ET’s affairs, whether voluntary or involuntary, a liquidation preference of $1,000 per ET Series A Preferred Unit.

 

If the amount of ET’s gross income and gain available to be specially allocated to the ET Series A Preferred Units is not sufficient to cause the capital account of such ET Series A Preferred Unit to equal the

 

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ETO Series A Preferred Unitholders

  

ET Series A Preferred Unitholders

liquidation preference of the ETO Series A Preferred Unit, then the amount that a holder of such ETO Series A Preferred Units would receive upon liquidation may be less than the ETO Series A Preferred Unit liquidation preference. Any accumulated and unpaid distributions on the ETO Series A Preferred Units and the parity securities will be paid prior to any distributions in liquidation made in accordance with capital account balances. The rights of holders of the ETO Series A Preferred Units to receive the liquidation preference will be subject to the rights of the holders of any senior securities and the proportional rights of holders of the parity securities. A consolidation or merger of ETO with or into any other entity, individually or in a series of transactions, will not be deemed to be a liquidation, dissolution or winding up of ETO’s affairs.    liquidation preference of the ET Series A Preferred Unit, then the amount that a holder of such ET Series A Preferred Units would receive upon liquidation may be less than the ET Series A Preferred Unit liquidation preference. Any accumulated and unpaid distributions on the ET Series A Preferred Units and the parity securities will be paid prior to any distributions in liquidation made in accordance with capital account balances. The rights of holders of the ET Series A Preferred Units to receive the liquidation preference will be subject to the rights of the holders of any senior securities and the proportional rights of holders of the parity securities. A consolidation or merger of ET with or into any other entity, individually or in a series of transactions, will not be deemed to be a liquidation, dissolution or winding up of ET’s affairs.
VOTING RIGHTS

Except as described below, holders of the ETO Series A Preferred Units generally have no voting rights.

 

Unless ETO has received the affirmative vote or consent of the holders of at least two-thirds of the outstanding ETO Series A Preferred Units, voting as a separate class, ETO may not adopt any amendment to the ETO Partnership Agreement that would have a material adverse effect on the terms of the ETO Series A Preferred Units.

 

In addition, unless ETO has received the affirmative vote or consent of the holders of at least two-thirds of the outstanding ETO Series A Preferred Units, voting as a class together with holders of any other parity securities upon which like voting rights have been conferred and are exercisable, ETO may not (i) create or issue any parity securities (including any additional ETO Series A Preferred Units) if the cumulative distributions payable on then outstanding ETO Series A Preferred Units (or parity securities, if applicable) are in arrears, or (ii) create or issue any senior securities.

 

On any matter on which the holders of the ETO Series A Preferred Units are entitled to vote as a class, such holders will be entitled to one vote per ETO Series A Preferred Unit

  

Except as described below, holders of the ET Series A Preferred Units generally will have no voting rights.

 

Unless ET has received the affirmative vote or consent of the holders of at least two-thirds of the outstanding ET Series A Preferred Units, voting as a separate class, ET may not adopt any amendment to the ET Partnership Agreement that would have a material adverse effect on the terms of the ET Series A Preferred Units.

 

In addition, unless ET has received the affirmative vote or consent of the holders of at least two-thirds of the outstanding ET Series A Preferred Units, voting as a class together with holders of any other parity securities upon which like voting rights have been conferred and are exercisable, ET may not (i) create or issue any parity securities (including any additional ET Series A Preferred Units) if the cumulative distributions payable on then outstanding ET Series A Preferred Units (or parity securities, if applicable) are in arrears, or (ii) create or issue any senior securities.

 

On any matter on which the holders of the ET Series A Preferred Units are entitled to vote as a class, such holders will be entitled to one vote per ET Series A Preferred Unit

 

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ETO Series A Preferred Unitholders

  

ET Series A Preferred Unitholders

TRANSFER OF UNITS
There is no restriction on the transfer of the ETO Series A Preferred Units other than restrictions and conditions applicable to transfers of any limited partner interests under the ETO Partnership Agreement.    There is no restriction on the transfer of the ET Series A Preferred Units other than restrictions and conditions applicable to transfers of any limited partner interests under the ET Partnership Agreement.
PREEMPTIVE RIGHTS
No holder of ETO Series A Preferred Units has any preemptive, preferential or other similar right with respect to the issuance of additional partnership securities under the ETO Partnership Agreement.    No holder of ET Series A Preferred Units will have any preemptive, preferential or other similar right with respect to the issuance of additional partnership securities under the ET Partnership Agreement.
RIGHTS UPON A CHANGE OF CONTROL
The holders of ETO Series A Preferred Units do not have any specific rights or protections upon a change of control at ETO.    The holders of ET Series A Preferred Units will not have any specific rights or protections upon a change of control at ET.
NO SINKING FUND
The ETO Series A Preferred Units do not have the benefit of any sinking fund.    The ET Series A Preferred Units will not have the benefit of any sinking fund.

Series B Preferred Units

 

ETO Series B Preferred Unitholders

  

ET Series B Preferred Unitholders

ISSUANCE AND DISTRIBUTIONS
In November 2017, ETO issued and sold 550,000 ETO Series B Preferred Units at a price to the public of $1,000 per unit.    By adoption of Amendment No. 8 to the ET Partnership Agreement, ET will create the ET Series B Preferred Units, which, following the effective time of the Merger, will (i) rank pari passu with the other ET Preferred Units with respect to distributions and rights upon liquidation and (ii) have substantially the same preferences, rights, powers and duties as the ET Series B Preferred Units (other than any non-substantive differences to reflect the issuance of such securities by ET, as opposed to ETO).
Distributions on the ETO Series B Preferred Units are cumulative from the date of original issue and are payable semi-annually in arrears on the 15th day of February and August of each year up to and including February 15, 2028. After February 15, 2028, distributions on the ETO Series B Preferred Units will be payable quarterly in arrears on the 15th day of    Distributions on the ET Series B Preferred Units will be cumulative                from                 , 2021 and will be payable semi-annually in arrears on the 15th day of February and August of each year up to and including February 15, 2028. After February 15, 2028, distributions on the ET Series B Preferred Units will be payable quarterly in arrears on the 15th

 

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ET Series B Preferred Unitholders

February, May, August and November of each year, in each case when, as, and if declared by ETO’s general partner.    day of February, May, August and November of each year, in each case when, as, and if declared by ET’s general partner.
Distributions on the ETO Series B Preferred Units are payable out of amounts legally available therefor from and including the date of original issue to, but excluding February 15, 2028, at a rate of 6.625% per annum of the $1,000 liquidation preference per ETO Series B Preferred Unit (equal to $66.25 per ETO Series B Preferred Unit per annum). On and after February 15, 2028, distributions on the ETO Series B Preferred Units will accumulate for each distribution period at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR plus a spread of 4.155% per annum.    Distributions on the ET Series B Preferred Units will be payable out of amounts legally available therefor from and including the date of original issue to, but excluding February 15, 2028, at a rate of 6.625% per annum of the $1,000 liquidation preference per ET Series B Preferred Unit (equal to $66.25 per ET Series B Preferred Unit per annum). On and after February 15, 2028, distributions on the ET Series B Preferred Units will accumulate for each distribution period at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR plus a spread of 4.155% per annum.
RANKING
The ETO Series B Preferred Units, with respect to anticipated semi-annual or quarterly distributions and distributions upon the liquidation, winding-up and dissolution of ETO’s affairs, rank:    The ET Series B Preferred Units will, with respect to anticipated semi-annual or quarterly distributions and distributions upon the liquidation, winding-up and dissolution of ET’s affairs, rank:

 

•  senior to any junior securities (including ET Common Units and the general partner interest);

 

•  pari passu with any parity securities (including each other series of ET Preferred Units); and

 

•  junior to any senior securities.

  

 

•  senior to any junior securities (including ET Common Units and the general partner interest);

 

•  pari passu with any parity securities (including each other series of ET Preferred Units); and

 

•  junior to any senior securities.

The ETO Series B Preferred Units are subordinated to all of ETO’s and its subsidiaries’ existing and future indebtedness and other liabilities (including indebtedness outstanding under existing credit facilities, ETO’s senior notes, and any other senior securities ETO may issue in the future with respect to assets available to satisfy claims against it).    The ET Series B Preferred Units will be subordinated to all of ET’s and its subsidiaries’ existing and future indebtedness and other liabilities (including ET’s senior notes, and any other senior securities ET may issue in the future with respect to assets available to satisfy claims against it).
Under the ETO Partnership Agreement, ETO may issue junior securities from time to time in one or more series without the consent of the holders of the ETO Series B Preferred Units. ETO’s general partner has the authority to determine the designations, preferences, rights, powers, and duties of any such series before the issuance of any units of that series. ETO’s general partner will also determine the number of units constituting each series of securities. ETO’s ability to issue additional parity securities in certain    Under the ET Partnership Agreement, ET may issue junior securities from time to time in one or more series without the consent of the holders of the ET Series B Preferred Units. ET’s general partner has the authority to determine the designations, preferences, rights, powers, and duties of any such series before the issuance of any units of that series. ET’s general partner will also determine the number of units constituting each series of securities. ET’s ability to issue additional parity securities in certain

 

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ET Series B Preferred Unitholders

circumstances or senior securities is limited as described below under “Voting Rights.”    circumstances or senior securities is limited as described below under “Voting Rights.”
RESTRICTIONS ON DISTRIBUTIONS

ETO will not declare or pay or set aside for payment distributions on any junior securities (other than a distribution payable solely in junior securities) unless full cumulative distributions have been or contemporaneously are being paid or provided for on all outstanding ETO Series B Preferred Units and any parity securities through the most recent respective distribution periods.

 

Accumulated distributions in arrears for any past distribution period may be declared by ETO’s general partner and paid on any date fixed by ETO’s general partner, whether or not a distribution payment date, to holders of the ETO Series B Preferred Units on the record date for such payment, which may not be less than 10 days before such distribution periods.

  

ET will not declare or pay or set aside for payment distributions on any junior securities (other than a distribution payable solely in junior securities) unless full cumulative distributions have been or contemporaneously are being paid or provided for on all outstanding ET Series B Preferred Units and any parity securities through the most recent respective distribution periods.

 

Accumulated distributions in arrears for any past distribution period may be declared by ET’s general partner and paid on any date fixed by ET’s general partner, whether or not a distribution payment date, to holders of the ET Series B Preferred Units on the record date for such payment, which may not be less than 10 days before such distribution periods.

To the extent a distribution period applicable to a class of junior securities or parity securities is shorter than the distribution period applicable to the ETO Series B Preferred Units (e.g., quarterly rather than semi-annually), ETO’s general partner may declare and pay regular distributions with respect to such junior securities or parity securities so long as, at the time of declaration of such distribution, ETO’s general partner expects to have sufficient funds to pay the full distribution in respect of the ETO Series B Preferred Units on the next successive distribution payment date.    To the extent a distribution period applicable to a class of junior securities or parity securities is shorter than the distribution period applicable to the ET Series B Preferred Units (e.g., quarterly rather than semi-annually), ET’s general partner may declare and pay regular distributions with respect to such junior securities or parity securities so long as, at the time of declaration of such distribution, ET’s general partner expects to have sufficient funds to pay the full distribution in respect of the ET Series B Preferred Units on the next successive distribution payment date.
OPTIONAL REDEMPTION
At any time on or after February 15, 2028, ETO may redeem the ETO Series B Preferred Units, in whole or in part, out of amounts legally available therefor, at a redemption price of $1,000 per ETO Series B Preferred Unit plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption, whether or not declared. In addition, upon the occurrence of a Series B Rating Event (as defined below), ETO may redeem the ETO Series B Preferred Units, in whole but not in part, out of amounts legally available therefor, at a price of $1,020 per ETO Series B Preferred Unit plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption, whether or not declared. Any such redemption would be effected only    At any time on or after February 15, 2028, ET may redeem the ET Series B Preferred Units, in whole or in part, out of amounts legally available therefor, at a redemption price of $1,000 per ET Series B Preferred Unit plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption, whether or not declared. In addition, upon the occurrence of a Series B Rating Event (as defined below), ET may redeem the ET Series B Preferred Units, in whole but not in part, out of amounts legally available therefor, at a price of $1,020 per ET Series B Preferred Unit plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption, whether or not declared. Any such

 

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ETO Series B Preferred Unitholders

  

ET Series B Preferred Unitholders

out of funds legally available for such purpose and would be subject to compliance with the provisions of the instruments governing ETO’s outstanding indebtedness. ETO must provide not less than 15 days’ and not more than 60 days’ written notice of any such redemption. ETO may undertake multiple partial redemptions.

 

“Series B Rating Event” means a change by any rating agency to the current criteria, which change results in (i) any shortening of the length of time for which the current criteria are scheduled to be in effect with respect to the ETO Series B Preferred Units, or (ii) a lower Equity Credit being given to the ETO Series B Preferred Units than the Equity Credit that would have been assigned to the ETO Series B Preferred Units by such rating agency pursuant to the current criteria. “Equity Credit” for the purposes of the ETO Series B Preferred Units means the dollar amount or percentage in relation to the stated liquidation preference amount of $1,000 per ETO Series B Preferred Unit assigned to the ETO Series B Preferred Units as equity, rather than debt, by a rating agency in evaluating the capital structure of an entity.

  

redemption would be effected only out of funds legally available for such purpose and would be subject to compliance with the provisions of the instruments governing ET’s outstanding indebtedness. ET must provide not less than 15 days’ and not more than 60 days’ written notice of any such redemption. ET may undertake multiple partial redemptions.

 

“Series B Rating Event” means a change by any rating agency to the current criteria, which change results in (i) any shortening of the length of time for which the current criteria are scheduled to be in effect with respect to the ET Series B Preferred Units, or (ii) a lower Equity Credit being given to the ET Series B Preferred Units than the Equity Credit that would have been assigned to the ET Series B Preferred Units by such rating agency pursuant to the current criteria. “Equity Credit” for the purposes of the ET Series B Preferred Units means the dollar amount or percentage in relation to the stated liquidation preference amount of $1,000 per ET Series B Preferred Unit assigned to the ET Series B Preferred Units as equity, rather than debt, by a rating agency in evaluating the capital structure of an entity.

CONVERSION RIGHTS
The ETO Series B Preferred Units are not convertible into or exchangeable for any other securities or property at the option of the holder.    The ET Series B Preferred Units will not be convertible into or exchangeable for any other securities or property at the option of the holder.
LIQUIDATION RIGHTS

If necessary, the holders of outstanding ETO Series B Preferred Units will first be specially allocated items of ETO’s gross income and gain in a manner designed to cause, in the event of any liquidation, dissolution or winding up of ETO’s affairs, whether voluntary or involuntary, a liquidation preference of $1,000 per ETO Series B Preferred Unit.

 

If the amount of ETO’s gross income and gain available to be specially allocated to the ETO Series B Preferred Units is not sufficient to cause the capital account of such ETO Series B Preferred Unit to equal the liquidation preference of the ETO Series B Preferred Unit, then the amount that a holder of such ETO Series B Preferred Units would receive upon liquidation may be less than the ETO Series B Preferred Unit liquidation preference. Any accumulated and unpaid distributions

  

If necessary, the holders of outstanding ET Series B Preferred Units will first be specially allocated items of ET’s gross income and gain in a manner designed to cause, in the event of any liquidation, dissolution or winding up of ET’s affairs, whether voluntary or involuntary, a liquidation preference of $1,000 per ET Series B Preferred Unit.

 

If the amount of ET’s gross income and gain available to be specially allocated to the ET Series B Preferred Units is not sufficient to cause the capital account of such ET Series B Preferred Unit to equal the liquidation preference of the ET Series B Preferred Unit, then the amount that a holder of such ET Series B Preferred Units would receive upon liquidation may be less than the ET Series B Preferred Unit liquidation preference. Any

 

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ETO Series B Preferred Unitholders

  

ET Series B Preferred Unitholders

on the ETO Series B Preferred Units and the parity securities will be paid prior to any distributions in liquidation made in accordance with capital account balances. The rights of holders of the ETO Series B Preferred Units to receive the liquidation preference will be subject to the rights of the holders of any senior securities and the proportional rights of holders of the parity securities. A consolidation or merger of ETO with or into any other entity, individually or in a series of transactions, will not be deemed to be a liquidation, dissolution or winding up of ETO’s affairs.    accumulated and unpaid distributions on the ET Series B Preferred Units and the parity securities will be paid prior to any distributions in liquidation made in accordance with capital account balances. The rights of holders of the ET Series B Preferred Units to receive the liquidation preference will be subject to the rights of the holders of any senior securities and the proportional rights of holders of the parity securities. A consolidation or merger of ET with or into any other entity, individually or in a series of transactions, will not be deemed to be a liquidation, dissolution or winding up of ET’s affairs.
VOTING RIGHTS

Except as described below, holders of the ETO Series B Preferred Units generally have no voting rights.

 

Unless ETO has received the affirmative vote or consent of the holders of at least two-thirds of the outstanding ETO Series B Preferred Units, voting as a separate class, ETO may not adopt any amendment to the ETO Partnership Agreement that would have a material adverse effect on the terms of the ETO Series B Preferred Units.

 

In addition, unless ETO has received the affirmative vote or consent of the holders of at least two-thirds of the outstanding ETO Series B Preferred Units, voting as a class together with holders of any other parity securities upon which like voting rights have been conferred and are exercisable, ETO may not (i) create or issue any parity securities (including any additional ETO Series B Preferred Units) if the cumulative distributions payable on then outstanding ETO Series B Preferred Units (or parity securities, if applicable) are in arrears, or (ii) create or issue any senior securities.

 

On any matter on which the holders of the ETO Series B Preferred Units are entitled to vote as a class, such holders will be entitled to one vote per ETO Series B Preferred Unit

  

Except as described below, holders of the ET Series B Preferred Units generally will have no voting rights.

 

Unless ET has received the affirmative vote or consent of the holders of at least two-thirds of the outstanding ET Series B Preferred Units, voting as a separate class, ET may not adopt any amendment to the ET Partnership Agreement that would have a material adverse effect on the terms of the ET Series B Preferred Units.

 

In addition, unless ET has received the affirmative vote or consent of the holders of at least two-thirds of the outstanding ET Series B Preferred Units, voting as a class together with holders of any other parity securities upon which like voting rights have been conferred and are exercisable, ET may not (i) create or issue any parity securities (including any additional ET Series B Preferred Units) if the cumulative distributions payable on then outstanding ET Series B Preferred Units (or parity securities, if applicable) are in arrears, or (ii) create or issue any senior securities.

 

On any matter on which the holders of the ET Series B Preferred Units are entitled to vote as a class, such holders will be entitled to one vote per ET Series B Preferred Unit

TRANSFER OF UNITS
There is no restriction on the transfer of the ETO Series B Preferred Units other than restrictions and conditions applicable to transfers of any limited partner interests under the ETO Partnership Agreement.    There is no restriction on the transfer of the ET Series B Preferred Units other than restrictions and conditions applicable to transfers of any limited partner interests under the ET Partnership Agreement.

 

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ETO Series B Preferred Unitholders

  

ET Series B Preferred Unitholders

PREEMPTIVE RIGHTS
No holder of ETO Series B Preferred Units has any preemptive, preferential or other similar right with respect to the issuance of additional partnership securities under the ETO Partnership Agreement.    No holder of ET Series B Preferred Units will have any preemptive, preferential or other similar right with respect to the issuance of additional partnership securities under the ET Partnership Agreement.
RIGHTS UPON A CHANGE OF CONTROL
The holders of ETO Series B Preferred Units do not have any specific rights or protections upon a change of control at ETO.    The holders of ET Series B Preferred Units will not have any specific rights or protections upon a change of control at ET.
NO SINKING FUND
The ETO Series B Preferred Units do not have the benefit of any sinking fund.    The ET Series B Preferred Units will not have the benefit of any sinking fund.

Series C Preferred Units

 

ETO Series C Preferred Unitholders

  

ET Series C Preferred Unitholders

ISSUANCE AND DISTRIBUTIONS

In April 2018, ETO issued 18,000,000 ETO Series C Preferred Units at a price to the public of $25.00 per unit.

 

Distributions on the ETO Series C Preferred Units are cumulative from and including the date of original issue and are payable quarterly in arrears on the 15th day of February, May, August and November of each year, in each case when, as, and if declared by ETO’s general partner. Distributions on the ETO Series C Preferred Units will be payable out of amounts legally available therefor from and including the date of original issue to, but excluding, May 15, 2023, at a rate equal to 7.375% per annum of the $25.00 liquidation preference per ETO Series C Preferred Unit (equal to $1.84375 per ETO Series C Preferred Unit per annum). On and after May 15, 2023, distributions on the ETO Series C Preferred Units will accumulate for each distribution period at a percentage of the $25.00 liquidation preference equal to an annual floating rate of the three-month LIBOR plus a spread of 4.530% per annum.

  

By adoption of Amendment No. 8 to the ET Partnership Agreement, ET will create the ET Series C Preferred Units, which, following the effective time of the Merger, will (i) rank pari passu with the other ET Preferred Units with respect to distributions and rights upon liquidation and (ii) have substantially the same preferences, rights, powers and duties as the ETO Series C Preferred Units (other than any non-substantive differences to reflect the issuance of such securities by ET, as opposed to ETO).

 

Distributions on the Series ET C Preferred Units will be cumulative from and including                 , 2021 and will be payable quarterly in arrears on the 15th day of February, May, August and November of each year, in each case when, as, and if declared by ET’s general partner. Distributions on the ET Series C Preferred Units will be payable out of amounts legally available therefor from and including the date of original issue to, but excluding, May 15, 2023, at a rate equal to 7.375% per annum of the $25.00 liquidation preference per ET Series C Preferred Unit (equal to $1.84375 per ET Series C Preferred Unit per annum). On and after May 15, 2023, distributions on the ET Series C Preferred Units will accumulate

 

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ET Series C Preferred Unitholders

   for each distribution period at a percentage of the $25.00 liquidation preference equal to an annual floating rate of the three-month LIBOR plus a spread of 4.530% per annum.
RANKING

The ETO Series C Preferred Units, with respect to anticipated quarterly distributions and distributions upon the liquidation, winding-up and dissolution of ETO’s affairs, rank:

 

•  senior to any junior securities (including ET Common Units and the general partner interest);

 

•  pari passu with any parity securities (including each other series of ET Preferred Units); and

 

•  junior to any senior securities.

 

The ETO Series C Preferred Units are subordinated to all of ETO’s and its subsidiaries’ existing and future indebtedness and other liabilities (including indebtedness outstanding under existing credit facilities, ETO’s senior notes, and any other senior securities ETO may issue in the future with respect to assets available to satisfy claims against it).

 

Under the ETO Partnership Agreement, ETO may issue junior securities from time to time in one or more series without the consent of the holders of the ETO Series C Preferred Units. ETO’s general partner has the authority to determine the designations, preferences, rights, powers, and duties of any such series before the issuance of any units of that series. ETO’s general partner will also determine the number of units constituting each series of securities. ETO’s ability to issue additional parity securities in certain circumstances or senior securities is limited as described below under “Voting Rights.”

  

The ET Series C Preferred Units will, with respect to anticipated quarterly distributions and distributions upon the liquidation, winding-up and dissolution of ET’s affairs, rank:

 

•  senior to any junior securities (including ET Common Units and the general partner interest);

 

•  pari passu with any parity securities (including each other series of ET Preferred Units); and

 

•  junior to any senior securities.

 

The ET Series C Preferred Units will be subordinated to all of ET’s and its subsidiaries’ existing and future indebtedness and other liabilities (including ET’s senior notes, and any other senior securities ET may issue in the future with respect to assets available to satisfy claims against it).

 

Under the ET Partnership Agreement, ET may issue junior securities from time to time in one or more series without the consent of the holders of the ET Series C Preferred Units. ET’s general partner will have the authority to determine the designations, preferences, rights, powers, and duties of any such series before the issuance of any units of that series. ET’s general partner will also determine the number of units constituting each series of securities. ET’s ability to issue additional parity securities in certain circumstances or senior securities is limited as described below under “Voting Rights.”

RESTRICTIONS ON DISTRIBUTIONS
ETO will not declare or pay or set aside for payment any distribution on any junior securities (other than a distribution payable solely in junior securities) unless full cumulative distributions have been or contemporaneously are being paid or provided for on all outstanding ETO Series C Preferred Units and any parity securities through the most recent respective distribution periods.    ET will not declare or pay or set aside for payment any distribution on any junior securities (other than a distribution payable solely in junior securities) unless full cumulative distributions have been or contemporaneously are being paid or provided for on all outstanding ET Series C Preferred Units and any parity securities through the most recent respective distribution periods.

 

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ET Series C Preferred Unitholders

Accumulated distributions in arrears for any past distribution period may be declared by ETO’s general partner and paid on any date fixed by ETO’s general partner, whether or not a distribution payment date, to holders of the ETO Series C Preferred Units on the record date for such payment, which may not be less than 10 days before such distribution periods.

 

To the extent a distribution period applicable to a class of junior securities or parity securities is shorter than the distribution period applicable to the ETO Series C Preferred Units (e.g., monthly rather than quarterly), ETO’s general partner may declare and pay regular distributions with respect to such junior securities or parity securities so long as, at the time of declaration of such distribution, the general partner expects to have sufficient funds to pay the full distribution in respect of the ETO Series C Preferred Units on the next successive distribution payment date.

  

Accumulated distributions in arrears for any past distribution period may be declared by ET’s general partner and paid on any date fixed by ET’s general partner, whether or not a distribution payment date, to holders of the ET Series C Preferred Units on the record date for such payment, which may not be less than 10 days before such distribution periods.

 

To the extent a distribution period applicable to a class of junior securities or parity securities is shorter than the distribution period applicable to the ET Series C Preferred Units (e.g., monthly rather than quarterly), ET’s general partner may declare and pay regular distributions with respect to such junior securities or parity securities so long as, at the time of declaration of such distribution, the general partner expects to have sufficient funds to pay the full distribution in respect of the ET Series C Preferred Units on the next successive distribution payment date.

OPTIONAL REDEMPTION

At any time on or after May 15, 2023, ETO may redeem the ETO Series C Preferred Units, in whole or in part, out of amounts legally available therefor, at a redemption price of $25.00 per ETO Series C Preferred Unit plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption, whether or not declared. In addition, upon the occurrence of a “Series C Rating Event” (as defined below), ETO may redeem the ETO Series C Preferred Units, in whole but not in part, out of amounts legally available therefor, at a price of $25.50 per ETO Series C Preferred Unit plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption, whether or not declared. Any such redemption would be effected only out of funds legally available for such purpose and would be subject to compliance with the provisions of the instruments governing ETO’s outstanding indebtedness. ETO must provide not less than 30 days’ and not more than 60 days’ written notice of any such redemption. ETO may undertake multiple partial redemptions.

 

“Series C Rating Event” means a change by any rating agency to the current criteria, which change results in (i) any shortening of the length of time for which the current criteria are scheduled to be in effect with respect to the ETO Series C Preferred Units, or (ii) a lower

  

At any time on or after May 15, 2023, ET may redeem the ET Series C Preferred Units, in whole or in part, out of amounts legally available therefor, at a redemption price of $25.00 per ET Series C Preferred Unit plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption, whether or not declared. In addition, upon the occurrence of a “Series C Rating Event” (as defined below), ET may redeem the ET Series C Preferred Units, in whole but not in part, out of amounts legally available therefor, at a price of $25.50 per ET Series C Preferred Unit plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption, whether or not declared. Any such redemption would be effected only out of funds legally available for such purpose and would be subject to compliance with the provisions of the instruments governing ET’s outstanding indebtedness. ET must provide not less than 30 days’ and not more than 60 days’ written notice of any such redemption. ET may undertake multiple partial redemptions.

 

“Series C Rating Event” means a change by any rating agency to the current criteria, which change results in (i) any shortening of the length of time for which the current criteria are scheduled to be in

 

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ETO Series C Preferred Unitholders

  

ET Series C Preferred Unitholders

Equity Credit being given to the ETO Series C Preferred Units than the Equity Credit that would have been assigned to the ETO Series C Preferred Units by such rating agency pursuant to the current criteria. “Equity Credit” for the purposes of the ETO Series C Preferred Units means the dollar amount or percentage in relation to the stated liquidation preference amount of $25.00 per ETO Series C Preferred Unit assigned to the ETO Series C Preferred Units as equity, rather than debt, by a rating agency in evaluating the capital structure of an entity.    effect with respect to the ET Series C Preferred Units, or (ii) a lower Equity Credit being given to the ET Series C Preferred Units than the Equity Credit that would have been assigned to the ET Series C Preferred Units by such rating agency pursuant to the current criteria. “Equity Credit” for the purposes of the ET Series C Preferred Units means the dollar amount or percentage in relation to the stated liquidation preference amount of $25.00 per ET Series C Preferred Unit assigned to the ET Series C Preferred Units as equity, rather than debt, by a rating agency in evaluating the capital structure of an entity.
CONVERSION RIGHTS
The ETO Series C Preferred Units are not convertible into or exchangeable for any other securities or property at the option of the holder.    The ET Series C Preferred Units will not be convertible into or exchangeable for any other securities or property at the option of the holder.
LIQUIDATION RIGHTS

If necessary, the holders of outstanding ETO Series C Preferred Units will first be specially allocated items of ETO’s gross income and gain in a manner designed to cause, in the event of any liquidation, dissolution or winding up of ETO’s affairs, whether voluntary or involuntary, a liquidation preference of $25.00 per ETO Series C Preferred Unit.

 

If the amount of ETO’s gross income and gain available to be specially allocated to the ETO Series C Preferred Units is not sufficient to cause the capital account of such ETO Series C Preferred Unit to equal the liquidation preference of the ETO Series C Preferred Unit, then the amount that a holder of such ETO Series C Preferred Units would receive upon liquidation may be less than the ETO Series C Preferred Unit liquidation preference. Any accumulated and unpaid distributions on the ETO Series C Preferred Units and the parity securities will be paid prior to any distributions in liquidation made in accordance with capital account balances. The rights of holders of the ETO Series C Preferred Units to receive the liquidation preference will be subject to the rights of the holders of any senior securities and the proportional rights of holders of the parity securities. A consolidation or merger of ETO with or into any other entity, individually or in a series of transactions, will not be deemed to be a liquidation, dissolution or winding up of ETO’s affairs.

  

If necessary, the holders of outstanding ET Series C Preferred Units will first be specially allocated items of ET’s gross income and gain in a manner designed to cause, in the event of any liquidation, dissolution or winding up of ET’s affairs, whether voluntary or involuntary, a liquidation preference of $25.00 per ET Series C Preferred Unit.

 

If the amount of ET’s gross income and gain available to be specially allocated to the ET Series C Preferred Units is not sufficient to cause the capital account of such ET Series C Preferred Unit to equal the liquidation preference of the ET Series C Preferred Unit, then the amount that a holder of such ET Series C Preferred Units would receive upon liquidation may be less than the ET Series C Preferred Unit liquidation preference. Any accumulated and unpaid distributions on the ET Series C Preferred Units and the parity securities will be paid prior to any distributions in liquidation made in accordance with capital account balances. The rights of holders of the ET Series C Preferred Units to receive the liquidation preference will be subject to the rights of the holders of any senior securities and the proportional rights of holders of the parity securities. A consolidation or merger of ET with or into any other entity, individually or in a series of transactions, will not be deemed to be a liquidation, dissolution or winding up of ET’s affairs.

 

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ETO Series C Preferred Unitholders

  

ET Series C Preferred Unitholders

VOTING RIGHTS

Except as described below, holders of the ETO Series C Preferred Units generally have no voting rights.

 

Unless ETO has received the affirmative vote or consent of the holders of at least two-thirds of the outstanding ETO Series C Preferred Units, voting as a separate class, ETO may not adopt any amendment to the ETO Partnership Agreement that would have a material adverse effect on the terms of the ETO Series C Preferred Units.

 

In addition, unless ETO has received the affirmative vote or consent of the holders of at least two-thirds of the outstanding ETO Series C Preferred Units, voting as a class together with holders of any other parity securities upon which like voting rights have been conferred and are exercisable, ETO may not (i) create or issue any parity securities (including any additional ETO Series C Preferred Units) if the cumulative distributions payable on then outstanding ETO Series C Preferred Units (or parity securities, if applicable) are in arrears, or (ii) create or issue any senior securities.

 

On any matter on which the holders of the ETO Series C Preferred Units are entitled to vote as a class, such holders will be entitled to one vote per ETO Series C Preferred Unit.

  

Except as described below, holders of the ET Series C Preferred Units generally will have no voting rights.

 

Unless ET has received the affirmative vote or consent of the holders of at least two-thirds of the outstanding ET Series C Preferred Units, voting as a separate class, ET may not adopt any amendment to the ET Partnership Agreement that would have a material adverse effect on the terms of the ET Series C Preferred Units.

 

In addition, unless ET has received the affirmative vote or consent of the holders of at least two-thirds of the outstanding ET Series C Preferred Units, voting as a class together with holders of any other parity securities upon which like voting rights have been conferred and are exercisable, ET may not (i) create or issue any parity securities (including any additional ET Series C Preferred Units) if the cumulative distributions payable on then outstanding ET Series C Preferred Units (or parity securities, if applicable) are in arrears, or (ii) create or issue any senior securities.

 

On any matter on which the holders of the ET Series C Preferred Units are entitled to vote as a class, such holders will be entitled to one vote per ET Series C Preferred Unit.

TRANSFER OF UNITS
There is no restriction on the transfer of the ETO Series C Preferred Units other than restrictions and conditions applicable to transfers of any limited partner interests under the ETO Partnership Agreement.    There is no restriction on the transfer of the ET Series C Preferred Units other than restrictions and conditions applicable to transfers of any limited partner interests under the ET Partnership Agreement.
PREEMPTIVE RIGHTS
No holder of ETO Series C Preferred Units has any preemptive, preferential or other similar right with respect to the issuance of additional partnership securities under the ETO Partnership Agreement.    No holder of ET Series C Preferred Units will have any preemptive, preferential or other similar right with respect to the issuance of additional partnership securities under the ET Partnership Agreement.

 

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ETO Series C Preferred Unitholders

  

ET Series C Preferred Unitholders

RIGHTS UPON A CHANGE OF CONTROL
The holders of ETO Series C Preferred Units do not have any specific rights upon a change of control under the ETO Partnership Agreement.    The holders of ET Series C Preferred Units will not have any specific rights upon a change of control under the ET Partnership Agreement.
NO SINKING FUND
The ETO Series C Preferred Units do not have the benefit of any sinking fund.    The ET Series C Preferred Units will not have the benefit of any sinking fund.

Series D Preferred Units

 

ETO Series D Preferred Unitholders

  

ET Series D Preferred Unitholders

ISSUANCE AND DISTRIBUTIONS

In July 2018, ETO issued 16,000,000 ETO Series D Preferred Units at a price to the public of $25.00 per unit.

 

Distributions on the ETO Series D Preferred Units are cumulative from and including the date of original issue and are payable quarterly in arrears on the 15th day of February, May, August and November of each year, in each case when, as, and if declared by ETO’s general partner. Distributions on the ETO Series D Preferred Units will be payable out of amounts legally available therefor from and including the date of original issue to, but excluding, August 15, 2023, at a rate equal to 7.625% per annum of the $25.00 liquidation preference per ETO Series D Preferred Unit (equal to $1.9063 per ETO Series D Preferred Unit per annum). On and after August 15, 2023, distributions on the ETO Series D Preferred Units will accumulate for each distribution period at a percentage of the $25.00 liquidation preference equal to an annual floating rate of the three-month LIBOR plus a spread of 4.738% per annum.

  

By adoption of Amendment No. 8 to the ET Partnership Agreement, ET will create the ET Series D Preferred Units, which, following the effective time of the Merger, will (i) rank pari passu with the other ET Preferred Units with respect to distributions and rights upon liquidation and (ii) have substantially the same preferences, rights, powers and duties as the ETO Series D Preferred Units (other than any non-substantive differences to reflect the issuance of such securities by ET, as opposed to ETO).

 

Distributions on the Series ET C Preferred Units will be cumulative from and including                 , 2021 and will be payable quarterly in arrears on the 15th day of February, May, August and November of each year, in each case when, as, and if declared by ET’s general partner. Distributions on the ET Series D Preferred Units will be payable out of amounts legally available therefor from and including the date of original issue to, but excluding, August 15, 2023, at a rate equal to 7.625% per annum of the $25.00 liquidation preference per ET Series D Preferred Unit (equal to $1.9063 per ET Series D Preferred Unit per annum). On and after August 15, 2023, distributions on the ET Series D Preferred Units will accumulate for each distribution period at a percentage of the $25.00 liquidation preference equal to an annual floating rate of the three-month LIBOR plus a spread of 4.738% per annum.

 

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ETO Series D Preferred Unitholders

  

ET Series D Preferred Unitholders

RANKING

The ETO Series D Preferred Units, with respect to anticipated quarterly distributions and distributions upon the liquidation, winding-up and dissolution of ETO’s affairs, rank:

 

•  senior to any junior securities (including ET Common Units and the general partner interest);

 

•  pari passu with any parity securities (including each other series of ET Preferred Units); and

 

•  junior to any senior securities.

 

The ETO Series D Preferred Units are subordinated to all of ETO’s and its subsidiaries’ existing and future indebtedness and other liabilities (including indebtedness outstanding under existing credit facilities, ETO’s senior notes, and any other senior securities ETO may issue in the future with respect to assets available to satisfy claims against it).

 

Under the ETO Partnership Agreement, ETO may issue junior securities from time to time in one or more series without the consent of the holders of the ETO Series D Preferred Units. ETO’s general partner has the authority to determine the designations, preferences, rights, powers, and duties of any such series before the issuance of any units of that series. ETO’s general partner will also determine the number of units constituting each series of securities. ETO’s ability to issue additional parity securities in certain circumstances or senior securities is limited as described below under “Voting Rights.”

  

The ET Series D Preferred Units will, with respect to anticipated quarterly distributions and distributions upon the liquidation, winding-up and dissolution of ET’s affairs, rank:

 

•  senior to any junior securities (including ET Common Units and the general partner interest);

 

•  pari passu with any parity securities (including each other series of ET Preferred Units); and

 

•  junior to any senior securities.

 

The ET Series D Preferred Units will be subordinated to all of ET’s and its subsidiaries’ existing and future indebtedness and other liabilities (including ET’s senior notes, and any other senior securities ET may issue in the future with respect to assets available to satisfy claims against it).

 

Under the ET Partnership Agreement, ET may issue junior securities from time to time in one or more series without the consent of the holders of the ET Series D Preferred Units. ET’s general partner will have the authority to determine the designations, preferences, rights, powers, and duties of any such series before the issuance of any units of that series. ET’s general partner will also determine the number of units constituting each series of securities. ET’s ability to issue additional parity securities in certain circumstances or senior securities is limited as described below under “Voting Rights.”

RESTRICTIONS ON DISTRIBUTIONS

ETO will not declare or pay or set aside for payment any distribution on any junior securities (other than a distribution payable solely in junior securities) unless full cumulative distributions have been or contemporaneously are being paid or provided for on all outstanding ETO Series D Preferred Units and any parity securities through the most recent respective distribution periods.

 

Accumulated distributions in arrears for any past distribution period may be declared by ETO’s general partner and paid on any date fixed by ETO’s general partner, whether or not a distribution payment date, to

  

ET will not declare or pay or set aside for payment any distribution on any junior securities (other than a distribution payable solely in junior securities) unless full cumulative distributions have been or contemporaneously are being paid or provided for on all outstanding ET Series D Preferred Units and any parity securities through the most recent respective distribution periods.

 

Accumulated distributions in arrears for any past distribution period may be declared by ET’s general partner and paid on any date fixed by ET’s general partner, whether or not a distribution payment date,

 

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ETO Series D Preferred Unitholders

  

ET Series D Preferred Unitholders

holders of the ETO Series D Preferred Units on the record date for such payment, which may not be less than 10 days before such distribution periods.

 

To the extent a distribution period applicable to a class of junior securities or parity securities is shorter than the distribution period applicable to the ETO Series D Preferred Units (e.g., monthly rather than quarterly), ETO’s general partner may declare and pay regular distributions with respect to such junior securities or parity securities so long as, at the time of declaration of such distribution, the general partner expects to have sufficient funds to pay the full distribution in respect of the ETO Series D Preferred Units on the next successive distribution payment date.

  

to holders of the ET Series D Preferred Units on the record date for such payment, which may not be less than 10 days before such distribution periods.

 

To the extent a distribution period applicable to a class of junior securities or parity securities is shorter than the distribution period applicable to the ET Series D Preferred Units (e.g., monthly rather than quarterly), ET’s general partner may declare and pay regular distributions with respect to such junior securities or parity securities so long as, at the time of declaration of such distribution, the general partner expects to have sufficient funds to pay the full distribution in respect of the ET Series D Preferred Units on the next successive distribution payment date.

OPTIONAL REDEMPTION

At any time on or after August 15, 2023, ETO may redeem the ETO Series D Preferred Units, in whole or in part, out of amounts legally available therefor, at a redemption price of $25.00 per ETO Series D Preferred Unit plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption, whether or not declared. In addition, upon the occurrence of a Series D Rating Event (as defined below), ETO may redeem the ETO Series D Preferred Units, in whole but not in part, out of amounts legally available therefor, at a price of $25.50 per ETO Series D Preferred Unit plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption, whether or not declared. Any such redemption would be effected only out of funds legally available for such purpose and would be subject to compliance with the provisions of the instruments governing ETO’s outstanding indebtedness. ETO must provide not less than 30 days’ and not more than 60 days’ written notice of any such redemption. ETO may undertake multiple partial redemptions.

 

“Series D Rating Event” means a change by any rating agency to the current criteria, which change results in (i) any shortening of the length of time for which the current criteria are scheduled to be in effect with respect to the ETO Series D Preferred Units, or (ii) a lower Equity Credit being given to the ETO Series D Preferred Units than the Equity Credit that would have been assigned to the ETO Series D Preferred Units by such rating agency pursuant to the current criteria. “Equity

  

At any time on or after August 15, 2023, ET may redeem the ET Series D Preferred Units, in whole or in part, out of amounts legally available therefor, at a redemption price of $25.00 per ET Series D Preferred Unit plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption, whether or not declared. In addition, upon the occurrence of a Series D Rating Event (as defined below), ET may redeem the ET Series D Preferred Units, in whole but not in part, out of amounts legally available therefor, at a price of $25.50 per ET Series D Preferred Unit plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption, whether or not declared. Any such redemption would be effected only out of funds legally available for such purpose and would be subject to compliance with the provisions of the instruments governing ET’s outstanding indebtedness. ET must provide not less than 30 days’ and not more than 60 days’ written notice of any such redemption. ET may undertake multiple partial redemptions.

 

“Series D Rating Event” means a change by any rating agency to the current criteria, which change results in (i) any shortening of the length of time for which the current criteria are scheduled to be in effect with respect to the ET Series D Preferred Units, or (ii) a lower Equity Credit being given to the ET Series D Preferred Units than the Equity Credit that would have been assigned to the ET Series D Preferred Units by such rating agency pursuant to the

 

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ETO Series D Preferred Unitholders

  

ET Series D Preferred Unitholders

Credit” for the purposes of the ETO Series D Preferred Units means the dollar amount or percentage in relation to the stated liquidation preference amount of $25.00 per ETO Series D Preferred Unit assigned to the ETO Series D Preferred Units as equity, rather than debt, by a rating agency in evaluating the capital structure of an entity.    Preferred Units by such rating agency pursuant to the current criteria. “Equity Credit” for the purposes of the ET Series D Preferred Units means the dollar amount or percentage in relation to the stated liquidation preference amount of $25.00 per ET Series D Preferred Unit assigned to the ET Series D Preferred Units as equity, rather than debt, by a rating agency in evaluating the capital structure of an entity.
CONVERSION RIGHTS
The ETO Series D Preferred Units are not convertible into or exchangeable for any other securities or property at the option of the holder.    The ET Series D Preferred Units will not be convertible into or exchangeable for any other securities or property at the option of the holder.
LIQUIDATION RIGHTS

If necessary, the holders of outstanding ETO Series D Preferred Units will first be specially allocated items of ETO’s gross income and gain in a manner designed to cause, in the event of any liquidation, dissolution or winding up of ETO’s affairs, whether voluntary or involuntary, a liquidation preference of $25.00 per ETO Series D Preferred Unit.

 

If the amount of ETO’s gross income and gain available to be specially allocated to the ETO Series D Preferred Units is not sufficient to cause the capital account of such ETO Series D Preferred Unit to equal the liquidation preference of the ETO Series D Preferred Unit, then the amount that a holder of such ETO Series D Preferred Units would receive upon liquidation may be less than the ETO Series D Preferred Unit liquidation preference. Any accumulated and unpaid distributions on the ETO Series D Preferred Units and the parity securities will be paid prior to any distributions in liquidation made in accordance with capital account balances. The rights of holders of the ETO Series D Preferred Units to receive the liquidation preference will be subject to the rights of the holders of any senior securities and the proportional rights of holders of the parity securities. A consolidation or merger of ETO with or into any other entity, individually or in a series of transactions, will not be deemed to be a liquidation, dissolution or winding up of ETO’s affairs.

  

If necessary, the holders of outstanding ET Series D Preferred Units will first be specially allocated items of ET’s gross income and gain in a manner designed to cause, in the event of any liquidation, dissolution or winding up of ET’s affairs, whether voluntary or involuntary, a liquidation preference of $25.00 per ET Series D Preferred Unit.

 

If the amount of ET’s gross income and gain available to be specially allocated to the ET Series D Preferred Units is not sufficient to cause the capital account of such ET Series D Preferred Unit to equal the liquidation preference of the ET Series D Preferred Unit, then the amount that a holder of such ET Series D Preferred Units would receive upon liquidation may be less than the ET Series D Preferred Unit liquidation preference. Any accumulated and unpaid distributions on the ET Series D Preferred Units and the parity securities will be paid prior to any distributions in liquidation made in accordance with capital account balances. The rights of holders of the ET Series D Preferred Units to receive the liquidation preference will be subject to the rights of the holders of any senior securities and the proportional rights of holders of the parity securities. A consolidation or merger of ET with or into any other entity, individually or in a series of transactions, will not be deemed to be a liquidation, dissolution or winding up of ET’s affairs.

VOTING RIGHTS
Except as described below, holders of the ETO Series D Preferred Units generally have no voting rights.    Except as described below, holders of the ET Series D Preferred Units generally will have no voting rights.

 

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ETO Series D Preferred Unitholders

  

ET Series D Preferred Unitholders

 

Unless ETO has received the affirmative vote or consent of the holders of at least two-thirds of the outstanding ETO Series D Preferred Units, voting as a separate class, ETO may not adopt any amendment to the ETO Partnership Agreement that would have a material adverse effect on the terms of the ETO Series D Preferred Units.

 

In addition, unless ETO has received the affirmative vote or consent of the holders of at least two-thirds of the outstanding ETO Series D Preferred Units, voting as a class together with holders of any other parity securities upon which like voting rights have been conferred and are exercisable, ETO may not (i) create or issue any parity securities (including any additional ETO Series D Preferred Units) if the cumulative distributions payable on then outstanding ETO Series D Preferred Units (or parity securities, if applicable) are in arrears, or (ii) create or issue any senior securities.

 

On any matter on which the holders of the ETO Series D Preferred Units are entitled to vote as a class, such holders will be entitled to one vote per ETO Series D Preferred Unit.

  

 

Unless ET has received the affirmative vote or consent of the holders of at least two-thirds of the outstanding ET Series D Preferred Units, voting as a separate class, ET may not adopt any amendment to the ET Partnership Agreement that would have a material adverse effect on the terms of the ET Series D Preferred Units.

 

In addition, unless ET has received the affirmative vote or consent of the holders of at least two-thirds of the outstanding ET Series D Preferred Units, voting as a class together with holders of any other parity securities upon which like voting rights have been conferred and are exercisable, ET may not (i) create or issue any parity securities (including any additional ET Series D Preferred Units) if the cumulative distributions payable on then outstanding ET Series D Preferred Units (or parity securities, if applicable) are in arrears, or (ii) create or issue any senior securities.

 

On any matter on which the holders of the ET Series D Preferred Units are entitled to vote as a class, such holders will be entitled to one vote per ET Series D Preferred Unit.

TRANSFER OF UNITS
There is no restriction on the transfer of the ETO Series D Preferred Units other than restrictions and conditions applicable to transfers of any limited partner interests under the ETO Partnership Agreement.    There is no restriction on the transfer of the ET Series D Preferred Units other than restrictions and conditions applicable to transfers of any limited partner interests under the ET Partnership Agreement.
PREEMPTIVE RIGHTS
No holder of ETO Series D Preferred Units has any preemptive, preferential or other similar right with respect to the issuance of additional partnership securities under the ETO Partnership Agreement.    No holder of ET Series D Preferred Units will have any preemptive, preferential or other similar right with respect to the issuance of additional partnership securities under the ET Partnership Agreement.
RIGHTS UPON A CHANGE OF CONTROL
The holders of ETO Series D Preferred Units do not have any specific rights upon a change of control under the ETO Partnership Agreement.    The holders of ET Series D Preferred Units will not have any specific rights upon a change of control under the ET Partnership Agreement.
NO SINKING FUND
The ETO Series D Preferred Units do not have the benefit of any sinking fund.    The ET Series D Preferred Units will not have the benefit of any sinking fund.

 

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Series E Preferred Units

 

ETO Series E Preferred Unitholders

  

ET Series E Preferred Unitholders

ISSUANCE AND DISTRIBUTIONS

In April 2019, ETO issued 28,000,000 ETO Series E Preferred Units at a price to the public of $25.00 per unit.

 

Distributions on the ETO Series E Preferred Units are cumulative from and including the date of original issue and are payable quarterly in arrears on the 15th day of February, May, August and November of each year, in each case when, as, and if declared by ETO’s general partner. Distributions on the ETO Series E Preferred Units will be payable out of amounts legally available therefor from and including the date of original issue to, but excluding, May 15, 2024, at a rate equal to 7.600% per annum of the $25.00 liquidation preference per ETO Series E Preferred Unit (equal to $1.900 per ETO Series E Preferred Unit per annum). On and after May 15, 2024, distributions on the ETO Series E Preferred Units will accumulate for each distribution period at a percentage of the $25.00 liquidation preference equal to an annual floating rate of the three-month LIBOR plus a spread of 5.161% per annum.

  

By adoption of Amendment No. 8 to the ET Partnership Agreement, ET will create the ET Series E Preferred Units, which, following the effective time of the Merger, will (i) rank pari passu with the other ET Preferred Units with respect to distributions and rights upon liquidation and (ii) have substantially the same preferences, rights, powers and duties as the ETO Series E Preferred Units (other than any non-substantive differences to reflect the issuance of such securities by ET, as opposed to ETO).

 

Distributions on the Series ET C Preferred Units will be cumulative from and including                 , 2021 and will be payable quarterly in arrears on the 15th day of February, May, August and November of each year, in each case when, as, and if declared by ET’s general partner. Distributions on the ET Series E Preferred Units will be payable out of amounts legally available therefor from and including the date of original issue to, but excluding, May 15, 2024, at a rate equal to 7.600% per annum of the $25.00 liquidation preference per ET Series E Preferred Unit (equal to $1.900 per ET Series E Preferred Unit per annum). On and after May 15, 2024, distributions on the ET Series E Preferred Units will accumulate for each distribution period at a percentage of the $25.00 liquidation preference equal to an annual floating rate of the three-month LIBOR plus a spread of 5.161% per annum.

RANKING

The ETO Series E Preferred Units, with respect to anticipated quarterly distributions and distributions upon the liquidation, winding-up and dissolution of ETO’s affairs, rank:

 

•  senior to any junior securities (including ET Common Units and the general partner interest);

 

•  pari passu with any parity securities (including each other series of ET Preferred Units); and

 

•  junior to any senior securities.

  

The ET Series E Preferred Units will, with respect to anticipated quarterly distributions and distributions upon the liquidation, winding-up and dissolution of ET’s affairs, rank:

 

•  senior to any junior securities (including ET Common Units and the general partner interest);

 

•  pari passu with any parity securities (including each other series of ET Preferred Units); and

 

•  junior to any senior securities.

 

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ETO Series E Preferred Unitholders

  

ET Series E Preferred Unitholders

 

The ETO Series E Preferred Units are subordinated to all of ETO’s and its subsidiaries’ existing and future indebtedness and other liabilities (including indebtedness outstanding under existing credit facilities, ETO’s senior notes, and any other senior securities ETO may issue in the future with respect to assets available to satisfy claims against it).

 

Under the ETO Partnership Agreement, ETO may issue junior securities from time to time in one or more series without the consent of the holders of the ETO Series E Preferred Units. ETO’s general partner has the authority to determine the designations, preferences, rights, powers, and duties of any such series before the issuance of any units of that series. ETO’s general partner will also determine the number of units constituting each series of securities. ETO’s ability to issue additional parity securities in certain circumstances or senior securities is limited as described below under “Voting Rights.”

  

 

The ET Series E Preferred Units will be subordinated to all of ET’s and its subsidiaries’ existing and future indebtedness and other liabilities (including ET’s senior notes, and any other senior securities ET may issue in the future with respect to assets available to satisfy claims against it).

 

Under the ET Partnership Agreement, ET may issue junior securities from time to time in one or more series without the consent of the holders of the ET Series E Preferred Units. ET’s general partner will have the authority to determine the designations, preferences, rights, powers, and duties of any such series before the issuance of any units of that series. ET’s general partner will also determine the number of units constituting each series of securities. ET’s ability to issue additional parity securities in certain circumstances or senior securities is limited as described below under “Voting Rights.”

RESTRICTIONS ON DISTRIBUTIONS

ETO will not declare or pay or set aside for payment any distribution on any junior securities (other than a distribution payable solely in junior securities) unless full cumulative distributions have been or contemporaneously are being paid or provided for on all outstanding ETO Series E Preferred Units and any parity securities through the most recent respective distribution periods.

 

Accumulated distributions in arrears for any past distribution period may be declared by ETO’s general partner and paid on any date fixed by ETO’s general partner, whether or not a distribution payment date, to holders of the ETO Series E Preferred Units on the record date for such payment, which may not be less than 10 days before such distribution periods.

 

To the extent a distribution period applicable to a class of junior securities or parity securities is shorter than the distribution period applicable to the ETO Series E Preferred Units (e.g., monthly rather than quarterly), ETO’s general partner may declare and pay regular distributions with respect to such junior securities or parity securities so long as, at the time of declaration of such distribution, the general partner expects to have sufficient funds to pay the full distribution in respect of the ETO Series E Preferred Units on the next successive distribution payment date.

  

ET will not declare or pay or set aside for payment any distribution on any junior securities (other than a distribution payable solely in junior securities) unless full cumulative distributions have been or contemporaneously are being paid or provided for on all outstanding ET Series E Preferred Units and any parity securities through the most recent respective distribution periods.

 

Accumulated distributions in arrears for any past distribution period may be declared by ET’s general partner and paid on any date fixed by ET’s general partner, whether or not a distribution payment date, to holders of the ET Series E Preferred Units on the record date for such payment, which may not be less than 10 days before such distribution periods.

 

To the extent a distribution period applicable to a class of junior securities or parity securities is shorter than the distribution period applicable to the ET Series E Preferred Units (e.g., monthly rather than quarterly), ET’s general partner may declare and pay regular distributions with respect to such junior securities or parity securities so long as, at the time of declaration of such distribution, the general partner expects to have sufficient funds to pay the full distribution in respect of the ET Series E Preferred Units on the next successive distribution payment date.

 

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ETO Series E Preferred Unitholders

  

ET Series E Preferred Unitholders

OPTIONAL REDEMPTION

At any time on or after May 15, 2024, ETO may redeem the ETO Series E Preferred Units, in whole or in part, out of amounts legally available therefor, at a redemption price of $25.00 per ETO Series E Preferred Unit plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption, whether or not declared. In addition, upon the occurrence of a Series E Rating Event (as defined below), ETO may redeem the ETO Series E Preferred Units, in whole but not in part, out of amounts legally available therefor, at a price of $25.50 per ETO Series E Preferred Unit plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption, whether or not declared. Any such redemption would be effected only out of funds legally available for such purpose and would be subject to compliance with the provisions of the instruments governing ETO’s outstanding indebtedness. ETO must provide not less than 30 days’ and not more than 60 days’ written notice of any such redemption. ETO may undertake multiple partial redemptions.

 

“Series E Rating Event” means a change by any rating agency to the current criteria, which change results in (i) any shortening of the length of time for which the current criteria are scheduled to be in effect with respect to the ETO Series E Preferred Units, or (ii) a lower Equity Credit being given to the ETO Series E Preferred Units than the Equity Credit that would have been assigned to the ETO Series E Preferred Units by such rating agency pursuant to the current criteria. “Equity Credit” for the purposes of the ETO Series E Preferred Units means the dollar amount or percentage in relation to the stated liquidation preference amount of $25.00 per ETO Series E Preferred Unit assigned to the ETO Series E Preferred Units as equity, rather than debt, by a rating agency in evaluating the capital structure of an entity.

  

At any time on or after May 15, 2024, ET may redeem the ET Series E Preferred Units, in whole or in part, out of amounts legally available therefor, at a redemption price of $25.00 per ET Series E Preferred Unit plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption, whether or not declared. In addition, upon the occurrence of a Series E Rating Event (as defined below), ET may redeem the ET Series E Preferred Units, in whole but not in part, out of amounts legally available therefor, at a price of $25.50 per ET Series E Preferred Unit plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption, whether or not declared. Any such redemption would be effected only out of funds legally available for such purpose and would be subject to compliance with the provisions of the instruments governing ET’s outstanding indebtedness. ET must provide not less than 30 days’ and not more than 60 days’ written notice of any such redemption. ET may undertake multiple partial redemptions.

 

“Series E Rating Event” means a change by any rating agency to the current criteria, which change results in (i) any shortening of the length of time for which the current criteria are scheduled to be in effect with respect to the ET Series E Preferred Units, or (ii) a lower Equity Credit being given to the ET Series E Preferred Units than the Equity Credit that would have been assigned to the ET Series E Preferred Units by such rating agency pursuant to the current criteria. “Equity Credit” for the purposes of the ET Series E Preferred Units means the dollar amount or percentage in relation to the stated liquidation preference amount of $25.00 per ET Series E Preferred Unit assigned to the ET Series E Preferred Units as equity, rather than debt, by a rating agency in evaluating the capital structure of an entity.

CONVERSION RIGHTS
The ETO Series E Preferred Units are not convertible into or exchangeable for any other securities or property at the option of the holder.    The ET Series E Preferred Units will not be convertible into or exchangeable for any other securities or property at the option of the holder.

 

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ETO Series E Preferred Unitholders

  

ET Series E Preferred Unitholders

LIQUIDATION RIGHTS

If necessary, the holders of outstanding ETO Series E Preferred Units will first be specially allocated items of ETO’s gross income and gain in a manner designed to cause, in the event of any liquidation, dissolution or winding up of ETO’s affairs, whether voluntary or involuntary, a liquidation preference of $25.00 per ETO Series E Preferred Unit.

 

If the amount of ETO’s gross income and gain available to be specially allocated to the ETO Series E Preferred Units is not sufficient to cause the capital account of such ETO Series E Preferred Unit to equal the liquidation preference of the ETO Series E Preferred Unit, then the amount that a holder of such ETO Series E Preferred Units would receive upon liquidation may be less than the ETO Series E Preferred Unit liquidation preference. Any accumulated and unpaid distributions on the ETO Series E Preferred Units and the parity securities will be paid prior to any distributions in liquidation made in accordance with capital account balances. The rights of holders of the ETO Series E Preferred Units to receive the liquidation preference will be subject to the rights of the holders of any senior securities and the proportional rights of holders of the parity securities. A consolidation or merger of ETO with or into any other entity, individually or in a series of transactions, will not be deemed to be a liquidation, dissolution or winding up of ETO’s affairs.

  

If necessary, the holders of outstanding ET Series E Preferred Units will first be specially allocated items of ET’s gross income and gain in a manner designed to cause, in the event of any liquidation, dissolution or winding up of ET’s affairs, whether voluntary or involuntary, a liquidation preference of $25.00 per ET Series E Preferred Unit.

 

If the amount of ET’s gross income and gain available to be specially allocated to the ET Series E Preferred Units is not sufficient to cause the capital account of such ET Series E Preferred Unit to equal the liquidation preference of the ET Series E Preferred Unit, then the amount that a holder of such ET Series E Preferred Units would receive upon liquidation may be less than the ET Series E Preferred Unit liquidation preference. Any accumulated and unpaid distributions on the ET Series E Preferred Units and the parity securities will be paid prior to any distributions in liquidation made in accordance with capital account balances. The rights of holders of the ET Series E Preferred Units to receive the liquidation preference will be subject to the rights of the holders of any senior securities and the proportional rights of holders of the parity securities. A consolidation or merger of ET with or into any other entity, individually or in a series of transactions, will not be deemed to be a liquidation, dissolution or winding up of ET’s affairs.

VOTING RIGHTS

Except as described below, holders of the ETO Series E Preferred Units generally have no voting rights.

 

Unless ETO has received the affirmative vote or consent of the holders of at least two-thirds of the outstanding ETO Series E Preferred Units, voting as a separate class, ETO may not adopt any amendment to the ETO Partnership Agreement that would have a material adverse effect on the terms of the ETO Series E Preferred Units.

 

In addition, unless ETO has received the affirmative vote or consent of the holders of at least two-thirds of the outstanding ETO Series E Preferred Units, voting as a class together with holders of any other parity securities upon which like voting rights have been

  

Except as described below, holders of the ET Series E Preferred Units generally will have no voting rights.

 

Unless ET has received the affirmative vote or consent of the holders of at least two-thirds of the outstanding ET Series E Preferred Units, voting as a separate class, ET may not adopt any amendment to the ET Partnership Agreement that would have a material adverse effect on the terms of the ET Series E Preferred Units.

 

In addition, unless ET has received the affirmative vote or consent of the holders of at least two-thirds of the outstanding ET Series E Preferred Units, voting as a class together with holders of any other parity

 

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ETO Series E Preferred Unitholders

  

ET Series E Preferred Unitholders

conferred and are exercisable, ETO may not (i) create or issue any parity securities (including any additional ETO Series E Preferred Units) if the cumulative distributions payable on then outstanding ETO Series E Preferred Units (or parity securities, if applicable) are in arrears, or (ii) create or issue any senior securities.

 

On any matter on which the holders of the ETO Series E Preferred Units are entitled to vote as a class, such holders will be entitled to one vote per ETO Series E Preferred Unit.

  

securities upon which like voting rights have been conferred and are exercisable, ET may not (i) create or issue any parity securities (including any additional ET Series E Preferred Units) if the cumulative distributions payable on then outstanding ET Series E Preferred Units (or parity securities, if applicable) are in arrears, or (ii) create or issue any senior securities.

 

On any matter on which the holders of the ET Series E Preferred Units are entitled to vote as a class, such holders will be entitled to one vote per ET Series E Preferred Unit.

TRANSFER OF UNITS
There is no restriction on the transfer of the ETO Series E Preferred Units other than restrictions and conditions applicable to transfers of any limited partner interests under the ETO Partnership Agreement.    There is no restriction on the transfer of the ET Series E Preferred Units other than restrictions and conditions applicable to transfers of any limited partner interests under the ET Partnership Agreement.
PREEMPTIVE RIGHTS
No holder of ETO Series E Preferred Units has any preemptive, preferential or other similar right with respect to the issuance of additional partnership securities under the ETO Partnership Agreement.    No holder of ET Series E Preferred Units will have any preemptive, preferential or other similar right with respect to the issuance of additional partnership securities under the ET Partnership Agreement.
RIGHTS UPON A CHANGE OF CONTROL
The holders of ETO Series E Preferred Units do not have any specific rights upon a change of control under the ETO Partnership Agreement.    The holders of ET Series E Preferred Units will not have any specific rights upon a change of control under the ET Partnership Agreement.
NO SINKING FUND
The ETO Series E Preferred Units do not have the benefit of any sinking fund.    The ET Series E Preferred Units will not have the benefit of any sinking fund.

Series F Preferred Units

 

ETO Series F Preferred Unitholders

  

ET Series F Preferred Unitholders

ISSUANCE AND DISTRIBUTIONS
In January 2020, ETO issued and sold 500,000 ETO Series F Preferred Units at a price to the public of $1,000 per unit.    By adoption of Amendment No. 8 to the ET Partnership Agreement, ET will create the ET Series F Preferred Units, which, following the effective time of the Merger, will (i) rank pari passu with the other ET Preferred Units with respect to distributions and

 

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Distributions on the ETO Series F Preferred Units are cumulative from the date of original issue and are payable semi-annually in arrears on the 15th day of May and November of each year.

 

Distributions on the ETO Series F Preferred Units are payable out of amounts legally available therefor from and including the date of original issue to, but excluding May 15, 2025 (the “Series F First Call Date”), at a rate of 6.750% per annum of the $1,000 liquidation preference per ETO Series F Preferred Unit (equal to $67.50 per ETO Series F Preferred Unit per annum).

 

On and after the Series F First Call Date, the distribution rate on the ETO Series F Preferred Units for each Series F Reset Period (as defined below) will equal a percentage of the $1,000 liquidation preference equal to the five-year U.S. Treasury Rate as of the most recent Series F Reset Distribution Determination Date plus a spread of 5.134% per annum.

 

“Series F Reset Date” means the Series F First Call Date and each date falling on the fifth anniversary of the preceding Series F Reset Date.

 

“Series F Reset Distribution Determination Date” means, in respect of any Series F Reset Period, the day falling two business days prior to the beginning of such Series F Reset Period.

 

“Series F Reset Period” means the period from and including the Series F First Call Date to, but excluding, the next following Series F Reset Date and thereafter each period from and including each Series F Reset Date to, but excluding, the next following Series F Reset Date.

 

The distribution rate for each Series F Reset Period will be determined by the calculation agent for the ETO Series F Preferred Units, as of the applicable Series F Reset Distribution Determination Date. Unless ETO has validly called all ETO Series F Preferred Units for redemption on the ETO Series F First Call Date, ETO will appoint a calculation agent (other than ETO or its affiliates) for the ETO Series F Preferred Units prior to the Series F Reset Distribution Determination Date preceding the Series F First Call Date and will keep a record of such appointment at ETO’s principal offices, which will be available to any ETO unitholder upon request.

  

rights upon liquidation and (ii) have substantially the same preferences, rights, powers and duties as the ETO Series F Preferred Units (other than any non-substantive differences to reflect the issuance of such securities by ET, as opposed to ETO).

 

Distributions on the ET Series F Preferred Units are cumulative                 from                 , 2021 and are payable semi-annually in arrears on the 15th day of May and November of each year.

 

Distributions on the ET Series F Preferred Units will be payable out of amounts legally available therefor from and including the date of original issue to, but excluding May 15, 2025 (the “Series F First Call Date”), at a rate of 6.750% per annum of the $1,000 liquidation preference per ET Series F Preferred Unit (equal to $67.50 per ET Series F Preferred Unit per annum).

 

On and after the Series F First Call Date, the distribution rate on the ET Series F Preferred Units for each Series F Reset Period (as defined below) will equal a percentage of the $1,000 liquidation preference equal to the five-year U.S. Treasury Rate as of the most recent Series F Reset Distribution Determination Date plus a spread of 5.134% per annum.

 

“Series F Reset Date” means the Series F First Call Date and each date falling on the fifth anniversary of the preceding Series F Reset Date.

 

“Series F Reset Distribution Determination Date” means, in respect of any Series F Reset Period, the day falling two business days prior to the beginning of such Series F Reset Period.

 

“Series F Reset Period” means the period from and including the Series F First Call Date to, but excluding, the next following Series F Reset Date and thereafter each period from and including each Series F Reset Date to, but excluding, the next following Series F Reset Date.

 

The distribution rate for each Series F Reset Period will be determined by the calculation agent for the ET Series F Preferred Units, as of the applicable Series F Reset Distribution Determination Date. Unless ET has validly called all ET Series F Preferred Units for redemption on the ET Series F

 

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ET Series F Preferred Unitholders

   First Call Date, ET will appoint a calculation agent (other than ET or its affiliates) for the ET Series F Preferred Units prior to the Series F Reset Distribution Determination Date preceding the Series F First Call Date and will keep a record of such appointment at ET’s principal offices, which will be available to any ET unitholder upon request.
RANKING

The ETO Series F Preferred Units, with respect to anticipated semi-annual distributions and distributions upon the liquidation, winding-up and dissolution of ETO’s affairs, rank:

 

•  senior to any junior securities (including ET Common Units and the general partner interest);

 

•  pari passu with any parity securities (including each other series of ET Preferred Units); and

 

•  junior to any senior securities.

 

The ETO Series F Preferred Units are subordinated to all of ETO’s and its subsidiaries’ existing and future indebtedness and other liabilities (including indebtedness outstanding under existing credit facilities, ETO’s senior notes, and any other senior securities ETO may issue in the future with respect to assets available to satisfy claims against it).

 

Under the ETO Partnership Agreement, ETO may issue junior securities from time to time in one or more series without the consent of the holders of the ETO Series F Preferred Units. ETO’s general partner has the authority to determine the designations, preferences, rights, powers, and duties of any such series before the issuance of any units of that series. ETO’s general partner will also determine the number of units constituting each series of securities. ETO’s ability to issue additional parity securities in certain circumstances or senior securities is limited as described below under “Voting Rights.”

  

The ET Series F Preferred Units will, with respect to anticipated semi-annual distributions and distributions upon the liquidation, winding-up and dissolution of ET’s affairs, rank:

 

•  senior to any junior securities (including ET Common Units and the general partner interest);

 

•  pari passu with any parity securities (including each other series of ET Preferred Units); and

 

•  junior to any senior securities.

 

The ET Series F Preferred Units will be subordinated to all of ET’s and its subsidiaries’ existing and future indebtedness and other liabilities (including ET’s senior notes, and any other senior securities ET may issue in the future with respect to assets available to satisfy claims against it).

 

Under the ET Partnership Agreement, ET may issue junior securities from time to time in one or more series without the consent of the holders of the ET Series F Preferred Units. ET’s general partner has the authority to determine the designations, preferences, rights, powers, and duties of any such series before the issuance of any units of that series. ET’s general partner will also determine the number of units constituting each series of securities. ET’s ability to issue additional parity securities in certain circumstances or senior securities is limited as described below under “Voting Rights.”

RESTRICTIONS ON DISTRIBUTIONS
ETO will not declare or pay or set aside for payment distributions on any junior securities (other than a distribution payable solely in junior securities) unless full cumulative distributions have been or contemporaneously are being paid or provided for on all    ET will not declare or pay or set aside for payment distributions on any junior securities (other than a distribution payable solely in junior securities) unless full cumulative distributions have been or contemporaneously are being paid or provided for on

 

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outstanding ETO Series F Preferred Units and any parity securities through the most recent respective distribution periods.

 

Accumulated distributions in arrears for any past distribution period may be declared by ETO’s general partner and paid on any date fixed by ETO’s general partner, whether or not a distribution payment date, to holders of the ETO Series F Preferred Units on the record date for such payment, which may not be less than 10 days before such distribution periods.

 

To the extent a distribution period applicable to a class of junior securities or parity securities is shorter than the distribution period applicable to the ETO Series F Preferred Units (e.g., quarterly rather than semi-annually), ETO’s general partner may declare and pay regular distributions with respect to such junior securities or parity securities so long as, at the time of declaration of such distribution, ETO’s general partner expects to have sufficient funds to pay the full distribution in respect of the ETO Series F Preferred Units on the next successive distribution payment date.

  

all outstanding ET Series F Preferred Units and any parity securities through the most recent respective distribution periods.

 

Accumulated distributions in arrears for any past distribution period may be declared by ET’s general partner and paid on any date fixed by ET’s general partner, whether or not a distribution payment date, to holders of the ET Series F Preferred Units on the record date for such payment, which may not be less than 10 days before such distribution periods.

 

To the extent a distribution period applicable to a class of junior securities or parity securities is shorter than the distribution period applicable to the ET Series F Preferred Units (e.g., quarterly rather than semi-annually), ET’s general partner may declare and pay regular distributions with respect to such junior securities or parity securities so long as, at the time of declaration of such distribution, ET’s general partner expects to have sufficient funds to pay the full distribution in respect of the ET Series F Preferred Units on the next successive distribution payment date.

OPTIONAL REDEMPTION
At any time on or after February 15, 2023, ETO may redeem the ETO Series F Preferred Units, in whole or in part, out of amounts legally available therefor, at a redemption price of $1,000 per ETO Series F Preferred Unit plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption, whether or not declared. In addition, upon the occurrence of a Series F Rating Event (as defined below), ETO may redeem the ETO Series F Preferred Units, in whole but not in part, out of amounts legally available therefor, at a price of $1,020 per ETO Series F Preferred Unit plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption, whether or not declared. Any such redemption would be effected only out of funds legally available for such purpose and would be subject to compliance with the provisions of the instruments governing ETO’s outstanding indebtedness. ETO must provide not less than 30 days’ and not more than 60 days’ written notice of any such redemption. ETO may undertake multiple partial redemptions.    At any time on or after February 15, 2023, ET may redeem the ET Series F Preferred Units, in whole or in part, out of amounts legally available therefor, at a redemption price of $1,000 per ET Series F Preferred Unit plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption, whether or not declared. In addition, upon the occurrence of a Series F Rating Event (as defined below), ET may redeem the ET Series F Preferred Units, in whole but not in part, out of amounts legally available therefor, at a price of $1,020 per ET Series F Preferred Unit plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption, whether or not declared. Any such redemption would be effected only out of funds legally available for such purpose and would be subject to compliance with the provisions of the instruments governing ET’s outstanding indebtedness. ET must provide not less than 30 days’ and not more than 60 days’ written notice of any such redemption. ET may undertake multiple partial redemptions.

 

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ET Series F Preferred Unitholders

“Series F Rating Event” means a change by any rating agency to the current criteria, which change results in (i) any shortening of the length of time for which the current criteria are scheduled to be in effect with respect to the ETO Series F Preferred Units, or (ii) a lower Equity Credit being given to the ETO Series F Preferred Units than the Equity Credit that would have been assigned to the ETO Series F Preferred Units by such rating agency pursuant to the current criteria. “Equity Credit” for the purposes of the ETO Series F Preferred Units means the dollar amount or percentage in relation to the stated liquidation preference amount of $1,000 per ETO Series F Preferred Unit assigned to the ETO Series F Preferred Units as equity, rather than debt, by a rating agency in evaluating the capital structure of an entity.    “Series F Rating Event” means a change by any rating agency to the current criteria, which change results in (i) any shortening of the length of time for which the current criteria are scheduled to be in effect with respect to the ET Series F Preferred Units, or (ii) a lower Equity Credit being given to the ET Series F Preferred Units than the Equity Credit that would have been assigned to the ET Series F Preferred Units by such rating agency pursuant to the current criteria. “Equity Credit” for the purposes of the ET Series F Preferred Units means the dollar amount or percentage in relation to the stated liquidation preference amount of $1,000 per ET Series F Preferred Unit assigned to the ET Series F Preferred Units as equity, rather than debt, by a rating agency in evaluating the capital structure of an entity.
CONVERSION RIGHTS
The ETO Series F Preferred Units are not convertible into or exchangeable for any other securities or property at the option of the holder.    The ET Series F Preferred Units will not be convertible into or exchangeable for any other securities or property at the option of the holder.
LIQUIDATION RIGHTS

If necessary, the holders of outstanding ETO Series F Preferred Units will first be specially allocated items of ETO’s gross income and gain in a manner designed to cause, in the event of any liquidation, dissolution or winding up of ETO’s affairs, whether voluntary or involuntary, a liquidation preference of $1,000 per ETO Series F Preferred Unit.

 

If the amount of ETO’s gross income and gain available to be specially allocated to the ETO Series F Preferred Units is not sufficient to cause the capital account of such ETO Series F Preferred Unit to equal the liquidation preference of the ETO Series F Preferred Unit, then the amount that a holder of such ETO Series F Preferred Units would receive upon liquidation may be less than the ETO Series F Preferred Unit liquidation preference. Any accumulated and unpaid distributions on the ETO Series F Preferred Units and the parity securities will be paid prior to any distributions in liquidation made in accordance with capital account balances. The rights of holders of the ETO Series F Preferred Units to receive the liquidation preference will be subject to the rights of the holders of any senior securities and the proportional rights of holders of the parity securities. A consolidation or merger of ETO with or into any other entity, individually or in a series of

  

If necessary, the holders of outstanding ET Series F Preferred Units will first be specially allocated items of ET’s gross income and gain in a manner designed to cause, in the event of any liquidation, dissolution or winding up of ET’s affairs, whether voluntary or involuntary, a liquidation preference of $1,000 per ET Series F Preferred Unit.

 

If the amount of ET’s gross income and gain available to be specially allocated to the ET Series F Preferred Units is not sufficient to cause the capital account of such ET Series F Preferred Unit to equal the liquidation preference of the ET Series F Preferred Unit, then the amount that a holder of such ET Series F Preferred Units would receive upon liquidation may be less than the ET Series F Preferred Unit liquidation preference. Any accumulated and unpaid distributions on the ET Series F Preferred Units and the parity securities will be paid prior to any distributions in liquidation made in accordance with capital account balances. The rights of holders of the ET Series F Preferred Units to receive the liquidation preference will be subject to the rights of the holders of any senior securities and the proportional rights of holders of the parity securities. A consolidation or merger of ET with or

 

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ET Series F Preferred Unitholders

transactions, will not be deemed to be a liquidation, dissolution or winding up of ETO’s affairs.    into any other entity, individually or in a series of transactions, will not be deemed to be a liquidation, dissolution or winding up of ET’s affairs.
VOTING RIGHTS

Except as described below, holders of the ETO Series F Preferred Units generally have no voting rights.

 

Unless ETO has received the affirmative vote or consent of the holders of at least two-thirds of the outstanding ETO Series F Preferred Units, voting as a separate class, ETO may not adopt any amendment to the ETO Partnership Agreement that would have a material adverse effect on the terms of the ETO Series F Preferred Units.

 

In addition, unless ETO has received the affirmative vote or consent of the holders of at least two-thirds of the outstanding ETO Series F Preferred Units, voting as a class together with holders of any other parity securities upon which like voting rights have been conferred and are exercisable, ETO may not (i) create or issue any parity securities (including any additional ETO Series F Preferred Units) if the cumulative distributions payable on then outstanding ETO Series F Preferred Units (or parity securities, if applicable) are in arrears, or (ii) create or issue any senior securities.

 

On any matter on which the holders of the ETO Series F Preferred Units are entitled to vote as a class, such holders will be entitled to one vote per ETO Series F Preferred Unit

  

Except as described below, holders of the ET Series F Preferred Units generally will have no voting rights.

 

Unless ET has received the affirmative vote or consent of the holders of at least two-thirds of the outstanding ET Series F Preferred Units, voting as a separate class, ET may not adopt any amendment to the ET Partnership Agreement that would have a material adverse effect on the terms of the ET Series F Preferred Units.

 

In addition, unless ET has received the affirmative vote or consent of the holders of at least two-thirds of the outstanding ET Series F Preferred Units, voting as a class together with holders of any other parity securities upon which like voting rights have been conferred and are exercisable, ET may not (i) create or issue any parity securities (including any additional ET Series F Preferred Units) if the cumulative distributions payable on then outstanding ET Series F Preferred Units (or parity securities, if applicable) are in arrears, or (ii) create or issue any senior securities.

 

On any matter on which the holders of the ET Series F Preferred Units are entitled to vote as a class, such holders will be entitled to one vote per ET Series F Preferred Unit

TRANSFER OF UNITS
There is no restriction on the transfer of the ETO Series F Preferred Units other than restrictions and conditions applicable to transfers of any limited partner interests under the ETO Partnership Agreement.    There is no restriction on the transfer of the ET Series F Preferred Units other than restrictions and conditions applicable to transfers of any limited partner interests under the ET Partnership Agreement.
PREEMPTIVE RIGHTS
No holder of ETO Series F Preferred Units has any preemptive, preferential or other similar right with respect to the issuance of additional partnership securities under the ETO Partnership Agreement.    No holder of ET Series F Preferred Units will have any preemptive, preferential or other similar right with respect to the issuance of additional partnership securities under the ET Partnership Agreement.

 

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ET Series F Preferred Unitholders

RIGHTS UPON A CHANGE OF CONTROL
The holders of ETO Series F Preferred Units do not have any specific rights or protections upon a change of control at ETO.    The holders of ET Series F Preferred Units will not have any specific rights or protections upon a change of control at ET.
NO SINKING FUND
The ETO Series F Preferred Units do not have the benefit of any sinking fund.    The ET Series F Preferred Units will not have the benefit of any sinking fund.

Series G Preferred Units

 

ETO Series G Preferred Unitholders

  

ET Series G Preferred Unitholders

ISSUANCE AND DISTRIBUTIONS

In January 2020, ETO issued and sold 1,100,000 ETO Series G Preferred Units at a price to the public of $1,000 per unit.

 

Distributions on the ETO Series G Preferred Units are cumulative from the date of original issue and are payable semi-annually in arrears on the 15th day of May and November of each year.

 

Distributions on the ETO Series G Preferred Units are payable out of amounts legally available therefor from and including the date of original issue to, but excluding May 15, 2030 (the “Series G First Call Date”), at a rate of 7.125% per annum of the $1,000 liquidation preference per ETO Series G Preferred Unit (equal to $71.25 per ETO Series G Preferred Unit per annum).

 

On and after the Series G First Call Date, the distribution rate on the ETO Series G Preferred Units for each Series G Reset Period (as defined below) will equal a percentage of the $1,000 liquidation preference equal to the five-year U.S. Treasury Rate as of the most recent Series G Reset Distribution Determination Date plus a spread of 5.306% per annum.

 

“Series G Reset Date” means the Series G First Call Date and each date falling on the fifth anniversary of the preceding Series G Reset Date.

 

“Series G Reset Distribution Determination Date” means, in respect of any Series G Reset Period, the day falling two business days prior to the beginning of such Series G Reset Period.

  

By adoption of Amendment No. 8 to the ET Partnership Agreement, ET will create the ET Series G Preferred Units, which, following the effective time of the Merger, will (i) rank pari passu with the other ET Preferred Units with respect to distributions and rights upon liquidation and (ii) have substantially the same preferences, rights, powers and duties as the ETO Series G Preferred Units (other than any non-substantive differences to reflect the issuance of such securities by ET, as opposed to ETO).

 

Distributions on the ET Series G Preferred Units are cumulative             from                 , 2021 and are payable semi-annually in arrears on the 15th day of May and November of each year.

 

Distributions on the ET Series G Preferred Units will be payable out of amounts legally available therefor from and including the date of original issue to, but excluding May 15, 2030 (the “Series G First Call Date”), at a rate of 7.125% per annum of the $1,000 liquidation preference per ET Series G Preferred Unit (equal to $71.25 per ET Series G Preferred Unit per annum).

 

On and after the Series G First Call Date, the distribution rate on the ET Series G Preferred Units for each Series G Reset Period (as defined below) will equal a percentage of the $1,000 liquidation preference equal to the five-year U.S. Treasury Rate as of the most recent Series G Reset Distribution Determination Date plus a spread of 5.306% per annum.

 

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ET Series G Preferred Unitholders

“Series G Reset Period” means the period from and including the Series G First Call Date to, but excluding, the next following Series G Reset Date and thereafter each period from and including each Series G Reset Date to, but excluding, the next following Series G Reset Date.

 

The distribution rate for each Series G Reset Period will be determined by the calculation agent for the ETO Series G Preferred Units, as of the applicable Series G Reset Distribution Determination Date. Unless ETO has validly called all ETO Series G Preferred Units for redemption on the ETO Series G First Call Date, ETO will appoint a calculation agent (other than ETO or its affiliates) for the ETO Series G Preferred Units prior to the Series G Reset Distribution Determination Date preceding the Series G First Call Date and will keep a record of such appointment at ETO’s principal offices, which will be available to any ETO unitholder upon request.

  

“Series G Reset Date” means the Series G First Call Date and each date falling on the fifth anniversary of the preceding Series G Reset Date.

 

“Series G Reset Distribution Determination Date” means, in respect of any Series G Reset Period, the day falling two business days prior to the beginning of such Series G Reset Period.

 

“Series G Reset Period” means the period from and including the Series G First Call Date to, but excluding, the next following Series G Reset Date and thereafter each period from and including each Series G Reset Date to, but excluding, the next following Series G Reset Date.

 

The distribution rate for each Series G Reset Period will be determined by the calculation agent for the ET Series G Preferred Units, as of the applicable Series G Reset Distribution Determination Date. Unless ET has validly called all ET Series G Preferred Units for redemption on the ET Series G First Call Date, ET will appoint a calculation agent (other than ET or its affiliates) for the ET Series G Preferred Units prior to the Series G Reset Distribution Determination Date preceding the Series G First Call Date and will keep a record of such appointment at ET’s principal offices, which will be available to any ET unitholder upon request.

RANKING

The ETO Series G Preferred Units, with respect to anticipated semi-annual distributions and distributions upon the liquidation, winding-up and dissolution of ETO’s affairs, rank:

 

•  senior to any junior securities (including ET Common Units and the general partner interest);

 

•  pari passu with any parity securities (including each other series of ET Preferred Units); and

 

•  junior to any senior securities.

 

The ETO Series G Preferred Units are subordinated to all of ETO’s and its subsidiaries’ existing and future indebtedness and other liabilities (including indebtedness outstanding under existing credit facilities, ETO’s senior notes, and any other senior securities ETO may issue in the future with respect to assets available to satisfy claims against it).

  

The ET Series G Preferred Units will, with respect to anticipated semi-annual distributions and distributions upon the liquidation, winding-up and dissolution of ET’s affairs, rank:

 

•  senior to any junior securities (including ET Common Units and the general partner interest);

 

•  pari passu with any parity securities (including each other series of ET Preferred Units); and

 

•  junior to any senior securities.

 

The ET Series G Preferred Units will be subordinated to all of ET’s and its subsidiaries’ existing and future indebtedness and other liabilities (including ET’s senior notes, and any other senior securities ET may issue in the future with respect to assets available to satisfy claims against it).

 

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ET Series G Preferred Unitholders

Under the ETO Partnership Agreement, ETO may issue junior securities from time to time in one or more series without the consent of the holders of the ETO Series G Preferred Units. ETO’s general partner has the authority to determine the designations, preferences, rights, powers, and duties of any such series before the issuance of any units of that series. ETO’s general partner will also determine the number of units constituting each series of securities. ETO’s ability to issue additional parity securities in certain circumstances or senior securities is limited as described below under “Voting Rights.”   

 

Under the ET Partnership Agreement, ET may issue junior securities from time to time in one or more series without the consent of the holders of the ET Series G Preferred Units. ET’s general partner has the authority to determine the designations, preferences, rights, powers, and duties of any such series before the issuance of any units of that series. ET’s general partner will also determine the number of units constituting each series of securities. ET’s ability to issue additional parity securities in certain circumstances or senior securities is limited as described below under “Voting Rights.”

RESTRICTIONS ON DISTRIBUTIONS

ETO will not declare or pay or set aside for payment distributions on any junior securities (other than a distribution payable solely in junior securities) unless full cumulative distributions have been or contemporaneously are being paid or provided for on all outstanding ETO Series G Preferred Units and any parity securities through the most recent respective distribution periods.

 

Accumulated distributions in arrears for any past distribution period may be declared by ETO’s general partner and paid on any date fixed by ETO’s general partner, whether or not a distribution payment date, to holders of the ETO Series G Preferred Units on the record date for such payment, which may not be less than 10 days before such distribution periods.

 

To the extent a distribution period applicable to a class of junior securities or parity securities is shorter than the distribution period applicable to the ETO Series G Preferred Units (e.g., quarterly rather than semi-annually), ETO’s general partner may declare and pay regular distributions with respect to such junior securities or parity securities so long as, at the time of declaration of such distribution, ETO’s general partner expects to have sufficient funds to pay the full distribution in respect of the ETO Series G Preferred Units on the next successive distribution payment date.

  

ET will not declare or pay or set aside for payment distributions on any junior securities (other than a distribution payable solely in junior securities) unless full cumulative distributions have been or contemporaneously are being paid or provided for on all outstanding ET Series G Preferred Units and any parity securities through the most recent respective distribution periods.

 

Accumulated distributions in arrears for any past distribution period may be declared by ET’s general partner and paid on any date fixed by ET’s general partner, whether or not a distribution payment date, to holders of the ET Series G Preferred Units on the record date for such payment, which may not be less than 10 days before such distribution periods.

 

To the extent a distribution period applicable to a class of junior securities or parity securities is shorter than the distribution period applicable to the ET Series G Preferred Units (e.g., quarterly rather than semi-annually), ET’s general partner may declare and pay regular distributions with respect to such junior securities or parity securities so long as, at the time of declaration of such distribution, ET’s general partner expects to have sufficient funds to pay the full distribution in respect of the ET Series G Preferred Units on the next successive distribution payment date.

OPTIONAL REDEMPTION
At any time on or after February 15, 2023, ETO may redeem the ETO Series G Preferred Units, in whole or in part, out of amounts legally available therefor, at a redemption price of $1,000 per ETO Series G Preferred    At any time on or after February 15, 2023, ET may redeem the ET Series G Preferred Units, in whole or in part, out of amounts legally available therefor, at a redemption price of $1,000 per ET Series G Preferred

 

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ET Series G Preferred Unitholders

Unit plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption, whether or not declared. In addition, upon the occurrence of a Series G Rating Event (as defined below), ETO may redeem the ETO Series G Preferred Units, in whole but not in part, out of amounts legally available therefor, at a price of $1,020 per ETO Series G Preferred Unit plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption, whether or not declared. Any such redemption would be effected only out of funds legally available for such purpose and would be subject to compliance with the provisions of the instruments governing ETO’s outstanding indebtedness. ETO must provide not less than 30 days’ and not more than 60 days’ written notice of any such redemption. ETO may undertake multiple partial redemptions.

 

“Series G Rating Event” means a change by any rating agency to the current criteria, which change results in (i) any shortening of the length of time for which the current criteria are scheduled to be in effect with respect to the ETO Series G Preferred Units, or (ii) a lower Equity Credit being given to the ETO Series G Preferred Units than the Equity Credit that would have been assigned to the ETO Series G Preferred Units by such rating agency pursuant to the current criteria. “Equity Credit” for the purposes of the ETO Series G Preferred Units means the dollar amount or percentage in relation to the stated liquidation preference amount of $1,000 per ETO Series G Preferred Unit assigned to the ETO Series G Preferred Units as equity, rather than debt, by a rating agency in evaluating the capital structure of an entity.

  

Unit plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption, whether or not declared. In addition, upon the occurrence of a Series G Rating Event (as defined below), ET may redeem the ET Series G Preferred Units, in whole but not in part, out of amounts legally available therefor, at a price of $1,020 per ET Series G Preferred Unit plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption, whether or not declared. Any such redemption would be effected only out of funds legally available for such purpose and would be subject to compliance with the provisions of the instruments governing ET’s outstanding indebtedness. ET must provide not less than 30 days’ and not more than 60 days’ written notice of any such redemption. ET may undertake multiple partial redemptions.

 

“Series G Rating Event” means a change by any rating agency to the current criteria, which change results in (i) any shortening of the length of time for which the current criteria are scheduled to be in effect with respect to the ET Series G Preferred Units, or (ii) a lower Equity Credit being given to the ET Series G Preferred Units than the Equity Credit that would have been assigned to the ET Series G Preferred Units by such rating agency pursuant to the current criteria. “Equity Credit” for the purposes of the ET Series G Preferred Units means the dollar amount or percentage in relation to the stated liquidation preference amount of $1,000 per ET Series G Preferred Unit assigned to the ET Series G Preferred Units as equity, rather than debt, by a rating agency in evaluating the capital structure of an entity.

CONVERSION RIGHTS
The ETO Series G Preferred Units are not convertible into or exchangeable for any other securities or property at the option of the holder.    The ET Series G Preferred Units will not be convertible into or exchangeable for any other securities or property at the option of the holder.
LIQUIDATION RIGHTS
If necessary, the holders of outstanding ETO Series G Preferred Units will first be specially allocated items of ETO’s gross income and gain in a manner designed to cause, in the event of any liquidation, dissolution or winding up of ETO’s affairs, whether voluntary or    If necessary, the holders of outstanding ET Series G Preferred Units will first be specially allocated items of ET’s gross income and gain in a manner designed to cause, in the event of any liquidation, dissolution or winding up of ET’s affairs, whether voluntary or

 

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ETO Series G Preferred Unitholders

  

ET Series G Preferred Unitholders

involuntary, a liquidation preference of $1,000 per ETO Series G Preferred Unit.

 

If the amount of ETO’s gross income and gain available to be specially allocated to the ETO Series G Preferred Units is not sufficient to cause the capital account of such ETO Series G Preferred Unit to equal the liquidation preference of the ETO Series G Preferred Unit, then the amount that a holder of such ETO Series G Preferred Units would receive upon liquidation may be less than the ETO Series G Preferred Unit liquidation preference. Any accumulated and unpaid distributions on the ETO Series G Preferred Units and the parity securities will be paid prior to any distributions in liquidation made in accordance with capital account balances. The rights of holders of the ETO Series G Preferred Units to receive the liquidation preference will be subject to the rights of the holders of any senior securities and the proportional rights of holders of the parity securities. A consolidation or merger of ETO with or into any other entity, individually or in a series of transactions, will not be deemed to be a liquidation, dissolution or winding up of ETO’s affairs.

  

involuntary, a liquidation preference of $1,000 per ET Series G Preferred Unit.

 

If the amount of ET’s gross income and gain available to be specially allocated to the ET Series G Preferred Units is not sufficient to cause the capital account of such ET Series G Preferred Unit to equal the liquidation preference of the ET Series G Preferred Unit, then the amount that a holder of such ET Series G Preferred Units would receive upon liquidation may be less than the ET Series G Preferred Unit liquidation preference. Any accumulated and unpaid distributions on the ET Series G Preferred Units and the parity securities will be paid prior to any distributions in liquidation made in accordance with capital account balances. The rights of holders of the ET Series G Preferred Units to receive the liquidation preference will be subject to the rights of the holders of any senior securities and the proportional rights of holders of the parity securities. A consolidation or merger of ET with or into any other entity, individually or in a series of transactions, will not be deemed to be a liquidation, dissolution or winding up of ET’s affairs.

VOTING RIGHTS

Except as described below, holders of the ETO Series G Preferred Units generally have no voting rights.

 

Unless ETO has received the affirmative vote or consent of the holders of at least two-thirds of the outstanding ETO Series G Preferred Units, voting as a separate class, ETO may not adopt any amendment to the ETO Partnership Agreement that would have a material adverse effect on the terms of the ETO Series G Preferred Units.

 

In addition, unless ETO has received the affirmative vote or consent of the holders of at least two-thirds of the outstanding ETO Series G Preferred Units, voting as a class together with holders of any other parity securities upon which like voting rights have been conferred and are exercisable, ETO may not (i) create or issue any parity securities (including any additional ETO Series G Preferred Units) if the cumulative distributions payable on then outstanding ETO Series G Preferred Units (or parity securities, if applicable) are in arrears, or (ii) create or issue any senior securities.

  

Except as described below, holders of the ET Series G Preferred Units generally will have no voting rights.

 

Unless ET has received the affirmative vote or consent of the holders of at least two-thirds of the outstanding ET Series G Preferred Units, voting as a separate class, ET may not adopt any amendment to the ET Partnership Agreement that would have a material adverse effect on the terms of the ET Series G Preferred Units.

 

In addition, unless ET has received the affirmative vote or consent of the holders of at least two-thirds of the outstanding ET Series G Preferred Units, voting as a class together with holders of any other parity securities upon which like voting rights have been conferred and are exercisable, ET may not (i) create or issue any parity securities (including any additional ET Series G Preferred Units) if the cumulative distributions payable on then outstanding ET Series G Preferred Units (or parity securities, if applicable) are in arrears, or (ii) create or issue any senior securities.

 

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ETO Series G Preferred Unitholders

  

ET Series G Preferred Unitholders

On any matter on which the holders of the ETO Series G Preferred Units are entitled to vote as a class, such holders will be entitled to one vote per ETO Series G Preferred Unit    On any matter on which the holders of the ET Series G Preferred Units are entitled to vote as a class, such holders will be entitled to one vote per ET Series G Preferred Unit
TRANSFER OF UNITS
There is no restriction on the transfer of the ETO Series G Preferred Units other than restrictions and conditions applicable to transfers of any limited partner interests under the ETO Partnership Agreement.    There is no restriction on the transfer of the ET Series G Preferred Units other than restrictions and conditions applicable to transfers of any limited partner interests under the ET Partnership Agreement.
PREEMPTIVE RIGHTS
No holder of ETO Series G Preferred Units has any preemptive, preferential or other similar right with respect to the issuance of additional partnership securities under the ETO Partnership Agreement.    No holder of ET Series G Preferred Units will have any preemptive, preferential or other similar right with respect to the issuance of additional partnership securities under the ET Partnership Agreement.
RIGHTS UPON A CHANGE OF CONTROL
The holders of ETO Series G Preferred Units do not have any specific rights or protections upon a change of control at ETO.    The holders of ET Series G Preferred Units will not have any specific rights or protections upon a change of control at ET.
NO SINKING FUND
The ETO Series G Preferred Units do not have the benefit of any sinking fund.    The ET Series G Preferred Units will not have the benefit of any sinking fund.

 

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NO APPRAISAL OR DISSENTERS’ RIGHTS

Holders of ETO Preferred Units do not have appraisal or dissenters’ rights under applicable law or contractual appraisal or dissenters’ rights under the ETO Partnership Agreement or the Merger Agreement.

 

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BUSINESS

ET

For information on ET’s business, see Part I. Item 1. “Business” in ET’s Annual Report on Form 10-K for the year ended December 31, 2020, attached as Annex C to this prospectus.

ETO

For information on ETO’s business, see Part I. Item 1. “Business” in ETO’s Annual Report on Form 10-K for the year ended December 31, 2020, attached as Annex D to this prospectus.

 

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PROPERTY

ET

For information on ET’s property, see Part I. Item 2. “Properties” in ET’s Annual Report on Form 10-K for the year ended December 31, 2020, attached as Annex C to this prospectus.

ETO

For information on ETO’s property, see Part I. Item 2. “Properties” in ETO’s Annual Report on Form 10-K for the year ended December 31, 2020, attached as Annex D to this prospectus.

 

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LEGAL PROCEEDINGS

ET

For information on ET’s legal proceedings, see Part I. Item 3. “Legal Proceedings” in ET’s Annual Report on Form 10-K for the year ended December 31, 2020, attached as Annex C to this prospectus.

ETO

For information on ETO’s property, see Part I. Item 3. “Legal Proceedings” in ETO’s Annual Report on Form 10-K for the year ended December 31, 2020, attached as Annex D to this prospectus.

 

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MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER

MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

ET

For information on ET’s common units, related unitholder matters and issuer purchases of securities, see Part II. Item 5. “Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities” in ET’s Annual Report on Form 10-K for the year ended December 31, 2020, attached as Annex C to this prospectus.

ETO

For information on ETO’s common units, related unitholder matters and issuer purchases of securities, see Part II. Item 5. “Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities” in ETO’s Annual Report on Form 10-K for the year ended December 31, 2020, attached as Annex D to this prospectus.

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

ET

For information on ET’s management’s discussion and analysis of financial condition and results of operations, see Part II. Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in ET’s Annual Report on Form 10-K for the year ended December 31, 2020, attached as Annex C to this prospectus.

ETO

For information on ETO’s management’s discussion and analysis of financial condition and results of operations, see Part II. Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in ETO’s Annual Report on Form 10-K for the year ended December 31, 2020, attached as Annex D to this prospectus.

 

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CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING

AND FINANCIAL DISCLOSURE

ET

For information on ET’s changes in and disagreements with accountants on accounting and financial disclosure, see Part II. Item 9. “Changes In and Disagreements with Accountants on Accounting and Financial Disclosure” in ET’s Annual Report on Form 10-K for the year ended December 31, 2020, attached as Annex C to this prospectus.

ETO

For information on ETO’s changes in and disagreements with accountants on accounting and financial disclosure, see Part II. Item 9. “Changes In and Disagreements with Accountants on Accounting and Financial Disclosure” in ETO’s Annual Report on Form 10-K for the year ended December 31, 2020, attached as Annex D to this prospectus.

 

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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ET

For information on quantitative and qualitative disclosures about ET’s market risk, see Part II. Item 7A. “Quantitative and Qualitative Disclosures About Market Risk” in ET’s Annual Report on Form 10-K for the year ended December 31, 2020, attached as Annex C to this prospectus.

ETO

For information on quantitative and qualitative disclosures about ETO’s market risk, see Part II. Item 7A. “Quantitative and Qualitative Disclosures About Market Risk” in ETO’s Annual Report on Form 10-K for the year ended December 31, 2020, attached as Annex D to this prospectus.

 

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LEGAL MATTERS

The validity of the ET Preferred Units to be issued in connection with the Merger and being offered hereby will be passed upon for ET by Latham & Watkins LLP, Houston, Texas. Certain U.S. federal income tax consequences relating to the ET Preferred Units will be passed upon by Latham & Watkins LLP, Houston, Texas.

 

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EXPERTS

ET

The consolidated financial statements of Energy Transfer LP and subsidiaries and management’s assessment of the effectiveness of internal control over financial reporting incorporated by reference in this prospectus and elsewhere in the registration statement have been so incorporated by reference in reliance upon the reports of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

ETO

The consolidated financial statements of Energy Transfer Operating, L.P. and subsidiaries incorporated by reference in this prospectus and elsewhere in the registration statement have been so incorporated by reference in reliance upon the report of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

 

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WHERE YOU CAN FIND MORE INFORMATION

ET has filed with the SEC a registration statement under the Securities Act of which this prospectus forms a part, which registers the ET Preferred Units to be issued to ETO Preferred Unitholders in connection with the Merger. The registration statement, including the exhibits and schedules attached to the registration statement, contains additional relevant information about ET and the ET Preferred Units.

ET and ETO are subject to the information and reporting requirements of the Exchange Act. In accordance with the Exchange Act, ET and ETO file annual, quarterly and current reports and other information with the SEC under the Exchange Act. Copies of ET’s and ETO’s filings with the SEC are available to you without charge upon written or oral request. You can obtain any of these documents by requesting them in writing or by telephone from ET or ETO at: 8111 Westchester Drive, Suite 600, Dallas, TX 75225, Attention: Investor Relations, Email: InvestorRelations@energytransfer.com. ET and ETO also make available free of charge on their internet website at www.energytransfer.com, respectively, the reports and other information filed by ET and ETO with the SEC, as soon as reasonably practicable after such material is electronically filed or furnished to the SEC. Neither ET’s nor ETO’s website, nor the information contained on their website, is part of this prospectus or the documents included herein.

In order to receive timely delivery of the documents in advance of closing of the Merger, your request should be received no later than                     , 2021. If you request any documents, ET or ETO will mail them to you by first class mail, or another equally prompt means, within one business day after receipt of your request.

This prospectus includes as annexes certain documents that ET and ETO have previously filed with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the Exchange Act as set forth in the table of contents of this prospectus. Any statement contained in such a document shall be deemed to be modified or superseded for purposes of this prospectus to the extent that a statement contained in this prospectus or in an annex hereto consisting of a document filed with the SEC subsequently to such document modifies or replaces such statement. The information included in the annexes hereto is incorporated into this prospectus except to the extent so modified or superseded.

The information concerning ET contained in this prospectus or the documents included herein has been provided by ET, and the information concerning ETO contained in this prospectus or the documents included herein has been provided by ETO.

Neither ET nor ETO has authorized anyone to give any information or make any representation about the Merger, ET or ETO that is different from, or in addition to, that contained in this prospectus or the documents included herein. Therefore, if anyone distributes this type of information, you should not rely on it. If you are in a jurisdiction where offers to exchange or sell, or solicitations of offers to exchange or purchase, the securities offered by this prospectus is unlawful, or you are a person to whom it is unlawful to direct these types or activities, then the offer presented in this prospectus does not extend to you. The information contained in this prospectus speaks only as of its date, or in the case of information in a document included herein, as of the date of such document, unless the information specifically indicates that another date applies.

 

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Annex A

 

AGREEMENT AND PLAN OF MERGER

by and among

ENERGY TRANSFER LP,

ETO MERGER SUB LLC

and

ENERGY TRANSFER OPERATING, L.P.

Dated as of March 5, 2021

 

 


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TABLE OF CONTENTS

 

ARTICLE I.

 

THE MERGER

 

Section 1.1

   The Merger      1  

Section 1.2

   Closing      2  

Section 1.3

   Effective Time      2  

Section 1.4

   Effects of the Merger      2  

Section 1.5

   Organizational Documents of the Surviving Entity      2  

Section 1.6

   ET Partnership Agreement      2  
ARTICLE II.

 

CONVERSION OF UNITS; EXCHANGE OF CERTIFICATES

 

Section 2.1

   Effect on ETO Partnership Interests.      2  

Section 2.2

   Exchange of Hook Units      4  

Section 2.3

   Exchange of ETO Preferred Units      4  

Section 2.4

   Withholding      6  
ARTICLE III.

 

REPRESENTATIONS AND WARRANTIES OF ETO

 

Section 3.1

   Organization and Existence      6  

Section 3.2

   Capitalization      7  

Section 3.3

   Power and Authority      7  

Section 3.4

   No Violations      7  
ARTICLE IV.

 

REPRESENTATIONS AND WARRANTIES OF ET AND MERGER SUB

 

Section 4.1

   Organization and Existence      8  

Section 4.2

   Capitalization      8  

Section 4.3

   Power and Authority      8  

Section 4.4

   No Violations      9  
ARTICLE V.

 

COVENANTS AND AGREEMENTS

 

Section 5.1

   Further Assurances      9  

Section 5.2

   Tax Matters      9  

Section 5.3

   Registration Statement      10  

Section 5.4

   NYSE Listing      10  
ARTICLE VI.

 

CONDITIONS TO THE MERGER

 

Section 6.1

   Conditions to Each Party’s Obligation to Effect the Merger      10  

 

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ARTICLE VII.

 

TERMINATION

 

Section 7.1

   Termination or Abandonment      10  
ARTICLE VIII.

 

MISCELLANEOUS

 

Section 8.1

   No Survival      10  

Section 8.2

   Expenses      11  

Section 8.3

   Counterparts; Effectiveness      11  

Section 8.4

   Governing Law      11  

Section 8.5

   Jurisdiction; Specific Enforcement      11  

Section 8.6

   WAIVER OF JURY TRIAL      11  

Section 8.7

   Assignment; Binding Effect      12  

Section 8.8

   Severability      12  

Section 8.9

   Entire Agreement      12  

Section 8.10

   Amendments; Waivers      12  

Section 8.11

   Headings      12  

Section 8.12

   No Third-Party Beneficiaries      12  

Section 8.13

   Interpretation      12  

Section 8.14

   Definitions      13  

Exhibit A

   Amendment No. 8 to ET Partnership Agreement   

 

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AGREEMENT AND PLAN OF MERGER

This AGREEMENT AND PLAN OF MERGER (this “Agreement”), dated as of March 5, 2021, is by and among Energy Transfer LP, a Delaware limited partnership (“ET”), ETO Merger Sub LLC, a Delaware limited liability company and a direct wholly owned subsidiary of ET (“Merger Sub”), and Energy Transfer Operating, L.P., a Delaware limited partnership (“ETO”) (each, a “party” and, together, the “parties”).

WITNESSETH:

WHEREAS, the parties intend that Merger Sub be merged with and into ETO (the “Merger”), with ETO surviving the Merger as a wholly owned subsidiary of ET;

WHEREAS, the Board of Directors of Energy Transfer Partners, L.L.C. (“ETO GP LLC”), a Delaware limited liability company and the general partner of Energy Transfer Partners GP, L.P. (“ETO GP”), a Delaware limited partnership and the general partner of ETO, has (a) determined that it is in the best interests of, and fair and reasonable to, ETO and its unitholders, and declared it advisable, for ETO to enter into this Agreement, (b) approved this Agreement, the execution, delivery and performance of this Agreement and the consummation of the transactions contemplated hereby, including the Merger and (c) directed that this Agreement be submitted to the holders of ETO Common Units and the holders of Hook Units for approval by written consent;

WHEREAS, ET, in its capacity as the record and beneficial owner of ETO Common Units constituting a “Unit Majority” (as defined in the ETO Partnership Agreement), has approved, by written consent, this Agreement and the transactions contemplated hereby, including the Merger;

WHEREAS, ETP Holdco Corporation, a Delaware corporation, in its capacity as the record and beneficial owner of all of the Hook Units, has approved, by written consent, this Agreement and the transactions contemplated hereby, including the Merger;

WHEREAS, the Board of Directors of LE GP, LLC, a Delaware limited liability company and the sole general partner of ET (“ET GP”), has (a) determined that it is in the best interests of, and fair and reasonable to, ET and its unitholders, and declared it advisable, for ET to enter into this Agreement, and (b) approved this Agreement, the execution, delivery and performance of this Agreement and the consummation of the transactions contemplated hereby, including the Merger;

WHEREAS, ET, as the sole member of Merger Sub, has (a) determined that it is in the best interests of Merger Sub, and declared it advisable, for Merger Sub to enter into this Agreement, and (b) approved this Agreement, the execution, delivery and performance of this Agreement and the consummation of the transactions contemplated hereby, including the Merger; and

WHEREAS, ET, Merger Sub and ETO desire to make certain representations, warranties, covenants and agreements specified herein in connection with this Agreement.

NOW, THEREFORE, in consideration of the foregoing and the representations, warranties, covenants and agreements contained herein, and intending to be legally bound hereby, ET, Merger Sub and ETO agree as follows:

ARTICLE I.

THE MERGER

Section 1.1 The Merger. At the Effective Time, upon the terms and subject to the conditions set forth in this Agreement and in accordance with the applicable provisions of the Delaware Revised Uniform Limited Partnership Act (the “Delaware LP Act”) and the Delaware Limited Liability Company Act (the “Delaware LLC

 

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Act”), Merger Sub shall be merged with and into ETO, whereupon the separate limited liability company existence of Merger Sub shall cease, and ETO shall continue its limited partnership existence under Delaware law as the surviving entity in the Merger (the “Surviving Entity”) with all limited partner interests in the Surviving Entity owned directly by ET and, prior to the dissolution of ETO GP contemplated by Section 2.1(e), all general partner interests in the Surviving Entity owned directly by ETO GP.

Section 1.2 Closing. The closing of the Merger (the “Closing”) shall take place at the offices of Latham & Watkins LLP, 811 Main Street, Suite 3700, Houston, Texas 77002, at 10:00 a.m., local time, on the second business day after the satisfaction or waiver (to the extent permitted by applicable Law) of the conditions set forth in Article VI (other than those conditions that by their nature are to be satisfied at the Closing, but subject to the satisfaction or waiver of such conditions), or at such other place, date and time as ET and ETO may agree. The date on which the Closing actually occurs is referred to as the “Closing Date.”

Section 1.3 Effective Time. On the Closing Date, ETO shall file with the Secretary of State of the State of Delaware a certificate of merger (the “Certificate of Merger”), executed in accordance with, and containing such information as is required by, the relevant provisions of the Delaware LP Act and the Delaware LLC Act in order to effect the Merger, and make any other filings or recordings as may be required by Delaware law in connection with the Merger. The Merger shall become effective at the date and time of the filing of the Certificate of Merger or at such later date and time as agreed to by ET and ETO and set forth in the Certificate of Merger in accordance with the relevant provisions of the Delaware LP Act and the Delaware LLC Act (such date and time is hereinafter referred to as the “Effective Time”).

Section 1.4 Effects of the Merger. The effects of the Merger shall be as provided in this Agreement and in the applicable provisions of the Delaware LP Act and the Delaware LLC Act. Without limiting the generality of the foregoing, and subject thereto, at the Effective Time, all of the property, rights, privileges, powers and franchises of ETO and Merger Sub shall vest in the Surviving Entity, and all debts, liabilities and duties of ETO and Merger Sub shall become the debts, liabilities and duties of the Surviving Entity, all as provided under the Delaware LP Act and the Delaware LLC Act.

Section 1.5 Organizational Documents of the Surviving Entity.

(a) At the Effective Time, the certificate of limited partnership of ETO, as in effect immediately prior to the Effective Time, shall remain unchanged and shall be the certificate of limited partnership of the Surviving Entity from and after the Effective Time until thereafter amended in accordance with the provisions thereof and applicable Law.

(b) At the Effective Time, the ETO Partnership Agreement, as in effect immediately prior to the Effective Time, shall remain unchanged and shall be the partnership agreement of the Surviving Entity from and after the Effective Time until thereafter amended in accordance with the provisions thereof and applicable Law.

Section 1.6 ET Partnership Agreement. Contemporaneously with the Closing, the Third Amended and Restated Agreement of Limited Partnership of ET, dated February 8, 2006, as amended (the “ET Partnership Agreement”), shall be amended pursuant to the authority of the General Partner in Sections 13.1(d) and 13.1(g) of the ET Partnership Agreement in substantially the form set forth in Exhibit A attached hereto (the “ET LPA Amendment”).

ARTICLE II.

CONVERSION OF UNITS; EXCHANGE OF CERTIFICATES

Section 2.1 Effect on ETO Partnership Interests.

(a) Treatment of Common Units. At the Effective Time, each common unit representing a limited partner interest in ETO (the “ETO Common Units”) issued and outstanding immediately prior to the Effective Time shall

 

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be unaffected by the Merger and remain outstanding as a limited partner interest in the Surviving Entity, and ET shall continue as a limited partner of ETO and be the sole limited partner of ETO.

(b) Conversion of Hook Units. At the Effective Time, by virtue of the Merger and without any action on the part of the parties or the holder thereof, the (i) Class K Units representing limited partner interests in ETO (the “ETO Class K Units”), (ii) Class L Units representing limited partner interests in ETO (the “ETO Class L Units”), (iii) Class M Units representing limited partner interests in ETO (the “ETO Class M Units”) and (iv) Class N Units representing limited partner interests in ETO (the “ETO Class N Units” and, together with the ETO Class K Units, the ETO Class L Units and the ETO Class M Units, the “Hook Units”), issued and outstanding immediately prior to the Effective Time shall be converted into the right to receive the following duly authorized, validly issued, fully paid and non-assessable (except to the extent such non-assessability may be affected by Sections 17-303, 17-607 and 17-804 of the Delaware LP Act) Class B Units representing limited partner interests in ET (the “ET Class B Units”) (the “Hook Unit Merger Consideration”):

 

  (i)

101,525,429 ETO Class K Units shall be converted into 193,396,409 ET Class B Units;

 

  (ii)

307,304,055 ETO Class L Units shall be converted into 244,726,324 ET Class B Units;

 

  (iii)

281,280,400 ETO Class M Units shall be converted into 149,334,657 ET Class B Units; and

 

  (iv)

166,068,756 ETO Class N Units shall be converted into 88,167,610 ET Class B Units.

(c) Conversion of ETO Preferred Units. At the Effective Time, by virtue of the Merger and without any action on the part of the parties or the holders thereof,

(i) each 6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Unit representing a limited partner interest in ETO (the “ETO Series A Preferred Units”) issued and outstanding immediately prior to the Effective Time shall be converted into the right to receive one duly authorized, validly issued, fully paid and non-assessable (except to the extent such non-assessability may be affected by Sections 17-303, 17-607 and 17-804 of the Delaware LP Act) ET Series A Preferred Unit;

(ii) each 6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Unit representing a limited partner interest in ETO (the “ETO Series B Preferred Units”) issued and outstanding immediately prior to the Effective Time shall be converted into the right to receive one duly authorized, validly issued, fully paid and non-assessable (except to the extent such non-assessability may be affected by Sections 17-303, 17-607 and 17-804 of the Delaware LP Act) ET Series B Preferred Unit;

(iii) each 7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Unit representing a limited partner interest in ETO (the “ETO Series C Preferred Units”) issued and outstanding immediately prior to the Effective Time shall be converted into the right to receive one duly authorized, validly issued, fully paid and non-assessable (except to the extent such non-assessability may be affected by Sections 17-303, 17-607 and 17-804 of the Delaware LP Act) ET Series C Preferred Unit;

(iv) each 7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Unit representing a limited partner interest in ETO (the “ETO Series D Preferred Units”) issued and outstanding immediately prior to the Effective Time shall be converted into the right to receive one duly authorized, validly issued, fully paid and non-assessable (except to the extent such non-assessability may be affected by Sections 17-303, 17-607 and 17-804 of the Delaware LP Act) ET Series D Preferred Unit;

(v) each 7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Unit representing a limited partner interest in ETO (the “ETO Series E Preferred Units”) issued and outstanding immediately prior to the Effective Time shall be converted into the right to receive one duly authorized, validly issued, fully paid and non-assessable (except to the extent such non-assessability may be affected by Sections 17-303, 17-607 and 17-804 of the Delaware LP Act) ET Series E Preferred Unit;

(vi) each 6.750% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Unit representing a limited partner interest in ETO (the “ETO Series F Preferred Units”) issued and outstanding

 

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immediately prior to the Effective Time shall be converted into the right to receive one duly authorized, validly issued, fully paid and non-assessable (except to the extent such non-assessability may be affected by Sections 17-303, 17-607 and 17-804 of the Delaware LP Act) ET Series F Preferred Unit;

(vii) each 7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Unit representing a limited partner interest in ETO (the “ETO Series G Preferred Units” and, together with the ETO Series A Preferred Units, ETO Series B Preferred Units, ETO Series C Preferred Units, ETO Series D Preferred Units, ETO Series E Preferred Units and ETO Series F Preferred Units, the “ETO Preferred Units” issued and outstanding immediately prior to the Effective Time shall be converted into the right to receive one duly authorized, validly issued, fully paid and non-assessable (except to the extent such non-assessability may be affected by Sections 17-303, 17-607 and 17-804 of the Delaware LP Act) ET Series G Preferred Unit (the “ET Series G Preferred Units,” and together with the ET Series A Preferred Units, ET Series B Preferred Units, ET Series C Preferred Units, ET Series D Preferred Units, ET Series E Preferred Units and the ET Series F Preferred Units, the “New ET Preferred Units” and collectively, the “Preferred Merger Consideration” and, together with the Hook Unit Merger Consideration, the “Merger Consideration”).

(d) Effect of the Merger on ETO Partnership Interests. All of the Hook Units and ETO Preferred Units converted into the right to receive ET Class B Units and New ET Preferred Units, respectively, shall cease to be outstanding, shall be cancelled and shall cease to exist as of the Effective Time, and each book-entry account formerly representing any Hook Unit or ETO Preferred Unit (each, a “Book-Entry Unit”) shall thereafter represent only the right to receive the applicable Merger Consideration.

(e) ETO General Partner Interest. At the Effective Time, the General Partner Interest (as defined in the ETO Partnership Agreement) of ETO issued and outstanding immediately prior to the Effective Time shall be unaffected by the Merger and remain outstanding as a general partner interest of the Surviving Entity, and ETO GP shall continue as the general partner of ETO (subject to the following sentence). Following the Effective Time, it is anticipated that ETO GP will be dissolved and as a result of such dissolution, ETO GP will withdraw as the general partner of ETO, the ETO general partner interest shall be distributed to ETO GP LLC, and ETO GP LLC shall be admitted as the successor general partner of ETO, with such admission being effective immediately prior to the withdrawal of ETO GP.

(f) Treatment of Merger Sub Interests. At the Effective Time, by virtue of the Merger and without any action on the part of the holder thereof, the limited liability company interests of Merger Sub (the “Merger Sub Units”) issued and outstanding immediately prior to the Effective Time shall be canceled and no consideration shall be paid in exchange therefor.

(g) No Dissenters or Appraisal Rights. No dissenters’ or appraisal rights shall be available with respect to the Merger or the other transactions contemplated hereby.

Section 2.2 Exchange of Hook Units. At the Effective Time, ET shall issue to the previous holders of the Hook Units the Hook Unit Merger Consideration to be held in non-certificated book-entry form.

Section 2.3 Exchange of ETO Preferred Units.

(a) Exchange Agent. Prior to the Effective Time, ET shall appoint an exchange agent mutually acceptable to ET and ETO (the “Exchange Agent”) for the purpose of exchanging ETO Preferred Units for the applicable portion of the Preferred Merger Consideration. Prior to the Effective Time, ET shall deposit, or shall cause to be deposited, with the Exchange Agent, in trust for the benefit of holders of ETO Preferred Units, New ET Preferred Units (which shall be in non-certificated book-entry form) issuable pursuant to Article II sufficient to effect the delivery of the applicable portion of the Preferred Merger Consideration to the holders of ETO Preferred Units. Following the Effective Time, ET agrees to make available to the Exchange Agent, from time to time as needed,

 

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New ET Preferred Units and cash sufficient to make any distributions pursuant to Section 2.3(c). All New ET Preferred Units and cash deposited with the Exchange Agent from time to time is hereinafter referred to as the “Exchange Fund.”

(b) Exchange Procedures. As soon as reasonably practicable after the Effective Time and in any event not later than the fifth business day following the Effective Time, ET shall cause the Exchange Agent to mail to each holder of ETO Preferred Units, which at the Effective Time were converted into the right to receive the applicable portion of the Preferred Merger Consideration pursuant to Section 2.1(a), (i) a customary letter of transmittal and (ii) instructions for use in effecting the surrender of the certificates or book-entry notations representing ETO Preferred Units (including customary provisions with respect to delivery of an “agent’s message” with respect to Book-Entry Units representing ETO Preferred Units) (in each case, “Certificates”) in exchange for the applicable portion of the Preferred Merger Consideration and any distributions payable pursuant to Section 2.3(c). Upon surrender of Certificates for cancellation to the Exchange Agent, together with such letter of transmittal, duly completed and validly executed in accordance with the instructions thereto, and such other documents as may reasonably be required by the Exchange Agent, the holder of such ETO Preferred Units shall be entitled to receive in exchange therefor (subject to withholding tax as specified in Section 2.4), as applicable, that number of whole New ET Preferred Units to which such holder is entitled pursuant to Section 2.1(c), and a check in an amount equal to the aggregate amount of cash that such holder has a right to receive pursuant to Section 2.3(c) to which such holder is entitled, and the ETO Preferred Units represented by the Certificates so surrendered shall forthwith be cancelled. If any cash payment is to be made to, or any New ET Preferred Units constituting any part of the applicable portion of the Preferred Merger Consideration is to be registered in the name of, a person other than the person in whose name the applicable surrendered ETO Preferred Units is registered, it shall be a condition to the payment or registration thereof that the surrendered Certificate be in proper form for transfer and that the person requesting such payment or delivery of the Preferred Merger Consideration pay any transfer or other similar Taxes required as a result of such registration in the name of a person other than the registered holder of such Certificate or establish to the satisfaction of the Exchange Agent that such Tax has been paid or is not payable. Until surrendered as contemplated by this Section 2.3(b), each Certificate shall be deemed at any time after the Effective Time to represent only the right to receive the applicable portion of the Preferred Merger Consideration (and any amounts to be paid pursuant to Section 2.3(c)) upon such surrender. No interest shall be paid or shall accrue on any amount payable pursuant to Section 2.3(c).

(c) Distributions with Respect to New ET Preferred Units. No distributions with respect to New ET Preferred Units shall be paid to the holder of any unsurrendered Certificates with respect to ETO Preferred Units represented thereby until such Certificate has been surrendered in accordance with this Article II. Subject to applicable Laws, following surrender of any such Certificate, there shall be paid to the record holder thereof, without interest, (i) promptly after such surrender, the amount of distributions with a record date after the Effective Time and a payment date on or prior to the date of such surrender and not theretofore paid with respect to such New ET Preferred Units and (ii) at the appropriate payment date, the amount of distributions with a record date after the Effective Time and a payment date subsequent to the date of such surrender payable with respect to such New ET Preferred Units.

(d) No Further Ownership Rights in ETO Preferred Units; Closing of Transfer Books. All Preferred Merger Consideration issued upon the surrender for exchange of Certificates representing ETO Preferred Units in accordance with the terms of this Article II and any cash paid pursuant to Section 2.3(c) shall be deemed to have been issued (or paid) in full satisfaction of all rights pertaining to ETO Preferred Units previously represented by such Certificates. After the Effective Time, the transfer books of ETO shall be closed, and there shall be no further registration of transfers on the transfer books of the Surviving Entity of ETO Preferred Units that were outstanding immediately prior to the Effective Time. If, after the Effective Time, Certificates are presented to the Surviving Entity or the Exchange Agent for any reason, they shall be cancelled and exchanged as provided in this Article II.

 

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(e) Termination of Exchange Fund. Any portion of the Exchange Fund (including the proceeds of any investments thereof) that remains undistributed to the former holders of ETO Preferred Units for one year after the Effective Time shall be delivered to ET upon demand, and any holders of ETO Preferred Units who have not theretofore complied with this Article II shall thereafter look only to ET for payment of their claim of the applicable portion of the Preferred Merger Consideration and any distributions pursuant to Section 2.3(c). Any amounts remaining unclaimed by holders of ETO Preferred Units immediately prior to such time as such amounts would otherwise escheat to or become the property of any federal, state of the United States, local, foreign, domestic, tribal or multinational government, regulatory or administrative agency, bureau, commission, commissioner, legislature, court, arbitrator, body, entity or other authority or governmental instrumentality (each, a “Governmental Entity”) will, to the extent permitted by applicable Law, become the property of ET.

(f) Lost, Stolen or Destroyed Certificates. If any Certificate shall have been lost, stolen or destroyed, upon the making of an affidavit of that fact by the person claiming such Certificate to be lost, stolen or destroyed and, if required by ET, the posting by such person of a bond, in such reasonable amount as ET may direct, as indemnity against any claim that may be made against it with respect to such Certificate, the Exchange Agent will issue and pay in exchange for such lost, stolen or destroyed Certificate the applicable portion of the Preferred Merger Consideration and distributions to be paid in respect of ETO Preferred Units represented by such Certificate as contemplated by this Article II.

(g) No Liability. Notwithstanding anything in this Agreement to the contrary, none of ETO, ET, Merger Sub, the Exchange Agent or any other person shall be liable to any former holder of ETO Preferred Units for any amount properly delivered to a public official pursuant to any applicable abandoned property, escheat or similar Law.

Section 2.4 Withholding. Each of ET, Merger Sub and the Exchange Agent shall be entitled to deduct and withhold from the consideration otherwise payable pursuant to this Agreement such amounts as ET, Merger Sub and the Exchange Agent are required to deduct and withhold under the Internal Revenue Code of 1986, as amended (the “Code”), or any Tax Law, with respect to the making of such payment (and to the extent deduction and withholding is required, such deduction and withholding may be taken in ET Class B Units or New ET Preferred Units, as applicable). To the extent that amounts are so withheld and paid over to the applicable Governmental Entity, such withheld amounts shall be treated for all purposes of this Agreement as having been paid to the person in respect of whom such deduction and withholding was made. If withholding is taken in ET Class B Units or New ET Preferred Units, ET, Merger Sub or the Exchange Agent (as applicable) shall be treated as having sold such ET Class B Units or New ET Preferred Units, as applicable, for an amount of cash equal to the fair market value of such ET Class B Units or New ET Preferred Units at the time of such deemed sale.

ARTICLE III.

REPRESENTATIONS AND WARRANTIES OF ETO

ETO hereby represents and warrants to ET and Merger Sub as follows:

Section 3.1 Organization and Existence. Each of ETO and its Subsidiaries is a legal entity duly organized or formed, validly existing and in good standing under the Laws of its jurisdiction of organization or formation and has all requisite limited partnership, limited liability company or other applicable power and authority to own, lease and operate its properties and assets and to carry on its business as presently conducted, except to the extent that the failure to have such power or authority would not be reasonably likely to have a material adverse effect on ETO’s ability to enter into or perform its obligations under this Agreement or consummate the transactions contemplated hereby. Each of ETO and its Subsidiaries is qualified to do business in each jurisdiction where the nature of its business or the ownership of its properties requires it to be so qualified, except to the extent that the failure to be so qualified would not be reasonably likely to have a material adverse effect on ETO’s ability to enter into or perform its obligations under this Agreement or consummate the transactions contemplated hereby.

 

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Section 3.2 Capitalization. As of March 4, 2021, the issued and outstanding limited partner interests and general partner interests of ETO consisted of: (a) 2,458,702,066 ETO Common Units; (b) 101,525,429 ETO Class K Units; (c) 307,304,055 ETO Class L Units; (d) 281,280,400 ETO Class M Units; (e) 166,068,939 ETO Class N Units; (f) 950,000 ETO Series A Preferred Units; (g) 550,000 ETO Series B Preferred Units; (h) 18,000,000 ETO Series C Preferred Units; (i) 17,800,000 ETO Series D Preferred Units; (j) 32,000,000 ETO Series E Preferred Units; (k) 500,000 ETO Series F Preferred Units; (l) 1,100,000 ETO Series G Preferred Units issued and outstanding; and (m) the non-economic general partner interest (the “ETO GP Interest”). All outstanding limited partner interests and the ETO GP Interest are duly authorized, validly issued, fully paid (to the extent required by the ETO Partnership Agreement) and nonassessable (except as such nonassessability may be affected by matters described in Sections 17-303, 17-607 and 17-804 of the Delaware LP Act) and free of preemptive rights (except as set forth in the ETO Partnership Agreement).

Section 3.3 Power and Authority.

(a) ETO has the limited partnership power and authority to enter into this Agreement and to perform all of its obligations and consummate the transactions contemplated hereby and thereby. ETO has taken all necessary and appropriate limited partnership actions to authorize, execute and deliver this Agreement and each agreement and instrument to be executed and delivered by ETO pursuant hereto, and to consummate the transactions contemplated hereby and thereby. This Agreement has been duly and validly executed and delivered by ETO and is a valid and binding obligation of ETO enforceable in accordance with its terms, except as such enforcement may be limited by applicable bankruptcy, insolvency, moratorium or similar laws affecting the rights of creditors generally and by general principles of equity (collectively, the “Enforceability Exceptions”).

(b) Other than in connection with or in compliance with (i) the Delaware LP Act, (ii) the Delaware LLC Act, (iii) the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the rules promulgate thereunder, (iv) the Securities Act of 1933, as amended (the “Securities Act”), and the rules promulgated thereunder, (v) applicable state securities, takeover, and “blue sky” laws, (vi) the filing of the Certificate of Merger with the Secretary of State of the State of Delaware, (vii) the rules and regulations of the New York Stock Exchange (the “NYSE”), (viii) the rules and regulations of the Securities and Exchange Commission (the “SEC”) in connection with the filing with the SEC of a registration statement on Form S-4 to register the issuance of the Preferred Merger Consideration, and subject to the accuracy of the representations and warranties of ET and Merger Sub in Section 4.3(b), no authorization, consent, order, license, permit or approval of, or registration, declaration, notice or filing with, any Governmental Entity is necessary, under applicable Law, for the consummation by ETO or ETO GP LLC of the transactions contemplated by this Agreement, except such authorizations, consent, orders, licenses permits, approvals or filings that are not required to be obtained or made prior to consummation of such transactions or that, if not obtained or made, would not materially impede or delay the consummation of the Merger and the other transactions contemplated by this Agreement.

Section 3.4 No Violations. The execution and delivery of this Agreement or any other agreement or instrument executed and delivered pursuant hereto by ETO, does not, or when executed will not, and the consummation of the transactions contemplated hereby or thereby and the performance by ETO of the obligations that it is obligated to perform hereunder or thereunder do not:

(a) conflict with or result in a breach of any of the provisions of the ETO Partnership Agreement;

(b) create any lien on ETO under any indenture, mortgage, lien, agreement, contract, commitment or instrument to which ETO is a party or its properties and assets are bound;

(c) conflict with any municipal, state or federal ordinance, law (including common law), rule, regulation, judgment, order, writ, injunction, or decree (collectively, “Laws”) applicable to ETO; or

(d) conflict with, result in a breach of, constitute a default under (whether with notice or the lapse of time or both) or accelerate or permit the acceleration of the performance required by, or require any consent,

 

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authorization or approval under, any indenture, mortgage, lien or agreement, contract, commitment or instrument to which ETO is a party or by which it is bound;

except, in the case of clauses (b), (c) and (d), as would not be reasonably likely to have, individually or in the aggregate, a materially adverse effect on ETO or result in any material loss, cost or liability of ETO.

ARTICLE IV.

REPRESENTATIONS AND WARRANTIES OF ET AND MERGER SUB

Each of ET and Merger Sub, jointly and severally, represents and warrants to ETO as follows:

Section 4.1 Organization and Existence.

(a) Each of ET and Merger Sub is a legal entity duly organized, validly existing and in good standing under the laws of the State of Delaware and has all requisite limited partnership and limited liability company power and authority to own, lease and operate its properties and assets and to carry on its business as presently conducted, except to the extent that the failure to have such power or authority would not be reasonably likely to have a material adverse effect on ET or Merger Sub’s ability to perform its obligations under this Agreement or consummate the transactions contemplated hereby. Each of ET and Merger Sub is qualified to do business in each jurisdiction where the nature of its business or the ownership of its properties requires it to be qualified, except to the extent that the failure to be so qualified would not be reasonably likely to have a material and adverse effect on ET or Merger Sub’s ability to enter into or perform its obligations under this Agreement or consummate the transaction contemplated hereby.

Section 4.2 Capitalization.

(a) As of March 4, 2021, the issued and outstanding limited partner interests and general partner interests of ET consisted of (i) 2,703,455,611 common units representing limited partner interests in ET, (ii) 669,124,023 Class A Units representing limited partner interests in ET and (iii) the general partner interest (the “ET GP Interest”). All outstanding limited partner interests and the ET GP Interest are duly authorized, validly issued, fully paid (to the extent required by the ET Partnership Agreement) and nonassessable (except as such nonassessability may be affected by matters described in Sections 17-303, 17-607 and 17-804 of the Delaware LP Act) and free of preemptive rights (except as set forth in the ET Partnership Agreement).

(b) As of the date of this Agreement, all of the issued and outstanding limited liability company interests of Merger Sub are validly issued and outstanding. All of the issued and outstanding limited liability company interests of Merger Sub are, and at the Effective Time will be, owned by ET or a direct or indirect wholly owned Subsidiary of ET. Merger Sub does not have any outstanding option, warrant, right or any other agreement pursuant to which any person other than ET may acquire any equity security of Merger Sub. Merger Sub has not conducted any business prior to the date hereof and neither has, and prior to the Effective Time will not have, any assets, liabilities or obligations of any nature other than those incident to their respective formation and pursuant to this Agreement, the Merger and the other transactions contemplated by this Agreement.

Section 4.3 Power and Authority.

(a) Each of ET and Merger Sub has the requisite limited partnership or limited liability company, as applicable, power and authority to enter into this Agreement and to perform all of their respective obligations and consummate the transactions contemplated hereby and thereby. Each of ET and Merger Sub has taken all necessary and appropriate limited partnership or limited liability company, as applicable, actions to authorize, execute and deliver this Agreement and each agreement and instrument to be executed and delivered by ET

 

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pursuant hereto, and to consummate the transactions contemplated hereby and thereby. This Agreement has been duly and validly executed and delivered by ET and is a valid and binding obligation of ET enforceable in accordance with its terms, except as such enforcement may be limited by the Enforceability Exceptions.

(b) Other than in connection with or in compliance with (i) the Delaware LP Act, (ii) the Delaware LLC Act, (iii) the Exchange Act, and the rules promulgated thereunder, (iv) the Securities Act, and the rules promulgated thereunder, (v) applicable state securities, takeover and “blue sky” laws, (vi) the filing of the Certificate of Merger with the Secretary of State of the State of Delaware, (vii) the rules and regulations of the NYSE, (viii) rules and regulations of the SEC in connection with the filing with the SEC of a registration statement on Form S-4 to register the issuance of the Preferred Merger Consideration, and, subject to the accuracy of the representations and warranties of the ETO in Section 3.3(b), no authorization, consent, order, license, permit or approval of, or registration, declaration, notice or filing with, any Governmental Entity is necessary, under applicable Law, for the consummation by ET or Merger Sub of the transactions contemplated by this Agreement, except for such authorizations, consent, orders, licenses, permits, approvals or filings that are not required to be obtained or made prior to consummation of such transactions or that, if not obtained or made, would not materially impede or delay the consummation of the Merger and the other transactions contemplated by this Agreement.

Section 4.4 No Violations. The execution and delivery of this Agreement, or any other agreement or instrument executed and delivered pursuant hereto by ET and Merger Sub, does not, or when executed will not, and the consummation of the transactions contemplated hereby or thereby and the performance by ET and Merger Sub of the respective obligations that they are obligated to perform hereunder or thereunder do not:

(a) conflict with or result in a breach of any of the provisions of the ET Partnership Agreement or the limited liability company agreement of Merger Sub;

(b) create any lien on ET or Merger Sub under any indenture, mortgage, lien, agreement, contract, commitment or instrument to which ET or Merger Sub is a party or their respective properties and assets are bound;

(c) conflict with any Laws applicable to ET or Merger Sub; or

(d) conflict with, result in a breach of, constitute a default under (whether with notice or the lapse of time or both) or accelerate or permit the acceleration of the performance required by, or require any consent, authorization or approval under, any indenture, mortgage, lien or agreement, contract, commitment or instrument to which ET or Merger Sub is a party or by which it is bound;

except, in the case of clauses (b), (c) and (d), as would not be reasonably likely to have, individually or in the aggregate, a materially adverse effect on ET or Merger Sub or result in any material loss, cost or liability of ET or Merger Sub.

ARTICLE V.

COVENANTS AND AGREEMENTS

Section 5.1 Further Assurances. In case at any time after the Closing any further action is necessary to carry out the transactions contemplated hereby or the purposes of this Agreement, each of the parties will take such further action as the other party may reasonably request.

Section 5.2 Tax Matters. ET and ETO each acknowledges and agrees that, for U.S. federal income and applicable state and local tax purposes, the Merger is intended to be treated as a partnership merger transaction

 

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under Treasury Regulations Sections 1.708-1(c)(1) and 1.708-1(c)(3)(i), whereby ETO will be the terminating partnership and ET will be the resulting partnership (the “Intended Tax Treatment”). Unless required to do so as a result of a “determination” as defined in Section 1313 of the Code, each of ET and ETO agrees not to make any tax filings or otherwise take any position inconsistent with the Intended Tax Treatment and to cooperate with the other party to make any filings, statements, or reports required to effect, disclose or report the Intended Tax Treatment.

Section 5.3 Registration Statement. Each of ET, Merger Sub and ETO shall jointly prepare, and ET shall file with the SEC, a registration statement on Form S-4 to be filed with the SEC in connection with the issuance of the New ET Preferred Units in the Merger (including any amendments or supplements, the “Form S-4”).

Section 5.4 NYSE Listing. ET shall cause the ET Series C Preferred Units, ET Series D Preferred Units and ET Series E Preferred Units to be issued in the Merger to be approved for listing on the NYSE, subject to official notice of issuance, prior to the Closing Date.

ARTICLE VI.

CONDITIONS TO THE MERGER

Section 6.1 Conditions to Each Partys Obligation to Effect the Merger. The respective obligations of each party to effect the Merger shall be subject to the fulfillment (or waiver by all parties, to the extent permissible under applicable Law) at or prior to the Effective Time of the following conditions:

(a) no injunction, order or decree by any court or other Governmental Entity of competent jurisdiction shall have been entered and shall continue to be in effect, no Law shall have been adopted or be effective, and no agreement with any Governmental Entity shall be in effect, in each case that prohibits, prevents or makes unlawful the consummation of the Merger or the other transactions contemplated by this Agreement;

(b) the representations and warranties of each party shall be true and correct in all material respects both at and as of the date of this Agreement and at and as of the Closing Date as though made at and as of the Closing Date; and

(c) the Form S-4 shall have been declared effective by the SEC under the Securities Act and no stop order suspending the effectiveness of the Form S-4 shall have been issued by the SEC and no proceedings for that purpose shall have been initiated or threatened by the SEC.

ARTICLE VII.

TERMINATION

Section 7.1 Termination or Abandonment. Notwithstanding anything in this Agreement to the contrary, this Agreement may be terminated and abandoned at any time prior to the Effective Time by the mutual written consent of ETO and ET.

ARTICLE VIII.

MISCELLANEOUS

Section 8.1 No Survival. None of the representations, warranties, covenants and agreements in this Agreement or in any instrument delivered pursuant to this Agreement shall survive the Merger, except for covenants and agreements which contemplate performance after the Effective Time or otherwise expressly by their terms survive the Effective Time.

 

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Section 8.2 Expenses. All costs and expenses incurred in connection with the Merger, this Agreement and the transactions contemplated hereby shall be paid by the party incurring or required to incur such expenses.

Section 8.3 Counterparts; Effectiveness. This Agreement may be executed in two or more counterparts, each of which shall be an original, with the same effect as if the signatures thereto and hereto were upon the same instrument, and shall become effective when one or more counterparts have been signed by each of the parties and delivered (by telecopy, electronic delivery or otherwise) to the other parties. Signatures to this Agreement transmitted by facsimile transmission, by electronic mail in “portable document format” (“.pdf”) form, or by any other electronic means intended to preserve the original graphic and pictorial appearance of a document, will have the same effect as physical delivery of the paper document bearing the original signature.

Section 8.4 Governing Law. This Agreement, and all claims or causes of action (whether at Law, in contract or in tort or otherwise) that may be based upon, arise out of or relate to this Agreement or the negotiation, execution or performance hereof, shall be governed by and construed in accordance with the laws of the State of Delaware, without giving effect to any choice or conflict of law provision or rule (whether of the State of Delaware or any other jurisdiction) that would cause the application of the laws of any jurisdiction other than the State of Delaware.

Section 8.5 Jurisdiction; Specific Enforcement. The parties agree that irreparable damage, for which monetary damages would not be an adequate remedy, would occur in the event that any of the provisions of this Agreement were not performed, or were threatened to not be performed, in accordance with their specific terms or were otherwise breached. It is accordingly agreed that, in addition to any other remedy that may be available to it at law or in equity, each of the parties shall be entitled to an injunction or injunctions or equitable relief to prevent breaches of this Agreement and to enforce specifically the terms and provisions of this Agreement exclusively in the Delaware Court of Chancery and any state appellate court therefrom within the State of Delaware (or, if the Delaware Court of Chancery declines to accept jurisdiction over a particular matter, any state or federal court within the State of Delaware), and all such rights and remedies at law or in equity shall be cumulative. The parties further agree that no party to this Agreement shall be required to obtain, furnish or post any bond or similar instrument in connection with or as a condition to obtaining any remedy referred to in this Section 8.5 and each party waives any objection to the imposition of such relief or any right it may have to require the obtaining, furnishing or posting of any such bond or similar instrument. In addition, each of the parties hereto irrevocably agrees that any legal action or proceeding relating to or arising out of this Agreement and the rights and obligations hereunder, or for recognition and enforcement of any judgment relating to or arising out of this Agreement and the rights and obligations hereunder brought by the other party hereto or its successors or assigns, shall be brought and determined exclusively in the Delaware Court of Chancery and any state appellate court therefrom within the State of Delaware (or, if the Delaware Court of Chancery declines to accept jurisdiction over a particular matter, any state or federal court within the State of Delaware). Each of the parties hereto hereby irrevocably submits with regard to any such action or proceeding for itself and in respect of its property, generally and unconditionally, to the personal jurisdiction of the aforesaid courts and agrees that it will not bring any action relating to or arising out of this Agreement or any of the transactions contemplated by this Agreement in any court other than the aforesaid courts. Each of the parties hereto hereby irrevocably waives, and agrees not to assert, by way of motion, as a defense, counterclaim or otherwise, in any action or proceeding with respect to this Agreement, (a) any claim that it is not personally subject to the jurisdiction of the above named courts, (b) any claim that it or its property is exempt or immune from jurisdiction of any such court or from any legal process commenced in such courts (whether through service of notice, attachment prior to judgment, attachment in aid of execution of judgment, execution of judgment or otherwise) and (c) to the fullest extent permitted by the applicable Law, any claim that (i) the suit, action or proceeding in such court is brought in an inconvenient forum, (ii) the venue of such suit, action or proceeding is improper or (iii) this Agreement, or the subject matter hereof, may not be enforced in or by such courts.

Section 8.6 WAIVER OF JURY TRIAL. EACH OF THE PARTIES HERETO ACKNOWLEDGES AND AGREES THAT ANY CONTROVERSY THAT MAY ARISE UNDER THIS AGREEMENT IS LIKELY TO

 

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INVOLVE COMPLICATED AND DIFFICULT ISSUES, AND THEREFORE EACH SUCH PARTY IRREVOCABLY AND UNCONDITIONALLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY AND ALL RIGHT TO TRIAL BY JURY IN ANY ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY.

Section 8.7 Assignment; Binding Effect. This Agreement shall be binding upon and shall inure to the benefit of the parties hereto and their respective successors and assigns.

Section 8.8 Severability. Any term or provision of this Agreement that is held to be invalid or unenforceable in a court of competent jurisdiction shall be ineffective to the extent of such invalidity or unenforceability without rendering invalid or unenforceable the remaining terms and provisions of this Agreement. Upon such a determination, the parties hereto shall negotiate in good faith to modify this Agreement so as to effect the original intent of the parties hereto as closely as possible in an acceptable manner in order that the transactions contemplated hereby are consummated as originally contemplated to the fullest extent possible. If any provision of this Agreement is so broad as to be unenforceable, such provision shall be interpreted to be only so broad as is enforceable.

Section 8.9 Entire Agreement. This Agreement together with the exhibits and schedules hereto constitutes the entire agreement, and supersedes all other prior agreements and understandings, both written and oral, between the parties, or any of them, with respect to the subject matter hereof, and this Agreement is not intended to grant standing to any person other than the parties hereto.

Section 8.10 Amendments; Waivers. At any time prior to the Effective Time, any provision of this Agreement may be amended or waived if, and only if, such amendment or waiver is in writing and signed, in the case of an amendment, by ETO, ET and Merger Sub or, in the case of a waiver, by the party against whom the waiver is to be effective.

Section 8.11 Headings. Headings of the Articles and Sections of this Agreement are for convenience of the parties only and shall be given no substantive or interpretive effect whatsoever. The table of contents to this Agreement is for reference purposes only and shall not affect in any way the meaning or interpretation of this Agreement.

Section 8.12 No Third-Party Beneficiaries. Each of ET, Merger Sub and ETO agrees that (a) their respective representations, warranties, covenants and agreements set forth herein are solely for the benefit of ETO or ET and Merger Sub, as applicable, in accordance with and subject to the terms of this Agreement, and (b) except for the right of ETO’s unitholders to receive the Merger Consideration on the terms and conditions of this Agreement, this Agreement is not intended to, and does not, confer upon any person other than the parties hereto any rights or remedies hereunder, including the right to rely upon the representations and warranties set forth herein.

Section 8.13 Interpretation. When a reference is made in this Agreement to an Article or Section, such reference shall be to an Article or Section of this Agreement unless otherwise indicated. Whenever the words “include,” “includes” or “including” are used in this Agreement, they shall be deemed to be followed by the words “without limitation.” The words “hereof,” “herein” and “hereunder” and words of similar import when used in this Agreement shall refer to this Agreement as a whole and not to any particular provision of this Agreement, unless the context otherwise requires. All terms defined in this Agreement shall have the defined meanings when used in any certificate or other document made or delivered pursuant thereto unless otherwise defined therein. The definitions contained in this Agreement are applicable to the singular as well as the plural forms of such terms and to the masculine as well as to the feminine and neuter genders of such term. References in this Agreement to specific laws or to specific provisions of laws shall include all rules and regulations promulgated thereunder, and any statute defined or referred to herein or in any agreement or instrument referred

 

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to herein shall mean such statute as from time to time amended, modified or supplemented, including by succession of comparable successor statutes. Each of the parties has participated in the drafting and negotiation of this Agreement. If an ambiguity or question of intent or interpretation arises, this Agreement must be construed as if it is drafted by all the parties, and no presumption or burden of proof shall arise favoring or disfavoring any party by virtue of authorship of any of the provisions of this Agreement.

Section 8.14 Definitions.

(a) As used in this Agreement:

(i) “business day” means any day other than a Saturday, a Sunday or a legal holiday for commercial banks in New York, New York.

(ii) “ET Series A Preferred Unit” means a new series of preferred units representing limited partner interests in ET, to be established at Closing pursuant to the ET LPA Amendment, designated as “6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units” and having the preferences, rights, powers and duties set forth in the ET LPA Amendment.

(iii) “ET Series B Preferred Unit” means a new series of preferred units representing limited partner interests in ET, to be established at Closing pursuant to the ET LPA Amendment, designated as “6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units” and having the preferences, rights, powers and duties set forth in the ET LPA Amendment.

(iv) “ET Series C Preferred Unit” means a new series of preferred units representing limited partner interests in ET, to be established at Closing pursuant to the ET LPA Amendment, designated as “7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units” and having the preferences, rights, powers and duties set forth in the ET LPA Amendment.

(v) “ET Series D Preferred Unit” means a new series of preferred units representing limited partner interests in ET, to be established at Closing pursuant to the ET LPA Amendment, designated as “7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units” and having the preferences, rights, powers and duties set forth in the ET LPA Amendment.

(vi) “ET Series E Preferred Unit” means a new series of preferred units representing limited partner interests in ET, to be established at Closing pursuant to the ET LPA Amendment, designated as “7.600% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units” and having the preferences, rights, powers and duties set forth in the ET LPA Amendment.

(vii) “ET Series F Preferred Unit” means a new series of preferred units representing limited partner interests in ET, to be established at Closing pursuant to the ET LPA Amendment, designated as “6.750% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units” and having the preferences, rights, powers and duties set forth in the ET LPA Amendment.

(viii) “ET Series G Preferred Unit” means a new series of preferred units representing limited partner interests in ET, to be established at Closing pursuant to the ET LPA Amendment, designated as “7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units” and having the preferences, rights, powers and duties set forth in the ET LPA Amendment.

(ix) “ETO Partnership Agreement” means that certain Fifth Amended Restated Agreement of Limited Partnership of ETO, dated October 19, 2018, as amended.

(x) “person” means an individual, a corporation, a partnership, a limited liability company, an association, a trust or any other entity, group (as such term is used in Section 13 of the Exchange Act) or organization, including a Governmental Entity, and any permitted successors and assigns of such person.

 

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(xi) “Subsidiary” means, with respect to any person, any corporation, limited liability company, partnership, association, or business entity, whether incorporated or unincorporated, of which (A) if a corporation, a majority of the total voting power of shares of stock entitled (without regard to the occurrence of any contingency) to vote in the election of directors, managers, or trustees thereof is at the time owned or controlled, directly or indirectly, by that person or one or more Subsidiaries of that person or a combination thereof, (B) if a partnership (whether general or limited), a general partner interest is at the time owned or controlled, directly or indirectly, by that person or one or more Subsidiaries of that person or a combination thereof or (C) if a limited liability company, partnership, association, or other business entity (other than a corporation), a majority of partnership or other similar ownership interest thereof is at the time owned or controlled, directly or indirectly, by that person or one or more Subsidiaries of that person or a combination thereof. For purposes hereof, a person or persons shall be deemed to have a majority ownership interest in a limited liability company, partnership, association, or other business entity (other than a corporation) if such person or persons shall be allocated a majority of limited liability company, partnership, association, or other business entity gains or losses. Notwithstanding the foregoing, none of USA Compression Partners, LP, Sunoco LP or any of their respective Subsidiaries shall be deemed Subsidiaries of ET or ETO.

(xii) “Tax” or “Taxes” means any and all U.S. federal, state or local or non-U.S. or provincial taxes, charges, imposts, levies or other assessments, including all net income, gross receipts, capital, sales, use, ad valorem, value added, transfer, franchise, profits, inventory, capital stock, license, withholding, payroll, employment, social security, unemployment, excise, severance, stamp, occupation, property and estimated taxes, customs duties, fees, assessments and similar charges, including any and all interest, penalties, fines, additions to tax or additional amounts imposed by any Governmental Entity in connection or with respect thereto.

(xiii) “Tax Return” means any return, report or similar filing (including any attached schedules, supplements and additional or supporting material) filed or required to be filed with respect to Taxes, including any information return, claim for refund, amended return or declaration of estimated Taxes (and including any amendments with respect thereto).

(xiv) “Treasury Regulations” means the regulations (including temporary regulations) promulgated by the United States Department of the Treasury pursuant to and in respect of provisions of the Code. All references in this Agreement to sections of the Treasury Regulations shall include any corresponding provisions or provisions of succeeding, similar or substitute, temporary or final Treasury Regulations.

(b) Each of the following terms is defined in the section of this Agreement set forth opposite such term:

 

Agreement

   Preamble

Book-Entry Unit

   Section 2.1(d)

business day

   Section 8.14(a)(i)

Certificate of Merger

   Section 1.3

Certificates

   Section 2.3(b)

Closing

   Section 1.2

Closing Date

   Section 1.2

Code

   Section 2.4

Delaware LLC Act

   Section 1.1

Delaware LP Act

   Section 1.1

Effective Time

   Section 1.3

Enforceability Exceptions

   Section 3.3

ET

   Preamble

ET Class B Units

   Section 2.1(b)

ET GP

   Recitals

ET LPA Amendment

   Section 1.6

ET Partnership Agreement

   Section 1.6

ET Series A Preferred Units

   Section 8.14(a)(i)

 

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ET Series B Preferred Units

   Section 8.14(a)(i)

ET Series C Preferred Units

   Section 8.14(a)(i)

ET Series D Preferred Units

   Section 8.14(a)(i)

ET Series E Preferred Units

   Section 8.14(a)(i)

ET Series F Preferred Units

   Section 8.14(a)(i)

ET Series G Preferred Units

   Section 8.14(a)(i)

ETO

   Preamble

ETO Class K Units

   Section 2.1(b)

ETO Class L Units

   Section 2.1(b)

ETO Class M Units

   Section 2.1(b)

ETO Class N Units

   Section 2.1(b)

ETO Common Units

   Section 2.1(a)

ETO GP

   Preamble

ETO GP Interest

   Section 3.2

ETO GP LLC

   Preamble

ETO Partnership Agreement

   Section 8.14(a)(ix)

ETO Preferred Units

   Section 2.1(c)(vii)

ETO Series A Preferred Units

   Section 2.1(c)(i)

ETO Series B Preferred Units

   Section 2.1(c)(ii)

ETO Series C Preferred Units

   Section 2.1(c)(iii)

ETO Series D Preferred Units

   Section 2.1(c)(iv)

ETO Series E Preferred Units

   Section 2.1(c)(v)

ETO Series F Preferred Units

   Section 2.1(c)(vi)

ETO Series G Preferred Units

   Section 2.1(c)(vii)

Exchange Act

   Section 3.3(b)

Exchange Agent

   Section 2.3(a)

Exchange Fund

   Section 2.3(a)

Form S-4

   Section 2.1(b)

Governmental Entity

   Section 2.3(e)

Hook Unit Merger Consideration

   Section 2.1(b)

Hook Units

   Section 2.1(b)

Laws

   Section 3.4(c)

Merger

   Recitals

Merger Consideration

   Section 2.1(c)(vii)

Merger Sub

   Preamble

Merger Sub Units

   Section 2.1(f)

New ET Preferred Units

   Section 2.1(c)(vii)

NYSE

   Section 3.3(b)

person

   Section 8.14(a)(ii)

Preferred Merger Consideration

   Section 2.1(c)(vii)

SEC

   Section 3.3(b)

Securities Act

   Section 3.3(b)

Subsidiary

   Section 8.14(a)(xi)

Tax

   Section 8.14(a)(xii)

Tax Return

   Section 8.14(a)(xiii)

Treasury Regulation

   Section 8.14(a)(xiv)

 

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IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed and delivered as of the date first above written.

 

ENERGY TRANSFER LP
By:  

LE GP, LLC,

its general partner

By:  

/s/ Thomas E. Long

 

Name: Thomas E. Long

Title: Co-Chief Executive Officer

 

ETO MERGER SUB LLC
By:   /s/ Thomas E. Long
 

Name: Thomas E. Long

Title: Co-Chief Executive Officer

 

ENERGY TRANSFER OPERATING, L.P.
By:  

Energy Transfer Partners GP, L.P.,

its general partner

By:  

Energy Transfer Partners, L.L.C.,

its general partner

By:   /s/ Thomas E. Long
 

Name: Thomas E. Long

Title: Co-Chief Executive Officer

Signature Page to Agreement and Plan of Merger

 

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Exhibit A

Amendment No. 8 to ET Partnership Agreement

[See attached as Annex B.]

 

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Annex B

AMENDMENT NO. 8 TO

THIRD AMENDED AND RESTATED

AGREEMENT OF LIMITED PARTNERSHIP

OF

ENERGY TRANSFER LP

This Amendment No. 8 (this “Amendment No. 8”) to the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer LP (the “Partnership”) dated as of February 8, 2006 (as amended to date, the “Partnership Agreement”) is hereby adopted effective as of [ ● ] (the “Effective Date”) by LE GP, LLC, a Delaware limited liability company (the “General Partner”), as the general partner of the Partnership. Capitalized terms used but not defined herein have the meaning given such terms in the Partnership Agreement.

WHEREAS, Section 5.8 of the Partnership Agreement provides that the General Partner, without the approval of any Limited Partner except as otherwise provided in the Partnership Agreement, may, for any Partnership purpose, at any time and from time to time, issue additional Partnership Securities to such Persons for such consideration and on such terms and conditions as the General Partner shall determine;

WHEREAS, the General Partner, without the approval of any Partner, may amend any provision of the Partnership Agreement (i) pursuant to Section 13.1(d)(i) of the Partnership Agreement to reflect a change that, the General Partner determines, does not adversely affect the Limited Partners (including any particular class of Partnership Interests as compared to other classes of Partnership Interests) in any material respect and (ii) pursuant to Section 13.1(g) of the Partnership Agreement to reflect an amendment that the General Partner determines to be necessary or appropriate in connection with the authorization of issuance of any class or series of Partnership Securities pursuant to Section 5.8 of the Partnership Agreement;

WHEREAS, in connection with the transactions contemplated by that certain Agreement and Plan of Merger, dated as of March 5, 2021, by and among the Partnership, the MLP and ETO Merger Sub LLC, a Delaware limited liability company, a Delaware limited liability company and wholly owned subsidiary of the Partnership, pursuant to which Merger Sub will merge with and into the MLP, with the MLP surviving as a wholly owned subsidiary of the Partnership, the Partnership will issue limited partner interests designated as (i) “6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units”; (ii) “6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units”; (iii) “7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units”; (iv) “7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units”; (v) “7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units”; (vi) “6.750% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units”; (vii) “7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units”; and (viii) “Class B Units,” each having the rights, preferences and privileges set forth in this Amendment No. 8;

WHEREAS, the General Partner has determined, pursuant to Section 13.1(g) of the Partnership Agreement, that the amendments to the Partnership Agreement set forth herein are necessary or appropriate in connection with the authorization of the issuance of the (i) “6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units”; (ii) “6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units”; (iii) “7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units”; (iv) “7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units”; (v) “7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units”; (vi) “6.750% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units”; (vii) “7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units,” and (vii) Class B Units; and

WHEREAS, the General Partner has determined, pursuant to Section 13.1(d)(i) of the Partnership Agreement, that, if and to the extent any amendments set forth herein are not necessary or appropriate in connection with the authorization of the issuance of the New Units, such amendments to the Partnership Agreement set forth herein do not adversely affect the Limited Partners (including any particular class of Partnership Interests as compared to other classes of Partnership Interests) in any material respect.

 

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NOW THEREFORE, the General Partner does hereby amend the Partnership Agreement as follows:

Section 1 Amendments.

(a) Section 1.1 of the Partnership Agreement is amended to add or to amend and restate the following definitions in their entirety in the appropriate alphabetical order:

Arrears” means, (a) with respect to the Series A Distributions, the full cumulative Series A Distributions through the most recent Series A Distribution Payment Date that have not been paid on all Outstanding Series A Preferred Units, (b) with respect to the Series B Distributions, the full cumulative Series B Distributions through the most recent Series B Distribution Payment Date that have not been paid on all Outstanding Series B Preferred Units, (c) with respect to the Series C Distributions, the full cumulative Series C Distributions through the most recent Series C Distribution Payment Date that have not been paid on all Outstanding Series C Preferred Units, (d) with respect to the Series D Distributions, the full cumulative Series D Distributions through the most recent Series D Distribution Payment Date that have not been paid on all Outstanding Series D Preferred Units, (e) with respect to the Series E Distributions, the full cumulative Series E Distributions through the most recent Series E Distribution Payment Date that have not been paid on all Outstanding Series E Preferred Units, (f) with respect to the Series F Distributions, the full cumulative Series F Distributions through the most recent Series F Distribution Payment Date that have not been paid on all Outstanding Series F Preferred Units and (g) with respect to the Series G Distributions, the full cumulative Series G Distributions through the most recent Series G Distribution Payment Date that have not been paid on all Outstanding Series G Preferred Units.

Available Cash” means, with respect to any Quarter ending prior to the Liquidation Date:

(a) the sum of (i) all cash and cash equivalents of the Partnership Group (or the Partnership’s proportionate share of cash and cash equivalents in the case of Subsidiaries that are not wholly owned) on hand at the end of such Quarter, and (ii) all additional cash and cash equivalents of the Partnership Group (or the Partnership’s proportionate share of cash and cash equivalents in the case of Subsidiaries that are not wholly owned) on hand immediately prior to the date of the distribution of Available Cash with respect to such Quarter, less

(b) the amount of any cash reserves (or the Partnership’s proportionate share of cash reserves in the case of Subsidiaries that are not wholly owned) established by the General Partner to (i) provide for the proper conduct of the business of the Partnership (including reserves for future capital expenditures, for anticipated future credit needs of the Partnership Group and for refunds of collected rates reasonably likely to be refunded as a result of a settlement or hearing relating to FERC rate proceedings) subsequent to such Quarter, (ii) comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which any Group Member is a party or by which it is bound or its assets are subject, (iii) provide funds for distributions under Section 6.3 in respect of any one or more of the next four Quarters; (iv) provide funds for Series A Distributions, (v) provide funds for Series B Distributions, (vi) provide funds for Series C Distributions, (vii) provide funds for Series D Distributions, (viii) provide funds for Series E Distributions, (ix) provide funds for Series F Distributions, (x) provide funds for Series G Distributions or (xi) provide funds for distributions to the Class B Units; provided, however, that disbursements made by a Group Member or cash reserves established, increased or reduced after the end of such Quarter but on or before the date of determination of Available Cash with respect to such Quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining Available Cash, within such Quarter if the General Partner so determines.

Notwithstanding the foregoing, “Available Cash” with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero.

 

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Calculation Agent” means the financial institution that will be appointed by the General Partner prior to the Series A Floating Rate Period, Series B Floating Rate Period, Series C Floating Rate Period, Series D Floating Rate Period, Series E Floating Rate Period, Series F Reset Distribution Determination Date preceding the Series F First Call Date or Series G Reset Distribution Determination Date preceding the Series G First Call Date to act in its capacity as calculation agent for the Series A Preferred Units, the Series B Preferred Units, the Series C Preferred Units, the Series D Preferred Units, the Series E Preferred Units, the Series F Preferred Units and the Series G Preferred Units, as applicable, and its successors and assigns or any other calculation agent appointed by the General Partner. For the avoidance of doubt, the Partnership and its affiliates shall not be appointed by the General Partner to act as calculation agent for the Series A Preferred Units, the Series B Preferred Units, the Series C Preferred Units, the Series D Preferred Units, the Series E Preferred Units, the Series F Preferred Units or the Series G Preferred Units.

Class B Units” has the meaning given such term in Section 5.24(a).

Class B Unit Distribution Rate” means an amount per Class B Unit equal to 7.5% per annum (1.875% per Quarter), of the Class B Unit Issue Price.

Class B Unit Issuance Date” means [                ], 2021.

Class B Unit Issue Price” means $18.84.

Class B Unit Quarterly Distribution” has the meaning set forth in Section 5.24(b)(iii)(B).

Common Unit” means a Partnership Security representing a fractional part of the Partnership Interests of all Limited Partners, and having the rights and obligations specified with respect to Common Units in this Agreement. The term “Common Unit” does not include a Class A Unit, Class B Unit, a Series A Preferred Unit, a Series B Preferred Unit, a Series C Preferred Unit, a Series D Preferred Unit, a Series E Preferred Unit, a Series F Preferred Unit or a Series G Preferred Unit.

Equity Credit” means the dollar amount or percentage in relation to the stated liquidation preference amount of (a) $1,000.00 per Series A Preferred Unit, (b) $1,000.00 per Series B Preferred Unit, (c) $25.00 per Series C Preferred Unit, (d) $25.00 per Series D Preferred Unit, (e) $25.00 per Series E Preferred Unit, (f) $1,000.00 per Series F Preferred Unit or (g) $1,000.00 per Series G Preferred Unit, assigned to the Series A Preferred Units, Series B Preferred Units, Series C Preferred Units, Series D Preferred Units, Series E Preferred Units, Series F Preferred Units or Series G Preferred Units, as applicable, as equity, rather than debt, by a Rating Agency in evaluating the capital structure of the Partnership.

ETP Holdco” means ETP Holdco Corporation, a Delaware corporation.

ETP Holdco Items” means any item of Partnership income, gain, loss, deduction or credit attributable to the Partnership’s ownership of ETP Holdco or the Partnership’s ownership of any indebtedness of ETP Holdco or any of its subsidiaries.

ETP Holdco Distributions” means any portion of the Partnership cash distributions attributable to (i) any distribution or dividend received by the Partnership from ETP Holdco or the proceeds of sale of the capital stock of ETP Holdco or (ii) any interest payments received by the Partnership with respect to indebtedness of ETP Holdco or its subsidiaries.

H.15(519)” means the statistical release designated as such, or any successor publication, published by the Board of Governors of the U.S. Federal Reserve System.

Limited Partner Interest” means the ownership interest of a Limited Partner or Assignee in the Partnership, which may be evidenced by Common Units, Class A Units, Series A Preferred Units, Series B

 

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Preferred Units, Series C Preferred Units, Series D Preferred Units, Series E Preferred Units, Series F Preferred Units, Series G Preferred Units and Class B Units or other Partnership Securities or a combination thereof or interest therein, and includes any and all benefits to which such Limited Partner or Assignee is entitled as provided in this Agreement, together with all obligations of such Limited Partner or Assignee to comply with the terms and provisions of this Agreement.

most recent H.15(519)” means the H.15(519) published closest in time but prior to the close of business on the second Business Day prior to the Series F Reset Date or the Series G Reset Date, as applicable.

New Units” means the Series A Preferred Units, the Series B Preferred Units, the Series C Preferred Units, the Series D Preferred Units, the Series E Preferred Units, the Series F Preferred Units, the Series G Preferred Units, and the Class B Units.

Outstanding” means, with respect to Partnership Securities, all Partnership Securities that are issued by the Partnership and reflected as outstanding on the Partnership’s books and records as of the date of determination; provided, however, that if at any time any Person or Group (other than the General Partner or its Affiliates) beneficially owns 20% or more of any Outstanding Partnership Securities of any class then Outstanding, all Partnership Securities owned by such Person or Group shall not be voted on any matter and shall not be considered to be Outstanding when sending notices of a meeting of Limited Partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under this Agreement, except that Common Units so owned shall be considered to be Outstanding for purposes of Section 11.1(b)(iv) (such Common Units shall not, however, be treated as a separate class of Partnership Securities for purposes of this Agreement); provided, further, that the limitation in the foregoing proviso shall not apply (i) to any Person or Group who acquired 20% or more of any Outstanding Partnership Securities of any class then Outstanding directly from the General Partner or its Affiliates, (ii) to any Person or Group who acquired 20% or more of any Outstanding Partnership Securities of any class then Outstanding directly or indirectly from a Person or Group described in clause (i) if the General Partner shall have notified such Person or Group in writing that such limitation shall not apply to such Person or Group, (iii) to any Person or Group who acquired 20% or more of any Partnership Securities issued by the Partnership with the prior approval of the Board of Directors of the General Partner, (iv) to any Series A Holder in connection with any vote, consent or approval of the Series A Holders pursuant to Section 5.17(b)(iii), (v) to any Series B Holder in connection with any vote, consent or approval of the Series B Holders pursuant to Section 5.18(b)(iii), (vi) to any Series C Holder in connection with any vote, consent or approval of the Series C Holders pursuant to Section 5.19(b)(iii), (vii) to any Series D Holder in connection with any vote, consent or approval of the Series D Holders pursuant to Section 5.20(b)(iii), (viii) to any Series E Holder in connection with any vote, consent or approval of the Series E Holders pursuant to Section 5.21(b)(iii), (ix) to any Series F Holder in connection with any vote, consent or approval of the Series F Holders pursuant to Section 5.22(b)(iii) or (x) to any Series G Holder in connection with any vote, consent or approval of the Series G Holders pursuant to Section 5.23(b)(iii).

Partnership Security” means any class or series of equity interest in the Partnership (but excluding any options, rights, warrants and appreciation rights relating to an equity interest in the Partnership) and General Partner Units and any General Partner Interest represented thereby, including without limitation, Common Units, Class A Units, Series A Preferred Units, Series B Preferred Units, Series C Preferred Units, Series D Preferred Units, Series E Preferred Units, Series F Preferred Units, Series G Preferred Units and Class B Units.

Paying Agent” means the Transfer Agent, acting in its capacity as paying agent for the Series A Preferred Units, the Series B Preferred Units, the Series C Preferred Units, the Series D Preferred Units, the Series E Preferred Units, the Series F Preferred Units and the Series G Preferred Units, and its respective successors and assigns or any other paying agent appointed by the General Partner; provided, however, that if no Paying Agent is specifically designated for the Series A Preferred Units, the Series B Preferred Units, the Series C Preferred Units, the Series D Preferred Units, the Series E Preferred Units, the Series F Preferred Units or the Series G Preferred Units, the General Partner shall act in such capacity.

 

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Percentage Interest” means as of any date of determination (a) as to the General Partner, the amount of its aggregate Capital Contributions to the Partnership divided by the aggregate Capital Contributions made to the Partnership by all Partners (other than Capital Contributions made to the Partnership by a Partner with respect to a Class A Unit, a Class B Unit, a Series A Preferred Unit, a Series B Preferred Unit, a Series C Preferred Unit, a Series D Preferred Unit, a Series E Preferred Unit, a Series F Preferred Unit or a Series G Preferred Unit), (b) as to any Unitholder or Assignee holding Common Units, the product obtained by multiplying (i) 100% less the percentage applicable to paragraphs (a) and (c) hereof by (ii) the quotient obtained by dividing (A) the number of Common Units held by such Unitholder or Assignee by (B) the total number of all Outstanding Common Units, and (c) as to the holders of other Partnership Securities issued by the Partnership in accordance with Section 5.8, the percentage established as a part of such issuance. The Percentage Interest with respect to a Class A Unit, Class B Unit, Series A Preferred Unit, Series B Preferred Unit, Series C Preferred Unit, Series D Preferred Unit, Series E Preferred Unit, Series F Preferred Unit and Series G Preferred Unit shall at all times be zero.

Pro Rata” means (a) when modifying Units or any class thereof, apportioned equally among all such designated Units in accordance with their relative Percentage Interests, (b) when modifying Partners and Assignees, apportioned among all Partners and Assignees in accordance with their relative Percentage Interests, (c) solely when modifying Series A Holders, apportioned equally among all Series A Holders in accordance with the relative number or percentage of Series A Preferred Units held by each such Series A Holder, (d) solely when modifying Series B Holders, apportioned equally among all Series B Holders in accordance with the relative number or percentage of Series B Preferred Units held by each such Series B Holder, (e) solely when modifying Series C Holders, apportioned equally among all Series C Holders in accordance with the relative number or percentage of Series C Preferred Units held by each such Series C Holder, (f) solely when modifying Series D Holders, apportioned equally among all Series D Holders in accordance with the relative number or percentage of Series D Preferred Units held by each such Series D Holder, (g) solely when modifying Series E Holders, apportioned equally among all Series E Holders in accordance with the relative number or percentage of Series E Preferred Units held by each such Series E Holder, (h) solely when modifying Series F Holders, apportioned equally among all Series F Holders in accordance with the relative number or percentage of Series F Preferred Units held by each such Series F Holder, (i) solely when modifying Series G Holders, apportioned equally among all Series G Holders in accordance with the relative number or percentage of Series G Preferred Units held by each such Series G Holder and (j) solely when modifying holders of Class B Units, apportioned equally among all holders of Class B Units in accordance with the relative number or percentage of Class B Units held by each such holder.

Rating Agency” means any nationally recognized statistical rating organization (within the meaning of Section 3(a)(62) of the Securities Exchange Act) that publishes a rating for the Partnership.

Recapitalized Unit” means the Class K Units, the Class L Units, the Class M Units and the Class N Units established pursuant to the Fifth Amended and Restated Agreement of Limited Partnership of the MLP, as amended.

Series A Base Liquidation Preference” means a liquidation preference for each Series A Preferred Unit initially equal to $1,000 per unit.

Series A Current Criteria” means the Equity Credit criteria of a Rating Agency for securities such as the Series A Preferred Units, as such criteria were in effect as of the Series A Original Issue Date.

Series A Distribution Payment Date” means (a) during the Series A Fixed Rate Period, the 15th day of each February and August of each year and (b) during the Series A Floating Rate Period, the 15th day of each February, May, August and November of each year; provided however, that if any Series A Distribution Payment Date would otherwise occur on a day that is not a Business Day, such Series A Distribution Payment Date shall instead be on the immediately succeeding Business Day.

 

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Series A Distribution Period” means a period of time from and including the preceding Series A Distribution Payment Date, to, but excluding, the next Series A Distribution Payment Date for such Series A Distribution Period.

Series A Distribution Rate” means an annual rate equal to (a) during the Series A Fixed Rate Period, 6.250% of the Series A Liquidation Preference and (b) during the Series A Floating Rate Period, a percentage of the Series A Liquidation Preference equal to the sum of (i) the Three-Month LIBOR, as calculated on each applicable Series A LIBOR Determination Date, and (ii) 4.028%.

Series A Distribution Record Date” has the meaning given such term in Section 5.17(b)(ii)(B).

Series A Distributions” means distributions with respect to Series A Preferred Units pursuant to Section 5.17(b)(ii).

Series A Fixed Rate Period” means the period from and including the date hereof to, but excluding, February 15, 2023.

Series A Floating Rate Period” means the period from and including February 15, 2023 and thereafter until such time as all of the Outstanding Series A Preferred Units are redeemed in accordance with Section 5.17(b)(iv).

Series A Holder” means a Record Holder of Series A Preferred Units.

Series A Junior Securities” means any class or series of Partnership Securities that, with respect to distributions on such Partnership Securities and distributions upon liquidation of the Partnership, ranks junior to the Series A Preferred Units, including but not limited to Common Units, Class A Units, Class B Units and the General Partner Interest, but excluding any Series A Parity Securities and Series A Senior Securities.

Series A LIBOR Determination Date” means the London Business Day immediately preceding the first day in each relevant Series A Distribution Period.

Series A Liquidation Preference” means a liquidation preference for each Series A Preferred Unit initially equal to $1,000 per unit (subject to adjustment for any splits, combinations or similar adjustments to the Series A Preferred Units), which liquidation preference shall be subject to increase by the per Series A Preferred Unit amount of any accumulated and unpaid Series A Distributions (whether or not such distributions shall have been declared).

Series A Original Issue Date” means November 16, 2017.

Series A Parity Securities” means the Series B Preferred Units, Series C Preferred Units, Series D Preferred Units, Series E Preferred Units, Series F Preferred Units, Series G Preferred Units and any other class or series of Partnership Interests established after the date hereof by the General Partner, the terms of which class or series expressly provide that it ranks on parity with the Series A Preferred Units as to distributions and amounts payable upon a dissolution or liquidation pursuant to Article XII.

Series A Preferred Units” has the meaning given such term in Section 5.17(a).

Series A Rating Event” means a change by any Rating Agency to the Series A Current Criteria, which change results in (a) any shortening of the length of time for which the Series A Current Criteria are scheduled to be in effect with respect to the Series A Preferred Units or (b) a lower Equity Credit being given to the Series A Preferred Units than the Equity Credit that would have been assigned to the Series A Preferred Units by such Rating Agency pursuant to its Series A Current Criteria.

Series A Redemption Date” has the meaning given such term in Section 5.17(b)(iv)(A).

 

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Series A Redemption Notice” has the meaning given such term in Section 5.17(b)(iv)(B).

Series A Redemption Price” has the meaning given such term in Section 5.17(b)(iv)(A).

Series A Senior Securities” means any class or series of Partnership Interests established after the date hereof by the General Partner, the terms of which class or series expressly provide that it ranks senior to the Series A Preferred Units as to distributions and amounts payable upon a dissolution or liquidation pursuant to Article XII.

Series B Base Liquidation Preference” means a liquidation preference for each Series B Preferred Unit initially equal to $1,000 per unit.

Series B Current Criteria” means the Equity Credit criteria of a Rating Agency for securities such as the Series B Preferred Units, as such criteria were in effect as of the Series B Original Issue Date.

Series B Distribution Payment Date” means (a) during the Series B Fixed Rate Period, the 15th day of each February and August of each year and (b) during the Series B Floating Rate Period, the 15th day of each February, May, August and November of each year; provided however, that if any Series B Distribution Payment Date would otherwise occur on a day that is not a Business Day, such Series B Distribution Payment Date shall instead be on the immediately succeeding Business Day.

Series B Distribution Period” means a period of time from and including the preceding Series B Distribution Payment Date, to, but excluding, the next Series B Distribution Payment Date for such Series B Distribution Period.

Series B Distribution Rate” means an annual rate equal to (a) during the Series B Fixed Rate Period, 6.625% of the Series B Liquidation Preference and (b) during the Series B Floating Rate Period, a percentage of the Series B Liquidation Preference equal to the sum of (i) the Three-Month LIBOR, as calculated on each applicable Series B LIBOR Determination Date, and (ii) 4.155%.

Series B Distribution Record Date” has the meaning given such term in Section 5.18(b)(ii)(B).

Series B Distributions” means distributions with respect to Series B Preferred Units pursuant to Section 5.18(b)(ii).

Series B Fixed Rate Period” means the period from and including the date hereof to, but excluding, February 15, 2028.

Series B Floating Rate Period” means the period from and including February 15, 2028 and thereafter until such time as all of the Outstanding Series B Preferred Units are redeemed in accordance with Section 5.18(b)(iv).

Series B Holder” means a Record Holder of Series B Preferred Units.

Series B Junior Securities” means any class or series of Partnership Securities that, with respect to distributions on such Partnership Securities and distributions upon liquidation of the Partnership, ranks junior to the Series B Preferred Units, including but not limited to Common Units, Class A Units, Class B Units and the General Partner Interest, but excluding any Series B Parity Securities and Series B Senior Securities.

Series B LIBOR Determination Date” means the London Business Day immediately preceding the first day in each relevant Series B Distribution Period.

Series B Liquidation Preference” means a liquidation preference for each Series B Preferred Unit initially equal to $1,000 per unit (subject to adjustment for any splits, combinations or similar adjustments to the

 

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Series B Preferred Units), which liquidation preference shall be subject to increase by the per Series B Preferred Unit amount of any accumulated and unpaid Series B Distributions (whether or not such distributions shall have been declared).

Series B Original Issue Date” means November 16, 2017.

Series B Parity Securities” means the Series A Preferred Units, Series C Preferred Units, Series D Preferred Units, Series E Preferred Units, Series F Preferred Units, Series G Preferred Units and any other class or series of Partnership Interests established after the date hereof by the General Partner, the terms of which class or series expressly provide that it ranks on parity with the Series B Preferred Units as to distributions and amounts payable upon a dissolution or liquidation pursuant to Article XII.

Series B Preferred Units” has the meaning given such term in Section 5.18(a).

Series B Rating Event” means a change by any Rating Agency to the Series B Current Criteria, which change results in (a) any shortening of the length of time for which the Series B Current Criteria are scheduled to be in effect with respect to the Series B Preferred Units or (b) a lower Equity Credit being given to the Series B Preferred Units than the Equity Credit that would have been assigned to the Series B Preferred Units by such Rating Agency pursuant to its Series B Current Criteria.

Series B Redemption Date” has the meaning given such term in Section 5.18(b)(iv)(A).

Series B Redemption Notice” has the meaning given such term in Section 5.18(b)(iv)(B).

Series B Redemption Price” has the meaning given such term in Section 5.18(b)(iv)(A).

Series B Senior Securities” means any class or series of Partnership Interests established after the date hereof by the General Partner, the terms of which class or series expressly provide that it ranks senior to the Series B Preferred Units as to distributions and amounts payable upon a dissolution or liquidation pursuant to Article XII.

Series C Base Liquidation Preference” means a liquidation preference for each Series C Preferred Unit initially equal to $25.00 per unit.

Series C Current Criteria” means the Equity Credit criteria of a Rating Agency for securities such as the Series C Preferred Units, as such criteria were in effect as of the Series C Original Issue Date.

Series C Distribution Payment Date” means the 15th day of each February, May, August and November of each year; provided however, that if any Series C Distribution Payment Date would otherwise occur on a day that is not a Business Day, such Series C Distribution Payment Date shall instead be on the immediately succeeding Business Day.

Series C Distribution Period” means a period of time from and including the preceding Series C Distribution Payment Date, to, but excluding, the next Series C Distribution Payment Date for such Series C Distribution Period.

Series C Distribution Rate” means an annual rate equal to (a) during the Series C Fixed Rate Period, 7.375% of the Series C Liquidation Preference and (b) during the Series C Floating Rate Period, a percentage of the Series C Liquidation Preference equal to the sum of (i) the Three-Month LIBOR, as calculated on each applicable Series C LIBOR Determination Date, and (ii) 4.530%.

Series C Distribution Record Date” has the meaning given such term in Section 5.19(b)(ii)(B).

 

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Series C Distributions” means distributions with respect to Series C Preferred Units pursuant to Section 5.19(b)(ii).

Series C Fixed Rate Period” means the period from and including the date hereof to, but excluding, May 15, 2023.

Series C Floating Rate Period” means the period from and including May 15, 2023 and thereafter until such time as all of the Outstanding Series C Preferred Units are redeemed in accordance with Section 5.19(b)(iv).

Series C Holder” means a Record Holder of Series C Preferred Units.

Series C Junior Securities” means any class or series of Partnership Securities that, with respect to distributions on such Partnership Securities and distributions upon liquidation of the Partnership, ranks junior to the Series C Preferred Units, including but not limited to Common Units, Class A Units, Class B Units and the General Partner Interest, but excluding any Series C Parity Securities and Series C Senior Securities.

Series C LIBOR Determination Date” means the London Business Day immediately preceding the first day in each relevant Series C Distribution Period.

Series C Liquidation Preference” means a liquidation preference for each Series C Preferred Unit initially equal to $25.00 per unit (subject to adjustment for any splits, combinations or similar adjustments to the Series C Preferred Units), which liquidation preference shall be subject to increase by the per Series C Preferred Unit amount of any accumulated and unpaid Series C Distributions (whether or not such distributions shall have been declared).

Series C Original Issue Date” means April 25, 2018.

Series C Parity Securities” means the Series A Preferred Units, Series B Preferred Units, Series D Preferred Units, Series E Preferred Units, Series F Preferred Units, Series G Preferred Units and other any class or series of Partnership Interests established after the date hereof by the General Partner, the terms of which class or series expressly provide that it ranks on parity with the Series C Preferred Units as to distributions and amounts payable upon a dissolution or liquidation pursuant to Article XII.

Series C Preferred Units” has the meaning given such term in Section 5.19(a).

Series C Rating Event” means a change by any Rating Agency to the Series C Current Criteria, which change results in (a) any shortening of the length of time for which the Series C Current Criteria are scheduled to be in effect with respect to the Series C Preferred Units or (b) a lower Equity Credit being given to the Series C Preferred Units than the Equity Credit that would have been assigned to the Series C Preferred Units by such Rating Agency pursuant to its Series C Current Criteria.

Series C Redemption Date” has the meaning given such term in Section 5.19(b)(iv)(A).

Series C Redemption Notice” has the meaning given such term in Section 5.19(b)(iv)(B).

Series C Redemption Price” has the meaning given such term in Section 5.19(b)(iv)(A).

Series C Senior Securities” means any class or series of Partnership Interests established after the date hereof by the General Partner, the terms of which class or series expressly provide that it ranks senior to the Series C Preferred Units as to distributions and amounts payable upon a dissolution or liquidation pursuant to Article XII.

 

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Series D Base Liquidation Preference” means a liquidation preference for each Series D Preferred Unit initially equal to $25.00 per unit.

Series D Current Criteria” means the Equity Credit criteria of a Rating Agency for securities such as the Series D Preferred Units, as such criteria were in effect as of the Series D Original Issue Date.

Series D Distribution Payment Date” means the 15th day of each February, May, August and November of each year; provided however, that if any Series D Distribution Payment Date would otherwise occur on a day that is not a Business Day, such Series D Distribution Payment Date shall instead be on the immediately succeeding Business Day.

Series D Distribution Period” means a period of time from and including the preceding Series D Distribution Payment Date, to, but excluding, the next Series D Distribution Payment Date for such Series D Distribution Period.

Series D Distribution Rate” means an annual rate equal to (a) during the Series D Fixed Rate Period, 7.625% of the Series D Liquidation Preference and (b) during the Series D Floating Rate Period, a percentage of the Series D Liquidation Preference equal to the sum of (i) the Three-Month LIBOR, as calculated on each applicable Series D LIBOR Determination Date, and (ii) 4.738%.

Series D Distribution Record Date” has the meaning given such term in Section 5.20(b)(ii)(B).

Series D Distributions” means distributions with respect to Series D Preferred Units pursuant to Section 5.20(b)(ii).

Series D Fixed Rate Period” means the period from and including the date hereof to, but excluding, August 15, 2023.

Series D Floating Rate Period” means the period from and including August 15, 2023 and thereafter until such time as all of the Outstanding Series D Preferred Units are redeemed in accordance with Section 5.20(b)(iv).

Series D Holder” means a Record Holder of Series D Preferred Units.

Series D Junior Securities” means any class or series of Partnership Securities that, with respect to distributions on such Partnership Securities and distributions upon liquidation of the Partnership, ranks junior to the Series D Preferred Units, including but not limited to Common Units, Class A Units, Class B Units and the General Partner Interest, but excluding any Series D Parity Securities and Series D Senior Securities.

Series D LIBOR Determination Date” means the Business Day immediately preceding the first day in each relevant Series D Distribution Period.

Series D Liquidation Preference” means a liquidation preference for each Series D Preferred Unit initially equal to $25.00 per unit (subject to adjustment for any splits, combinations or similar adjustments to the Series D Preferred Units), which liquidation preference shall be subject to increase by the per Series D Preferred Unit amount of any accumulated and unpaid Series D Distributions (whether or not such distributions shall have been declared).

Series D Original Issue Date” means July 23, 2018.

Series D Parity Securities” means the Series A Preferred Units, Series B Preferred Units, Series C Preferred Units, Series E Preferred Units, Series F Preferred Units, Series G Preferred Units and any other class

 

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or series of Partnership Interests established after the date hereof by the General Partner, the terms of which class or series expressly provide that it ranks on parity with the Series D Preferred Units as to distributions and amounts payable upon a dissolution or liquidation pursuant to Article XII.

Series D Preferred Units” has the meaning given such term in Section 5.20(a).

Series D Rating Event” means a change by any Rating Agency to the Series D Current Criteria, which change results in (a) any shortening of the length of time for which the Series D Current Criteria are scheduled to be in effect with respect to the Series D Preferred Units or (b) a lower Equity Credit being given to the Series D Preferred Units than the Equity Credit that would have been assigned to the Series D Preferred Units by such Rating Agency pursuant to its Series D Current Criteria.

Series D Redemption Date” has the meaning given such term in Section 5.20(b)(iv)(A).

Series D Redemption Notice” has the meaning given such term in Section 5.20(b)(iv)(B).

Series D Redemption Price” has the meaning given such term in Section 5.20(b)(iv)(A).

Series D Senior Securities” means any class or series of Partnership Interests established after the date hereof by the General Partner, the terms of which class or series expressly provide that it ranks senior to the Series D Preferred Units as to distributions and amounts payable upon a dissolution or liquidation pursuant to Article XII.

Series E Base Liquidation Preference” means a liquidation preference for each Series E Preferred Unit initially equal to $25.00 per unit.

Series E Current Criteria” means the Equity Credit criteria of a Rating Agency for securities such as the Series E Preferred Units, as such criteria were in effect as of the Series E Original Issue Date.

Series E Distribution Payment Date” means the 15th day of each February, May, August and November of each year; provided however, that if any Series E Distribution Payment Date would otherwise occur on a day that is not a Business Day, such Series E Distribution Payment Date shall instead be on the immediately succeeding Business Day.

Series E Distribution Period” means a period of time from and including the preceding Series E Distribution Payment Date, to, but excluding, the next Series E Distribution Payment Date for such Series E Distribution Period.

Series E Distribution Rate” means an annual rate equal to (a) during the Series E Fixed Rate Period, 7.600% of the Series E Liquidation Preference and (b) during the Series E Floating Rate Period, a percentage of the Series E Liquidation Preference equal to the sum of (i) the Three-Month LIBOR, as calculated on each applicable Series E LIBOR Determination Date, and (ii) 5.161%.

Series E Distribution Record Date” has the meaning given such term in Section 5.21(b)(ii)(B).

Series E Distributions” means distributions with respect to Series E Preferred Units pursuant to Section 5.21(b)(ii).

Series E Fixed Rate Period” means the period from and including the date hereof to, but excluding, May 15, 2024.

Series E Floating Rate Period” means the period from and including May 15, 2024 and thereafter until such time as all of the Outstanding Series E Preferred Units are redeemed in accordance with Section 5.21(b)(iv).

 

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Series E Holder” means a Record Holder of Series E Preferred Units.

Series E Junior Securities” means any class or series of Partnership Securities that, with respect to distributions on such Partnership Securities and distributions upon liquidation of the Partnership, ranks junior to the Series E Preferred Units, including but not limited to Common Units, Class A Units, Class B Units and the General Partner Interest, but excluding any Series E Parity Securities and Series E Senior Securities.

Series E LIBOR Determination Date” means the Business Day immediately preceding the first day in each relevant Series E Distribution Period.

Series E Liquidation Preference” means a liquidation preference for each Series E Preferred Unit initially equal to $25.00 per unit (subject to adjustment for any splits, combinations or similar adjustments to the Series E Preferred Units), which liquidation preference shall be subject to increase by the per Series E Preferred Unit amount of any accumulated and unpaid Series E Distributions (whether or not such distributions shall have been declared).

Series E Original Issue Date” means April 25, 2019.

Series E Parity Securities” means the Series A Preferred Units, Series B Preferred Units, Series C Preferred Units, Series D Preferred Units, Series F Preferred Units, Series G Preferred Units and any other class or series of Partnership Interests established after the date hereof by the General Partner, the terms of which class or series expressly provide that it ranks on parity with the Series E Preferred Units as to distributions and amounts payable upon a dissolution or liquidation pursuant to Article XII.

Series E Preferred Units” has the meaning given such term in Section 5.21(a).

Series E Rating Event” means a change by any Rating Agency to the Series E Current Criteria, which change results in (a) any shortening of the length of time for which the Series E Current Criteria are scheduled to be in effect with respect to the Series E Preferred Units or (b) a lower Equity Credit being given to the Series E Preferred Units than the Equity Credit that would have been assigned to the Series E Preferred Units by such Rating Agency pursuant to its Series E Current Criteria.

Series E Redemption Date” has the meaning given such term in Section 5.21(b)(iv)(A).

Series E Redemption Notice” has the meaning given such term in Section 5.21(b)(iv)(B).

Series E Redemption Price” has the meaning given such term in Section 5.21(b)(iv)(A).

Series E Senior Securities” means any class or series of Partnership Interests established after the date hereof by the General Partner, the terms of which class or series expressly provide that it ranks senior to the Series E Preferred Units as to distributions and amounts payable upon a dissolution or liquidation pursuant to Article XII.

Series F Base Liquidation Preference” means a liquidation preference for each Series F Preferred Unit initially equal to $1,000.00 per Series F Preferred Unit.

Series F Current Criteria” means the Equity Credit criteria of a Rating Agency for securities such as the Series F Preferred Units, as such criteria were in effect as of the Series F Original Issue Date.

Series F Distribution Payment Date” means the 15th day of each May and November of each year; provided however, that if any Series F Distribution Payment Date would otherwise occur on a day that is not a Business Day, such Series F Distribution Payment Date shall instead be on the immediately succeeding Business Day.

 

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Series F Distribution Period” means a period of time from and including the preceding Series F Distribution Payment Date, to, but excluding, the next Series F Distribution Payment Date for such Series F Distribution Period.

Series F Distribution Rate” means an initial distribution rate for the Series F Preferred Units from and including the date of original issue to, but excluding, the Series F First Call Date equal to 6.750% per annum of the $1,000.00 liquidation preference per Series F Preferred Unit (equal to $67.50 per Series F Preferred Unit per annum). On and after the Series F First Call Date, the distribution rate on the Series F Preferred Units for each Series F Reset Period will equal for each Series F Preferred Unit a percentage of the $1,000.00 liquidation preference for such Series F Preferred Unit equal to the Series F Five-year U.S. Treasury Rate as of the most recent Series F Reset Distribution Determination Date plus a spread of 5.134% per annum.

Series F Distribution Record Date” has the meaning given such term in Section 5.22(b)(ii)(B).

Series F Distributions” means distributions with respect to Series F Preferred Units pursuant to Section 5.22(b)(ii).

Series F First Call Date” means May 15, 2025.

Series F Five-year U.S. Treasury Rate” means, as of any Series F Reset Distribution Determination Date, as applicable, (i) an interest rate (expressed as a decimal) determined to be the per annum rate equal to the arithmetic mean, for the immediately preceding week, of the daily yields to maturity for U.S. Treasury securities with a maturity of five years from the next Series F Reset Date and trading in the public securities markets or (ii) if the H.15(519) is not published during the week preceding the Series F Reset Distribution Determination Date, or does not contain such yields, then the rate will be determined by interpolation between the arithmetic mean, for the immediately preceding week, of the daily yields to maturity for each of the two series of U.S. Treasury securities trading in the public securities markets, (A) one maturing as close as possible to, but earlier than, the Series F Reset Date following the next succeeding Series F Reset Distribution Determination Date, and (B) the other maturity as close as possible to, but later than, the Series F Reset Date following the next succeeding Series F Reset Distribution Determination Date, in each case as published in the most recent H.15(519) under the caption “Treasury Constant Maturities” as the yield on actively traded U.S. Treasury securities adjusted to constant maturity. If the Series F Five-year U.S. Treasury Rate cannot be determined pursuant to the methods described in clauses (i) or (ii) above, then the Series F Five-year U.S. Treasury Rate will be the same interest rate determined for the immediately preceding Series F Reset Distribution Determination Date, or if this sentence is applicable with respect to the first Series F Reset Distribution Determination Date, 6.750%.

Series F Holder” means a Record Holder of Series F Preferred Units.

Series F Junior Securities” means any class or series of Partnership Securities that, with respect to distributions on such Partnership Securities and distributions upon liquidation of the Partnership, ranks junior to the Series F Preferred Units, including but not limited to Common Units, Class A Units, Class B Units and the General Partner Interest, but excluding any Series F Parity Securities and Series F Senior Securities.

Series F Liquidation Preference” means a liquidation preference for each Series F Preferred Unit initially equal to $1,000.00 per Series F Preferred Unit (subject to adjustment for any splits, combinations or similar adjustments to the Series F Preferred Units), which liquidation preference shall be subject to increase by the per Series F Preferred Unit amount of any accumulated and unpaid Series F Distributions (whether or not such distributions shall have been declared).

Series F Original Issue Date” means January 22, 2020.

 

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Series F Parity Securities” means the Series A Preferred Units, Series B Preferred Units, Series C Preferred Units, Series D Preferred Units, Series E Preferred Units, Series G Preferred Units and any other class or series of Partnership Interests established after the date hereof by the General Partner, the terms of which class or series expressly provide that it ranks on parity with the Series F Preferred Units as to distributions and amounts payable upon a dissolution or liquidation pursuant to Article XII.

Series F Preferred Units” has the meaning given such term in Section 5.22(a).

Series F Rating Event” means a change by any Rating Agency to the Series F Current Criteria, which change results in (a) any shortening of the length of time for which the Series F Current Criteria are scheduled to be in effect with respect to the Series F Preferred Units or (b) a lower Equity Credit being given to the Series F Preferred Units than the Equity Credit that would have been assigned to the Series F Preferred Units by such Rating Agency pursuant to its Series F Current Criteria.

Series F Redemption Date” has the meaning given such term in Section 5.22(b)(iv)(A).

Series F Redemption Notice” has the meaning given such term in Section 5.22(b)(iv)(B).

Series F Redemption Price” has the meaning given such term in Section 5.22(b)(iv)(A).

Series F Reset Date” means the Series F First Call Date and each date falling on the fifth anniversary of the preceding Series F Reset Date.

Series F Reset Distribution Determination Date” means, in respect of any Series F Reset Period, the day falling two Business Days prior to the beginning of such Series F Reset Period.

Series F Reset Period” means the period from and including the Series F First Call Date to, but excluding, the next following Series F Reset Date and thereafter each period from and including each Series F Reset Date to, but excluding, the next following Series F Reset Date, until such time as all of the Outstanding Series F Preferred Units are redeemed in accordance with Section 5.22(b)(iv).

Series F Senior Securities” means any class or series of Partnership Interests established after the date hereof by the General Partner, the terms of which class or series expressly provide that it ranks senior to the Series F Preferred Units as to distributions and amounts payable upon a dissolution or liquidation pursuant to Article XII.

Series G Base Liquidation Preference” means a liquidation preference for each Series G Preferred Unit initially equal to $1,000.00 per Series G Preferred Unit.

Series G Current Criteria” means the Equity Credit criteria of a Rating Agency for securities such as the Series G Preferred Units, as such criteria were in effect as of the Series G Original Issue Date.

Series G Distribution Payment Date” means the 15th day of each May and November of each year; provided however, that if any Series G Distribution Payment Date would otherwise occur on a day that is not a Business Day, such Series G Distribution Payment Date shall instead be on the immediately succeeding Business Day.

Series G Distribution Period” means a period of time from and including the preceding Series G Distribution Payment Date, to, but excluding, the next Series G Distribution Payment Date for such Series G Distribution Period.

Series G Distribution Rate” means an initial distribution rate for the Series G Preferred Units from and including the date of original issue to, but excluding, the Series G First Call Date equal to 7.125% per annum of the $1,000.00 liquidation preference per Series G Preferred Unit (equal to $71.25 per Series G Preferred Unit per

 

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annum). On and after the Series G First Call Date, the distribution rate on the Series G Preferred Units for each Series G Reset Period will equal for each Series G Preferred Unit a percentage of the $1,000.00 liquidation preference for such Series G Preferred Unit equal to the Series G Five-year U.S. Treasury Rate as of the most recent Series G Reset Distribution Determination Date plus a spread of 5.306% per annum.

Series G Distribution Record Date” has the meaning given such term in Section 5.23(b)(ii)(B).

Series G Distributions” means distributions with respect to Series G Preferred Units pursuant to Section 5.23(b)(ii).

Series G First Call Date” means May 15, 2030.

Series G Five-year U.S. Treasury Rate” means, as of any Series G Reset Distribution Determination Date, as applicable, (i) an interest rate (expressed as a decimal) determined to be the per annum rate equal to the arithmetic mean, for the immediately preceding week, of the daily yields to maturity for U.S. Treasury securities with a maturity of five years from the next Series G Reset Date and trading in the public securities markets or (ii) if the H.15(519) is not published during the week preceding the Series G Reset Distribution Determination Date, or does not contain such yields, then the rate will be determined by interpolation between the arithmetic mean, for the immediately preceding week, of the daily yields to maturity for each of the two series of U.S. Treasury securities trading in the public securities markets, (A) one maturing as close as possible to, but earlier than, the Series G Reset Date following the next succeeding Series G Reset Distribution Determination Date, and (B) the other maturity as close as possible to, but later than, the Series G Reset Date following the next succeeding Series G Reset Distribution Determination Date, in each case as published in the most recent H.15(519) under the caption “Treasury Constant Maturities” as the yield on actively traded U.S. Treasury securities adjusted to constant maturity. If the Series G Five-year U.S. Treasury Rate cannot be determined pursuant to the methods described in clauses (i) or (ii) above, then the Series G Five-year U.S. Treasury Rate will be the same interest rate determined for the immediately preceding Series G Reset Distribution Determination Date, or if this sentence is applicable with respect to the first Series G Reset Distribution Determination Date, 7.125%.

Series G Holder” means a Record Holder of Series G Preferred Units.

Series G Junior Securities” means any class or series of Partnership Securities that, with respect to distributions on such Partnership Securities and distributions upon liquidation of the Partnership, ranks junior to the Series G Preferred Units, including but not limited to Common Units, Class A Units, Class B Unit and the General Partner Interest, but excluding any Series G Parity Securities and Series G Senior Securities.

Series G Liquidation Preference” means a liquidation preference for each Series G Preferred Unit initially equal to $1,000.00 per Series G Preferred Unit (subject to adjustment for any splits, combinations or similar adjustments to the Series G Preferred Units), which liquidation preference shall be subject to increase by the per Series G Preferred Unit amount of any accumulated and unpaid Series G Distributions (whether or not such distributions shall have been declared).

Series G Original Issue Date” means January 22, 2020.

Series G Parity Securities” means the Series A Preferred Units, Series B Preferred Units, Series C Preferred Units, Series D Preferred Units, Series E Preferred Units, Series F Preferred Units and any other class or series of Partnership Interests established after the date hereof by the General Partner, the terms of which class or series expressly provide that it ranks on parity with the Series G Preferred Units as to distributions and amounts payable upon a dissolution or liquidation pursuant to Article XII.

Series G Preferred Units” has the meaning given such term in Section 5.23(a).

 

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Series G Rating Event” means a change by any Rating Agency to the Series G Current Criteria, which change results in (a) any shortening of the length of time for which the Series G Current Criteria are scheduled to be in effect with respect to the Series G Preferred Units or (b) a lower Equity Credit being given to the Series G Preferred Units than the Equity Credit that would have been assigned to the Series G Preferred Units by such Rating Agency pursuant to its Series G Current Criteria.

Series G Redemption Date” has the meaning given such term in Section 5.23(b)(iv)(A).

Series G Redemption Notice” has the meaning given such term in Section 5.23(b)(iv)(B).

Series G Redemption Price” has the meaning given such term in Section 5.23(b)(iv)(A).

Series G Reset Date” means the Series G First Call Date and each date falling on the fifth anniversary of the preceding Series G Reset Date.

Series G Reset Distribution Determination Date” means, in respect of any Series G Reset Period, the day falling two Business Days prior to the beginning of such Series G Reset Period.

Series G Reset Period” means the period from and including the Series G First Call Date to, but excluding, the next following Series G Reset Date and thereafter each period from and including each Series G Reset Date to, but excluding, the next following Series G Reset Date, until such time as all of the Outstanding Series G Preferred Units are redeemed in accordance with Section 5.23(b)(iv).

Series G Senior Securities” means any class or series of Partnership Interests established after the date hereof by the General Partner, the terms of which class or series expressly provide that it ranks senior to the Series G Preferred Units as to distributions and amounts payable upon a dissolution or liquidation pursuant to Article XII.

Transfer Agent” means such bank, trust company or other Person (including the General Partner or one of its Affiliates) as shall be appointed from time to time by the Partnership to act as registrar and transfer agent for the Common Units; provided that if no Transfer Agent is specifically designated for any other Partnership Securities, the General Partner shall act in such capacity. The Transfer Agent for the Series A Preferred Units, the Series B Preferred Units, the Series C Preferred Units, the Series D Preferred Units, the Series E Preferred Units, the Series F Preferred Units and the Series G Preferred Units shall be American Stock Transfer & Trust Company, LLC, and its successors and assigns, or any other transfer agent and registrar appointed by the General Partner for the Series A Preferred Units, the Series B Preferred Units, the Series C Preferred Units, the Series D Preferred Units, the Series E Preferred Units, the Series F Preferred Units or the Series G Preferred Units, as applicable.

Unit” means a Partnership Security that is designated as a “Unit” and shall include Common Units, Series A Preferred Units, Series B Preferred Units, Series C Preferred Units, Series D Preferred Units, Series E Preferred Units, Series F Preferred Units, Series G Preferred Units and Class B Units, but shall not include the General Partner Units (or the General Partner Interest represented thereby) or Class A Units.

Unit Majority” means at least a majority of the Outstanding Units (excluding the Series A Preferred Units, Series B Preferred Units, Series C Preferred Units, Series D Preferred Units, Series E Preferred Units, Series F Preferred Units, Series G Preferred Units and Class B Units in respect of matters in which the holders of the Series A Preferred Units, Series B Preferred Units, Series C Preferred Units, Series D Preferred Units, Series E Preferred Units, Series F Preferred Units, Series G Preferred Units and Class B Units are not entitled to a vote), voting together as a single class.

 

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(b) Section 5.6(a) of the Partnership Agreement is hereby amended and restated in its entirety as follows:

“Section 5.6 Capital Accounts.

(a) The Partnership shall maintain for each Partner (or a beneficial owner of Partnership Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method acceptable to the General Partner) owning a Partnership Interest a separate Capital Account with respect to such Partnership Interest in accordance with the rules of Treasury Regulation Section 1.704-1(b)(2)(iv). Such Capital Account shall be increased by (i) the amount of all Capital Contributions made to the Partnership with respect to such Partnership Interest and (ii) all items of Partnership income and gain (including, without limitation, income and gain exempt from tax) computed in accordance with Section 5.6(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1, and decreased by (x) the amount of cash or Net Agreed Value of all actual and deemed distributions of cash or property made with respect to such Partnership Interest (provided that the Capital Account of a Series A Holder, a Series B Holder, a Series C Holder, a Series D Holder, a Series E Holder, a Series F Holder or a Series G Holder shall not be reduced by any Series A Distributions, Series B Distributions, Series C Distributions, Series D Distributions, Series E Distributions, Series F Distributions or Series G Distributions it receives) and (y) all items of Partnership deduction and loss computed in accordance with Section 5.6(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1. The Capital Account balance with respect to each Common Unit as of the Effective Date was the Closing Price of the Common Units on the Effective Date. The initial Capital Account Balance in respect of each Series A Preferred Unit on the date hereof is the Series A Liquidation Preference on such date. The initial Capital Account Balance in respect of each Series B Preferred Unit on the date hereof is the Series B Liquidation Preference on such date. The initial Capital Account Balance in respect of each Series C Preferred Unit on the date hereof is the Series C Liquidation Preference on such date. The initial Capital Account Balance in respect of each Series D Preferred Unit on the date hereof is the Series D Liquidation Preference on such date. The initial Capital Account Balance in respect of each Series E Preferred Unit on the date hereof is the Series E Liquidation Preference on such date. The initial Capital Account Balance in respect of each Series F Preferred Unit on the date hereof is the Series F Liquidation Preference on such date. The initial Capital Account Balance in respect of each Series G Preferred Unit on the date hereof is the Series G Liquidation Preference on such date. The initial Capital Account Balance in respect of each Class B Unit on the date hereof is the Class B Unit Price on such date.

(c) Article V of the Partnership Agreement is hereby amended by deleting Section 5.13 in its entirety and replacing with “[Reserved]” and adding a new Section 5.17, Section 5.18, Section 5.19, Section 5.20, Section 5.21, Section 5.22, Section 5.23 and Section 5.24 at the end thereof as follows:

“Section 5.17 Establishment of Series A Preferred Units.

(a) General. The Partnership hereby designates and creates a class of Partnership Securities to be designated as “6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units” (the “Series A Preferred Units”), having the preferences, rights, powers, and duties set forth herein, including this Section 5.17. Each Series A Preferred Unit shall be identical in all respects to every other Series A Preferred Unit, except as to the respective dates from which the Series A Liquidation Preference shall increase or from which Series A Distributions may begin accruing, to the extent such dates may differ. The Series A Preferred Units represent perpetual equity interests in the Partnership and shall not give rise to a claim by the Partnership or a Series A Holder for conversion or, except as set forth in Section 5.17(b)(iv), redemption thereof at a particular date.

(b) Rights of Series A Preferred Units. The Series A Preferred Units shall have the following rights, preferences and privileges and shall be subject to the following duties and obligations:

(i) Series A Preferred Units.

(A) The authorized number of Series A Preferred Units shall be unlimited. Series A Preferred Units that are purchased or otherwise acquired by the Partnership shall be cancelled.

 

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(B) The Series A Preferred Units shall be represented by one or more global Certificates registered in the name of the Depositary or its nominee, and no Series A Holder shall be entitled to receive a definitive Certificate evidencing its Series A Preferred Units, unless (1) requested by a Series A Holder and consented to by the General Partner in its sole discretion, (2) otherwise required by law or (3) the Depositary gives notice of its intention to resign or is no longer eligible to act as such with respect to the Series A Preferred Units and the General Partner shall have not selected a substitute Depositary within 60 calendar days thereafter. So long as the Depositary shall have been appointed and is serving with respect to the Series A Preferred Units, payments and communications made by the Partnership to Series A Holders shall be made by making payments to, and communicating with, the Depositary.

(ii) Distributions.

(A) Distributions on each Outstanding Series A Preferred Unit shall be cumulative and shall accumulate at the applicable Series A Distribution Rate from and including [ ● ], 2021 (or, for any subsequently issued and newly Outstanding Series A Preferred Units, from and including the Series A Distribution Payment Date immediately preceding the issue date of such Series A Preferred Units) until such time as the Partnership pays the Series A Distribution or redeems such Series A Preferred Unit in accordance with Section 5.17(b)(iv), whether or not such Series A Distributions shall have been declared. Series A Holders shall be entitled to receive Series A Distributions from time to time out of any assets of the Partnership legally available for the payment of distributions at the Series A Distribution Rate per Series A Preferred Unit when, as, and, if declared by the General Partner. Series A Distributions, to the extent declared by the General Partner to be paid by the Partnership in accordance with this Section 5.17(b)(ii), shall be paid, in Arrears, on each Series A Distribution Payment Date. Series A Distributions shall accumulate in each Series A Distribution Period from and including the preceding Series A Distribution Payment Date (other than the initial Series A Distribution Period, which shall commence on and include [ ● ], 2021), to, but excluding, the next Series A Distribution Payment Date for such Series A Distribution Period; provided that distributions shall accrue on accumulated but unpaid Series A Distributions at the Series A Distribution Rate. If any Series A Distribution Payment Date otherwise would occur on a date that is not a Business Day, declared Series A Distributions shall be paid on the immediately succeeding Business Day without the accumulation of additional distributions. During the Series A Fixed Rate Period, Series A Distributions shall be payable based on a 360-day year consisting of twelve 30 day months. During the Series A Floating Rate Period, Series A Distributions shall be computed by multiplying the Series A Distribution Rate by a fraction, the numerator of which will be the actual number of days elapsed during that Series A Distribution Period (determined by including the first day of such Series A Distribution Period and excluding the last day, which is the Series A Distribution Payment Date), and the denominator of which will be 360, and by multiplying the result by the aggregate Series A Liquidation Preference of all Outstanding Series A Preferred Units. All Series A Distributions that are (1) accumulated and unpaid or (2) payable by the Partnership pursuant to this Section 5.17(b)(ii) shall be payable without regard to income of the Partnership and shall be treated for federal income tax purposes as guaranteed payments for the use of capital under Section 707(c) of the Code. The guaranteed payment with respect to any Series A Distribution Period shall be for the account of the holders of Series A Preferred Units as of the applicable Series A Distribution Record Date.

(B) Not later than 5:00 p.m., New York City time, on each Series A Distribution Payment Date, the Partnership shall pay those Series A Distributions, if any, that shall have been declared by the General Partner to Series A Holders on the Record Date for the applicable Series A Distribution. The Record Date (the “Series A Distribution Record Date”) for the payment of any Series A Distributions shall be as of the close of business on the first Business Day of the month of the applicable Series A Distribution Payment Date, except that in the case of payments of

 

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Series A Distributions in Arrears, the Series A Distribution Record Date with respect to a Series A Distribution Payment Date shall be such date as may be designated by the General Partner in accordance with this Section 5.17. So long as any Series A Preferred Units are Outstanding, no distribution shall be declared or paid or set aside for payment on any Series A Junior Securities (other than a distribution payable solely in Series A Junior Securities) unless full cumulative Series A Distributions have been or contemporaneously are being paid or set apart for payment on all Outstanding Series A Preferred Units (and distributions on any other Series A Parity Securities) through the most recent respective Series A Distribution Payment Date (and distribution payment date with respect to such Series A Parity Securities, if any); provided, however, notwithstanding anything to the contrary in this Section 5.17(b)(ii)(B), if a distribution period with respect to a class of Series A Junior Securities or Series A Parity Securities is shorter than the Series A Distribution Period, the General Partner may declare and pay regular distributions with respect to such Series A Junior Securities or Series A Parity Securities, so long as, at the time of declaration of such distribution, (1) there are no Series A Distributions in Arrears, and (2) the General Partner expects to have sufficient funds to pay the full distribution in respect of the Series A Preferred Units on the next successive Series A Distribution Payment Date. Accumulated Series A Distributions in Arrears for any past Series A Distribution Period may be declared by the General Partner and paid on any date fixed by the General Partner, whether or not a Series A Distribution Payment Date, to Series A Holders on the Record Date for such payment, which may not be less than 10 days before such payment date. Subject to the next succeeding sentence, if all accumulated Series A Distributions in Arrears on all Outstanding Series A Preferred Units and all accumulated distributions in arrears on any Series A Parity Securities shall not have been declared and paid, or if sufficient funds for the payment thereof shall not have been set apart, payment of accumulated distributions in Arrears on the Series A Preferred Units and accumulated distributions in arrears on any such Series A Parity Securities shall be made in order of their respective distribution payment dates, commencing with the earliest distribution payment date. If less than all distributions payable with respect to all Series A Preferred Units and any other Series A Parity Securities are paid, any partial payment shall be made Pro Rata with respect to the Series A Preferred Units and any such other Series A Parity Securities entitled to a distribution payment at such time in proportion to the aggregate distribution amounts remaining due in respect of such Series A Preferred Units and such other Series A Parity Securities at such time. Subject to Section 12.4 and Section 5.17(b)(v), Series A Holders shall not be entitled to any distribution, whether payable in cash, property or Partnership Securities, in excess of full cumulative Series A Distributions. Except insofar as distributions accrue on the amount of any accumulated and unpaid Series A Distributions as described in Section 5.17(b)(ii)(A), no interest or sum of money in lieu of interest shall be payable in respect of any distribution payment which may be in Arrears on the Series A Preferred Units. So long as the Series A Preferred Units are held of record by the Depositary or its nominee, declared Series A Distributions shall be paid to the Depositary in same-day funds on each Series A Distribution Payment Date or other distribution payment date in the case of payments for Series A Distributions in Arrears.

(C) The Series A Distribution Rate for each Series A Distribution Period in the Series A Floating Rate Period will be determined by the Calculation Agent using Three-Month LIBOR as in effect on the Distribution Determination Date for such Series A Distribution Period. The Calculation Agent then will add the spread of 4.028% per annum to Three-Month LIBOR as determined on the applicable Distribution Determination Date.

Notwithstanding the foregoing:

(A) If the Calculation Agent determines on the relevant Distribution Determination Date that the LIBOR base rate has been discontinued, then the Calculation Agent will use a substitute or successor base rate that it has determined in its sole discretion is most comparable to the LIBOR base rate, provided that if the Calculation Agent determines there is an industry-accepted

 

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substitute or successor base rate, then the Calculation Agent shall use such substitute or successor base rate; and

(B) If the Calculation Agent has determined a substitute or successor base rate in accordance with the foregoing, the Calculation Agent in its sole discretion may determine what business day convention to use, the definition of business day, the Distribution Determination Date to be used and any other relevant methodology for calculating such substitute or successor base rate.

(C) Unless otherwise determined by the General Partner, Series A Distributions shall be deemed to have been paid out of deductions from Available Cash with respect to the Quarter ended immediately preceding the Quarter in which the Series A Distribution is made.

(iii) Voting Rights.

(A) Notwithstanding anything to the contrary in this Agreement, the Series A Preferred Units shall not have any voting rights or rights to consent or approve any action or matter, except as set forth in Section 13.3(c), this Section 5.17(b)(iii) or as otherwise required by the Delaware Act.

(B) Notwithstanding anything to the contrary in this Agreement, without the affirmative vote or consent of the holders of at least 66 2/3% of the Outstanding Series A Preferred Units, voting as a separate class, the General Partner shall not adopt any amendment to this Agreement that the General Partner determines would have a material adverse effect on the powers, preferences, duties, or special rights of the Series A Preferred Units; provided, however, that (i) subject to Section 5.17(b)(iii)(C), the issuance of additional Partnership Securities (and any amendment to this Agreement in connection therewith) shall not be deemed to constitute such a material adverse effect for purposes of this Section 5.17(b)(iii)(B) and (ii) for purposes of this Section 5.17(b)(iii)(B), no amendment of this Agreement in connection with a merger or other transaction in which the Series A Preferred Units remain Outstanding with the terms thereof materially unchanged in any respect adverse to the Series A Holders (as determined by the General Partner) shall be deemed to materially and adversely affect the powers, preferences, duties, or special rights of the Series A Preferred Units.

(C) Notwithstanding anything to the contrary in this Agreement, without the affirmative vote or consent of the holders of at least 66 2/3% of the Outstanding Series A Preferred Units, voting as a class together with holders of any other Series A Parity Securities upon which like voting rights have been conferred and are exercisable, the Partnership shall not (x) create or issue any Series A Parity Securities (including any additional Series A Preferred Units) if the cumulative distributions payable on Outstanding Series A Preferred Units (or any Series A Parity Securities, if the holders of such Series A Parity Securities vote as a class together with the Series A Holders pursuant to this Section 5.17(b)(iii)(C)) are in Arrears or (y) create or issue any Series A Senior Securities.

(D) For any matter described in this Section 5.17(b)(iii) in which the Series A Holders are entitled to vote as a class (whether separately or together with the holders of any Series A Parity Securities), such Series A Holders shall be entitled to one vote per Series A Preferred Unit. Any Series A Preferred Units held by the Partnership or any of its Subsidiaries or their controlled Affiliates shall not be entitled to vote.

(E) Notwithstanding Section 5.17(b)(iii)(B) and 5.17(b)(iii)(C), no vote of the Series A Holders shall be required if, at or prior to the time when such action is to take effect, provision is made for the redemption of all Series A Preferred Units at the time Outstanding.

(iv) Optional Redemption; Series A Rating Event.

(A) The Partnership shall have the right (1) at any time, and from time to time, on or after February 15, 2023 or (2) at any time within 120 days after the conclusion of any review or appeal process instituted by the Partnership following the occurrence of a Series A Rating Event, in each

 

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case, to redeem the Series A Preferred Units, which redemption may be in whole or in part (except with respect to a redemption pursuant to clause (2) of this Section 5.17(b)(iv)(A) which shall be in whole but not in part), using any source of funds legally available for such purpose. Any such redemption shall occur on a date set by the General Partner (the “Series A Redemption Date”). The Partnership shall effect any such redemption by paying cash for each Series A Preferred Unit to be redeemed equal to 100% (in the case of a redemption described in clause (1) of this Section 5.17(b)(iv)(A)), or 102% (in the case of a redemption described in clause (2) of this Section 5.17(b)(iv)(A)), of the Series A Liquidation Preference for such Series A Preferred Unit on such Series A Redemption Date plus an amount equal to all unpaid Series A Distributions thereon from the date of issuance to, but excluding, the Series A Redemption Date (whether or not such distributions shall have been declared) (the “Series A Redemption Price”). So long as the Series A Preferred Units to be redeemed are held of record by the Depositary or the nominee of the Depositary, the Series A Redemption Price shall be paid by the Paying Agent to the Depositary on the Series A Redemption Date.

(B) The Partnership shall give notice of any redemption by mail, postage prepaid, not less than 15 days and not more than 60 days before the scheduled Series A Redemption Date to the Series A Holders (as of 5:00 p.m. New York City time on the Business Day next preceding the day on which notice is given) of any Series A Preferred Units to be redeemed as such Series A Holders’ names appear on the books of the Transfer Agent and at the address of such Series A Holders shown therein. Such notice (the “Series A Redemption Notice”) shall state, as applicable: (1) the Series A Redemption Date, (2) the number of Series A Preferred Units to be redeemed and, if less than all Outstanding Series A Preferred Units are to be redeemed, the number (and in the case of Series A Preferred Units in certificated form, the identification) of Series A Preferred Units to be redeemed from such Series A Holder, (3) the Series A Redemption Price, (4) the place where any Series A Preferred Units in certificated form are to be redeemed and shall be presented and surrendered for payment of the Series A Redemption Price therefor (which shall occur automatically if the Certificate representing such Series A Preferred Units is issued in the name of the Depositary or its nominee), and (5) that distributions on the Series A Preferred Units to be redeemed shall cease to accumulate from and after such Series A Redemption Date.

(C) If the Partnership elects to redeem less than all of the Outstanding Series A Preferred Units, the number of Series A Preferred Units to be redeemed shall be determined by the General Partner, and such Series A Preferred Units shall be redeemed by such method of selection as the Depositary shall determine, either Pro Rata or by lot, with adjustments to avoid redemption of fractional Series A Preferred Units. The aggregate Series A Redemption Price for any such partial redemption of the Outstanding Series A Preferred Units shall be allocated correspondingly among the redeemed Series A Preferred Units. The Series A Preferred Units not redeemed shall remain Outstanding and entitled to all the rights, preferences and duties provided in this Section 5.17.

(D) If the Partnership gives or causes to be given a Series A Redemption Notice, the Partnership shall deposit with the Paying Agent funds sufficient to redeem the Series A Preferred Units as to which such Series A Redemption Notice shall have been given, no later than 10:00 a.m. New York City time on the Series A Redemption Date, and shall give the Paying Agent irrevocable instructions and authority to pay the Series A Redemption Price to each Series A Holder whose Series A Preferred Units are to be redeemed upon surrender or deemed surrender (which shall occur automatically if the Certificate representing such Series A Preferred Units is issued in the name of the Depositary or its nominee) of the Certificates therefor as set forth in the Series A Redemption Notice. If a Series A Redemption Notice shall have been given, from and after the Series A Redemption Date, unless the Partnership defaults in providing funds sufficient for such redemption at the time and place specified for payment pursuant to the Series A Redemption Notice, all Series A Distributions on such Series A Preferred Units to be redeemed shall cease to accumulate and all rights of holders of such Series A Preferred Units as Limited

 

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Partners with respect to such Series A Preferred Units to be redeemed shall cease, except the right to receive the Series A Redemption Price, and such Series A Preferred Units shall not thereafter be transferred on the books of the Transfer Agent or be deemed to be Outstanding for any purpose whatsoever. The Series A Holders shall have no claim to the interest income, if any, earned on funds deposited with the Paying Agent. Any funds deposited with the Paying Agent hereunder by the Partnership for any reason, including redemption of Series A Preferred Units, that remain unclaimed or unpaid after one year after the applicable Series A Redemption Date or other payment date, as applicable, shall be, to the extent permitted by law, repaid to the Partnership upon its written request, after which repayment the Series A Holders entitled to such redemption or other payment shall have recourse only to the Partnership.

Notwithstanding any Series A Redemption Notice, there shall be no redemption of any Series A Preferred Units called for redemption until funds sufficient to pay the full Series A Redemption Price of such Series A Preferred Units shall have been deposited by the Partnership with the Paying Agent.

(E) Any Series A Preferred Units that are redeemed or otherwise acquired by the Partnership shall be cancelled. If only a portion of the Series A Preferred Units represented by a Certificate shall have been called for redemption, upon surrender of the Certificate to the Paying Agent (which shall occur automatically if the Certificate representing such Series A Preferred Units is registered in the name of the Depositary or its nominee), the Partnership shall issue and the Paying Agent shall deliver to the Series A Holders a new Certificate (or adjust the applicable book-entry account) representing the number of Series A Preferred Units represented by the surrendered Certificate that have not been called for redemption.

(F) Notwithstanding anything to the contrary in this Section 5.17, in the event that full cumulative distributions on the Series A Preferred Units and any Series A Parity Securities shall not have been paid or declared and set aside for payment, the Partnership shall not be permitted to repurchase, redeem or otherwise acquire, in whole or in part, any Series A Preferred Units or Series A Parity Securities except pursuant to a purchase or exchange offer made on the same relative terms to all Series A Holders and holders of any Series A Parity Securities. Subject to Section 4.9, so long as any Series A Preferred Units are Outstanding, the Partnership shall not be permitted to redeem, repurchase or otherwise acquire any Common Units or any other Series A Junior Securities unless full cumulative distributions on the Series A Preferred Units and any Series A Parity Securities for all prior and the then-ending Series A Distribution Periods, with respect to the Series A Preferred Units, and all prior and then ending distribution periods, with respect to any such Series A Parity Securities, shall have been paid or declared and set aside for payment.

(v) Liquidation Rights. In the event of the dissolution and winding up of the Partnership under Section 12.4 or a sale, exchange, or other disposition of all or substantially all of the assets of the Partnership, either voluntary or involuntary, the Record Holders of the Series A Preferred Units shall be entitled to receive, out of the assets of the Partnership available for distribution to the Partners or any Assignees, prior and in preference to any distribution of any assets of the Partnership to the Record Holders of any other class or series of Partnership Interests (other than Series A Senior Securities or Series A Parity Securities), (A) first, any accumulated and unpaid distributions on the Series A Preferred Units (regardless of whether previously declared) and (B) then, any positive value in each such holder’s Capital Account in respect of such Series A Preferred Units. If in the year of such dissolution and winding up, or sale, exchange, or other disposition of all or substantially all of the assets of the Partnership, any such Record Holder’s Capital Account in respect of such Series A Preferred Units is less than the aggregate Series A Base Liquidation Preference of such Series A Preferred Units, then, notwithstanding anything to the contrary contained in this Agreement, and prior to any other allocation pursuant to this Agreement for such year and any distribution pursuant to the preceding sentence (other than any allocations or distributions made with respect to any other Series A Parity Securities upon which like allocation and distribution rights have been conferred), items of gross

 

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income and gain shall be allocated to all Unitholders then holding Series A Preferred Units, Pro Rata, until the Capital Account in respect of each Outstanding Series A Preferred Unit is equal to the Series A Base Liquidation Preference (and no other allocation pursuant to this Agreement shall reverse the effect of such allocation); provided, however, that in the event that like allocation rights have been conferred upon other Series A Parity Securities (including pursuant to Sections 5.18(b)(v), 5.19(b)(v), 5.20(b)(v), 5.21(b)(v), 5.22(b)(v) and 5.23(b)(v)), then items of gross income and gain shall be allocated to all Unitholders then holding Series A Preferred Units and such Series A Parity Securities, Pro Rata, until the Capital Account in respect of each Outstanding Series A Preferred Unit and such Series A Parity Security is equal to the applicable liquidation preference (and no other allocation pursuant to this Agreement shall reverse the effect of such allocation). If in the year of such dissolution and winding up any such Record Holder’s Capital Account in respect of such Series A Preferred Units is less than the aggregate Series A Base Liquidation Preference of such Series A Preferred Units after the application of the preceding sentence, then to the extent permitted by applicable law, but otherwise notwithstanding anything to the contrary contained in this Agreement, items of gross income and gain for any preceding taxable year(s) with respect to which IRS Form 1065 Schedules K-1 have not been filed by the Partnership shall be reallocated to all Unitholders then holding Series A Preferred Units, Pro Rata, until the Capital Account in respect of each such Outstanding Series A Preferred Unit after making allocations pursuant to this and the immediately preceding sentence is equal to the Series A Base Liquidation Preference (and no other allocation pursuant to this Agreement shall reverse the effect of such allocation); provided, however, that in the event like allocation rights have been conferred upon other Series A Parity Securities (including pursuant to Sections 5.18(b)(v), 5.19(b)(v), 5.20(b)(v), 5.21(b)(v), 5.22(b)(v) and 5.23(b)(v)), then any such items of gross income and gain shall be reallocated to all Unitholders then holding Series A Preferred Units and such Series A Parity Securities, Pro Rata, until the Capital Account in respect of each Outstanding Series A Preferred Unit and such Series A Parity Security after making allocations pursuant to this and the immediately preceding sentence is equal to the applicable liquidation preference (and no other allocation pursuant to this Agreement shall reverse the effect of such allocation). After such allocations have been made to the Outstanding Series A Preferred Units, and any Series A Parity Securities, as applicable, any remaining Net Termination Gain or Net Termination Loss shall be allocated to the Partners pursuant to Section 6.1(c) or Section 6.1(d), as the case may be. At the time of the dissolution of the Partnership, subject to Section 17-804 of the Delaware Act, the Record Holders of the Series A Preferred Units shall become entitled to receive any distributions in respect of the Series A Preferred Units that are accrued and unpaid as of the date of such distribution, and shall have the status of, and shall be entitled to all remedies available to, a creditor of the Partnership, and such entitlement of the Record Holders of the Series A Preferred Units to such accrued and unpaid distributions shall have priority over any entitlement of any other Partners or Assignees (other than holders of any Series A Senior Securities or Series A Parity Securities) with respect to any distributions by the Partnership to such other Partners or Assignees; provided, however, that the General Partner, as such, will have no liability for any obligations with respect to such distributions to any Record Holder(s) of Series A Preferred Units.

(vi) Rank. The Series A Preferred Units shall each be deemed to rank as to distributions on such Partnership Securities and distributions upon liquidation of the Partnership:

(A) senior to any Series A Junior Securities;

(B) on a parity with any Series A Parity Securities;

(C) junior to any Series A Senior Securities; and

(D) junior to all existing and future indebtedness of the Partnership and other liabilities with respect to assets available to satisfy claims against the Partnership.

(vii) No Sinking Fund. The Series A Preferred Units shall not have the benefit of any sinking fund.

 

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(viii) Record Holders. To the fullest extent permitted by applicable law, the General Partner, the Partnership, the Transfer Agent, and the Paying Agent may deem and treat any Series A Holder as the true, lawful, and absolute owner of the applicable Series A Preferred Units for all purposes, and none of the General Partner, the Partnership, the Transfer Agent or the Paying Agent shall be affected by any notice to the contrary, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which the Series A Preferred Units may be listed or admitted to trading, if any.

(ix) Other Rights; Fiduciary Duties. The Series A Preferred Units and the Series A Holders shall not have any designations, preferences, rights, powers or duties, other than as set forth in this Agreement or as provided by applicable law. Notwithstanding anything to the contrary in this Agreement or any duty existing at law, in equity or otherwise, to the fullest extent permitted by applicable law, neither the General Partner nor any other Indemnitee shall owe any duties, including fiduciary duties, or have any liabilities to Series A Holders, other than the implied contractual covenant of good faith and fair dealing.

“Section 5.18 Establishment of Series B Preferred Units.

(a) General. The Partnership hereby designates and creates a class of Partnership Securities to be designated as “6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units” (the “Series B Preferred Units”), having the preferences, rights, powers, and duties set forth herein, including this Section 5.18. Each Series B Preferred Unit shall be identical in all respects to every other Series B Preferred Unit, except as to the respective dates from which the Series B Liquidation Preference shall increase or from which Series B Distributions may begin accruing, to the extent such dates may differ. The Series B Preferred Units represent perpetual equity interests in the Partnership and shall not give rise to a claim by the Partnership or a Series B Holder for conversion or, except as set forth in Section 5.18(b)(iv), redemption thereof at a particular date.

(b) Rights of Series B Preferred Units. The Series B Preferred Units shall have the following rights, preferences and privileges and shall be subject to the following duties and obligations:

(i) Series B Preferred Units.

(A) The authorized number of Series B Preferred Units shall be unlimited. Series B Preferred Units that are purchased or otherwise acquired by the Partnership shall be cancelled.

(B) The Series B Preferred Units shall be represented by one or more global Certificates registered in the name of the Depositary or its nominee, and no Series B Holder shall be entitled to receive a definitive Certificate evidencing its Series B Preferred Units, unless (1) requested by a Series B Holder and consented to by the General Partner in its sole discretion, (2) otherwise required by law or (3) the Depositary gives notice of its intention to resign or is no longer eligible to act as such with respect to the Series B Preferred Units and the General Partner shall have not selected a substitute Depositary within 60 calendar days thereafter. So long as the Depositary shall have been appointed and is serving with respect to the Series B Preferred Units, payments and communications made by the Partnership to Series B Holders shall be made by making payments to, and communicating with, the Depositary.

(ii) Distributions.

(A) Distributions on each Outstanding Series B Preferred Unit shall be cumulative and shall accumulate at the applicable Series B Distribution Rate from and including [ ● ], 2021 (or, for any subsequently issued and newly Outstanding Series B Preferred Units, from and including the Series B Distribution Payment Date immediately preceding the issue date of such Series B Preferred Units) until such time as the Partnership pays the Series B Distribution or redeems such Series B Preferred Unit in accordance with Section 5.18(b)(iv), whether or not such Series B Distributions shall have been declared. Series B Holders shall be entitled to receive Series B

 

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Distributions from time to time out of any assets of the Partnership legally available for the payment of distributions at the Series B Distribution Rate per Series B Preferred Unit when, as, and, if declared by the General Partner. Series B Distributions, to the extent declared by the General Partner to be paid by the Partnership in accordance with this Section 5.18(b)(ii), shall be paid, in Arrears, on each Series B Distribution Payment Date. Series B Distributions shall accumulate in each Series B Distribution Period from and including the preceding Series B Distribution Payment Date (other than the initial Series B Distribution Period, which shall commence on and include [ ● ], 2021), to, but excluding, the next Series B Distribution Payment Date for such Series B Distribution Period; provided that distributions shall accrue on accumulated but unpaid Series B Distributions at the Series B Distribution Rate. If any Series B Distribution Payment Date otherwise would occur on a date that is not a Business Day, declared Series B Distributions shall be paid on the immediately succeeding Business Day without the accumulation of additional distributions. During the Series B Fixed Rate Period, Series B Distributions shall be payable based on a 360-day year consisting of twelve 30 day months. During the Series B Floating Rate Period, Series B Distributions shall be computed by multiplying the Series B Distribution Rate by a fraction, the numerator of which will be the actual number of days elapsed during that Series B Distribution Period (determined by including the first day of such Series B Distribution Period and excluding the last day, which is the Series B Distribution Payment Date), and the denominator of which will be 360, and by multiplying the result by the aggregate Series B Liquidation Preference of all Outstanding Series B Preferred Units. All Series B Distributions that are (1) accumulated and unpaid or (2) payable by the Partnership pursuant to this Section 5.18(b)(ii) shall be payable without regard to income of the Partnership and shall be treated for federal income tax purposes as guaranteed payments for the use of capital under Section 707(c) of the Code. The guaranteed payment with respect to any Series B Distribution Period shall be for the account of the holders of Series B Preferred Units as of the applicable Series B Distribution Record Date.

(B) Not later than 5:00 p.m., New York City time, on each Series B Distribution Payment Date, the Partnership shall pay those Series B Distributions, if any, that shall have been declared by the General Partner to Series B Holders on the Record Date for the applicable Series B Distribution. The Record Date (the “Series B Distribution Record Date”) for the payment of any Series B Distributions shall be as of the close of business on the first Business Day of the month of the applicable Series B Distribution Payment Date, except that in the case of payments of Series B Distributions in Arrears, the Series B Distribution Record Date with respect to a Series B Distribution Payment Date shall be such date as may be designated by the General Partner in accordance with this Section 5.18. So long as any Series B Preferred Units are Outstanding, no distribution shall be declared or paid or set aside for payment on any Series B Junior Securities (other than a distribution payable solely in Series B Junior Securities) unless full cumulative Series B Distributions have been or contemporaneously are being paid or set apart for payment on all Outstanding Series B Preferred Units (and distributions on any other Series B Parity Securities) through the most recent respective Series B Distribution Payment Date (and distribution payment date with respect to such Series B Parity Securities, if any); provided, however, notwithstanding anything to the contrary in this Section 5.18(b)(ii)(B), if a distribution period with respect to a class of Series B Junior Securities or Series B Parity Securities is shorter than the Series B Distribution Period, the General Partner may declare and pay regular distributions with respect to such Series B Junior Securities or Series B Parity Securities, so long as, at the time of declaration of such distribution, (i) there are no Series B Distributions in Arrears, and (ii) the General Partner expects to have sufficient funds to pay the full distribution in respect of the Series B Preferred Units on the next successive Series B Distribution Payment Date. Accumulated Series B Distributions in Arrears for any past Series B Distribution Period may be declared by the General Partner and paid on any date fixed by the General Partner, whether or not a Series B Distribution Payment Date, to Series B Holders on the Record Date for such payment, which may not be less

 

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than 10 days before such payment date. Subject to the next succeeding sentence, if all accumulated Series B Distributions in Arrears on all Outstanding Series B Preferred Units and all accumulated distributions in arrears on any Series B Parity Securities shall not have been declared and paid, or if sufficient funds for the payment thereof shall not have been set apart, payment of accumulated distributions in Arrears on the Series B Preferred Units and accumulated distributions in arrears on any such Series B Parity Securities shall be made in order of their respective distribution payment dates, commencing with the earliest distribution payment date. If less than all distributions payable with respect to all Series B Preferred Units and any other Series B Parity Securities are paid, any partial payment shall be made Pro Rata with respect to the Series B Preferred Units and any such other Series B Parity Securities entitled to a distribution payment at such time in proportion to the aggregate distribution amounts remaining due in respect of such Series B Preferred Units and such other Series B Parity Securities at such time. Subject to Section 12.4 and Section 5.18(b)(v), Series B Holders shall not be entitled to any distribution, whether payable in cash, property or Partnership Securities, in excess of full cumulative Series B Distributions. Except insofar as distributions accrue on the amount of any accumulated and unpaid Series B Distributions as described in Section 5.18(b)(ii)(A), no interest or sum of money in lieu of interest shall be payable in respect of any distribution payment which may be in Arrears on the Series B Preferred Units. So long as the Series B Preferred Units are held of record by the Depositary or its nominee, declared Series B Distributions shall be paid to the Depositary in same-day funds on each Series B Distribution Payment Date or other distribution payment date in the case of payments for Series B Distributions in Arrears.

(C) The Series B Distribution Rate for each Series B Distribution Period in the Series B Floating Rate Period will be determined by the Calculation Agent using Three-Month LIBOR as in effect on the Distribution Determination Date for such Series B Distribution Period. The Calculation Agent then will add the spread of 4.155% per annum to Three-Month LIBOR as determined on the applicable Distribution Determination Date.

Notwithstanding the foregoing:

(A) If the Calculation Agent determines on the relevant Distribution Determination Date that the LIBOR base rate has been discontinued, then the Calculation Agent will use a substitute or successor base rate that it has determined in its sole discretion is most comparable to the LIBOR base rate, provided that if the Calculation Agent determines there is an industry-accepted substitute or successor base rate, then the Calculation Agent shall use such substitute or successor base rate; and

(B) If the Calculation Agent has determined a substitute or successor base rate in accordance with the foregoing, the Calculation Agent in its sole discretion may determine what business day convention to use, the definition of business day, the Distribution Determination Date to be used and any other relevant methodology for calculating such substitute or successor base rate.

(C) Unless otherwise determined by the General Partner, Series B Distributions shall be deemed to have been paid out of deductions from Available Cash with respect to the Quarter ended immediately preceding the Quarter in which the Series B Distribution is made.

(iii) Voting Rights.

(A) Notwithstanding anything to the contrary in this Agreement, the Series B Preferred Units shall not have any voting rights or rights to consent or approve any action or matter, except as set forth in Section 13.3(c), this Section 5.18(b)(iii) or as otherwise required by the Delaware Act.

(B) Notwithstanding anything to the contrary in this Agreement, without the affirmative vote or consent of the holders of at least 66 2/3% of the Outstanding Series B Preferred Units, voting as a separate class, the General Partner shall not adopt any amendment to this Agreement that the General Partner determines would have a material adverse effect on the powers, preferences,

 

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duties, or special rights of the Series B Preferred Units; provided, however, that (1) subject to Section 5.18(b)(iii)(C), the issuance of additional Partnership Securities (and any amendment to this Agreement in connection therewith) shall not be deemed to constitute such a material adverse effect for purposes of this Section 5.18(b)(iii)(B) and

(2) for purposes of this Section 5.18(b)(iii)(B), no amendment of this Agreement in connection with a merger or other transaction in which the Series B Preferred Units remain Outstanding with the terms thereof materially unchanged in any respect adverse to the Series B Holders (as determined by the General Partner) shall be deemed to materially and adversely affect the powers, preferences, duties, or special rights of the Series B Preferred Units.

(C) Notwithstanding anything to the contrary in this Agreement, without the affirmative vote or consent of the holders of at least 66 2/3% of the Outstanding Series B Preferred Units, voting as a class together with holders of any other Series B Parity Securities upon which like voting rights have been conferred and are exercisable, the Partnership shall not (x) create or issue any Series B Parity Securities (including any additional Series B Preferred Units) if the cumulative distributions payable on Outstanding Series B Preferred Units (or any Series B Parity Securities, if the holders of such Series B Parity Securities vote as a class together with the Series B Holders pursuant to this Section 5.18(b)(iii)(C)) are in Arrears or (y) create or issue any Series B Senior Securities.

(D) For any matter described in this Section 5.18(b)(iii) in which the Series B Holders are entitled to vote as a class (whether separately or together with the holders of any Series B Parity Securities), such Series B Holders shall be entitled to one vote per Series B Preferred Unit. Any Series B Preferred Units held by the Partnership or any of its Subsidiaries or their controlled Affiliates shall not be entitled to vote.

(E) Notwithstanding Section 5.18(b)(iii)(B) and Section 5.18(b)(iii)(C), no vote of the Series B Holders shall be required if, at or prior to the time when such action is to take effect, provision is made for the redemption of all Series B Preferred Units at the time Outstanding.

(iv) Optional Redemption; Series B Rating Event.

(A) The Partnership shall have the right (1) at any time, and from time to time, on or after February 15, 2028 or (2) at any time within 120 days after the conclusion of any review or appeal process instituted by the Partnership following the occurrence of a Series B Rating Event, in each case, to redeem the Series B Preferred Units, which redemption may be in whole or in part (except with respect to a redemption pursuant to clause (2) of this Section 5.18(b)(iv)(A) which shall be in whole but not in part), using any source of funds legally available for such purpose. Any such redemption shall occur on a date set by the General Partner (the “Series B Redemption Date”). The Partnership shall effect any such redemption by paying cash for each Series B Preferred Unit to be redeemed equal to 100% (in the case of a redemption described in clause (1) of this Section 5.18(b)(iv)(A)), or 102% (in the case of a redemption described in clause (2) of this Section 5.18(b)(iv)(A)), of the Series B Liquidation Preference for such Series B Preferred Unit on such Series B Redemption Date plus an amount equal to all unpaid Series B Distributions thereon from the date of issuance to, but excluding, the Series B Redemption Date (whether or not such distributions shall have been declared) (the “Series B Redemption Price”). So long as the Series B Preferred Units to be redeemed are held of record by the Depositary or the nominee of the Depositary, the Series B Redemption Price shall be paid by the Paying Agent to the Depositary on the Series B Redemption Date.

(B) The Partnership shall give notice of any redemption by mail, postage prepaid, not less than 15 days and not more than 60 days before the scheduled Series B Redemption Date to the Series B Holders (as of 5:00 p.m. New York City time on the Business Day next preceding the day on which notice is given) of any Series B Preferred Units to be redeemed as such Series B Holders’ names appear on the books of the Transfer Agent and at the address of such Series B

 

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Holders shown therein. Such notice (the “Series B Redemption Notice”) shall state, as applicable: (1) the Series B Redemption Date, (2) the number of Series B Preferred Units to be redeemed and, if less than all Outstanding Series B Preferred Units are to be redeemed, the number (and in the case of Series B Preferred Units in certificated form, the identification) of Series B Preferred Units to be redeemed from such Series B Holder, (3) the Series B Redemption Price, (4) the place where any Series B Preferred Units in certificated form are to be redeemed and shall be presented and surrendered for payment of the Series B Redemption Price therefor (which shall occur automatically if the Certificate representing such Series B Preferred Units is issued in the name of the Depositary or its nominee), and (5) that distributions on the Series B Preferred Units to be redeemed shall cease to accumulate from and after such Series B Redemption Date.

(C) If the Partnership elects to redeem less than all of the Outstanding Series B Preferred Units, the number of Series B Preferred Units to be redeemed shall be determined by the General Partner, and such Series B Preferred Units shall be redeemed by such method of selection as the Depositary shall determine, either Pro Rata or by lot, with adjustments to avoid redemption of fractional Series B Preferred Units. The aggregate Series B Redemption Price for any such partial redemption of the Outstanding Series B Preferred Units shall be allocated correspondingly among the redeemed Series B Preferred Units. The Series B Preferred Units not redeemed shall remain Outstanding and entitled to all the rights, preferences and duties provided in this Section 5.18.

(D) If the Partnership gives or causes to be given a Series B Redemption Notice, the Partnership shall deposit with the Paying Agent funds sufficient to redeem the Series B Preferred Units as to which such Series B Redemption Notice shall have been given, no later than 10:00 a.m. New York City time on the Series B Redemption Date, and shall give the Paying Agent irrevocable instructions and authority to pay the Series B Redemption Price to each Series B Holder whose Series B Preferred Units are to be redeemed upon surrender or deemed surrender (which shall occur automatically if the Certificate representing such Series B Preferred Units is issued in the name of the Depositary or its nominee) of the Certificates therefor as set forth in the Series B Redemption Notice. If a Series B Redemption Notice shall have been given, from and after the Series B Redemption Date, unless the Partnership defaults in providing funds sufficient for such redemption at the time and place specified for payment pursuant to the Series B Redemption Notice, all Series B Distributions on such Series B Preferred Units to be redeemed shall cease to accumulate and all rights of holders of such Series B Preferred Units as Limited Partners with respect to such Series B Preferred Units to be redeemed shall cease, except the right to receive the Series B Redemption Price, and such Series B Preferred Units shall not thereafter be transferred on the books of the Transfer Agent or be deemed to be Outstanding for any purpose whatsoever. The Series B Holders shall have no claim to the interest income, if any, earned on funds deposited with the Paying Agent.

Any funds deposited with the Paying Agent hereunder by the Partnership for any reason, including redemption of Series B Preferred Units, that remain unclaimed or unpaid after one year after the applicable Series B Redemption Date or other payment date, as applicable, shall be, to the extent permitted by law, repaid to the Partnership upon its written request, after which repayment the Series B Holders entitled to such redemption or other payment shall have recourse only to the Partnership. Notwithstanding any Series B Redemption Notice, there shall be no redemption of any Series B Preferred Units called for redemption until funds sufficient to pay the full Series B Redemption Price of such Series B Preferred Units shall have been deposited by the Partnership with the Paying Agent.

(E) Any Series B Preferred Units that are redeemed or otherwise acquired by the Partnership shall be cancelled. If only a portion of the Series B Preferred Units represented by a Certificate shall have been called for redemption, upon surrender of the Certificate to the Paying Agent (which shall occur automatically if the Certificate representing such Series B Preferred Units is registered in the name of the Depositary or its nominee), the Partnership shall issue and the Paying

 

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Agent shall deliver to the Series B Holders a new Certificate (or adjust the applicable book-entry account) representing the number of Series B Preferred Units represented by the surrendered Certificate that have not been called for redemption.

(F) Notwithstanding anything to the contrary in this Section 5.18, in the event that full cumulative distributions on the Series B Preferred Units and any Series B Parity Securities shall not have been paid or declared and set aside for payment, the Partnership shall not be permitted to repurchase, redeem or otherwise acquire, in whole or in part, any Series B Preferred Units or Series B Parity Securities except pursuant to a purchase or exchange offer made on the same relative terms to all Series B Holders and holders of any Series B Parity Securities. Subject to Section 4.9, so long as any Series B Preferred Units are Outstanding, the Partnership shall not be permitted to redeem, repurchase or otherwise acquire any Common Units or any other Series B Junior Securities unless full cumulative distributions on the Series B Preferred Units and any Series B Parity Securities for all prior and the then-ending Series B Distribution Periods, with respect to the Series B Preferred Units, and all prior and then ending distribution periods, with respect to any such Series B Parity Securities, shall have been paid or declared and set aside for payment.

(v) Liquidation Rights. In the event of the dissolution and winding up of the Partnership under Section 12.4 or a sale, exchange, or other disposition of all or substantially all of the assets of the Partnership, either voluntary or involuntary, the Record Holders of the Series B Preferred Units shall be entitled to receive, out of the assets of the Partnership available for distribution to the Partners or any Assignees, prior and in preference to any distribution of any assets of the Partnership to the Record Holders of any other class or series of Partnership Interests (other than Series B Senior Securities or Series B Parity Securities), (A) first, any accumulated and unpaid distributions on the Series B Preferred Units (regardless of whether previously declared) and (B) then, any positive value in each such holder’s Capital Account in respect of such Series B Preferred Units. If in the year of such dissolution and winding up, or sale, exchange, or other disposition of all or substantially all of the assets of the Partnership, any such Record Holder’s Capital Account in respect of such Series B Preferred Units is less than the aggregate Series B Base Liquidation Preference of such Series B Preferred Units, then, notwithstanding anything to the contrary contained in this Agreement, and prior to any other allocation pursuant to this Agreement for such year and any distribution pursuant to the preceding sentence (other than any allocations or distributions made with respect to any other Series B Parity Securities upon which like allocation and distribution rights have been conferred), items of gross income and gain shall be allocated to all Unitholders then holding Series B Preferred Units, Pro Rata, until the Capital Account in respect of each Outstanding Series B Preferred Unit is equal to the Series B Base Liquidation Preference (and no other allocation pursuant to this Agreement shall reverse the effect of such allocation); provided, however, that in the event that like allocation rights have been conferred upon other Series B Parity Securities (including pursuant to Sections 5.17(b)(v), 5.19(b)(v), 5.20(b)(v), 5.21(b)(v), 5.22(b)(v) and 5.23(b)(v)), then items of gross income and gain shall be allocated to all Unitholders then holding Series B Preferred Units and such Series B Parity Securities, Pro Rata, until the Capital Account in respect of each Outstanding Series B Preferred Unit and such Series B Parity Security is equal to the applicable liquidation preference (and no other allocation pursuant to this Agreement shall reverse the effect of such allocation). If in the year of such dissolution and winding up any such Record Holder’s Capital Account in respect of such Series B Preferred Units is less than the aggregate Series B Base Liquidation Preference of such Series B Preferred Units after the application of the preceding sentence, then to the extent permitted by applicable law, but otherwise notwithstanding anything to the contrary contained in this Agreement, items of gross income and gain for any preceding taxable year(s) with respect to which IRS Form 1065 Schedules K-1 have not been filed by the Partnership shall be reallocated to all Unitholders then holding Series B Preferred Units, Pro Rata, until the Capital Account in respect of each such Outstanding Series B Preferred Unit after making allocations pursuant to this and the immediately preceding sentence is equal to the Series B Base Liquidation Preference (and no other allocation pursuant to this Agreement shall reverse the

 

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effect of such allocation); provided, however, that in the event like allocation rights have been conferred upon other Series B Parity Securities (including pursuant to Sections 5.17(b)(v), 5.19(b)(v), 5.20(b)(v), 5.21(b)(v), 5.22(b)(v) and 5.23(b)(v)), then any such items of gross income and gain shall be reallocated to all Unitholders then holding Series B Preferred Units and such Series B Parity Securities, Pro Rata, until the Capital Account in respect of each Outstanding Series B Preferred Unit and such Series B Parity Security after making allocations pursuant to this and the immediately preceding sentence is equal to the applicable liquidation preference (and no other allocation pursuant to this Agreement shall reverse the effect of such allocation). After such allocations have been made to the Outstanding Series B Preferred Units, and any Series B Parity Securities, as applicable, any remaining Net Termination Gain or Net Termination Loss shall be allocated to the Partners pursuant to Section 6.1(c) or Section 6.1(d), as the case may be. At the time of the dissolution of the Partnership, subject to Section 17-804 of the Delaware Act, the Record Holders of the Series B Preferred Units shall become entitled to receive any distributions in respect of the Series B Preferred Units that are accrued and unpaid as of the date of such distribution, and shall have the status of, and shall be entitled to all remedies available to, a creditor of the Partnership, and such entitlement of the Record Holders of the Series B Preferred Units to such accrued and unpaid distributions shall have priority over any entitlement of any other Partners or Assignees (other than holders of any Series B Senior Securities or Series B Parity Securities) with respect to any distributions by the Partnership to such other Partners or Assignees; provided, however, that the General Partner, as such, will have no liability for any obligations with respect to such distributions to any Record Holder(s) of Series B Preferred Units.

(vi) Rank. The Series B Preferred Units shall each be deemed to rank as to distributions on such Partnership Securities and distributions upon liquidation of the Partnership:

(A) senior to any Series B Junior Securities;

(B) on a parity with any Series B Parity Securities;

(C) junior to any Series B Senior Securities; and

(D) junior to all existing and future indebtedness of the Partnership and other liabilities with respect to assets available to satisfy claims against the Partnership.

(vii) No Sinking Fund. The Series B Preferred Units shall not have the benefit of any sinking fund.

(viii) Record Holders. To the fullest extent permitted by applicable law, the General Partner, the Partnership, the Transfer Agent, and the Paying Agent may deem and treat any Series B Holder as the true, lawful, and absolute owner of the applicable Series B Preferred Units for all purposes, and none of the General Partner, the Partnership, the Transfer Agent or the Paying Agent shall be affected by any notice to the contrary, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which the Series B Preferred Units may be listed or admitted to trading, if any.

(ix) Other Rights; Fiduciary Duties. The Series B Preferred Units and the Series B Holders shall not have any designations, preferences, rights, powers or duties, other than as set forth in this Agreement or as provided by applicable law. Notwithstanding anything to the contrary in this Agreement or any duty existing at law, in equity or otherwise, to the fullest extent permitted by applicable law, neither the General Partner nor any other Indemnitee shall owe any duties, including fiduciary duties, or have any liabilities to Series B Holders, other than the implied contractual covenant of good faith and fair dealing.

“Section 5.19 Establishment of Series C Preferred Units.

(a) General. The Partnership hereby designates and creates a class of Partnership Securities to be designated as “7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units” (the “Series C Preferred Units”), having the preferences, rights, powers, and duties set forth herein, including this Section 5.19. Each Series C Preferred Unit shall be identical in all respects to every other

 

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Series C Preferred Unit, except as to the respective dates from which the Series C Liquidation Preference shall increase or from which Series C Distributions may begin accruing, to the extent such dates may differ. The Series C Preferred Units represent perpetual equity interests in the Partnership and shall not give rise to a claim by the Partnership or a Series C Holder for conversion or, except as set forth in Section 5.19(b)(iv), redemption thereof at a particular date.

(b) Rights of Series C Preferred Units. The Series C Preferred Units shall have the following rights, preferences and privileges and shall be subject to the following duties and obligations:

(i) Series C Preferred Units.

(A) The authorized number of Series C Preferred Units shall be unlimited. Series C Preferred Units that are purchased or otherwise acquired by the Partnership shall be cancelled.

(B) The Series C Preferred Units shall be represented by one or more global Certificates registered in the name of the Depositary or its nominee, and no Series C Holder shall be entitled to receive a definitive Certificate evidencing its Series C Preferred Units, unless (1) requested by a Series C Holder and consented to by the General Partner in its sole discretion, (2) otherwise required by law or (3) the Depositary gives notice of its intention to resign or is no longer eligible to act as such with respect to the Series C Preferred Units and the General Partner shall have not selected a substitute Depositary within 60 calendar days thereafter. So long as the Depositary shall have been appointed and is serving with respect to the Series C Preferred Units, payments and communications made by the Partnership to Series C Holders shall be made by making payments to, and communicating with, the Depositary.

(ii) Distributions.

(A) Distributions on each Outstanding Series C Preferred Unit shall be cumulative and shall accumulate at the applicable Series C Distribution Rate from and including [ ● ], 2021 (or, for any subsequently issued and newly Outstanding Series C Preferred Units, from and including the Series C Distribution Payment Date immediately preceding the issue date of such Series C Preferred Units) until such time as the Partnership pays the Series C Distribution or redeems such Series C Preferred Unit in accordance with Section 5.19(b)(iv), whether or not such Series C Distributions shall have been declared. Series C Holders shall be entitled to receive Series C Distributions from time to time out of any assets of the Partnership legally available for the payment of distributions at the Series C Distribution Rate per Series C Preferred Unit when, as, and, if declared by the General Partner. Series C Distributions, to the extent declared by the General Partner to be paid by the Partnership in accordance with this Section 5.19(b)(ii), shall be paid, in Arrears, on each Series C Distribution Payment Date. Series C Distributions shall accumulate in each Series C Distribution Period from and including the preceding Series C Distribution Payment Date (other than the initial Series C Distribution Period, which shall commence on and include [ ● ], 2021), to, but excluding, the next Series C Distribution Payment Date for such Series C Distribution Period; provided that distributions shall accrue on accumulated but unpaid Series C Distributions at the Series C Distribution Rate. If any Series C Distribution Payment Date otherwise would occur on a date that is not a Business Day, declared Series C Distributions shall be paid on the immediately succeeding Business Day without the accumulation of additional distributions. During the Series C Fixed Rate Period, Series C Distributions shall be payable based on a 360-day year consisting of twelve 30 day months. During the Series C Floating Rate Period, Series C Distributions shall be computed by multiplying the Series C Distribution Rate by a fraction, the numerator of which will be the actual number of days elapsed during that Series C Distribution Period (determined by including the first day of such Series C Distribution Period and excluding the last day, which is the Series C Distribution Payment Date), and the denominator of which will be 360, and by multiplying the result by the aggregate Series C Liquidation Preference of all Outstanding Series C Preferred Units. All Series C Distributions that are (1) accumulated and unpaid or (2) payable by the Partnership

 

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pursuant to this Section 5.19(b)(ii) shall be payable without regard to income of the Partnership and shall be treated for federal income tax purposes as guaranteed payments for the use of capital under Section 707(c) of the Code. The guaranteed payment with respect to any Series C Distribution Period shall be for the account of the holders of Series C Preferred Units as of the applicable Series C Distribution Record Date.

(B) Not later than 5:00 p.m., New York City time, on each Series C Distribution Payment Date, the Partnership shall pay those Series C Distributions, if any, that shall have been declared by the General Partner to Series C Holders on the Record Date for the applicable Series C Distribution. The Record Date (the “Series C Distribution Record Date”) for the payment of any Series C Distributions shall be as of the close of business on the first Business Day of the month of the applicable Series C Distribution Payment Date, except that in the case of payments of Series C Distributions in Arrears, the Series C Distribution Record Date with respect to a Series C Distribution Payment Date shall be such date as may be designated by the General Partner in accordance with this Section 5.19. So long as any Series C Preferred Units are Outstanding, no distribution shall be declared or paid or set aside for payment on any Series C Junior Securities (other than a distribution payable solely in Series C Junior Securities) unless full cumulative Series C Distributions have been or contemporaneously are being paid or set apart for payment on all Outstanding Series C Preferred Units (and distributions on any other Series C Parity Securities) through the most recent respective Series C Distribution Payment Date (and distribution payment date with respect to such Series C Parity Securities, if any); provided, however, notwithstanding anything to the contrary in this Section 5.19(b)(ii)(B), if a distribution period with respect to a class of Series C Junior Securities or Series C Parity Securities is shorter than the Series C Distribution Period, the General Partner may declare and pay regular distributions with respect to such Series C Junior Securities or Series C Parity Securities, so long as, at the time of declaration of such distribution, (1) there are no Series C Distributions in Arrears, and (2) the General Partner expects to have sufficient funds to pay the full distribution in respect of the Series C Preferred Units on the next successive Series C Distribution Payment Date. Accumulated Series C Distributions in Arrears for any past Series C Distribution Period may be declared by the General Partner and paid on any date fixed by the General Partner, whether or not a Series C Distribution Payment Date, to Series C Holders on the Record Date for such payment, which may not be less than 10 days before such payment date. Subject to the next succeeding sentence, if all accumulated Series C Distributions in Arrears on all Outstanding Series C Preferred Units and all accumulated distributions in arrears on any Series C Parity Securities shall not have been declared and paid, or if sufficient funds for the payment thereof shall not have been set apart, payment of accumulated distributions in Arrears on the Series C Preferred Units and accumulated distributions in arrears on any such Series C Parity Securities shall be made in order of their respective distribution payment dates, commencing with the earliest distribution payment date. If less than all distributions payable with respect to all Series C Preferred Units and any other Series C Parity Securities are paid, any partial payment shall be made Pro Rata with respect to the Series C Preferred Units and any such other Series C Parity Securities entitled to a distribution payment at such time in proportion to the aggregate distribution amounts remaining due in respect of such Series C Preferred Units and such other Series C Parity Securities at such time. Subject to Section 12.4 and Section 5.19(b)(v), Series C Holders shall not be entitled to any distribution, whether payable in cash, property or Partnership Securities, in excess of full cumulative Series C Distributions. Except insofar as distributions accrue on the amount of any accumulated and unpaid Series C Distributions as described in Section 5.19(b)(ii)(A), no interest or sum of money in lieu of interest shall be payable in respect of any distribution payment which may be in Arrears on the Series C Preferred Units. So long as the Series C Preferred Units are held of record by the Depositary or its nominee, declared Series C Distributions shall be paid to the Depositary in same-day funds on each Series C Distribution Payment Date or other distribution payment date in the case of payments for Series C Distributions in Arrears.

 

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(C) The Series C Distribution Rate for each Series C Distribution Period in the Series C Floating Rate Period will be determined by the Calculation Agent using Three-Month LIBOR as in effect on the Distribution Determination Date for such Series C Distribution Period. The Calculation Agent then will add the spread of 4.530% per annum to Three-Month LIBOR as determined on the applicable Distribution Determination Date.

Notwithstanding the foregoing:

(A) If the Calculation Agent determines on the relevant Distribution Determination Date that the LIBOR base rate has been discontinued, then the Calculation Agent will use a substitute or successor base rate that it has determined in its sole discretion is most comparable to the LIBOR base rate, provided that if the Calculation Agent determines there is an industry-accepted substitute or successor base rate, then the Calculation Agent shall use such substitute or successor base rate.

(B) If the Calculation Agent has determined a substitute or successor base rate in accordance with the foregoing, the Calculation Agent in its sole discretion may determine what business day convention to use, the definition of business day, the Distribution Determination Date to be used and any other relevant methodology for calculating such substitute or successor base rate.

(C) Unless otherwise determined by the General Partner, Series C Distributions shall be deemed to have been paid out of deductions from Available Cash with respect to the Quarter ended immediately preceding the Quarter in which the Series C Distribution is made.

(iii) Voting Rights.

(A) Notwithstanding anything to the contrary in this Agreement, the Series C Preferred Units shall not have any voting rights or rights to consent or approve any action or matter, except as set forth in Section 13.3(c), this Section 5.19(b)(iii) or as otherwise required by the Delaware Act.

(B) Notwithstanding anything to the contrary in this Agreement, without the affirmative vote or consent of the holders of at least 66 2/3% of the Outstanding Series C Preferred Units, voting as a separate class, the General Partner shall not adopt any amendment to this Agreement that the General Partner determines would have a material adverse effect on the powers, preferences, duties, or special rights of the Series C Preferred Units; provided, however, that (1) subject to Section 5.19(b)(iii)(C), the issuance of additional Partnership Securities (and any amendment to this Agreement in connection therewith) shall not be deemed to constitute such a material adverse effect for purposes of this Section 5.19(b)(iii)(B) and (2) for purposes of this Section 5.19(b)(iii)(B), no amendment of this Agreement in connection with a merger or other transaction in which the Series C Preferred Units remain Outstanding with the terms thereof materially unchanged in any respect adverse to the Series C Holders (as determined by the General Partner) shall be deemed to materially and adversely affect the powers, preferences, duties, or special rights of the Series C Preferred Units.

(C) Notwithstanding anything to the contrary in this Agreement, without the affirmative vote or consent of the holders of at least 66 2/3% of the Outstanding Series C Preferred Units, voting as a class together with holders of any other Series C Parity Securities upon which like voting rights have been conferred and are exercisable, the Partnership shall not (x) create or issue any Series C Parity Securities (including any additional Series C Preferred Units) if the cumulative distributions payable on Outstanding Series C Preferred Units (or any Series C Parity Securities, if the holders of such Series C Parity Securities vote as a class together with the Series C Holders pursuant to this Section 5.19(b)(iii)(C)) are in Arrears or (y) create or issue any Series C Senior Securities.

(D) For any matter described in this Section 5.19(b)(iii) in which the Series C Holders are entitled to vote as a class (whether separately or together with the holders of any Series C Parity

 

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Securities), such Series C Holders shall be entitled to one vote per Series C Preferred Unit. Any Series C Preferred Units held by the Partnership or any of its Subsidiaries or their controlled Affiliates shall not be entitled to vote.

(E) Notwithstanding Sections 5.19(b)(iii)(B) and 5.19(b)(iii)(C), no vote of the Series C Holders shall be required if, at or prior to the time when such action is to take effect, provision is made for the redemption of all Series C Preferred Units at the time Outstanding.

(iv) Optional Redemption; Series C Rating Event.

(A) The Partnership shall have the right (1) at any time, and from time to time, on or after May 15, 2023 or (2) at any time within 120 days after the conclusion of any review or appeal process instituted by the Partnership following the occurrence of a Series C Rating Event, in each case, to redeem the Series C Preferred Units, which redemption may be in whole or in part (except with respect to a redemption pursuant to clause (2) of this Section 5.19(b)(iv)(A) which shall be in whole but not in part), using any source of funds legally available for such purpose. Any such redemption shall occur on a date set by the General Partner (the “Series C Redemption Date”). The Partnership shall effect any such redemption by paying cash for each Series C Preferred Unit to be redeemed equal to 100% (in the case of a redemption described in clause (1) of this Section 5.19(b)(iv)(A)), or 102% (in the case of a redemption described in clause (2) of this Section 5.19(b)(iv)(A)), of the Series C Liquidation Preference for such Series C Preferred Unit on such Series C Redemption Date plus an amount equal to all unpaid Series C Distributions thereon from the date of issuance to, but excluding, the Series C Redemption Date (whether or not such distributions shall have been declared) (the “Series C Redemption Price”). So long as the Series C Preferred Units to be redeemed are held of record by the Depositary or the nominee of the Depositary, the Series C Redemption Price shall be paid by the Paying Agent to the Depositary on the Series C Redemption Date.

(B) The Partnership shall give notice of any redemption by mail, postage prepaid, not less than 30 days and not more than 60 days before the scheduled Series C Redemption Date to the Series C Holders (as of 5:00 p.m. New York City time on the Business Day next preceding the day on which notice is given) of any Series C Preferred Units to be redeemed as such Series C Holders’ names appear on the books of the Transfer Agent and at the address of such Series C Holders shown therein. Such notice (the “Series C Redemption Notice”) shall state, as applicable: (1) the Series C Redemption Date, (2) the number of Series C Preferred Units to be redeemed and, if less than all Outstanding Series C Preferred Units are to be redeemed, the number (and in the case of Series C Preferred Units in certificated form, the identification) of Series C Preferred Units to be redeemed from such Series C Holder, (3) the Series C Redemption Price, (4) the place where any Series C Preferred Units in certificated form are to be redeemed and shall be presented and surrendered for payment of the Series C Redemption Price therefor (which shall occur automatically if the Certificate representing such Series C Preferred Units is issued in the name of the Depositary or its nominee), and (5) that distributions on the Series C Preferred Units to be redeemed shall cease to accumulate from and after such Series C Redemption Date.

(C) If the Partnership elects to redeem less than all of the Outstanding Series C Preferred Units, the number of Series C Preferred Units to be redeemed shall be determined by the General Partner, and such Series C Preferred Units shall be redeemed by such method of selection as the Depositary shall determine, either Pro Rata or by lot, with adjustments to avoid redemption of fractional Series C Preferred Units. The aggregate Series C Redemption Price for any such partial redemption of the Outstanding Series C Preferred Units shall be allocated correspondingly among the redeemed Series C Preferred Units. The Series C Preferred Units not redeemed shall remain Outstanding and entitled to all the rights, preferences and duties provided in this Section 5.19.

(D) If the Partnership gives or causes to be given a Series C Redemption Notice, the Partnership shall deposit with the Paying Agent funds sufficient to redeem the Series C Preferred

 

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Units as to which such Series C Redemption Notice shall have been given, no later than 10:00 a.m. New York City time on the Series C Redemption Date, and shall give the Paying Agent irrevocable instructions and authority to pay the Series C Redemption Price to each Series C Holder whose Series C Preferred Units are to be redeemed upon surrender or deemed surrender (which shall occur automatically if the Certificate representing such Series C Preferred Units is issued in the name of the Depositary or its nominee) of the Certificates therefor as set forth in the Series C Redemption Notice. If a Series C Redemption Notice shall have been given, from and after the Series C Redemption Date, unless the Partnership defaults in providing funds sufficient for such redemption at the time and place specified for payment pursuant to the Series C Redemption Notice, all Series C Distributions on such Series C Preferred Units to be redeemed shall cease to accumulate and all rights of holders of such Series C Preferred Units as Limited Partners with respect to such Series C Preferred Units to be redeemed shall cease, except the right to receive the Series C Redemption Price, and such Series C Preferred Units shall not thereafter be transferred on the books of the Transfer Agent or be deemed to be Outstanding for any purpose whatsoever. The Series C Holders shall have no claim to the interest income, if any, earned on funds deposited with the Paying Agent. Any funds deposited with the Paying Agent hereunder by the Partnership for any reason, including redemption of Series C Preferred Units, that remain unclaimed or unpaid after one year after the applicable Series C Redemption Date or other payment date, as applicable, shall be, to the extent permitted by law, repaid to the Partnership upon its written request, after which repayment the Series C Holders entitled to such redemption or other payment shall have recourse only to the Partnership. Notwithstanding any Series C Redemption Notice, there shall be no redemption of any Series C Preferred Units called for redemption until funds sufficient to pay the full Series C Redemption Price of such Series C Preferred Units shall have been deposited by the Partnership with the Paying Agent.

(E) Any Series C Preferred Units that are redeemed or otherwise acquired by the Partnership shall be cancelled. If only a portion of the Series C Preferred Units represented by a Certificate shall have been called for redemption, upon surrender of the Certificate to the Paying Agent (which shall occur automatically if the Certificate representing such Series C Preferred Units is registered in the name of the Depositary or its nominee), the Partnership shall issue and the Paying Agent shall deliver to the Series C Holders a new Certificate (or adjust the applicable book-entry account) representing the number of Series C Preferred Units represented by the surrendered Certificate that have not been called for redemption.

(F) Notwithstanding anything to the contrary in this Section 5.19, in the event that full cumulative distributions on the Series C Preferred Units and any Series C Parity Securities shall not have been paid or declared and set aside for payment, the Partnership shall not be permitted to repurchase, redeem or otherwise acquire, in whole or in part, any Series C Preferred Units or Series C Parity Securities except pursuant to a purchase or exchange offer made on the same relative terms to all Series C Holders and holders of any Series C Parity Securities. Subject to Section 4.9, so long as any Series C Preferred Units are Outstanding, the Partnership shall not be permitted to redeem, repurchase or otherwise acquire any Common Units or any other Series C Junior Securities unless full cumulative distributions on the Series C Preferred Units and any Series C Parity Securities for all prior and the then-ending Series C Distribution Periods, with respect to the Series C Preferred Units, and all prior and then ending distribution periods, with respect to any such Series C Parity Securities, shall have been paid or declared and set aside for payment.

(v) Liquidation Rights. In the event of the dissolution and winding up of the Partnership under Section 12.4 or a sale, exchange, or other disposition of all or substantially all of the assets of the Partnership, either voluntary or involuntary, the Record Holders of the Series C Preferred Units shall be entitled to receive, out of the assets of the Partnership available for distribution to the Partners or any Assignees, prior and in preference to any distribution of any assets of the Partnership to the Record

 

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Holders of any other class or series of Partnership Interests (other than Series C Senior Securities or Series C Parity Securities), (1) first, any accumulated and unpaid distributions on the Series C Preferred Units (regardless of whether previously declared) and (2) then, any positive value in each such holder’s Capital Account in respect of such Series C Preferred Units. If in the year of such dissolution and winding up, or sale, exchange, or other disposition of all or substantially all of the assets of the Partnership, any such Record Holder’s Capital Account in respect of such Series C Preferred Units is less than the aggregate Series C Base Liquidation Preference of such Series C Preferred Units, then, notwithstanding anything to the contrary contained in this Agreement, and prior to any other allocation pursuant to this Agreement for such year and any distribution pursuant to the preceding sentence (other than any allocations or distributions made with respect to any other Series C Parity Securities upon which like allocation and distribution rights have been conferred), items of gross income and gain shall be allocated to all Unitholders then holding Series C Preferred Units, Pro Rata, until the Capital Account in respect of each Outstanding Series C Preferred Unit is equal to the Series C Base Liquidation Preference (and no other allocation pursuant to this Agreement shall reverse the effect of such allocation); provided, however, that in the event that like allocation rights have been conferred upon other Series C Parity Securities (including pursuant to Sections 5.17(b)(v), 5.18(b)(v), 5.20(b)(v), 5.21(b)(v), 5.22(b)(v) and 5.23(b)(v)), then items of gross income and gain shall be allocated to all Unitholders then holding Series C Preferred Units and such Series C Parity Securities, Pro Rata, until the Capital Account in respect of each Outstanding Series C Preferred Unit and such Series C Parity Security is equal to the applicable liquidation preference (and no other allocation pursuant to this Agreement shall reverse the effect of such allocation). If in the year of such dissolution and winding up any such Record Holder’s Capital Account in respect of such Series C Preferred Units is less than the aggregate Series C Base Liquidation Preference of such Series C Preferred Units after the application of the preceding sentence, then to the extent permitted by applicable law, but otherwise notwithstanding anything to the contrary contained in this Agreement, items of gross income and gain for any preceding taxable year(s) with respect to which IRS Form 1065 Schedules K-1 have not been filed by the Partnership shall be reallocated to all Unitholders then holding Series C Preferred Units, Pro Rata, until the Capital Account in respect of each such Outstanding Series C Preferred Unit after making allocations pursuant to this and the immediately preceding sentence is equal to the Series C Base Liquidation Preference (and no other allocation pursuant to this Agreement shall reverse the effect of such allocation); provided, however, that in the event like allocation rights have been conferred upon other Series C Parity Securities (including pursuant to Sections 5.17(b)(v), 5.18(b)(v), 5.20(b)(v), 5.21(b)(v), 5.22(b)(v) and 5.23(b)(v)), then any such items of gross income and gain shall be reallocated to all Unitholders then holding Series C Preferred Units and such Series C Parity Securities, Pro Rata, until the Capital Account in respect of each Outstanding Series C Preferred Unit and such Series C Parity Security after making allocations pursuant to this and the immediately preceding sentence is equal to the applicable liquidation preference (and no other allocation pursuant to this Agreement shall reverse the effect of such allocation). After such allocations have been made to the Outstanding Series C Preferred Units and any Series C Parity Securities, as applicable, any remaining Net Termination Gain or Net Termination Loss shall be allocated to the Partners pursuant to Section 6.1(c) or Section 6.1(d), as the case may be. At the time of the dissolution of the Partnership, subject to Section 17-804 of the Delaware Act, the Record Holders of the Series C Preferred Units shall become entitled to receive any distributions in respect of the Series C Preferred Units that are accrued and unpaid as of the date of such distribution, and shall have the status of, and shall be entitled to all remedies available to, a creditor of the Partnership, and such entitlement of the Record Holders of the Series C Preferred Units to such accrued and unpaid distributions shall have priority over any entitlement of any other Partners or Assignees (other than holders of any Series C Senior Securities or Series C Parity Securities) with respect to any distributions by the Partnership to such other Partners or Assignees; provided, however, that the General Partner, as such, will have no liability for any obligations with respect to such distributions to any Record Holder(s) of Series C Preferred Units.

 

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(vi) Rank. The Series C Preferred Units shall each be deemed to rank as to distributions on such Partnership Securities and distributions upon liquidation of the Partnership:

(A) senior to any Series C Junior Securities;

(B) on a parity with any Series C Parity Securities;

(C) junior to any Series C Senior Securities; and

(D) junior to all existing and future indebtedness of the Partnership and other liabilities with respect to assets available to satisfy claims against the Partnership.

(vii) No Sinking Fund. The Series C Preferred Units shall not have the benefit of any sinking fund.

(viii) Record Holders. To the fullest extent permitted by applicable law, the General Partner, the Partnership, the Transfer Agent, and the Paying Agent may deem and treat any Series C Holder as the true, lawful, and absolute owner of the applicable Series C Preferred Units for all purposes, and none of the General Partner, the Partnership, the Transfer Agent or the Paying Agent shall be affected by any notice to the contrary, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which the Series C Preferred Units may be listed or admitted to trading, if any.

(ix) Other Rights; Fiduciary Duties. The Series C Preferred Units and the Series C Holders shall not have any designations, preferences, rights, powers or duties, other than as set forth in this Agreement or as provided by applicable law. Notwithstanding anything to the contrary in this Agreement or any duty existing at law, in equity or otherwise, to the fullest extent permitted by applicable law, neither the General Partner nor any other Indemnitee shall owe any duties, including fiduciary duties, or have any liabilities to Series C Holders, other than the implied contractual covenant of good faith and fair dealing.

“Section 5.20 Establishment of Series D Preferred Units.

(a) General. The Partnership hereby designates and creates a class of Partnership Securities to be designated as “7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units” (the “Series D Preferred Units”), having the preferences, rights, powers, and duties set forth herein, including this Section 5.20. Each Series D Preferred Unit shall be identical in all respects to every other Series D Preferred Unit, except as to the respective dates from which the Series D Liquidation Preference shall increase or from which Series D Distributions may begin accruing, to the extent such dates may differ. The Series D Preferred Units represent perpetual equity interests in the Partnership and shall not give rise to a claim by the Partnership or a Series D Holder for conversion or, except as set forth in Section 5.20(b)(iv), redemption thereof at a particular date.

(b) Rights of Series D Preferred Units. The Series D Preferred Units shall have the following rights, preferences and privileges and shall be subject to the following duties and obligations:

(i) Series D Preferred Units.

(A) The authorized number of Series D Preferred Units shall be unlimited. Series D Preferred Units that are purchased or otherwise acquired by the Partnership shall be cancelled.

(B) The Series D Preferred Units shall be represented by one or more global Certificates registered in the name of the Depositary or its nominee, and no Series D Holder shall be entitled to receive a definitive Certificate evidencing its Series D Preferred Units, unless (1) requested by a Series D Holder and consented to by the General Partner in its sole discretion, (2) otherwise required by law or (3) the Depositary gives notice of its intention to resign or is no longer eligible to act as such with respect to the Series D Preferred Units and the General Partner shall have not selected a substitute Depositary within 60 calendar days thereafter. So long as the Depositary shall have been appointed and is serving with respect to the Series D Preferred Units, payments and

 

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communications made by the Partnership to Series D Holders shall be made by making payments to, and communicating with, the Depositary.

(ii) Distributions.

(A) Distributions on each Outstanding Series D Preferred Unit shall be cumulative and shall accumulate at the applicable Series D Distribution Rate from and including [ ● ], 2021 (or, for any subsequently issued and newly Outstanding Series D Preferred Units, from and including the Series D Distribution Payment Date immediately preceding the issue date of such Series D Preferred Units) until such time as the Partnership pays the Series D Distribution or redeems such Series D Preferred Unit in accordance with Section 5.20(b)(iv), whether or not such Series D Distributions shall have been declared. Series D Holders shall be entitled to receive Series D Distributions from time to time out of any assets of the Partnership legally available for the payment of distributions at the Series D Distribution Rate per Series D Preferred Unit when, as, and, if declared by the General Partner. Series D Distributions, to the extent declared by the General Partner to be paid by the Partnership in accordance with this Section 5.20(b)(ii), shall be paid, in Arrears, on each Series D Distribution Payment Date. Series D Distributions shall accumulate in each Series D Distribution Period from and including the preceding Series D Distribution Payment Date (other than the initial Series D Distribution Period, which shall commence on and include [ ● ], 2021), to, but excluding, the next Series D Distribution Payment Date for such Series D Distribution Period; provided that distributions shall accrue on accumulated but unpaid Series D Distributions at the Series D Distribution Rate. If any Series D Distribution Payment Date otherwise would occur on a date that is not a Business Day, declared Series D Distributions shall be paid on the immediately succeeding Business Day without the accumulation of additional distributions. During the Series D Fixed Rate Period, Series D Distributions shall be payable based on a 360-day year consisting of twelve 30 day months. During the Series D Floating Rate Period, Series D Distributions shall be computed by multiplying the Series D Distribution Rate by a fraction, the numerator of which will be the actual number of days elapsed during that Series D Distribution Period (determined by including the first day of such Series D Distribution Period and excluding the last day, which is the Series D Distribution Payment Date), and the denominator of which will be 360, and by multiplying the result by the aggregate Series D Liquidation Preference of all Outstanding Series D Preferred Units. All Series D Distributions that are (1) accumulated and unpaid or (2) payable by the Partnership pursuant to this Section 5.20(b)(ii) shall be payable without regard to income of the Partnership and shall be treated for federal income tax purposes as guaranteed payments for the use of capital under Section 707(c) of the Code. The guaranteed payment with respect to any Series D Distribution Period shall be for the account of the holders of Series D Preferred Units as of the applicable Series D Distribution Record Date.

(B) Not later than 5:00 p.m., New York City time, on each Series D Distribution Payment Date, the Partnership shall pay those Series D Distributions, if any, that shall have been declared by the General Partner to Series D Holders on the Record Date for the applicable Series D Distribution. The Record Date (the “Series D Distribution Record Date”) for the payment of any Series D Distributions shall be as of the close of business on the first Business Day of the month of the applicable Series D Distribution Payment Date, except that in the case of payments of Series D Distributions in Arrears, the Series D Distribution Record Date with respect to a Series D Distribution Payment Date shall be such date as may be designated by the General Partner in accordance with this Section 5.20. So long as any Series D Preferred Units are Outstanding, no distribution shall be declared or paid or set aside for payment on any Series D Junior Securities (other than a distribution payable solely in Series D Junior Securities) unless full cumulative Series D Distributions have been or contemporaneously are being paid or set apart for payment on all Outstanding Series D Preferred Units (and distributions on any other Series D Parity Securities) through the most recent respective Series D Distribution Payment Date (and

 

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distribution payment date with respect to such Series D Parity Securities, if any); provided, however, notwithstanding anything to the contrary in this Section 5.20(b)(ii)(B), if a distribution period with respect to a class of Series D Junior Securities or Series D Parity Securities is shorter than the Series D Distribution Period, the General Partner may declare and pay regular distributions with respect to such Series D Junior Securities or Series D Parity Securities, so long as, at the time of declaration of such distribution, (1) there are no Series D Distributions in Arrears, and (2) the General Partner expects to have sufficient funds to pay the full distribution in respect of the Series D Preferred Units on the next successive Series D Distribution Payment Date. Accumulated Series D Distributions in Arrears for any past Series D Distribution Period may be declared by the General Partner and paid on any date fixed by the General Partner, whether or not a Series D Distribution Payment Date, to Series D Holders on the Record Date for such payment, which may not be less than 10 days before such payment date. Subject to the next succeeding sentence, if all accumulated Series D Distributions in Arrears on all Outstanding Series D Preferred Units and all accumulated distributions in arrears on any Series D Parity Securities shall not have been declared and paid, or if sufficient funds for the payment thereof shall not have been set apart, payment of accumulated distributions in Arrears on the Series D Preferred Units and accumulated distributions in arrears on any such Series D Parity Securities shall be made in order of their respective distribution payment dates, commencing with the earliest distribution payment date. If less than all distributions payable with respect to all Series D Preferred Units and any other Series D Parity Securities are paid, any partial payment shall be made Pro Rata with respect to the Series D Preferred Units and any such other Series D Parity Securities entitled to a distribution payment at such time in proportion to the aggregate distribution amounts remaining due in respect of such Series D Preferred Units and such other Series D Parity Securities at such time. Subject to Section 12.4 and Section 5.20(b)(v), Series D Holders shall not be entitled to any distribution, whether payable in cash, property or Partnership Securities, in excess of full cumulative Series D Distributions. Except insofar as distributions accrue on the amount of any accumulated and unpaid Series D Distributions as described in Section 5.20(b)(ii)(A), no interest or sum of money in lieu of interest shall be payable in respect of any distribution payment which may be in Arrears on the Series D Preferred Units. So long as the Series D Preferred Units are held of record by the Depositary or its nominee, declared Series D Distributions shall be paid to the Depositary in same-day funds on each Series D Distribution Payment Date or other distribution payment date in the case of payments for Series D Distributions in Arrears.

(C) The Series D Distribution Rate for each Series D Distribution Period in the Series D Floating Rate Period will be determined by the Calculation Agent using Three-Month LIBOR as in effect on the Distribution Determination Date for such Series D Distribution Period. The Calculation Agent then will add the spread of 4.738% per annum to Three-Month LIBOR as determined on the applicable Distribution Determination Date.

Notwithstanding the foregoing:

(A) If the Calculation Agent determines on the relevant Distribution Determination Date that the LIBOR base rate has been discontinued, then the Calculation Agent will use a substitute or successor base rate that it has determined in its sole discretion is most comparable to the LIBOR base rate, provided that if the Calculation Agent determines there is an industry-accepted substitute or successor base rate, then the Calculation Agent shall use such substitute or successor base rate.

(B) If the Calculation Agent has determined a substitute or successor base rate in accordance with the foregoing, the Calculation Agent in its sole discretion may determine what business day convention to use, the definition of business day, the Distribution Determination Date to be used and any other relevant methodology for calculating such substitute or successor base rate.

 

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(C) Unless otherwise determined by the General Partner, Series D Distributions shall be deemed to have been paid out of deductions from Available Cash with respect to the Quarter ended immediately preceding the Quarter in which the Series D Distribution is made.

(iii) Voting Rights.

(A) Notwithstanding anything to the contrary in this Agreement, the Series D Preferred Units shall not have any voting rights or rights to consent or approve any action or matter, except as set forth in Section 13.3(c), this Section 5.20(b)(iii) or as otherwise required by the Delaware Act.

(B) Notwithstanding anything to the contrary in this Agreement, without the affirmative vote or consent of the holders of at least 66 2/3% of the Outstanding Series D Preferred Units, voting as a separate class, the General Partner shall not adopt any amendment to this Agreement that the General Partner determines would have a material adverse effect on the powers, preferences, duties, or special rights of the Series D Preferred Units; provided, however, that (1) subject to Section 5.20(b)(iii)(C), the issuance of additional Partnership Securities (and any amendment to this Agreement in connection therewith) shall not be deemed to constitute such a material adverse effect for purposes of this Section 5.20(b)(iii)(B) and (2) for purposes of this Section 5.20(b)(iii)(B), no amendment of this Agreement in connection with a merger or other transaction in which the Series D Preferred Units remain Outstanding with the terms thereof materially unchanged in any respect adverse to the Series D Holders (as determined by the General Partner) shall be deemed to materially and adversely affect the powers, preferences, duties, or special rights of the Series D Preferred Units.

(C) Notwithstanding anything to the contrary in this Agreement, without the affirmative vote or consent of the holders of at least 66 2/3% of the Outstanding Series D Preferred Units, voting as a class together with holders of any other Series D Parity Securities upon which like voting rights have been conferred and are exercisable, the Partnership shall not (x) create or issue any Series D Parity Securities (including any additional Series D Preferred Units) if the cumulative distributions payable on Outstanding Series D Preferred Units (or any Series D Parity Securities, if the holders of such Series D Parity Securities vote as a class together with the Series D Holders pursuant to this Section 5.20(b)(iii)(C)) are in Arrears or (y) create or issue any Series D Senior Securities.

(D) For any matter described in this Section 5.20(b)(iii) in which the Series D Holders are entitled to vote as a class (whether separately or together with the holders of any Series D Parity Securities), such Series D Holders shall be entitled to one vote per Series D Preferred Unit. Any Series D Preferred Units held by the Partnership or any of its Subsidiaries or their controlled Affiliates shall not be entitled to vote.

(E) Notwithstanding Sections 5.20(b)(iii)(B) and 5.20(b)(iii)(C), no vote of the Series D Holders shall be required if, at or prior to the time when such action is to take effect, provision is made for the redemption of all Series D Preferred Units at the time Outstanding.

(iv) Optional Redemption; Series D Rating Event.

(A) The Partnership shall have the right (1) at any time, and from time to time, on or after August 15, 2023 or (2) at any time within 120 days after the conclusion of any review or appeal process instituted by the Partnership following the occurrence of a Series D Rating Event, in each case, to redeem the Series D Preferred Units, which redemption may be in whole or in part (except with respect to a redemption pursuant to clause (2) of this Section 5.20(b)(iv)(A) which shall be in whole but not in part), using any source of funds legally available for such purpose. Any such redemption shall occur on a date set by the General Partner (the “Series D Redemption Date”). The Partnership shall effect any such redemption by paying cash for each Series D Preferred Unit to be redeemed equal to 100% (in the case of a redemption described in clause (1) of this Section 5.20(b)(iv)(A)), or 102% (in the case of a redemption described in clause (2) of this Section 5.20(b)(iv)(A)), of the Series D Liquidation Preference for such Series D Preferred Unit on such Series D Redemption Date plus an amount equal to all unpaid Series D Distributions

 

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thereon from the date of issuance to, but excluding, the Series D Redemption Date (whether or not such distributions shall have been declared) (the “Series D Redemption Price”). So long as the Series D Preferred Units to be redeemed are held of record by the Depositary or the nominee of the Depositary, the Series D Redemption Price shall be paid by the Paying Agent to the Depositary on the Series D Redemption Date.

(B) The Partnership shall give notice of any redemption by mail, postage prepaid, not less than 30 days and not more than 60 days before the scheduled Series D Redemption Date to the Series D Holders (as of 5:00 p.m. New York City time on the Business Day next preceding the day on which notice is given) of any Series D Preferred Units to be redeemed as such Series D Holders’ names appear on the books of the Transfer Agent and at the address of such Series D Holders shown therein. Such notice (the “Series D Redemption Notice”) shall state, as applicable: (1) the Series D Redemption Date, (2) the number of Series D Preferred Units to be redeemed and, if less than all Outstanding Series D Preferred Units are to be redeemed, the number (and in the case of Series D Preferred Units in certificated form, the identification) of Series D Preferred Units to be redeemed from such Series D Holder, (3) the Series D Redemption Price, (4) the place where any Series D Preferred Units in certificated form are to be redeemed and shall be presented and surrendered for payment of the Series D Redemption Price therefor (which shall occur automatically if the Certificate representing such Series D Preferred Units is issued in the name of the Depositary or its nominee), and (5) that distributions on the Series D Preferred Units to be redeemed shall cease to accumulate from and after such Series D Redemption Date.

(C) If the Partnership elects to redeem less than all of the Outstanding Series D Preferred Units, the number of Series D Preferred Units to be redeemed shall be determined by the General Partner, and such Series D Preferred Units shall be redeemed by such method of selection as the Depositary shall determine, either Pro Rata or by lot, with adjustments to avoid redemption of fractional Series D Preferred Units. The aggregate Series D Redemption Price for any such partial redemption of the Outstanding Series D Preferred Units shall be allocated correspondingly among the redeemed Series D Preferred Units. The Series D Preferred Units not redeemed shall remain Outstanding and entitled to all the rights, preferences and duties provided in this Section 5.20.

(D) If the Partnership gives or causes to be given a Series D Redemption Notice, the Partnership shall deposit with the Paying Agent funds sufficient to redeem the Series D Preferred Units as to which such Series D Redemption Notice shall have been given, no later than 10:00 a.m. New York City time on the Series D Redemption Date, and shall give the Paying Agent irrevocable instructions and authority to pay the Series D Redemption Price to each Series D Holder whose Series D Preferred Units are to be redeemed upon surrender or deemed surrender (which shall occur automatically if the Certificate representing such Series D Preferred Units is issued in the name of the Depositary or its nominee) of the Certificates therefor as set forth in the Series D Redemption Notice. If a Series D Redemption Notice shall have been given, from and after the Series D Redemption Date, unless the Partnership defaults in providing funds sufficient for such redemption at the time and place specified for payment pursuant to the Series D Redemption Notice, all Series D Distributions on such Series D Preferred Units to be redeemed shall cease to accumulate and all rights of holders of such Series D Preferred Units as Limited Partners with respect to such Series D Preferred Units to be redeemed shall cease, except the right to receive the Series D Redemption Price, and such Series D Preferred Units shall not thereafter be transferred on the books of the Transfer Agent or be deemed to be Outstanding for any purpose whatsoever. The Series D Holders shall have no claim to the interest income, if any, earned on funds deposited with the Paying Agent. Any funds deposited with the Paying Agent hereunder by the Partnership for any reason, including redemption of Series D Preferred Units, that remain unclaimed or unpaid after one year after the applicable Series D Redemption Date or other payment date, as applicable, shall be, to the extent permitted by law, repaid to the Partnership upon its written request, after which repayment the Series D Holders entitled to such redemption

 

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or other payment shall have recourse only to the Partnership. Notwithstanding any Series D Redemption Notice, there shall be no redemption of any Series D Preferred Units called for redemption until funds sufficient to pay the full Series D Redemption Price of such Series D Preferred Units shall have been deposited by the Partnership with the Paying Agent.

(E) Any Series D Preferred Units that are redeemed or otherwise acquired by the Partnership shall be cancelled. If only a portion of the Series D Preferred Units represented by a Certificate shall have been called for redemption, upon surrender of the Certificate to the Paying Agent (which shall occur automatically if the Certificate representing such Series D Preferred Units is registered in the name of the Depositary or its nominee), the Partnership shall issue and the Paying Agent shall deliver to the Series D Holders a new Certificate (or adjust the applicable book-entry account) representing the number of Series D Preferred Units represented by the surrendered Certificate that have not been called for redemption.

(F) Notwithstanding anything to the contrary in this Section 5.20, in the event that full cumulative distributions on the Series D Preferred Units and any Series D Parity Securities shall not have been paid or declared and set aside for payment, the Partnership shall not be permitted to repurchase, redeem or otherwise acquire, in whole or in part, any Series D Preferred Units or Series D Parity Securities except pursuant to a purchase or exchange offer made on the same relative terms to all Series D Holders and holders of any Series D Parity Securities. Subject to Section 4.9, so long as any Series D Preferred Units are Outstanding, the Partnership shall not be permitted to redeem, repurchase or otherwise acquire any Common Units or any other Series D Junior Securities unless full cumulative distributions on the Series D Preferred Units and any Series D Parity Securities for all prior and the then-ending Series D Distribution Periods, with respect to the Series D Preferred Units, and all prior and then ending distribution periods, with respect to any such Series D Parity Securities, shall have been paid or declared and set aside for payment.

(v) Liquidation Rights. In the event of the dissolution and winding up of the Partnership under Section 12.4 or a sale, exchange, or other disposition of all or substantially all of the assets of the Partnership, either voluntary or involuntary, the Record Holders of the Series D Preferred Units shall be entitled to receive, out of the assets of the Partnership available for distribution to the Partners or any Assignees, prior and in preference to any distribution of any assets of the Partnership to the Record Holders of any other class or series of Partnership Interests (other than Series D Senior Securities or Series D Parity Securities), (A) first, any accumulated and unpaid distributions on the Series D Preferred Units (regardless of whether previously declared) and (B) then, any positive value in each such holder’s Capital Account in respect of such Series D Preferred Units. If in the year of such dissolution and winding up, or sale, exchange, or other disposition of all or substantially all of the assets of the Partnership, any such Record Holder’s Capital Account in respect of such Series D Preferred Units is less than the aggregate Series D Base Liquidation Preference of such Series D Preferred Units, then, notwithstanding anything to the contrary contained in this Agreement, and prior to any other allocation pursuant to this Agreement for such year and any distribution pursuant to the preceding sentence (other than any allocations or distributions made with respect to any other Series D Parity Securities upon which like allocation and distribution rights have been conferred), items of gross income and gain shall be allocated to all Unitholders then holding Series D Preferred Units, Pro Rata, until the Capital Account in respect of each Outstanding Series D Preferred Unit is equal to the Series D Base Liquidation Preference (and no other allocation pursuant to this Agreement shall reverse the effect of such allocation); provided, however, that in the event that like allocation rights have been conferred upon other Series D Parity Securities (including pursuant to Sections 5.17(b)(v), 5.18(b)(v), 5.19(b)(v), 5.21(b)(v), 5.22(b)(v) and 5.23(b)(v)), then items of gross income and gain shall be allocated to all Unitholders then holding Series D Preferred Units and such Series D Parity Securities, Pro Rata, until the Capital Account in respect of each Outstanding Series D Preferred Unit and such Series D Parity Security is equal to the applicable liquidation preference (and no other allocation

 

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pursuant to this Agreement shall reverse the effect of such allocation). If in the year of such dissolution and winding up any such Record Holder’s Capital Account in respect of such Series D Preferred Units is less than the aggregate Series D Base Liquidation Preference of such Series D Preferred Units after the application of the preceding sentence, then to the extent permitted by applicable law, but otherwise notwithstanding anything to the contrary contained in this Agreement, items of gross income and gain for any preceding taxable year(s) with respect to which IRS Form 1065 Schedules K-1 have not been filed by the Partnership shall be reallocated to all Unitholders then holding Series D Preferred Units, Pro Rata, until the Capital Account in respect of each such Outstanding Series D Preferred Unit after making allocations pursuant to this and the immediately preceding sentence is equal to the Series D Base Liquidation Preference (and no other allocation pursuant to this Agreement shall reverse the effect of such allocation); provided, however, that in the event like allocation rights have been conferred upon other Series D Parity Securities (including pursuant to Sections 5.17(b)(v), 5.18(b)(v), 5.19(b)(v), 5.21(b)(v), 5.22(b)(v) and 5.23(b)(v)), then any such items of gross income and gain shall be reallocated to all Unitholders then holding Series D Preferred Units and such Series D Parity Securities, Pro Rata, until the Capital Account in respect of each Outstanding Series D Preferred Unit and such Series D Parity Security after making allocations pursuant to this and the immediately preceding sentence is equal to the applicable liquidation preference (and no other allocation pursuant to this Agreement shall reverse the effect of such allocation). After such allocations have been made to the Outstanding Series D Preferred Units and any Series D Parity Securities, as applicable, any remaining Net Termination Gain or Net Termination Loss shall be allocated to the Partners pursuant to Section 6.1(c) or Section 6.1(d), as the case may be. At the time of the dissolution of the Partnership, subject to Section 17-804 of the Delaware Act, the Record Holders of the Series D Preferred Units shall become entitled to receive any distributions in respect of the Series D Preferred Units that are accrued and unpaid as of the date of such distribution, and shall have the status of, and shall be entitled to all remedies available to, a creditor of the Partnership, and such entitlement of the Record Holders of the Series D Preferred Units to such accrued and unpaid distributions shall have priority over any entitlement of any other Partners or Assignees (other than holders of any Series D Senior Securities or Series D Parity Securities) with respect to any distributions by the Partnership to such other Partners or Assignees; provided, however, that the General Partner, as such, will have no liability for any obligations with respect to such distributions to any Record Holder(s) of Series D Preferred Units.

(vi) Rank. The Series D Preferred Units shall each be deemed to rank as to distributions on such Partnership Securities and distributions upon liquidation of the Partnership:

(A) senior to any Series D Junior Securities;

(B) on a parity with any Series D Parity Securities;

(C) junior to any Series D Senior Securities; and

(D) junior to all existing and future indebtedness of the Partnership and other liabilities with respect to assets available to satisfy claims against the Partnership.

(vii) No Sinking Fund. The Series D Preferred Units shall not have the benefit of any sinking fund.

(viii) Record Holders. To the fullest extent permitted by applicable law, the General Partner, the Partnership, the Transfer Agent, and the Paying Agent may deem and treat any Series D Holder as the true, lawful, and absolute owner of the applicable Series D Preferred Units for all purposes, and none of the General Partner, the Partnership, the Transfer Agent or the Paying Agent shall be affected by any notice to the contrary, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which the Series D Preferred Units may be listed or admitted to trading, if any.

(ix) Other Rights; Fiduciary Duties. The Series D Preferred Units and the Series D Holders shall not have any designations, preferences, rights, powers or duties, other than as set forth in this

 

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Agreement or as provided by applicable law. Notwithstanding anything to the contrary in this Agreement or any duty existing at law, in equity or otherwise, to the fullest extent permitted by applicable law, neither the General Partner nor any other Indemnitee shall owe any duties, including fiduciary duties, or have any liabilities to Series D Holders, other than the implied contractual covenant of good faith and fair dealing.

“Section 5.21 Establishment of Series E Preferred Units.

(a) General. The Partnership hereby designates and creates a class of Partnership Securities to be designated as “7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units” (the “Series E Preferred Units”), having the preferences, rights, powers, and duties set forth herein, including this Section 5.21. Each Series E Preferred Unit shall be identical in all respects to every other Series E Preferred Unit, except as to the respective dates from which the Series E Liquidation Preference shall increase or from which Series E Distributions may begin accruing, to the extent such dates may differ. The Series E Preferred Units represent perpetual equity interests in the Partnership and shall not give rise to a claim by the Partnership or a Series E Holder for conversion or, except as set forth in Section 5.21(b)(iv), redemption thereof at a particular date.

(b) Rights of Series E Preferred Units. The Series E Preferred Units shall have the following rights, preferences and privileges and shall be subject to the following duties and obligations:

(i) Series E Preferred Units.

(A) The authorized number of Series E Preferred Units shall be unlimited. Series E Preferred Units that are purchased or otherwise acquired by the Partnership shall be cancelled.

(B) The Series E Preferred Units shall be represented by one or more global Certificates registered in the name of the Depositary or its nominee, and no Series E Holder shall be entitled to receive a definitive Certificate evidencing its Series E Preferred Units, unless (1) requested by a Series E Holder and consented to by the General Partner in its sole discretion, (2) otherwise required by law or (3) the Depositary gives notice of its intention to resign or is no longer eligible to act as such with respect to the Series E Preferred Units and the General Partner shall have not selected a substitute Depositary within 60 calendar days thereafter. So long as the Depositary shall have been appointed and is serving with respect to the Series E Preferred Units, payments and communications made by the Partnership to Series E Holders shall be made by making payments to, and communicating with, the Depositary.

(ii) Distributions.

(A) Distributions on each Outstanding Series E Preferred Unit shall be cumulative and shall accumulate at the applicable Series E Distribution Rate from and including [ ● ], 2021 (or, for any subsequently issued and newly Outstanding Series E Preferred Units, from and including the Series E Distribution Payment Date immediately preceding the issue date of such Series E Preferred Units) until such time as the Partnership pays the Series E Distribution or redeems such Series E Preferred Unit in accordance with Section 5.21(b)(iv), whether or not such Series E Distributions shall have been declared. Series E Holders shall be entitled to receive Series E Distributions from time to time out of any assets of the Partnership legally available for the payment of distributions at the Series E Distribution Rate per Series E Preferred Unit when, as, and, if declared by the General Partner. Series E Distributions, to the extent declared by the General Partner to be paid by the Partnership in accordance with this Section 5.21(b)(ii), shall be paid, in Arrears, on each Series E Distribution Payment Date. Series E Distributions shall accumulate in each Series E Distribution Period from and including the preceding Series E Distribution Payment Date (other than the initial Series E Distribution Period, which shall commence on and include [ ● ], 2021), to, but excluding, the next Series E Distribution Payment Date for such Series E Distribution Period; provided that distributions shall accrue on accumulated

 

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but unpaid Series E Distributions at the Series E Distribution Rate. If any Series E Distribution Payment Date otherwise would occur on a date that is not a Business Day, declared Series E Distributions shall be paid on the immediately succeeding Business Day without the accumulation of additional distributions.

During the Series E Fixed Rate Period, Series E Distributions shall be payable based on a 360- day year consisting of twelve 30 day months. During the Series E Floating Rate Period, Series E Distributions shall be computed by multiplying the Series E Distribution Rate by a fraction, the numerator of which will be the actual number of days elapsed during that Series E Distribution Period (determined by including the first day of such Series E Distribution Period and excluding the last day, which is the Series E Distribution Payment Date), and the denominator of which will be 360, and by multiplying the result by the aggregate Series E Liquidation Preference of all Outstanding Series E Preferred Units. All Series E Distributions that are (1) accumulated and unpaid or (2) payable by the Partnership pursuant to this Section 5.21(b)(ii) shall be payable without regard to income of the Partnership and shall be treated for federal income tax purposes as guaranteed payments for the use of capital under Section 707(c) of the Code. The guaranteed payment with respect to any Series E Distribution Period shall be for the account of the holders of Series E Preferred Units as of the applicable Series E Distribution Record Date.

(B) Not later than 5:00 p.m., New York City time, on each Series E Distribution Payment Date, the Partnership shall pay those Series E Distributions, if any, that shall have been declared by the General Partner to Series E Holders on the Record Date for the applicable Series E Distribution. The Record Date (the “Series E Distribution Record Date”) for the payment of any Series E Distributions shall be as of the close of business on the first Business Day of the month of the applicable Series E Distribution Payment Date, except that in the case of payments of Series E Distributions in Arrears, the Series E Distribution Record Date with respect to a Series E Distribution Payment Date shall be such date as may be designated by the General Partner in accordance with this Section 5.21. So long as any Series E Preferred Units are Outstanding, no distribution shall be declared or paid or set aside for payment on any Series E Junior Securities (other than a distribution payable solely in Series E Junior Securities) unless full cumulative Series E Distributions have been or contemporaneously are being paid or set apart for payment on all Outstanding Series E Preferred Units (and distributions on any other Series E Parity Securities) through the most recent respective Series E Distribution Payment Date (and distribution payment date with respect to such Series E Parity Securities, if any); provided, however, notwithstanding anything to the contrary in this Section 5.21(b)(ii)(B), if a distribution period with respect to a class of Series E Junior Securities or Series E Parity Securities is shorter than the Series E Distribution Period, the General Partner may declare and pay regular distributions with respect to such Series E Junior Securities or Series E Parity Securities, so long as, at the time of declaration of such distribution, (i) there are no Series E Distributions in Arrears, and (ii) the General Partner expects to have sufficient funds to pay the full distribution in respect of the Series E Preferred Units on the next successive Series E Distribution Payment Date. Accumulated Series E Distributions in Arrears for any past Series E Distribution Period may be declared by the General Partner and paid on any date fixed by the General Partner, whether or not a Series E Distribution Payment Date, to Series E Holders on the Record Date for such payment, which may not be less than 10 days before such payment date.

Subject to the next succeeding sentence, if all accumulated Series E Distributions in Arrears on all Outstanding Series E Preferred Units and all accumulated distributions in arrears on any Series E Parity Securities shall not have been declared and paid, or if sufficient funds for the payment thereof shall not have been set apart, payment of accumulated distributions in Arrears on the Series E Preferred Units and accumulated distributions in arrears on any such Series E Parity Securities shall be made in order of their respective distribution payment dates, commencing with the earliest distribution payment date. If less than all distributions payable with respect to all

 

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Series E Preferred Units and any other Series E Parity Securities are paid, any partial payment shall be made Pro Rata with respect to the Series E Preferred Units and any such other Series E Parity Securities entitled to a distribution payment at such time in proportion to the aggregate distribution amounts remaining due in respect of such Series E Preferred Units and such other Series E Parity Securities at such time. Subject to Section 12.4 and Section 5.21(b)(v), Series E Holders shall not be entitled to any distribution, whether payable in cash, property or Partnership Securities, in excess of full cumulative Series E Distributions. Except insofar as distributions accrue on the amount of any accumulated and unpaid Series E Distributions as described in Section 5.21(b)(ii)(A), no interest or sum of money in lieu of interest shall be payable in respect of any distribution payment which may be in Arrears on the Series E Preferred Units. So long as the Series E Preferred Units are held of record by the Depositary or its nominee, declared Series E Distributions shall be paid to the Depositary in same-day funds on each Series E Distribution Payment Date or other distribution payment date in the case of payments for Series E Distributions in Arrears.

(C) The Series E Distribution Rate for each Series E Distribution Period in the Series E Floating Rate Period will be determined by the Calculation Agent using Three-Month LIBOR as in effect on the Distribution Determination Date for such Series E Distribution Period. The Calculation Agent then will add the spread of 5.161% per annum to Three-Month LIBOR as determined on the applicable Distribution Determination Date.

Notwithstanding the foregoing:

(a) If the Calculation Agent determines on the relevant Distribution Determination Date that the LIBOR base rate has been discontinued, then the Calculation Agent will use a substitute or successor base rate that it has determined in its sole discretion is most comparable to the LIBOR base rate, provided that if the Calculation Agent determines there is an industry-accepted substitute or successor base rate, then the Calculation Agent shall use such substitute or successor base rate.

(b) If the Calculation Agent has determined a substitute or successor base rate in accordance with the foregoing, the Calculation Agent in its sole discretion may determine what business day convention to use, the definition of business day, the Distribution Determination Date to be used and any other relevant methodology for calculating such substitute or successor base rate.

(c) Unless otherwise determined by the General Partner, Series E Distributions shall be deemed to have been paid out of deductions from Available Cash with respect to the Quarter ended immediately preceding the Quarter in which the Series E Distribution is made.

(iii) Voting Rights.

(A) Notwithstanding anything to the contrary in this Agreement, the Series E Preferred Units shall not have any voting rights or rights to consent or approve any action or matter, except as set forth in Section 13.3(c), this Section 5.21(b)(iii) or as otherwise required by the Delaware Act.

(B) Notwithstanding anything to the contrary in this Agreement, without the affirmative vote or consent of the holders of at least 66 2/3% of the Outstanding Series E Preferred Units, voting as a separate class, the General Partner shall not adopt any amendment to this Agreement that the General Partner determines would have a material adverse effect on the powers, preferences, duties, or special rights of the Series E Preferred Units; provided, however, that (i) subject to Section 5.21(b)(iii)(C), the issuance of additional Partnership Securities (and any amendment to this Agreement in connection therewith) shall not be deemed to constitute such a material adverse effect for purposes of this Section 5.21(b)(iii)(B) and (ii) for purposes of this Section 5.21(b)(iii)(B), no amendment of this Agreement in connection with a merger or other transaction in which the Series E Preferred Units remain Outstanding with the terms thereof materially unchanged in any respect adverse to the Series E Holders (as determined by the General

 

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Partner) shall be deemed to materially and adversely affect the powers, preferences, duties, or special rights of the Series E Preferred Units.

(C) Notwithstanding anything to the contrary in this Agreement, without the affirmative vote or consent of the holders of at least 66 2/3% of the Outstanding Series E Preferred Units, voting as a class together with holders of any other Series E Parity Securities upon which like voting rights have been conferred and are exercisable, the Partnership shall not (x) create or issue any Series E Parity Securities (including any additional Series E Preferred Units) if the cumulative distributions payable on Outstanding Series E Preferred Units (or any Series E Parity Securities, if the holders of such Series E Parity Securities vote as a class together with the Series E Holders pursuant to this Section 5.21(b)(iii)(C)) are in Arrears or (y) create or issue any Series E Senior Securities.

(D) For any matter described in this Section 5.21(b)(iii) in which the Series E Holders are entitled to vote as a class (whether separately or together with the holders of any Series E Parity Securities), such Series E Holders shall be entitled to one vote per Series E Preferred Unit. Any Series E Preferred Units held by the Partnership or any of its Subsidiaries or their controlled Affiliates shall not be entitled to vote.

(E) Notwithstanding Sections 5.21(b)(iii)(B) and 5.21(b)(iii)(C), no vote of the Series E Holders shall be required if, at or prior to the time when such action is to take effect, provision is made for the redemption of all Series E Preferred Units at the time Outstanding.

(iv) Optional Redemption; Series E Rating Event.

(A) The Partnership shall have the right (i) at any time, and from time to time, on or after May 15, 2024 or (ii) at any time within 120 days after the conclusion of any review or appeal process instituted by the Partnership following the occurrence of a Series E Rating Event, in each case, to redeem the Series E Preferred Units, which redemption may be in whole or in part (except with respect to a redemption pursuant to clause (ii) of this Section 5.21(b)(iv)(A) which shall be in whole but not in part), using any source of funds legally available for such purpose. Any such redemption shall occur on a date set by the General Partner (the “Series E Redemption Date”). The Partnership shall effect any such redemption by paying cash for each Series E Preferred Unit to be redeemed equal to 100% (in the case of a redemption described in clause (i) of this Section 5.21(b)(iv)(A)), or 102% (in the case of a redemption described in clause (ii) of this Section 5.21(b)(iv)(A)), of the Series E Liquidation Preference for such Series E Preferred Unit on such Series E Redemption Date plus an amount equal to all unpaid Series E Distributions thereon from the date of issuance to, but excluding, the Series E Redemption Date (whether or not such distributions shall have been declared) (the “Series E Redemption Price”). So long as the Series E Preferred Units to be redeemed are held of record by the Depositary or the nominee of the Depositary, the Series E Redemption Price shall be paid by the Paying Agent to the Depositary on the Series E Redemption Date.

(B) The Partnership shall give notice of any redemption by mail, postage prepaid, not less than 30 days and not more than 60 days before the scheduled Series E Redemption Date to the Series E Holders (as of 5:00 p.m. New York City time on the Business Day next preceding the day on which notice is given) of any Series E Preferred Units to be redeemed as such Series E Holders’ names appear on the books of the Transfer Agent and at the address of such Series E Holders shown therein. Such notice (the “Series E Redemption Notice”) shall state, as applicable: (1) the Series E Redemption Date, (2) the number of Series E Preferred Units to be redeemed and, if less than all Outstanding Series E Preferred Units are to be redeemed, the number (and in the case of Series E Preferred Units in certificated form, the identification) of Series E Preferred Units to be redeemed from such Series E Holder, (3) the Series E Redemption Price, (4) the place where any Series E Preferred Units in certificated form are to be redeemed and shall be presented and surrendered for payment of the Series E Redemption Price therefor (which shall occur automatically if the Certificate representing such Series E Preferred Units is issued in the name of

 

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the Depositary or its nominee), and (5) that distributions on the Series E Preferred Units to be redeemed shall cease to accumulate from and after such Series E Redemption Date.

(C) If the Partnership elects to redeem less than all of the Outstanding Series E Preferred Units, the number of Series E Preferred Units to be redeemed shall be determined by the General Partner, and such Series E Preferred Units shall be redeemed by such method of selection as the Depositary shall determine, either Pro Rata or by lot, with adjustments to avoid redemption of fractional Series E Preferred Units. The aggregate Series E Redemption Price for any such partial redemption of the Outstanding Series E Preferred Units shall be allocated correspondingly among the redeemed Series E Preferred Units. The Series E Preferred Units not redeemed shall remain Outstanding and entitled to all the rights, preferences and duties provided in this Section 5.21.

(D) If the Partnership gives or causes to be given a Series E Redemption Notice, the Partnership shall deposit with the Paying Agent funds sufficient to redeem the Series E Preferred Units as to which such Series E Redemption Notice shall have been given, no later than 10:00 a.m. New York City time on the Series E Redemption Date, and shall give the Paying Agent irrevocable instructions and authority to pay the Series E Redemption Price to each Series E Holder whose Series E Preferred Units are to be redeemed upon surrender or deemed surrender (which shall occur automatically if the Certificate representing such Series E Preferred Units is issued in the name of the Depositary or its nominee) of the Certificates therefor as set forth in the Series E Redemption Notice. If a Series E Redemption Notice shall have been given, from and after the Series E Redemption Date, unless the Partnership defaults in providing funds sufficient for such redemption at the time and place specified for payment pursuant to the Series E Redemption Notice, all Series E Distributions on such Series E Preferred Units to be redeemed shall cease to accumulate and all rights of holders of such Series E Preferred Units as Limited Partners with respect to such Series E Preferred Units to be redeemed shall cease, except the right to receive the Series E Redemption Price, and such Series E Preferred Units shall not thereafter be transferred on the books of the Transfer Agent or be deemed to be Outstanding for any purpose whatsoever. The Series E Holders shall have no claim to the interest income, if any, earned on funds deposited with the Paying Agent. Any funds deposited with the Paying Agent hereunder by the Partnership for any reason, including redemption of Series E Preferred Units, that remain unclaimed or unpaid after one year after the applicable Series E Redemption Date or other payment date, as applicable, shall be, to the extent permitted by law, repaid to the Partnership upon its written request, after which repayment the Series E Holders entitled to such redemption or other payment shall have recourse only to the Partnership. Notwithstanding any Series E Redemption Notice, there shall be no redemption of any Series E Preferred Units called for redemption until funds sufficient to pay the full Series E Redemption Price of such Series E Preferred Units shall have been deposited by the Partnership with the Paying Agent.

(E) Any Series E Preferred Units that are redeemed or otherwise acquired by the Partnership shall be cancelled. If only a portion of the Series E Preferred Units represented by a Certificate shall have been called for redemption, upon surrender of the Certificate to the Paying Agent (which shall occur automatically if the Certificate representing such Series E Preferred Units is registered in the name of the Depositary or its nominee), the Partnership shall issue and the Paying Agent shall deliver to the Series E Holders a new Certificate (or adjust the applicable book-entry account) representing the number of Series E Preferred Units represented by the surrendered Certificate that have not been called for redemption.

(F) Notwithstanding anything to the contrary in this Section 5.21, in the event that full cumulative distributions on the Series E Preferred Units and any Series E Parity Securities shall not have been paid or declared and set aside for payment, the Partnership shall not be permitted to repurchase, redeem or otherwise acquire, in whole or in part, any Series E Preferred Units or Series E Parity Securities except pursuant to a purchase or exchange offer made on the same relative terms to all Series E Holders and holders of any Series E Parity Securities. Subject to

 

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Section 4.9, so long as any Series E Preferred Units are Outstanding, the Partnership shall not be permitted to redeem, repurchase or otherwise acquire any Common Units or any other Series E Junior Securities unless full cumulative distributions on the Series E Preferred Units and any Series E Parity Securities for all prior and the then-ending Series E Distribution Periods, with respect to the Series E Preferred Units, and all prior and then ending distribution periods, with respect to any such Series E Parity Securities, shall have been paid or declared and set aside for payment.

(v) Liquidation Rights.

In the event of the dissolution and winding up of the Partnership under Section 12.4 or a sale, exchange, or other disposition of all or substantially all of the assets of the Partnership, either voluntary or involuntary, the Record Holders of the Series E Preferred Units shall be entitled to receive, out of the assets of the Partnership available for distribution to the Partners or any Assignees, prior and in preference to any distribution of any assets of the Partnership to the Record Holders of any other class or series of Partnership Interests (other than Series E Senior Securities or Series E Parity Securities), (i) first, any accumulated and unpaid distributions on the Series E Preferred Units (regardless of whether previously declared) and (ii) then, any positive value in each such holder’s Capital Account in respect of such Series E Preferred Units. If in the year of such dissolution and winding up, or sale, exchange, or other disposition of all or substantially all of the assets of the Partnership, any such Record Holder’s Capital Account in respect of such Series E Preferred Units is less than the aggregate Series E Base Liquidation Preference of such Series E Preferred Units, then, notwithstanding anything to the contrary contained in this Agreement, and prior to any other allocation pursuant to this Agreement for such year and any distribution pursuant to the preceding sentence (other than any allocations or distributions made with respect to any other Series E Parity Securities upon which like allocation and distribution rights have been conferred), items of gross income and gain shall be allocated to all Unitholders then holding Series E Preferred Units, Pro Rata, until the Capital Account in respect of each Outstanding Series E Preferred Unit is equal to the Series E Base Liquidation Preference (and no other allocation pursuant to this Agreement shall reverse the effect of such allocation); provided, however, that in the event that like allocation rights have been conferred upon other Series E Parity Securities (including pursuant to Sections 5.17(b)(v), 5.18(b)(v), 5.19(b)(v), 5.20(b)(v), 5.22(b)(v) and 5.23(b)(v)), then items of gross income and gain shall be allocated to all Unitholders then holding Series E Preferred Units and such Series E Parity Securities, Pro Rata, until the Capital Account in respect of each Outstanding Series E Preferred Unit and such Series E Parity Security is equal to the applicable liquidation preference (and no other allocation pursuant to this Agreement shall reverse the effect of such allocation). If in the year of such dissolution and winding up any such Record Holder’s Capital Account in respect of such Series E Preferred Units is less than the aggregate Series E Base Liquidation Preference of such Series E Preferred Units after the application of the preceding sentence, then to the extent permitted by applicable law, but otherwise notwithstanding anything to the contrary contained in this Agreement, items of gross income and gain for any preceding taxable year(s) with respect to which IRS Form 1065 Schedules K-1 have not been filed by the Partnership shall be reallocated to all Unitholders then holding Series E Preferred Units, Pro Rata, until the Capital Account in respect of each such Outstanding Series E Preferred Unit after making allocations pursuant to this and the immediately preceding sentence is equal to the Series E Base Liquidation Preference (and no other allocation pursuant to this Agreement shall reverse the effect of such allocation); provided, however, that in the event like allocation rights have been conferred upon other Series E Parity Securities (including pursuant to Sections 5.17(b)(v), 5.18(b)(v), 5.19(b)(v), 5.20 (b)(v), 5.22(b)(v) and 5.23(b)(v)), then any such items of gross income and gain shall be reallocated to all Unitholders then holding Series E Preferred Units and such Series E Parity Securities, Pro Rata, until the Capital Account in respect of each Outstanding Series E Preferred Unit and such Series E Parity Security after making allocations pursuant to this and the immediately preceding sentence

 

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is equal to the applicable liquidation preference (and no other allocation pursuant to this Agreement shall reverse the effect of such allocation). After such allocations have been made to the Outstanding Series E Preferred Units and any Series E Parity Securities, as applicable, any remaining Net Termination Gain or Net Termination Loss shall be allocated to the Partners pursuant to Section 6.1(c) or Section 6.1(d), as the case may be. At the time of the dissolution of the Partnership, subject to Section 17-804 of the Delaware Act, the Record Holders of the Series E Preferred Units shall become entitled to receive any distributions in respect of the Series E Preferred Units that are accrued and unpaid as of the date of such distribution, and shall have the status of, and shall be entitled to all remedies available to, a creditor of the Partnership, and such entitlement of the Record Holders of the Series E Preferred Units to such accrued and unpaid distributions shall have priority over any entitlement of any other Partners or Assignees (other than holders of any Series E Senior Securities or Series E Parity Securities) with respect to any distributions by the Partnership to such other Partners or Assignees; provided, however, that the General Partner, as such, will have no liability for any obligations with respect to such distributions to any Record Holder(s) of Series E Preferred Units.

(vi) Rank.

The Series E Preferred Units shall each be deemed to rank as to distributions on such Partnership Securities and distributions upon liquidation of the Partnership:

(A) senior to any Series E Junior Securities;

(B) on a parity with any Series E Parity Securities;

(C) junior to any Series E Senior Securities; and

(D) junior to all existing and future indebtedness of the Partnership and other liabilities with respect to assets available to satisfy claims against the Partnership.

(vii) No Sinking Fund.

The Series E Preferred Units shall not have the benefit of any sinking fund.

(viii) Record Holders.

To the fullest extent permitted by applicable law, the General Partner, the Partnership, the Transfer Agent, and the Paying Agent may deem and treat any Series E Holder as the true, lawful, and absolute owner of the applicable Series E Preferred Units for all purposes, and none of the General Partner, the Partnership, the Transfer Agent or the Paying Agent shall be affected by any notice to the contrary, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which the Series E Preferred Units may be listed or admitted to trading, if any.

(ix) Other Rights; Fiduciary Duties.

The Series E Preferred Units and the Series E Holders shall not have any designations, preferences, rights, powers or duties, other than as set forth in this Agreement or as provided by applicable law. Notwithstanding anything to the contrary in this Agreement or any duty existing at law, in equity or otherwise, to the fullest extent permitted by applicable law, neither the General Partner nor any other Indemnitee shall owe any duties, including fiduciary duties, or have any liabilities to Series E Holders, other than the implied contractual covenant of good faith and fair dealing.”

“Section 5.22 Establishment of Series F Preferred Units.

(a) General. The Partnership hereby designates and creates a class of Partnership Securities to be designated as “6.750% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units” (the

 

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Series F Preferred Units”), having the preferences, rights, powers, and duties set forth herein, including this Section 5.22. Each Series F Preferred Unit shall be identical in all respects to every other Series F Preferred Unit, except as to the respective dates from which the Series F Liquidation Preference shall increase or from which Series F Distributions may begin accruing, to the extent such dates may differ. The Series F Preferred Units represent perpetual equity interests in the Partnership and shall not give rise to a claim by the Partnership or a Series F Holder for conversion or, except as set forth in Section 5.22(b)(iv), redemption thereof at a particular date.

(b) Rights of Series F Preferred Units. The Series F Preferred Units shall have the following rights, preferences and privileges and shall be subject to the following duties and obligations:

(i) Series F Preferred Units.

(A) The authorized number of Series F Preferred Units shall be unlimited. Series F Preferred Units that are purchased or otherwise acquired by the Partnership shall be cancelled.

(B) The Series F Preferred Units shall be represented by one or more global Certificates registered in the name of the Depositary or its nominee, and no Series F Holder shall be entitled to receive a definitive Certificate evidencing its Series F Preferred Units, unless (1) requested by a Series F Holder and consented to by the General Partner in its sole discretion, (2) otherwise required by law or (3) the Depositary gives notice of its intention to resign or is no longer eligible to act as such with respect to the Series F Preferred Units and the General Partner shall have not selected a substitute Depositary within 60 calendar days thereafter. So long as the Depositary shall have been appointed and is serving with respect to the Series F Preferred Units, payments and communications made by the Partnership to Series F Holders shall be made by making payments to, and communicating with, the Depositary.

(ii) Distributions.

(A) Distributions on each Outstanding Series F Preferred Unit shall be cumulative and shall accumulate at the applicable Series F Distribution Rate from and including [ ● ], 2021 (or, for any subsequently issued and newly Outstanding Series F Preferred Units, from and including the Series F Distribution Payment Date immediately preceding the issue date of such Series F Preferred Units) until such time as the Partnership pays the Series F Distribution or redeems such Series F Preferred Unit in accordance with Section 5.22(b)(iv), whether or not such Series F Distributions shall have been declared. Series F Holders shall be entitled to receive Series F Distributions from time to time out of any assets of the Partnership legally available for the payment of distributions at the Series F Distribution Rate per Series F Preferred Unit when, as, and, if declared by the General Partner. Series F Distributions, to the extent declared by the General Partner to be paid by the Partnership in accordance with this Section 5.22(b)(ii), shall be paid, in Arrears, on each Series F Distribution Payment Date. Series F Distributions shall accumulate in each Series F Distribution Period from and including the preceding Series F Distribution Payment Date (other than the initial Series F Distribution Period, which shall commence on and include [ ● ], 2021), to, but excluding, the next Series F Distribution Payment Date for such Series F Distribution Period; provided that distributions shall accrue on accumulated but unpaid Series F Distributions at the Series F Distribution Rate. If any Series F Distribution Payment Date otherwise would occur on a date that is not a Business Day, declared Series F Distributions shall be paid on the immediately succeeding Business Day without the accumulation of additional distributions. All Series F Distributions that are (1) accumulated and unpaid or (2) payable by the Partnership pursuant to this Section 5.22(b)(ii) shall be payable without regard to income of the Partnership and shall be treated for federal income tax purposes as guaranteed payments for the use of capital under Section 707(c) of the Code. The guaranteed payment with respect to any Series F Distribution Period shall be for the account of the holders of Series F Preferred Units as of the applicable Series F Distribution Record Date.

 

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(B) Not later than 5:00 p.m., New York City time, on each Series F Distribution Payment Date, the Partnership shall pay those Series F Distributions, if any, that shall have been declared by the General Partner to Series F Holders on the Record Date for the applicable Series F Distribution. The Record Date (the “Series F Distribution Record Date”) for the payment of any Series F Distributions shall be as of the close of business on the first Business Day of the month of the applicable Series F Distribution Payment Date, except that in the case of payments of Series F Distributions in Arrears, the Series F Distribution Record Date with respect to a Series F Distribution Payment Date shall be such date as may be designated by the General Partner in accordance with this Section 5.22. So long as any Series F Preferred Units are Outstanding, no distribution shall be declared or paid or set aside for payment on any Series F Junior Securities (other than a distribution payable solely in Series F Junior Securities) unless full cumulative Series F Distributions have been or contemporaneously are being paid or set apart for payment on all Outstanding Series F Preferred Units (and distributions on any other Series F Parity Securities) through the most recent respective Series F Distribution Payment Date (and distribution payment date with respect to such Series F Parity Securities, if any); provided, however, notwithstanding anything to the contrary in this Section 5.22(b)(ii)(B), if a distribution period with respect to a class of Series F Junior Securities or Series F Parity Securities is shorter than the Series F Distribution Period, the General Partner may declare and pay regular distributions with respect to such Series F Junior Securities or Series F Parity Securities, so long as, at the time of declaration of such distribution, (i) there are no Series F Distributions in Arrears, and (ii) the General Partner expects to have sufficient funds to pay the full distribution in respect of the Series F Preferred Units on the next successive Series F Distribution Payment Date. Accumulated Series F Distributions in Arrears for any past Series F Distribution Period may be declared by the General Partner and paid on any date fixed by the General Partner, whether or not a Series F Distribution Payment Date, to Series F Holders on the Record Date for such payment, which may not be less than 10 calendar days before such payment date. Subject to the next succeeding sentence, if all accumulated Series F Distributions in Arrears on all Outstanding Series F Preferred Units and all accumulated distributions in arrears on any Series F Parity Securities shall not have been declared and paid, or if sufficient funds for the payment thereof shall not have been set apart, payment of accumulated distributions in Arrears on the Series F Preferred Units and accumulated distributions in arrears on any such Series F Parity Securities shall be made in order of their respective distribution payment dates, commencing with the earliest distribution payment date. If less than all distributions payable with respect to all Series F Preferred Units and any other Series F Parity Securities are paid, any partial payment shall be made Pro Rata with respect to the Series F Preferred Units and any such other Series F Parity Securities entitled to a distribution payment at such time in proportion to the aggregate distribution amounts remaining due in respect of such Series F Preferred Units and such other Series F Parity Securities at such time. Subject to Section 12.4 and Section 5.22 (b)(v), Series F Holders shall not be entitled to any distribution, whether payable in cash, property or Partnership Securities, in excess of full cumulative Series F Distributions. Except insofar as distributions accrue on the amount of any accumulated and unpaid Series F Distributions as described in Section 5.22(b)(ii)(A), no interest or sum of money in lieu of interest shall be payable in respect of any distribution payment which may be in Arrears on the Series F Preferred Units. So long as the Series F Preferred Units are held of record by the Depositary or its nominee, declared Series F Distributions shall be paid to the Depositary in same-day funds on each Series F Distribution Payment Date or other distribution payment date in the case of payments for Series F Distributions in Arrears.

(C) The Series F Distribution Rate for each Series F Reset Period will be determined by the Calculation Agent for the Series F Preferred Units using the Series F Five-year U.S. Treasury Rate, as of the applicable Series F Reset Distribution Determination Date for such Series F Reset Period. The Calculation Agent for the Series F Preferred Units then will add the spread of 5.134% per annum to the Series F Five-year U.S. Treasury Rate as determined by the Calculation Agent as

 

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of the applicable Series F Reset Distribution Determination Date for such Series F Reset Period. Promptly following such determination by the Calculation Agent for the Series F Preferred Units, the Calculation Agent shall notify the Partnership of the Series F Distribution Rate for such Series F Reset Period. Such Calculation Agent’s determination of any Series F Distribution Rate for each Series F Reset Period and its calculation of the amount of Series F Distributions for any Series F Reset Period will be (i) available on file at the principal offices of the Partnership beginning on or after the Series F First Call Date, (ii) made available to any Series F Holder upon request and (iii) final and binding on each Series F Holder in the absence of manifest error.

(D) The Partnership will provide notice of the relevant Series F Five-year U.S. Treasury Rate as soon as practicable to the Transfer Agent and the Series F Holders.

(E) Notwithstanding the foregoing, unless otherwise determined by the General Partner, Series F Distributions shall be deemed to have been paid out of deductions from Available Cash with respect to the Quarter ended immediately preceding the Quarter in which the Series F Distribution is made.

(iii) Voting Rights.

(A) Notwithstanding anything to the contrary in this Agreement, the Series F Preferred Units shall not have any voting rights or rights to consent or approve any action or matter, except as set forth in Section 13.3(c), this Section 5.22(b)(iii) or as otherwise required by the Delaware Act.

(B) Notwithstanding anything to the contrary in this Agreement, without the affirmative vote or consent of the holders of at least 66 2/3% of the Outstanding Series F Preferred Units, voting as a separate class, the General Partner shall not adopt any amendment to this Agreement that the General Partner determines would have a material adverse effect on the powers, preferences, duties, or special rights of the Series F Preferred Units; provided, however, that (i) subject to Section 5.22(b)(iii)(C), the issuance of additional Partnership Securities (and any amendment to this Agreement in connection therewith) shall not be deemed to constitute such a material adverse effect for purposes of this Section 5.22(b)(iii)(B) and (ii) for purposes of this Section 5.22(b)(iii)(B), no amendment of this Agreement in connection with a merger or other transaction in which the Series F Preferred Units remain Outstanding with the terms thereof materially unchanged in any respect adverse to the Series F Holders (as determined by the General Partner) shall be deemed to materially and adversely affect the powers, preferences, duties, or special rights of the Series F Preferred Units.

(C) Notwithstanding anything to the contrary in this Agreement, without the affirmative vote or consent of the holders of at least 66 2/3% of the Outstanding Series F Preferred Units, voting as a class together with holders of any other Series F Parity Securities upon which like voting rights have been conferred and are exercisable, the Partnership shall not (x) create or issue any Series F Parity Securities (including any additional Series F Preferred Units) if the cumulative distributions payable on Outstanding Series F Preferred Units (or any Series F Parity Securities, if the holders of such Series F Parity Securities vote as a class together with the Series F Holders pursuant to this Section 5.22(b)(iii)(C)) are in Arrears or (y) create or issue any Series F Senior Securities.

(D) For any matter described in this Section 5.22(b)(iii) in which the Series F Holders are entitled to vote as a class (whether separately or together with the holders of any Series F Parity Securities), such Series F Holders shall be entitled to one vote per Series F Preferred Unit. Any Series F Preferred Units held by the Partnership or any of its Subsidiaries or their controlled Affiliates shall not be entitled to vote.

(E) Notwithstanding Section 5.22(b)(iii)(B) and Section 5.22(b)(iii)(C), no vote of the Series F Holders shall be required if, at or prior to the time when such action is to take effect, provision is made for the redemption of all Series F Preferred Units at the time Outstanding.

 

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(iv) Optional Redemption; Series F Rating Event.

(A) The Partnership shall have the right (i) on the Series F First Call Date or on any subsequent Series F Reset Date or (ii) at any time within 120 calendar days after the conclusion of any review or appeal process instituted by the Partnership following the occurrence of a Series F Rating Event, in each case, to redeem the Series F Preferred Units, which redemption may be in whole or in part (except with respect to a redemption pursuant to clause (ii) of this Section 5.22(b)(iv)(A) which shall be in whole but not in part), using any source of funds legally available for such purpose. Any such redemption shall occur on a date set by the General Partner (the “Series F Redemption Date”). The Partnership shall effect any such redemption by paying cash for each Series F Preferred Unit to be redeemed equal to 100% (in the case of a redemption described in clause (i) of this Section 5.22(b)(iv)(A)), or 102% (in the case of a redemption described in clause (ii) of this Section 5.22(b)(iv)(A)), of the Series F Liquidation Preference for such Series F Preferred Unit on such Series F Redemption Date plus an amount equal to all unpaid Series F Distributions thereon from the date of issuance to, but excluding, the Series F Redemption Date (whether or not such distributions shall have been declared) (the “Series F Redemption Price”). So long as the Series F Preferred Units to be redeemed are held of record by the Depositary or the nominee of the Depositary, the Series F Redemption Price shall be paid by the Paying Agent to the Depositary on the Series F Redemption Date.

(B) The Partnership shall give notice of any redemption by mail, postage prepaid, not less than 30 calendar days and not more than 60 calendar days before the scheduled Series F Redemption Date to the Series F Holders (as of 5:00 p.m. New York City time on the Business Day next preceding the day on which notice is given) of any Series F Preferred Units to be redeemed as such Series F Holders’ names appear on the books of the Transfer Agent and at the address of such Series F Holders shown therein. Such notice (the “Series F Redemption Notice”) shall state, as applicable: (1) the Series F Redemption Date, (2) the number of Series F Preferred Units to be redeemed and, if less than all Outstanding Series F Preferred Units are to be redeemed, the number (and in the case of Series F Preferred Units in certificated form, the identification) of Series F Preferred Units to be redeemed from such Series F Holder, (3) the Series F Redemption Price, (4) the place where any Series F Preferred Units in certificated form are to be redeemed and shall be presented and surrendered for payment of the Series F Redemption Price therefor (which shall occur automatically if the Certificate representing such Series F Preferred Units is issued in the name of the Depositary or its nominee), and (5) that distributions on the Series F Preferred Units to be redeemed shall cease to accumulate from and after such Series F Redemption Date.

(C) If the Partnership elects to redeem less than all of the Outstanding Series F Preferred Units, the number of Series F Preferred Units to be redeemed shall be determined by the General Partner, and such Series F Preferred Units shall be redeemed by such method of selection as the Depositary shall determine, either Pro Rata or by lot, with adjustments to avoid redemption of fractional Series F Preferred Units. The aggregate Series F Redemption Price for any such partial redemption of the Outstanding Series F Preferred Units shall be allocated correspondingly among the redeemed Series F Preferred Units. The Series F Preferred Units not redeemed shall remain Outstanding and entitled to all the rights, preferences and duties provided in this Section 5.22.

(D) If the Partnership gives or causes to be given a Series F Redemption Notice, the Partnership shall deposit with the Paying Agent funds sufficient to redeem the Series F Preferred Units as to which such Series F Redemption Notice shall have been given, no later than 10:00 a.m. New York City time on the Series F Redemption Date, and shall give the Paying Agent irrevocable instructions and authority to pay the Series F Redemption Price to each Series F Holder whose Series F Preferred Units are to be redeemed upon surrender or deemed surrender (which shall occur automatically if the Certificate representing such Series F Preferred Units is issued in the name of the Depositary or its nominee) of the Certificates therefor as set forth in the Series F Redemption Notice. If a Series F Redemption Notice shall have been given, from and

 

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after the Series F Redemption Date, unless the Partnership defaults in providing funds sufficient for such redemption at the time and place specified for payment pursuant to the Series F Redemption Notice, all Series F Distributions on such Series F Preferred Units to be redeemed shall cease to accumulate and all rights of holders of such Series F Preferred Units as Limited Partners with respect to such Series F Preferred Units to be redeemed shall cease, except the right to receive the Series F Redemption Price, and such Series F Preferred Units shall not thereafter be transferred on the books of the Transfer Agent or be deemed to be Outstanding for any purpose whatsoever. The Series F Holders shall have no claim to the interest income, if any, earned on funds deposited with the Paying Agent. Any funds deposited with the Paying Agent hereunder by the Partnership for any reason, including redemption of Series F Preferred Units, that remain unclaimed or unpaid after one year after the applicable Series F Redemption Date or other payment date, as applicable, shall be, to the extent permitted by law, repaid to the Partnership upon its written request, after which repayment the Series F Holders entitled to such redemption or other payment shall have recourse only to the Partnership. Notwithstanding any Series F Redemption Notice, there shall be no redemption of any Series F Preferred Units called for redemption until funds sufficient to pay the full Series F Redemption Price of such Series F Preferred Units shall have been deposited by the Partnership with the Paying Agent.

(E) Any Series F Preferred Units that are redeemed or otherwise acquired by the Partnership shall be cancelled. If only a portion of the Series F Preferred Units represented by a Certificate shall have been called for redemption, upon surrender of the Certificate to the Paying Agent (which shall occur automatically if the Certificate representing such Series F Preferred Units is registered in the name of the Depositary or its nominee), the Partnership shall issue and the Paying Agent shall deliver to the Series F Holders a new Certificate (or adjust the applicable book-entry account) representing the number of Series F Preferred Units represented by the surrendered Certificate that have not been called for redemption.

(F) Notwithstanding anything to the contrary in this Section 5.22, in the event that full cumulative distributions on the Series F Preferred Units and any Series F Parity Securities shall not have been paid or declared and set aside for payment, the Partnership shall not be permitted to repurchase, redeem or otherwise acquire, in whole or in part, any Series F Preferred Units or Series F Parity Securities except pursuant to a purchase or exchange offer made on the same relative terms to all Series F Holders and holders of any Series F Parity Securities. Subject to Section 4.9, so long as any Series F Preferred Units are Outstanding, the Partnership shall not be permitted to redeem, repurchase or otherwise acquire any Common Units or any other Series F Junior Securities unless full cumulative distributions on the Series F Preferred Units and any Series F Parity Securities for all prior and the then-ending Series F Distribution Periods, with respect to the Series F Preferred Units, and all prior and then ending distribution periods, with respect to any such Series F Parity Securities, shall have been paid or declared and set aside for payment.

(v) Liquidation Rights.

In the event of the dissolution and winding up of the Partnership under Section 12.4 or a sale, exchange, or other disposition of all or substantially all of the assets of the Partnership, either voluntary or involuntary, the Record Holders of the Series F Preferred Units shall be entitled to receive, out of the assets of the Partnership available for distribution to the Partners or any Assignees, prior and in preference to any distribution of any assets of the Partnership to the Record Holders of any other class or series of Partnership Interests (other than Series F Senior Securities or Series F Parity Securities), (i) first, any accumulated and unpaid distributions on the Series F Preferred Units (regardless of whether previously declared) and (ii) then, any positive value in each such holder’s Capital Account in respect of such Series F Preferred Units. If in the year of such dissolution and winding up, or sale, exchange, or other disposition of all or substantially all of the assets of the Partnership, any such Record Holder’s Capital Account in

 

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respect of such Series F Preferred Units is less than the aggregate Series F Base Liquidation Preference of such Series F Preferred Units, then, notwithstanding anything to the contrary contained in this Agreement, and prior to any other allocation pursuant to this Agreement for such year and any distribution pursuant to the preceding sentence (other than any allocations or distributions made with respect to any other Series F Parity Securities upon which like allocation and distribution rights have been conferred), items of gross income and gain shall be allocated to all Unitholders then holding Series F Preferred Units, Pro Rata, until the Capital Account in respect of each Outstanding Series F Preferred Unit is equal to the Series F Base Liquidation Preference (and no other allocation pursuant to this Agreement shall reverse the effect of such allocation); provided, however, that in the event that like allocation rights have been conferred upon other Series F Parity Securities (including pursuant to Sections 5.17(b)(v), 5.18(b)(v), 5.19(b)(v), 5.20(b)(v), 5.21(b)(v) and 5.23(b)(v)), then items of gross income and gain shall be allocated to all Unitholders then holding Series F Preferred Units and such Series F Parity Securities, Pro Rata, until the Capital Account in respect of each Outstanding Series F Preferred Unit and such Series F Parity Security is equal to the applicable liquidation preference (and no other allocation pursuant to this Agreement shall reverse the effect of such allocation). If in the year of such dissolution and winding up any such Record Holder’s Capital Account in respect of such Series F Preferred Units is less than the aggregate Series F Base Liquidation Preference of such Series F Preferred Units after the application of the preceding sentence, then to the extent permitted by applicable law, but otherwise notwithstanding anything to the contrary contained in this Agreement, items of gross income and gain for any preceding taxable year(s) with respect to which IRS Form 1065 Schedules K-1 have not been filed by the Partnership shall be reallocated to all Unitholders then holding Series F Preferred Units, Pro Rata, until the Capital Account in respect of each such Outstanding Series F Preferred Unit after making allocations pursuant to this and the immediately preceding sentence is equal to the Series F Base Liquidation Preference (and no other allocation pursuant to this Agreement shall reverse the effect of such allocation); provided, however, that in the event like allocation rights have been conferred upon other Series F Parity Securities (including pursuant to Sections 5.17(b)(v), 5.18(b)(v), 5.19(b)(v), 5.20(b)(v), 5.21(b)(v) and 5.23(b)(v)), then any such items of gross income and gain shall be reallocated to all Unitholders then holding Series F Preferred Units and such Series F Parity Securities, Pro Rata, until the Capital Account in respect of each Outstanding Series F Preferred Unit and such Series F Parity Security after making allocations pursuant to this and the immediately preceding sentence is equal to the applicable liquidation preference (and no other allocation pursuant to this Agreement shall reverse the effect of such allocation). After such allocations have been made to the Outstanding Series F Preferred Units and any Series F Parity Securities, as applicable, any remaining Net Termination Gain or Net Termination Loss shall be allocated to the Partners pursuant to Section 6.1(c) or Section 6.1(d), as the case may be. At the time of the dissolution of the Partnership, subject to Section 17-804 of the Delaware Act, the Record Holders of the Series F Preferred Units shall become entitled to receive any distributions in respect of the Series F Preferred Units that are accrued and unpaid as of the date of such distribution, and shall have the status of, and shall be entitled to all remedies available to, a creditor of the Partnership, and such entitlement of the Record Holders of the Series F Preferred Units to such accrued and unpaid distributions shall have priority over any entitlement of any other Partners or Assignees (other than holders of any Series F Senior Securities or Series F Parity Securities) with respect to any distributions by the Partnership to such other Partners or Assignees; provided, however, that the General Partner, as such, will have no liability for any obligations with respect to such distributions to any Record Holder(s) of Series F Preferred Units.

 

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(vi) Rank.

The Series F Preferred Units shall each be deemed to rank as to distributions on such Partnership Securities and distributions upon liquidation of the Partnership:

(A) senior to any Series F Junior Securities;

(B) on a parity with any Series F Parity Securities;

(C) junior to any Series F Senior Securities; and

(D) junior to all existing and future indebtedness of the Partnership and other liabilities with respect to assets available to satisfy claims against the Partnership.

(vii) No Sinking Fund.

The Series F Preferred Units shall not have the benefit of any sinking fund.

(viii) Record Holders.

To the fullest extent permitted by applicable law, the General Partner, the Partnership, the Transfer Agent, and the Paying Agent may deem and treat any Series F Holder as the true, lawful, and absolute owner of the applicable Series F Preferred Units for all purposes, and none of the General Partner, the Partnership, the Transfer Agent or the Paying Agent shall be affected by any notice to the contrary, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which the Series F Preferred Units may be listed or admitted to trading, if any.

(ix) Notices. All notices or other communications in respect of Series F Holders shall be sufficiently given (i) if given in writing and either delivered in person or by first class mail, postage prepaid, or (ii) if given in such other manner as may be permitted in this Section 5.22, the Agreement or by applicable law.

(x) Other Rights; Fiduciary Duties.

The Series F Preferred Units and the Series F Holders shall not have any designations, preferences, rights, powers or duties, other than as set forth in this Agreement or as provided by applicable law. Notwithstanding anything to the contrary in this Agreement or any duty existing at law, in equity or otherwise, to the fullest extent permitted by applicable law, neither the General Partner nor any other Indemnitee shall owe any duties, including fiduciary duties, or have any liabilities to Series F Holders, other than the implied contractual covenant of good faith and fair dealing.

Section 5.23 Establishment of Series G Preferred Units.

(a) General. The Partnership hereby designates and creates a class of Partnership Securities to be designated as “7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units” (the “Series G Preferred Units”), having the preferences, rights, powers, and duties set forth herein, including this Section 5.23. Each Series G Preferred Unit shall be identical in all respects to every other Series G Preferred Unit, except as to the respective dates from which the Series G Liquidation Preference shall increase or from which Series G Distributions may begin accruing, to the extent such dates may differ. The Series G Preferred Units represent perpetual equity interests in the Partnership and shall not give rise to a claim by the Partnership or a Series G Holder for conversion or, except as set forth in Section 5.23(b)(iv), redemption thereof at a particular date.

 

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(b) Rights of Series G Preferred Units. The Series G Preferred Units shall have the following rights, preferences and privileges and shall be subject to the following duties and obligations:

(i) Series G Preferred Units.

(A) The authorized number of Series G Preferred Units shall be unlimited. Series G Preferred Units that are purchased or otherwise acquired by the Partnership shall be cancelled.

(B) The Series G Preferred Units shall be represented by one or more global Certificates registered in the name of the Depositary or its nominee, and no Series G Holder shall be entitled to receive a definitive Certificate evidencing its Series G Preferred Units, unless (1) requested by a Series G Holder and consented to by the General Partner in its sole discretion, (2) otherwise required by law or (3) the Depositary gives notice of its intention to resign or is no longer eligible to act as such with respect to the Series G Preferred Units and the General Partner shall have not selected a substitute Depositary within 60 calendar days thereafter. So long as the Depositary shall have been appointed and is serving with respect to the Series G Preferred Units, payments and communications made by the Partnership to Series G Holders shall be made by making payments to, and communicating with, the Depositary.

(ii) Distributions.

(A) Distributions on each Outstanding Series G Preferred Unit shall be cumulative and shall accumulate at the applicable Series G Distribution Rate from and including [ ● ], 2021 (or, for any subsequently issued and newly Outstanding Series G Preferred Units, from and including the Series G Distribution Payment Date immediately preceding the issue date of such Series G Preferred Units) until such time as the Partnership pays the Series G Distribution or redeems such Series G Preferred Unit in accordance with Section 5.23(b)(iv), whether or not such Series G Distributions shall have been declared. Series G Holders shall be entitled to receive Series G Distributions from time to time out of any assets of the Partnership legally available for the payment of distributions at the Series G Distribution Rate per Series G Preferred Unit when, as, and, if declared by the General Partner. Series G Distributions, to the extent declared by the General Partner to be paid by the Partnership in accordance with this Section 5.23(b)(ii), shall be paid, in Arrears, on each Series G Distribution Payment Date. Series G Distributions shall accumulate in each Series G Distribution Period from and including the preceding Series G Distribution Payment Date (other than the initial Series G Distribution Period, which shall commence on and include [ ● ], 2021), to, but excluding, the next Series G Distribution Payment Date for such Series G Distribution Period; provided that distributions shall accrue on accumulated but unpaid Series G Distributions at the Series G Distribution Rate. If any Series G Distribution Payment Date otherwise would occur on a date that is not a Business Day, declared Series G Distributions shall be paid on the immediately succeeding Business Day without the accumulation of additional distributions. All Series G Distributions that are (1) accumulated and unpaid or (2) payable by the Partnership pursuant to this Section 5.23(b)(ii) shall be payable without regard to income of the Partnership and shall be treated for federal income tax purposes as guaranteed payments for the use of capital under Section 707(c) of the Code. The guaranteed payment with respect to any Series G Distribution Period shall be for the account of the holders of Series G Preferred Units as of the applicable Series G Distribution Record Date.

(B) Not later than 5:00 p.m., New York City time, on each Series G Distribution Payment Date, the Partnership shall pay those Series G Distributions, if any, that shall have been declared by the General Partner to Series G Holders on the Record Date for the applicable Series G Distribution. The Record Date (the “Series G Distribution Record Date”) for the payment of any Series G Distributions shall be as of the close of business on the first Business Day of the month of the applicable Series G Distribution Payment Date, except that in the case of payments of Series G Distributions in Arrears, the Series G Distribution Record Date with respect to a Series G Distribution Payment Date shall be such date as may be designated by the General Partner in

 

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accordance with this Section 5.23. So long as any Series G Preferred Units are Outstanding, no distribution shall be declared or paid or set aside for payment on any Series G Junior Securities (other than a distribution payable solely in Series G Junior Securities) unless full cumulative Series G Distributions have been or contemporaneously are being paid or set apart for payment on all Outstanding Series G Preferred Units (and distributions on any other Series G Parity Securities) through the most recent respective Series G Distribution Payment Date (and distribution payment date with respect to such Series G Parity Securities, if any); provided, however, notwithstanding anything to the contrary in this Section 5.23(b)(ii)(B), if a distribution period with respect to a class of Series G Junior Securities or Series G Parity Securities is shorter than the Series G Distribution Period, the General Partner may declare and pay regular distributions with respect to such Series G Junior Securities or Series G Parity Securities, so long as, at the time of declaration of such distribution, (i) there are no Series G Distributions in Arrears, and (ii) the General Partner expects to have sufficient funds to pay the full distribution in respect of the Series G Preferred Units on the next successive Series G Distribution Payment Date. Accumulated Series G Distributions in Arrears for any past Series G Distribution Period may be declared by the General Partner and paid on any date fixed by the General Partner, whether or not a Series G Distribution Payment Date, to Series G Holders on the Record Date for such payment, which may not be less than 10 calendar days before such payment date. Subject to the next succeeding sentence, if all accumulated Series G Distributions in Arrears on all Outstanding Series G Preferred Units and all accumulated distributions in arrears on any Series G Parity Securities shall not have been declared and paid, or if sufficient funds for the payment thereof shall not have been set apart, payment of accumulated distributions in Arrears on the Series G Preferred Units and accumulated distributions in arrears on any such Series G Parity Securities shall be made in order of their respective distribution payment dates, commencing with the earliest distribution payment date. If less than all distributions payable with respect to all Series G Preferred Units and any other Series G Parity Securities are paid, any partial payment shall be made Pro Rata with respect to the Series G Preferred Units and any such other Series G Parity Securities entitled to a distribution payment at such time in proportion to the aggregate distribution amounts remaining due in respect of such Series G Preferred Units and such other Series G Parity Securities at such time. Subject to Section 12.4 and Section 5.23(b)(v), Series G Holders shall not be entitled to any distribution, whether payable in cash, property or Partnership Securities, in excess of full cumulative Series G Distributions. Except insofar as distributions accrue on the amount of any accumulated and unpaid Series G Distributions as described in Section 5.23(b)(ii)(A), no interest or sum of money in lieu of interest shall be payable in respect of any distribution payment which may be in Arrears on the Series G Preferred Units. So long as the Series G Preferred Units are held of record by the Depositary or its nominee, declared Series G Distributions shall be paid to the Depositary in same-day funds on each Series G Distribution Payment Date or other distribution payment date in the case of payments for Series G Distributions in Arrears.

(C) The Series G Distribution Rate for each Series G Reset Period will be determined by the Calculation Agent for the Series G Preferred Units using the Series G Five-year U.S. Treasury Rate, as of the applicable Series G Reset Distribution Determination Date for such Series G Reset Period. The Calculation Agent for the Series G Preferred Units then will add the spread of 5.306% per annum to the Series G Five-year U.S. Treasury Rate as determined by the Calculation Agent as of the applicable Series G Reset Distribution Determination Date for such Series G Reset Period. Promptly following such determination by the Calculation Agent for the Series G Preferred Units, the Calculation Agent shall notify the Partnership of the Series G Distribution Rate for such Series G Reset Period. Such Calculation Agent’s determination of any Series G Distribution Rate for each Series G Reset Period and its calculation of the amount of Series G Distributions for any Series G Reset Period will be (i) available on file at the principal offices of the Partnership beginning on or after the Series G First Call Date, (ii) made available to any Series

 

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G Holder upon request and (iii) final and binding on each Series G Holder in the absence of manifest error.

(D) The Partnership will provide notice of the relevant Series G Five-year U.S. Treasury Rate as soon as practicable to the Transfer Agent and the Series G Holders.

(E) Notwithstanding the foregoing, unless otherwise determined by the General Partner, Series G Distributions shall be deemed to have been paid out of deductions from Available Cash with respect to the Quarter ended immediately preceding the Quarter in which the Series G Distribution is made.

(iii) Voting Rights.

(A) Notwithstanding anything to the contrary in this Agreement, the Series G Preferred Units shall not have any voting rights or rights to consent or approve any action or matter, except as set forth in Section 13.3(c), this Section 5.23(b)(iii) or as otherwise required by the Delaware Act.

(B) Notwithstanding anything to the contrary in this Agreement, without the affirmative vote or consent of the holders of at least 66 2/3% of the Outstanding Series G Preferred Units, voting as a separate class, the General Partner shall not adopt any amendment to this Agreement that the General Partner determines would have a material adverse effect on the powers, preferences, duties, or special rights of the Series G Preferred Units; provided, however, that (i) subject to Section 5.23(b)(iii)(C), the issuance of additional Partnership Securities (and any amendment to this Agreement in connection therewith) shall not be deemed to constitute such a material adverse effect for purposes of this Section 5.23(b)(iii)(B) and (ii) for purposes of this Section 5.23(b)(iii)(B), no amendment of this Agreement in connection with a merger or other transaction in which the Series G Preferred Units remain Outstanding with the terms thereof materially unchanged in any respect adverse to the Series G Holders (as determined by the General Partner) shall be deemed to materially and adversely affect the powers, preferences, duties, or special rights of the Series G Preferred Units.

(C) Notwithstanding anything to the contrary in this Agreement, without the affirmative vote or consent of the holders of at least 66 2/3% of the Outstanding Series G Preferred Units, voting as a class together with holders of any other Series G Parity Securities upon which like voting rights have been conferred and are exercisable, the Partnership shall not (x) create or issue any Series G Parity Securities (including any additional Series G Preferred Units) if the cumulative distributions payable on Outstanding Series G Preferred Units (or any Series G Parity Securities, if the holders of such Series G Parity Securities vote as a class together with the Series G Holders pursuant to this Section 5.23(b)(iii)(C)) are in Arrears or (y) create or issue any Series G Senior Securities.

(D) For any matter described in this Section 5.23(b)(iii) in which the Series G Holders are entitled to vote as a class (whether separately or together with the holders of any Series G Parity Securities), such Series G Holders shall be entitled to one vote per Series G Preferred Unit. Any Series G Preferred Units held by the Partnership or any of its Subsidiaries or their controlled Affiliates shall not be entitled to vote.

(E) Notwithstanding Section 5.23(b)(iii)(B) and Section 5.23(b)(iii)(C), no vote of the Series G Holders shall be required if, at or prior to the time when such action is to take effect, provision is made for the redemption of all Series G Preferred Units at the time Outstanding.

(iv) Optional Redemption; Series G Rating Event.

(A) The Partnership shall have the right (i) on the Series G First Call Date or on any subsequent Series G Reset Date or (ii) at any time within 120 calendar days after the conclusion of any review or appeal process instituted by the Partnership following the occurrence of a Series G Rating Event, in each case, to redeem the Series G Preferred Units, which redemption may be in whole or in part (except with respect to a redemption pursuant to clause (ii) of this

 

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Section 5.23(b)(iv)(A) which shall be in whole but not in part), using any source of funds legally available for such purpose. Any such redemption shall occur on a date set by the General Partner (the “Series G Redemption Date”). The Partnership shall effect any such redemption by paying cash for each Series G Preferred Unit to be redeemed equal to 100% (in the case of a redemption described in clause (i) of this Section 5.23(b)(iv)(A)), or 102% (in the case of a redemption described in clause (ii) of this Section 5.23(b)(iv)(A)), of the Series G Liquidation Preference for such Series G Preferred Unit on such Series G Redemption Date plus an amount equal to all unpaid Series G Distributions thereon from the date of issuance to, but excluding, the Series G Redemption Date (whether or not such distributions shall have been declared) (the “Series G Redemption Price”). So long as the Series G Preferred Units to be redeemed are held of record by the Depositary or the nominee of the Depositary, the Series G Redemption Price shall be paid by the Paying Agent to the Depositary on the Series G Redemption Date.

(B) The Partnership shall give notice of any redemption by mail, postage prepaid, not less than 30 calendar days and not more than 60 calendar days before the scheduled Series G Redemption Date to the Series G Holders (as of 5:00 p.m. New York City time on the Business Day next preceding the day on which notice is given) of any Series G Preferred Units to be redeemed as such Series G Holders’ names appear on the books of the Transfer Agent and at the address of such Series G Holders shown therein. Such notice (the “Series G Redemption Notice”) shall state, as applicable: (1) the Series G Redemption Date, (2) the number of Series G Preferred Units to be redeemed and, if less than all Outstanding Series G Preferred Units are to be redeemed, the number (and in the case of Series G Preferred Units in certificated form, the identification) of Series G Preferred Units to be redeemed from such Series G Holder, (3) the Series G Redemption Price, (4) the place where any Series G Preferred Units in certificated form are to be redeemed and shall be presented and surrendered for payment of the Series G Redemption Price therefor (which shall occur automatically if the Certificate representing such Series G Preferred Units is issued in the name of the Depositary or its nominee), and (5) that distributions on the Series G Preferred Units to be redeemed shall cease to accumulate from and after such Series G Redemption Date.

(C) If the Partnership elects to redeem less than all of the Outstanding Series G Preferred Units, the number of Series G Preferred Units to be redeemed shall be determined by the General Partner, and such Series G Preferred Units shall be redeemed by such method of selection as the Depositary shall determine, either Pro Rata or by lot, with adjustments to avoid redemption of fractional Series G Preferred Units. The aggregate Series G Redemption Price for any such partial redemption of the Outstanding Series G Preferred Units shall be allocated correspondingly among the redeemed Series G Preferred Units. The Series G Preferred Units not redeemed shall remain Outstanding and entitled to all the rights, preferences and duties provided in this Section 5.23.

(D) If the Partnership gives or causes to be given a Series G Redemption Notice, the Partnership shall deposit with the Paying Agent funds sufficient to redeem the Series G Preferred Units as to which such Series G Redemption Notice shall have been given, no later than 10:00 a.m. New York City time on the Series G Redemption Date, and shall give the Paying Agent irrevocable instructions and authority to pay the Series G Redemption Price to each Series G Holder whose Series G Preferred Units are to be redeemed upon surrender or deemed surrender (which shall occur automatically if the Certificate representing such Series G Preferred Units is issued in the name of the Depositary or its nominee) of the Certificates therefor as set forth in the Series G Redemption Notice. If a Series G Redemption Notice shall have been given, from and after the Series G Redemption Date, unless the Partnership defaults in providing funds sufficient for such redemption at the time and place specified for payment pursuant to the Series G Redemption Notice, all Series G Distributions on such Series G Preferred Units to be redeemed shall cease to accumulate and all rights of holders of such Series G Preferred Units as Limited Partners with respect to such Series G Preferred Units to be redeemed shall cease, except the right

 

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to receive the Series G Redemption Price, and such Series G Preferred Units shall not thereafter be transferred on the books of the Transfer Agent or be deemed to be Outstanding for any purpose whatsoever. The Series G Holders shall have no claim to the interest income, if any, earned on funds deposited with the Paying Agent. Any funds deposited with the Paying Agent hereunder by the Partnership for any reason, including redemption of Series G Preferred Units, that remain unclaimed or unpaid after one year after the applicable Series G Redemption Date or other payment date, as applicable, shall be, to the extent permitted by law, repaid to the Partnership upon its written request, after which repayment the Series G Holders entitled to such redemption or other payment shall have recourse only to the Partnership. Notwithstanding any Series G Redemption Notice, there shall be no redemption of any Series G Preferred Units called for redemption until funds sufficient to pay the full Series G Redemption Price of such Series G Preferred Units shall have been deposited by the Partnership with the Paying Agent.

(E) Any Series G Preferred Units that are redeemed or otherwise acquired by the Partnership shall be cancelled. If only a portion of the Series G Preferred Units represented by a Certificate shall have been called for redemption, upon surrender of the Certificate to the Paying Agent (which shall occur automatically if the Certificate representing such Series G Preferred Units is registered in the name of the Depositary or its nominee), the Partnership shall issue and the Paying Agent shall deliver to the Series G Holders a new Certificate (or adjust the applicable book-entry account) representing the number of Series G Preferred Units represented by the surrendered Certificate that have not been called for redemption.

(F) Notwithstanding anything to the contrary in this Section 5.23, in the event that full cumulative distributions on the Series G Preferred Units and any Series G Parity Securities shall not have been paid or declared and set aside for payment, the Partnership shall not be permitted to repurchase, redeem or otherwise acquire, in whole or in part, any Series G Preferred Units or Series G Parity Securities except pursuant to a purchase or exchange offer made on the same relative terms to all Series G Holders and holders of any Series G Parity Securities. Subject to Section 4.9, so long as any Series G Preferred Units are Outstanding, the Partnership shall not be permitted to redeem, repurchase or otherwise acquire any Common Units or any other Series G Junior Securities unless full cumulative distributions on the Series G Preferred Units and any Series G Parity Securities for all prior and the then-ending Series G Distribution Periods, with respect to the Series G Preferred Units, and all prior and then ending distribution periods, with respect to any such Series G Parity Securities, shall have been paid or declared and set aside for payment.

(v) Liquidation Rights.

In the event of the dissolution and winding up of the Partnership under Section 12.4 or a sale, exchange, or other disposition of all or substantially all of the assets of the Partnership, either voluntary or involuntary, the Record Holders of the Series G Preferred Units shall be entitled to receive, out of the assets of the Partnership available for distribution to the Partners or any Assignees, prior and in preference to any distribution of any assets of the Partnership to the Record Holders of any other class or series of Partnership Interests (other than Series G Senior Securities or Series G Parity Securities), (i) first, any accumulated and unpaid distributions on the Series G Preferred Units (regardless of whether previously declared) and (ii) then, any positive value in each such holder’s Capital Account in respect of such Series G Preferred Units. If in the year of such dissolution and winding up, or sale, exchange, or other disposition of all or substantially all of the assets of the Partnership, any such Record Holder’s Capital Account in respect of such Series G Preferred Units is less than the aggregate Series G Base Liquidation Preference of such Series G Preferred Units, then, notwithstanding anything to the contrary contained in this Agreement, and prior to any other allocation pursuant to this Agreement for such year and any distribution pursuant to the preceding sentence (other than any allocations or distributions made with respect to any other Series G Parity Securities upon which like allocation

 

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and distribution rights have been conferred), items of gross income and gain shall be allocated to all Unitholders then holding Series G Preferred Units, Pro Rata, until the Capital Account in respect of each Outstanding Series G Preferred Unit is equal to the Series G Base Liquidation Preference (and no other allocation pursuant to this Agreement shall reverse the effect of such allocation); provided, however, that in the event that like allocation rights have been conferred upon other Series G Parity Securities (including pursuant to Sections 5.17(b)(v), 5.18(b)(v), 5.19(b)(v), 5.20(b)(v), 5.21(b)(v) and 5.22(b)(v)), then items of gross income and gain shall be allocated to all Unitholders then holding Series G Preferred Units and such Series G Parity Securities, Pro Rata, until the Capital Account in respect of each Outstanding Series G Preferred Unit and such Series G Parity Security is equal to the applicable liquidation preference (and no other allocation pursuant to this Agreement shall reverse the effect of such allocation). If in the year of such dissolution and winding up any such Record Holder’s Capital Account in respect of such Series G Preferred Units is less than the aggregate Series G Base Liquidation Preference of such Series G Preferred Units after the application of the preceding sentence, then to the extent permitted by applicable law, but otherwise notwithstanding anything to the contrary contained in this Agreement, items of gross income and gain for any preceding taxable year(s) with respect to which IRS Form 1065 Schedules K-1 have not been filed by the Partnership shall be reallocated to all Unitholders then holding Series G Preferred Units, Pro Rata, until the Capital Account in respect of each such Outstanding Series G Preferred Unit after making allocations pursuant to this and the immediately preceding sentence is equal to the Series G Base Liquidation Preference (and no other allocation pursuant to this Agreement shall reverse the effect of such allocation); provided, however, that in the event like allocation rights have been conferred upon other Series G Parity Securities (including pursuant to Sections 5.17(b)(v), 5.18(b)(v), 5.19(b)(v), 5.20(b)(v), 5.21(b)(v) and 5.22(b)(v)), then any such items of gross income and gain shall be reallocated to all Unitholders then holding Series G Preferred Units and such Series G Parity Securities, Pro Rata, until the Capital Account in respect of each Outstanding Series G Preferred Unit and such Series G Parity Security after making allocations pursuant to this and the immediately preceding sentence is equal to the applicable liquidation preference (and no other allocation pursuant to this Agreement shall reverse the effect of such allocation). After such allocations have been made to the Outstanding Series G Preferred Units and any Series G Parity Securities, as applicable, any remaining Net Termination Gain or Net Termination Loss shall be allocated to the Partners pursuant to Section 6.1(c) or Section 6.1(d), as the case may be. At the time of the dissolution of the Partnership, subject to Section 17-804 of the Delaware Act, the Record Holders of the Series G Preferred Units shall become entitled to receive any distributions in respect of the Series G Preferred Units that are accrued and unpaid as of the date of such distribution, and shall have the status of, and shall be entitled to all remedies available to, a creditor of the Partnership, and such entitlement of the Record Holders of the Series G Preferred Units to such accrued and unpaid distributions shall have priority over any entitlement of any other Partners or Assignees (other than holders of any Series G Senior Securities or Series G Parity Securities) with respect to any distributions by the Partnership to such other Partners or Assignees; provided, however, that the General Partner, as such, will have no liability for any obligations with respect to such distributions to any Record Holder(s) of Series G Preferred Units.

(vi) Rank.

The Series G Preferred Units shall each be deemed to rank as to distributions on such Partnership Securities and distributions upon liquidation of the Partnership:

(A) senior to any Series G Junior Securities;

(B) on a parity with any Series G Parity Securities;

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(D) junior to all existing and future indebtedness of the Partnership and other liabilities with respect to assets available to satisfy claims against the Partnership.

(vii) No Sinking Fund.

The Series G Preferred Units shall not have the benefit of any sinking fund.

(viii) Record Holders.

To the fullest extent permitted by applicable law, the General Partner, the Partnership, the Transfer Agent, and the Paying Agent may deem and treat any Series G Holder as the true, lawful, and absolute owner of the applicable Series G Preferred Units for all purposes, and none of the General Partner, the Partnership, the Transfer Agent or the Paying Agent shall be affected by any notice to the contrary, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which the Series G Preferred Units may be listed or admitted to trading, if any.

(ix) Notices. All notices or other communications in respect of Series G Holders shall be sufficiently given (i) if given in writing and either delivered in person or by first class mail, postage prepaid, or (ii) if given in such other manner as may be permitted in this Section 5.23, the Agreement or by applicable law.

(x) Other Rights; Fiduciary Duties.

The Series G Preferred Units and the Series G Holders shall not have any designations, preferences, rights, powers or duties, other than as set forth in this Agreement or as provided by applicable law. Notwithstanding anything to the contrary in this Agreement or any duty existing at law, in equity or otherwise, to the fullest extent permitted by applicable law, neither the General Partner nor any other Indemnitee shall owe any duties, including fiduciary duties, or have any liabilities to Series G Holders, other than the implied contractual covenant of good faith and fair dealing.”

Section 5.24 Establishment of Class B Units.

(a) General. The Partnership hereby designates and creates a class of Partnership Securities to be designated as “Class B Units” (the “Class B Units”), having the preferences, rights, powers and duties set forth herein, including this Section 5.24. In accordance with Section 5.8, the General Partner shall have the power and authority to issue additional Class B Units in the future.

(b) Rights of Class B Units. The Class B Units shall have the following rights, preferences and privileges and shall be subject to the following duties and obligations:

(i) Initial Capital Account. The initial Capital Account with respect to each Class B Unit will be equal to the Class B Unit Issue Price. For the avoidance of doubt, the sum of the initial Capital Accounts with respect to each Class B Unit as of the Effective Date is equal to the sum of the Capital Accounts of each Recapitalized Unit issued to ETP Holdco as of the Effective Date.

(ii) Allocations.

(A) The holders of Class B Units shall not be entitled to receive (1) any allocations of ETP Holdco Items, and (2) except as otherwise provided in this Section 5.24(b)(ii), allocations of (a) Net Income pursuant to Section 6.1(a), (b) Net Loss pursuant to Section 6.1(b), or (c) Net Termination Gains and Losses pursuant to Section 6.1(c).

(B) With respect to each taxable period, the holders of the Class B Units shall be allocated, Pro Rata in proportion to the number of Class B Units of the holders, items of Partnership gross income, gain, loss or deduction (other than from ETP Holdco Items and items of Partnership depreciation, amortization and cost recovery deductions) until the aggregate amount of such items allocated to the holders of the Class B Units pursuant to this Section 5.24(b)(ii)(B) for the current

 

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taxable period and all previous taxable periods is equal to the cumulative amount of all distributions made to the holders of the Class B Units pursuant to Section 5.24(b)(iii).

(C) Items of Partnership depreciation, amortization and cost recovery deductions (other than from ETP Holdco Items) with respect to each taxable period shall be allocated to the holders of Class B Units to the extent such items would be allocated to the holders of Class B Units as if each Class B Unit was treated as a Common Unit.

(D) With respect to each taxable period, after the application of Section 6.1(c)(i)(B) but before the application of Section 6.1(c)(i)(C), Net Termination Gain (other than from ETP Holdco Items) shall be allocated to the holders of the Class B Units, until the Capital Account of each Class B Unit is equal to the Class B Unit Issue Price.

(E) For each taxable period, after the application of Section 6.1(c)(i)(B) but before the application of Section 6.1(c)(i)(C), and after making the allocations provided for in Section 5.24(b)(ii)(D), the holder of the Class B Units shall be allocated, 1% of the remaining aggregate Net Termination Gain (other than from ETP Holdco Items), if any, that is to be allocated pursuant to Section 6.1(c)(i)(C); provided, however, that an allocation shall only be made to the holder of Class B Units pursuant to this Section 5.24(b)(ii)(E) if the Capital Account of each Common Unit is equal to or greater than the Class B Unit Issue Price immediately prior to making such allocation.

(F) For each taxable period, after the application of Section 6.1(c)(ii)(B), but before the application of Section 6.1(c)(ii)(C), the holders of the Class B Units shall be allocated Net Termination Loss (other than from ETP Holdco Items) until the Capital Account in respect of each Class B Unit has been reduced to zero.

(G) For the purposes of effectuating the intent of the foregoing allocation provisions, the General Partner shall have the sole discretion to make special allocations of items of Partnership gross income, gain, loss or deductions among the General Partner and the Unitholders as it deems reasonable.

(iii) Distributions.

(A) For each taxable period, no portion of any Partnership cash distribution attributable to ETP Holdco Distributions shall be distributed to the holders of the Class B Units.

(B) Commencing with the Class B Unit Issuance Date, the holder of the Class B Units as of an applicable Record Date shall be entitled to receive distributions (each, a “Class B Unit Quarterly Distribution”) in cash in an amount equal to the Class B Unit Distribution Rate on all Outstanding Class B Units. Distributions shall be paid Quarterly, in arrears, within 50 days after the end of each Quarter. Each Record Date established for paying a Class B Unit Quarterly Distribution in respect of any Quarter shall be the same Record Date established for any distribution to be made by the Partnership in respect of other Partnership Interests pursuant to Section 6.3. If the Partnership is unable to pay the Class B Unit Quarterly Distribution with respect to any Quarter, (1) the amount of such accrued and unpaid distributions will accumulate until paid in full in cash and (2) the balance of such accrued and unpaid distributions shall increase at a rate of 1.5% per annum, compounded quarterly, from the date such distribution was due until the date it is paid. For the avoidance of doubt, except as set forth in this Section 5.24(b)(iii)(B) or Article XII, the Class B Units will not be entitled to receive any distributions.

(iv) Voting Rights. Except as set forth in this Section 5.24(b)(iv) and Section 13.3(c) and except to the extent the Delaware Act gives the Class B Units a vote as a class on any matter, the Class B Units shall not have any voting rights. With respect to any matter on which the Class B Units are entitled to vote, each Class B Unit will be entitled to one vote on such matter. The General Partner shall not, without the affirmative vote or written consent of holders of a majority of the Class B Units then Outstanding, amend, alter, modify or change this Section 5.24 (or vote or consent or resolve to take such action).

 

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(v) Redemption and Conversion Rights. The Class B Units will be perpetual and shall not have any rights of redemption or conversion.

(vi) Certificates; Book-Entry. Unless the General Partner shall determine otherwise, the Class B Units shall not be evidenced by Certificates. Any Certificates relating to the Class B Units that may be issued will be in such form as the General Partner may approve. The Class B Units, subject to the satisfaction of any applicable legal, regulatory and contractual requirements, may be assigned or transferred in a manner identical to the assignment and transfer of other Units.

(vii) Registrar and Transfer Agent. Unless and until the General Partner determines to assign the responsibility to another Person, the General Partner will act as the registrar and transfer agent for the Class B Units.”

(d) Section 6.1(a) of the Partnership Agreement is hereby amended and restated in its entirety as follows:

“(a) Net Income. After giving effect to the special allocations set forth in Section 6.1(d) and as otherwise provided in Article V, Net Income for each taxable year and all items of income, gain, loss and deduction taken into account in computing Net Income for such taxable year shall be allocated as follows:

(i) First, 100% to the General Partner until the aggregate Net Income allocated to the General Partner pursuant to this Section 6.1(a)(i) for the current taxable year and all previous taxable years is equal to the aggregate Net Losses allocated to the General Partner pursuant to Section 6.1(b)(iv) for all previous taxable years;

(ii) Second, to all Series A Holders, Series B Holders, Series C Holders, Series D Holders, Series E Holders, Series F Holders and Series G Holders, in proportion to, and to the extent of the Net Loss allocated to such Series A Holders, Series B Holders, Series C Holders, Series D Holders, Series E Holders, Series F Holders and Series G Holders pursuant to Section 6.1(b)(iii) for all previous taxable years, until the aggregate amount of Net Income allocated to such Series A Holders, Series B Holders, Series C Holders, Series D Holders, Series E Holders, Series F Holders and Series G Holders pursuant to this Section 6.1(a)(ii) for the current and all previous taxable years is equal to the aggregate amount of Net Loss allocated to such Series A Holders, Series B Holders, Series C Holders, Series D Holders, Series E Holders, Series F Holders and Series G Holders pursuant to Section 6.1(b)(iii) for all previous taxable years; provided that in no event shall Net Income be allocated to any such Series A Holders, Series B Holders, Series C Holders, Series D Holders, Series E Holders, Series F Holders and Series G Holders to cause its Capital Account in respect of a Series A Preferred Unit, a Series B Preferred Unit, a Series C Preferred Unit, a Series D Preferred Unit, a Series E Preferred Unit, a Series F Preferred Unit or a Series G Preferred Unit to exceed the Series A Base Liquidation Preference, the Series B Base Liquidation Preference, the Series C Base Liquidation Preference, the Series D Base Liquidation Preference, the Series E Base Liquidation Preference, the Series F Base Liquidation Preference or the Series G Base Liquidation Preference in respect of such Series A Preferred Units, Series B Preferred Units, Series C Preferred Units, Series D Preferred Units, Series E Preferred Units, Series F Preferred Units or Series G Preferred Units;

(iii) Third, 100% to the Unitholders (other than Series A Holders, Series B Holders, Series C Holders, Series D Holders, Series E Holders, Series F Holders and Series G Holders), in accordance with their respective Percentage Interests, until the aggregate Net Income allocated to such Unitholders pursuant to this Section 6.1(a)(iii) for the current taxable year and all previous taxable years is equal to the aggregate Net Losses allocated to such Unitholders pursuant to Section 6.1(b)(ii) for all previous taxable years; and

(iv) Fourth, the balance, if any, 100% to the Unitholders in accordance with their respective Percentage Interests.”

 

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(e) Section 6.1(b) of the Partnership Agreement is hereby amended and restated as follows:

“(b) Net Losses. After giving effect to the special allocations set forth in Section 6.1(d) and as otherwise provided in Article V, Net Losses for each taxable year and all items of income, gain, loss and deduction taken into account in computing Net Losses for such taxable year shall be allocated as follows:

(i) First, 100% to the Unitholders, in accordance with their respective Percentage Interests, until the aggregate Net Losses allocated pursuant to this Section 6.1(b)(i) for the current taxable year and all previous taxable years is equal to the aggregate Net Income allocated to such Unitholders pursuant to Section 6.1(a)(iv) for all previous taxable years, provided that the Net Losses shall not be allocated pursuant to this Section 6.1(b)(i) to the extent that such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable year (or increase any existing deficit balance in its Adjusted Capital Account);

(ii) Second, 100% to the Unitholders (other than Series A Holders, Series B Holders, Series C Holders, Series D Holders, Series E Holders, Series F Holders and Series G Holders) in accordance with their respective Percentage Interests; provided, that Net Losses shall not be allocated pursuant to this Section 6.1(b)(ii) to the extent that such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable year (or increase any existing deficit balance in its Adjusted Capital Account);

(iii) Third, to all Series A Holders, Series B Holders, Series C Holders, Series D Holders, Series E Holders, Series F Holders and Series G Holders, in proportion to their respective positive Adjusted Capital Account balances, until the Adjusted Capital Account in respect of each Series A Preferred Unit, Series B Preferred Unit, Series C Preferred Unit, Series D Preferred Unit, Series E Preferred Unit, Series F Preferred Unit and Series G Preferred Unit then Outstanding has been reduced to zero; and

(iv) Fourth, the balance, if any, 100% to the General Partner.”

(f) Section 6.1(c) of the Partnership Agreement is hereby amended and restated as follows:

“(c) Net Termination Gains and Losses. After giving effect to the special allocations set forth in Section 6.1(d) and as otherwise provided in Article V, all items of income, gain, loss and deduction taken into account in computing Net Termination Gain or Net Termination Loss for such taxable year shall be allocated in the same manner as such Net Termination Gain or Net Termination Loss is allocated hereunder. All allocations under this Section 6.1(c) shall be made after Capital Account balances have been adjusted by all other allocations provided under this Section 6.1 and after all distributions pursuant to Section 6.3; provided, however, that solely for purposes of this Section 6.1(c), Capital Accounts shall not be adjusted for distributions made pursuant to Section 12.4.

(i) If a Net Termination Gain is recognized (or deemed recognized pursuant to Section 5.4(d)) such Net Termination Gain shall be allocated among the Partners in the following manner (and the Capital Accounts of the Partners shall be increased by the amount so allocated in each of the following subclauses, in the order listed, before an allocation is made pursuant to the next succeeding subclause):

(A) First, to each Unitholder having a deficit balance in its Capital Account, in the proportion that such deficit balance bears to the total deficit balances in the Capital Accounts of all Partners, until each such Partner has been allocated Net Termination Gain equal to any such deficit balance in its Capital Account;

(B) Second, to all Series A Holders, Series B Holders, Series C Holders, Series D Holders, Series E Holders, Series F Holders and Series G Holders, Pro Rata, until the Capital Account in respect of each Outstanding Series A Preferred Unit, Series B Preferred Unit, Series C Preferred Unit, Series D Preferred Unit, Series E Preferred Unit, Series F Preferred Unit and Series G Preferred Unit equals the Series A Base Liquidation Preference, the Series B Base Liquidation Preference, the Series C Base Liquidation Preference, the Series D Base Liquidation Preference,

 

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the Series E Base Liquidation Preference, the Series F Base Liquidation Preference or the Series G Base Liquidation Preference; and

(C) Third, to all Unitholders in accordance with their Percentage Interests.

(ii) If a Net Termination Loss is recognized (or deemed recognized pursuant to Section 5.4(d)), such Net Termination Loss shall be allocated among the Partners in the following manner:

(A) First, to all Unitholders in accordance with their Percentage Interests until the Adjusted Capital Account in respect of each Unit then Outstanding has been reduced to zero;

(B) Second, to all Series A Holders, Series B Holders, Series C Holders, Series D Holders, Series E Holders, Series F Holders and Series G Holders, in proportion to their Adjusted Capital Account balances, until the Adjusted Capital Account in respect of each Series A Preferred Unit, Series B Preferred Unit, Series C Preferred Unit, Series D Preferred Unit, Series E Preferred Unit, Series F Preferred Unit or Series G Preferred Unit then Outstanding has been reduced to zero; and

(C) Third, the balance, if any, 100% to the General Partner.”

(g) Section 6.1(d) of the Partnership Agreement is hereby amended by adding a new subsection (xviii) at the end thereof as follows:

“(xviii) ETP Holdco Allocations.

(A) The Class B Units shall not be entitled to receive any allocation of any ETP Holdco Items, and such ETP Holdco Items (which shall not be included in the computation of Net Income, Net Loss, Net Termination Gain or Net Termination Loss for any taxable year while any Class B Units remain Outstanding) shall instead be specifically allocated to the Unitholders (other than the holders of Class B Units), Pro Rata.

(B) For the purposes of effectuating the intent of Section 6.1(d)(xi), the General Partner may make special allocations of items of Partnership gross income, gain, loss or deductions among the Unitholders as it deems reasonable.”

(h) Section 6.3(a) of the Partnership Agreement is hereby amended and restated in its entirety as follows:

“(a) Within 50 calendar days following the end of each Quarter, an amount equal to 100% of Available Cash with respect to such Quarter shall, subject to Section 17-607 of the Delaware Act, be distributed in accordance with this Article VI by the Partnership to the Partners as of the Record Date selected by the General Partner. All Available Cash shall be distributed to all Partners in accordance with their Percentage Interests, except as otherwise required by Section 5.17(b)(ii), Section 5.18(b)(ii), Section 5.19(b)(ii), Section 5.20(b)(ii), Section 5.21(b)(ii), Section 5.22(b)(ii), Section 5.23(b)(ii), and Section 5.24(b)(iii), or Section 5.8(b) in respect of additional Partnership Securities issued pursuant thereto. All distributions required to be made under this Agreement shall be made subject to Section 17-607 of the Delaware Act.”

(i) Article VI of the Partnership Agreement is hereby amended by adding a new Section 6.10 at the end thereof as follows:

“6.10 Special Provisions Relating to Preferred Unitholders.

Notwithstanding anything to the contrary set forth in this Agreement, the holders of the Series A Preferred Units, Series B Preferred Units, Series C Preferred Units, Series D Preferred Units, Series E Preferred Units, Series F Preferred Units and Series G Preferred Units (a) shall (i) possess the rights and obligations provided in this Agreement with respect to a Limited Partner pursuant to Article III and Article VII and (ii) have a Capital Account as a Partner pursuant to Section 5.6 and all other provisions

 

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related thereto and (b) shall not (i) be entitled to vote on any matters requiring the approval or vote of the holders of Outstanding Units, except as provided in Sections 5.17(b)(iii), 5.18(b)(iii), 5.19(b)(iii), 5.20(b)(iii), 5.21(b)(iii), 5.22(b)(iii), and 5.23(b)(iii) or as required by applicable law, or (ii) be entitled to any distributions other than as provided in Sections 5.17(b)(ii), 5.18(b)(ii), 5.19(b)(ii), 5.20(b)(ii), 5.21(b)(ii), 5.22(b)(ii), and 5.23(b)(ii).

(j) Section 12.4(c) of the Partnership Agreement is hereby amended and restated in its entirety as follows:

“(c) All property and all cash in excess of that required to discharge liabilities as provided in Section 12.4(b) and that required to satisfy the Series A Liquidation Preference provided for under Section 5.17(b)(v), the Series B Liquidation Preference provided for under Section 5.18(b)(v), the Series C Liquidation Preference provided for under Section 5.19(b)(v), the Series D Liquidation Preference provided for under Section 5.20(b)(v), the Series E Liquidation Preference provided for under Section 5.21(b)(v), the Series F Liquidation Preference provided for under Section 5.22(b)(v) and the Series G Liquidation Preference provided for under Section 5.23(b)(v) shall be distributed to the Partners in accordance with, and to the extent of, the positive balances in their respective Capital Accounts, as determined after taking into account all Capital Account adjustments (other than those made by reason of distributions pursuant to this Section 12.4(c)) for the taxable year of the Partnership during which the liquidation of the Partnership occurs (with such date of occurrence being determined pursuant to Treasury Regulation Section 1.704-1(b)(2)(ii)(g)), and such distribution shall be made by the end of such taxable year (or, if later, within 90 calendar days after said date of such occurrence).”

(k) Section 13.1(e) of the Partnership Agreement is hereby amended and restated in its entirety as follows:

“(e) a change in the fiscal year or taxable year of the Partnership and any other changes that the General Partner determines to be necessary or appropriate as a result of a change in the fiscal year or taxable year of the Partnership including, if the General Partner shall so determine, a change in the definition of “Quarter” and the dates on which distributions (other than Series A Distributions, Series B Distributions, Series C Distributions, Series D Distributions, Series E Distributions, Series F Distributions and Series G Distributions) are to be made by the Partnership;”

Section 2 Ratification of Partnership Agreement. Except as hereby amended, the Partnership Agreement shall remain in full force and effect.

Section 3 Governing Law. This Amendment No. 8 shall be governed by, and interpreted in accordance with the laws of the State of Delaware, all rights and remedies being governed by such laws without regard to principles of conflicts of laws.

(a) Severability of Provision. Each provision of this Amendment No. 8 shall be considered severable, and if for any reason any provision or provisions herein are determined to be invalid, unenforceable or illegal under any existing or future law, such invalidity, unenforceability or illegality shall not impair the operation of or affect those portions of this Amendment No. 8 that are valid, enforceable and legal.

[Signature page follows.]

 

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IN WITNESS WHEREOF, this Amendment No. 8 has been executed effective as of the Effective Date.

 

GENERAL PARTNER:
LE GP, LLC
By:    
  Name:
  Title:

 

 

 

 

 

[Signature Page to Amendment No. 8 to Third Amended and Restated Agreement

of Limited Partnership of Energy Transfer LP]

 

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Annex C

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K

 

 

 

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2020

or

 

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-32740

 

 

ENERGY TRANSFER LP

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   30-0108820

(state or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

8111 Westchester Drive, Suite 600, Dallas, Texas 75225

(Address of principal executive offices) (zip code)

(214) 981-0700

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class

 

Trading Symbol(s)

 

Name of each exchange on which registered

Common Units   ET   New York Stock Exchange

Securities registered pursuant to section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ☒    No  ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ☐    No  ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.    Yes  ☒    No  ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  ☒    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer      Accelerated filer  
Non-accelerated filer      Smaller reporting company  
     Emerging growth company  

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.  ☒

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐    No  ☒

The aggregate market value as of June 30, 2020, of the registrant’s Common Units held by non-affiliates of the registrant, based on the reported closing price of such Common Units on the New York Stock Exchange on such date, was $16.46 billion. Common Units held by each executive officer and director and by each person who owns 5% or more of the outstanding Common Units have been excluded in that such persons may be deemed to be affiliates. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

At February 12, 2021, the registrant had 2,702,436,307 Common Units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None

 

 

 

 

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TABLE OF CONTENTS

 

PART I

 

         PAGE  
ITEM 1.   BUSINESS      C-10  
ITEM 1A.   RISK FACTORS      C-50  
ITEM 1B.   UNRESOLVED STAFF COMMENTS      C-99  
ITEM 2.   PROPERTIES      C-99  
ITEM 3.   LEGAL PROCEEDINGS      C-99  
ITEM 4.   MINE SAFETY DISCLOSURES      C-101  
PART II

 

ITEM 5.   MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES      C-102  
ITEM 6.   SELECTED FINANCIAL DATA      C-103  
ITEM 7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS      C-104  
ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK      C-153  
ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA      C-156  
ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE      C-156  
ITEM 9A.   CONTROLS AND PROCEDURES      C-157  
ITEM 9B.   OTHER INFORMATION      C-159  
PART III

 

ITEM 10.   DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE      C-160  
ITEM 11.   EXECUTIVE COMPENSATION      C-168  
ITEM 12.   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS      C-186  
ITEM 13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE      C-187  
ITEM 14.   PRINCIPAL ACCOUNTANT FEES AND SERVICES      C-188  
PART IV

 

ITEM 15.   EXHIBITS AND FINANCIAL STATEMENT SCHEDULES      C-190  
ITEM 16.   FORM 10-K SUMMARY      C-191  
  Signatures      C-197  

 

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Definitions

The following is a list of certain acronyms and terms used throughout this document:

 

/d    per day
AOCI    accumulated other comprehensive income (loss)
AROs    asset retirement obligations
Bbls    barrels
BBtu    billion British thermal units
Bcf    billion cubic feet
Btu    British thermal unit, an energy measurement used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy content
Capacity    capacity of a pipeline, processing plant or storage facility refers to the maximum capacity under normal operating conditions and, with respect to pipeline transportation capacity, is subject to multiple factors (including natural gas injections and withdrawals at various delivery points along the pipeline and the utilization of compression) which may reduce the throughput capacity from specified capacity levels
CDM    CDM Resource Management LLC and CDM Environmental & Technical Services LLC, collectively
Citrus    Citrus, LLC, a 50/50 joint venture which owns FGT
Dakota Access    Dakota Access, LLC, a less than wholly-owned subsidiary of ETO
DOE    United States Department of Energy
DOJ    United States Department of Justice
DOT    United States Department of Transportation
Enable    Enable Midstream Partners, LP, a Delaware limited partnership

Energy Transfer Canada

   Energy Transfer Canada ULC (formerly SemCAMS Midstream ULC), a less than wholly-owned subsidiary of ETO
EPA    United States Environmental Protection Agency
ETC Sunoco    ETC Sunoco Holdings LLC (formerly Sunoco Inc.), a wholly-owned subsidiary of ETO
ETC Tiger    ETC Tiger Pipeline, LLC, a wholly-owned subsidiary of ETO, which owns the Tiger Pipeline
ETO    Energy Transfer Operating, L.P.

ETO Preferred Units

   ETO Series A Preferred Units, ETO Series B Preferred Units, ETO Series D Preferred Units, ETO Series E Preferred Units, ETO Series F Preferred Units and ETO Series G Preferred Units, collectively

ETO Series A Preferred Units

   6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

ETO Series B Preferred Units

   6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

ETO Series C Preferred Units

   7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

 

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ETO Series D Preferred Units

   7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

ETO Series E Preferred Units

   7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

ETO Series F Preferred Units

   6.750% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units

ETO Series G Preferred Units

   7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units
ETP GP    Energy Transfer Partners GP, L.P., the general partner of ETO
ETP Holdco    ETP Holdco Corporation, a wholly-owned subsidiary of ETO
ETP LLC    Energy Transfer Partners, L.L.C., the general partner of ETP GP
Exchange Act    Securities Exchange Act of 1934
ExxonMobil    Exxon Mobil Corporation
FEP    Fayetteville Express Pipeline LLC
FERC    Federal Energy Regulatory Commission
FGT    Florida Gas Transmission Pipeline and/or Florida Gas Transmission Company, LLC, a wholly-owned subsidiary of Citrus
GAAP    accounting principles generally accepted in the United States of America
General Partner    LE GP, LLC, the general partner of ET
HFOTCO    Houston Fuel Oil Terminal Company, a wholly-owned subsidiary of ETO, which owns the Houston Terminal
IDRs    incentive distribution rights
KMI    Kinder Morgan Inc.
Lake Charles LNG    Lake Charles LNG Company, LLC, a wholly-owned subsidiary of ETO
LCL    Lake Charles LNG Export Company, LLC, a wholly-owned subsidiary of ETO
LIBOR    London Interbank Offered Rate
LNG    liquefied natural gas
Lone Star    Lone Star NGL LLC, a wholly-owned subsidiary of ETO
MBbls    thousand barrels
MEP    Midcontinent Express Pipeline LLC
Mid-Valley    Mid-Valley Pipeline Company, a wholly-owned subsidiary of ETO
MMBbls    million barrels
MMcf    million cubic feet
MTBE    methyl tertiary butyl ether
NGL    natural gas liquid, such as propane, butane and natural gasoline
NYMEX    New York Mercantile Exchange

 

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NYSE    New York Stock Exchange
ORS    Ohio River System LLC, a less than wholly-owned subsidiary of ETO
OSHA    Federal Occupational Safety and Health Act
OTC    over-the-counter
Panhandle    Panhandle Eastern Pipe Line Company, LP, a wholly-owned subsidiary of ETO
PCBs    polychlorinated biphenyls
PEP    Permian Express Partners LLC, a less than wholly-owned subsidiary of ETO
PES    Philadelphia Energy Solutions Refining and Marketing LLC
Phillips 66    Phillips 66 Partners LP
PHMSA    Pipeline Hazardous Materials Safety Administration
Regency    Regency Energy Partners LP, a wholly-owned subsidiary of ETO
RIGS    Regency Intrastate Gas System, a wholly-owned subsidiary of ETO
Rover    Rover Pipeline LLC, a less than wholly-owned subsidiary of ETO
Sea Robin    Sea Robin Pipeline Company, LLC, a wholly-owned subsidiary of Panhandle
SEC    Securities and Exchange Commission
SemGroup    SemGroup, LLC (formerly SemGroup Corporation)
Shell    Royal Dutch Shell plc
Southwest Gas    Pan Gas Storage, LLC (d.b.a. Southwest Gas Storage Company)
SPLP    Sunoco Pipeline L.P., a wholly-owned subsidiary of ETO

Sunoco Logistics Operations

   Sunoco Logistics Partners Operations L.P, a wholly-owned subsidiary of ETO
Sunoco (R&M)    Sunoco (R&M), LLC
Transwestern    Transwestern Pipeline Company, LLC, a wholly-owned subsidiary of ETO
TRRC    Texas Railroad Commission
Trunkline    Trunkline Gas Company, LLC, a wholly-owned subsidiary of Panhandle
Unitholders    holders of Energy Transfer LP common units
USAC    USA Compression Partners, LP, a subsidiary of ETO
WMB    The Williams Companies, Inc.
White Cliffs    White Cliffs Pipeline, L.L.C.

Adjusted EBITDA is a term used throughout this document, which we define as total Partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded

 

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from the calculation of Segment Adjusted EBITDA and consolidated Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. The use of Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.

Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer LP (the “Partnership” or “ET”) in periodic press releases and some oral statements of the Partnership’s officials during presentations about the Partnership, include forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “continue,” “could,” “believe,” “may,” “will” or similar expressions help identify forward-looking statements. Although the Partnership and its General Partner believe such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that such assumptions, expectations or projections will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, the Partnership’s actual results may vary materially from those anticipated, estimated, projected, forecasted, expressed or expected in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see the risk factor summary below and “Item 1A. Risk Factors” included in this annual report.

Risk Factor Summary

Summary of Risks Related to the Partnership’s Business

Results of Operations and Financial Condition. Our results of operations and financial condition could be impacted by many risks that are beyond our control, including the following:

 

   

fluctuations in the demand for and price of natural gas, NGLs, crude oil and refined products;

 

   

the outbreak of COVID-19 and recent geopolitical developments in the crude oil market;

 

   

failure to successfully combine the businesses of Energy Transfer and Enable;

 

   

an impairment of goodwill and intangible assets;

 

   

an interruption of supply of crude oil to our facilities;

 

   

the loss of any key producers or customers;

 

   

failure to retain or replace existing customers or volumes due to declining demand or increased competition;

 

   

unfavorable changes in natural gas price spreads between two or more physical locations;

 

   

production declines over time, which we may not be able to replace with production from newly drilled wells;

 

   

our customers’ ability to use our pipelines and third-party pipelines over which we have no control;

 

   

the inability to access or continue to access lands owned by third parties;

 

   

the overall forward market for crude oil and other products we store;

 

   

a natural disaster, catastrophe, terrorist attack or other similar event;

 

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union disputes and strikes or work stoppages by unionized employees;

 

   

cybersecurity breaches and other disruptions or failures of our information systems;

 

   

failure to establish or maintain adequate corporate governance;

 

   

product liability claims and litigation;

 

   

actions taken by certain of our joint ventures that we do not control;

 

   

increasing levels of congestion in the Houston Ship Channel;

 

   

the costs of providing pension and other postretirement health care benefits and related funding requirements;

 

   

mergers among customers and competitors;

 

   

fraudulent activity or misuse of proprietary data involving our outsourcing partners; and

 

   

failure of the liquefaction project to secure long-term contractual arrangements or necessary approvals.

Indebtedness. Our business, results of operations, cash flows and financial condition, as well as our ability to make distributions, could be impacted by the following:

 

   

our debt level and debt agreements, or increases in interest rates;

 

   

changes in LIBOR reporting practices or the method in which LIBOR is determined;

 

   

the credit and risk profile of our general partner and its owners;

 

   

a downgrade of our credit ratings; and

 

   

losses resulting from the use of derivative financial instruments.

Capital Projects and Future Growth. Our business, results of operations, cash flows, financial condition, and future growth could be impacted by the following:

 

   

failure to make acquisitions on economically acceptable terms, or to successfully integrate acquired assets;

 

   

failure to secure debt and equity financing for capital projects on acceptable terms;

 

   

failure to construct new pipelines or to do so efficiently;

 

   

failure to execute our growth strategy due to increased competition within any of our core businesses; and

 

   

failure to attract and retain qualified employees.

Regulatory Matters. Our business, results of operations, cash flows, financial condition, and future growth could be impacted by the following:

 

   

increased regulation of hydraulic fracturing or produced water disposal;

 

   

legal or regulatory actions related to the Dakota Access Pipeline;

 

   

competition for water resources or limitations on water usage for hydraulic fracturing;

 

   

laws, regulations and policies governing the rates, terms and conditions of our services;

 

   

failure to recover the full amount of increases in the costs of our pipeline operations;

 

   

imposition of regulation on assets not previously subject to regulation;

 

   

costs and liabilities resulting from performance of pipeline integrity programs and related repairs;

 

   

new or more stringent pipeline safety controls or enforcement of legal requirements;

 

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costs and liabilities associated with environmental and worker health and safety laws and regulations;

 

   

climate change legislation or regulations restricting emissions of greenhouse gases;

 

   

regulatory provisions of the Dodd-Frank Act and the rules adopted thereunder;

 

   

deepwater drilling laws and regulations, delays in the processing and approval of drilling permits and exploration, development, oil spill-response and decommissioning plans, and related developments; and

 

   

laws and regulations governing the specifications of products that we store and transport.

Risks Relating to Our Partnership Structure

Cash Distributions to Unitholders. Our cash distributions could be impacted by the following:

 

   

cash distributions are not guaranteed and may fluctuate with our performance and other external factors;

 

   

limitations on available cash that are imposed by our distribution policy;

 

   

our general partner’s absolute discretion in determining the level of cash reserves; and

 

   

unitholders’ potential liability to repay distributions.

Our General Partner. Our stakeholders could be impacted by risks related to our general partner, including:

 

   

transfer of control of our general partner to a third party without unitholder consent; and

 

   

substantial cost reimbursements due to our general partner.

Our Subsidiaries. Risks that are unique to our subsidiaries and/or our relationship to our subsidiaries could reduce our subsidiaries’ cash available for distributions to us, including:

 

   

the potential issuance of additional common units by Sunoco LP or USAC;

 

   

a significant decrease in demand for or the price of motor fuel in the areas Sunoco LP serves;

 

   

seasonal industry trends, which may cause Sunoco LP’s operating costs to fluctuate;

 

   

disruptions in Sunoco LP’s operations due to dangers inherent in motor fuel transportation;

 

   

adverse publicity for Sunoco LP resulting from negative events or developments;

 

   

increased costs to retain necessary land use, which could disrupt Sunoco LP’s operations; and

 

   

federal, state and local laws and regulations that govern the industries in which our subsidiaries operate.

Risks Related to Conflicts of Interest. Our stakeholders could be impacted by conflicts of interest, including:

 

   

our general partner may favor its own interests to the detriment of our Unitholders;

 

   

fiduciary duties owed to Sunoco LP, USAC and their respective unitholders by their general partners; and

 

   

potential conflicts of interest faced by directors and officers in managing our business.

Tax Risks. Our stakeholders could be impacted by tax risks, including:

 

   

our tax treatment depends on our status as a partnership for federal income tax purposes, and not being subject to a material amount of entity-level taxation;

 

   

our cash available for distribution to Unitholders may be substantially reduced if we become subject to entity-level taxation as a result of the Internal Revenue Service (“IRS”) treating us as a corporation or legislative, judicial or administrative changes, and may also be reduced by any audit adjustments if imposed directly on the partnership;

 

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even if Unitholders do not receive any cash distributions from us, Unitholders will be required to pay taxes on their share of our taxable income;

 

   

a Unitholder’s share of our taxable income may be increased as a result of the IRS successfully contesting any of the federal income tax positions we take; and

 

   

tax-exempt entities and non-U.S. Unitholders face unique tax issues from owning our common units that may result in adverse tax consequences to them.

 

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PART I

ITEM 1. BUSINESS

Overview

We are a Delaware limited partnership with common units publicly traded on the NYSE under the ticker symbol “ET.”

Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership,” “ET” and “Energy Transfer” mean Energy Transfer LP and its consolidated subsidiaries, which include ETO, ETP GP, ETP LLC, Panhandle, Sunoco LP, USAC and Lake Charles LNG. References to the “Parent Company” mean Energy Transfer LP on a stand-alone basis.

The primary activities in which we are engaged, which are in the United States and Canada, and the operating subsidiaries through which we conduct those activities are as follows:

 

   

natural gas operations, including the following:

 

   

natural gas midstream and intrastate transportation and storage;

 

   

interstate natural gas transportation and storage; and

 

   

crude oil, NGL and refined products transportation, terminalling services and acquisition and marketing activities, as well as NGL storage and fractionation services.

In addition, we own investments in other businesses, including Sunoco LP and USAC, both of which are publicly traded master limited partnerships.

Substantially all of the Partnership’s cash flows are derived from distributions related to its investment in ETO, whose cash flows are derived from its subsidiaries, including ETO’s investments in Sunoco LP and USAC. The Parent Company’s primary cash requirements are for distributions to its partners, general and administrative expenses and debt service requirements. The Parent Company-only assets and liabilities are not available to satisfy the debts and other obligations of its subsidiaries. The Parent Company distributes its available cash remaining after satisfaction of the aforementioned cash requirements to its Unitholders on a quarterly basis.

We expect our subsidiaries to utilize their resources, along with cash from their operations, to fund their announced growth capital expenditures and working capital needs; however, the Parent Company may issue debt or equity securities from time to time as we deem prudent to provide liquidity for new capital projects of our subsidiaries or for other partnership purposes.

 

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The following chart summarizes our organizational structure as of February 12, 2021. For simplicity, certain immaterial entities and ownership interests have not been depicted.

 

 

LOGO

 

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Unless the context requires otherwise, the Partnership and its subsidiaries are collectively referred to in this report as “we,” “us,” “ET,” “Energy Transfer” or “the Partnership.”

Significant Achievements in 2020 and Beyond

 

   

During the third quarter of 2020, the Partnership completed its Lone Star Express expansion under budget and ahead of schedule.

 

   

During this first quarter of 2020, we completed the integration of the recently acquired SemGroup business and we began to realize financial savings from those actions.

 

   

During the fourth quarter of 2020, the Partnership completed construction of the Orbit Gulf Coast export terminal at Nederland and in January of 2021 loaded the first Very Large Ethane Carrier (“VLEC”) with 911,000 barrels of ethane destined for the northeastern Jiangsu Province, China.

 

   

In February 2021, the Partnership announced its entry into a definitive merger agreement to acquire Enable.

Segment Overview

See Note 17 to our consolidated financial statements in “Item 8. Financial Statements and Supplementary Data” for additional financial information about our segments.

Intrastate Transportation and Storage Segment

Natural gas transportation pipelines receive natural gas from other mainline transportation pipelines, storage facilities and gathering systems and deliver the natural gas to industrial end-users, storage facilities, utilities, power generators and other third-party pipelines. Through our intrastate transportation and storage segment, we own and operate (through wholly-owned subsidiaries or through joint venture interests) approximately 9,400 miles of natural gas transportation pipelines with approximately 22 Bcf/d of transportation capacity and three natural gas storage facilities located in the state of Texas.

Energy Transfer operates one of the largest intrastate pipeline systems in the United States providing energy logistics to major trading hubs and industrial consumption areas throughout the United States. Our intrastate transportation and storage segment focuses on the transportation of natural gas to major markets from various prolific natural gas producing areas (Permian, Barnett, Haynesville and Eagle Ford Shale) through our Oasis pipeline, our ETC Katy pipeline, our natural gas pipeline and storage systems that are referred to as the ET Fuel System, and our HPL System, as further described below.

Our intrastate transportation and storage segment’s results are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, our customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay a fee even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly.

We also generate revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and marketing companies on our HPL System. Generally, we purchase natural gas from either the market (including purchases from our marketing operations) or from producers at the wellhead. To the extent the natural gas comes from producers, it is primarily purchased at a discount to a specified market price and typically resold to customers based on an index price. In addition, our intrastate transportation and storage segment generates revenues from fees charged for storing customers’ working natural gas in our storage facilities and from managing natural gas for our own account.

 

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Interstate Transportation and Storage Segment

Natural gas transportation pipelines receive natural gas from supply sources including other transportation pipelines, storage facilities and gathering systems and deliver the natural gas to industrial end-users and other pipelines. Through our interstate transportation and storage segment, we directly own and operate approximately 12,340 miles of interstate natural gas pipelines with approximately 10.7 Bcf/d of transportation capacity and another approximately 6,780 miles and 10.7 Bcf/d of transportation capacity through joint venture interests.

ETO’s vast interstate natural gas network spans the United States from Florida to California and Texas to Michigan, offering a comprehensive array of pipeline and storage services. Our pipelines have the capability to transport natural gas from nearly all Lower 48 onshore and offshore supply basins to customers in the Southeast, Gulf Coast, Southwest, Midwest, Northeast and Canada. Through numerous interconnections with other pipelines, our interstate systems can access virtually any supply or market in the country. As discussed further herein, our interstate segment operations are regulated by the FERC, which has broad regulatory authority over the business and operations of interstate natural gas pipelines.

Lake Charles LNG, our wholly-owned subsidiary, owns an LNG import terminal and regasification facility located on Louisiana’s Gulf Coast near Lake Charles, Louisiana. The import terminal has approximately 9.0 Bcf of above ground storage capacity and the regasification facility has a send out capacity of 1.8 Bcf/d. Lake Charles LNG derives all of its revenue from a series of long-term contracts with a wholly-owned subsidiary of Shell.

LCL, a wholly-owned subsidiary of ETO, is currently developing a natural gas liquefaction facility for the export of LNG. The project would utilize existing dock and storage facilities owned by Lake Charles LNG located on the Lake Charles site. LCL entered into a prior development agreement with Shell in March 2019; however, Shell withdrew from the project in March 2020 due to adverse market factors affecting Shell’s business following the onset of the COVID-19 pandemic. We intend to continue to develop the project, possibly in conjunction with one or more equity partners, and we plan to evaluate a variety of alternatives to advance the project, including the possibility of reducing the size of the project from three trains (16.45 million tonnes per annum of LNG capacity) to two trains (11.0 million tonnes per annum). The project as currently designed is fully permitted by federal, state and local authorities, has all necessary export licenses and benefits from the infrastructure related to the existing regasification facility at the same site, including four LNG storage tanks, two deep water docks and other assets. In light of the existing brownfield infrastructure and the advanced state of the development of the project, we plan to continue to pursue the project on a disciplined, cost effective basis, and ultimately we will determine whether to make a final investment decision to proceed with the project based on market conditions, capital expenditure considerations and our success in securing equity participation by third parties as well as long-term LNG offtake commitments on satisfactory terms.

The results from our interstate transportation and storage segment are primarily derived from the fees we earn from natural gas transportation and storage services.

Midstream Segment

The midstream industry consists of natural gas gathering, compression, treating, processing, storage, and transportation, and is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells and the proximity of storage facilities to production areas and end-use markets. Gathering systems generally consist of a network of small diameter pipelines and, if necessary, compression systems, that collect natural gas from points near producing wells and transports it to larger pipelines for further transportation.

Treating plants remove carbon dioxide and hydrogen sulfide from natural gas that is higher in carbon dioxide, hydrogen sulfide or certain other contaminants, to ensure that it meets pipeline quality specifications. Natural gas processing involves the separation of natural gas into pipeline quality natural gas, or residue gas, and a mixed

 

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NGL stream. Some natural gas produced by a well does not meet the pipeline quality specifications established by downstream pipelines or is not suitable for commercial use and must be processed to remove the mixed NGL stream. In addition, some natural gas can be processed to take advantage of favorable margins for NGLs extracted from the gas stream.

Through our midstream segment, we own and operate natural gas gathering and NGL pipelines, natural gas processing plants, natural gas treating facilities and natural gas conditioning facilities with an aggregate processing capacity of approximately 8.7 Bcf/d. Our midstream segment focuses on the gathering, compression, treating, blending, and processing, and our operations are currently concentrated in major producing basins and shales in South Texas, West Texas, New Mexico, North Texas, East Texas, West Virginia, Pennsylvania, Ohio, Oklahoma, Kansas and Louisiana. Many of our midstream assets are integrated with our intrastate transportation and storage assets.

Our midstream segment also includes a 60% interest in Edwards Lime Gathering, LLC, which operates natural gas gathering, oil pipeline and oil stabilization facilities in South Texas and a 75% membership interest in ORS, which operates a natural gas gathering system in the Utica shale in Ohio.

Our midstream segment results are derived primarily from margins we earn for natural gas volumes that are gathered, transported, purchased and sold through our pipeline systems and the natural gas and NGL volumes processed at our processing and treating facilities.

NGL and Refined Products Transportation and Services Segment

Our NGL operations transport, store and execute acquisition and marketing activities utilizing a complementary network of pipelines, storage and blending facilities, and strategic off-take locations that provide access to multiple NGL markets.

Our NGL and refined products transportation and services segment includes:

 

   

approximately 4,823 miles of NGL pipelines;

 

   

Nederland Terminal and connecting pipelines which provide transportation of ethane, propane, butane and natural gasoline from our Mont Belvieu Facility to our Nederland Terminal where these products can be exported;

 

   

Marcus Hook Terminal which includes fractionation, storage and exporting assets. This facility is connected to our Mariner East pipeline system, which provides for the transportation of ethane and LPG products from western Pennsylvania, West Virginia and eastern Ohio to our Marcus Hook Terminal where these component products can be exported, processed or locally distributed;

 

   

NGL and propane fractionation facilities with an aggregate capacity of 975 MBbls/d;

 

   

NGL storage facility in Mont Belvieu with a working storage capacity of approximately 50 MMBbls; and

 

   

other NGL storage assets, located at our Cedar Bayou and Hattiesburg storage facilities, and our Nederland, Marcus Hook and Inkster NGL terminals with an aggregate storage capacity of approximately 17 MMBbls.

In the first quarter of 2020, we completed and placed into operation a seventh fractionator at our Mont Belvieu facility. In addition, we placed into service the Lone Star Express pipeline in the third quarter of 2020. The NGL pipelines primarily transport NGLs from the Permian and Delaware basins and the Barnett and Eagle Ford Shales to Mont Belvieu.

NGL terminalling services are facilitated by approximately 10 MMBbls of NGL storage capacity. These operations also support our liquids blending activities, including the use of our patented butane blending technology. Refined products operations provide transportation and terminalling services through the use of

 

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approximately 2,918 miles of refined products pipelines and 37 active refined products marketing terminals. Our marketing terminals are located primarily in the northeast, midwest and southwest United States, with approximately 8 MMBbls of refined products storage capacity. Our refined products operations utilize our integrated pipeline and terminalling assets, as well as acquisition and marketing activities, to service refined products markets in several regions throughout the United States. The mix of products delivered through our refined products pipelines varies seasonally, with gasoline demand peaking during the summer months, and demand for heating oil and other distillate fuels peaking in the winter. The products transported in these pipelines include multiple grades of gasoline and middle distillates, such as heating oil, diesel and jet fuel. Rates for shipments on these product pipelines are regulated by the FERC and other state regulatory agencies, as applicable.

Revenues in this segment are principally generated from fees charged to customers under dedicated contracts or take-or-pay contracts. Under a dedicated contract, the customer agrees to deliver the total output from particular processing plants that are connected to the NGL pipeline. Take-or-pay contracts have minimum throughput commitments requiring the customer to pay regardless of whether a fixed volume is transported. Fees are market-based, negotiated with customers and competitive with regional regulated pipelines and fractionators. Storage revenues are derived from base storage and throughput fees. This segment also derives revenues from the marketing of NGLs and processing and fractionating refinery off-gas.

Crude Oil Transportation and Services Segment

Our crude oil operations provide transportation (via pipeline and trucking), terminalling and acquisition and marketing services to crude oil markets throughout the southwest, midwest, northwestern and northeastern United States. Through our crude oil transportation and services segment, we own and operate (through wholly-owned subsidiaries or joint venture interests) approximately 10,850 miles of crude oil trunk and gathering pipelines in the southwest and midwest United States. This segment includes equity ownership interests in four crude oil pipelines, the Bakken Pipeline system, Bayou Bridge Pipeline, White Cliffs Pipeline and Maurepas Pipeline. Our crude oil terminalling services operate with an aggregate storage capacity of approximately 71 MMBbls, including approximately 29 MMBbls at our Gulf Coast terminal in Nederland, Texas, approximately 18.2 MMBbls at our Gulf coast terminal on the Houston Ship Channel and approximately 7.7 MMBbls at our Cushing facility in Cushing, Oklahoma. Our crude oil acquisition and marketing activities utilize our pipeline and terminal assets, our proprietary fleet crude oil tractor trailers and truck unloading facilities, as well as third-party assets, to service crude oil markets principally in the midcontinent United States.

Revenues throughout our crude oil pipeline systems are generated from tariffs paid by shippers utilizing our transportation services. These tariffs are filed with the FERC and other state regulatory agencies, as applicable.

Our crude oil acquisition and marketing activities include the gathering, purchasing, marketing and selling of crude oil. Specifically, the crude oil acquisition and marketing activities include:

 

   

purchasing crude oil at both the wellhead from producers, and in bulk from aggregators at major pipeline interconnections and trading locations;

 

   

storing inventory during contango market conditions (when the price of crude oil for future delivery is higher than current prices);

 

   

buying and selling crude oil of different grades at different locations in order to maximize value;

 

   

transporting crude oil using the pipelines, terminals and trucks or, when necessary or cost effective, pipelines, terminals or trucks owned and operated by third parties; and

 

   

marketing crude oil to major integrated oil companies, independent refiners and resellers through various types of sale and exchange transactions.

 

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Investment in Sunoco LP

Sunoco LP is engaged in the distribution of motor fuels to independent dealers, distributors, and other commercial customers and the distribution of motor fuels to end-user customers at retail sites operated by commission agents. Additionally, it receives rental income through the leasing or subleasing of real estate used in the retail distribution of motor fuel. Sunoco LP also operates 78 retail stores located in Hawaii and New Jersey.

Sunoco LP is a distributor of motor fuels and other petroleum products which Sunoco LP supplies to third-party dealers and distributors, to independent operators of commission agent locations and other commercial consumers of motor fuel. Also included in the wholesale operations are transmix processing plants and refined products terminals. Transmix is the mixture of various refined products (primarily gasoline and diesel) created in the supply chain (primarily in pipelines and terminals) when various products interface with each other. Transmix processing plants separate this mixture and return it to salable products of gasoline and diesel.

Sunoco LP is the exclusive wholesale supplier of the Sunoco-branded motor fuel, supplying an extensive distribution network of approximately 5,556 Sunoco-branded company and third-party operated locations throughout the East Coast, Midwest, South Central and Southeast regions of the United States. Sunoco LP believes it is one of the largest independent motor fuel distributors of Chevron, ExxonMobil and Valero branded motor fuel in the United States. In addition to distributing motor fuels, Sunoco LP also distributes other petroleum products such as propane and lubricating oil, and Sunoco LP receives rental income from real estate that it leases or subleases.

Sunoco LP operations primarily consist of fuel distribution and marketing.

Investment in USAC

USAC provides natural gas compression services throughout the United States, including the Utica, Marcellus, Permian Basin, Delaware Basin, Eagle Ford, Mississippi Lime, Granite Wash, Woodford, Barnett, Haynesville, Niobrara and Fayetteville shales. USAC provides compression services to its customers primarily in connection with infrastructure applications, including both allowing for the processing and transportation of natural gas through the domestic pipeline system and enhancing crude oil production through artificial lift processes. As such, USAC’s compression services play a critical role in the production, processing and transportation of both natural gas and crude oil. As of December 31, 2020, USAC had 3,726,181 horsepower in its fleet.

USAC operates a modern fleet of compression units, with an average age of approximately seven years. USAC’s standard new-build compression units are generally configured for multiple compression stages allowing USAC to operate its units across a broad range of operating conditions. As part of USAC’s services, it engineers, designs, operates, services and repairs its compression units and maintains related support inventory and equipment.

USAC provides compression services to its customers under fixed-fee contracts with initial contract terms typically between six months and five years, depending on the application and location of the compression unit. USAC typically continues to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. USAC primarily enters into fixed-fee contracts whereby its customers are required to pay a monthly fee even during periods of limited or disrupted throughput, which enhances the stability and predictability of its cash flows. USAC is not directly exposed to commodity price risk because it does not take title to the natural gas or crude oil involved in its services and because the natural gas used as fuel by its compression units is supplied by its customers without cost to USAC.

USAC’s assets and operations are all located and conducted in the United States.

 

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All Other Segment

Our “All Other” segment includes the following:

 

   

Our marketing operations in which we market the natural gas that flows through our gathering and intrastate transportation assets, referred to as on-system gas. We also attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other suppliers and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices of natural gas, less the costs of transportation. For the off-system gas, we purchase gas or act as an agent for small independent producers that may not have marketing operations.

 

   

Our natural gas compression equipment business which has operations in Arkansas, California, Colorado, Louisiana, New Mexico, Oklahoma, Pennsylvania and Texas.

 

   

Our wholly-owned subsidiary, Dual Drive Technologies, Ltd. (“DDT”), which provides compression services to customers engaged in the transportation of natural gas, including our other segments.

 

   

Our subsidiaries are involved in the management of coal and natural resources properties and the related collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties. These operations also include end-user coal handling facilities.

 

   

PEI Power LLC and PEI Power II LLC, which own and operate a facility in Pennsylvania that generates a total of 75 megawatts of electrical power.

 

   

Our 51% ownership interest in Energy Transfer Canada, which owns and operates natural gas processing and gathering facilities in Alberta, Canada.

Asset Overview

The descriptions below include summaries of significant assets within the Partnership’s reportable segments. Amounts, such as capacities, volumes and miles included in the descriptions below are approximate and are based on information currently available; such amounts are subject to change based on future events or additional information.

Intrastate Transportation and Storage

The following details our pipelines and storage facilities in the intrastate transportation and storage segment:

 

Description of Assets

   Ownership
Interest
    Miles of
Natural Gas
Pipeline
     Pipeline
Throughput
Capacity
(Bcf/d)
     Working
Storage
Capacity
(Bcf/d)
 

ET Fuel System

     100     3,150      5.2      11.2

Oasis Pipeline(1)

     100     750      2.0      —    

HPL System

     100     3,920      5.3      52.5

ETC Katy Pipeline

     100     460      2.9      —    

Regency Intrastate Gas

     100     450      2.1      —    

Comanche Trail Pipeline

     16     195      1.1      —    

Trans-Pecos Pipeline

     16     143      1.4      —    

Old Ocean Pipeline, LLC

     50     240      0.2      —    

Red Bluff Express Pipeline

     70     108      1.4      —    

 

(1) 

Includes bi-directional capabilities

 

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The following information describes our principal intrastate transportation and storage assets:

 

   

The ET Fuel System serves some of the most prolific production areas in the United States and is comprised of intrastate natural gas pipeline and related natural gas storage facilities. The ET Fuel System has many interconnections with pipelines providing direct access to power plants, other intrastate and interstate pipelines, and has bi-directional capabilities. It is strategically located near high-growth production areas and provides access to the three major natural gas trading centers in Texas, the Waha Hub near Pecos, Texas, the Maypearl Hub in Central Texas and the Carthage Hub in East Texas.

The ET Fuel System also includes our Bethel natural gas storage facility, with a working capacity of 6.0 Bcf, an average withdrawal capacity of 300 MMcf/d and an injection capacity of 75 MMcf/d, and our Bryson natural gas storage facility, with a working capacity of 5.2 Bcf, an average withdrawal capacity of 120 MMcf/d and an average injection capacity of 96 MMcf/d. Storage capacity on the ET Fuel System is contracted to third parties under fee-based arrangements that extend through 2023.

In addition, the ET Fuel System is integrated with our Godley processing plant which gives us the ability to bypass the plant when processing margins are unfavorable by blending the untreated natural gas from the North Texas System with natural gas on the ET Fuel System while continuing to meet pipeline quality specifications.

 

   

The Oasis Pipeline is primarily a 36-inch natural gas pipeline. It has bi-directional capabilities with approximately 1.3 Bcf/d of throughput capacity moving west-to-east and greater than 750 MMcf/d of throughput capacity moving east-to-west. The Oasis pipeline connects to the Waha and Katy market hubs and has many interconnections with other pipelines, power plants, processing facilities, municipalities and producers.

The Oasis pipeline is integrated with our gathering system known as the Southeast Texas System and is an important component to maximizing our Southeast Texas System’s profitability. The Oasis pipeline enhances the Southeast Texas System by (i) providing access for natural gas gathered on the Southeast Texas System to other third-party supply and market points and interconnecting pipelines and (ii) allowing us to bypass our processing plants and treating facilities on the Southeast Texas System when processing margins are unfavorable by blending untreated natural gas from the Southeast Texas System with gas on the Oasis pipeline while continuing to meet pipeline quality specifications.

 

   

The HPL System is an extensive network of intrastate natural gas pipelines, an underground Bammel storage reservoir and related transportation assets. The system has access to multiple sources of historically significant natural gas supply reserves from South Texas, the Gulf Coast of Texas, East Texas and the western Gulf of Mexico, and is directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus Christi, Texas City, Beaumont and other cities located along the Gulf Coast of Texas. The HPL System is well situated to gather and transport gas in many of the major gas producing areas in Texas including a strong presence in the key Houston Ship Channel and Katy Hub markets, allowing us to play an important role in the Texas natural gas markets. The HPL System also offers its shippers off-system opportunities due to its numerous interconnections with other pipeline systems, its direct access to multiple market hubs at Katy, the Houston Ship Channel, Carthage and Agua Dulce, as well as our Bammel storage facility.

The Bammel storage facility has a total working gas capacity of approximately 52.5 Bcf, a peak withdrawal rate of 1.3 Bcf/d and a peak injection rate of 0.6 Bcf/d. The Bammel storage facility is located near the Houston Ship Channel market area and the Katy Hub, and is ideally suited to provide a physical backup for on-system and off-system customers. As of December 31, 2020, we had approximately 19.0 Bcf committed under fee-based arrangements with third parties and approximately 28.7 Bcf stored in the facility for our own account.

 

   

The ETC Katy Pipeline connects three treating facilities, one of which we own, with our gathering system known as Southeast Texas System. The ETC Katy pipeline serves producers in East and North Central Texas and provided access to the Katy Hub. The ETC Katy pipeline expansions include the 36-inch East

 

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Texas extension to connect our Reed compressor station in Freestone County to our Grimes County compressor station, the 36-inch Katy expansion connecting Grimes to the Katy Hub, and the 42-inch Southeast Bossier pipeline connecting our Cleburne to Carthage pipeline to the HPL System.

 

   

RIGS is a 450-mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets.

 

   

Comanche Trail Pipeline is a 195-mile intrastate pipeline that delivers natural gas from the Waha Hub near Pecos, Texas to the United States/Mexico border near San Elizario, Texas. The Partnership owns a 16% membership interest in and operates Comanche Trail.

 

   

Trans-Pecos Pipeline is a 143-mile intrastate pipeline that delivers natural gas from the Waha Hub near Pecos, Texas to the United States/Mexico border near Presidio, Texas. The Partnership owns a 16% membership interest in and operates Trans-Pecos.

 

   

Old Ocean is a 240-mile intrastate pipeline system that delivers natural gas from Ellis County, Texas to Brazoria County, Texas. The Partnership owns a 50% membership interest in and operates Old Ocean.

 

   

The Red Bluff Express Pipeline is an approximately 108-mile intrastate pipeline that runs through the heart of the Delaware basin and connects our Orla Plant, as well as third-party plants to the Waha Oasis Header. The Partnership owns a 70% membership interest in and operates Red Bluff Express.

Interstate Transportation and Storage

The following details our pipelines in the interstate transportation and storage segment:

 

Description of Assets

   Ownership
Interest
    Miles of
Natural Gas
Pipeline
     Pipeline
Throughput
Capacity
(Bcf/d)
     Working
Gas
Capacity
(Bcf/d)
 

Florida Gas Transmission

     50     5,362      3.5      —    

Transwestern Pipeline

     100     2,614      2.1      —    

Panhandle Eastern Pipe Line(1)

     100     6,298      2.8      73.4

Trunkline Gas Company

     100     2,190      0.9      13.0

Tiger Pipeline

     100     197      2.4      —    

Fayetteville Express Pipeline

     50     185      2.0      —    

Sea Robin Pipeline

     100     740      2.0      —    

Stingray Pipeline

     100     287      0.4      —    

Rover Pipeline

     32.6     719      3.4      —    

Midcontinent Express Pipeline

     50     512      1.8      —    

Gulf States Transmission

     100     10      0.1      —    

 

(1) 

Natural gas storage assets are owned by Southwest Gas.

The following information describes our principal interstate transportation and storage assets:

 

   

Florida Gas Transmission Pipeline (“FGT”) has mainline capacity of 3.5 Bcf/d and approximately 5,362 miles of pipelines extending from south Texas through the Gulf Coast region of the United States to south Florida. The FGT system receives natural gas from various onshore and offshore natural gas producing basins. FGT is the principal transporter of natural gas to the Florida energy market, delivering approximately 60% of the natural gas consumed in the state. In addition, FGT’s system operates and maintains multiple interconnects with major interstate and intrastate natural gas pipelines, which provide FGT’s customers access to diverse natural gas producing regions. FGT’s customers include electric utilities, independent power producers, industrial end-users and local distribution companies. FGT is owned by Citrus, a 50/50 joint venture with KMI.

 

   

Transwestern Pipeline transports natural gas supply from the Permian Basin in West Texas and eastern New Mexico, the San Juan Basin in northwestern New Mexico and southern Colorado, and the Anadarko

 

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Basin in the Texas and Oklahoma panhandles. The system has bi-directional capabilities and can access Texas and Midcontinent natural gas market hubs, as well as major western markets in Arizona, Nevada and California. Transwestern’s customers include local distribution companies, producers, marketers, electric power generators and industrial end-users.

 

   

Panhandle Eastern Pipe Line’s transmission system consists of four large diameter pipelines with bi-directional capabilities, extending approximately 1,300 miles from producing areas in the Anadarko Basin of Texas, Oklahoma and Kansas through Missouri, Illinois, Indiana, Ohio and into Michigan. Panhandle contracts for over 73 Bcf of natural gas storage.

 

   

Trunkline Gas Company’s transmission system consists of one large diameter pipeline with bi-directional capabilities, extending approximately 1,400 miles from the Gulf Coast areas of Texas and Louisiana through Arkansas, Mississippi, Tennessee, Kentucky, Illinois, Indiana and Michigan. Trunkline has one natural gas storage field located in Louisiana.

 

   

Tiger Pipeline is a bi-directional system that extends through the heart of the Haynesville Shale and ends near Delhi, Louisiana, interconnecting with multiple interstate pipelines.

 

   

Fayetteville Express Pipeline originates near Conway County, Arkansas and continues eastward to Panola County, Mississippi with multiple pipeline interconnections along the route. Fayetteville Express Pipeline is owned by a 50/50 joint venture with KMI.

 

   

Sea Robin Pipeline’s system consists of two offshore Louisiana natural gas supply pipelines extending 120 miles into the Gulf of Mexico.

 

   

Stingray Pipeline is an interstate natural gas pipeline system with related assets located in the western Gulf of Mexico and Johnson Bayou, Louisiana. Stingray has recently filed with the FERC to abandon a portion of its system to be used in non-gas service and the remaining portion to be operated as a non-FERC-regulated gathering system. The proceeding is pending a decision from FERC.

 

   

Rover Pipeline is a large diameter pipeline with total capacity to transport 3.4 Bcf/d natural gas from processing plants in West Virginia, Eastern Ohio and Western Pennsylvania for delivery to other pipeline interconnects in Ohio and Michigan, where the gas is delivered for distribution to markets across the United States, as well as to Ontario, Canada.

 

   

Midcontinent Express Pipeline originates near Bennington, Oklahoma and traverses northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipeline system in Butler, Alabama. The Midcontinent Express Pipeline is owned by a 50/50 joint venture with KMI, the operator of the system.

 

   

Gulf States Transmission is a 10-mile interstate pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana.

Regasification Facility

Lake Charles LNG, our wholly-owned subsidiary, owns an LNG import terminal and regasification facility located on Louisiana’s Gulf Coast near Lake Charles, Louisiana. The import terminal has approximately 9.0 Bcf of above ground LNG storage capacity and the regasification facility has a send out capacity of 1.8 Bcf/d.

Liquefaction Project

LCL, a wholly-owned subsidiary of ETO, is in the process of developing an LNG liquefaction project at the site of our Lake Charles LNG import terminal and regasification facility. The project would utilize existing dock and storage facilities owned by Lake Charles LNG located on the Lake Charles site. LCL entered into a prior development agreement with Shell in March 2019; however, Shell withdrew from the project in March 2020 due to adverse market factors affecting Shell’s business following the onset of the COVID-19 pandemic. We intend to continue to develop the project, possibly in conjunction with one or more equity partners, and we plan to evaluate a variety of alternatives to advance the project, including the possibility of reducing the size of the

 

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project from three trains (16.45 million tonnes per annum of LNG capacity) to two trains (11.0 million tonnes per annum). The project as currently designed is fully permitted by federal, state and local authorities, has all necessary export licenses and benefits from the infrastructure related to the existing regasification facility at the same site, including four LNG storage tanks, two deep water docks and other assets. In light of the existing brownfield infrastructure and the advanced state of the development of the project, we plan to continue to pursue the project on a disciplined, cost effective basis, and ultimately we will determine whether to make a final investment decision to proceed with the project based on market conditions, capital expenditure considerations and our success in securing equity participation by third parties as well as long-term LNG offtake commitments on satisfactory terms. LCL is actively involved in a variety of activities related to the development of the project and has also been marketing LNG offtake to numerous potential customers in Asia and Europe.

The export of LNG produced by the liquefaction project from the United States would be undertaken under long-term export authorizations issued by the DOE to LCL. In March 2013, LCL obtained a DOE authorization to export LNG to countries with which the United States has or will have Free Trade Agreements (“FTA”) for trade in natural gas (the “FTA Authorization”). In July 2016, LCL also obtained a conditional DOE authorization to export LNG to countries that do not have an FTA for trade in natural gas (the “Non-FTA Authorization”). In October 2020, the DOE extended the FTA Authorization and Non-FTA Authorization to 30- and 25-year terms, respectively, following first deliveries on or before December 2025, consistent with the FERC authorization for the project. The FTA Authorization and Non-FTA Authorization have 25- and 20-year terms, respectively, commencing with the completion of construction of the liquefaction facility. In addition, LCL received its wetlands permits from the USACE to perform wetlands mitigation work and to perform modification and dredging work for the temporary and permanent dock facilities at the Lake Charles LNG facilities.

Midstream

The following details our assets in the midstream segment:

 

Description of Assets

   Net Gas
Processing
Capacity
(MMcf/d)
 

South Texas Region:

  

Southeast Texas System

     410

Eagle Ford System

     1,920

Ark-La-Tex Region

     1,442

North Central Texas Region

     700

Permian Region

     2,740

Midcontinent Region

     1,238

Eastern Region

     200

The following information describes our principal midstream assets:

South Texas Region:

 

   

The Southeast Texas System is an integrated system that gathers, compresses, treats, processes, dehydrates and transports natural gas from the Austin Chalk trend and Eagle Ford shale formation. The Southeast Texas System is a large natural gas gathering system covering thirteen counties between Austin and Houston. This system is connected to the Katy Hub through the ETC Katy Pipeline and is also connected to the Oasis Pipeline. The Southeast Texas System includes two natural gas processing plants (La Grange and Alamo) with aggregate capacity of 410 MMcf/d. The La Grange and Alamo processing plants are natural gas processing plants that process the rich gas that flows through our gathering system to produce residue gas and NGLs. Residue gas is delivered into our intrastate pipelines and NGLs are delivered into our NGL pipelines to Lone Star.

 

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Our treating facilities remove carbon dioxide and hydrogen sulfide from natural gas gathered into our system before the natural gas is introduced to transportation pipelines to ensure that the gas meets pipeline quality specifications.

 

   

The Eagle Ford Gathering System consists of 30-inch and 42-inch natural gas gathering pipelines with over 1.4 Bcf/d of capacity originating in Dimmitt County, Texas, and extending to both our King Ranch gas plant in Kleberg County, Texas and Jackson plant in Jackson County, Texas. The Eagle Ford Gathering System includes four processing plants (Chisholm, Kenedy, Jackson and King Ranch) with aggregate capacity of 1.92 Bcf/d. Our Chisholm, Kenedy, Jackson and King Ranch processing plants are connected to our intrastate transportation pipeline systems for deliveries of residue gas and are also connected with our NGL pipelines for delivery of NGLs to Lone Star.

Ark-La-Tex Region:

 

   

Our Northern Louisiana assets are comprised of several gathering systems in the Haynesville Shale with access to multiple markets through interconnects with several pipelines, including our Tiger Pipeline. Our Northern Louisiana assets include the Bistineau, Creedence, and Tristate Systems, which collectively include three natural gas treating facilities, with aggregate capacity of 1.4 Bcf/d.

 

   

The Ark-La-Tex assets gather, compress, treat and dehydrate natural gas in several parishes in north and west Louisiana and several counties in East Texas. These assets also include cryogenic natural gas processing facilities, a refrigeration plant, a conditioning plant, amine treating plants, a residue gas pipeline that provides market access for natural gas from our processing plants, including connections with pipelines that provide access to the Perryville Hub and other markets in the Gulf Coast region, and an NGL pipeline that provides connections to the Mont Belvieu market for NGLs produced from our processing plants. Collectively, the ten natural gas processing facilities (Dubach, Dubberly, Lisbon, Salem, Elm Grove, Minden, Ada, Brookeland, Lincoln Parish and Mt. Olive) have an aggregate capacity of 1.3 Bcf/d.

 

   

Through the gathering and processing systems described above and their interconnections with RIGS in north Louisiana, as well as other pipelines, we offer producers wellhead-to-market services, including natural gas gathering, compression, processing, treating and transportation.

North Central Texas Region:

 

   

The North Central Texas System is an integrated system located in four counties in North Central Texas that gathers, compresses, treats, processes and transports natural gas from the Barnett and Woodford Shales. Our North Central Texas assets include our Godley and Crescent plants, which process rich gas produced from the Barnett Shale and STACK play, with aggregate capacity of 700 MMcf/d. The Godley plant is integrated with the ET Fuel System.

Permian Region:

 

   

The Permian Basin Gathering System offers wellhead-to-market services to producers in eleven counties in West Texas, as well as two counties in New Mexico which surround the Waha Hub, one of Texas’s developing NGL-rich natural gas market areas. As a result of the proximity of our system to the Waha Hub, the Waha Gathering System has a variety of market outlets for the natural gas that we gather and process, including several major interstate and intrastate pipelines serving California, the midcontinent region of the United States and Texas natural gas markets. The NGL market outlets includes Lone Star’s liquids pipelines. The Permian Basin Gathering System includes eleven processing facilities (Waha, Coyanosa, Red Bluff, Halley, Jal, Keyston, Tippet, Orla, Panther, Rebel and Arrowhead) with an aggregate processing capacity of 2.4 Bcf/d and one natural gas conditioning facility with aggregate capacity of 200 MMcf/d.

 

   

We own a 50% membership interest in Mi Vida JV LLC, a joint venture which owns a 200 MMcf/d cryogenic processing plant in West Texas. We operate the plant and related facilities on behalf of the joint venture.

 

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We own a 50% membership interest in Ranch Westex JV, LLC, which processes natural gas delivered from the NGL-rich Bone Spring and Avalon Shale formations in West Texas. The joint venture owns a 25 MMcf/d refrigeration plant and a 125 MMcf/d cryogenic processing plant.

Midcontinent Region:

 

   

The Midcontinent Systems are located in two large natural gas producing regions in the United States, the Hugoton Basin in southwest Kansas, and the Anadarko Basin in western Oklahoma and the Texas Panhandle and the STACK in central Oklahoma. These mature basins have continued to provide generally long-lived, predictable production volume. Our Midcontinent assets are extensive systems that gather, compress and dehydrate low-pressure gas. The Midcontinent Systems include sixteen natural gas processing facilities (Mocane, Beaver, Antelope Hills, Woodall, Wheeler, Sunray, Hemphill, Phoenix, Hamlin, Spearman, Red Deer, Lefors, Cargray, Gray, Rose Valley, and Hopeton) with an aggregate capacity of approximately 1.2 Bcf/d.

 

   

We operate our Midcontinent Systems at low pressures to maximize the total throughput volumes from the connected wells. Wellhead pressures are therefore adequate to allow for flow of natural gas into the gathering lines without the cost of wellhead compression.

 

   

We also own the Hugoton Gathering System that has 1,900 miles of pipeline extending over nine counties in Kansas and Oklahoma. This system is operated by a third party.

Eastern Region:

 

   

The Eastern Region assets are located in eleven counties in Pennsylvania, four counties in Ohio, three counties in West Virginia, and gather natural gas from the Marcellus and Utica basins. Our Eastern Region assets include approximately 600 miles of natural gas gathering pipeline, natural gas trunklines, fresh-water pipelines, and nine gathering and processing systems, as well as the 200 MMcf/d Revolution processing plant, which feeds into our Mariner East and Rover pipeline systems.

 

   

We also own a 51% membership interest in Aqua—ETC Water Solutions LLC, a joint venture that transports and supplies fresh water to natural gas producers drilling in the Marcellus Shale in Pennsylvania.

 

   

We own a 75% membership interest in ORS. On behalf of ORS, we operate its Ohio Utica River System, which consists of 47 miles of 36-inch, 13 miles of 30-inch and 3 miles of 24-inch gathering trunklines, that delivers up to 3.6 Bcf/d to Rockies Express Pipeline, Texas Eastern Transmission, Leach Xpress, Rover and DEO TPL-18.

NGL and Refined Products Transportation and Services

The following details the assets in our NGL and refined products transportation and services segment:

 

Description of Assets

   Miles of
Liquids
Pipeline(1)
     NGL
Fractionation/
Processing
Capacity
(MBbls/d)
     Working
Storage
Capacity
(MBbls)
 

Liquids Pipelines:

        

Lone Star Express

     892      —          —    

West Texas Gateway Pipeline

     510      —          —    

Lone Star

     1,400      —          —    

Mariner East

     667      —          —    

Mariner South

     67      —          —    

Mariner West

     398      —          —    

White Cliffs Pipeline(2)

     540      —          —    

Other NGL Pipelines

     279      —          —    

 

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Description of Assets

   Miles of
Liquids
Pipeline(1)
     NGL
Fractionation/
Processing
Capacity
(MBbls/d)
     Working
Storage
Capacity
(MBbls)
 

Liquids Fractionation and Services Facilities:

        

Mont Belvieu Facilities

     182      940      50,000

Sea Robin Processing Plant(3)

     —          26      —    

Refinery Services(3)

     100      35      —    

Hattiesburg Storage Facilities

     —          —          5,200

Cedar Bayou

     —          —          1,600

NGL Terminals:

        

Nederland

     —          —          1,900

Orbit Gulf Coast

     70      —          1,200

Marcus Hook Terminal

     —          132      6,000

Inkster

     —          —          860

Refined Products Pipelines:

        

Eastern region pipelines

     1,016      —          —    

Midcontinent region pipelines

     332      —          —    

Southwest region pipelines

     376      —          —    

Inland Pipeline

     690      —          —    

JC Nolan Pipeline

     504      —          —    

Refined Products Terminals:

        

Eagle Point

     —          —          6,700

Marcus Hook Terminal

     —          —          930

Marcus Hook Tank Farm

     —          —          1,900

Marketing Terminals

     —          —          7,700

JC Nolan Terminal

     —          —          134

 

(1) 

Miles of pipeline as reported to PHMSA.

(2) 

The White Cliffs Pipeline consists of two parallel, 12-inch common carrier pipelines: one crude oil pipeline and one NGL pipeline.

(3) 

Additionally, the Sea Robin Processing Plant and Refinery Services have inlet volume capacities of 850 MMcf/d and 54 MMcf/d, respectively.

The following information describes our principal NGL and refined products transportation and services assets:

 

   

The Lone Star Express System is an interstate NGL pipeline consisting of 24-inch and 30-inch long-haul transportation pipeline, with throughput capacity of approximately 500 MBbls/d, that delivers mixed NGLs from processing plants in the Permian Basin, the Barnett Shale, and from East Texas to the Mont Belvieu NGL storage facility. In the third quarter of 2020, we completed an expansion of the pipeline, which added approximately 400 MBbls/d of NGL pipeline capacity from Lone Star’s pipeline system near Wink, Texas to the Lone Star Express 30-inch pipeline south of Fort Worth, Texas. It is expected to be in service by the fourth quarter of 2020.

 

   

The West Texas Gateway Pipeline transports NGLs produced in the Permian and Delaware Basins and the Eagle Ford Shale to Mont Belvieu, Texas and has a throughput capacity of approximately 240 MBbls/d.

 

   

The Mariner East pipeline transports NGLs from the Marcellus and Utica Shales areas in Western Pennsylvania, West Virginia and Eastern Ohio to destinations in Pennsylvania, including our Marcus Hook Terminal on the Delaware River, where they are processed, stored and distributed to local, domestic and waterborne markets. The first phase of the project, referred to as Mariner East 1, consisted of interstate and intrastate propane and ethane service and commenced operations in the fourth quarter of 2014 and the first quarter of 2016, respectively. The second phase of the project, referred to as Mariner East 2, began service in December 2018. The Mariner East pipeline has a throughput capacity of approximately 345 MBbls/d.

 

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The Mariner South liquids pipeline system consists of three pipelines and delivers export-grade propane, butane and natural gasoline from Lone Star’s Mont Belvieu, Texas storage and fractionation complex to our marine terminal in Nederland, Texas and has a total throughput capacity of approximately 600 MBbls/d.

 

   

The Mariner West pipeline provides transportation of ethane from the Marcellus shale processing and fractionating areas in Houston, Pennsylvania to Marysville, Michigan and the Canadian border and has a throughput capacity of approximately 50 MBbls/d.

 

   

The White Cliffs NGL pipeline, in which we have 51% ownership interest and was acquired by ET in the SemGroup acquisition and contributed to ETO in January 2020, transports NGLs produced in the DJ Basin to Cushing, where it interconnects with the Southern Hills Pipeline to move NGLs to Mont Belvieu, Texas and has a throughput capacity of approximately 90 MBbls/d.

 

   

Other NGL pipelines include the 127-mile Justice pipeline with capacity of 375 MBbls/d, the 45-mile Freedom pipeline with a capacity of 56 MBbls/d, the 20-mile Spirit pipeline with a capacity of 20 MBbls/d and a 50% interest in the 87-mile Liberty pipeline with a capacity of 140 MBbls/d.

 

   

Our Mont Belvieu storage facility is an integrated liquids storage facility with approximately 50 MMBbls of salt dome capacity providing 100% fee-based cash flows. The Mont Belvieu storage facility has access to multiple NGL and refined products pipelines, the Houston Ship Channel trading hub, and numerous chemical plants, refineries and fractionators.

 

   

Our Mont Belvieu fractionators handle NGLs delivered from several sources, including the Lone Star Express pipeline and the Justice pipeline. Fractionator VI was placed in service in February 2019 and Fractionator VII was placed in service in the first quarter of 2020.

 

   

Sea Robin is a rich gas processing plant located on the Sea Robin Pipeline in southern Louisiana. The plant is connected to nine interstate and four intrastate residue pipelines, as well as various deep-water production fields.

 

   

Refinery Services consists of a refinery off-gas processing unit and an O-grade NGL fractionation / Refinery-Grade Propylene (“RGP”) splitting complex located along the Mississippi River refinery corridor in southern Louisiana. The off-gas processing unit cryogenically processes refinery off-gas, and the fractionation / RGP splitting complex fractionates the streams into higher value components. The O-grade fractionator and RGP splitting complex, located in Geismar, Louisiana, is connected by approximately 100 miles of pipeline to the Chalmette processing plant, which has a processing capacity of 54 MMcf/d.

 

   

The Hattiesburg storage facility is an integrated liquids storage facility with approximately 5 MMBbls of salt dome capacity, providing 100% fee-based cash flows.

 

   

The Cedar Bayou storage facility is an integrated liquids storage facility with approximately 1.6 MMBbls of tank storage, generating revenues from fixed fee storage contracts, throughput fees, and revenue from blending butane into refined gasoline.

 

   

The Nederland Terminal, in addition to crude oil activities, also provides approximately 1.9 MMBbls of storage and distribution services for NGLs in connection with the Mariner South and Mariner South 2 pipelines, which provide transportation of propane and butane products from the Mont Belvieu region to the Nederland Terminal, where such products can be exported via ship.

 

   

The Orbit Gulf Coast joint venture consists of a 70-mile, 20-inch ethane pipeline with a throughput capacity of approximately 180 MBbls/d, delivering from Lone Star’s Mont Belvieu, Texas storage and fractionation complex to our marine terminal in Nederland, Texas, as well as a 180 MBbls/d ethane refrigeration facility and 1.2 MMBbls of storage capacity.

 

   

The Marcus Hook Terminal includes fractionation, terminalling and storage assets, with a capacity of approximately 2 MMBbls of NGL storage capacity in underground caverns, 4 MMBbls of above-ground refrigerated storage, and related commercial agreements. The terminal has a total active refined products storage capacity of approximately 1 MMBbls. The facility can receive NGLs and refined products via

 

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marine vessel, pipeline, truck and rail, and can deliver via marine vessel, pipeline and truck. In addition to providing NGL storage and terminalling services to both affiliates and third-party customers, the Marcus Hook Terminal currently serves as an off-take outlet for our Mariner East 1 and Mariner East 2 pipeline systems.

 

   

The Inkster terminal, located near Detroit, Michigan, consists of multiple salt caverns with a total storage capacity of approximately 860 MBbls of NGLs. We use the Inkster terminal’s storage in connection with the Toledo North pipeline system and for the storage of NGLs from local producers and a refinery in Western Ohio. The terminal can receive and ship by pipeline in both directions and has a truck loading and unloading rack.

 

   

The Eastern region refined products pipelines consist of 6-inch to 16-inch diameters refined product pipelines in Eastern, Central and North Central Pennsylvania, 8-inch refined products pipeline in western New York and various diameters refined products pipeline in New Jersey (including 80 miles of the 16-inch diameter Harbor Pipeline).

 

   

The midcontinent region refined products pipelines primarily consist of 3-inch to 12-inch refined products pipelines in Ohio and 6-inch and 8-inch refined products pipeline in Michigan.

 

   

The Southwest region refined products pipelines are located in Eastern Texas and consist primarily of 8-inch diameter refined products pipeline.

 

   

The Inland refined products pipeline consists of 12, 10, 8 and 6-inch diameter pipelines in the western, northwestern, and northeastern regions of Ohio.

 

   

The JC Nolan Pipeline is a joint venture between a wholly-owned subsidiary of the Partnership and a wholly-owned subsidiary of Sunoco LP, which transports diesel fuel from a tank farm in Hebert, Texas to Midland, Texas, and was placed into service in July 2019 and has a throughput capacity of approximately 36 MBbls/d.

 

   

We have 37 refined products terminals with an aggregate storage capacity of approximately 8 MMBbls that facilitate the movement of refined products to or from storage or transportation systems, such as a pipeline, to other transportation systems, such as trucks or other pipelines. Each facility typically consists of multiple storage tanks and is equipped with automated truck loading equipment that is operational 24 hours a day.

 

   

In addition to crude oil service, the Eagle Point terminal can accommodate three marine vessels (ships or barges) to receive and deliver refined products to outbound ships and barges. The tank farm has a total active refined products storage capacity of approximately 7 MMBbls and provides customers with access to the facility via ship, barge and pipeline. The terminal can deliver via ship, barge, truck or pipeline, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.

 

   

The Marcus Hook Terminal also has a tank farm with total refined products storage capacity of approximately 2 MMBbls of refined products storage. The terminal receives and delivers refined products via pipeline and primarily provides terminalling services to support movements on our refined products pipelines.

 

   

The JC Nolan Terminal, located in Midland, Texas, is a joint venture between a wholly-owned subsidiary of the Partnership and a wholly-owned subsidiary of Sunoco LP, which provides diesel fuel storage that was placed into service in August 2019.

 

   

This segment also includes the following joint ventures: 15% membership interest in the Explorer Pipeline Company, a 1,850-mile pipeline which originates from refining centers in Beaumont, Port Arthur, and Houston, Texas and extends to Chicago, Illinois; 31% membership interest in the Wolverine Pipe Line Company, a 1,055-mile pipeline that originates from Chicago, Illinois and extends to Detroit, Grand Haven, and Bay City, Michigan; 17% membership interest in the West Shore Pipe Line Company, a 650-mile pipeline which originates in Chicago, Illinois and extends to Madison and Green Bay, Wisconsin; a 14%

 

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membership interest in the Yellowstone Pipe Line Company, a 710-mile pipeline which originates from Billings, Montana and extends to Moses Lake, Washington.

Crude Oil Transportation and Services

The following details our pipelines and terminals in its crude oil transportation and services operations:

 

Description of Assets

   Ownership
Interest
    Miles of
Crude
Pipeline(1)
     Working
Storage
Capacity
(MBbls)
 

Dakota Access Pipeline

     36.40     1,172      —    

Energy Transfer Crude Oil Pipeline

     36.40     744      —    

Bayou Bridge Pipeline

     60     212      —    

Permian Express Pipelines

     87.7     1,760      —    

Wattenberg Oil Trunkline

     100     75      360

White Cliffs Pipeline(2)

     51     527      100

Maurepas Pipeline

     51     106      —    

Other Crude Oil Pipelines

     100     6,256      —    

Nederland Terminal

     100     —          29,000

Fort Mifflin Terminal

     100     —          3,300

Eagle Point Terminal

     100     —          1,800

Midland Terminal

     100     —          1,000

Marcus Hook Terminal

     100     —          1,000

Houston Terminal

     100     —          18,200

Cushing Facility

     100     —          7,700

Patoka, Illinois Terminal

     87.7     —          1,900

 

(1) 

Miles of pipeline as reported to PHMSA.

(2) 

The White Cliffs Pipeline consists of two parallel, 12-inch common carrier crude oil pipelines: one crude oil pipeline and one NGL pipeline.

Our crude oil operations consist of an integrated set of pipeline, terminalling, trucking and acquisition and marketing assets that service the movement of crude oil from producers to end-user markets. The following details our assets in the crude oil transportation and services segment:

Crude Oil Pipelines

Our crude oil pipelines consist of approximately 10,850 miles of crude oil trunk and gathering pipelines in the southwest, northwest and midwest United States, including our wholly-owned interests in West Texas Gulf, Permian Express Terminal LLC, Mid-Valley and Wattenberg Oil Trunkline. Additionally, we have equity ownership interests in two crude oil pipelines. Our crude oil pipelines provide access to several trading hubs, including the largest trading hub for crude oil in the United States located in Cushing, Oklahoma, and other trading hubs located in Midland, Colorado City and Longview, Texas. Our crude oil pipelines also deliver to and connect with other pipelines that deliver crude oil to a number of refineries.

 

   

Bakken Pipeline. The Dakota Access and Energy Transfer Crude Oil pipelines are collectively referred to as the “Bakken Pipeline.” The Bakken Pipeline is a 1,916-mile pipeline with capacity of 570 MBbls/d, that transports domestically produced crude oil from the Bakken/Three Forks production areas in North Dakota to a storage and terminal hub outside of Patoka, Illinois, or to gulf coast connections including our crude terminal in Nederland, Texas.

The pipeline transports light, sweet crude oil from North Dakota to major refining markets in the Midwest and Gulf Coast regions.

 

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The Dakota Access Pipeline went into service on June 1, 2017 and consists of approximately 1,172 miles of 12, 20, 24 and 30-inch diameter pipeline traversing North Dakota, South Dakota, Iowa and Illinois. Crude oil transported on the Dakota Access Pipeline originates at six terminal locations in the North Dakota counties of Mountrail, Williams and McKenzie. The pipeline delivers the crude oil to a hub outside of Patoka, Illinois where it can be delivered to the Energy Transfer Crude Oil Pipeline for delivery to the Gulf Coast or can be transported via other pipelines to refining markets throughout the Midwest.

The Energy Transfer Crude Oil Pipeline went into service on June 1, 2017 and consists of approximately 675 miles of mostly 30-inch converted natural gas pipeline and 69 miles of new 30-inch pipeline from Patoka, Illinois to Nederland, Texas, where the crude oil can be refined or further transported to additional refining markets.

 

   

Bayou Bridge Pipeline. The Bayou Bridge Pipeline is a joint venture between ETO and Phillips 66, in which ETO has a 60% ownership interest and serves as the operator of the pipeline. Phase I of the pipeline, which consists of a 30-inch pipeline from Nederland, Texas to Lake Charles, Louisiana, went into service in April 2016. Phase II of the pipeline, which consists of 24-inch pipe from Lake Charles, Louisiana to St. James, Louisiana, which went into service in March 2019.

With the completion of Phase II, Bayou Bridge Pipeline has a capacity of approximately 480 MBbls/d of light and heavy crude oil from different sources to the St. James crude oil hub, which is home to important refineries located in the Gulf Coast region.

 

   

Permian Express Pipelines. The Permian Express pipelines are part of the PEP joint venture and include the Permian Express 1, Permian Express 2, Permian Express 3, Permian Express 4, Permian Longview, Louisiana Access, Longview to Louisiana and Nederland Access pipelines. These pipelines are comprised of crude oil trunk pipelines and crude oil gathering pipelines in Texas and Oklahoma and provide takeaway capacity from the Permian Basin, with origins in multiple locations in Western Texas.

 

   

White Cliffs Pipeline. White Cliffs Pipeline, which was acquired by ET in the SemGroup acquisition and contributed to ETO in January 2020, owns a 12-inch common carrier, crude oil pipeline, with a throughput capacity of 100 MBbls/d, that transports crude oil from Platteville, Colorado to Cushing, Oklahoma.

 

   

Maurepas Pipeline. The Maurepas Pipeline, which was acquired by ET in the SemGroup acquisition and contributed to ETO in January 2020, consists of three pipelines, with an aggregate throughput capacity of 460 MBbls/d, which service refineries in the Gulf Coast region.

 

   

Other Crude Oil pipelines include the Mid-Valley pipeline system which originates in Longview, Texas and passes through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky and Ohio and terminates in Samaria, Michigan. This pipeline provides crude oil to a number of refineries, primarily in the Midwest United States.

In addition, we own a crude oil pipeline that runs from Marysville, Michigan to Toledo, Ohio, and a truck injection point for local production at Marysville. This pipeline receives crude oil from the Enbridge pipeline system for delivery to refineries located in Toledo, Ohio and to MPLX’s Samaria, Michigan tank farm, which supplies Marathon Petroleum Corporation’s refinery in Detroit, Michigan.

We also own and operate crude oil pipeline and gathering systems in Oklahoma and Kansas. We have the ability to deliver substantially all of the crude oil gathered on our Oklahoma and Kansas systems to Cushing. We are one of the largest purchasers of crude oil from producers in the area, and our crude oil acquisition and marketing activities business is the primary shipper on our Oklahoma crude oil system.

Crude Oil Terminals

 

   

Nederland. The Nederland Terminal, located on the Sabine-Neches waterway between Beaumont and Port Arthur, Texas, is a large marine terminal providing storage and distribution services for refiners and other large transporters of crude oil and NGLs. The terminal receives, stores, and distributes crude oil, NGLs, feedstocks, petrochemicals and bunker oils (used for fueling ships and other marine vessels). The terminal

 

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currently has a total storage capacity of approximately 29 MMBbls in approximately 160 above ground storage tanks with individual capacities of up to 660 MBbls.

The Nederland Terminal can receive crude oil at four of its five ship docks and four barge berths. The four ship docks are capable of receiving over 2 MMBbls/d of crude oil. In addition to our crude oil pipelines, the terminal can also receive crude oil through a number of other pipelines, including the DOE. The DOE pipelines connect the terminal to the United States Strategic Petroleum Reserve’s West Hackberry caverns at Hackberry, Louisiana and Big Hill caverns near Winnie, Texas, which have an aggregate storage capacity of approximately 395 MMBbls.

The Nederland Terminal can deliver crude oil and other petroleum products via pipeline, barge and ship. The terminal has three ship docks and three barge berths that are capable of delivering crude oils for international transport. In total, the terminal is capable of delivering over 2 MMBbls/d of crude oil to our crude oil pipelines or a number of third-party pipelines including the DOE. The Nederland Terminal generates crude oil revenues primarily by providing term or spot storage services and throughput capabilities to a number of customers.

 

   

Fort Mifflin. The Fort Mifflin terminal complex is located on the Delaware River in Philadelphia, Pennsylvania and includes the Fort Mifflin terminal, the Hog Island wharf, the Darby Creek tank farm and connecting pipelines. The Fort Mifflin terminal contains two ship docks with freshwater drafts and a total storage capacity of approximately 570 MBbls. Crude oil and some refined products enter the Fort Mifflin terminal primarily from marine vessels on the Delaware River.

The Hog Island wharf is located next to the Fort Mifflin terminal on the Delaware River and receives crude oil via two ship docks. The Darby Creek tank farm is a primary crude oil storage terminal that receives crude oil from the Fort Mifflin terminal and Hog Island wharf via our pipelines and has a total storage capacity of approximately 2.7 MMBbls

 

   

Eagle Point. The Eagle Point terminal is located in Westville, New Jersey and consists of docks, truck loading facilities and a tank farm. The docks are located on the Delaware River and can accommodate three marine vessels (ships or barges) to receive and deliver crude oil, intermediate products and refined products to outbound ships and barges. The tank farm has a total active storage capacity of approximately 1.8 MMBbls and can receive crude oil via barge and rail and deliver via ship and barge, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.

 

   

Midland. The Midland terminal is located in Midland, Texas and was acquired in November 2016 from Vitol. The facility includes approximately 1 MMBbls of crude oil storage, a combined 20 lanes of truck loading and unloading, and provides access to the Permian Express 2 transportation system.

 

   

Marcus Hook Terminal. The Marcus Hook Terminal can receive crude oil via marine vessel and can deliver via marine vessel and pipeline. The terminal has a total active crude oil storage capacity of approximately 1 MMBbls.

 

   

Patoka, Illinois Terminal. The Patoka, Illinois terminal is a tank farm owned by the PEP joint venture and is located in Marion County, Illinois. The facility includes 234 acres of owned land and provides for approximately 1.9 MMBbls of crude oil storage.

 

   

Houston Terminal. The Houston Terminal, which was acquired by ET in the SemGroup acquisition and contributed to ETO in February 2020, consists of storage tanks located on the Houston Ship Channel with an aggregate storage capacity of 18.2 MMBbls used to store, blend and transport refinery products and refinery feedstocks via pipeline, barge, rail, truck and ship. This facility has five deep-water ship docks on the Houston Ship Channel capable of loading and unloading Suezmax cargo vessels and seven barge docks which can accommodate 23 barges simultaneously, three crude oil pipelines connecting to four refineries and numerous rail and truck loading spots.

 

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Cushing Facilities. The Cushing Facility, which was acquired by ET in the SemGroup acquisition and contributed to ETO in January 2020, has approximately 7.7 MMBbls of crude oil storage, of which 5.7 MMBbls are leased to customers and 2.0 MMBbls are available for crude oil operations, blending and marketing activities. The storage terminal has inbound connections with the White Cliffs Pipeline from Platteville, Colorado, the Great Salt Plains Pipeline from Cherokee, Oklahoma, the Cimarron Pipeline from Boyer, Kansas, and two-way connections with all of the other major storage terminals in Cushing. The Cushing terminal also includes truck unloading facilities.

Crude Oil Acquisition and Marketing

Our crude oil acquisition and marketing operations are conducted using our assets, which include approximately 363 crude oil transport trucks, 350 trailers and approximately 166 crude oil truck unloading facilities, as well as third-party truck, rail, pipeline and marine assets.

Investment in Sunoco LP

Sunoco LP is a distributor of motor fuels and other petroleum products which Sunoco LP supplies to third-party dealers and distributors, to independent operators of commission agent locations and other commercial consumers of motor fuel. Also included in the wholesale operations are transmix processing plants and refined products terminals. Transmix is the mixture of various refined products (primarily gasoline and diesel) created in the supply chain (primarily in pipelines and terminals) when various products interface with each other. Transmix processing plants separate this mixture and return it to salable products of gasoline and diesel.

Sunoco LP is the exclusive wholesale supplier of the Sunoco-branded motor fuel, supplying an extensive distribution network of approximately 5,556 Sunoco-branded company and third-party operated locations throughout the East Coast, Midwest, South Central and Southeast regions of the United States. Sunoco LP believes it is one of the largest independent motor fuel distributors of Chevron, ExxonMobil and Valero branded motor fuel in the United States. In addition to distributing motor fuels, Sunoco LP also distributes other petroleum products such as propane and lubricating oil, and Sunoco LP receives rental income from real estate that it leases or subleases.

Sunoco LP operations primarily consist of fuel distribution and marketing.

Sunoco LP’s Fuel Distribution and Marketing Operations

Sunoco LP’s fuel distribution and marketing operations are conducted by the following consolidated subsidiaries:

 

   

Sunoco, LLC (“Sunoco LLC”), a Delaware limited liability company, primarily distributes motor fuel in 30 states throughout the East Coast, Midwest, South Central and Southeast regions of the United States. Sunoco LLC also processes transmix and distributes refined product through its terminals in Alabama, Texas, Arkansas and New York;

 

   

Sunoco Retail LLC (“Sunoco Retail”), a Pennsylvania limited liability company, owns and operates retail stores that sell motor fuel and merchandise primarily in New Jersey;

 

   

Aloha Petroleum LLC, a Delaware limited liability company, distributes motor fuel and operates terminal facilities on the Hawaiian Islands; and

 

   

Aloha Petroleum, Ltd. (“Aloha”), a Hawaii corporation, owns and operates retail stores on the Hawaiian Islands.

Sunoco LP purchases motor fuel primarily from independent refiners and major oil companies and distributes it across more than 30 states throughout the East Coast, Midwest, South Central and Southeast regions of the United States, as well as Hawaii to approximately:

 

   

78 company owned and operated retail stores;

 

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539 independently operated consignment locations where Sunoco LP sells motor fuel to customers under commission agent arrangements with such operators;

 

   

6,803 convenience stores and retail fuel outlets operated by independent operators, which are referred to as “dealers” or “distributors,” pursuant to long-term distribution agreements; and

 

   

2,476 other commercial customers, including unbranded convenience stores, other fuel distributors, school districts and municipalities and other industrial customers.

Sunoco LP’s Other Operations

Sunoco LP’s other operations include retail operations in Hawaii and New Jersey, credit card services and franchise royalties.

Investment in USAC

The following details the assets of USAC:

USAC’s modern, standardized compression unit fleet is powered primarily by the Caterpillar, Inc.’s 3400, 3500 and 3600 engine classes, which range from 401 to 5,000 horsepower per unit. These larger horsepower units, which USAC defines as 400 horsepower per unit or greater, represented 86.3% of its total fleet horsepower as of December 31, 2020. The remainder of its fleet consists of smaller horsepower units ranging from 40 horsepower to 399 horsepower that are primarily used in gas lift applications.

The following table provides a summary of USAC’s compression units by horsepower as of December 31, 2020:

 

Unit Horsepower

   Fleet
Horsepower
     Number
of Units
     Percent of
Fleet
Horsepower
    Percent of
Units
 

Small horsepower

          

<400

     510,123      3,001      13.7     55.0

Large horsepower

          

>400 and <1,000

     437,543      751      11.7     13.8

>1,000

     2,778,515      1,702      74.6     31.2
  

 

 

    

 

 

    

 

 

   

 

 

 

Total large horsepower

     3,216,058      2,453      86.3     45.0
  

 

 

    

 

 

    

 

 

   

 

 

 

Total horsepower

     3,726,181      5,454      100.0     100.0
  

 

 

    

 

 

    

 

 

   

 

 

 

All Other

The following details the significant assets in the “All Other” segment.

Contract Services Operations

We own and operate a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and Btu management. Our contract treating services are primarily located in Texas, Louisiana and Arkansas.

Compression

We own DDT, which provides compression services to customers engaged in the transportation of natural gas, including our other segments.

 

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Natural Resources Operations

Our Natural Resources operations primarily involve the management and leasing of coal properties and the subsequent collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants, collecting oil and gas royalties and from coal transportation, or wheelage fees. As of December 31, 2020, we owned or controlled approximately 757 million tons of proven and probable coal reserves in central and northern Appalachia, properties in eastern Kentucky, southwestern Virginia and southern West Virginia, and in the Illinois Basin, properties in southern Illinois, Indiana, and western Kentucky and as the operator of end-user coal handling facilities.

Canadian Operations

Our Canadian operations, which were acquired in the SemGroup acquisition, include a 51% ownership interest in Energy Transfer Canada which owns and operates natural gas processing and gathering facilities in Alberta, Canada. The Canadian operations assets include four sour natural gas processing plants and two sweet natural gas processing plants that have a combined operating capacity of 1,290 MMcf/d and a network of approximately 848 miles of natural gas gathering and transportation pipelines. The principal process performed at the processing plants is to remove contaminants and render the gas salable to downstream pipelines and markets.

Business Strategy

We believe we have engaged, and will continue to engage, in a well-balanced plan for growth through strategic acquisitions, internally generated expansion, measures aimed at increasing the profitability of our existing assets and executing cost control measures where appropriate to manage our operations.

We intend to continue to operate as a diversified, growth-oriented limited partnership. We believe that by pursuing independent operating and growth strategies we will be best positioned to achieve our objectives. We balance our desire for growth with our goal of preserving a strong balance sheet, ample liquidity and investment grade credit metrics.

Following is a summary of the business strategies of our core businesses:

Growth through acquisitionsWe intend to continue to make strategic acquisitions that offer the opportunity for operational efficiencies and the potential for increased utilization and expansion of our existing assets while supporting our investment grade credit ratings.

Engage in construction and expansion opportunitiesWe intend to leverage our existing infrastructure and customer relationships by constructing and expanding systems to meet new or increased demand for midstream and transportation services.

Increase cash flow from fee-based businessesWe intend to increase the percentage of our business conducted with third parties under fee-based arrangements in order to provide for stable, consistent cash flows over long contract periods while reducing exposure to changes in commodity prices.

Enhance profitability of existing assetsWe intend to increase the profitability of our existing asset base by adding new volumes under long-term producer commitments, undertaking additional initiatives to enhance utilization and reducing costs by improving operations.

Competition

Natural Gas

The business of providing natural gas gathering, compression, treating, transportation, storage and marketing services is highly competitive. Since pipelines are generally the only practical mode of transportation for natural

 

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gas over land, the most significant competitors of our transportation and storage segment are other pipelines. Pipelines typically compete with each other based on location, capacity, price and reliability.

We face competition with respect to retaining and obtaining significant natural gas supplies under terms favorable to us for the gathering, treating and marketing portions of our business. Our competitors include major integrated oil and gas companies, interstate and intrastate pipelines and other companies that gather, compress, treat, process, transport and market natural gas. Many of our competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than ours.

In marketing natural gas, we have numerous competitors, including marketing affiliates of interstate pipelines, major integrated oil and gas companies, and local and national natural gas gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Local utilities and distributors of natural gas are, in some cases, engaged directly, and through affiliates, in marketing activities that compete with our marketing operations.

NGL

In markets served by our NGL pipelines, we face competition with other pipeline companies, including those affiliated with major oil, petrochemical and natural gas companies, and barge, rail and truck fleet operations. In general, our NGL pipelines compete with these entities in terms of transportation fees, reliability and quality of customer service. We face competition with other storage facilities based on fees charged and the ability to receive and distribute the customer’s products. We compete with a number of NGL fractionators in Texas and Louisiana. Competition for such services is primarily based on the fractionation fee charged.

Crude Oil and Refined Products

In markets served by our crude oil and refined products pipelines, we face competition from other pipelines as well as rail and truck transportation. Generally, pipelines are the safest, lowest cost method for long-haul, overland movement of products and crude oil. Therefore, the most significant competitors for large volume shipments in the areas served by our pipelines are other pipelines. In addition, pipeline operations face competition from rail and trucks that deliver products in a number of areas that our pipeline operations serve. While their costs may not be competitive for longer hauls or large volume shipments, rail and trucks compete effectively for incremental and marginal volume in many areas served by our pipelines.

With respect to competition from other pipelines, the primary competitive factors consist of transportation charges, access to crude oil supply and market demand. Competitive factors in crude oil purchasing and marketing include price and contract flexibility, quantity and quality of services, and accessibility to end markets.

Our refined product terminals compete with other independent terminals with respect to price, versatility and services provided. The competition primarily comes from integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading operations.

Wholesale Fuel Distribution and Retail Marketing

In our wholesale fuel distribution business, we compete primarily with other independent motor fuel distributors. The markets for distribution of wholesale motor fuel and the large and growing convenience store industry are highly competitive and fragmented, which results in narrow margins. We have numerous competitors, some of which may have significantly greater resources and name recognition than we do. Significant competitive factors include the availability of major brands, customer service, price, range of services offered and quality of service, among others. We rely on our ability to provide value-added and reliable service and to control our operating costs in order to maintain our margins and competitive position.

 

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In our retail business, we face strong competition in the market for the sale of retail gasoline and merchandise. Our competitors include service stations of large integrated oil companies, independent gasoline service stations, convenience stores, fast food stores, supermarkets, drugstores, dollar stores, club stores and other similar retail outlets, some of which are well-recognized national or regional retail systems. The number of competitors varies depending on the geographical area. It also varies with gasoline and convenience store offerings. The principal competitive factors affecting our retail marketing operations include gasoline and diesel acquisition costs, site location, product price, selection and quality, site appearance and cleanliness, hours of operation, store safety, customer loyalty and brand recognition. We compete by pricing gasoline competitively, combining our retail gasoline business with convenience stores that provide a wide variety of products, and using advertising and promotional campaigns.

Credit Risk and Customers

Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.

The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrial end-users, oil and gas producers, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.

Our natural gas transportation and midstream revenues are derived significantly from companies that engage in exploration and production activities. The discovery and development of new shale formations across the United States has created an abundance of natural gas and crude oil resulting in a negative impact on prices in recent years for natural gas and crude oil. As a result, some of our exploration and production customers have been adversely impacted; however, we are monitoring these customers and mitigating credit risk as necessary.

During the year ended December 31, 2020, none of our customers individually accounted for more than 10% of our consolidated revenues.

Regulation

Regulation of Interstate Natural Gas Pipelines. The FERC has broad regulatory authority over the business and operations of interstate natural gas pipelines. Under the Natural Gas Act of 1938 (“NGA”), the FERC generally regulates the transportation of natural gas in interstate commerce. For FERC regulatory purposes, “transportation” includes natural gas pipeline transmission (forwardhauls and backhauls), storage and other services. The Florida Gas Transmission, Transwestern, Panhandle, Trunkline, Tiger, Fayetteville Express, Rover, Sea Robin, Gulf States and Midcontinent Express pipelines transport natural gas in interstate commerce and thus each qualifies as a “natural-gas company” under the NGA subject to the FERC’s regulatory jurisdiction. We also hold certain natural gas storage facilities that are subject to the FERC’s regulatory oversight under the NGA.

 

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The FERC’s NGA authority includes the power to:

 

   

approve the siting, construction and operation of new facilities;

 

   

review and approve transportation rates;

 

   

determine the types of services our regulated assets are permitted to perform;

 

   

regulate the terms and conditions associated with these services;

 

   

permit the extension or abandonment of services and facilities;

 

   

require the maintenance of accounts and records; and

 

   

authorize the acquisition and disposition of facilities.

Under the NGA, interstate natural gas companies must charge rates that are just and reasonable. In addition, the NGA prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.

The maximum rates to be charged by NGA-jurisdictional natural gas companies and their terms and conditions for service are required to be on file with the FERC. Most natural gas companies are authorized to offer discounts from their FERC-approved maximum just and reasonable rates when competition warrants such discounts. Natural gas companies are also generally permitted to offer negotiated rates different from rates established in their tariff if, among other requirements, such companies’ tariffs offer a cost-based recourse rate to a prospective shipper as an alternative to the negotiated rate. Natural gas companies must make offers of rate discounts and negotiated rates on a basis that is not unduly discriminatory. Existing tariff rates may be challenged by complaint or on the FERC’s own motion, and if found unjust and unreasonable, may be altered on a prospective basis from no earlier than the date of the complaint or initiation of a proceeding by the FERC. The FERC must also approve all rate changes. We cannot guarantee that the FERC will allow us to charge rates that fully recover our costs or continue to pursue its approach of pro-competitive policies.

For two of our NGA-jurisdictional natural gas companies, ETC Tiger and FEP, the large majority of capacity in those pipelines is subscribed for lengthy terms under FERC-approved negotiated rates. However, as indicated above, cost-based recourse rates are also offered under their respective tariffs.

Pursuant to the FERC’s rules promulgated under the Energy Policy Act of 2005, it is unlawful for any entity, directly or indirectly, in connection with the purchase or sale of electric energy or natural gas or the purchase or sale of transmission or transportation services subject to FERC jurisdiction: (i) to defraud using any device, scheme or artifice; (ii) to make any untrue statement of material fact or omit a material fact; or (iii) to engage in any act, practice or course of business that operates or would operate as a fraud or deceit. The Commodity Futures Trading Commission (“CFTC”) also holds authority to monitor certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act (“CEA”). With regard to our physical purchases and sales of natural gas, NGLs or other energy commodities; our transportation of these energy commodities; and any related hedging activities that we undertake, we are required to observe these anti-market manipulation laws and related regulations enforced by the FERC and/or the CFTC. These agencies hold substantial enforcement authority, including the ability to assess or seek civil penalties of up to $1.3 million per day per violation, to order disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

Failure to comply with the NGA, the Energy Policy Act of 2005, the CEA and the other federal laws and regulations governing our operations and business activities can result in the imposition of administrative, civil and criminal remedies.

Regulation of Intrastate Natural Gas and NGL Pipelines. Intrastate transportation of natural gas and NGLs is largely regulated by the state in which such transportation takes place. To the extent that our intrastate natural gas

 

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transportation systems transport natural gas in interstate commerce, the rates and terms and conditions of such services are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act of 1978 (“NGPA”). The NGPA regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of a local distribution company or an interstate natural gas pipeline. The rates and terms and conditions of some transportation and storage services provided on the Oasis pipeline, HPL System, East Texas pipeline, ET Fuel System, Trans-Pecos pipeline and Comanche Trail pipeline are subject to FERC regulation pursuant to Section 311 of the NGPA. Under Section 311, rates charged for intrastate transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. The terms and conditions of service set forth in the intrastate facility’s statement of operating conditions are also subject to FERC review and approval. Should the FERC determine not to authorize rates equal to or greater than our currently approved Section 311 rates, our business may be adversely affected. Failure to observe the service limitations applicable to transportation and storage services under Section 311, failure to comply with the rates approved by the FERC for Section 311 service, and failure to comply with the terms and conditions of service established in the pipeline’s FERC-approved statement of operating conditions could result in an alteration of jurisdictional status, and/or the imposition of administrative, civil and criminal remedies.

Our intrastate natural gas operations are also subject to regulation by various agencies in Texas, principally the TRRC. Our intrastate pipeline and storage operations in Texas are also subject to the Texas Utilities Code, as implemented by the TRRC. Generally, the TRRC is vested with authority to ensure that rates, operations and services of gas utilities, including intrastate pipelines, are just and reasonable and not discriminatory. The rates we charge for transportation services are deemed just and reasonable under Texas law unless challenged in a customer or TRRC complaint. We cannot predict whether such a complaint will be filed against us or whether the TRRC will change its regulation of these rates. Failure to comply with the Texas Utilities Code can result in the imposition of administrative, civil and criminal remedies.

Our NGL pipelines and operations are subject to state statutes and regulations which could impose additional environmental, safety and operational requirements relating to the design, siting, installation, testing, construction, operation, replacement and management of NGL transportation systems. In some jurisdictions, state public utility commission oversight may include the possibility of fines, penalties and delays in construction related to these regulations. In addition, the rates, terms and conditions of service for shipments of NGLs on our pipelines are subject to regulation by the FERC under the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992 (the “EPAct of 1992”) if the NGLs are transported in interstate or foreign commerce whether by our pipelines or other means of transportation. Since we do not control the entire transportation path of all NGLs shipped on our pipelines, FERC regulation could be triggered by our customers’ transportation decisions.

Regulation of Sales of Natural Gas and NGLs. The price at which we buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. The price at which we sell NGLs is not subject to federal or state regulation.

To the extent that we enter into transportation contracts with natural gas pipelines that are subject to FERC regulation, we are subject to FERC requirements related to the use of such capacity. Any failure on our part to comply with the FERC’s regulations and policies, or with an interstate pipeline’s tariff, could result in the imposition of civil and criminal penalties.

Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC frequently proposes and implements new rules and regulations affecting those segments of the natural gas industry. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation. We cannot predict the ultimate impact of these regulatory changes to our natural gas marketing operations, and we note that some of the FERC’s regulatory changes may adversely affect the availability and reliability of interruptible transportation

 

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service on interstate pipelines. We do not believe that we will be affected by any such FERC action in a manner that is materially different from other natural gas marketers with whom we compete.

Regulation of Gathering Pipelines. Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC under the NGA. We own a number of natural gas pipelines in Texas, Louisiana and West Virginia that we believe meet the traditional tests the FERC uses to establish a pipeline’s status as a gathering pipeline not subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of substantial litigation and varying interpretations, so the classification and regulation of our gathering facilities could be subject to change based on future determinations by the FERC, the courts and Congress. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation.

In Texas, our gathering facilities are subject to regulation by the TRRC under the Texas Utilities Code in the same manner as described above for our intrastate pipeline facilities. Louisiana’s Pipeline Operations Section of the Department of Natural Resources’ Office of Conservation is generally responsible for regulating intrastate pipelines and gathering facilities in Louisiana and has authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities.

Historically, apart from pipeline safety, Louisiana has not acted to exercise this jurisdiction respecting gathering facilities. In Louisiana, our Chalkley System is regulated as an intrastate transporter, and the Louisiana Office of Conservation has determined that our Whiskey Bay System is a gathering system.

We are subject to state ratable take and common purchaser statutes in all of the states in which we operate. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting the right of an owner of gathering facilities to decide with whom it contracts to purchase or transport natural gas.

Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels. For example, the TRRC has approved changes to its regulations governing transportation and gathering services performed by intrastate pipelines and gatherers, which prohibit such entities from unduly discriminating in favor of their affiliates. Many of the producing states have adopted some form of complaint-based regulation that generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination allegations. Our gathering operations could be adversely affected should they be subject in the future to the application of additional or different state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Regulation of Interstate Crude Oil, NGL and Products Pipelines. Interstate common carrier pipeline operations are subject to rate regulation by the FERC under the ICA, the EPAct of 1992, and related rules and orders. The ICA requires that tariff rates for petroleum pipelines be “just and reasonable” and not unduly discriminatory and that such rates and terms and conditions of service be filed with the FERC. This statute also permits interested persons to challenge proposed new or changed rates. The FERC is authorized to suspend the effectiveness of such rates for up to seven months, though rates are typically not suspended for the maximum allowable period. If the FERC finds that the new or changed rate is unlawful, it may require the carrier to pay refunds for the period

 

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that the rate was in effect. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.

The FERC generally has not investigated interstate rates on its own initiative when those rates, like those we charge, have not been the subject of a protest or a complaint by a shipper. However, the FERC could investigate our rates at the urging of a third party if the third party is either a current shipper or has a substantial economic interest in the tariff rate level. Although no assurance can be given that the tariff rates charged by us ultimately will be upheld if challenged, management believes that the tariff rates now in effect for our pipelines are within the maximum rates allowed under current FERC policies and precedents.

For many locations served by our product and crude pipelines, we are able to establish negotiated rates. Otherwise, we are permitted to charge cost-based rates, or in many cases, grandfathered rates based on historical charges or settlements with our customers. To the extent we rely on cost-of-service ratemaking to establish or support our rates, the issue of the proper allowance for federal and state income taxes could arise. In July 2016, the United States Court of Appeals for the District of Columbia Circuit issued an opinion in United Airlines, Inc., et al. v. FERC, finding that the FERC had acted arbitrarily and capriciously when it failed to demonstrate that permitting an interstate petroleum products pipeline organized as a master limited partnership, or MLP, to include an income tax allowance in the cost of service underlying its rates, in addition to the discounted cash flow return on equity, would not result in the pipeline partnership owners double recovering their income taxes. The court vacated the FERC’s order and remanded to the FERC to consider mechanisms for demonstrating that there is no double recovery as a result of the income tax allowance. In December 2016, the FERC issued a Notice of Inquiry Regarding the Commission’s Policy for Recovery of Income Tax Costs. The FERC requested comments regarding how to address any double recovery resulting from the Commission’s current income tax allowance and rate of return policies. The comment period with respect to the notice of inquiry ended in April 2017.

In March 2018, the FERC issued a Revised Policy Statement on Treatment of Income Taxes in which the FERC found that an impermissible double recovery results from granting an MLP pipeline both an income tax allowance and a return on equity pursuant to the FERC’s discounted cash flow methodology. The FERC revised its previous policy, stating that it would no longer permit an MLP pipeline to recover an income tax allowance in its cost of service. The FERC stated it will address the application of the United Airlines decision to non-MLP partnership forms as those issues arise in subsequent proceedings. The FERC will also apply the revised Policy Statement and the Tax Cuts and Jobs Act of 2017 to initial crude oil pipeline cost-of-service rates and cost-of-service rate changes on a going-forward basis under the FERC’s existing ratemaking policies, including cost-of-service rate proceedings resulting from shipper-initiated complaints. In July 2018, the FERC dismissed requests for rehearing and clarification of the March 2018 Revised Policy Statement, but provided further guidance, clarifying that a pass-through entity will not be precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double recovery of investors’ income tax costs. On July 31, 2020, the United States Court of Appeals for the District of Columbia Circuit issued an opinion upholding FERC’s decision denying a separate master limited partnership recovery of an income tax allowance and its decision not to require the master limited partnership to refund accumulated deferred income tax balances. In light of the rehearing order’s clarification regarding individual entities’ ability to argue in support of recovery of an income tax allowance and the court’s subsequent opinion upholding denial of an income tax allowance to a master limited partnership, the impacts the FERC’s policy on the treatment of income taxes may have on the rates an interstate pipeline held in a tax-pass-through entity can charge for the FERC regulated transportation services are unknown at this time. Please see “Item 1A. Risk Factors—Regulatory Matters.”

Effective January 2018, the 2017 Tax Cuts and Jobs Act changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. With the lower tax rate, and as discussed immediately

 

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above, the maximum tariff rates allowed by the FERC under its rate base methodology may be impacted by a lower income tax allowance component. Many of our interstate pipelines, such as Tiger, Midcontinent Express and Fayetteville Express, have negotiated market rates that were agreed to by customers in connection with long-term contracts entered into to support the construction of the pipelines. Other systems, such as FGT, Transwestern and Panhandle, have a mix of tariff rate, discount rate, and negotiated rate agreements. In addition, several of these pipelines are covered by approved settlements, pursuant to which rate filings will be made in the future. As such, the timing and impact to these systems of any tax-related policy change is unknown at this time.

The EPAct of 1992 required the FERC to establish a simplified and generally applicable methodology to adjust tariff rates for inflation for interstate petroleum pipelines. As a result, the FERC adopted an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods, or PPI-FG. The FERC’s indexing methodology is subject to review every five years.

In December 2020, FERC issued an order setting the indexed rate at PPI-FG plus 0.78% during the five-year period commencing July 1, 2021 and ending June 30, 2026. That order is subject to rehearing and appeal, and several rehearing requests have been filed and are pending before FERC. The indexing methodology is applicable to existing rates, including grandfathered rates, with the exclusion of market-based rates. A pipeline is not required to raise its rates up to the index ceiling, but it is permitted to do so and rate increases made under the index are presumed to be just and reasonable unless a protesting party can demonstrate that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs. Under the indexing rate methodology, in any year in which the index is negative, pipelines must file to lower their rates if those rates would otherwise be above the rate ceiling.

Finally, in November 2017, the FERC responded to a petition for declaratory order and issued an order that may have significant impacts on the way a marketer of crude oil or petroleum products that is affiliated with an interstate pipeline can price its services if those services include transportation on an affiliate’s interstate pipeline. In particular, the FERC’s November 2017 order prohibits buy/sell arrangements by a marketing affiliate if: (i) the transportation differential applicable to its affiliate’s interstate pipeline transportation service is at a discount to the affiliated pipeline’s filed rate for that service; and (ii) the pipeline affiliate subsidizes the loss. Several parties have requested that the FERC clarify its November 2017 order or, in the alternative, grant rehearing of the November 2017 order. The FERC extended the time frame to respond to such requests in January 2018 but has not yet taken final action. We are unable to predict how the FERC will respond to such requests. Depending on how the FERC responds, it could have an impact on the rates we are permitted to charge.

Regulation of Intrastate Crude Oil, NGL and Products Pipelines. Some of our crude oil, NGL and products pipelines are subject to regulation by the TRRC, the Pennsylvania Public Utility Commission and the Oklahoma Corporation Commission. The operations of our joint venture interests are also subject to regulation in the states in which they operate. The applicable state statutes require that pipeline rates be nondiscriminatory and provide no more than a fair return on the aggregate value of the pipeline property used to render services. State commissions generally have not initiated an investigation of rates or practices of petroleum pipelines in the absence of shipper complaints. Complaints to state agencies have been infrequent and are usually resolved informally. Although management cannot be certain that our intrastate rates ultimately would be upheld if challenged, we believe that, given this history, the tariffs now in effect are not likely to be challenged or, if challenged, are not likely to be ordered to be reduced.

In addition, as noted above, the rates, terms and conditions for shipments of crude oil, NGLs or products on our pipelines could be subject to regulation by the FERC under the ICA and the EPAct of 1992 if the crude oil, NGLs or products are transported in interstate or foreign commerce whether by our pipelines or other means of transportation. Since we do not control the entire transportation path of all crude oil, NGLs or products shipped on our pipelines, FERC regulation could be triggered by our customers’ transportation decisions.

 

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Regulation of Pipeline Safety. Our pipeline operations are subject to regulation by the DOT, through PHMSA, pursuant to the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), with respect to natural gas and the Hazardous Liquids Pipeline Safety Act of 1979, as amended (“HLPSA”), with respect to crude oil, NGLs and condensates. The NGPSA and HLPSA, as amended, govern the design, installation, testing, construction, operation, replacement and management of natural gas as well as crude oil, NGL and condensate pipeline facilities. Pursuant to these acts, PHMSA has promulgated regulations governing pipeline wall thickness, design pressures, maximum operating pressures, pipeline patrols and leak surveys, minimum depth requirements, and emergency procedures, as well as other matters intended to ensure adequate protection for the public and to prevent accidents and failures. Additionally, PHMSA has established a series of rules requiring pipeline operators to develop and implement integrity management programs for certain gas and hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect high consequence areas (“HCAs”), which are areas where a release could have the most significant adverse consequences, including high population areas, certain drinking water sources and unusually sensitive ecological areas. Failure to comply with the pipeline safety laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory, remedial or corrective action obligations, the occurrence of delays in permitting or the performance of projects, or the issuance of injunctions limiting or prohibiting some or all of our operations in the affected area.

The HLPSA and NGPSA have been amended by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”) and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (“2016 Pipeline Safety Act”). The 2011 Pipeline Safety Act increased the penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of safety issues that could result in the adoption of new regulatory requirements by PHMSA for existing pipelines. The 2011 Pipeline Safety Act doubled the maximum administrative fines for safety violations from $100,000 to $200,000 for a single violation and from $1 million to $2 million for a related series of violations, but provided that these maximum penalty caps do not apply to certain civil enforcement actions. In January 2021, PHMSA issued a final rule increasing those maximum civil penalties to $222,504 per day, with a maximum of $2,225,034 for a series of violations. Upon reauthorization of PHMSA, Congress often directs the agency to complete certain rulemakings. For example, in the Consolidated Appropriations Bill for Fiscal Year 2021, Congress reauthorized PHMSA through fiscal year 2023 and directed the agency to move forward with several regulatory actions, including the “Pipeline Safety: Class Location Change Requirements” and the “Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines” proposed rulemakings; Congress has also instructed PHMSA to issue final regulations to require operations of non-rural gas gathering lines and new and existing transmission and distribution pipelines to conduct certain leak detection and repair programs to require facility inspection and maintenance plans to align with those regulations. The timing and scope of such future rulemakings is uncertain.

In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. The states in which we conduct operations typically have developed regulatory programs that parallel the federal regulatory scheme and are applicable to intrastate pipelines. Under such state regulatory programs, states have the authority to conduct pipeline inspections, to investigate accidents and to oversee compliance and enforcement, safety programs and record maintenance and reporting. Congress, PHMSA and individual states may pass or implement additional safety requirements that could result in increased compliance costs for us and other companies in our industry. For example, federal construction, maintenance and inspection standards under the NGPSA that apply to pipelines in relatively populated areas may not apply to gathering lines running through rural regions. However, in October 2019, PHMSA published three final rules that create or expand reporting, inspection, maintenance, and other pipeline safety obligations, including, among other things, extending pipeline integrity assessments to pipelines in certain locations, including newly-defined “Moderate Consequence Areas” (“MCAs”).

In another example of how future legal requirements could result in increased compliance costs, notwithstanding the applicability of the federal OSHA’s Process Safety Management (“PSM”) regulations and the EPA’s Risk Management Planning (“RMP”) requirements at regulated facilities, PHMSA and one or more state regulators,

 

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including the TRRC, have in recent years, expanded the scope of their regulatory inspections to include certain in-plant equipment and pipelines found within NGL fractionation facilities and associated storage facilities, in order to assess compliance of such equipment and pipelines with hazardous liquid pipeline safety requirements. To the extent that these actions are pursued by PHMSA, midstream operators of NGL fractionation facilities and associated storage facilities subject to such inspection may be required to make operational changes or modifications at their facilities to meet standards beyond current PSM and RMP requirements, which changes or modifications may result in additional capital costs, possible operational delays and increased costs of operation that, in some instances, may be significant.

Environmental Matters

General. Our operation of processing plants, pipelines and associated facilities, including compression, in connection with the gathering, processing, storage and transmission of natural gas and the storage and transportation of NGLs, crude oil and refined products is subject to stringent U.S. federal, tribal, state and local laws and regulations, including those governing, among other things, air emissions, wastewater discharges, the use, management and disposal of hazardous and nonhazardous materials and wastes, and the cleanup of contamination. Similar or more stringent laws also exist in Canada. Noncompliance with such laws and regulations, or incidents resulting in environmental releases, could cause us to incur substantial costs, penalties, fines and criminal sanctions, third-party claims for personal injury or property damage, capital expenditures to retrofit or upgrade our facilities and programs, or curtailment or cancellation of permits on operations. As with the industry generally, compliance with existing and anticipated environmental laws and regulations increases our overall cost of doing business, including our cost of planning, permitting, constructing and operating our plants, pipelines and other facilities. As a result of these laws and regulations, our construction and operation costs include capital, operating and maintenance cost items necessary to maintain or upgrade our equipment and facilities.

We have implemented procedures designed to ensure that governmental environmental approvals for both existing operations and those under construction are updated as circumstances require. Historically, our environmental compliance costs have not had a material adverse effect on our business, results of operations or financial condition; however, there can be no assurance that such costs will not be material in the future. For example, we cannot be certain that identification of presently unidentified conditions, more rigorous enforcement by regulatory agencies, enactment of more stringent environmental laws and regulations or unanticipated events will not arise in the future and give rise to environmental liabilities that could have a material adverse effect on our business, financial condition or results of operations.

Uncertainty about the future course of regulation exists because of the recent change in U.S. presidential administrations. In January 2021, the current administration issued an executive order directing all federal agencies to review and take action to address any federal regulations promulgated during the prior administration that may be inconsistent with the current administration’s policies. As a result, it is unclear the degree to which certain recent regulatory developments may be modified or rescinded. The executive order also established an Interagency Working Group on the Social Cost of Greenhouse Gases (“Working Group”), which is called on to, among other things, develop methodologies for calculating the “social cost of carbon,” “social cost of nitrous oxide” and “social cost of methane.” Recommendations from the Working Group are due beginning June 1, 2021, and final recommendations no later than January 2022. Further regulation of air emissions, as well as uncertainty regarding the future course of regulation, could eventually reduce the demand for oil and natural gas and, in turn, have a material adverse effect on our business, financial condition or results of operations.

Hazardous Substances and Waste Materials. To a large extent, the environmental laws and regulations affecting our operations relate to the release of hazardous substances and waste materials into soils, groundwater and surface water and include measures to prevent, minimize or remediate contamination of the environment. These laws and regulations generally regulate the generation, storage, treatment, transportation and disposal of hazardous substances and waste materials and may require investigatory and remedial actions at sites where such

 

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material has been released or disposed. For example, the Comprehensive Environmental Response, Compensation and Liability Act, as amended, (“CERCLA”), also known as the “Superfund” law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct on certain classes of persons that contributed to a release of a “hazardous substance” into the environment. These persons include the owner and operator of the site where a release occurred and companies that disposed or arranged for the disposal of the hazardous substance that has been released into the environment. Under CERCLA, these persons may be subject to strict, joint and several liability, without regard to fault, for, among other things, the costs of investigating and remediating the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA and comparable state law also authorize the federal EPA, its state counterparts, and, in some instances, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Although “petroleum” as well as natural gas and NGLs are excluded from CERCLA’s definition of a “hazardous substance,” in the course of our ordinary operations we generate wastes that may fall within that definition or that may be subject to other waste disposal laws and regulations. We may be responsible under CERCLA or state laws for all or part of the costs required to clean up sites at which such substances or wastes have been disposed.

We also generate both hazardous and nonhazardous wastes that are subject to requirements of the federal Resource Conservation and Recovery Act, as amended, (“RCRA”) and comparable state statutes. We are not currently required to comply with a substantial portion of the RCRA hazardous waste requirements at many of our facilities because the minimal quantities of hazardous wastes generated there make us subject to less stringent non-hazardous management standards. From time to time, the EPA has considered or third parties have petitioned the agency on the adoption of stricter handling, storage and disposal standards for nonhazardous wastes, including certain wastes associated with the exploration, development and production of crude oil and natural gas. For example, in 2016, the EPA entered into an agreement with several environmental groups to analyze certain Subtitle D criteria regulations pertaining to oil and gas wastes and, if necessary, revise them. In response to the decree, in April 2019, the EPA signed a determination that revision of the regulations is not necessary at this time. It is possible that some wastes generated by us that are currently classified as nonhazardous may in the future be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly disposal requirements, or that the full complement of RCRA standards could be applied to facilities that generate lesser amounts of hazardous waste. Changes such as these examples in applicable regulations may result in a material increase in our capital expenditures or plant operating and maintenance expense and, in the case of our oil and natural gas exploration and production customers, could result in increased operating costs for those customers and a corresponding decrease in demand for our processing, transportation and storage services.

We currently own or lease sites that have been used over the years by prior owners and lessees and by us for various activities related to gathering, processing, storage and transmission of natural gas, NGLs, crude oil and refined products. Waste disposal practices within the oil and gas industry have improved over the years with the passage and implementation of various environmental laws and regulations. Nevertheless, some hydrocarbons and wastes have been disposed of or otherwise released on or under various sites during the operating history of those facilities that are now owned or leased by us. Notwithstanding the possibility that these releases may have occurred during the ownership or operation of these assets by others, these sites may be subject to CERCLA, RCRA and comparable state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or contamination (including soil and groundwater contamination) or to prevent the migration of contamination.

As of December 31, 2020 and 2019, accruals of $306 million and $320 million, respectively, were recorded in our consolidated balance sheets as accrued and other current liabilities and other non-current liabilities to cover estimated material environmental liabilities.

 

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The Partnership is subject to extensive and frequently changing federal, tribal, state and local laws and regulations, including those relating to the discharge of materials into the environment or that otherwise relate to the protection of the environment, waste management and the characteristics and composition of fuels. These laws and regulations require environmental assessment and remediation efforts at many of ETC Sunoco’s facilities and at formerly owned or third-party sites. Accruals for these environmental remediation activities amounted to $247 million and $252 million at December 31, 2020 and 2019, respectively, which is included in the total accruals above. These legacy sites that are subject to environmental assessments include formerly owned terminals and other logistics assets, retail sites that are no longer operated by ETC Sunoco, closed and/or sold refineries and other formerly owned sites. We have established a wholly-owned captive insurance company for these legacy sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company. As of December 31, 2020, the captive insurance company held $189 million of cash and investments.

The Partnership’s accrual for environmental remediation activities reflects anticipated work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. The accrual for known claims is undiscounted and is based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. It is often extremely difficult to develop reasonable estimates of future site remediation costs due to changing regulations, changing technologies and their associated costs, and changes in the economic environment. Engineering studies, historical experience and other factors are used to identify and evaluate remediation alternatives and their related costs in determining the estimated accruals for environmental remediation activities.

Under various environmental laws, including the RCRA, the Partnership has initiated corrective remedial action at certain of its facilities, formerly owned facilities and at certain third-party sites. At the Partnership’s major manufacturing facilities, we have typically assumed continued industrial use and a containment/remediation strategy focused on eliminating unacceptable risks to human health or the environment. The remediation accruals for these sites reflect that strategy. Accruals include amounts designed to prevent or mitigate off-site migration and to contain the impact on the facility property, as well as to address known, discrete areas requiring remediation within the plants. Remedial activities include, for example, closure of RCRA waste management units, recovery of hydrocarbons, handling of impacted soil, mitigation of surface water impacts and prevention or mitigation of off-site migration. A change in this approach as a result of changing the intended use of a property or a sale to a third party could result in a comparatively higher cost remediation strategy in the future.

In general, a remediation site or issue is typically evaluated on an individual basis based upon information available for the site or issue and no pooling or statistical analysis is used to evaluate an aggregate risk for a group of similar items (for example, service station sites) in determining the amount of probable loss accrual to be recorded. The estimates of environmental remediation costs also frequently involve evaluation of a range of estimates. In many cases, it is difficult to determine that one point in the range of loss estimates is more likely than any other. In these situations, existing accounting guidance allows us the minimum amount of the range to accrue. Accordingly, the low end of the range often represents the amount of loss which has been recorded. The Partnership’s consolidated balance sheet reflected $306 million in environmental accruals as of December 31, 2020.

In summary, total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the nature of operations at each site, the technology available and needed to meet the various existing legal requirements, the nature and terms of cost-sharing arrangements with other potentially responsible parties, the availability of insurance coverage, the nature and extent of future environmental laws and regulations, inflation rates, terms of consent agreements or remediation permits with regulatory agencies and the determination of the Partnership’s liability at the sites, if any, in light of the number, participation level and financial viability of the other parties. The recognition of additional losses, if and when

 

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they were to occur, would likely extend over many years, but management can provide no assurance that it would be over many years. If changes in environmental laws or regulations occur or the assumptions used to estimate losses at multiple sites are adjusted, such changes could materially and adversely impact multiple facilities, formerly owned facilities and third-party sites at the same time. As a result, from time to time, significant charges against income for environmental remediation may occur. And while management does not believe that any such charges would have a material adverse impact on the Partnership’s consolidated financial position, it can provide no assurance.

Transwestern conducts soil and groundwater remediation at a number of its facilities. Some of the cleanup activities include remediation of several compressor sites on the Transwestern system for contamination by PCBs, and the costs of this work are not eligible for recovery in rates. The total accrued future estimated cost of remediation activities expected to continue through 2025 is $4 million, which is included in the total environmental accruals mentioned above. Transwestern received FERC approval for rate recovery of projected soil and groundwater remediation costs not related to PCBs effective April 1, 2007. Transwestern, as part of ongoing arrangements with customers, continues to incur costs associated with containing and removing potential PCB contamination. Future costs cannot be reasonably estimated because remediation activities are undertaken as potential claims are made by customers and former customers. Such future costs are not expected to have a material impact on our financial position, results of operations or cash flows, but management can provide no assurance.

Air Emissions. Our operations are subject to the federal Clean Air Act, as amended, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our processing plants, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities, such as our processing plants and compression facilities, expected to produce air emissions or to result in the increase of existing air emissions, that we obtain and strictly comply with air permits containing various emissions and operational limitations, or that we utilize specific emission control technologies to limit emissions. We will incur capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. In addition, our processing plants, pipelines and compression facilities are subject to increasingly stringent regulations, including regulations that require the installation of control technology or the implementation of work practices to control hazardous air pollutants. Moreover, the Clean Air Act requires an operating permit for major sources of emissions and this requirement applies to some of our facilities. Historically, our costs for compliance with existing Clean Air Act and comparable state law requirements have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future. The EPA and state agencies are often considering, proposing or finalizing new regulations that could impact our existing operations and the costs and timing of new infrastructure development. For example, in October 2015, the EPA published a final rule under the Clean Air Act, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone to 70 parts per billion for the 8-hour primary and secondary ozone standards. The EPA completed attainment/non-attainment designations in 2018, and states with moderate or high non-attainment areas must submit state implementation plans to the EPA by October 2021. By law, the EPA must review each NAAQS every five years. In December 2020, the EPA announced that it was retaining without revision the 2015 NAAQS for ozone. However, as mentioned above, in January 2021, the Biden administration issued an executive order directing federal agencies to review and take action to address any federal regulations or similar agency actions during the prior administration that may be inconsistent with the current administration’s stated priorities. The EPA was specifically ordered to, among other things, propose a Federal Implementation Plan for ozone standards for California, Connecticut, New York, Pennsylvania and Texas by January 2022. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Also, states are expected to implement more stringent requirements as a result of this new final rule, which could apply to our customers’ operations. Compliance with this or other new regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact our business.

 

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Clean Water Act. The Federal Water Pollution Control Act of 1972, as amended, (“Clean Water Act”) and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including hydrocarbon-bearing wastes, into state waters and waters of the United States. Pursuant to the Clean Water Act and similar state laws, a National Pollutant Discharge Elimination System, or state permit, or both, must be obtained to discharge pollutants into federal and state waters. In addition, the Clean Water Act and comparable state laws require that individual permits or coverage under general permits be obtained by subject facilities for discharges of storm water runoff. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. In June 2015, the EPA and the USACE published a final rule attempting to clarify the federal jurisdictional reach over “waters of the United States” (“WOTUS”), but legal challenges to this rule followed. In January 2020, a new “waters of the United States” rule was finalized to replace the June 2015 rule, defining the following four categories of waters as WOTUS: traditional navigable waters and territorial seas; perennial and intermittent tributaries to those waters; lakes, ponds and impoundments of jurisdictional waters; and wetlands adjacent to jurisdictional waters. However, legal challenges to this rulemaking are ongoing, and it is possible that the Biden Administration could propose a broader interpretation of WOTUS. As a result of these developments, the scope of jurisdiction under the Clean Water Act is uncertain at this time, but to the extent any rule expands the scope of the Clean Water Act’s jurisdiction, our operations as well as our exploration and production customers’ drilling programs could incur increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.

Additionally, for over 35 years, the USACE has authorized construction, maintenance, and repair of pipelines under a streamlined Nationwide Permit (“NWP”) program. From time to time, environmental groups have challenged the NWP program, and, in April 2020, the U.S. District Court for the District of Montana determined that NWP 12 failed to comply with consultation requirements under the federal Endangered Species Act. The district court vacated NWP 12 and enjoined the issuance of new authorizations for oil and gas pipeline projects under the permit. While the district court’s order has subsequently been limited pending appeal, and NWP 12 authorizations remain available for certain oil and gas pipeline projects, we cannot predict the ultimate outcome of this case and its impacts on the NWP program. Additionally, in response to the vacatur, the Corps has announced a reissuance of NWP 13 for oil and natural gas pipeline activities, including certain revisions to the conditions for the use of NWP 12; however, the rulemaking may be subject to litigation or to further revision under the Biden Administration. While the full extent and impact of the vacatur is unclear at this time, we could face significant delays and financial costs if we must obtain individual permit coverage from USACE for our projects.

Spills. Our operations can result in the discharge of regulated substances, including NGLs, crude oil or other products. The Clean Water Act, as amended by the federal Oil Pollution Act of 1990, as amended, (“OPA”), and comparable state laws impose restrictions and strict controls regarding the discharge of regulated substances into state waters or waters of the United States. The Clean Water Act and comparable state laws can impose substantial administrative, civil and criminal penalties for non-compliance including spills and other non-authorized discharges. The OPA subjects owners of covered facilities to strict joint and potentially unlimited liability for removal costs and other consequences of a release of oil, where the release is into navigable waters, along shorelines or in the exclusive economic zone of the United States. Spill prevention control and countermeasure requirements of the Clean Water Act and some state laws require that containment dikes and similar structures be installed to help prevent the impact on navigable waters in the event of a release of oil. PHMSA, the EPA, or various state regulatory agencies, has approved our oil spill emergency response plans that are to be used in the event of a spill incident.

In addition, some states maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Our management believes that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our results of operations, financial position or expected cash flows.

Endangered Species. The Endangered Species Act, as amended, restricts activities that may affect endangered or threatened species or their habitat. Similar protections are offered to migratory birds under the Migratory Bird

 

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Treaty Act. We may operate in areas that are currently designated as a habitat for endangered or threatened species or where the discovery of previously unidentified endangered species, or the designation of additional species as endangered or threatened may occur in which event such one or more developments could cause us to incur additional costs, to develop habitat conservation plans, to become subject to expansion or operating restrictions, or bans in the affected areas. Moreover, such designation of previously unprotected species as threatened or endangered in areas where our oil and natural gas exploration and production customers operate could cause our customers to incur increased costs arising from species protection measures and could result in delays or limitations in our customers’ performance of operations, which could reduce demand for our services.

Climate Change. Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of greenhouse gases (“GHGs”). These efforts have included consideration of cap-and-trade programs, carbon taxes and GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. In the United States, no comprehensive climate change legislation has been implemented at the federal level to date. However, Canada has implemented a federal carbon pricing regime, and, in the United States, President Biden has announced that he intends to pursue substantial reductions in greenhouse gas emissions, particularly from the oil and gas sector. For example, on January 27, 2021, President Biden signed an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, an increase in the production of offshore wind energy, and an increased emphasis on climate-related risks across government agencies and economic sectors. Additionally, the EPA has adopted rules under authority of the Clean Air Act that, among other things, establish Potential for Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal, or criteria, pollutant emissions, which reviews could require securing PSD permits at covered facilities emitting GHGs and meeting “best available control technology” standards for those GHG emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, including, among others, onshore processing, transmission, storage and distribution facilities. In October 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting facilities and blowdowns of natural gas transmission pipelines.

Federal agencies also have begun directly regulating GHG emissions, such as methane, from oil and natural gas operations. In June 2016, the EPA published New Source Performance Standards (“NSPS”), known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound (“VOC”) emissions. These Subpart OOOOa standards expand previously issued NSPS published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices, requiring additional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations. In September 2020, the EPA removed natural gas transmission and storage operations from this sector and rescinded the methane-specific requirements of the rule for production and processing facilities. However, President Biden has signed an executive order calling for the suspension, revision, or rescission of the September 2020 rule and the reinstatement or issuance of methane emissions standards for new, modified, and existing oil and has facilities, including the transmission and storage segments. Methane emission standards imposed on the oil and gas sector could result in increased costs to our operations as well as result in delays or curtailment in such operations, which costs, delays or curtailment could adversely affect our business. Several states have also adopted, or are considering adopting, regulations related to GHG emissions, some of which are more stringent than those implemented by the federal government. Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France in signing the “Paris Agreement,” a treaty that requires member countries to submit individually-determined, non-binding emission reduction goals every five years beginning in 2020. Although the United States has withdrawn from this agreement, President Biden has signed executive

 

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orders recommitting the United States to the Paris Agreement and calling for the federal government to formulate the United States’ emissions reduction goal. However, the impacts of these orders are unclear at this time.

The January 2021 climate change executive order also directed the Secretary of the Interior to pause new oil and natural gas leasing on public lands or in offshore waters pending completion of a comprehensive review of the federal permitting and leasing practices, consider whether to adjust royalties associated with coal, oil, and gas resources extracted from public lands and offshore waters, or take other appropriate action, to account for corresponding climate costs. The executive order also directed the federal government to identify “fossil fuel subsidies” to take steps to ensure that, to the extent consistent with applicable law, federal funding is not directly subsidizing fossil fuels. As noted above, a separate executive order issued in January 2021 established a Working Group that is called on to, among other things, develop methodologies for calculating the “social cost of carbon,” “social cost of nitrous oxide” and “social cost of methane.” Recommendations from the Working Group are due beginning June 1, 2021, and final recommendations no later than January 2022.

The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our services, results of operations, and cash flows. Litigation risks are also increasing, as several oil and gas companies have been sued for allegedly causing climate-related damages due to their production and sale of fossil fuel products or for allegedly being aware of the impacts of climate change for some time but failing to adequately disclose such risks to their investors or customers. There is also a risk that financial institutions could be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. For example, recently, the Federal Reserve announced that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Ultimately, this could make it more difficult to secure funding for exploration and production or midstream activities. Finally, most scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events that could have an adverse effect on our assets.

If such effects were to occur, our operations could be adversely affected in various ways, including damages to our facilities from powerful winds or rising waters, or increased costs for insurance. Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for our NGLs and natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we transport, and thus demand for our services. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our products could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.

Employee Health and Safety. We are subject to the requirements of the federal OSHA and comparable state laws that regulate the protection of the health and safety of workers. In addition, the Occupational Safety and Health Administration’s hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. Historically, our costs for OSHA required activities, including general industry standards, recordkeeping requirements, and monitoring of occupational exposure to regulated substances, have not had a material adverse effect on our results of operations but there is no assurance that such costs will not be material in the future.

Natural Resource Reviews. The National Environmental Policy Act (“NEPA”) provides for an environmental impact assessment process in connection with certain projects that involve federal lands or require approvals by federal agencies. The NEPA process implicates a number of other environmental laws and regulations, including the Endangered Species Act, Migratory Bird Treaty Act, Rivers and Harbors Act, Clean Water Act, Bald and Golden

 

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Eagle Protection Act, Fish and Wildlife Coordination Act, Marine Mammal Protection Act and National Historic Preservation Act, often requiring coordination with numerous governmental authorities. The NEPA review process can be lengthy and subjective, resulting in delays in obtaining federal approvals for projects. Our projects that are subject to the NEPA can include pipeline construction and pipeline integrity projects that involve federal lands or require approvals by federal agencies. More stringent environmental impact analyses under or third-party challenges with respect to the sufficiency of any environmental impact statement or assessment prepared pursuant to NEPA could adversely impact such projects in the form of delays or increased compliance and mitigations costs.

Indigenous Protections. Part of our operations cross land that has historically been apportioned to various Native American/First Nations tribes (“Indigenous Peoples”), who may exercise significant jurisdiction and sovereignty over their lands. Indigenous Peoples may also have certain treaty rights and rights to consultation on projects that may affect such lands. Our operations may be impacted to the extent these tribal governments are found to have and choose to act upon such jurisdiction over lands where we operate. For example, in 2020, the Supreme Court ruled in McGirt v. Oklahoma that the Muscogee (Creek) Nation reservation in Eastern Oklahoma has not been disestablished. Although the court’s ruling indicates that it is limited to criminal law, as applied within the Muscogee (Creek) Nation reservation, the ruling may have significant potential implications for civil law, both in the Muscogee (Creek) Nation reservation and other reservations that may similarly be found to not have been disestablished. State courts in Oklahoma have applied the analysis in McGirt in ruling that the Cherokee, Chickasaw, Seminole, and Choctaw reservations likewise had not been disestablished.

On October 1, 2020, the EPA granted approval to the State of Oklahoma under Section 10211(a) of the Safe, Accountable, Flexible, Efficient Transportation Equity Act of 2005 (the “SAFETE Act”) to administer all of the State’s existing EPA-approved regulatory programs to Indian Country within the state except: Indian allotments to which Indians titles have not been extinguished; lands that are held in trust by the United States on behalf of any Indian or Tribe; lands that are owned in fee by any Tribe where title was acquired through a treaty with the United States to which such tribe is a party and that have never been allotted to any citizen or member of such Tribe. The approval extends the State’s authority for existing EPA-approved regulatory programs to all lands within the State to which the State applied such programs prior to the U.S. Supreme Court’s ruling in McGirt. However, several Tribes have expressed dissatisfaction with the consultation process performed in relation to this approval, and it is possible that EPA’s approval under the SAFETE Act could be challenged. Additionally, the SAFETE Act provides that any Tribe in Oklahoma may seek “Treatment as a State” by the EPA, and it is possible that one or more of the Tribes in Oklahoma may seek such an approval from EPA. At this time, we cannot predict how these jurisdictional issues may ultimately be resolved.

Human Capital Management

As of December 31, 2020, ET and its consolidated subsidiaries employed an aggregate of 11,421 employees, 1,217 of which are represented by labor unions. We believe that our relations with our employees are good.

Our employees are our greatest asset, and we seek to attract and retain top talent by fostering a culture that is guided by our core values in a manner that respects all people and cultures, promotes safety, and focuses on the protection of public health and the environment.

Ethics and Values. We are committed to operating our business in a manner that honors and respects all people and the communities in which we do business. We recognize that people are our most valued resource, and we are committed to hiring and investing in employees who strive for excellence and live by our core values: working safely, corporate stewardship, ethics and integrity, entrepreneurial mindset, our people, excellence and results, and social responsibility. We value our employees for what they bring to our organization by embracing those from all backgrounds, cultures, and experiences. We also believe that the keys to our successes have been the cultivation of an atmosphere of inclusion and respect within our family of partnerships and sustaining organizations that promote diversity and provide support across all communities. These are the principles upon which we build and strengthen relationships among our people, our stakeholders, and those within the communities we support.

 

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Respecting All People and All Cultures. We believe strict adherence to our Code of Business Conduct and Ethics is not only right, but is in the best interest of the Partnership, its Unitholders, its customers, and the industry in general. In all instances, the policies of the Partnership require that the business of the Partnership be conducted in a lawful and ethical manner. Every employee acting on behalf of the Partnership must adhere to these policies. Please refer to “Item 10. Directors, Executive Officers and Corporate Governance” for additional information on our Code of Business Conduct and Ethics.

Commitment to Protecting Public Health, Safety and the Environment. Protecting public health and the environment is the primary initiative for our environmental management teams, both in the construction and operation of our assets. These teams consist of environmental engineers, scientists and geologists focused on ensuring that our environmental management systems responsibly and efficiently reduce emissions, protect and preserve the land, water and air around us, and remain in compliance with all applicable regulations. Our environmental, health and safety department’s more than 100 environmental and safety professionals provide environmental and safety training to our field representatives. This group also assists others throughout the organization in identifying continuous training for personnel, including the training that is required by applicable laws, regulations, standards, and permit conditions. Our safety standards and expectations are communicated to all employees and contractors with the expectation that each individual has the obligation to make safety the highest priority. Our safety culture aims to promote an open environment for discovering, resolving, and sharing safety challenges. We strive to eliminate unwanted safety events through a comprehensive process that promotes leadership, employee involvement, communication, personal responsibility to comply with standard operating procedures and regulatory requirements, effective risk reduction processes, maintaining clean facilities, contractor safety, and personal wellness. Energy Transfer’s goal is operational excellence, which means an injury- and incident-free workplace. To achieve this, we strive to hire and maintain the most qualified and dedicated workforce in the industry and make safety and safety accountability part of our daily operations. The OSHA Total Reportable Incident Rate (“TRIR”) is a key performance indicator by which we evaluate the success of our safety programs. TRIR provides companies with a look at their safety record performance for the year by calculating the number of recordable incidents per 200,000 hours worked. Out of more than 17 million hours worked, our TRIR was 0.87 for 2020, compared to 0.94 in 2019. We believe the Partnership’s low TRIR speaks to the investment in and focus on safety and environmental compliance as well as the reliability of our assets.

Regarding COVID-19, as an essential business providing critical energy infrastructure, the safety of our employees and the continued operation of our assets are our top priorities, and we will continue to operate in accordance with federal, state and local health guidelines and safety protocols. We have implemented several new policies and provided employees with training to help maintain the health and safety of our workforce.

For additional information on our Human Capital initiatives, please see our Community Engagement Report available on our website at http://www.energytransfer.com/corporate-responsibility/. Information contained on our website is not part of this report.

SEC Reporting

We file or furnish annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any related amendments and supplements thereto with the SEC. From time to time, we may also file registration and related statements pertaining to equity or debt offerings. The SEC maintains an internet website at http://www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.

We provide electronic access, free of charge, to our periodic and current reports, and amendments to these reports, on our internet website located at http://www.energytransfer.com. These reports are available on our website as soon as reasonably practicable after we electronically file such materials with the SEC. Information contained on our website is not part of this report.

 

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ITEM 1A. RISK FACTORS

In addition to risks and uncertainties in the ordinary course of business that are common to all businesses, important factors that are specific to our structure as a limited partnership, our industry and our company could materially impact our future performance and results of operations. We have provided below a list of these risk factors that should be reviewed when considering an investment in our securities. ETO, Panhandle, Sunoco LP and USAC file Annual Reports on Form 10-K that include risk factors that can be reviewed for further information. The risk factors set forth below, and those included in ETO’s, Panhandle’s, Sunoco LP’s and USAC’s Annual Reports, are not all the risks we face, and other factors currently considered immaterial or unknown to us may impact our future operations.

Risk Relating to the Partnership’s Business

Results of Operations and Financial Condition

Our cash flow depends primarily on the cash distributions we receive from our partnership interests in ETO, Sunoco LP and USAC, including the incentive distribution rights in Sunoco LP and, therefore, our cash flow is dependent upon the ability of ETO, Sunoco LP and USAC to make distributions in respect of those partnership interests.

We do not have any significant assets other than our partnership interests in ETO. As a result, our cash flow depends on the performance of ETO and its subsidiaries, including Sunoco LP and USAC, and their ability to make cash distributions, which is dependent on the results of operations, cash flows and financial condition of ETO and its subsidiaries, including Sunoco LP and USAC.

The amount of cash that ETO distributes to us each quarter depends upon the amount of cash ETO generates from its operations, which will fluctuate from quarter to quarter and will depend upon, among other things:

 

   

the amount of natural gas, NGLs, crude oil and refined products transported through ETO’s pipelines;

 

   

the level of throughput in processing and treating operations;

 

   

the fees charged and the margins realized by ETO, Sunoco LP and USAC for their services;

 

   

the price of natural gas, NGLs, crude oil and refined products;

 

   

the relationship between natural gas, NGL and crude oil prices;

 

   

the weather in their respective operating areas;

 

   

the level of competition from other midstream, transportation and storage and retail marketing companies and other energy providers;

 

   

the level of their respective operating costs and maintenance and integrity capital expenditures;

 

   

the tax profile on any blocker entities treated as corporations for federal income tax purposes that are owned by any of our subsidiaries;

 

   

prevailing economic conditions; and

 

   

the level and results of their respective derivative activities.

In addition, the actual amount of cash that ETO, and its subsidiaries, including Sunoco LP and USAC, will have available for distribution will also depend on other factors, such as:

 

   

the level of capital expenditures they make;

 

   

the level of costs related to litigation and regulatory compliance matters;

 

   

the cost of acquisitions, if any;

 

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the levels of any margin calls that result from changes in commodity prices;

 

   

debt service requirements;

 

   

fluctuations in working capital needs;

 

   

their ability to borrow under their respective revolving credit facilities;

 

   

their ability to access capital markets;

 

   

restrictions on distributions contained in their respective debt agreements; and

 

   

the amount, if any, of cash reserves established by the board of directors and their respective general partners in their discretion for the proper conduct of their respective businesses.

ET does not have any control over many of these factors, including the level of cash reserves established by the board of directors. Accordingly, we cannot guarantee that ETO, Sunoco LP and USAC will have sufficient available cash to pay a specific level of cash distributions to their respective partners.

Furthermore, Unitholders should be aware that the amount of cash that our subsidiaries have available for distribution depends primarily upon cash flow and is not solely a function of profitability, which is affected by non-cash items. As a result, our subsidiaries may declare and/or pay cash distributions during periods when they record net losses. Please read “Risks Related to the Businesses of our Subsidiaries” included in this Item 1A for a discussion of further risks affecting ETO’s ability to generate distributable cash flow.

Income from our midstream, transportation, terminalling and storage operations is exposed to risks due to fluctuations in the demand for and price of natural gas, NGLs, crude oil and refined products that are beyond our control.

The prices for natural gas, NGLs, crude oil and refined products reflect market demand that fluctuates with changes in global and United States economic conditions and other factors, including:

 

   

the level of domestic natural gas, NGL, refined products and oil production;

 

   

the level of natural gas, NGL, refined products and oil imports and exports, including liquefied natural gas;

 

   

actions taken by natural gas and oil producing nations;

 

   

instability or other events affecting natural gas and oil producing nations;

 

   

the impact of weather, public health crises such as pandemics (including COVID-19), and other events of nature on the demand for natural gas, NGLs, refined products and oil;

 

   

the availability of storage, terminal and transportation systems, and refining, processing and treating facilities;

 

   

the price, availability and marketing of competitive fuels;

 

   

the demand for electricity;

 

   

activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of oil and natural gas and related products;

 

   

the cost of capital needed to maintain or increase production levels and to construct and expand facilities;

 

   

the impact of energy conservation and fuel efficiency efforts; and

 

   

the extent of governmental regulations, taxation, fees and duties.

In the past, the prices of natural gas, NGLs, refined products and oil have been extremely volatile, and we expect this volatility to continue.

 

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Any loss of business from existing customers or our inability to attract new customers due to a decline in demand for natural gas, NGLs, refined products or oil could have a material adverse effect on our revenues and results of operations. In addition, significant price fluctuations for natural gas, NGL, refined products and oil commodities could materially affect our profitability.

The outbreak of COVID-19 and recent geopolitical developments in the crude oil market could adversely impact our business, financial condition and results of operations.

On January 30, 2020, the World Health Organization (“WHO”) announced a global health emergency because of a new strain of coronavirus known as COVID-19 due to the risks it imposes on the international community as the virus spreads globally. In March 2020, the WHO classified the COVID-19 outbreak as a pandemic, based on the rapid increase in exposure globally. The global spread of COVID-19 caused a significant decline in economic activity and a reduced demand for goods and services, particularly in the energy industry, due to reduced operations and/or closures of businesses, “shelter in place” and other similar requirements imposed by government authorities, or other actions voluntarily undertaken by individuals and businesses concerned about exposure to COVID-19. The extent to which the COVID-19 pandemic continues to impact our business, operations and financial results depends on numerous evolving factors that we cannot accurately predict, including: the duration and scope of the pandemic; governmental, business and individuals’ actions taken in response to the pandemic and the associated impact on economic activity; the effect on the level of demand for natural gas, NGLs, refined products and/or crude oil; our ability to procure materials and services from third parties that are necessary for the operation of our business; our ability to provide our services, including as a result of travel restrictions on our employees and employees of third parties that we utilize in connection with our services; the potential for key executives or employees to fall ill with COVID-19; and the ability of our customers to pay for our services if their businesses suffer as a result of the pandemic.

In addition, policy disputes between the Organization of Petroleum Exporting Countries and Russia in the first quarter of 2020 resulted in Saudi Arabia significantly discounting the price of its crude oil, as well as Saudi Arabia and Russia significantly increasing the amount of crude oil they produce. These actions led to significant volatility in crude oil prices. More specifically, the spot price for West Texas Intermediate (WTI) crude oil, for physical delivery at Cushing, Oklahoma, decreased from $63.27 per barrel on January 6, 2020 to $(36.98) per barrel on April 20, 2020 and increased to more than $60 per barrel in February 2021.

Reduced demand for natural gas, NGLs, refined products and/or crude oil caused by the COVID-19 pandemic and a decline in WTI crude oil prices caused by the actions of foreign oil-producing nations or other market factors may result in the shut-in of production from U.S. oil and gas wells, which in turn may result in decreased utilization of our midstream services related to crude oil, NGLs, refined products and natural gas. In addition, reduced demand for crude oil has resulted in an increase in worldwide crude oil storage inventories, which limits our options for end-markets for the products we transport.

The factors discussed above could have a material adverse effect on our business, results of operations and financial condition. In addition, significant price fluctuations for natural gas, NGLs, refined products and oil commodities could materially affect the value of our inventory, as well as the linefill and tank bottoms that we account for as non-current assets. We may be forced to delay some of our capital projects and our customers, who may be in financial distress, may slow down decision-making, delay planned projects or seek to renegotiate or terminate agreements with us. To the extent our counterparties are successful, we may not be able to obtain new contract terms that are favorable to us or to replace contracts that are terminated.

Further, the effects of the pandemic and geopolitical developments have market impacts, such that additional capital may be more difficult for us to obtain or available only on terms less favorable to us. Our inability to fund capital expenditures could have a material impact on our results of operations.

At this time, we cannot estimate the magnitude and duration of potential social, economic and labor instability as a direct result of COVID-19, or of potential industry disruption as a direct result of geopolitical developments in

 

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the oil market. Should any of these potential impacts continue for an extended period of time, it will have a negative impact on the demand for our services and an adverse effect on our financial position and results of operations. To the extent these factors adversely affect our business and financial results, they may also have the effect of heightening many of the other risks described in this “Risk Factors” section, as well as the risks discussed or referenced in any applicable prospectus supplement, including in the documents we incorporate by reference herein or therein, such as those relating to our indebtedness, our need to generate sufficient cash flows to service our indebtedness and our ability to comply with the covenants contained in the agreements that govern our indebtedness.

The failure to successfully combine the businesses of Energy Transfer and Enable in the expected time frame may adversely affect Energy Transfer’s future results.

The success of the merger will depend, in part, on the ability of Energy Transfer to realize the anticipated benefits from combining the businesses of Energy Transfer and Enable. To realize these anticipated benefits, Energy Transfer’s and Enable’s businesses must be successfully combined. If the combined entity is not able to achieve these objectives, the anticipated benefits of the merger may not be realized fully or at all or may take longer to realize than expected. In addition, the actual integration may result in additional and unforeseen expenses, which could reduce the anticipated benefits of the merger.

Energy Transfer and Enable, including their respective subsidiaries, have operated and, until the completion of the merger, will continue to operate independently. It is possible that the integration process could result in the loss of key employees, as well as the disruption of each partnership’s ongoing businesses or inconsistencies in their standards, controls, procedures and policies.

Any or all of those occurrences could adversely affect the combined entity’s ability to maintain relationships with customers and employees after the merger or to achieve the anticipated benefits of the merger. Integration efforts between the two partnerships will also divert management attention and resources. These integration matters could have an adverse effect on each of Energy Transfer and Enable.

An impairment of goodwill and intangible assets could reduce our earnings.

As of December 31, 2020, our consolidated balance sheet reflected $2.39 billion of goodwill and $5.75 billion of intangible assets. Goodwill is recorded when the purchase price of a business exceeds the fair value of the tangible and separately measurable intangible net assets. Accounting principles generally accepted in the United States require us to test goodwill for impairment on an annual basis or when events or circumstances occur, indicating that goodwill might be impaired. Long-lived assets such as intangible assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If we determine that any of our goodwill or intangible assets were impaired, we would be required to take an immediate charge to earnings with a correlative effect on partners’ capital and balance sheet leverage as measured by debt to total capitalization.

During the year ended December 31, 2020, the Partnership recognized goodwill impairments of $483 million related to our midstream operations, $1.28 billion related to our crude operations, $198 million related to our all other operations, $10 million related to our intrastate operations and $226 million related to our interstate operations, primarily due to decreases in projected future cash flow as a result of the overall market demand decline. In addition, USAC recognized a goodwill impairment of $619 million during the year ended December 31, 2020, which is included in the Partnership’s consolidated results of operations.

We depend on certain key producers for our supply of natural gas and the loss of any of these key producers could adversely affect our financial results.

Certain producers who are connected to our systems represent a material source of our supply of natural gas. We are not the only option available to these producers for disposition of the natural gas they produce. To the extent

 

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that these and other producers may reduce the volumes of natural gas that they supply us, we would be adversely affected unless we were able to acquire comparable supplies of natural gas from other producers.

Our intrastate transportation and storage and interstate transportation and storage operations depend on key customers to transport natural gas through our pipelines and the pipelines of our joint ventures.

During 2020, Trafigura US Inc. accounted for approximately 29% of our intrastate transportation and storage revenues. During 2020, Shell, Ascent Resources LLC and Antero Resources Corporation collectively accounted for 32% of our interstate transportation and storage revenues.

Our joint ventures, FEP and Citrus, also depend on key customers for the transport of natural gas through their pipelines. FEP has a small number of major shippers with one shipper accounting for approximately 64% of its revenues in 2020 while Citrus has long-term agreements with its top two customers which accounted for 54% of its 2020 revenue. For the Trans-Pecos and Comanche Trail pipelines, CFE International LLC is the primary shipper.

The failure of the major shippers on our and our joint ventures’ intrastate and interstate transportation and storage pipelines to fulfill their contractual obligations could have a material adverse effect on our cash flow and results of operations if we or our joint ventures were unable to replace these customers under arrangements that provide similar economic benefits as these existing contracts.

We may be unable to retain or replace existing midstream, transportation, terminalling and storage customers or volumes due to declining demand or increased competition in crude oil, refined products, natural gas and NGL markets, which would reduce our revenues and limit our future profitability.

The retention or replacement of existing customers and the volume of services that we provide at rates sufficient to maintain or increase current revenues and cash flows depends on a number of factors beyond our control, including the price of and demand for crude oil, refined products, natural gas and NGLs in the markets we serve and competition from other service providers.

A significant portion of our sales of natural gas are to industrial customers and utilities. As a consequence of the volatility of natural gas prices and increased competition in the industry and other factors, industrial customers, utilities and other gas customers are increasingly reluctant to enter into long-term purchase contracts. Many customers purchase natural gas from more than one supplier and have the ability to change suppliers at any time. Some of these customers also have the ability to switch between gas and alternate fuels in response to relative price fluctuations in the market. Because there are many companies of greatly varying size and financial capacity that compete with us in the marketing of natural gas, we often compete in natural gas sales markets primarily on the basis of price.

We also receive a substantial portion of our revenues by providing natural gas gathering, processing, treating, transportation and storage services. While a substantial portion of our services are sold under long-term contracts for reserved service, we also provide service on an unreserved or short-term basis. Demand for our services may be substantially reduced due to changing market prices. Declining prices may result in lower rates of natural gas production resulting in less use of services, while rising prices may diminish consumer demand and also limit the use of services. In addition, our competitors may attract our customers’ business. If demand declines or competition increases, we may not be able to sustain existing levels of unreserved service or renew or extend long-term contracts as they expire or we may reduce our rates to meet competitive pressures.

Revenue from our NGL transportation systems and refined products storage is also exposed to risks due to fluctuations in demand for transportation and storage service as a result of unfavorable commodity prices, competition from nearby pipelines, and other factors. We receive substantially all of our transportation revenues through dedicated contracts under which the customer agrees to deliver the total output from particular

 

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processing plants that are connected only to our transportation system. Reduction in demand for natural gas or NGLs due to unfavorable prices or other factors, however, may result lower rates of production under dedicated contracts and lower demand for our services. In addition, our refined products storage revenues are primarily derived from fixed capacity arrangements between us and our customers, a portion of our revenue is derived from fungible storage and throughput arrangements, under which our revenue is more dependent upon demand for storage from our customers.

The volume of crude oil and refined products transported through our crude oil and refined products pipelines and terminal facilities depends on the availability of attractively priced crude oil and refined products in the areas serviced by our assets. A period of sustained price reductions for crude oil or refined products could lead to a decline in drilling activity, production and refining of crude oil or import levels in these areas. A period of sustained increases in the price of crude oil or refined products supplied from or delivered to any of these areas could materially reduce demand for crude oil or refined products in these areas. In either case, the volumes of crude oil or refined products transported in our crude oil and refined products pipelines and terminal facilities could decline.

The loss of existing customers by our midstream, transportation, terminalling and storage facilities or a reduction in the volume of the services our customers purchase from us, or our inability to attract new customers and service volumes would negatively affect our revenues, be detrimental to our growth, and adversely affect our results of operations.

We and our subsidiaries, including Sunoco LP and USA Compression Partners, LP (“USAC”), are exposed to the credit risk of our customers and derivative counterparties, and an increase in the nonpayment and nonperformance by our customers or derivative counterparties could reduce our ability to make distributions to our unitholders.

We, Sunoco LP and USAC are subject to risks of loss resulting from nonpayment or nonperformance by our, Sunoco LP’s and USAC’s customers. Commodity price volatility and/or the tightening of credit in the financial markets may make it more difficult for customers to obtain financing and, depending on the degree to which this occurs, there may be a material increase in the nonpayment and nonperformance by our customers. In addition, our risk management activities are subject to the risks that a counterparty may not perform its obligation under the applicable derivative instrument, the terms of the derivative instruments are imperfect, and our risk management policies and procedures are not properly followed. Any material nonpayment or nonperformance by our customers or our derivative counterparties could reduce our ability to make distributions to our unitholders. Any substantial increase in the nonpayment and nonperformance by our customers could have a material effect on our, Sunoco LP’s and USAC’s results of operations and operating cash flows.

Due to recent market disruptions involving the COVID-19 pandemic, some of our counterparties may be forced to file for bankruptcy protection, in which case our existing contracts with those counterparties may be rejected by the bankruptcy court. Following the request of one of our FERC-regulated natural pipelines, the FERC commenced an investigation into whether the public interest requires abrogation or modification of a firm transportation agreement and an interruptible transportation agreement with one of our shippers. By order dated November 9, 2020, FERC held that the record did not support a finding that the public interest presently requires abrogation or modification of the subject firm transportation agreement. However, actual determination regarding the contract will depend upon further action by the counterparty and any further bankruptcy-related proceedings. If a counterparty is successful in rejecting an existing contract in bankruptcy, we expect that we would attempt to negotiate replacement contracts with those counterparties and, depending on the availability of alternatives to our services, these contracts may have terms that are less favorable to us than the contracts rejected in bankruptcy court.

 

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The profitability of certain activities in our natural gas gathering, processing, transportation and storage operations are largely dependent upon natural gas commodity prices, price spreads between two or more physical locations and market demand for natural gas and NGLs.

For a portion of the natural gas gathered on our systems, we purchase natural gas from producers at the wellhead and then gather and deliver the natural gas to pipelines where we typically resell the natural gas under various arrangements, including sales at index prices. Generally, the gross margins we realize under these arrangements decrease in periods of low natural gas prices.

We also enter into percent-of-proceeds arrangements, keep-whole arrangements, and processing fee agreements pursuant to which we agree to gather and process natural gas received from the producers.

Under percent-of-proceeds arrangements, we generally sell the residue gas and NGLs at market prices and remit to the producers an agreed upon percentage of the proceeds based on an index price. In other cases, instead of remitting cash payments to the producer, we deliver an agreed upon percentage of the residue gas and NGL volumes to the producer and sell the volumes we keep to third parties at market prices. Under these arrangements, our revenues and gross margins decline when natural gas prices and NGL prices decrease. Accordingly, a decrease in the price of natural gas or NGLs could have an adverse effect on our revenues and results of operations.

Under keep-whole arrangements, we generally sell the NGLs produced from our gathering and processing operations at market prices. Because the extraction of the NGLs from the natural gas during processing reduces the Btu content of the natural gas, we must either purchase natural gas at market prices for return to producers or make a cash payment to producers equal to the value of this natural gas. Under these arrangements, our gross margins generally decrease when the price of natural gas increases relative to the price of NGLs.

When we process the gas for a fee under processing fee agreements, we may guarantee recoveries to the producer. If recoveries are less than those guaranteed to the producer, we may suffer a loss by having to supply liquids or its cash equivalent to keep the producer whole.

We also receive fees and retain gas in kind from our natural gas transportation and storage customers. Our fuel retention fees and the value of gas that we retain in kind are directly affected by changes in natural gas prices. Decreases in natural gas prices tend to decrease our fuel retention fees and the value of retained gas.

In addition, we receive revenue from our off-gas processing and fractionating system in south Louisiana primarily through customer agreements that are a combination of keep-whole and percent-of-proceeds arrangements, as well as from transportation and fractionation fees. Consequently, a large portion of our off-gas processing and fractionation revenue is exposed to risks due to fluctuations in commodity prices. In addition, a decline in NGL prices could cause a decrease in demand for our off-gas processing and fractionation services and could have an adverse effect on our results of operations.

For our midstream segment, we generally analyze gross margin based on fee-based margin (which includes revenues from processing fee arrangements) and non-fee-based margin (which includes gross margin earned on percent-of-proceeds and keep-whole arrangements). The amount of segment margin earned by our midstream segment from fee-based and non-fee-based arrangements (individually and as a percentage of total revenues) will be impacted by the volumes associated with both types of arrangements, as well as commodity prices; therefore, the dollar amounts and the relative magnitude of gross margin from fee-based and non-fee-based arrangements in future periods may be significantly different from results reported in previous periods.

 

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Our midstream facilities and transportation pipelines provide services related to natural gas wells that experience production declines over time, which we may not be able to replace with natural gas production from newly drilled wells in the same natural gas basins or in other new natural gas producing areas.

In order to maintain or increase throughput levels on our gathering systems and transportation pipeline systems and asset utilization rates at our treating and processing plants, we must continually contract for new natural gas supplies and natural gas transportation services.

A substantial portion of our assets, including our gathering systems and our processing and treating plants, are connected to natural gas reserves and wells that experience declining production over time. Our gas transportation pipelines are also dependent upon natural gas production in areas served by our gathering systems or in areas served by other gathering systems or transportation pipelines that connect with our transportation pipelines. We may not be able to obtain additional contracts for natural gas supplies for our natural gas gathering systems, and we may be unable to maintain or increase the levels of natural gas throughput on our transportation pipelines. The primary factors affecting our ability to connect new supplies of natural gas to our gathering systems include our success in contracting for existing natural gas supplies that are not committed to other systems and the level of drilling activity and production of natural gas near our gathering systems or in areas that provide access to our transportation pipelines or markets to which our systems connect. We have no control over the level of drilling activity in our areas of operation, the amount of reserves underlying the wells and the rate at which production from a well will decline. In addition, we have no control over producers or their production and contracting decisions.

While a substantial portion of our services are provided under long-term contracts for reserved service, we also provide service on an unreserved basis. The reserves available through the supply basins connected to our gathering, processing, treating, transportation and storage facilities may decline and may not be replaced by other sources of supply. A decrease in development or production activity could cause a decrease in the volume of unreserved services we provide and a decrease in the number and volume of our contracts for reserved transportation service over the long run, which in each case would adversely affect our revenues and results of operations.

If we are unable to replace any significant volume declines with additional volumes from other sources, our results of operations and cash flows could be materially and adversely affected.

Our revenues depend on our customers’ ability to use our pipelines and third-party pipelines over which we have no control.

Our natural gas transportation, storage and NGL businesses depend, in part, on our customers’ ability to obtain access to pipelines to deliver gas to us and receive gas from us. Many of these pipelines are owned by parties not affiliated with us. Any interruption of service on our pipelines or third-party pipelines due to testing, line repair, reduced operating pressures, or other causes or adverse change in terms and conditions of service could have a material adverse effect on our ability, and the ability of our customers, to transport natural gas to and from our pipelines and facilities and a corresponding material adverse effect on our transportation and storage revenues. In addition, the rates charged by interconnected pipelines for transportation to and from our facilities affect the utilization and value of our storage services. Significant changes in the rates charged by those pipelines or the rates charged by other pipelines with which the interconnected pipelines compete could also have a material adverse effect on our storage revenues.

Shippers using our oil pipelines and terminals are also dependent upon our pipelines and connections to third-party pipelines to receive and deliver crude oil and products. Any interruptions or reduction in the capabilities of these pipelines due to testing, line repair, reduced operating pressures, or other causes could result in reduced volumes transported in our pipelines or through our terminals. Similarly, if additional shippers begin transporting volume over interconnecting oil pipelines, the allocations of pipeline capacity to our existing shippers on these interconnecting pipelines could be reduced, which also could reduce volumes transported in its pipelines or

 

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through our terminals. Allocation reductions of this nature are not infrequent and are beyond our control. Any such interruptions or allocation reductions that, individually or in the aggregate, are material or continue for a sustained period of time could have a material adverse effect on our results of operations, financial position, or cash flows.

The inability to continue to access lands owned by third parties could adversely affect our ability to operate and our financial results.

Our ability to operate our pipeline systems on certain lands owned by third parties will depend on our success in maintaining existing rights-of-way and obtaining new rights-of-way on those lands. We are parties to rights-of-way agreements, permits and licenses authorizing land use with numerous parties, including, private land owners, governmental entities, Native American tribes, rail carriers, public utilities and others. For more information, see our regulatory disclosure titled “Indigenous Protections.” Our ability to secure extensions of existing agreements, permits and licenses is essential to our continuing business operations, and securing additional rights-of-way will be critical to our ability to pursue expansion projects. We cannot provide any assurance that we will be able to maintain access to existing rights-of-way upon the expiration of the current grants, that all of the rights-of-way will be obtained in a timely fashion or that we will acquire new rights-of-way as needed.

Further, whether we have the power of eminent domain for our pipelines varies from state to state, depending upon the type of pipeline and the laws of the particular state and the ownership of the land to which we seek access. When we exercise eminent down rights or negotiate private agreements cases, we must compensate landowners for the use of their property and, in eminent domain actions, such compensation may be determined by a court. The inability to exercise the power of eminent domain could negatively affect our business if we were to lose the right to use or occupy the property on which our pipelines are located. For example, following a decision issued in May 2017 by the federal Tenth Circuit Court of Appeals, tribal ownership of even a very small fractional interest in an allotted land, that is, tribal land owned or at one time owned by an individual Indian landowner, bars condemnation of any interest in the allotment. Consequently, the inability to condemn such allotted lands under circumstances where existing pipeline rights-of-way may soon lapse or terminate serves as an additional impediment for pipeline operators. Any loss of rights with respect to our real property, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to unitholders.

Our storage operations are influenced by the overall forward market for crude oil and other products we store, and certain market conditions may adversely affect our financial and operating results.

Our storage operations are influenced by the overall forward market for crude oil and other products we store. A contango market (meaning that the price of crude oil or other products for future delivery is higher than the current price) is associated with greater demand for storage capacity, because a party can simultaneously purchase crude oil or other products at current prices for storage and sell at higher prices for future delivery. A backwardated market (meaning that the price of crude oil or other products for future delivery is lower than the current price) is associated with lower demand for storage capacity because a party can capture a premium for prompt delivery of crude oil or other products rather than storing it for future sale. A prolonged backwardated market, or other adverse market conditions, could have an adverse impact on its ability to negotiate favorable prices under new or renewing storage contracts, which could have an adverse impact on our storage revenues. As a result, the overall forward market for crude oil or other products may have an adverse effect on our financial condition or results of operations.

Competition for water resources or limitations on water usage for hydraulic fracturing could disrupt crude oil and natural gas production from shale formations.

Hydraulic fracturing is the process of creating or expanding cracks by pumping water, sand and chemicals under high pressure into an underground formation in order to increase the productivity of crude oil and natural gas

 

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wells. Water used in the process is generally fresh water, recycled produced water or salt water. There is competition for fresh water from municipalities, farmers, ranchers and industrial users. In addition, the available supply of fresh water can also be reduced directly by drought. Prolonged drought conditions increase the intensity of competition for fresh water. Limitations on oil and gas producers’ access to fresh water may restrict their ability to use hydraulic fracturing and could reduce new production. Such disruptions could potentially have a material adverse impact on our financial condition or results of operations.

A natural disaster, catastrophe or other event could result in severe personal injury, property damage and environmental damage, which could curtail our operations and otherwise materially adversely affect our cash flow.

Some of our operations involve risks of personal injury, property damage and environmental damage, which could curtail our operations and otherwise materially adversely affect our cash flow. For example, natural gas pipeline and other facilities operate at high pressures. Virtually all of our operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms, floods and/or earthquakes.

If one or more facilities that are owned by us, or that deliver natural gas or other products to us, are damaged by severe weather or any other disaster, accident, catastrophe or event, our operations could be significantly interrupted. Similar interruptions could result from damage to production or other facilities that supply our facilities or other stoppages arising from factors beyond our control. These interruptions might involve significant damage to people, property or the environment, and repairs might take from a week or less for a minor incident to six months or more for a major interruption. Any event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying distributions to Unitholders.

As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, we may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.

Terrorist attacks aimed at our facilities could adversely affect our business, results of operations, cash flows and financial condition.

The United States government has issued warnings that energy assets, including our nation’s pipeline infrastructure, may be the future target of terrorist organizations. Some of our facilities are subject to standards and procedures required by the Chemical Facility Anti-Terrorism Standards. We believe we are in compliance with all material requirements; however, such compliance may not prevent a terrorist attack from causing material damage to our facilities or pipelines. Any such terrorist attack on our facilities or pipelines, those of our customers, or in some cases, those of other pipelines could have a material adverse effect on our business, financial condition and results of operations.

Our business could be affected adversely by union disputes and strikes or work stoppages by unionized employees.

As of December 31, 2020, approximately 11% of our workforce is covered by a number of collective bargaining agreements with various terms and dates of expiration. There can be no assurances that we will not experience a work stoppage in the future as a result of labor disagreements. Any work stoppage could, depending on the affected operations and the length of the work stoppage, have a material adverse effect on our business, financial position, results of operations or cash flows.

 

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Cybersecurity breaches and other disruptions could compromise our information and operations, and expose us to liability, which would cause our business and reputation to suffer.

In the ordinary course of our business, we collect and store sensitive data, including intellectual property, our proprietary business information and that of our customers, suppliers and business partners, and personally identifiable information of our employees, in our data centers and on our networks. The secure processing, maintenance and transmission of this information is critical to our operations and business strategy. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties for divulging shipper information, disruption of our operations, damage to our reputation, and loss of confidence in our products and services, which could adversely affect our business.

Our information technology infrastructure is critical to the efficient operation of our business and essential to our ability to perform day-today operations. Breaches in our information technology infrastructure or physical facilities, or other disruptions, could result in damage to our assets, safety incidents, damage to the environment, potential liability or the loss of contracts, and have a material adverse effect on our operations, financial position and results of operations.

Our operations could be disrupted if our information systems fail, causing increased expenses and loss of sales.

Our business is highly dependent on financial, accounting and other data processing systems and other communications and information systems, including our enterprise resource planning tools. We process a large number of transactions on a daily basis and rely upon the proper functioning of computer systems. If a key system was to fail or experience unscheduled downtime for any reason, even if only for a short period, our operations and financial results could be affected adversely. Our systems could be damaged or interrupted by a security breach, fire, flood, power loss, telecommunications failure or similar event. We have a formal disaster recovery plan in place, but this plan may not entirely prevent delays or other complications that could arise from an information systems failure. Our business interruption insurance may not compensate us adequately for losses that may occur.

Product liability claims and litigation could adversely affect our business and results of operations.

Product liability is a significant commercial risk. Substantial damage awards have been made in certain jurisdictions against manufacturers and resellers based upon claims for injuries caused by the use of or exposure to various products. There can be no assurance that product liability claims against us would not have a material adverse effect on our business or results of operations.

Along with other refiners, manufacturers and sellers of gasoline, ETC Sunoco Holdings LLC (“ETC Sunoco”) is a defendant in numerous lawsuits that allege methyl tertiary butyl ether (“MTBE”) contamination in groundwater. Plaintiffs, who include water purveyors and municipalities responsible for supplying drinking water and private well owners, are seeking compensatory damages (and in some cases injunctive relief, punitive damages and attorneys’ fees) for claims relating to the alleged manufacture and distribution of a defective product (MTBE-containing gasoline) that contaminates groundwater, and general allegations of product liability, nuisance, trespass, negligence, violation of environmental laws and deceptive business practices. There has been insufficient information developed about the plaintiffs’ legal theories or the facts that would be relevant to an analysis of the ultimate liability to ETC Sunoco. An adverse determination of liability related to these allegations or other product liability claims against ETC Sunoco could have a material adverse effect on our business or results of operations.

 

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We do not control, and therefore may not be able to cause or prevent certain actions by, certain of our joint ventures.

Certain of our operations are conducted through joint ventures, some of which have their own governing boards. With respect to our joint ventures, we share ownership and management responsibilities with partners that may not share our goals and objectives. Consequently, it may be difficult or impossible for us to cause the joint venture entity to take actions that we believe would be in their or the joint venture’s best interests. Likewise, we may be unable to prevent actions of the joint venture. Differences in views among joint venture partners may result in delayed decisions or failures to agree on major matters, such as large expenditures or contractual commitments, the construction or acquisition of assets or borrowing money, among others. Delay or failure to agree may prevent action with respect to such matters, even though such action may serve our best interest or that of the joint venture. Accordingly, delayed decisions and disagreements could adversely affect the business and operations of the joint ventures and, in turn, our business and operations.

The use of derivative financial instruments could result in material financial losses by us.

From time to time, we and/or our subsidiaries have sought to reduce our exposure to fluctuations in commodity prices and interest rates by using derivative financial instruments and other risk management mechanisms and by our trading, marketing and/or system optimization activities. To the extent that we hedge our commodity price and interest rate exposures, we forgo the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor.

The accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions that are effective economically (whether to mitigate our exposure to fluctuations in commodity prices, or to balance our exposure to fixed and variable interest rates), these transactions may not be considered effective for accounting purposes. Accordingly, our consolidated financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at that point. It is also not always possible for us to engage in a hedging transaction that completely mitigates our exposure to commodity prices. Our consolidated financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge.

In addition, our derivatives activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the derivative arrangement, the hedge is imperfect, commodity prices move unfavorably related to our physical or financial positions or hedging policies and procedures are not followed.

Increasing levels of congestion in the Houston Ship Channel could result in a diversion of business to less busy ports.

Our Gulf Coast facilities are strategically situated on prime real estate located in the Houston Ship Channel, which is in close proximity to both supply sources and demand sources. In recent years, the success of the Port of Houston has led to an increase in vessel traffic driven in part by the growing overseas demand for U.S. crude, gasoline, liquefied natural gas and petrochemicals and in part by the Port of Houston’s recent decision to accept large container vessels, which can restrict the flow of other cargo. Increasing congestion in the Port of Houston could cause our customers or potential customers to divert their business to smaller ports in the Gulf of Mexico, which could result in lower utilization of our facilities.

The costs of providing pension and other postretirement health care benefits and related funding requirements are subject to changes in pension fund values, changing demographics and fluctuating actuarial assumptions and may have a material adverse effect on our financial results.

Certain of our subsidiaries provide pension plan and other postretirement healthcare benefits to certain of their employees. The costs of providing pension and other postretirement health care benefits and related funding

 

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requirements are subject to changes in pension and other postretirement fund values, changing demographics and fluctuating actuarial assumptions that may have a material adverse effect on the Partnership’s future consolidated financial results. While certain of the costs incurred in providing such pension and other postretirement healthcare benefits are recovered through the rates charged by the Partnership’s regulated businesses, the Partnership’s subsidiaries may not recover all of the costs and those rates are generally not immediately responsive to current market conditions or funding requirements. Additionally, if the current cost recovery mechanisms are changed or eliminated, the impact of these benefits on operating results could significantly increase.

Mergers among customers and competitors could result in lower volumes being shipped on our pipelines or products stored in or distributed through our terminals, or reduced crude oil marketing margins or volumes.

Mergers between existing customers could provide strong economic incentives for the combined entities to utilize their existing systems instead of our systems in those markets where the systems compete. As a result, we could lose some or all of the volumes and associated revenues from these customers and could experience difficulty in replacing those lost volumes and revenues, which could materially and adversely affect our results of operations, financial position, or cash flows.

Fraudulent activity or misuse of proprietary data involving our outsourcing partners could expose us to additional liability.

We utilize both affiliated entities and third parties in the processing of our information and data. Breaches of security measures or the accidental loss, inadvertent disclosure or unapproved dissemination of proprietary information, or sensitive or confidential data about us or our customers, including the potential loss or disclosure of such information or data as a result of fraud or other forms of deception, could expose us to a risk of loss, or misuse of this information, result in litigation and potential liability, lead to reputational damage, increase our compliance costs, or otherwise harm our business.

We compete with other businesses in our market with respect to attracting and retaining qualified employees.

Our continued success depends on our ability to attract and retain qualified personnel in all areas of our business. We compete with other businesses in our market with respect to attracting and retaining qualified employees. A tight labor market, increased overtime and a higher full-time employee ratio may cause labor costs to increase. A shortage of qualified employees may require us to enhance wage and benefits packages in order to compete effectively in the hiring and retention of such employees or to hire more expensive temporary employees. No assurance can be given that our labor costs will not increase, or that such increases can be recovered through increased prices charged to customers. We are especially vulnerable to labor shortages in oil and gas drilling areas when energy prices drive higher exploration and production activity.

Changes in currency exchange rates could adversely affect our results of operations for our Canadian operations.

A portion of our revenue is generated from operations in Canada, which use the Canadian dollar as the functional currency. Therefore, changes in the exchange rate between the U.S. dollar and the Canadian dollar could adversely affect our results of operations.

We are subject to the risks of doing business outside of the U.S.

The success of our business depends, in part, on continued performance in our non-U.S. operations. We currently have operations in Canada. In addition to the other risks described in this report on Form 10-K, there are numerous risks and uncertainties that specifically affect our non-U.S. operations. These risks and uncertainties include political and economic instability, changes in local governmental laws, regulations and policies,

 

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including those related to tariffs, investments, taxation, exchange controls, employment regulations and repatriation of earnings, and enforcement of contract and intellectual property rights. International transactions may also involve increased financial and legal risks due to differing legal systems and customs, including risks of non-compliance with U.S. and local laws affecting our activities abroad, including compliance with the U.S. Foreign Corrupt Practices Act. While these factors and the impact of these factors are difficult to predict, any one or more of them could adversely affect our financial and operational results.

Our trucking fleet operations are subject to the Federal Motor Carrier Safety Regulations which are enacted, reviewed and amended by the FMCSA. Our fleet currently has a “satisfactory” safety rating; however, if our safety rating were downgraded to “unsatisfactory,” our business and results of operations could be adversely affected.

All federally regulated carriers’ safety ratings are measured through a program implemented by the FMCSA known as the Compliance Safety Accountability (“CSA”) program. The CSA program measures a carrier’s safety performance based on violations observed during roadside inspections as opposed to compliance audits performed by the FMCSA. The quantity and severity of any violations are compared to a peer group of companies of comparable size and annual mileage. If a company rises above a threshold established by the FMCSA, it is subject to action from the FMCSA. There is a progressive intervention strategy that begins with a company providing the FMCSA with an acceptable plan of corrective action that the company will implement. If the issues are not corrected, the intervention escalates to on-site compliance audits and ultimately an “unsatisfactory” rating and the revocation of its operating authority by the FMCSA could have an adverse effect on our business, results of operations and financial condition.

Indebtedness

Our debt level and debt agreements may limit our ability to make distributions to Unitholders and may limit our future financial and operating flexibility.

As of December 31, 2020, we had approximately $51.44 billion of consolidated debt, excluding the debt of our unconsolidated joint ventures. Our level of indebtedness affects our operations in several ways, including, among other things:

 

   

a significant portion of our and our subsidiaries’ cash flow from operations will be dedicated to the payment of principal and interest on outstanding debt and will not be available for other purposes, including payment of distributions;

 

   

covenants contained in our and our subsidiaries’ existing debt agreements require us and them, as applicable, to meet financial tests that may adversely affect our flexibility in planning for and reacting to changes in our business;

 

   

our and our subsidiaries’ ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership, corporate or limited liability company purposes, as applicable, may be limited;

 

   

we may be at a competitive disadvantage relative to similar companies that have less debt;

 

   

we may be more vulnerable to adverse economic and industry conditions as a result of our significant debt level; and

 

   

failure by us or our subsidiaries to comply with the various restrictive covenants of our respective debt agreements could negatively impact our ability to incur additional debt, including our ability to utilize the available capacity under our revolving credit facility, and our ability to pay our distributions.

 

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The consolidated debt level and debt agreements of ETO and its subsidiaries, including Sunoco LP and USAC, may limit the distributions we receive from ETO, as well as our future financial and operating flexibility.

ETO’s and its subsidiaries’ levels of indebtedness affect their operations in several ways, including, among other things:

 

   

a significant portion of ETO’s and its subsidiaries’ cash flows from operations will be dedicated to the payment of principal and interest on outstanding debt and will not be available for other purposes, including payment of distributions to us;

 

   

covenants contained in ETO’s and its subsidiaries’ existing debt agreements require ETO and its subsidiaries, as applicable, to meet financial tests that may adversely affect their flexibility in planning for and reacting to changes in their respective businesses;

 

   

ETO’s and its subsidiaries’ ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership, corporate or limited liability company purposes, as applicable, may be limited;

 

   

ETO and its subsidiaries may be at a competitive disadvantage relative to similar companies that have less debt;

 

   

ETO and its subsidiaries may be more vulnerable to adverse economic and industry conditions as a result of their significant debt levels;

 

   

failure by ETO or its subsidiaries to comply with the various restrictive covenants of the respective debt agreements could negatively impact ETO’s and/or its subsidiaries’ ability to incur additional debt, including their ability to utilize the available capacity under their revolving credit facilities, and to pay distributions to us and their unitholders.

We do not have the same flexibility as other types of organizations to accumulate cash, which may limit cash available to service our debt or to repay debt at maturity.

Unlike a corporation, our partnership agreement requires us to distribute, on a quarterly basis, 100% of our Available Cash (as defined in our partnership agreement) to our Unitholders of record and our general partner. Available Cash is generally all of our cash on hand as of the end of a quarter, adjusted for cash distributions and net changes to reserves. Our general partner will determine the amount and timing of such distributions and has broad discretion to establish and make additions to our reserves or the reserves of our operating subsidiaries in amounts it determines in its reasonable discretion to be necessary or appropriate:

 

   

to provide for the proper conduct of our business and the businesses of our operating subsidiaries (including reserves for future capital expenditures and for our anticipated future credit needs);

 

   

to provide funds for distributions to our Unitholders and our general partner for any one or more of the next four calendar quarters; or

 

   

to comply with applicable law or any of our loan or other agreements.

Increases in interest rates could materially adversely affect our business, results of operations, cash flows and financial condition.

In addition to our exposure to commodity prices, we have significant exposure to changes in interest rates. Approximately $6.72 billion of our consolidated debt as of December 31, 2020 bears interest at variable interest rates and the remainder bears interest at fixed rates. To the extent that we have debt with floating interest rates, our results of operations, cash flows and financial condition could be materially adversely affected by increases in interest rates. We manage a portion of our interest rate exposures by utilizing interest rate swaps.

 

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An increase in interest rates could impact demand for our storage capacity.

There is a financing cost for a storage capacity user to own crude oil while it is stored. That financing cost is impacted by the cost of capital or interest rate incurred by the storage user, in addition to the commodity cost of the crude oil in inventory. Absent other factors, a higher financing cost adversely impacts the economics of storing crude oil for future sale. As a result, a significant increase in interest rates could adversely affect the demand for our storage capacity independent of other market factors.

An increase in interest rates may also cause a corresponding decline in demand for equity investments, in general, and in particular for yield-based equity investments such as our Common Units. Any such reduction in demand for our Common Units resulting from other more attractive investment opportunities may cause the trading price of our Common Units to decline.

An increase in the LIBOR or a phase-out or replacement of LIBOR with a benchmark rate that is higher or more volatile than the LIBOR rate could increase our cost of borrowing and could adversely affect our financial position.

As of December 31, 2020, we had outstanding approximately $6.40 billion of debt that bears interest at variable interest rates that use the LIBOR as a benchmark rate. Due to the perceived structural risks inherent in unsecured benchmark rates such as LIBOR, in July 2014, the Financial Stability Board (FSB) recommended developing alternative, near risk-free reference rates. In response to the recommendation put forth by the FSB, the Board of Governors of the Federal Reserve System and the Federal Reserve Bank of New York convened the Alternative Reference Rates Committee (“ARRC”) to identify alternatives to LIBOR. In June 2017, the ARRC selected the secured overnight financing rate (SOFR) as the preferred alternative reference rate to LIBOR. In July 2017, the U.K.’s Financial Conduct Authority (FCA), which oversees the LIBOR submission process for all currencies and regulates the authorized administrator of LIBOR, ICE Benchmark Administration (IBA), announced that it intends to stop persuading or compelling London banks to make these rate submissions after 2021. The cessation date for compulsory submission and publication of rates for certain tenors of LIBOR has since been extended by the IBA and FCA until June 2023. Additionally, the ARRC has published a series of principles for LIBOR fallback contract language which include a methodology for determining fallback rates, which are primarily comprised of SOFR as the replacement benchmark and a replacement benchmark spread.

It is unclear, if certain LIBOR tenors continue to be reported beyond 2021, whether they will be considered representative or whether SOFR as the identified successor benchmark rate will attain market acceptance as a replacement for LIBOR. It is not possible to predict the further effect of the rules, recommendations or administrative practices of the FCA, IBA or ARRC, any changes in the methods by which LIBOR is determined or any other reforms to LIBOR that may be enacted in the United Kingdom, the European Union or elsewhere. Any such developments may cause LIBOR to perform differently than in the past or cease to exist. In addition, any other legal or regulatory changes made by the FCA, the European Commission or any other successor governance or oversight body, or future changes adopted by such body, in the method by which LIBOR is determined or the change from LIBOR to an alternative benchmark rate may result in, among other things, a sudden or prolonged increase or decrease in LIBOR, a delay in the publication of LIBOR, and changes in the rules or methodologies in LIBOR, which may discourage market participants from continuing to administer or to participate in LIBOR’s determination, and, in certain situations, could result in LIBOR no longer being determined and published.

The adoption of SOFR, or any other alternative benchmark rate, may result in interest obligations which are more than or do not otherwise correlate over time with the payments that would have been made on such debt if U.S. dollar LIBOR was available in its current form. Further, the same costs and risks that may lead to the discontinuation or unavailability of U.S. dollar LIBOR may make one or more of the alternative methods impossible or impracticable to determine. Use of SOFR as an alternative benchmark rate and replacement for LIBOR could affect our debt securities, derivative instruments, receivables, debt payments and receipts. At this time, it is not possible to predict the effect of the establishment of any alternative benchmark rate(s). Any new

 

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benchmark rate will likely not replicate LIBOR exactly, and any changes to benchmark rates may have an uncertain impact on our cost of funds and our access to the capital markets. Any of these proposals or consequences could have a material adverse effect on our financing costs.

A downgrade of our credit ratings could impact our and our subsidiaries’ liquidity, access to capital and costs of doing business, and maintaining credit ratings is under the control of independent third parties.

A downgrade of our credit ratings may increase our and our subsidiaries’ cost of borrowing and could require us to post collateral with third parties, negatively impacting our available liquidity. Our and our subsidiaries’ ability to access capital markets could also be limited by a downgrade of our credit ratings and other disruptions. Such disruptions could include:

 

   

economic downturns;

 

   

deteriorating capital market conditions;

 

   

declining market prices for crude oil, natural gas, NGLs and other commodities;

 

   

terrorist attacks or threatened attacks on our facilities or those of other energy companies; and

 

   

the overall health of the energy industry, including the bankruptcy or insolvency of other companies.

Credit rating agencies perform independent analysis when assigning credit ratings. The analysis includes a number of criteria including, but not limited to, business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are not recommendations to buy, sell or hold investments in the rated entity. Ratings are subject to revision or withdrawal at any time by the rating agencies, and we cannot assure you that we will maintain our current credit ratings.

Capital Projects and Future Growth

If we and our subsidiaries do not make acquisitions on economically acceptable terms, our future growth could be limited.

Our results of operations and our ability to grow and to make distributions to Unitholders will depend in part on our ability to make acquisitions that are accretive to our distributable cash flow per unit.

We may be unable to make accretive acquisitions for any of the following reasons, among others:

 

   

because we are unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;

 

   

because we are unable to raise financing for such acquisitions on economically acceptable terms; or

 

   

because we are outbid by competitors, some of which are substantially larger than us and have greater financial resources and lower costs of capital then we do.

Furthermore, even if we consummate acquisitions that we believe will be accretive, those acquisitions may in fact adversely affect our results of operations or result in a decrease in distributable cash flow per unit. Any acquisition involves potential risks, including the risk that we may:

 

   

fail to realize anticipated benefits, such as new customer relationships, cost-savings or cash flow enhancements;

 

   

decrease our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;

 

   

significantly increase our interest expense or financial leverage if we incur additional debt to finance acquisitions;

 

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encounter difficulties operating in new geographic areas or new lines of business;

 

   

incur or assume unanticipated liabilities, losses or costs associated with the business or assets acquired for which we are not indemnified or for which the indemnity is inadequate;

 

   

be unable to hire, train or retrain qualified personnel to manage and operate our growing business and assets;

 

   

less effectively manage our historical assets, due to the diversion of management’s attention from other business concerns; or

 

   

incur other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.

If we consummate future acquisitions, our capitalization and results of operations may change significantly. As we determine the application of our funds and other resources, Unitholders will not have an opportunity to evaluate the economic, financial and other relevant information that we will consider.

Capital projects will require significant amounts of debt and equity financing, which may not be available to us on acceptable terms, or at all.

We plan to fund our growth capital expenditures, including any new pipeline construction projects and improvements or repairs to existing facilities that we may undertake, with proceeds from sales of our debt and equity securities and borrowings under our revolving credit facility; however, we cannot be certain that we will be able to issue our debt and equity securities on terms satisfactory to us, or at all. If we are unable to finance our expansion projects as expected, we could be required to seek alternative financing, the terms of which may not be attractive to us, or to revise or cancel our expansion plans.

A significant increase in our indebtedness that is proportionately greater than our issuance of equity could negatively impact our and our subsidiaries’ credit ratings or our ability to remain in compliance with the financial covenants under our revolving credit agreement, which could have a material adverse effect on our financial condition, results of operations and cash flows.

If we do not continue to construct new pipelines, our future growth could be limited.

Our results of operations and ability to grow and to increase distributable cash flow per unit will depend, in part, on our ability to construct pipelines that are accretive to our distributable cash flow. We may be unable to construct pipelines that are accretive to distributable cash flow for any of the following reasons, among others:

 

   

we are unable to identify pipeline construction opportunities with favorable projected financial returns;

 

   

we are unable to obtain necessary governmental approvals and contracts with qualified contractors and vendors on acceptable terms;

 

   

we are unable to raise financing for our identified pipeline construction opportunities; or

 

   

we are unable to secure sufficient transportation commitments from potential customers due to competition from other pipeline construction projects or for other reasons.

Furthermore, even if we construct a pipeline that we believe will be accretive, the pipeline may in fact adversely affect our results of operations or results from those projected prior to commencement of construction and other factors.

Expanding our business by constructing new pipelines and related facilities subjects us to risks.

One of the ways that we have grown our business is through the construction of additions to our existing gathering, compression, treating, processing and transportation systems. The construction of new pipelines and

 

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related facilities (or the improvement and repair of existing facilities) involves numerous regulatory, environmental, political and legal uncertainties beyond our control and requires the expenditure of significant amounts of capital that we will be required to finance through borrowings, the issuance of additional equity or from operating cash flow. If we undertake these projects, they may not be completed on schedule, at all, or at the budgeted cost. A variety of factors outside our control, such as weather, natural disasters and difficulties in obtaining permits and rights-of-way or other regulatory approvals, as well as the performance by third-party contractors, may result in increased costs or delays in construction. For example, in recent years, pipeline projects by many companies have been subject to several challenges by environmental groups, such as challenges to agency reviews under the NEPA and to the USACE NWP program. For more information on the NWP program, see our regulatory disclosure titled “Clean Water Act”. Separately, cost overruns or delays in completing a project could have a material adverse effect on our results of operations and cash flows. Moreover, our revenues may not increase immediately following the completion of a particular project. For instance, if we build a new pipeline, the construction will occur over an extended period of time, but we may not materially increase our revenues until long after the project’s completion. In addition, the success of a pipeline construction project will likely depend upon the level of oil and natural gas exploration and development drilling activity and the demand for pipeline transportation in the areas proposed to be serviced by the project as well as our ability to obtain commitments from producers in the area to utilize the newly constructed pipelines. In this regard, we may construct facilities to capture anticipated future growth in oil or natural gas production in a region in which such growth does not materialize. As a result, new facilities may be unable to attract enough throughput or contracted capacity reservation commitments to achieve our expected investment return, which could adversely affect our results of operations and financial condition.

The liquefaction project is dependent upon securing long-term contractual arrangements for the off-take of LNG on terms sufficient to support the financial viability of the project.

LCL, our wholly-owned subsidiary, is in the process of developing a liquefaction project at the site of our existing regasification facility in Lake Charles, Louisiana. The project would utilize existing dock and storage facilities owned by us located on the Lake Charles site. The parties’ determination as to the feasibility of the project will be particularly dependent upon the prospects for securing long-term contractual arrangements for the off-take of LNG which in turn will be dependent upon supply and demand factors affecting the price of LNG in foreign markets. The financial viability of the project will also be dependent upon a number of other factors, including the expected cost to construct the liquefaction facility, the terms and conditions of the financing for the construction of the liquefaction facility, the cost of the natural gas supply, the costs to transport natural gas to the liquefaction facility, the costs to operate the liquefaction facility and the costs to transport LNG from the liquefaction facility to customers in foreign markets (particularly Europe and Asia). Some of these costs fluctuate based on a variety of factors, including supply and demand factors affecting the price of natural gas in the United States, supply and demand factors affecting the costs for construction services for large infrastructure projects in the United States, and general economic conditions, there can be no assurance that the parties will determine to proceed to develop this project.

The construction of the liquefaction project remains subject to further approvals and some approvals may be subject to further conditions, review and/or revocation.

While LCL has received authorization from the DOE to export LNG to non-Free Trade Agreements (“non-FTA”) countries, the non-FTA authorization is subject to review, and the DOE may impose additional approval and permit requirements in the future or revoke the non-FTA authorization should the DOE conclude that such export authorization is inconsistent with the public interest. The FERC order (issued December 17, 2015) authorizing LCL to site, construct and operate the liquefaction project contains a condition requiring all phases of the liquefaction project to be completed and in-service within five years of the date of the order. The order also requires the modifications to our Trunkline pipeline facilities that connect to our Lake Charles facility and additionally requires execution of a transportation contract for natural gas supply to the liquefaction facility prior to the initiation of construction of the liquefaction facility. On December 5, 2019, the FERC granted an extension

 

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of time until and including December 16, 2025, to complete construction of the liquefaction project and pipeline facilities modifications and place the facilities into service.

Integration of assets acquired in past acquisitions or future acquisitions with our existing business will be a complex and time-consuming process. A failure to successfully integrate the acquired assets with our existing business in a timely manner may have a material adverse effect on our business, financial condition, results of operations or cash available for distribution to unitholders.

The difficulties of integrating past and future acquisitions with our business include, among other things:

 

   

operating a larger combined organization in new geographic areas and new lines of business;

 

   

hiring, training or retaining qualified personnel to manage and operate our growing business and assets;

 

   

integrating management teams and employees into existing operations and establishing effective communication and information exchange with such management teams and employees;

 

   

diversion of management’s attention from our existing business;

 

   

assimilation of acquired assets and operations, including additional regulatory programs;

 

   

loss of customers or key employees;

 

   

maintaining an effective system of internal controls in compliance with the Sarbanes-Oxley Act of 2002 as well as other regulatory compliance and corporate governance matters; and

 

   

integrating new technology systems for financial reporting.

If any of these risks or other unanticipated liabilities or costs were to materialize, then desired benefits from past acquisitions and future acquisitions resulting in a negative impact to our future results of operations. In addition, acquired assets may perform at levels below the forecasts used to evaluate their acquisition, due to factors beyond our control. If the acquired assets perform at levels below the forecasts, then our future results of operations could be negatively impacted.

Also, our reviews of proposed business or asset acquisitions are inherently imperfect because it is generally not feasible to perform an in-depth review of each such proposal given time constraints imposed by sellers. Even if performed, a detailed review of assets and businesses may not reveal existing or potential problems and may not provide sufficient familiarity with such business or assets to fully assess their deficiencies and potential. Inspections may not be performed on every asset, and environmental problems, may not be observable even when an inspection is undertaken.

We are affected by competition from other midstream, transportation, terminalling and storage companies.

We experience competition in all of our business segments. With respect to our midstream operations, we compete for both natural gas supplies and customers for our services. Our competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport, store and market natural gas.

Our natural gas and NGL transportation pipelines and storage facilities compete with other interstate and intrastate pipeline companies and storage providers in the transportation and storage of natural gas and NGLs. The principal elements of competition among pipelines are rates, terms of service, access to sources of supply and the flexibility and reliability of service. Natural gas and NGLs also compete with other forms of energy, including electricity, coal, fuel oils and renewable or alternative energy. Competition among fuels and energy supplies is primarily based on price; however, non-price factors, including governmental regulation, environmental impacts, efficiency, ease of use and handling, and the availability of subsidies and tax benefits also affects competitive outcomes.

 

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In markets served by our NGL pipelines, we compete with other pipeline companies and barge, rail and truck fleet operations. We also face competition with other storage and fractionation facilities based on fees charged and the ability to receive, distribute and/or fractionate the customer’s products.

Our crude oil and refined petroleum products pipelines face significant competition from other pipelines for large volume shipments. These operations also face competition from trucks for incremental and marginal volumes in the areas we serve. Further, our crude and refined product terminals compete with terminals owned by integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading operations.

We, Sunoco LP and USAC may not be able to fully execute our growth strategy if we encounter increased competition for qualified assets.

Our strategy contemplates growth through the development and acquisition of a wide range of midstream, transportation, storage and other energy infrastructure assets while maintaining a strong balance sheet. This strategy includes constructing and acquiring additional assets and businesses to enhance our ability to compete effectively and diversify our asset portfolio, thereby providing more stable cash flow. We regularly consider and enter into discussions regarding the acquisition of additional assets and businesses, stand-alone development projects or other transactions that we believe will present opportunities to realize synergies and increase our cash flow.

Consistent with our strategy, we may, from time to time, engage in discussions with potential sellers regarding the possible acquisition of additional assets or businesses. Such acquisition efforts may involve our participation in processes that involve a number of potential buyers, commonly referred to as “auction” processes, as well as situations in which we believe we are the only party or one of a very limited number of potential buyers in negotiations with the potential seller. We cannot give assurance that our acquisition efforts will be successful or that any acquisition will be completed on terms considered favorable to us.

In addition, we are experiencing increased competition for the assets we purchase or contemplate purchasing. Increased competition for a limited pool of assets could result in us losing to other bidders more often or acquiring assets at higher prices, both of which would limit our ability to fully execute our growth strategy. Inability to execute our growth strategy may materially adversely impact our results of operations.

Regulatory Matters

Litigation commenced by WMB against ET and its affiliates, if decided adverse to ET, could require ET to make a substantial payment to WMB.

WMB filed a complaint against ET and its affiliates (“ET Defendants) in the Delaware Court of Chancery, alleging that the ET Defendants breached the merger agreement between WMB, ET, and several of ET’s affiliates. Following a ruling by the Court on June 24, 2016, which allowed for the subsequent termination of the merger agreement by ET on June 29, 2016, WMB filed a notice of appeal to the Supreme Court of Delaware. WMB filed an amended complaint on September 16, 2016 and sought a $410 million termination fee and additional damages of up to $10 billion based on the purported lost value of the merger consideration. These damages claims are based on the alleged breaches of the Merger Agreement, as well as new allegations that the ET Defendants breached an additional representation and warranty in the Merger Agreement. The ET Defendants filed amended counterclaims and affirmative defenses on September 23, 2016 and sought a $1.48 billion termination fee under the Merger Agreement and additional damages caused by WMB’s misconduct. These damages claims are based on the alleged breaches of the Merger Agreement, as well as new allegations that WMB breached the Merger Agreement by failing to disclose material information that was required to be disclosed in the Form S-4. On September 29, 2016, WMB filed a motion to dismiss the ET Defendants’ amended counterclaims and to strike certain of the ET Defendants’ affirmative defenses. On December 1, 2017, the Court issued a Memorandum Opinion granting Williams’ motion to dismiss in part and denying it in part. On

 

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March 23, 2017, the Delaware Supreme Court affirmed the Court’s June 24, 2016 ruling, and as a result, Williams conceded that its $10 billion damages claim is foreclosed, although its $410 million termination fee claim remains pending.

In July 2020, the Court denied ET Defendant’s Motion for Summary Judgment and Williams’ Motion for Partial Summary Judgment. ET Defendants cannot predict the outcome of the Williams Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can ET Defendants predict the amount of time and expense that will be required to resolve these lawsuits. ET Defendants believe that Williams’ claims are without merit and intend to defend vigorously against them.

Increased regulation of hydraulic fracturing or produced water disposal could result in reductions or delays in crude oil and natural gas production in our areas of operation, which could adversely impact our business and results of operations.

The hydraulic fracturing process has come under considerable scrutiny from sections of the public as well as environmental and other groups asserting that chemicals used in the hydraulic fracturing process could adversely affect drinking water supplies and may have other detrimental impacts on public health, safety, welfare and the environment. In addition, the water disposal process has come under scrutiny from sections of the public as well as environmental and other groups asserting that the operation of certain water disposal wells has caused increased seismic activity. Additionally, several candidates for political office in both state and federal government have announced intentions to impose greater restrictions on hydraulic fracturing or produced water disposal. For example, the Biden Administration has issued orders temporarily suspending the issuance of new authorizations, and suspending the issuance of new leases pending completion of a review of current practices, for oil and gas development on federal lands and waters (but not tribal lands that the federal government merely holds in trust). Separately, the Colorado Oil and Gas Conservation Commission adopted new rules to cover a variety of matters related to public health, safety, welfare, wildlife, and environmental resources; most significantly, these rule changes establish more stringent setbacks (2,000-foot, instead of the prior 500-foot) on new oil and gas development and eliminate routine flaring and venting of natural gas at new existing wells across the state, each subject to only limited exceptions. While the final impacts of these developments cannot be predicted, the adoption of new laws or regulations imposing additional permitting, disclosures, restrictions or costs related to hydraulic fracturing or produced water disposal or prohibiting hydraulic fracturing in proximity to areas considered to be environmentally sensitive could make drilling certain wells impossible or less economically attractive. As a result, the volume of crude oil and natural gas we gather, transport and store for our customers could be substantially reduced which could have an adverse effect on our financial condition or results of operations.

Legal or regulatory actions related to the Dakota Access pipeline could cause an interruption to current or future operations, which could have an adverse effect on our business and results of operations.

On July 27, 2016, the Standing Rock Sioux Tribe and other Native American tribes (the “Tribes”) filed a lawsuit in the United States District Court for the District of Columbia (“District Court”) challenging permits issued by the USACE permitting Dakota Access, LLC (“Dakota Access”) to cross the Missouri River at Lake Oahe in North Dakota. The case was subsequently amended to challenge an easement issued by the USACE allowing the pipeline to cross land owned by the USACE adjacent to the Missouri River. As a result of this litigation, the District Court vacated the easement, ordered USACE to prepare an Environmental Impact Statement (“EIS”), and order the pipeline shutdown and drained of oil. Dakota Access and USACE appealed this decision and moved for a stay of the District Court’s orders. On August 5, 2020, the Court of Appeals granted a stay of the portion of the District Court order that required Dakota Access to shut the pipeline down and empty it of oil, but the Court of Appeals denied a stay of the easement vacatur. The August 5 order also stated that the Court of Appeals expected the USACE to clarify its position with respect to whether USACE intends to allow the continued operation of the pipeline notwithstanding the vacatur of the easement and that the District Court may consider additional relief, if necessary. Following this order, the Tribes filed a motion with the District Court

 

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seeking an injunction to prevent the continued operation of the pipeline. This motion has been briefed by the Tribes, USACE, and Dakota Access, but the District Court has not yet ruled on this motion. On January 26, 2021, the Court of Appeals affirmed the District Court’s order requiring an EIS and its order vacating the easement. In the same January 26 order, the Court of Appeals also overturned the District Court’s August 5, 2020 order that the pipeline be shut down and emptied of oil because of the lack of findings sufficient to satisfy the legal requirements for injunctive relief, including a finding of irreparable harm to the Tribes in the absence of an injunction. The District Court scheduled a status conference for February 10, 2021 to discuss the impact of the Court of Appeals’ ruling on the pending motion for injunctive relief, as well as USACE’s expectations as to how it will proceed in light of the Court of Appeals’ recent vacatur ruling. USACE filed a motion for a continuance of the status conference until April 9, 2021, and this motion was approved by the District Court on February 9, 2021. For further information, see Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” in this report.

Our interstate natural gas pipelines are subject to laws, regulations and policies governing the rates they are allowed to charge for their services, which may prevent us from fully recovering our costs.

Laws, regulations and policies governing interstate natural gas pipeline rates could affect the ability of our interstate pipelines to establish rates, to charge rates that would cover future increases in its costs, or to continue to collect rates that cover current costs.

We are required to file tariff rates (also known as recourse rates) with the FERC that shippers may pay for interstate natural gas transportation services. We may also agree to discount these rates on a not unduly discriminatory basis or negotiate rates with shippers who elect not to pay the recourse rates. The FERC must approve or accept all rate filings for us to be allowed to charge such rates.

The FERC may review existing tariff rates on its own initiative or upon receipt of a complaint filed by a third party. The FERC may, on a prospective basis, order refunds of amounts collected if it finds the rates to have been shown not to be just and reasonable or to have been unduly discriminatory. The FERC has recently exercised this authority with respect to several other pipeline companies. If the FERC were to initiate a proceeding against us and find that our rates were not just and reasonable or were unduly discriminatory, the maximum rates we are permitted to charge may be reduced and the reduction could have an adverse effect on our revenues and results of operations.

The costs of our interstate pipeline operations may increase, and we may not be able to recover all of those costs due to FERC regulation of our rates. If we propose to change our tariff rates, our proposed rates may be challenged by the FERC or third parties, and the FERC may deny, modify or limit our proposed changes if we are unable to persuade the FERC that changes would result in just and reasonable rates that are not unduly discriminatory. We also may be limited by the terms of rate case settlement agreements or negotiated rate agreements with individual customers from seeking future rate increases, or we may be constrained by competitive factors from charging our tariff rates.

To the extent our costs increase in an amount greater than our revenues increase, or there is a lag between our cost increases and our ability to file for and obtain rate increases, our operating results would be negatively affected. Even if a rate increase is permitted by the FERC to become effective, the rate increase may not be adequate. We cannot guarantee that our interstate pipelines will be able to recover all of our costs through existing or future rates.

The ability of interstate pipelines held in tax-pass-through entities, like us, to include an allowance for income taxes as a cost-of-service element in their regulated rates has been subject to extensive litigation before the FERC and the courts for a number of years. Effective January 2018, the 2017 Tax Cuts and Jobs Act (the “Tax Act”) changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. On March 15, 2018, in a set of related proposals, the FERC addressed treatment of federal income tax allowances in

 

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regulated entity rates. The FERC issued a Revised Policy Statement on Treatment of Income Taxes (“Revised Policy Statement”) stating that it will no longer permit master limited partnerships to recover an income tax allowance in their cost-of-service rates. The FERC issued the Revised Policy Statement in response to a remand from the United States Court of Appeals for the District of Columbia Circuit in United Airlines v. FERC, in which the court determined that the FERC had not justified its conclusion that a pipeline organized as a master limited partnership would not “double recover” its taxes under the current policy by both including an income-tax allowance in its cost of service and earning a return on equity (“ROE”) calculated using the discounted cash flow methodology. On July 18, 2018, the FERC issued an order denying requests for rehearing and clarification of its Revised Policy Statement because it is a non-binding policy and parties will have the opportunity to address the policy as applied in future cases. In the rehearing order, the FERC clarified that a pipeline organized as a master limited partnership will not be precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double-recovery of investors’ income tax costs. On July 31, 2020, the United States Court of Appeals for the District of Columbia Circuit issued an opinion upholding FERC’s decision denying a separate master limited partnership recovery of an income tax allowance and its decision not to require the master limited partnership to refund accumulated deferred income tax balances. In light of the rehearing order’s clarification regarding individual entities’ ability to argue in support of recovery of an income tax allowance and the court’s subsequent opinion upholding denial of an income tax allowance to a master limited partnership, the impacts that FERC’s policy on the treatment of income taxes may have on the rates an interstate pipeline held in a tax-pass-through entity can charge for the FERC regulated transportation services are unknown at this time.

Even without application of FERC’s recent rate making-related policy statements and rulemakings, under the NGA, FERC or our shippers may challenge the cost-of-service rates we charge. The FERC’s establishment of a just and reasonable rate is based on many components, including ROE and tax-related components, including the allowance for income taxes and the amount for accumulated deferred income taxes, but also other pipeline costs that will continue to affect the FERC’s determination of just and reasonable cost-of-service rates. Moreover, we receive revenues from our pipelines based on a variety of rate structures, including cost-of-service rates, negotiated rates, discounted rates and market-based rates. Many of our interstate pipelines, such as ETC Tiger, Midcontinent Express and Fayetteville Express, have negotiated market rates that were agreed to by customers in connection with long-term contracts entered into to support the construction of the pipelines. Other systems, such as FGT, Transwestern and Panhandle, have a mix of tariff rate, discount rate, and negotiated rate agreements. The revenues we receive from natural gas transportation services we provide pursuant to cost-of-service based rates may decrease in the future as a result of changes to FERC policies, combined with the reduced corporate federal income tax rate established in the Tax Act. The extent of any revenue reduction related to our cost-of-service rates, if any, will depend on a detailed review of all of a pipeline’s cost-of-service components and the outcomes of any challenges to our rates by the FERC or our shippers.

By order issued January 16, 2019, the FERC initiated a review of Panhandle’s existing rates pursuant to Section 5 of the NGA to determine whether the rates currently charged by Panhandle are just and reasonable and set the matter for hearing. Panhandle filed a cost and revenue study on April 1, 2019 and an NGA Section 4 rate case on August 30, 2019. The Section 4 and section 5 proceedings were consolidated by order of the Chief Judge on October 1, 2019. A hearing in the combined proceedings commenced on August 25, 2020 and adjourned on September 15, 2020. By order dated January 19, 2021, the Chief Judge has extended the deadline for the initial decision to March 2021.

Our interstate natural gas pipelines are subject to laws, regulations and policies governing terms and conditions of service, which could adversely affect our business and results of operations.

In addition to rate oversight, the FERC’s regulatory authority extends to many other aspects of the business and operations of our interstate natural gas pipelines, including:

 

   

terms and conditions of service;

 

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the types of services interstate pipelines may or must offer their customers;

 

   

construction of new facilities;

 

   

acquisition, extension or abandonment of services or facilities;

 

   

reporting and information posting requirements;

 

   

accounts and records; and

 

   

relationships with affiliated companies involved in all aspects of the natural gas and energy businesses.

Compliance with these requirements can be costly and burdensome. In addition, we cannot guarantee that the FERC will authorize tariff changes and other activities we might propose and to undertake in a timely manner and free from potentially burdensome conditions. Future changes to laws, regulations, policies and interpretations thereof may impair our access to capital markets or may impair the ability of our interstate pipelines to compete for business, may impair their ability to recover costs or may increase the cost and burden of operation.

In December 2017, the then-serving FERC Chairman announced that the FERC will review its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. To that end, FERC issued a Notice of Inquiry on April 9, 2018, requesting comments on its certification policies, but no action has been taken in that docket. We are unable to predict what, if any, changes may be proposed that will affect our natural gas pipeline business or when such proposals, if any, might become effective. We do not expect that any change in this policy would affect us in a materially different manner than any other similarly sized natural gas pipeline company operating in the United States.

Rate regulation or market conditions may not allow us to recover the full amount of increases in the costs of our crude oil, NGL and refined products pipeline operations.

Transportation provided on our common carrier interstate crude oil, NGL and refined products pipelines is subject to rate regulation by the FERC, which requires that tariff rates for transportation on these oil pipelines be just and reasonable and not unduly discriminatory. If we propose new or changed rates, the FERC or interested persons may challenge those rates and the FERC is authorized to suspend the effectiveness of such rates for up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the proposed rate is unjust or unreasonable, it is authorized to require the carrier to refund revenues in excess of the prior tariff during the term of the investigation. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.

The primary ratemaking methodology used by the FERC to authorize increases in the tariff rates of petroleum pipelines is price indexing. The FERC’s ratemaking methodologies may limit our ability to set rates based on our costs or may delay the use of rates that reflect increased costs. On March 25, 2020, the FERC issued a Notice of Inquiry seeking comment on a proposal to change the preliminary screen for complaints against oil pipeline index rate increases to a “Percentage Comparison Test” consistent with the preliminary screen used by the FERC for protests against oil pipeline index rate increases. The FERC also requested comment on whether the appropriate threshold for the screen is a 10% or more differential between a proposed index rate increase and the annual percentage change in cost of service reported by the pipeline. Initial comments were due June 16, 2020, and reply comments were due July 16, 2020. The FERC has not yet taken any further action on the Notice of Inquiry. At this time, we cannot determine the effect of a change in the FERC’s preliminary screen for complaints against index rates changes, however, a revised screen would result in a threshold aligned with the existing threshold for protests against index rate increases. Any complaint or protest raised by a shipper could materially and adversely affect our financial condition, results of operations or cash flows.

 

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On June 18, 2020, FERC issued a Notice of Inquiry requesting comments on a proposed oil pipeline index for the five-year period commencing July 1, 2021 and ending June 30, 2026, and requested comments on whether and how the index should reflect the Revised Policy Statement and FERC’s treatment of accumulated deferred income taxes as well as FERC’s revised ROE methodology. Comments on the indexing rate methodology Notice of Inquiry were due August 17, 2020, with reply comments due September 11, 2020.

On December 17, 2020, FERC issued an order establishing a new index of PPI-FG plus 0.78%. Rehearing of this order has been requested and remains pending before FERC.

Under the Energy Policy Act of 1992 (the “Energy Policy Act”), certain interstate pipeline rates were deemed just and reasonable or “grandfathered.” Revenues are derived from such grandfathered rates on most of our FERC-regulated pipelines. A person challenging a grandfathered rate must, as a threshold matter, establish a substantial change since the date of enactment of the Energy Policy Act, in either the economic circumstances or the nature of the service that formed the basis for the rate. If the FERC were to find a substantial change in circumstances, then the existing rates could be subject to detailed review and there is a risk that some rates could be found to be in excess of levels justified by the pipeline’s costs. In such event, the FERC could order us to reduce pipeline rates prospectively and to pay refunds to shippers.

If the FERC’s petroleum pipeline ratemaking methodologies procedures changes, the new methodology or procedures could adversely affect our business and results of operations.

State regulatory measures could adversely affect the business and operations of our midstream and intrastate pipeline and storage assets.

Our midstream and intrastate transportation and storage operations are generally exempt from FERC regulation under the NGA, but FERC regulation still significantly affects our business and the market for our products. The rates, terms and conditions of service for the interstate services we provide in our intrastate gas pipelines and gas storage are subject to FERC regulation under Section 311 of the NGPA. Our HPL System, East Texas pipeline, Oasis pipeline and ET Fuel System provide such services. Under Section 311, rates charged for transportation and storage must be fair and equitable. Amounts collected in excess of fair and equitable rates are subject to refund with interest, and the terms and conditions of service, set forth in the pipeline’s statement of operating conditions, are subject to FERC review and approval. Should the FERC determine not to authorize rates equal to or greater than our costs of service, our cash flow would be negatively affected.

Our midstream and intrastate gas and oil transportation pipelines and our intrastate gas storage operations are subject to state regulation. All of the states in which we operate midstream assets, intrastate pipelines or intrastate storage facilities have adopted some form of complaint-based regulation, which allow producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to the fairness of rates and terms of access. The states in which we operate have ratable take statutes, which generally require gatherers to take, without undue discrimination, production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas. Should a complaint be filed in any of these states or should regulation become more active, our business may be adversely affected.

Our intrastate transportation operations located in Texas are also subject to regulation as gas utilities by the Texas Railroad Commission (“TRRC”). Texas gas utilities must publish the rates they charge for transportation and storage services in tariffs filed with the TRRC, although such rates are deemed just and reasonable under Texas law unless challenged in a complaint.

We are subject to other forms of state regulation, including requirements to obtain operating permits, reporting requirements, and safety rules (see description of federal and state pipeline safety regulation below). Violations

 

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of state laws, regulations, orders and permit conditions can result in the modification, cancellation or suspension of a permit, civil penalties and other relief.

Certain of our assets may become subject to regulation.

The distinction between federally unregulated gathering facilities and FERC-regulated transmission pipelines under the NGA has been the subject of extensive litigation and may be determined by the FERC on a case-by-case basis, although the FERC has made no determinations as to the status of our facilities. Consequently, the classification and regulation of our gathering facilities could change based on future determinations by the FERC, the courts or Congress. If our gas gathering operations become subject to FERC jurisdiction, the result may adversely affect the rates we are able to charge and the services we currently provide, and may include the potential for a termination of our gathering agreements with our customers.

Intrastate transportation of NGLs is largely regulated by the state in which such transportation takes place. Lone Star’s NGL Pipeline transports NGLs within the state of Texas and is subject to regulation by the TRRC. This NGLs transportation system offers services pursuant to an intrastate transportation tariff on file with the TRRC. In 2013, Lone Star’s NGL pipeline also commenced the interstate transportation of NGLs, which is subject to the FERC’s jurisdiction under the Interstate Commerce Act (“ICA”) and the Energy Policy Act. Both intrastate and interstate NGL transportation services must be provided in a manner that is just, reasonable, and non-discriminatory. The tariff rates established for interstate services were based on a negotiated agreement; however, if the FERC’s ratemaking methodologies were imposed, they may, among other things, delay the use of rates that reflect increased costs and subject us to potentially burdensome and expensive operational, reporting and other requirements. In addition, the rates, terms and conditions for shipments of crude oil, petroleum products and NGLs on our pipelines are subject to regulation by the FERC if the NGLs are transported in interstate or foreign commerce, whether by our pipelines or other means of transportation. Since we do not control the entire transportation path of all crude oil, petroleum products and NGLs on our pipelines, FERC regulation could be triggered by our customers’ transportation decisions.

In addition, if any of our pipelines were found to have provided services or otherwise operated in violation of the NGA, Natural Gas Policy Act of 1978 (“NGPA”), or ICA, this could result in the imposition of administrative and criminal remedies and civil penalties, as well as a requirement to disgorge charges collected for such services in excess of the rate established by the FERC. Any of the foregoing could adversely affect revenues and cash flow related to these assets.

We may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs.

Pursuant to authority under the NGPSA and Hazardous Liquids Pipeline Safety Act of 1979, as amended (“HLPSA”), PHMSA has established a series of rules requiring pipeline operators to develop and implement integrity management programs for natural gas transmission and hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect high consequence areas (“HCAs”) which are areas where a release could have the most significant adverse consequences, including high population areas, certain drinking water sources, and unusually sensitive ecological areas. These regulations require operators of covered pipelines to:

 

   

perform ongoing assessments of pipeline integrity;

 

   

identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

 

   

improve data collection, integration and analysis;

 

   

repair and remediate the pipeline as necessary; and

 

   

implement preventive and mitigating actions.

 

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In addition, states have adopted regulations similar to existing PHMSA regulations for intrastate gathering and transmission lines. At this time, we cannot predict the ultimate cost of compliance with applicable pipeline integrity management regulations, as the cost will vary significantly depending on the number and extent of any repairs found to be necessary as a result of the pipeline integrity testing. We will continue our pipeline integrity testing programs to assess and maintain the integrity of our pipelines. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines. Any changes to pipeline safety laws by Congress and regulations by PHMSA that result in more stringent or costly safety standards could have a significant adverse effect on us and similarly situated midstream operators. For example, in October 2019, PHMSA published the first of three expected regulations relating to new or more stringent requirements for certain natural gas lines and gathering lines, that had originally been proposed in 2016 as part of PHMSA’s “Gas Megarule.” The rulemaking imposed numerous requirements, including, among other things, expanding certain of PHMSA’s current regulatory safety programs for natural gas pipelines in newly defined MCAs that contain as few as five dwellings within a potential impact area. PHMSA is still expected to issue the second and third parts of the Gas Megarule, but we cannot predict the timing of any such action. The safety and hazardous liquid pipelines rule would extend leak detection requirements to all non-gathering hazardous liquid pipelines and require operators to inspect affected pipelines following extreme weather events or natural disasters to address any resulting damage. Finally, the enhanced emergency procedures rule focuses on increased emergency safety measures. In particular, this rule increases the authority of PHMSA to issue an emergency order that addresses unsafe conditions or hazards that pose an imminent threat to pipeline safety. The changes adopted or proposed by these rulemakings or made in future legal requirements could have a material adverse effect on our results of operations and costs of transportation services.

Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.

The NGPSA and HLPSA were amended by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”). Among other things, the 2011 Pipeline Safety Act increased the penalties for safety violations and directed the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, testing to confirm that the material strength of certain pipelines are above 30% of specified minimum yield strength, and operator verification of records confirming the MAOP of certain interstate natural gas transmission pipelines. In January 2021, PHMSA issued a final rule increasing the maximum administrative fines for safety violations were increased to account for inflation, with maximum civil penalties set at $222,504 per day, with a maximum of $2,225,034 for a series of violations. Upon reauthorization of PHMSA, Congress often directs the agency to complete certain rulemakings. For example, in the Consolidated Appropriations Bill for Fiscal Year 2021, Congress reauthorized PHMSA through fiscal year 2023 and directed the agency to move forward with several regulatory actions, including the “Pipeline Safety: Class Location Change Requirements” and the “Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines” proposed rulemakings; Congress has also instructed PHMSA to issue final regulations to require operations of non-rural gas gathering lines and new existing transmission and distribution pipelines to conduct certain leak detection and repair programs to require facility inspection and maintenance plans to align with those regulations. The timing and scope of such future rulemakings is uncertain. The safety enhancement requirements and other provisions of Congressional mandates to PHMSA, as well as any implementation of PHMSA rules thereunder or any issuance or reinterpretation of guidance by PHMSA or any state agencies with respect thereto, could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could be significant and have a material adverse effect on our results of operations or financial condition.

 

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Our business involves the generation, handling and disposal of hazardous substances, hydrocarbons and wastes which activities are subject to environmental and worker health and safety laws and regulations that may cause us to incur significant costs and liabilities.

Our business is subject to stringent federal, tribal, state, and local laws and regulations governing the discharge of materials into the environment, worker health and safety and protection of the environment. These laws and regulations may require the acquisition of permits for the construction and operation of our pipelines, plants and facilities, result in capital expenditures to manage, limit or prevent emissions, discharges or releases of various materials from our pipelines, plants and facilities, impose specific health and safety standards addressing worker protection, and impose substantial liabilities for pollution resulting from our construction and operations activities. Several governmental authorities, such as the United States Environmental Protection Agency (“EPA”) and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them and frequently mandate difficult and costly remediation measures and other actions. Failure to comply with these laws, regulations and permits may result in the assessment of significant administrative, civil and criminal penalties, the imposition of investigatory remedial and corrective action obligations, the occurrence of delays in permitting and completion of projects, and the issuance of injunctive relief. For example, following an inadvertent return that occurred in connection with the construction of our Mariner East 2 pipeline (“Mariner 2”), the Pennsylvania Department of Environmental Protection in September 2020 ordered the rerouting of a section of Mariner 2. We have challenged this order and cannot predict the final outcome; however, any rerouting of Mariner 2 or other of our pipeline projects may result in delays in the completion of these projects.

Certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or wastes have been disposed or released, even under circumstances where the substances, hydrocarbons or wastes have been released by a predecessor operator. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property and natural resource damage allegedly caused by noise, odor or the release of hazardous substances, hydrocarbons or wastes into the environment.

We may incur substantial environmental costs and liabilities because of the underlying risk arising out of our operations. Although we have established financial reserves for our estimated environmental remediation liabilities, additional contamination or conditions may be discovered, resulting in increased remediation costs, liabilities or natural resource damages that could substantially increase our costs for site remediation projects. Accordingly, we cannot assure you that our current reserves are adequate to cover all future liabilities, even for currently known contamination.

Uncertainty about the future course of regulation exists because of the recent change in U.S. presidential administrations. In January 2021, the current administration issued an executive order directing all federal agencies to review and take action to address any federal regulations promulgated during the prior administration that may be inconsistent with the current administration’s policies. As a result, it is unclear the degree to which certain recent regulatory developments may be modified or rescinded. The executive order also established a Working Group that is called on to, among other things, develop methodologies for calculating the “social cost of carbon,” “social cost of nitrous oxide” and “social cost of methane.” Recommendations from the Working Group are due beginning June 1, 2021, and final recommendations no later than January 2022. Further regulation of air emissions, as well as uncertainty regarding the future course of regulation, could eventually reduce the demand for oil and natural gas and, in turn, have a material adverse effect on our business, financial condition or results of operations.

Changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, emission standards, or storage, transport, disposal or remediation requirements could have a material adverse effect on our operations or financial position. For example, in October 2015, the EPA published a final rule under the Clean Air Act, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone to 70 parts per billion for the 8-hour primary and

 

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secondary ozone standards, and the EPA finalized its attainment/non-attainment designations in 2018, though these are subject to change. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Also, states are expected to implement more stringent requirements as a result of this new final rule, which could apply to our customers’ operations. Compliance with this final rule or any other new regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines or new restrictions or prohibitions with respect to permits or projects, and significantly increase our capital expenditures and operating costs, which could adversely impact our business. Historically, we have been able to satisfy the more stringent nitrogen oxide emission reduction requirements that affect our compressor units in ozone non-attainment areas at reasonable cost, but there is no assurance that we will not incur material costs in the future to meet the new, more stringent ozone standard.

Regulations under the Clean Water Act, Oil Pollution Act of 1990, as amended (“OPA”), and state laws impose regulatory burdens on terminal operations. Spill prevention control and countermeasure requirements of federal and state laws require containment to mitigate or prevent contamination of waters in the event of a refined product overflow, rupture, or leak from above-ground pipelines and storage tanks. The Clean Water Act also requires us to maintain spill prevention control and countermeasure plans at our terminal facilities with above-ground storage tanks and pipelines. In addition, OPA requires that most fuel transport and storage companies maintain and update various oil spill prevention and oil spill contingency plans. Facilities that are adjacent to water require the engagement of Federally Certified Oil Spill Response Organizations to be available to respond to a spill on water from above-ground storage tanks or pipelines.

Transportation and storage of refined products over and adjacent to water involves risk and potentially subjects us to strict, joint, and potentially unlimited liability for removal costs and other consequences of an oil spill where the spill is into navigable waters, along shorelines or in the exclusive economic zone of the United States.

In the event of an oil spill into navigable waters, substantial liabilities could be imposed upon us. The Clean Water Act imposes restrictions and strict controls regarding the discharge of pollutants into navigable waters, with the potential of substantial liability for the violation of permits or permitting requirements.

Terminal operations and associated facilities are subject to the Clean Air Act as well as comparable state and local statutes. Under these laws, permits may be required before construction can commence on a new source of potentially significant air emissions, and operating permits may be required for sources that are already constructed. If regulations become more stringent, additional emission control technologies.

Climate change legislation or regulations restricting emissions of greenhouse gases (“GHGs”) could result in increased operating costs and reduced demand for the services we provide.

Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes and GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. In the United States, no comprehensive climate change legislation has been implemented at the federal level to date. However, Canada has implemented a federal carbon pricing regime, and, in the United States, President Biden has announced that he intends to pursue substantial reductions in greenhouse gas emissions, particularly from the oil and gas sector. For example, on January 27, 2021, President Biden signed an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, an increase in the production of offshore wind energy, and an increased emphasis on climate-related risks across government agencies and economic sectors. Additionally, the EPA has adopted rules under authority of the Clean Air Act that, among other things, establish Potential for Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG

 

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emissions from certain large stationary sources that are also potential major sources of certain principal, or criteria, pollutant emissions, which reviews could require securing PSD permits at covered facilities emitting GHGs and meeting “best available control technology” standards for those GHG emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, including, among others, onshore processing, transmission, storage and distribution facilities. In October 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting facilities and blowdowns of natural gas transmission pipelines.

Federal agencies also have begun directly regulating GHG emissions, such as methane, from oil and natural gas operations. In June 2016, the EPA published New Source Performance Standards (“NSPS”), known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound (“VOC”) emissions. These Subpart OOOOa standards expand previously issued NSPS published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices, requiring additional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations. In September 2020, the EPA finalized amendments to Subpart OOOOa that rescind the methane limits for new, reconstructed and modified oil and natural gas production sources while leaving in place the general emission limits for VOCs. In addition, the rulemaking removes from the oil and natural gas category the natural gas transmission and storage segment. However, President Biden has signed an executive order calling for the suspension, revision, or rescission of the September 2020 rule and the reinstatement or issuance of methane emissions standards for new, modified, and existing oil and gas facilities, including the transmission and storage. Methane emission standards imposed on the oil and gas sector could result in increased costs to our operations or those of our customers as well as result in delays or curtailment in such operations, which costs, delays or curtailment could adversely affect our business. Several states have also adopted, or are considering, adopting, regulations related to GHG emissions, some of which are more stringent than those implemented by the federal government.

Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France in signing the “Paris Agreement,” a treaty that requires member countries to submit individually-determined, non-binding GHG emission reduction goals every five years beginning in 2020. Although the United States had withdrawn from this agreement, President Biden has signed executive orders recommitting the United States to the Paris Agreement and calling for the federal government to formulate the United States’ emissions reduction goal. However, the impacts of these orders are unclear at this time.

The adoption, strengthening and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our services, results of operations, and cash flows. Litigation risks are also increasing, as several oil and gas companies have been sued for allegedly causing climate-related damages due to their production and sale of fossil fuel products or for allegedly being aware of the impacts of climate change for some time but failing to adequately disclose such risks to their investors or customers. There is also a risk that financial institutions could be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. For example, recently, the Federal Reserve announced that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Ultimately, this could make it more difficult to secure funding for exploration and production or midstream activities. Finally, most scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events that could have an adverse effect on our assets.

 

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The swaps regulatory provisions of the Dodd-Frank Act and the rules adopted thereunder could have an adverse effect on our ability to use derivative instruments to mitigate the risks of changes in commodity prices and interest rates and other risks associated with our business.

Provisions of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) and rules adopted by the Commodity Futures Trading Commission (the “CFTC”), the SEC and other prudential regulators establish federal regulation of the physical and financial derivatives, including over-the-counter derivatives market and entities, such as us, participating in that market. While most of these regulations are already in effect, the implementation process is still ongoing and the CFTC continues to review and refine its initial rulemakings through additional interpretations and supplemental rulemakings. As a result, any new regulations or modifications to existing regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability and/or liquidity of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. Any of these consequences could have a material adverse effect on our financial condition, results of operations and cash available for distribution to our Unitholders.

The CFTC has re-proposed speculative position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents, although certain bona fide hedging transactions would be exempt from these position limits provided that various conditions are satisfied. The CFTC has also finalized a related aggregation rule that requires market participants to aggregate their positions with certain other persons under common ownership and control, unless an exemption applies, for purposes of determining whether the position limits have been exceeded. If adopted, the revised position limits rule and its finalized companion rule on aggregation may create additional implementation or operational exposure. In addition to the CFTC federal speculative position limit regime, designated contract markets (“DCMs”) also maintain speculative position limit and accountability regimes with respect to contracts listed on their platform as well as aggregation requirements similar to the CFTC’s final aggregation rule. Any speculative position limit regime, whether imposed at the federal-level or at the DCM-level may impose added operating costs to monitor compliance with such position limit levels, addressing accountability level concerns and maintaining appropriate exemptions, if applicable.

The Dodd-Frank Act requires that certain classes of swaps be cleared on a derivatives clearing organization and traded on a DCM or other regulated exchange, unless exempt from such clearing and trading requirements, which could result in the application of certain margin requirements imposed by derivatives clearing organizations and their members. The CFTC and prudential regulators have also adopted mandatory margin requirements for uncleared swaps entered into between swap dealers and certain other counterparties. We currently qualify for and rely upon an end-user exception from such clearing and margin requirements for the swaps we enter into to hedge our commercial risks. However, the application of the mandatory clearing and trade execution requirements and the uncleared swaps margin requirements to other market participants, such as swap dealers, may adversely affect the cost and availability of the swaps that we use for hedging.

In addition to the Dodd-Frank Act, the European Union and other foreign regulators have adopted and are implementing local reforms generally comparable with the reforms under the Dodd-Frank Act. Implementation and enforcement of these regulatory provisions may reduce our ability to hedge our market risks with non-U.S. counterparties and may make transactions involving cross-border swaps more expensive and burdensome. Additionally, the lack of regulatory equivalency across jurisdictions may increase compliance costs and make it more difficult to satisfy our regulatory obligations.

Additional deepwater drilling laws and regulations, delays in the processing and approval of drilling permits and exploration, development, oil spill-response and decommissioning plans, and other related developments may have a material adverse effect on our business, financial condition, or results of operations.

The Federal Bureau of Ocean Energy Management (“BOEM”) and the federal Bureau of Safety and Environmental Enforcement (“BSEE”), each agencies of the United States Department of the Interior, have

 

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imposed more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. Compliance with these more stringent regulatory requirements and with existing environmental and oil spill regulations, together with any uncertainties or inconsistencies in decisions and rulings by governmental agencies, delays in the processing and approval of drilling permits or exploration, development, oil spill-response and decommissioning plans, and possible additional regulatory initiatives could result in difficult and more costly actions and adversely affect or delay new drilling and ongoing development efforts. For instance, in January 2021, the Biden administration issued an executive order focused on climate change that, among other things, directed the Secretary of the Interior to pause new oil and natural gas leasing on public lands or in offshore waters pending completion of a comprehensive review of the federal permitting and leasing practices, consider whether to adjust royalties associated with coal, oil, and gas resources extracted from public lands and offshore waters, or take other appropriate action, to account for corresponding climate costs.

In addition, new regulatory initiatives may be adopted or enforced by the BOEM or the BSEE in the future that could result in additional costs, delays, restrictions, or obligations with respect to oil and natural gas exploration and production operations conducted offshore by certain of our customers. Separately, in October 2020, BOEM and BSEE published a proposed rule regarding financial assurance requirements for offshore leases, particularly regarding requirements for bonds above base amounts prescribed by regulation. At this time, we cannot determine with any certainty the amount of any additional financial assurance that may be ordered by BOEM and required of us in the future, or that such additional financial assurance amounts can be obtained. The final publication or implementation of this rule, as well as any new rules, regulations, or legal initiatives, could delay or disrupt our customers’ operations, increase the risk of expired leases due to the time required to develop new technology, result in increased supplemental bonding and costs, limit activities in certain areas, or cause our customers’ to incur penalties, or shut-in production or lease cancellation. Also, if material spill events were to occur in the future, the United States or other countries could elect to issue directives to temporarily cease drilling activities offshore and, in any event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil and gas exploration and development. The overall costs imposed on our customers to implement and complete any such spill response activities or any decommissioning obligations could exceed estimated accruals, insurance limits, or supplemental bonding amounts, which could result in the incurrence of additional costs to complete. Separately, in January 2021, the Biden Administration has issued orders temporarily suspending the issuance of new authorizations and suspending the issuance of new leases pending completion of a review of current practices, for oil and gas development on federal lands and waters. The Biden Administration also published an order calling for an increase in the production of offshore wind energy, which may impact the use of federal waters. We cannot predict with any certainty the full impact of any new laws or regulations on our customers’ drilling operations or on the cost or availability of insurance to cover some or all of the risks associated with such operations. The occurrence of any one or more of these developments could result in decreased demand for our services, which could have a material adverse effect on our business as well as our financial position, results of operation and liquidity.

Our business is subject to federal, state and local laws and regulations that govern the product quality specifications of the petroleum products that we store and transport.

The petroleum products that we store and transport are sold by our customers for consumption into the public market. Various federal, state and local agencies have the authority to prescribe specific product quality specifications to commodities sold into the public market. Changes in product quality specifications could reduce our throughput volume, require us to incur additional handling costs or require the expenditure of significant capital. In addition, different product specifications for different markets impact the fungibility of products transported and stored in our pipeline systems and terminal facilities and could require the construction of additional storage to segregate products with different specifications. We may be unable to recover these costs through increased revenues.

In addition, our patented butane blending services are reliant upon gasoline vapor pressure specifications. Significant changes in such specifications could reduce butane blending opportunities, which would affect our

 

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ability to market our butane blending service licenses and which would ultimately affect our ability to recover the costs incurred to acquire and integrate our butane blending assets.

Risks Relating to Our Partnership Structure

Issuance of Limited Partner units or other classes of equity

We may issue an unlimited number of limited partner interests or other classes of equity without the consent of our Unitholders, which will dilute Unitholders’ ownership interest in us and may increase the risk that we will not have sufficient available cash to maintain or increase our per unit distribution level.

Our partnership agreement allows us to issue an unlimited number of additional limited partner interests, including securities senior to the Common Units, without the approval of our Unitholders. The issuance of additional Common Units or other equity securities by us will have the following effects:

 

   

our Unitholders’ current proportionate ownership interest in us will decrease;

 

   

the amount of cash available for distribution on each Common Unit or partnership security may decrease;

 

   

the ratio of taxable income to distributions may increase;

 

   

the relative voting strength of each previously outstanding Common Unit may be diminished; and

 

   

the market price of our Common Units may decline.

Cash Distributions to Unitholders and Governance

Cash distributions are not guaranteed and may fluctuate with our performance and other external factors.

Our principal source of earnings and cash flow is cash distributions from ETO. In addition, ETO’s earnings and cash flows are generated by its subsidiaries, including ETO’s investments in Sunoco LP and USAC. Therefore, the amount of distributions we are currently able to make to our Unitholders may fluctuate based on the level of distributions ETO and its subsidiaries, including Sunoco LP and USAC, make to their partners. ETO may not be able to continue to make quarterly distributions at its current level or increase its quarterly distributions in the future. In addition, while we would expect to increase or decrease distributions to our Unitholders if ETO increases or decreases distributions to us, the timing and amount of such increased or decreased distributions, if any, will not necessarily be comparable to the timing and amount of the increase or decrease in distributions made by ETO to us.

Our ability to distribute cash received from ETO to our Unitholders is limited by a number of factors, including:

 

   

interest expense and principal payments on our indebtedness;

 

   

restrictions on distributions contained in any current or future debt agreements;

 

   

our general and administrative expenses;

 

   

expenses of our subsidiaries other than ETO and its subsidiaries, including tax liabilities of our corporate subsidiaries, if any; and

 

   

reserves our general partner believes prudent for us to maintain for the proper conduct of our business or to provide for future distributions.

We cannot guarantee that in the future we will be able to pay distributions or that any distributions we do make will be at or above our current quarterly distribution. The actual amount of cash that is available for distribution to our Unitholders will depend on numerous factors, many of which are beyond our control or the control of our general partner.

 

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Our general partner’s absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to our preferred unitholders.

Our partnership agreement requires our general partner to deduct from operating surplus cash reserves that in its reasonable discretion are necessary to fund our future operating expenditures. In addition, our partnership agreement permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available for distribution to unitholders.

Unitholders may have liability to repay distributions.

Under certain circumstances, Unitholders may have to repay us amounts wrongfully distributed to them. Under Delaware law, we may not make a distribution to Unitholders if the distribution causes our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and non-recourse liabilities are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that a limited partner who receives such a distribution and knew at the time of the distribution that the distribution violated Delaware law, will be liable to the limited partnership for the distribution amount for three years from the distribution date.

The NYSE does not require a publicly traded partnership like us to comply with certain corporate governance requirements.

We have preferred units that are listed on the NYSE. Because we are a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, our Unitholders do not have the same protections afforded to stockholders of corporations that are subject to all of the corporate governance requirements of the applicable stock exchange.

Our General Partner

The control of our general partner may be transferred to a third party without Unitholder consent.

The general partner may transfer its general partner interest to a third party without the consent of the Unitholders. Furthermore, the general partner of our general partner may transfer its general partner interest in our general partner to a third party without the consent of the Unitholders. Any new owner of the general partner or the general partner of the general partner would be in a position to replace the officers of the general partner with its own choices and to control the decisions taken by such officers.

Cost reimbursements due to our general partner may be substantial and may reduce our ability to pay the distributions to Unitholders.

Prior to making any distributions to our Unitholders, we will reimburse our general partner for all expenses it has incurred on our behalf. In addition, our general partner and its affiliates may provide us with services for which we will be charged reasonable fees as determined by the general partner. The reimbursement of these expenses and the payment of these fees could adversely affect our ability to make distributions to the Unitholders. Our general partner has sole discretion to determine the amount of these expenses and fees.

Our general partner has a limited call right that may require Unitholders to sell their units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 90% of our outstanding units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire

 

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all, but not less than all, of the units held by unaffiliated persons at a price not less than their then-current market price. As a result, Unitholders may be required to sell their units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units. As of December 31, 2020, the directors and executive officers of our general partner owned approximately 14% of our Common Units.

Our Subsidiaries

We are dependent on third parties, including key personnel of ETO under a shared services agreement, to provide the financial, accounting, administrative and legal services necessary to operate our business.

We rely on the services of key personnel of ETO, including the ongoing involvement and continued leadership of Kelcy L. Warren, one of the founders of ETO’s midstream business. Mr. Warren has been integral to the ETO’s success because of his ability to identify and develop strategic business opportunities. Losing the leadership of Mr. Warren could make it difficult for ETO to identify internal growth projects and accretive acquisitions, which could have a material adverse effect on ETO’s ability to increase the cash distributions paid on its partnership interests.

ETO’s executive officers that provide services to us pursuant to a shared services agreement allocate their time between us and ETO. To the extent that these officers face conflicts regarding the allocation of their time, we may not receive the level of attention from them that the management of our business requires. If ETO is unable to provide us with a sufficient number of personnel with the appropriate level of technical accounting and financial expertise, our internal accounting controls could be adversely impacted.

We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets.

We are a holding company, and our subsidiaries conduct all of our operations and own all of our operating assets. We do not have significant assets other than the partnership interests and the equity in our subsidiaries. As a result, our ability to pay distributions to our Unitholders and to service our debt depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, credit facilities and applicable state partnership laws and other laws and regulations. If we are unable to obtain funds from our subsidiaries, we may not be able to pay distributions to our Unitholders or to pay interest or principal on our debt when due.

The interruption of distributions to us from our operating subsidiaries and equity investees may affect our ability to satisfy our obligations and to make distributions to our partners.

We are a holding company with no business operations other than that of our operating subsidiaries. Our only significant assets are the equity interests we own in our operating subsidiaries and equity investees. As a result, we depend upon the earnings and cash flow of our operating subsidiaries and equity investees and any interruption of distributions to us may affect our ability to meet our obligations, including any obligations under our debt agreements, and to make distributions to our partners.

Our subsidiaries are not prohibited from competing with us.

Neither our partnership agreement nor the partnership agreements of our subsidiaries, including ETO, Sunoco LP and USAC, prohibit our subsidiaries from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, our subsidiaries may acquire, construct or dispose of any assets in the future without any obligation to offer us the opportunity to purchase or construct any of those assets.

 

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ETO may issue additional preferred equity, and Sunoco LP and USAC may issue additional common units, which may increase the risk that each Partnership will not have sufficient available cash to maintain or increase its per unit distribution level.

The partnership agreements of ETO, Sunoco LP and USAC allow each partnership to issue an unlimited number of additional limited partner interests. The issuance of additional preferred units, common units or other equity securities by each respective partnership will have the following effects:

 

   

Unitholders’ current proportionate ownership interest in each partnership will decrease;

 

   

the amount of cash available for distribution on each common unit or partnership security may decrease;

 

   

the ratio of taxable income to distributions may increase;

 

   

the relative voting strength of each previously outstanding common unit may be diminished; and

 

   

the market price of each partnership’s common units may decline.

The payment of distributions on any additional units issued by ETO, Sunoco LP and USAC may increase the risk that either partnership may not have sufficient cash available to maintain or increase its per unit distribution level, which in turn may impact the available cash that we have to meet our obligations

A significant decrease in demand for motor fuel, including increased consumer preference for alternative motor fuels or improvements in fuel efficiency, in the areas Sunoco LP serves would reduce their ability to make distributions to its unitholders.

For the year ended December 31, 2020, sales of refined motor fuels accounted for approximately 96% of Sunoco LP’s total revenues and 72% of gross profit. A significant decrease in demand for motor fuel in the areas Sunoco LP serves could significantly reduce revenues and Sunoco LP’s ability to make distributions to its unitholders, including ETO. Sunoco LP revenues are dependent on various trends, such as trends in commercial truck traffic, travel and tourism in their areas of operation, and these trends can change. Regulatory action, including government imposed fuel efficiency standards, may also affect demand for motor fuel. Because certain of Sunoco LP’s operating costs and expenses are fixed and do not vary with the volumes of motor fuel distributed, their costs and expenses might not decrease ratably or at all should they experience such a reduction. As a result, Sunoco LP may experience declines in their profit margin if fuel distribution volumes decrease.

Any technological advancements, regulatory changes or changes in consumer preferences causing a significant shift toward alternative motor fuels could reduce demand for the conventional petroleum based motor fuels Sunoco LP currently sells. Additionally, a shift toward electric, hydrogen, natural gas or other alternative-power vehicles could fundamentally change customers’ shopping habits or lead to new forms of fueling destinations or new competitive pressures.

New technologies have been developed and governmental mandates have been implemented to improve fuel efficiency, which may result in decreased demand for petroleum-based fuel. Any of these outcomes could result in fewer visits to Sunoco LP’s convenience stores or independently operated commission agents and dealer locations, a reduction in demand from their wholesale customers, decreases in both fuel and merchandise sales revenue, or reduced profit margins, any of which could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to its unitholders.

Sunoco LP’s financial condition and results of operations are influenced by changes in the prices of motor fuel, which may adversely impact margins, customers’ financial condition and the availability of trade credit.

Sunoco LP’s operating results are influenced by prices for motor fuel. General economic and political conditions, acts of war or terrorism and instability in oil producing regions, particularly in the Middle East and South America, could significantly impact crude oil supplies and petroleum costs. Significant increases or high

 

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volatility in petroleum costs could impact consumer demand for motor fuel and convenience merchandise. Such volatility makes it difficult to predict the impact that future petroleum costs fluctuations may have on Sunoco LP’s operating results and financial condition. Sunoco LP is subject to dealer tank wagon pricing structures at certain locations further contributing to margin volatility. A significant change in any of these factors could materially impact both wholesale and retail fuel margins, the volume of motor fuel distributed or sold at retail, and overall customer traffic, each of which in turn could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to its unitholders.

Significant increases in wholesale motor fuel prices could impact Sunoco LP as some of their customers may have insufficient credit to purchase motor fuel from us at their historical volumes. Higher prices for motor fuel may also reduce access to trade credit support or cause it to become more expensive.

The industries in which Sunoco LP operates are subject to seasonal trends, which may cause its operating costs to fluctuate, affecting its cash flow.

Sunoco LP relies in part on customer travel and spending patterns and may experience more demand for gasoline in the late spring and summer months than during the fall and winter. Travel, recreation and construction are typically higher in these months in the geographic areas in which Sunoco LP or its commission agents and dealers operate, increasing the demand for motor fuel that they sell and distribute. Therefore, Sunoco LP’s revenues and cash flows are typically higher in the second and third quarters of our fiscal year. As a result, Sunoco LP’s results from operations may vary widely from period to period, affecting Sunoco LP’s cash flow.

The dangers inherent in the storage and transportation of motor fuel could cause disruptions in Sunoco LP’s operations and could expose them to potentially significant losses, costs or liabilities.

Sunoco LP stores motor fuel in underground and aboveground storage tanks. Sunoco LP transports the majority of its motor fuel in its own trucks, instead of by third-party carriers. Sunoco LP’s operations are subject to significant hazards and risks inherent in transporting and storing motor fuel. These hazards and risks include, but are not limited to, traffic accidents, fires, explosions, spills, discharges, and other releases, any of which could result in distribution difficulties and disruptions, environmental pollution, governmentally-imposed fines or clean-up obligations, personal injury or wrongful death claims, and other damage to its properties and the properties of others. Any such event not covered by Sunoco LP’s insurance could have a material adverse effect on its business, financial condition, results of operations and cash available for distribution to its unitholders.

Sunoco LP’s fuel storage terminals are subject to operational and business risks which may adversely affect their financial condition, results of operations, cash flows and ability to make distributions to its unitholders.

Sunoco LP’s fuel storage terminals are subject to operational and business risks, the most significant of which include the following:

 

   

the inability to renew a ground lease for certain of their fuel storage terminals on similar terms or at all;

 

   

the dependence on third parties to supply their fuel storage terminals;

 

   

outages at their fuel storage terminals or interrupted operations due to weather-related or other natural causes;

 

   

the threat that the nation’s terminal infrastructure may be a future target of terrorist organizations;

 

   

the volatility in the prices of the products stored at their fuel storage terminals and the resulting fluctuations in demand for storage services;

 

   

the effects of a sustained recession or other adverse economic conditions;

 

   

the possibility of federal and/or state regulations that may discourage their customers from storing gasoline, diesel fuel, ethanol and jet fuel at their fuel storage terminals or reduce the demand by consumers for petroleum products;

 

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competition from other fuel storage terminals that are able to supply their customers with comparable storage capacity at lower prices; and

 

   

climate change legislation or regulations that restrict emissions of GHGs could result in increased operating and capital costs and reduced demand for our storage services.

The occurrence of any of the above situations, amongst others, may affect operations at their fuel storage terminals and may adversely affect Sunoco LP’s business, financial condition, results of operations, cash flows and ability to make distributions to its unitholders.

Negative events or developments associated with Sunoco LP’s branded suppliers could have an adverse impact on its revenues.

Sunoco LP believes that the success of its operations is dependent, in part, on the continuing favorable reputation, market value, and name recognition associated with the motor fuel brands sold at Sunoco LP’s convenience stores and at stores operated by its independent, branded dealers and commission agents. Erosion of the value of those brands could have an adverse impact on the volumes of motor fuel Sunoco LP distributes, which in turn could have a material adverse effect on its business, financial condition, results of operations and ability to make distributions to its unitholders.

Sunoco LP currently depends on a limited number of principal suppliers in each of its operating areas for a substantial portion of its merchandise inventory and its products and ingredients for its food service facilities. A disruption in supply or a change in either relationship could have a material adverse effect on its business.

Sunoco LP currently depends on a limited number of principal suppliers in each of its operating areas for a substantial portion of its merchandise inventory and its products and ingredients for its food service facilities. If any of Sunoco LP’s principal suppliers elect not to renew their contracts, Sunoco LP may be unable to replace the volume of merchandise inventory and products and ingredients currently purchased from them on similar terms or at all in those operating areas. Further, a disruption in supply or a significant change in Sunoco LP’s relationship with any of these suppliers could have a material adverse effect on Sunoco LP’s business, financial condition and results of operations and cash available for distribution to its unitholders.

The wholesale motor fuel distribution industry and convenience store industry are characterized by intense competition and fragmentation and impacted by new entrants. Failure to effectively compete could result in lower margins.

The market for distribution of wholesale motor fuel is highly competitive and fragmented, which results in narrow margins. Sunoco LP has numerous competitors, some of which may have significantly greater resources and name recognition than it does. Sunoco LP relies on its ability to provide value-added, reliable services and to control its operating costs in order to maintain our margins and competitive position. If Sunoco LP fails to maintain the quality of its services, certain of its customers could choose alternative distribution sources and margins could decrease. While major integrated oil companies have generally continued to divest retail sites and the corresponding wholesale distribution to such sites, such major oil companies could shift from this strategy and decide to distribute their own products in direct competition with Sunoco LP, or large customers could attempt to buy directly from the major oil companies. The occurrence of any of these events could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to its unitholders.

The geographic areas in which Sunoco LP operates and supplies independently operated commission agent and dealer locations are highly competitive and marked by ease of entry and constant change in the number and type of retailers offering products and services of the type we and our independently operated commission agents and dealers sell in stores. Sunoco LP competes with other convenience store chains, independently owned convenience stores, motor fuel stations, supermarkets, drugstores, discount stores, dollar stores, club stores, mass

 

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merchants and local restaurants. Over the past two decades, several non-traditional retailers, such as supermarkets, hypermarkets, club stores and mass merchants, have impacted the convenience store industry, particularly in the geographic areas in which Sunoco LP operates, by entering the motor fuel retail business. These non-traditional motor fuel retailers have captured a significant share of the motor fuels market, and Sunoco LP expects their market share will continue to grow.

In some of Sunoco LP’s markets, its competitors have been in existence longer and have greater financial, marketing, and other resources than they or their independently operated commission agents and dealers do. As a result, Sunoco LP’s competitors may be able to better respond to changes in the economy and new opportunities within the industry. To remain competitive, Sunoco LP must constantly analyze consumer preferences and competitors’ offerings and prices to ensure that they offer a selection of convenience products and services at competitive prices to meet consumer demand. Sunoco LP must also maintain and upgrade our customer service levels, facilities and locations to remain competitive and attract customer traffic to our stores. Sunoco LP may not be able to compete successfully against current and future competitors, and competitive pressures faced by Sunoco LP could have a material adverse effect on its business, results of operations and cash available for distribution to its unitholders.

Sunoco LP may be subject to adverse publicity resulting from concerns over food quality, product safety, health or other negative events or developments that could cause consumers to avoid its retail locations or independently operated commission agent or dealer locations.

Sunoco LP may be the subject of complaints or litigation arising from food-related illness or product safety which could have a negative impact on its business. Negative publicity, regardless of whether the allegations are valid, concerning food quality, food safety or other health concerns, food service facilities, employee relations or other matters related to its operations may materially adversely affect demand for its food and other products and could result in a decrease in customer traffic to its retail stores or independently operated commission agent or dealer locations.

It is critical to Sunoco LP’s reputation that they maintain a consistent level of high quality at their food service facilities and other franchise or fast food offerings. Health concerns, poor food quality or operating issues stemming from one store or a limited number of stores could materially and adversely affect the operating results of some or all of their stores and harm the company-owned brands, continuing favorable reputation, market value and name recognition.

Sunoco LP does not own all of the land on which its retail service stations are located, and Sunoco LP leases certain facilities and equipment, and Sunoco LP is subject to the possibility of increased costs to retain necessary land use which could disrupt its operations.

Sunoco LP does not own all of the land on which its retail service stations are located. Sunoco LP has rental agreements for approximately 38% of the company, commission agent or dealer operated retail service stations where Sunoco LP currently controls the real estate. Sunoco LP also has rental agreements for certain logistics facilities. As such, Sunoco LP is subject to the possibility of increased costs under rental agreements with landowners, primarily through rental increases and renewals of expired agreements. Sunoco LP is also subject to the risk that such agreements may not be renewed. Additionally, certain facilities and equipment (or parts thereof) used by Sunoco LP are leased from third parties for specific periods. Sunoco LP’s inability to renew leases or otherwise maintain the right to utilize such facilities and equipment on acceptable terms, or the increased costs to maintain such rights, could have a material adverse effect on its financial condition, results of operations and cash flows.

Sunoco LP is subject to federal laws related to the Renewable Fuel Standard.

New laws, new interpretations of existing laws, increased governmental enforcement of existing laws or other developments could require us to make additional capital expenditures or incur additional liabilities. For

 

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example, certain independent refiners have initiated discussions with the EPA to change the way the Renewable Fuel Standard (“RFS”) is administered in an attempt to shift the burden of compliance from refiners and importers to blenders and distributors. Under the RFS, which requires an annually increasing amount of biofuels to be blended into the fuels used by U.S. drivers, refiners/importers are obligated to obtain renewable identification numbers (“RINS”) either by blending biofuel into gasoline or through purchase in the open market. If the obligation was shifted from the importer/refiner to the blender/distributor, the Partnership would potentially have to utilize the RINS it obtains through its blending activities to satisfy a new obligation and would be unable to sell RINS to other obligated parties, which may cause an impact on the fuel margins associated with Sunoco LP’s sale of gasoline. In addition, the RFS regulations are highly complex and evolving, and the RINS market is subject to significant price volatility as a result. The price of RINS to meet compliance obligations under the RFS could be substantial and adversely impact our financial condition.

The occurrence of any of the events described above could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to its unitholders.

Sunoco LP is subject to federal, state and local laws and regulations that govern the product quality specifications of refined petroleum products it purchases, stores, transports, and sells to its distribution customers.

Various federal, state, and local government agencies have the authority to prescribe specific product quality specifications for certain commodities, including commodities that Sunoco LP distributes. Changes in product quality specifications, such as reduced sulfur content in refined petroleum products, or other more stringent requirements for fuels, could reduce Sunoco LP’s ability to procure product, require it to incur additional handling costs and/or require the expenditure of capital. If Sunoco LP is unable to procure product or recover these costs through increased selling price, it may not be able to meet its financial obligations. Failure to comply with these regulations could result in substantial penalties for Sunoco LP.

USAC’s customers may choose to vertically integrate their operations by purchasing and operating their own compression fleet, increasing the number of compression units they currently own or using alternative technologies for enhancing crude oil production.

USAC’s customers that are significant producers, processors, gatherers and transporters of natural gas and crude oil may choose to vertically integrate their operations by purchasing and operating their own compression fleets in lieu of using USAC’s compression services. The historical availability of attractive financing terms from financial institutions and equipment manufacturers facilitates this possibility by making the purchase of individual compression units increasingly affordable to USAC’s customers. In addition, there are many technologies available for the artificial enhancement of crude oil production, and USAC’s customers may elect to use these alternative technologies instead of the gas lift compression services USAC provides. Such vertical integration, increases in vertical integration or use of alternative technologies could result in decreased demand for USAC’s compression services, which may have a material adverse effect on its business, results of operations, financial condition and reduce its cash available for distribution.

A significant portion of USAC’s services are provided to customers on a month-to-month basis, and USAC cannot be sure that such customers will continue to utilize its services.

USAC’s contracts typically have an initial term of between six months and five years, depending on the application and location of the compression unit. After the expiration of the initial term, the contract continues on a month-to-month or longer basis until terminated by USAC or USAC’s customers upon notice as provided for in the applicable contract. For the year ended December 31, 2020, approximately 30% of USAC’s compression services on a revenue basis were provided on a month-to-month basis to customers who continue to utilize its services following expiration of the primary term of their contracts. These customers can generally terminate their month-to-month compression services contracts on 30-days’ written notice. If a significant number of these

 

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customers were to terminate their month-to-month services, or attempt to renegotiate their month-to-month contracts at substantially lower rates, it could have a material adverse effect on USAC’s business, results of operations, financial condition and cash available for distribution.

USAC’s preferred units have rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of its common units.

USAC’s preferred units rank senior to all of its other classes or series of equity securities with respect to distribution rights and rights upon liquidation. These preferences could adversely affect the market price for its common units or could make it more difficult for USAC to sell its common units in the future.

In addition, distributions on USAC’s preferred units accrue and are cumulative, at the rate of 9.75% per annum on the original issue price, which amounts to a quarterly distribution of $24.375 per preferred unit. If USAC does not pay the required distributions on its preferred units, USAC will be unable to pay distributions on its common units. Additionally, because distributions on USAC’s preferred units are cumulative, USAC will have to pay all unpaid accumulated distributions on the preferred units before USAC can pay any distributions on its common units. Also, because distributions on USAC’s common units are not cumulative, if USAC does not pay distributions on its common units with respect to any quarter, USAC’s common unitholders will not be entitled to receive distributions covering any prior periods if USAC later recommences paying distributions on its common units.

USAC’s preferred units are convertible into common units by the holders of USAC’s preferred units or by USAC in certain circumstances. USAC’s obligation to pay distributions on USAC’s preferred units, or on the common units issued following the conversion of USAC’s preferred units, could impact USAC’s liquidity and reduce the amount of cash flow available for working capital, capital expenditures, growth opportunities, acquisitions and other general Partnership purposes. USAC’s obligations to the holders of USAC’s preferred units could also limit its ability to obtain additional financing or increase its borrowing costs, which could have an adverse effect on its financial condition.

Risks Related to Conflicts of Interest

The fiduciary duties of our general partner’s officers and directors may conflict with those of ETO’s, Sunoco LP’s or USAC’s respective general partners.

Conflicts of interest may arise because of the relationships among ETO, Sunoco LP, USAC, their general partners and us. Our General Partner’s directors and officers have fiduciary duties to manage our business in a manner beneficial to us and our Unitholders. Some of our general partner’s directors or officers are also directors and/or officers of ETO’s general partner, Sunoco LP’s general partner or USAC’s general partner, and have fiduciary duties to manage the respective businesses of ETO, Sunoco LP and USAC in a manner beneficial to ETO, Sunoco LP, USAC and their respective unitholders. The resolution of these conflicts may not always be in our best interest or that of our Unitholders.

Potential conflicts of interest may arise among our general partner, its affiliates and us. Our general partner and its affiliates have limited fiduciary duties to us, which may permit them to favor their own interests to the detriment of us.

Conflicts of interest may arise among our general partner and its affiliates, on the one hand, and us, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over our interests. These conflicts include, among others, the following:

 

   

our general partner is allowed to take into account the interests of parties other than us, including ETO, and its subsidiaries, including Sunoco LP and USAC, and their respective affiliates and any general partners and limited partnerships acquired in the future, in resolving conflicts of interest, which has the effect of limiting its fiduciary duties to us.

 

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our general partner has limited its liability and reduced its fiduciary duties under the terms of our partnership agreement, while also restricting the remedies available for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing our units, Unitholders consent to various actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law.

 

   

our general partner determines the amount and timing of our investment transactions, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available for distribution.

 

   

our general partner determines which costs it and its affiliates have incurred are reimbursable by us.

 

   

our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered, or from entering into additional contractual arrangements with any of these entities on our behalf, so long as the terms of any such payments or additional contractual arrangements are fair and reasonable to us.

 

   

our general partner controls the enforcement of obligations owed to us by it and its affiliates.

 

   

our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

Our partnership agreement limits our general partner’s fiduciary duties to us and restricts the remedies available for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:

 

   

permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner;

 

   

provides that our general partner is entitled to make other decisions in “good faith” if it reasonably believes that the decisions are in our best interests;

 

   

generally provides that affiliated transactions and resolutions of conflicts of interest not approved by a conflicts committee of the board of directors of our general partner and not involving a vote of Unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us;

 

   

provides that unless our general partner has acted in bad faith, the action taken by our general partner shall not constitute a breach of its fiduciary duty;

 

   

provides that our general partner may resolve any conflicts of interest involving us and our general partner and its affiliates, and any resolution of a conflict of interest by our general partner that is “fair and reasonable” to us will be deemed approved by all partners, including the Unitholders, and will not constitute a breach of the partnership agreement;

 

   

provides that our general partner may, but is not required, in connection with its resolution of a conflict of interest, to seek “special approval” of such resolution by appointing a conflicts committee of the general partner’s board of directors composed of two or more independent directors to consider such conflicts of interest and to recommend action to the board of directors, and any resolution of the conflict of interest by the conflicts committee shall be conclusively deemed “fair and reasonable” to us; and

 

   

provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable

 

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judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or gross negligence.

Our general partner’s absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to our Unitholders.

Our partnership agreement requires our general partner to deduct from operating surplus cash reserves that in its reasonable discretion are necessary to fund our future operating expenditures. In addition, our partnership agreement permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available for distribution to Unitholders.

Although we control Sunoco LP and USAC through our ownership of Sunoco LP’s and USAC’s general partners, Sunoco LP’s and USAC’s general partners owe duties to Sunoco LP and Sunoco LP’s unitholders and USAC and USAC’s unitholders, respectively, which may conflict with our interests.

Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, on the one hand, and Sunoco LP and USAC and their respective limited partners, on the other hand. The directors and officers of Sunoco LP’s and USAC’s general partners have duties to manage Sunoco LP and USAC, respectively, in a manner beneficial to us. At the same time, the general partners have fiduciary duties to manage Sunoco LP and USAC in a manner beneficial to Sunoco LP and USAC and their respective limited partners. The boards of directors of Sunoco LP’s and USAC’s general partner will resolve any such conflict and have broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest.

For example, conflicts of interest with Sunoco LP and USAC may arise in the following situations:

 

   

the allocation of shared overhead expenses to Sunoco LP, USAC and us;

 

   

the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and Sunoco LP and USAC, on the other hand;

 

   

the determination of the amount of cash to be distributed to Sunoco LP’s and USAC’s partners and the amount of cash to be reserved for the future conduct of Sunoco LP’s and USAC’s businesses;

 

   

the determination whether to make borrowings under Sunoco LP’s and USAC’s revolving credit facilities to pay distributions to their respective partners;

 

   

the determination of whether a business opportunity (such as a commercial development opportunity or an acquisition) that we may become aware of independently of Sunoco LP and USAC is made available for Sunoco LP and USAC to pursue; and

 

   

any decision we make in the future to engage in business activities independent of Sunoco LP and USAC.

Some of our executive officers and directors face potential conflicts of interest in managing our business.

Certain of our executive officers and directors are also officers and/or directors of ETO. These relationships may create conflicts of interest regarding corporate opportunities and other matters. The resolution of any such conflicts may not always be in our or our Unitholders’ best interests. In addition, these overlapping executive officers and directors allocate their time among us and ETO. These officers and directors face potential conflicts regarding the allocation of their time, which may adversely affect our business, results of operations and financial condition.

 

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Affiliates of our general partner may compete with us.

Except as provided in our partnership agreement, affiliates and related parties of our general partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us.

Tax Risks to Unitholders

Our tax treatment depends on our continuing status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation. If the IRS were to treat us, ETO or its subsidiaries, including Sunoco LP and USAC as a corporation for federal income tax purposes or if we, ETO, Sunoco LP or USAC become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our Common Units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this matter. The value of our investments in ETO and its subsidiaries, including Sunoco LP and USAC, depend largely on ETO, Sunoco LP and USAC being treated as partnerships for federal income tax purposes. Despite the fact that we, ETO, Sunoco LP and USAC are each a limited partnership under Delaware law, we would each be treated as a corporation for federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations and current Treasury Regulations, we believe we, ETO, Sunoco LP and USAC satisfy the qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us, ETO, Sunoco LP or USAC to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we, ETO, Sunoco LP or USAC were treated as a corporation for federal income tax purposes, we would pay federal income tax at the corporate tax rate and we would likely pay additional state income taxes at varying rates. Distributions to Unitholders would generally be taxed again as corporate distributions, and none of our income, gains, losses or deductions would flow through to Unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to Unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the Unitholders, likely causing a substantial reduction in the value of our Common Units.

At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, or other forms of taxation. We currently own property or conduct business in many states that impose a margin or franchise tax. In the future, we may expand our operations. Imposition of a similar tax on us in the jurisdictions in which we operate or in other jurisdictions to which we may expand could substantially reduce our cash available for distribution to our Unitholders. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for U.S. federal, state, local or foreign income tax purposes, the target distribution amounts may be adjusted to reflect the impact of that law or interpretation on us.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

The present United States federal income tax treatment of publicly traded partnerships, including us, or an investment in our Common Units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. Members of Congress have frequently proposed and considered substantive changes to the existing United States federal income tax laws that affect publicly traded partnerships, including proposals that would eliminate our ability to qualify for partnership tax treatment.

 

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Any modification to the United States federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for United States federal income tax purposes. We are unable to predict whether any changes or other proposals will ultimately be enacted. Any future legislative changes could negatively impact the value of an investment in our Common Units. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our Common Units.

If the IRS contests the federal income tax positions we take, the market for our Common Units may be adversely affected and the costs of any such contest will reduce cash available for distributions to our Unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our Common Units and the prices at which they trade. In addition, the costs of any contest between us and the IRS will result in a reduction in our cash available for distribution to our Unitholders and thus will be borne indirectly by our Unitholders.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us, in which case our cash available for distribution to our Unitholders might be substantially reduced.

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue an information statement to each Unitholder and former Unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our Unitholders and former Unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current Unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such Unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our Unitholders might be substantially reduced.

Unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Our Unitholders are required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income whether or not they receive cash distributions from us. Our Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

Tax gain or loss on disposition of our Common Units could be more or less than expected.

If a Unitholder sells their Common Units, the Unitholder will recognize a gain or loss equal to the difference between the amount realized and that Unitholder’s tax basis in those units. Because distributions in excess of a Unitholder’s allocable share of our net taxable income decrease such Unitholder’s tax basis in their Common Units, the amount, if any, of such prior excess distributions with respect to the units a Unitholder sells will, in

 

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effect, become taxable income to a Unitholder if such units are sold at a price greater than their tax basis in those units, even if the price such Unitholder receives is less than their original costs. In addition, because the amount realized includes a Unitholder’s share of our nonrecourse liabilities, if a Unitholder sells their Common Units, a Unitholder may incur a tax liability in excess of the amount of cash received from the sale.

A substantial portion of the amount realized from a Unitholder’s sale of their Common Units, whether or not representing gain, may be taxed as ordinary income to such Unitholder due to potential recapture items, including depreciation recapture.Thus, a Unitholder may recognize both ordinary income and capital loss from the sale of Common Units if the amount realized on a sale of such units is less than such Unitholder’s adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which a Unitholder sells their Common Units, such Unitholder may recognize ordinary income from our allocations of income and gain to such Unitholder prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of Common Units.

Tax-exempt entities face unique tax issues from owning our units that may result in adverse tax consequences to them.

Investment in our units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs) raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from United States federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Tax-exempt entities should consult a tax advisor before investing in our units.

Non-United States Unitholders will be subject to United States taxes and withholding with respect to their income and gain from owning our units.

Non-United States Unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a United States trade or business (“effectively connected income”). Income allocated to our Unitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a United States trade or business. As a result, distributions to a non-United States Unitholder will be subject to withholding at the highest applicable effective tax rate and a non-United States Unitholder who sells or otherwise disposes of a unit will also be subject to United States federal income tax on the gain realized from the sale or disposition of that unit.

Moreover, the transferee of an interest in a partnership that is engaged in a United States trade or business is generally required to withhold 10% of the “amount realized” by the transferor unless the transferor certifies that it is not a foreign person. While the determination of a partner’s “amount realized” generally includes any decrease of a partner’s share of the partnership’s liabilities, recently issued Treasury regulations provide that the “amount realized” on a transfer of an interest in a publicly traded partnership, such as our Common Units, will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and thus will be determined without regard to any decrease in that partner’s share of a publicly traded partnership’s liabilities. The Treasury regulations further provide that withholding on a transfer of an interest in a publicly traded partnership will not be imposed on a transfer that occurs prior to January 1, 2022, and after that date, if effected through a broker, the obligation to withhold is imposed on the transferor’s broker.

We have subsidiaries that will be treated as corporations for federal income tax purposes and subject to corporate-level income taxes.

Even though we (as a partnership for United States federal income tax purposes) are not subject to United States federal income tax, some of our operations are conducted through subsidiaries that are organized as corporations for United States federal income tax purposes. The taxable income, if any, of subsidiaries that are treated as corporations for United States federal income tax purposes, is subject to corporate-level United States federal

 

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income taxes, which may reduce the cash available for distribution to us and, in turn, to our Unitholders. If the IRS or other state or local jurisdictions were to successfully assert that these corporations have more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, the cash available for distribution could be further reduced. The income tax return filings positions taken by these corporate subsidiaries require significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is also required in assessing the timing and amounts of deductible and taxable items. Despite our belief that the income tax return positions taken by these subsidiaries are fully supportable, certain positions may be successfully challenged by the IRS, state or local jurisdictions.

We treat each purchaser of Common Units as having the same tax benefits without regard to the actual Common Units purchased. The IRS may challenge this treatment, which could result in a Unitholder owing more tax and may adversely affect the value of the Common Units.

Because we cannot match transferors and transferees of Common Units and because of other reasons, we have adopted certain methods for allocating depreciation, depletion and amortization that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to the use of these methods could adversely affect the amount of tax benefits available to our Unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of Common Units and could have a negative impact on the value of our Common Units or result in audit adjustments to tax returns of our Unitholders. Moreover, because we have subsidiaries that are organized as C corporations for federal income tax purposes owns units in us, a successful IRS challenge could result in this subsidiary having a greater tax liability than we anticipate and, therefore, reduce the cash available for distribution to our partnership and, in turn, to our Unitholders.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge aspects of our proration method, and if successful, we would be required to change the allocation of items of income, gain, loss and deduction among our Unitholders.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month (the “Allocation Date”), instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate (i) certain deductions for depreciation of capital additions, (ii) gain or loss realized on a sale or other disposition of our assets and (iii) in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of the proration method we have adopted. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our Unitholders.

A Unitholder whose units are the subject of a securities loan (e.g. a loan to a short seller to cover a short sale of units) may be considered as having disposed of those units. If so, such Unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a Unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the Unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller, and the Unitholder and may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the Unitholder and any cash distributions received by the Unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax advisor to

 

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determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

We have adopted certain valuation methodologies in determining Unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methods or the resulting allocations, and such a challenge could adversely affect the value of our Common Units.

When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to such assets to the capital accounts of our Unitholders and our general partner. Although we may from time to time consult with professional appraisers regarding valuation matters, including the valuation of our assets, we make many of the fair market value estimates of our assets ourselves using a methodology based on the market value of our Common Units as a means to measure the fair market value of our assets. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain Unitholders and our general partner, which may be unfavorable to such Unitholders. Moreover, under our current valuation methods, subsequent purchasers of our Common Units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our general partner and certain of our Unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our Unitholders. It also could affect the amount of gain on the sale of Common Units by our Unitholders and could have a negative impact on the value of our Common Units or result in audit adjustments to the tax returns of our Unitholders without the benefit of additional deductions.

Unitholders will likely be subject to state and local taxes and income tax return filing requirements in jurisdictions where they do not live as a result of investing in our units.

In addition to United States federal income taxes, the Unitholders may be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we or our subsidiaries conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, Unitholders may be subject to penalties for failure to comply with those requirements. It is the responsibility of each Unitholder to file all federal, state and local tax returns.

Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.

In general, our Unitholders are entitled to a deduction for the interest we have paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, subject to the exceptions in the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”), under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, our deduction for “business interest” is generally limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the 2020 taxable year, the CARES Act generally increases the 30% adjusted taxable income limitation to 50%. For the purposes of this limitation, adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion. The interest limitation does not apply to regulated pipeline businesses and, therefore, we believe that our interest expense is fully deductible. If the IRS contests this position or if further guidance is issued contrary to the positions taken, the unitholder’s ability to deduct this interest expense could be limited.

 

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ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

A description of our properties is included in “Item 1. Business.” In addition, we own office buildings for our executive offices in Dallas, Texas and office buildings in Newton Square, Pennsylvania; Houston, Texas and San Antonio, Texas. While we may require additional office space as our business expands, we believe that our existing facilities are adequate to meet our needs for the immediate future, and that additional facilities will be available on commercially reasonable terms as needed.

We believe that we have satisfactory title to or valid rights to use all of our material properties. Although some of our properties are subject to liabilities and leases, liens for taxes not yet due and payable, encumbrances securing payment obligations under non-competition agreements and immaterial encumbrances, easements and restrictions, we do not believe that any such burdens will materially interfere with our continued use of such properties in our business, taken as a whole. In addition, we believe that we have, or are in the process of obtaining, all required material approvals, authorizations, orders, licenses, permits, franchises and consents of, and have obtained or made all required material registrations, qualifications and filings with, the various state and local government and regulatory authorities which relate to ownership of our properties or the operations of our business.

Substantially all of our pipelines, which are described in “Item 1. Business,” are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained, where necessary, easement agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, railroad properties and state highways, as applicable. In some cases, properties on which our pipelines were built were purchased in fee. We also own and operate multiple natural gas and NGL storage facilities and own or lease other processing, treating and conditioning facilities in connection with our midstream operations.

ITEM 3. LEGAL PROCEEDINGS

ETC Sunoco Holdings LLC and Sunoco (R&M), LLC (collectively, “Sunoco Defendants”) are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability, nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices claims. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees.

As of December 31, 2020, Sunoco Defendants are defendants in five cases, including one case each initiated by the States of Maryland and Rhode Island, one by the Commonwealth of Pennsylvania and two by the Commonwealth of Puerto Rico. The more recent Puerto Rico action is a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. The actions brought by the State of Maryland and Commonwealth of Pennsylvania have also named as defendants ETO, ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals L.P. (“SPMT”).

It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position.

 

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In April 2016, PHMSA issued a Notice of Probable Violation, Proposed Compliance Order, and Proposed Civil Penalty related to certain welding practices and procedures followed during construction of ETO’s Permian Express 2 pipeline system in Texas. PHMSA subsequently issued a Final Order, and the related civil penalty has been paid. Additional penalties could be assessed related to ongoing compliance actions; however, the Partnership does not currently anticipate additional penalties.

In late 2016, FERC Enforcement Staff began a non-public investigation of Rover’s removal of the Stoneman House, a potential historic structure, in connection with Rover’s application for permission to construct a new interstate natural gas pipeline and related facilities. In mid-2017, FERC Enforcement Staff began a non-public investigation regarding allegations that diesel fuel may have been included in the drilling mud at the Tuscarawas River horizontal directional drilling (“HDD”) operations. Rover and the Partnership are cooperating with the investigations. Enforcement Staff has provided Rover its non-public preliminary findings regarding those investigations. The company disagrees with those findings and intends to vigorously defend against any potential penalty. Given the stage of the proceedings, and the non-public nature of the investigation, the Partnership is unable at this time to provide an assessment of the potential outcome or range of potential liability, if any.

On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (“Ohio EPA”) filed suit against Rover and other defendants (collectively, the “Defendants”) seeking to recover approximately $2.6 million in civil penalties allegedly owed and certain injunctive relief related to permit compliance. The Defendants filed several motions to dismiss, which were granted on all counts. The Ohio EPA appealed, and on December 9, 2019, the Fifth District court of appeals entered a unanimous judgment affirming the trial court. The Ohio EPA sought review from the Ohio Supreme Court. On April 22, 2020, the Ohio Supreme Court granted the review. Briefing has concluded and oral arguments were held on January 26, 2021, but no opinion has yet been issued.

Energy Transfer received an Administrative Compliance Order from the New Mexico Environmental Department on August 28, 2020 to settle the outstanding NOVs at its Jal 3 gas plant. The NOVs covered emission events that occurred January 1, 2017 through August 31, 2018. The Compliance Order includes an assessed civil penalty of $4,023,779.80. The proceedings in this case are stayed until May 17, 2021 to allow the parties to discuss possible settlement of this matter. Negotiations with the NMED are ongoing.

In January 2019, we received notice from the DOJ on behalf of the EPA that a civil penalty enforcement action was being pursued under the Clean Water Act for an estimated 450 barrel crude oil release from the Mid-Valley Pipeline operated by SPLP and owned by Mid-Valley Pipeline Corporation. The release purportedly occurred in October 2014 on a nature preserve located in Hamilton County, Ohio, near Cincinnati, Ohio. After discovery and notification of the release, SPLP conducted substantial emergency response, remedial work and primary restoration in three phases and the primary restoration has been acknowledged to be complete. Operation and maintenance (O&M) activities will continue for several years. In December of 2019, SPLP reached an agreement in principal with the EPA regarding payment of a civil penalty which will be subject to public comment. The DOJ, on behalf of United States Department of Interior Fish and Wildlife, and the Ohio Attorney General, on behalf of the Ohio EPA, along with technical representatives from those agencies have been discussing natural resource damage assessment claims related to state endangered species and compensatory restoration. The timing and outcome of these matters cannot be reasonably determined at this time; however, we do not expect there to be a material impact to our results of operations, cash flows or financial position.

On September 10, 2018, a pipeline release and fire (the “Incident”) occurred on the Revolution pipeline, a natural gas gathering line located in Center Township, Beaver County, Pennsylvania. There were no injuries. On February 8, 2019, the Pennsylvania Department of Environmental Protection (“PADEP”) issued a Permit Hold on any requests for approvals/permits or permit amendments for any project in Pennsylvania pursuant to the state’s water laws. The Partnership filed an appeal of the Permit Hold with the Pennsylvania Environmental Hearing Board. On January 3, 2020, the Partnership entered into a Consent Order and Agreement with the Department in which, among other things, the Permit Hold was lifted, the Partnership agreed to pay a

 

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$28.6 million civil penalty and fund a $2 million community environmental project, and all related appeals were withdrawn. On November 11, 2020, the PADEP issued an Order, which requires additional approvals and work prior to placing the Revolution Pipeline back in service. The Partnership filed an appeal of this Order with the Environmental Hearing Board on December 8, 2020.

The Pennsylvania Office of Attorney General has commenced an investigation regarding the Incident, and the United States Attorney for the Western District of Pennsylvania has issued a federal grand jury subpoena for documents relevant to the Incident. The scope of these investigations is not further known at this time.

On June 4, 2019, the Oklahoma Corporation Commission’s (“OCC”) Transportation Division filed a complaint against SPLP seeking a penalty of up to $1 million related to a May 2018 rupture near Edmond, Oklahoma. The rupture occurred on the Noble to Douglas 8” pipeline in an area of external corrosion and caused the release of approximately fifteen barrels of crude oil. SPLP responded immediately to the release and remediated the surrounding environment and pipeline in cooperation with the OCC. The OCC filed the complaint alleging that SPLP failed to provide adequate cathodic protection to the pipeline causing the failure. SPLP is negotiating a settlement agreement with the OCC for a lesser penalty.

Additionally, we have received notices of violations and potential fines under various federal, state and local provisions relating to the discharge of materials into the environment or protection of the environment. While we believe that even if any one or more of the environmental proceedings listed above were decided against us, it would not be material to our financial position, results of operations or cash flows, we are required to report environmental governmental proceedings if we reasonably believe that such proceedings will result in monetary sanctions in excess of $300,000.

For a description of other legal proceedings, see Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

 

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Parent Company

Description of Units

As of February 18, 2021, there were approximately 13,375 holders of record of our common units, which number does not separately account for individual participants in securities positions listings. Common units represent limited partner interests in us that entitle the holders to the rights and privileges specified in the Parent Company’s Third Amended and Restated Agreement of Limited Partnership, as amended to date (the “Partnership Agreement”).

As of December 31, 2020, limited partners own an aggregate 99.9% limited partner interest in us. Our General Partner owns an aggregate 0.1% general partner interest in us. Our common units are registered under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and are listed for trading on the NYSE under the ticker symbol “ET.” Each holder of a common unit is entitled to one vote per unit on all matters presented to the limited partners for a vote. In addition, if at any time any person or group (other than our General Partner and its affiliates) owns beneficially 20% or more of all common units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under our Partnership Agreement. The common units are entitled to distributions of Available Cash as described below under “Cash Distribution Policy.”

ET Class A Units

In October 2018, in connection with merger of ETO with a wholly-owned subsidiary of the Partnership in a unit-for-unit exchange (the “Energy Transfer Merger”), the Partnership issued 647,745,099 Class A units (“ET Class A Units”) representing limited partner interests in the Partnership to the General Partner. The number of ET Class A Units issued allows the General Partner and its affiliates to retain a voting interest in the Partnership that is identical to their voting interest in the Partnership prior to the completion of the Energy Transfer Merger. The ET Class A Units are entitled to vote together with the Partnership’s common units, as a single class, except as required by law. Additionally, ET’s partnership agreement provides that, under certain circumstances, upon the issuance by the Partnership of additional common units or any securities that have voting rights that are pari passu with the Partnership common units, the Partnership will issue to any holder of ET Class A Units additional ET Class A Units such that the holder maintains a voting interest in the Partnership that is identical to its voting interest in the Partnership prior to such issuance of common units. In connection with the SemGroup Transaction, we issued an additional 14,246,973 ET Class A Units in December 2019. The ET Class A Units are not entitled to distributions and otherwise have no economic attributes.

Cash Distribution Policy

General. The Parent Company will distribute all of its “Available Cash” to its unitholders and its General Partner within 50 days following the end of each fiscal quarter.

Definition of Available Cash. Available Cash is defined in the Partnership Agreement and generally means, with respect to any calendar quarter, all cash on hand at the end of such quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the General Partner to:

 

   

provide for the proper conduct of its business;

 

   

comply with applicable law and/or debt instrument or other agreement; and

 

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provide funds for distributions to unitholders and its General Partner in respect of any one or more of the next four quarters.

Recent Sales of Unregistered Securities

None.

Issuer Purchases of Equity Securities

None.

Securities Authorized for Issuance Under Equity Compensation Plans

For information on the securities authorized for issuance under ET’s equity compensation plans, see “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.”

ITEM 6. SELECTED FINANCIAL DATA

The selected historical financial data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical consolidated financial statements and accompanying notes thereto included elsewhere in this report. The amounts in the table below, except per unit data, are in millions.

As discussed in Note 2 to the consolidated financial statements in “Item 8. Financial Statements and Supplementary Data” the Partnership’s consolidated financial statements for all periods presented have been retrospectively adjusted to reflect the change in the accounting policy related to certain barrels of crude oil.

 

     Years Ended December 31,  
     2020     2019      2018     2017     2016  

Statement of Operations Data:

           

Total revenues

   $ 38,954   $ 54,213    $ 54,087   $ 40,523   $ 31,792

Operating income

     2,980     7,203      5,403     2,670     1,809

Income from continuing operations

     140     4,825      3,685     2,492     420

Loss from discontinued operations

     —         —          (265     (177     (462

Net income (loss)

     140     4,825      3,420     2,315     (42

Basic income (loss) from continuing operations per limited partner unit

     (0.24     1.34      1.21     0.81     0.91

Diluted income (loss) from continuing operations per limited partner unit

     (0.24     1.33      1.20     0.79     0.89

Basic loss from discontinued operations per limited partner unit

     —         —          (0.01     (0.01     (0.01

Diluted loss from discontinued operations per limited partner unit

     —         —          (0.01     (0.01     (0.01

Cash distribution per common unit

     0.92     1.22      1.22     1.17     1.14

Balance Sheet Data (at period end):

           

Assets held for sale

     —         —          —         3,313     3,588

Total assets

     95,144     98,973      88,413     86,358     79,088

Liabilities associated with assets held for sale

     —         —          —         75     48

Long-term debt, less current maturities

     51,417     51,028      43,373     43,671     42,608

Total equity

     31,388     33,938      31,017     30,092     22,594

 

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

(Tabular dollar and unit amounts, except per unit data, are in millions)

Energy Transfer LP is a Delaware limited partnership whose common units are publicly traded on the NYSE under the ticker symbol “ET.”

The following discussion of our historical consolidated financial condition and results of operations should be read in conjunction with our historical consolidated financial statements and accompanying notes thereto included in “Item 8. Financial Statements and Supplementary Data” of this report. This discussion includes forward-looking statements that are subject to risk and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in “Item 1A. Risk Factors” of this report.

Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ET” mean Energy Transfer LP and its consolidated subsidiaries, which include ETO, ETP GP, ETP LLC, Panhandle, Sunoco LP and Lake Charles LNG. References to the “Parent Company” mean Energy Transfer LP on a stand-alone basis.

OVERVIEW

Energy Transfer LP directly and indirectly owns equity interests in ETO, Sunoco LP and USAC, all of which are limited partnerships engaged in diversified energy-related services. Sunoco LP and USAC have publicly traded common units.

We control ETO through our ownership of its general partner.

The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETO. ETO’s earnings and cash flows are generated by its subsidiaries, including ETO’s investments in Sunoco LP and USAC. The amount of cash that ETO, Sunoco LP and USAC distribute to their respective partners, including the Parent Company, each quarter is based on earnings from their respective business activities and the amount of available cash, as discussed below.

In order to fully understand the financial condition and results of operations of the Parent Company on a stand-alone basis, we have included discussions of Parent Company matters apart from those of our consolidated group.

General

Our primary objective is to increase the level of our distributable cash flow to our Unitholders over time by pursuing a business strategy that is currently focused on growing our subsidiaries’ natural gas and liquids businesses through, among other things, pursuing certain construction and expansion opportunities relating to our subsidiaries’ existing infrastructure and acquiring certain strategic operations and businesses or assets. The actual amounts of cash that we will have available for distribution will primarily depend on the amount of cash our subsidiaries generate from their operations.

Our reportable segments are as follows:

 

   

intrastate transportation and storage;

 

   

interstate transportation and storage;

 

   

midstream;

 

   

NGL and refined products transportation and services;

 

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crude oil transportation and services;

 

   

investment in Sunoco LP;

 

   

investment in USAC; and

 

   

all other.

Recent Developments

COVID-19

In 2020, the COVID-19 pandemic prompted several states and municipalities in which we operate to take extraordinary and wide-ranging actions to contain and combat the outbreak and spread of the virus, including mandates for many individuals to substantially restrict daily activities and for many businesses to curtail or cease normal operations. To the extent COVID-19 continues or worsens, governments may impose additional similar restrictions. As a provider of critical energy infrastructure, our business has been designated as a “critical infrastructure sector” and our employees as “essential critical infrastructure workers” pursuant to the Department of Homeland Security Guidance on Essential Critical Infrastructure Workforce(s). To date, our field operations have continued uninterrupted, and remote work and other COVID-19 related conditions have not significantly impacted our ability to maintain operations or caused us to incur significant additional expenses; however, we are unable to predict the magnitude or duration of current and potential future COVID-19 mitigation measures. As an essential business providing critical energy infrastructure, the safety of our employees and the continued operation of our assets are our top priorities and we will continue to operate in accordance with federal and state health guidelines and safety protocols. We have implemented several new policies and provided employee training to help maintain the health and safety of our workforce.

Pending Enable Acquisition

On February 17, 2021, the Partnership announced its entry into a definitive merger agreement to acquire Enable. Under the terms of the merger agreement, Enable’s common unitholders will receive 0.8595 of an ET common unit in exchange for each Enable common unit. In addition, each outstanding Enable Series A preferred unit will be exchanged for 0.0265 of an ET Series G preferred unit, and ET will make a $10 million cash payment for Enable’s general partner. The transaction is subject to the approval of Enable’s unitholders and other customary regulatory approvals.

ET Contribution of SemGroup Assets to ETO

On December 5, 2019, ET completed the acquisition of SemGroup. During the first and second quarters of 2020, ET contributed former SemGroup assets to ETO through sale and contribution transactions.

ETO Series F and Series G Preferred Units Issuance

On January 22, 2020, ETO issued 500,000 of its 6.750% Series F Preferred Units at a price of $1,000 per unit and 1,100,000 of its 7.125% Series G Preferred Units at a price of $1,000 per unit. The net proceeds were used to repay amounts outstanding under ETO’s revolving credit facility and for general partnership purposes.

ETO January 2020 Senior Notes Offering and Redemption

Utilizing proceeds from the January 2020 Senior Notes Offering, ETO redeemed its $400 million aggregate principal amount of 5.75% Senior Notes due September 1, 2020, its $1.05 billion aggregate principal amount of 4.15% Senior Notes due October 1, 2020, its $1.14 billion aggregate principal amount of 7.50% Senior Notes due October 15, 2020, its $250 million aggregate principal amount of 5.50% Senior Notes due February 15, 2020, ET’s $52 million aggregate principal amount of 7.50% Senior Notes due October 15, 2020 and Transwestern’s

 

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$175 million aggregate principal amount of 5.36% Senior Notes due December 9, 2020. See “Liquidity and Capital Resources—Recent Financing Transactions” below for more information on the January 2020 Senior Notes Offering.

Lake Charles LNG

On March 30, 2020, Shell announced that it would not proceed with a proposed equity interest in the Lake Charles LNG liquefaction project due to adverse market factors affecting Shell’s business following the onset of the COVID-19 pandemic. We intend to continue to develop the project, possibly in conjunction with one or more equity partners, and we plan to evaluate a variety of alternatives to advance the project, including the possibility of reducing the size of the project from three trains (16.45 million tonnes per annum of LNG capacity) to two trains (11.0 million tonnes per annum). The project as currently designed is fully permitted by federal, state and local authorities, has all necessary export licenses and benefits from the infrastructure related to the existing regasification facility at the same site, including four LNG storage tanks, two deep water docks and other assets. In light of the existing brownfield infrastructure and the advanced state of the development of the project, we plan to continue to pursue the project on a disciplined, cost effective basis, and ultimately we will determine whether to make a final investment decision to proceed with the project based on market conditions, capital expenditure considerations and our success in securing equity participation by third parties as well as long-term LNG offtake commitments on satisfactory terms.

Sunoco LP November 2020 Senior Notes Offering and Repurchase

On November 9, 2020, Sunoco LP completed a private offering of $800 million in aggregate principal amount of 4.500% senior notes due 2029. Sunoco LP used the proceeds to fund the tender offer on its 4.875% $1 billion senior notes due 2023. Approximately 56% of the 2023 senior notes were tendered. On January 15, 2021, Sunoco LP repurchased the remaining outstanding portion of its 2023 senior notes.

Regulatory Update

Interstate Natural Gas Transportation Regulation

Rate Regulation

Effective January 2018, the 2017 Tax Cuts and Jobs Act (the “Tax Act”) changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. On March 15, 2018, in a set of related proposals, the FERC addressed treatment of federal income tax allowances in regulated entity rates. The FERC issued a Revised Policy Statement on Treatment of Income Taxes (“Revised Policy Statement”) stating that it will no longer permit master limited partnerships to recover an income tax allowance in their cost-of-service rates. The FERC issued the Revised Policy Statement in response to a remand from the United States Court of Appeals for the District of Columbia Circuit in United Airlines v. FERC, in which the court determined that the FERC had not justified its conclusion that a pipeline organized as a master limited partnership would not “double recover” its taxes under the current policy by both including an income-tax allowance in its cost of service and earning a return on equity calculated using the discounted cash flow methodology. On July 18, 2018, the FERC issued an order denying requests for rehearing and clarification of its Revised Policy Statement. In the rehearing order, the FERC clarified that a pipeline organized as a master limited partnership will not be precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double-recovery of investors’ income tax costs. On July 31, 2020, the United States Court of Appeals for the District of Columbia Circuit issued an opinion upholding the FERC’s decision denying a separate master limited partnership recovery of an income tax allowance and its decision not to require the master limited partnership to refund accumulated deferred income tax balances. In light of the rehearing order’s clarification regarding individual entities’ ability to argue in support of recovery of an income tax allowance and the court’s subsequent opinion upholding denial of an income tax allowance to a master limited partnership, the impacts that FERC’s policy on the treatment of

 

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income taxes may have on the rates ETO can charge for FERC-regulated transportation services are unknown at this time.

Even without application of the FERC’s recent rate making-related policy statements and rulemakings, the FERC or our shippers may challenge the cost-of-service rates we charge. The FERC’s establishment of a just and reasonable rate is based on many components, including ROE and tax-related components, although changes in these components may tend to decrease our cost-of-service rate, other components in the cost-of-service rate calculation may increase and result in a newly calculated cost-of-service rate that is less than, the same as, or greater than the prior cost-of-service rate. Moreover, we receive revenues from our pipelines based on a variety of rate structures, including cost-of-service rates, negotiated rates, discounted rates and market-based rates. Many of our interstate pipelines, such as ETC Tiger Pipeline, LLC, Midcontinent Express and Fayetteville Express, have negotiated market rates that were agreed to by customers in connection with long-term contracts entered into to support the construction of the pipelines. Other systems, such as FGT, Transwestern and Panhandle, have a mix of tariff rate, discount rate, and negotiated rate agreements. The revenues we receive from natural gas transportation services we provide pursuant to cost-of-service based rates may decrease in the future as a result of the Revised Policy Statement, changes to ROE methodology, or other FERC policies, combined with the reduced corporate federal income tax rate established in the Tax Act. The extent of any revenue reduction related to our cost-of-service rates, if any, will depend on a detailed review of all of ETO’s cost-of-service components and the outcomes of any challenges to our rates by the FERC or our shippers.

On July 18, 2018, the FERC issued a final rule establishing procedures to evaluate rates charged by the FERC-jurisdictional gas pipelines in light of the Tax Act and the FERC’s Revised Policy Statement. By order issued January 16, 2019, the FERC initiated a review of Panhandle’s existing rates pursuant to Section 5 of the NGA to determine whether the rates currently charged by Panhandle are just and reasonable and set the matter for hearing. Panhandle filed a cost and revenue study on April 1, 2019 and an NGA Section 4 rate case on August 30, 2019. The Section 4 and Section 5 proceedings were consolidated by order of the Chief Judge on October 1, 2019. A hearing in the combined proceedings commenced on August 25, 2020 and adjourned on September 15, 2020. By order dated January 19, 2021, the Chief Judge has extended the deadline for the initial decision to March 26, 2021.

Pipeline Certification

The FERC issued a Notice of Inquiry on April 19, 2018 (“Pipeline Certification NOI”), thereby initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. We are unable to predict what, if any, changes may be proposed as a result of the Pipeline Certification NOI that will affect our natural gas pipeline business or when such proposals, if any, might become effective. Comments in response to the Pipeline Certification NOI were due on or before July 25, 2018. We do not expect that any change in this policy would affect us in a materially different manner than any other natural gas pipeline company operating in the United States.

Interstate Common Carrier Regulation

The FERC utilizes an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods, or PPI-FG. Many existing pipelines utilize the FERC liquids index to change transportation rates annually. The indexing methodology is applicable to existing rates, with the exclusion of market-based rates. The FERC’s indexing methodology is subject to review every five years. In a December 2020 order, FERC determined that during the five-year period commencing July 1, 2021 and ending June 30, 2026, common carriers charging indexed rates will be permitted to adjust their indexed ceilings annually by PPI-FG plus 0.78 percent. Requests for rehearing of the December 2020 order were filed on January 19, 2021, and remain pending before FERC. Accordingly, the FERC’s final determination of the index rate coupled with the

 

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anticipated and subsequent appeals of the December 2020 order could adversely impact the final determination of the FERC approved index.

FERC has also implemented changes related to its treatment of federal income taxes. The change in treatment impacts two rate components. Those components are the allowance for income taxes and the amount for accumulated deferred income taxes. These changes will primarily impact any cost-of-service related filing and our revenues associated with any cost-based service could be adversely affected by future FERC or judicial rulings. However, we believe that these impacts, if any, will be minimal.

Trends and Outlook

Recent market disruptions involving the COVID-19 pandemic have negatively impacted our earnings and cash flows from operations and may continue to do so. Reduced demand for natural gas, NGLs, refined products and/or crude oil caused by the COVID-19 pandemic and low WTI crude oil prices may result in the continued shut-in of production from U.S. oil and gas wells, which in turn may result in decreased volumes transported on our pipeline systems and decreased overall utilization of our midstream services.

With respect to commodity prices, natural gas prices have strengthened in recent months as a reduction in crude oil production has led to decreased supplies of associated natural gas from these wells. Meanwhile, crude oil prices saw a sharp decline as a result of actions by foreign oil-producing nations and a decrease in global demand as result of the COVID-19 pandemic but have subsequently risen and stabilized. We cannot predict the future impacts, or the duration of such impacts, from the COVID-19 pandemic.

The outlook for commodity prices is mixed and could have a varying impact on our business. Reduced demand and increased supply of crude oil has resulted in an increase in worldwide crude oil storage inventories, which is expected to keep crude oil prices depressed for the near term. With respect to natural gas markets, a relatively more moderate decrease in demand, coupled with the previously mentioned decreases in gas production associated with wells drilled to produce crude oil, have more than counterbalanced the reduction in demand. The overall outlook for our midstream services will depend, in part, on the timing and extent of recovery in the commodity markets.

While we anticipate that current and projected commodity prices and the related impact to activity levels in both the upstream and midstream sectors will impact our business, we cannot predict the ultimate magnitude of that impact and expect it to be varied across our operations, depending on the region, customer, type of service, contract term and other factors.

While the vast majority of our counterparties are investment grade rated companies, recent market disruptions increased the likelihood that some of our counterparties may be forced to file for bankruptcy protection. However, we believe that the recent increases in commodity prices, along with recent expense-cutting initiatives by many companies, have generally strengthened the credit profile for the majority of our producer counterparties.

Ultimately, the extent to which our business will be impacted by recent market developments depends on the factors described above as well as future developments beyond our control, which are highly uncertain and cannot be predicted. In response to these market events and uncertainties, we reduced 2020 growth capital spending, and we expect to continue to a lower level of growth capital spending going forward. See “Liquidity and Capital Resources” below for additional information on our forecasted capital expenditures. In 2020, we also reduced operating expenses, and we expect that our operating expenses going forward will continue to be lower relative to pre-2020 levels. While current market volatility makes the near-term unpredictable, we believe that overall the long-term demand for our services will continue given the essential nature of the midstream natural gas, NGLs, refined products and crude oil businesses, although we cannot predict any possible changes in such demand with reasonable certainty.

 

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We currently have ample liquidity to fund our business and we do not anticipate any liquidity concerns in the immediate future (see “Liquidity and Capital Resources” below). In addition, while the trading price of ET common units declined significantly during the first nine months of 2020, thereby making equity capital market transactions less attractive in the near term, we continue to have access to the debt capital markets on generally favorable terms. In the event we seek additional equity or debt capital, our blended cost of capital for equity and debt is expected to be modestly higher in the near term; however, we will continue to evaluate growth projects and acquisitions as such opportunities may be identified in the future in light of this higher cost of capital.

In addition to the trends and outlook discussed above with respect to the Partnership’s existing business and finances, we also anticipate that the Partnership will continue to increase its focus on the development of alternative energy projects aimed at continuing to reduce its environmental footprint throughout its operations. In February 2021, the Partnership announced the creation of a new group focused on these efforts. The Partnership also recently announced its first-ever dedicated solar power contract, which will reduce the Partnership’s environmental footprint by integrating alternative energy sources when economically beneficial.

Results of Operations

We report Segment Adjusted EBITDA and consolidated Adjusted EBITDA as measures of segment performance. We define Segment Adjusted EBITDA and consolidated Adjusted EBITDA as total Partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Segment Adjusted EBITDA and consolidated Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA and consolidated Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. The use of Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.

Segment Adjusted EBITDA, as reported for each segment in the table below, is analyzed for each segment in the section titled “Segment Operating Results.” Adjusted EBITDA is a non-GAAP measure used by industry analysts, investors, lenders and rating agencies to assess the financial performance and the operating results of the Partnership’s fundamental business activities and should not be considered in isolation or as a substitution for net income, income from operations, cash flows from operating activities or other GAAP measures.

As discussed in Note 2 to the consolidated financial statements in “Item 8. Financial Statements and Supplementary Data” the Partnership’s consolidated financial statements for all periods presented have been retrospectively adjusted to reflect the change in the accounting policy related to certain barrels of crude oil.

 

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Year Ended December 31, 2020 Compared to the Year Ended December 31, 2019

Consolidated Results

 

     Years Ended December 31,         
         2020              2019          Change  

Segment Adjusted EBITDA:

        

Intrastate transportation and storage

   $ 863    $ 999    $ (136

Interstate transportation and storage

     1,680      1,792      (112

Midstream

     1,670      1,602      68

NGL and refined products transportation and services

     2,802      2,666      136

Crude oil transportation and services

     2,258      2,898      (640

Investment in Sunoco LP

     739      665      74

Investment in USAC

     414      420      (6

All other

     105      98      7
  

 

 

    

 

 

    

 

 

 

Total Segment Adjusted EBITDA

     10,531      11,140      (609

Depreciation, depletion and amortization

     (3,678      (3,147      (531

Interest expense, net of interest capitalized

     (2,327      (2,331      4

Impairment losses

     (2,880      (74      (2,806

Losses on interest rate derivatives

     (203      (241      38

Non-cash compensation expense

     (121      (113      (8

Unrealized losses on commodity risk management activities

     (71      (5      (66

Inventory valuation adjustments

     (82      79      (161

Losses on extinguishments of debt

     (75      (18      (57

Adjusted EBITDA related to unconsolidated affiliates

     (628      (626      (2

Equity in earnings of unconsolidated affiliates

     119      302      (183

Impairment of investments in unconsolidated affiliates

     (129      —          (129

Other, net

     (79      54      (133
  

 

 

    

 

 

    

 

 

 

Income before income tax expense

     377      5,020      (4,643

Income tax expense

     (237      (195      (42
  

 

 

    

 

 

    

 

 

 

Net income

   $ 140    $ 4,825    $ (4,685
  

 

 

    

 

 

    

 

 

 

Adjusted EBITDA (consolidated). For the year ended December 31, 2020 compared to the prior year, Adjusted EBITDA decreased 5.5%, primarily due to the impacts of lower volumes and market prices among several of our core operating segments resulting primarily from COVID-19 related demand reductions. These decreases were partially offset by an increase of $136 million from our NGL and refined products transportation and services segment primarily due to higher throughput volumes, an increase of $68 million from our midstream segment primarily due to the restructuring and assignment of certain gathering and processing contracts, and an increase of $74 million from our investment in Sunoco LP segment primarily due to increased gross profit per gallon sold and a decrease in operating costs. The decrease in Adjusted EBITDA was also offset by a net increase of approximately $569 million from recent acquisitions and assets placed in service.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased primarily due to additional depreciation from assets recently placed in service and recent acquisitions.

 

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Interest Expense, Net of Interest Capitalized. Interest expense, net of interest capitalized, decreased primarily due to the following:

 

   

interest expenses recognized by the Partnership (excluding Sunoco LP and USAC) decreased by $8 million due to lower borrowing costs on both recently refinanced and floating rate debt, and higher capitalized interest offsetting a higher consolidated debt balance;

 

   

an increase of $2 million recognized by USAC was primarily due to a full year of interest expense incurred in the current period on its senior notes 2027 issued in March 2019, partially offset by reduced borrowings and lower weighted average interest rates under its credit agreement; and

 

   

an increase of $2 million recognized by Sunoco LP due to a slight increase in average long-term debt.

Impairment Losses. During the year ended December 31, 2020, the Partnership recognized goodwill impairments totaling $2.2 billion and fixed asset impairments totaling $58 million, primarily due to decreases in projected future cash flows as a result of overall market demand decline. In addition, USAC recognized a goodwill impairment of $619 million as well as an equipment impairment of $8 million based on changes in market conditions.

During the year ended December 31, 2019, the Partnership recognized goodwill impairments totaling $21 million primarily due to changes in assumptions related to projected future revenues and cash flows. Also during the year ended December 31, 2019, Sunoco LP recognized a $47 million write-down on assets held for sale related to its ethanol plant in Fulton, New York, and USAC recognized a $6 million fixed asset impairment related to certain idle compressor assets.

Losses on Interest Rate Derivatives. Our interest rate derivatives are not designated as hedges for accounting purposes; therefore, changes in fair value are recorded in earnings each period. Losses on interest rate derivatives decreased by $38 million during the year ended December 31, 2020, compared to the prior year primarily due to a $400 million reduction in notional amount of outstanding forward-starting interest rate derivatives, which was partially offset by lower average interest rates and expenses related to the early termination and settlement of forward-starting interest rate derivatives.

Unrealized Gains (Losses) on Commodity Risk Management Activities. The unrealized gains and losses on our commodity risk management activities include changes in fair value of commodity derivatives and the hedged inventory included in designated fair value hedging relationships. Information on the unrealized gains and losses within each segment are included in “Segment Operating Results” below, and additional information on the commodity-related derivatives, including notional volumes, maturities and fair values, is available in “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and in Note 14 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”

Inventory Valuation Adjustments. Inventory valuation reserve adjustments were recorded for the inventory associated with Sunoco LP primarily driven by changes in fuel prices between periods.

Losses on Extinguishments of Debt. Year ended December 31, 2020 amounts were related to ETO Senior Note redemption in January 2020. In addition, Sunoco LP recognized a $13 million loss on extinguishment of debt related to the repurchase of its outstanding 2023 senior notes in 2020.

Impairment of Investments in Unconsolidated Affiliate. During the year ended December 31, 2020, the Partnership recorded an impairment to its investment in White Cliffs of $129 million due to a decrease in projected future revenues and cash flows as a result of the overall market demand decline that occurred subsequent to the SemGroup acquisition and related purchase price allocation in December 2019.

Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of Unconsolidated Affiliates. See additional information in “Supplemental Information on Unconsolidated Affiliates” and “Segment Operation Results” below.

 

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Other, net. Other, net primarily includes amortization of regulatory assets and other income and expense amounts.

Income Tax Expense. For the year ended December 31, 2020 compared to the same period in the prior year, income tax expense increased due to higher earnings from the Partnership’s consolidated corporate subsidiaries in 2020 and the impact of a current state tax benefit (net of federal benefit) of $17 million in the prior year, which was primarily due to a change in estimate related to state income taxes in 2019.

Supplemental Information on Unconsolidated Affiliates

The following table presents financial information related to unconsolidated affiliates:

 

     Years Ended December 31,         
         2020              2019          Change  

Equity in earnings (losses) of unconsolidated affiliates:

        

Citrus

   $ 162    $ 148    $ 14

FEP(1)

     (139      59      (198

MEP

     (6      15      (21

White Cliffs

     20      4      16

Other

     82      76      6
  

 

 

    

 

 

    

 

 

 

Total equity in earnings of unconsolidated affiliates

   $ 119    $ 302    $ (183
  

 

 

    

 

 

    

 

 

 

Adjusted EBITDA related to unconsolidated affiliates(2):

        

Citrus

   $ 347    $ 342    $ 5

FEP

     76      75      1

MEP

     28      60      (32

White Cliffs

     44      —          44

Other

     133      149      (16
  

 

 

    

 

 

    

 

 

 

Total Adjusted EBITDA related to unconsolidated affiliates

   $ 628    $ 626    $ 2
  

 

 

    

 

 

    

 

 

 

Distributions received from unconsolidated affiliates:

        

Citrus

   $ 191    $ 178    $ 13

FEP

     75      73      2

MEP

     26      36      (10

White Cliffs

     29      —          29

Other

     85      101      (16
  

 

 

    

 

 

    

 

 

 

Total distributions received from unconsolidated affiliates

   $ 406    $ 388    $ 18
  

 

 

    

 

 

    

 

 

 

 

(1)

For the year ended December 31, 2020, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by FEP, which reduced the Partnership’s equity in earnings by $208 million.

(2)

These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, depletion, amortization, non-cash items and taxes.

 

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Segment Operating Results

We evaluate segment performance based on Segment Adjusted EBITDA, which we believe is an important performance measure of the core profitability of our operations. This measure represents the basis of our internal financial reporting and is one of the performance measures used by senior management in deciding how to allocate capital resources among business segments.

The tables below identify the components of Segment Adjusted EBITDA, which is calculated as follows:

 

   

Segment margin, operating expenses, and selling, general and administrative expenses. These amounts represent the amounts included in our consolidated financial statements that are attributable to each segment.

 

   

Unrealized gains or losses on commodity risk management activities and inventory valuation adjustments. These are the unrealized amounts that are included in cost of products sold to calculate segment margin. These amounts are not included in Segment Adjusted EBITDA; therefore, the unrealized losses are added back and the unrealized gains are subtracted to calculate the segment measure.

 

   

Non-cash compensation expense. These amounts represent the total non-cash compensation recorded in operating expenses and selling, general and administrative expenses. This expense is not included in Segment Adjusted EBITDA and therefore is added back to calculate the segment measure.

 

   

Adjusted EBITDA related to unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates.

In the following analysis of segment operating results, a measure of segment margin is reported for segments with sales revenues. Segment margin is a non-GAAP financial measure and is presented herein to assist in the analysis of segment operating results and particularly to facilitate an understanding of the impacts that changes in sales revenues have on the segment performance measure of Segment Adjusted EBITDA. Segment margin is similar to the GAAP measure of gross margin, except that segment margin excludes charges for depreciation, depletion and amortization. Among the GAAP measures reported by the Partnership, the most directly comparable measure to segment margin is Segment Adjusted EBITDA; a reconciliation of segment margin to Segment Adjusted EBITDA is included in the following tables for each segment where segment margin is presented.

In addition, for certain segments, the sections below include information on the components of segment margin by sales type, which components are included in order to provide additional disaggregated information to facilitate the analysis of segment margin and Segment Adjusted EBITDA. For example, these components include transportation margin, storage margin, and other margin. These components of segment margin are calculated consistent with the calculation of segment margin; therefore, these components also exclude charges for depreciation, depletion and amortization.

For additional information regarding our business segments, see “Item 1. Business” and Notes 1 and 16 to our consolidated financial statements in “Item 8. Financial Statements and Supplementary Data.”

 

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Segment Operating Results

Intrastate Transportation and Storage

 

     Years Ended December 31,         
         2020              2019          Change  

Natural gas transported (BBtu/d)

     12,649      12,442      207

Revenues

   $ 2,544    $ 3,099    $ (555

Cost of products sold

     1,478      1,909      (431
  

 

 

    

 

 

    

 

 

 

Segment margin

     1,066      1,190      (124

Unrealized (gains) losses on commodity risk management activities

     (25      2      (27

Operating expenses, excluding non-cash compensation expense

     (177      (190      13

Selling, general and administrative expenses, excluding non-cash compensation expense

     (28      (29      1

Adjusted EBITDA related to unconsolidated affiliates

     25      25      —    

Other

     2      1      1
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 863    $ 999    $ (136
  

 

 

    

 

 

    

 

 

 

Volumes. For the year ended December 31, 2020 compared to the prior year, transported volumes increased primarily due to increased utilization of our Texas pipelines, partially offset by a decrease in volumes as a result of the bankruptcy filing of a transportation customer.

Segment Margin. The components of our intrastate transportation and storage segment margin were as follows:

 

     Years Ended December 31,         
         2020              2019          Change  

Transportation fees

   $ 617    $ 614    $ 3

Natural gas sales and other (excluding unrealized gains and losses)

     317      505      (188

Retained fuel revenues (excluding unrealized gains and losses)

     48      50      (2

Storage margin, including fees (excluding unrealized gains and losses)

     59      23      36

Unrealized gains (losses) on commodity risk management activities

     25      (2      27
  

 

 

    

 

 

    

 

 

 

Total segment margin

   $ 1,066    $ 1,190    $ (124
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA. For the year ended December 31, 2020 compared to the prior year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment decreased due to the net impacts of the following:

 

   

a decrease of $188 million in realized natural gas sales and other due to lower realized gains from pipeline optimization activity; and

 

   

a decrease of $2 million in retained fuel revenues primarily due to lower natural gas prices; offset by

 

   

an increase of $36 million in realized storage margin primarily due to higher realized gains on financial derivatives used to hedge physical storage gas;

 

   

a decrease of $13 million in operating expenses primarily due to a $5 million decrease in outside services, a $4 million decrease in employee costs, a $3 million decrease in maintenance project costs and a $2 million decrease in ad valorem taxes; and

 

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an increase of $3 million in transportation fees primarily due to volume ramp-ups on Red Bluff Express pipeline and new contracts partially offset by the expansion of certain contracts on Regency Intrastate Gas Systems,

Interstate Transportation and Storage

 

     Years Ended December 31,         
         2020              2019          Change  

Natural gas transported (BBtu/d)

     10,325      11,346      (1,021

Natural gas sold (BBtu/d)

     16      17      (1

Revenues

   $ 1,861    $ 1,963    $ (102

Operating expenses, excluding non-cash compensation, amortization and accretion expenses

     (567      (569      2

Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses

     (59      (72      13

Adjusted EBITDA related to unconsolidated affiliates

     451      477      (26

Other

     (6      (7      1
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 1,680    $ 1,792    $ (112
  

 

 

    

 

 

    

 

 

 

Volumes. For the year ended December 31, 2020 compared to the prior year, transported volumes decreased primarily due to lower crude production resulting in lower associated gas production and contract expirations on our Tiger Pipeline, as well as multiple weather events and maintenance of third-party facilities impacting our assets along the Gulf Coast.

Segment Adjusted EBITDA. For the year ended December 31, 2020 compared to the prior year, Segment Adjusted EBITDA related to our interstate transportation and storage segment decreased due to the net impacts of the following:

 

   

a decrease of $102 million in revenues primarily due to a decrease of $63 million from a contractual rate adjustment on commitments at our Lake Charles LNG facility effective January 2020, a decrease of $30 million due to additional revenue recognized in 2019 associated with a shipper bankruptcy, a decrease of $28 million due to lower utilization and lower rates on our Panhandle and Trunkline systems, a decrease of $12 million in transportation fees as a result of multiple weather events and maintenance on third-party facilities connected to our systems, and a decrease of $8 million resulting from contract expirations on ETC Tiger. These decreases were partially offset by higher reservation revenue on Transwestern and Rover resulting from higher contracted capacity and higher parking revenue resulting from timing of transactions; and

 

   

a decrease of $26 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to lower earnings from our Midcontinent Express Pipeline primarily as a result of lower rates received following the expiration of certain contracts, partially offset by an increase from Citrus primarily due to higher revenues resulting from new contracts, rate increases on existing contracts, the recognition of a contract exit fee and lower operating expenses; partially offset by

 

   

a decrease of $2 million in operating expense primarily due to $22 million in refunds of ad valorem taxes on Transwestern and lower current year assessments, a $13 million decrease in employee costs and a $9 million decrease in maintenance project costs resulting from cost-cutting initiatives, partially offset by $38 million in bad debt expense associated with a shipper bankruptcy and a $5 million increase related to the valuation of inventory on Panhandle; and

 

   

a decrease of $13 million in selling, general and administrative expenses primarily resulting from a $17 million favorable settlement related to excise taxes on Rover and a $5 million decrease in employee

 

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costs due to cost-cutting initiatives, partially offset by a $4 million increase in legal and consulting fees related to an ongoing rate case and shipper bankruptcies and a $3 million increase in allocated overhead costs.

Midstream

 

     Years Ended December 31,         
         2020              2019          Change  

Gathered volumes (BBtu/d)

     12,961      13,468      (507

NGLs produced (MBbls/d)

     611      571      40

Equity NGLs (MBbls/d)

     35      31      4

Revenues

   $ 5,026    $ 6,031    $ (1,005

Cost of products sold

     2,598      3,577      (979
  

 

 

    

 

 

    

 

 

 

Segment margin

     2,428      2,454      (26

Operating expenses, excluding non-cash compensation expense

     (705      (791      86

Selling, general and administrative expenses, excluding non-cash compensation expense

     (87      (90      3

Adjusted EBITDA related to unconsolidated affiliates

     31      27      4

Other

     3      2      1
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 1,670    $ 1,602    $ 68
  

 

 

    

 

 

    

 

 

 

Volumes. For the year ended December 31, 2020 compared to the prior year, gathered volumes decreased primarily in the South Texas and Northeast regions, partially offset by the impact of the SemGroup acquisition in the Mid-Continent/Panhandle region and volume growth in the Ark-La-Tex and Permian regions. NGL production increased due to the impact of the SemGroup acquisition in the Mid-Continent/Panhandle region and ethane uplift in the Permian, South Texas and North Texas regions.

Segment Margin. The table below presents the components of our midstream segment margin.

 

     Years Ended December 31,         
         2020              2019          Change  

Gathering and processing fee-based revenues

   $ 2,187    $ 2,132    $ 55

Non-fee-based contracts and processing

     241      322      (81
  

 

 

    

 

 

    

 

 

 

Total segment margin

   $ 2,428    $ 2,454    $ (26
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA. For the year ended December 31, 2020 compared to the prior year, Segment Adjusted EBITDA related to our midstream segment increased due to the net impacts of the following:

 

   

an increase of $55 million in fee-based margin due to the impact of the SemGroup acquisition in the Mid-Continent/Panhandle region and recognized $103 million related to the restructuring and assignment of certain gathering and processing contracts in the Ark-La-Tex region, which included the recognition of $75 million of deferred revenue received in prior periods. This increase was partially offset by the impact of volume declines in the South Texas region;

 

   

a decrease of $86 million in operating expenses due to cost-saving initiatives, including a decrease of $39 million in outside services, $25 million in materials, $14 million in employee costs and $8 million in office expenses; and

 

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a decrease of $3 million in selling, general and administrative expenses due to a decrease in allocated overhead costs resulting from overall corporate cost reductions; partially offset by

 

   

a decrease of $70 million in non-fee-based margin due to unfavorable NGL prices of $75 million and favorable natural gas prices of $5 million; and

 

   

a decrease of $11 million in non-fee-based margin due to decreased throughput volume, primarily in the South Texas region.

NGL and Refined Products Transportation and Services

 

     Years Ended December 31,         
         2020              2019          Change  

NGL transportation volumes (MBbls/d)

     1,436      1,289      147

Refined products transportation volumes (MBbls/d)

     461      583      (122

NGL and refined products terminal volumes (MBbls/d)

     825      844      (19

NGL fractionation volumes (MBbls/d)

     835      706      129

Revenues

   $ 10,513    $ 11,641    $ (1,128

Cost of products sold

     7,139      8,393      (1,254
  

 

 

    

 

 

    

 

 

 

Segment margin

     3,374      3,248      126

Unrealized losses on commodity risk management activities

     78      81      (3

Operating expenses, excluding non-cash compensation expense

     (650      (656      6

Selling, general and administrative expenses, excluding non-cash compensation expense

     (82      (93      11

Adjusted EBITDA related to unconsolidated affiliates

     82      86      (4
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 2,802    $ 2,666    $ 136
  

 

 

    

 

 

    

 

 

 

Volumes. For the year ended December 31, 2020 compared to the prior year, NGL transportation volumes increased due to higher throughput volumes on our Mariner East pipeline system. In addition, throughput barrels on our Texas NGL pipeline system increased due to higher receipt of liquids production from both wholly-owned and third-party gas plants primarily in the Permian and North Texas regions, as well as higher export volumes feeding into our Nederland Terminal resulting from the initiation of service on our propane export pipeline in the fourth quarter of 2020.

Refined products transportation volumes decreased for the year ended December 31, 2020 compared to prior year due to the closure of a third-party refinery during the third quarter of 2019, which negatively impacted supply to our refined products transportation system, and less domestic demand for jet fuel and other refined products. These decreases in volumes were partially offset by the initiation of service of our JC Nolan diesel fuel pipeline in the third quarter of 2019.

NGL and refined products terminal volumes decreased for the year ended December 31, 2020 compared to the prior year primarily due to the closure of a third-party refinery during the third quarter of 2019 and less domestic demand for jet fuel and other refined products. These decreases were partially offset by higher volumes from our Mariner East system, an increase in loaded vessels at our Nederland Terminal, and the initiation of service on our JC Nolan diesel fuel pipeline and natural gasoline export project, both of which commences service in the third quarter of 2019.

 

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Average fractionated volumes at our Mont Belvieu, Texas fractionation facility increased for the year ended December 31, 2020 compared to the prior year primarily due to the commissioning of our sixth and seventh fractionators in February 2019 and February 2020, respectively.

Segment Margin. The components of our NGL and refined products transportation and services segment margin were as follows:

 

     Years Ended December 31,         
         2020              2019          Change  

Fractionators and refinery services margin

   $ 726    $ 664    $ 62

Transportation margin

     1,895      1,716      179

Storage margin

     250      223      27

Terminal Services margin

     541      630      (89

Marketing margin

     40      96      (56

Unrealized gains on commodity risk management activities

     (78      (81      3
  

 

 

    

 

 

    

 

 

 

Total segment margin

   $ 3,374    $ 3,248    $ 126
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA. For the year ended December 31, 2020 compared to the prior year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impacts of the following:

 

   

an increase of $179 million in transportation margin primarily due to a $128 million increase from higher throughput volumes on our Mariner East pipeline system, a $53 million increase from higher throughput volumes received from the Permian region, a $17 million increase due to the initiation of service on our JC Nolan diesel fuel pipeline in the third quarter of 2019, a $14 million increase from higher throughput volumes from the Barnett region, a $12 million increase from higher volumes from the South Texas region and a $3 million increase due to higher throughput on our Mariner West pipeline. These increases were partially offset by a $17 million decrease from lower throughput volumes received from the Eagle Ford region, a $16 million decrease due to less demand for jet fuel and other refined products, and a $13 million decrease resulting from the closure of a third-party refinery during the third quarter of 2019;

 

   

an increase of $62 million in fractionators and refinery services margin primarily due to a $57 million increase resulting from the commissioning of our sixth and seventh fractionators in February 2019 and February 2020, respectively, and higher NGL volumes from the Permian and Barnett regions feeding our Mont Belvieu fractionation facility, and a $9 million increase in rail and truck volumes feeding our refinery services facility. These increases were partially offset by a $7 million decrease due primarily to an expiration of a third-party blending contract during the second quarter of 2020;

 

   

an increase of $27 million in storage margin primarily due to a $16 million increase from throughput fees generated from exported volumes and an $11 million increase from component product storage fees; and

 

   

a decrease of $11 million in selling, general and administrative expenses primarily due to lower allocated overhead costs and lower employee costs resulting from cost-cutting initiatives; partially offset by

 

   

a decrease of $89 million in terminal services margin primarily due to a $90 million decrease resulting from an expiration of a third-party contract at our Nederland Terminal in the second quarter of 2020, a $29 million decrease due to lower third-party and intercompany volumes feeding our Marcus Hook Terminal, a $16 million decrease due to lower expense reimbursements in 2020, and a $14 million decrease due to less domestic demand for jet fuel and other refined products. These decreases were partially offset by a $60 million increase due to higher throughput on our Mariner East system; and

 

   

a decrease of $56 million in marketing margin primarily due to an $87 million decrease due to lower margin from our butane blending business, a $37 million decrease in gasoline blending and optimization due

 

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primarily to unfavorable market conditions primarily attributable to the COVID-19 pandemic. These decreases were partially offset by a $47 million increase due to higher optimization gains from the sale of NGL component products at our Mont Belvieu facility and a $21 million increase in NGL export and rack volumes.

Crude Oil Transportation and Services

 

     Years Ended December 31,         
         2020              2019          Change  

Crude transportation volumes (MBbls/d)

     3,763      4,217      (454

Crude terminals volumes (MBbls/d)

     2,553      2,513      40

Revenue

   $ 11,679    $ 18,447    $ (6,768

Cost of products sold

     8,838      14,832      (5,994
  

 

 

    

 

 

    

 

 

 

Segment margin

     2,841      3,615      (774

Unrealized (gains) losses on commodity risk management activities

     12      (69      81

Operating expenses, excluding non-cash compensation expense

     (526      (570      44

Selling, general and administrative expenses, excluding non-cash compensation expense

     (118      (85      (33

Adjusted EBITDA related to unconsolidated affiliates

     37      8      29

Other

     12      (1      13
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 2,258    $ 2,898    $ (640
  

 

 

    

 

 

    

 

 

 

Volumes. For the year ended December 31, 2020 compared to the prior year, crude transportation volumes were lower on our Texas pipeline system and our Bakken pipeline, driven by lower production in these regions due to lower crude oil prices as well as lower refinery utilization caused by COVID-19 demand destruction, partially offset by contributions from assets acquired in 2019. Crude terminal volumes were higher due to contributions from assets acquired in 2019, partially offset by lower Permian and Bakken pipeline volumes, reduced refinery utilization, and reduced export demand at our Nederland Terminal.

Segment Adjusted EBITDA. For the year ended December 31, 2020 compared to the prior year, Segment Adjusted EBITDA related to our crude oil transportation and services segment decreased due to the net impacts of the following:

 

   

a decrease of $693 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $430 million decrease from our Texas crude pipeline system due to lower utilization and lower average tariff rates realized, a $286 million decrease (excluding a net change of $84 million in unrealized gains and losses on commodity risk management activities) from our crude oil acquisition and marketing business primarily due to a significant contraction in spreads in 2020 as compared to 2019 primarily impacting our Permian to Gulf Coast and Bakken to Gulf Coast trading operations, a $224 million decrease due to lower volumes on our Bakken Pipeline due to lower basin production, and a $35 million decrease in throughput at our crude terminals primarily driven by lower Permian and Bakken volumes, reduced refinery utilization from COVID-19 demand destruction, reduced export demand, and hurricanes impacting operations in the third quarter of 2020; partially offset by a $285 million increase related to assets acquired in 2019; and

 

   

an increase of $33 million in selling, general and administrative expenses primarily due to legal expenses, higher insurance expenses, and an increase related to assets acquired in 2019; partially offset by

 

   

a decrease of $44 million in operating expenses primarily due to lower volume-driven pipeline expenses and corporate cost-cutting initiatives, partially offset by increased costs related to assets acquired in 2019; and

 

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an increase of $29 million in Adjusted EBITDA related to unconsolidated affiliates due to assets acquired in 2019.

Investment in Sunoco LP

 

     Years Ended December 31,         
         2020              2019          Change  

Revenues

   $ 10,710    $ 16,596    $ (5,886

Cost of products sold

     9,654      15,380      (5,726
  

 

 

    

 

 

    

 

 

 

Segment margin

     1,056      1,216      (160

Unrealized (gains) losses on commodity risk management activities

     6      (5      11

Operating expenses, excluding non-cash compensation expense

     (336      (365      29

Selling, general and administrative, excluding non-cash compensation expense

     (98      (123      25

Adjusted EBITDA related to unconsolidated affiliates

     10      4      6

Inventory valuation adjustments

     82      (79      161

Other, net

     19      17      2
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 739    $ 665    $ 74
  

 

 

    

 

 

    

 

 

 

The Investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.

Segment Adjusted EBITDA. For the year ended December 31, 2020 compared to the prior year, Segment Adjusted EBITDA related to the Investment in Sunoco LP segment increased due to the net impacts of the following:

 

   

an increase in the gross profit on motor fuel sales of $32 million, primarily due to a 18% increase in gross profit per gallon sold and the receipt of a $13 million make-up payment under Sunoco LP’s fuel supply agreement with 7-Eleven, Inc., partially offset by a 13% decrease in gallons sold; and

 

   

a decrease in operating expenses and selling, general and administrative expenses, excluding non-cash compensation expense of $54 million, primarily attributable to lower employee costs, maintenance, advertising, credit card fees and utilities, which was partially offset by a $12 million charge for current expected credit losses on Sunoco LP’s accounts receivable in connection with the financial impact from COVID-19; and

 

   

an increase of $6 million in Adjusted EBITDA related to unconsolidated affiliates due to Sunoco LP’s investment in the JC Nolan joint venture; partially offset by

 

   

a decrease of $18 million in non-motor fuel sales and lease gross profit primarily due to reduced credit card transactions related to the COVID-19 pandemic and rent concessions in 2020.

 

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Investment in USAC

 

     Years Ended December 31,         
         2020              2019          Change  

Revenues

   $ 667    $ 698    $ (31

Cost of products sold

     82      91      (9
  

 

 

    

 

 

    

 

 

 

Segment margin

     585      607      (22

Operating expenses, excluding non-cash compensation expense

     (124      (134      10

Selling, general and administrative, excluding non-cash compensation expense

     (51      (53      2

Other, net

     4      —          4
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 414    $ 420    $ (6
  

 

 

    

 

 

    

 

 

 

The investment in USAC segment reflects the consolidated results of USAC.

Segment Adjusted EBITDA. For the year ended December 31, 2020 compared to last year, Segment Adjusted EBITDA related to our investment in USAC segment increased due to the net impacts of the following:

 

   

a decrease of $10 million in operating expenses primarily driven by a decrease in average revenue generating horsepower and reduced headcount; partially offset by

 

   

a decrease of $22 million in segment margin primarily driven by a decrease in revenues primarily due to a decrease in average revenue generating horsepower as a result of a decline in demand for compression services primarily driven by a decrease in U.S. crude oil and natural gas activities and a reduction of ancillary maintenance work, offset by a decrease in costs of products sold of $9 million.

All Other

 

     Years Ended December 31,         
         2020              2019          Change  

Revenue

   $ 1,838    $ 1,689    $ 149

Cost of products sold

     1,527      1,504      23
  

 

 

    

 

 

    

 

 

 

Segment margin

     311      185      126

Unrealized (gains) losses on commodity risk management activities

     1      (4      5

Operating expenses, excluding non-cash compensation expense

     (133      (77      (56

Selling, general and administrative expenses, excluding non-cash compensation expense

     (101      (66      (35

Adjusted EBITDA related to unconsolidated affiliates

     2      2      —    

Other and eliminations

     25      58      (33
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 105    $ 98    $ 7
  

 

 

    

 

 

    

 

 

 

Amounts reflected in our all other segment primarily include:

 

   

our natural gas marketing operations;

 

   

our wholly-owned natural gas compression operations;

 

   

our investment in coal handling facilities.

 

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our Canadian operations, which were acquired in the SemGroup acquisition in December 2019 and include natural gas gathering and processing assets.

Segment Adjusted EBITDA. For the year ended December 31, 2020 compared to the prior year, Segment Adjusted EBITDA increased due to the net impacts of the following:

 

   

an increase of $97 million from the acquisition of Energy Transfer Canada; and

 

   

an increase of $26 million primarily due to insurance proceeds received on settled claims related to our MTBE litigation; partially offset by

 

   

a decrease of $22 million due to lower coal royalties and producer demand from our natural resources business;

 

   

a decrease of $35 million due to lower revenue from our compressor equipment business;

 

   

a decrease of $12 million from adverse market conditions due to COVID-19 related demand destruction;

 

   

a decrease of $28 million due to higher merger and acquisition expenses;

 

   

a decrease of $10 million due to intercompany eliminations; and

 

   

a decrease of $6 million due to the elimination of Sunoco LP’s interest in the JC Nolan Joint Venture.

Year Ended December 31, 2019 Compared to the Year Ended December 31, 2018

Consolidated Results

 

     Years Ended December 31,         
         2019              2018          Change  

Segment Adjusted EBITDA:

        

Intrastate transportation and storage

   $ 999    $ 927    $ 72

Interstate transportation and storage

     1,792      1,680      112

Midstream

     1,602      1,627      (25

NGL and refined products transportation and services

     2,666      1,979      687

Crude oil transportation and services

     2,898      2,385      513

Investment in Sunoco LP

     665      638      27

Investment in USAC

     420      289      131

All other

     98      40      58
  

 

 

    

 

 

    

 

 

 

Total

     11,140      9,565      1,575

Depreciation, depletion and amortization

     (3,147      (2,859      (288

Interest expense, net of interest capitalized

     (2,331      (2,055      (276

Impairment losses

     (74      (431      357

Gains (losses) on interest rate derivatives

     (241      47      (288

Non-cash compensation expense

     (113      (105      (8

Unrealized losses on commodity risk management activities

     (5      (11      6

Inventory valuation adjustments

     79      (85      164

Losses on extinguishments of debt

     (18      (112      94

Adjusted EBITDA related to unconsolidated affiliates

     (626      (655      29

Equity in earnings of unconsolidated affiliates

     302      344      (42

Adjusted EBITDA related to discontinued operations

     —          25      (25

Other, net

     54      21      33
  

 

 

    

 

 

    

 

 

 

 

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     Years Ended December 31,         
         2019              2018          Change  

Income from continuing operations before income tax expense

     5,020      3,689      1,331

Income tax expense from continuing operations

     (195      (4      (191
  

 

 

    

 

 

    

 

 

 

Income from continuing operations

     4,825      3,685      1,140

Loss from discontinued operations, net of income taxes

     —          (265      265
  

 

 

    

 

 

    

 

 

 

Net income

   $ 4,825    $ 3,420    $ 1,405
  

 

 

    

 

 

    

 

 

 

Adjusted EBITDA (consolidated). For the year ended December 31, 2019 compared to the prior year, Adjusted EBITDA increased approximately $1.58 billion, or 16%. The increase was primarily due to the impact of multiple revenue-generating assets being placed in service and recent acquisitions, as well as increased demand for services on existing assets. The impact of new assets and acquisitions was approximately $784 million, of which the largest increases were from increased volumes to our Mariner East pipeline and terminal assets due to the addition of pipeline capacity in the fourth quarter of 2018 (a $274 million impact to the NGL and refined products transportation and services segment), the commissioning of our fifth and sixth fractionators (a $131 million impact to the NGL and refined products transportation and services segment), the ramp up of volumes on our Bayou Bridge system due to placing phase II in service in the second quarter of 2019 (a $60 million impact to our crude oil transportation and services segment), the Rover pipeline (a $78 million impact to the interstate transportation and storage segment), the addition of gas processing capacity to our Arrowhead gas plant (a $31 million impact to our midstream segment), placing our Permian Express 4 pipeline in service in October 2019 (a $26 million impact to our crude oil transportation and services segment) and the acquisition of USAC (a net impact of $131 million among the investment in USAC and all other segments). The remainder of the increase in Adjusted EBITDA was primarily due to stronger demand on existing assets, particularly due to increased throughput on our Bakken Pipeline system as well as increased production in the Permian, which impacted multiple segments. Additional discussion of these and other factors affecting Adjusted EBITDA is included in the analysis of Segment Adjusted EBITDA in the “Segment Operating Results” section below.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased primarily due to additional depreciation and amortization from assets recently placed in service.

Interest Expense, Net of Interest Capitalized. Interest expense, net of interest capitalized, increased primarily due to the following:

 

   

an increase of $198 million recognized by the Partnership (excluding Sunoco LP and USAC, which are discussed below) primarily due to increases in ETO’s long-term debt.

 

   

an increase of $49 million recognized by USAC primarily attributable to higher overall debt balances and higher interest rates on borrowings under the credit agreement. These increases were partially offset by the decrease in borrowings under the credit agreement; and

 

   

an increase of $29 million recognized by Sunoco LP due to an increase in total long-term debt.

Impairment Losses. During the year ended December 31, 2019, the Partnership recognized goodwill impairments of $12 million related to the Southwest Gas operations within the interstate transportation and storage segment and $9 million related to our North Central operations within the midstream segment, both of which were primarily due to changes in assumptions related to projected future revenues and cash flows. Also during the year ended December 31, 2019, Sunoco LP recognized a $47 million write-down on assets held for sale related to its ethanol plant in Fulton, New York, and USAC recognized a $6 million fixed asset impairment related to certain idle compressor assets.

 

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During the year ended December 31, 2018, the Partnership recognized goodwill impairments of $378 million and asset impairments of $4 million related to our midstream operations and asset impairments of $9 million related to idle leased assets in our crude operations. Sunoco LP recognized a $30 million indefinite-lived intangible asset impairment related to contractual rights. USAC recognized a $9 million fixed asset impairment related to certain idle compressor assets. Additional discussion on these impairments is included in “Critical Accounting Estimates” below.

Gains (Losses) on Interest Rate Derivatives. Our interest rate derivatives are not designated as hedges for accounting purposes; therefore, changes in fair value are recorded in earnings each period. Losses on interest rate derivatives during the year ended December 31, 2019 resulted from a decrease in forward interest rates and gains in 2018 resulted from an increase in forward interest rates.

Unrealized Gains (Losses) on Commodity Risk Management Activities. The unrealized losses on our commodity risk management activities include changes in fair value of commodity derivatives and the hedged inventory included in designated fair value hedging relationships. Information on the unrealized gains and losses within each segment are included in “Segment Operating Results” below, and additional information on the commodity-related derivatives, including notional volumes, maturities and fair values, is available in “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and in Note 13 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”

Inventory Valuation Adjustments. Inventory valuation reserve adjustments were recorded for the inventory associated with Sunoco LP primarily driven by changes in fuel prices between periods.

Losses on Extinguishments of Debt. Amounts were related to Sunoco LP’s senior note and term loan redemption in January 2018.

Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of Unconsolidated Affiliates. See additional information in “Supplemental Information on Unconsolidated Affiliates” and “Segment Operation Results” below.

Adjusted EBITDA Related to Discontinued Operations. Amounts were related to the operations of Sunoco LP’s retail business that were disposed of in January 2018.

Other, net. Other, net primarily includes amortization of regulatory assets and other income and expense amounts.

Income Tax Expense. For the year ended December 31, 2019 compared to the prior year, income tax expense increased due to an increase in income at our corporate subsidiaries and the recognition of a favorable state tax rate change in the prior period.

Supplemental Information on Unconsolidated Affiliates

The following table presents financial information related to unconsolidated affiliates:

 

     Years Ended December 31,         
         2019              2018          Change  

Equity in earnings of unconsolidated affiliates:

        

Citrus

   $ 148    $ 141    $ 7

FEP

     59      55      4

MEP

     15      31      (16

White Cliffs

     4      —          4

Other

     76      117      (41
  

 

 

    

 

 

    

 

 

 

Total equity in earnings of unconsolidated affiliates

   $ 302    $ 344    $ (42
  

 

 

    

 

 

    

 

 

 

 

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     Years Ended December 31,         
         2019              2018          Change  

Adjusted EBITDA related to unconsolidated affiliates(1):

        

Citrus

   $ 342    $ 337    $ 5

FEP

     75      74      1

MEP

     60      81      (21

Other

     149      163      (14
  

 

 

    

 

 

    

 

 

 

Total Adjusted EBITDA related to unconsolidated affiliates

   $ 626    $ 655    $ (29
  

 

 

    

 

 

    

 

 

 

Distributions received from unconsolidated affiliates:

        

Citrus

   $ 178    $ 171    $ 7

FEP

     73      68      5

MEP

     36      48      (12

Other

     101      110      (9
  

 

 

    

 

 

    

 

 

 

Total distributions received from unconsolidated affiliates

   $ 388    $ 397    $ (9
  

 

 

    

 

 

    

 

 

 

 

(1)

These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, depletion, amortization, non-cash items and taxes.

Segment Operating Results

Intrastate Transportation and Storage

 

     Years Ended December 31,         
         2019              2018          Change  

Natural gas transported (BBtu/d)

     12,442      10,873      1,569

Revenues

   $ 3,099    $ 3,737    $ (638

Cost of products sold

     1,909      2,665      (756
  

 

 

    

 

 

    

 

 

 

Segment margin

     1,190      1,072      118

Unrealized losses on commodity risk management activities

     2      38      (36

Operating expenses, excluding non-cash compensation expense

     (190      (189      (1

Selling, general and administrative, excluding non-cash compensation expense

     (29      (27      (2

Adjusted EBITDA related to unconsolidated affiliates

     25      32      (7

Other

     1      1      —    
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 999    $ 927    $ 72
  

 

 

    

 

 

    

 

 

 

Volumes. For the year ended December 31, 2019 compared to the prior year, transported volumes increased primarily due to the impact of reflecting RIGS as a consolidated subsidiary beginning April 2018 and the impact of the Red Bluff Express pipeline coming online in May 2018, as well as the impact of favorable market pricing spreads.

 

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Segment Margin. The components of our intrastate transportation and storage segment margin were as follows:

 

     Years Ended December 31,         
         2019              2018          Change  

Transportation fees

   $ 614    $ 525    $ 89

Natural gas sales and other (excluding unrealized gains and losses)

     505      510      (5

Retained fuel revenues (excluding unrealized gains and losses)

     50      59      (9

Storage margin, including fees (excluding unrealized gains and losses)

     23      16      7

Unrealized losses on commodity risk management activities

     (2      (38      36
  

 

 

    

 

 

    

 

 

 

Total segment margin

   $ 1,190    $ 1,072    $ 118
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the prior year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment increased due to the net impacts of the following:

 

   

an increase of $64 million in transportation fees, excluding the impact of consolidating RIGS beginning April 2018 as discussed below, primarily due to the Red Bluff Express pipeline coming online in May 2018, as well as new contracts;

 

   

a net increase of $11 million primarily due to the consolidation of RIGS beginning April 2018, resulting in increases in transportation fees, retained fuel revenues and operating expenses of $24 million, $2 million and $6 million, respectively, partially offset by a decrease in Adjusted EBITDA related to unconsolidated affiliates of $9 million; and

 

   

an increase of $7 million in realized storage margin primarily due to a realized adjustment to the Bammel storage inventory of $25 million in 2018 and higher storage fees, partially offset by a $20 million decrease due to lower physical withdrawals; partially offset by

 

   

a decrease of $9 million in retained fuel revenues primarily due to lower gas prices; and

 

   

a decrease of $5 million in realized natural gas sales and other due to lower realized gains from pipeline optimization activity.

Interstate Transportation and Storage

 

     Years Ended December 31,         
         2019              2018          Change  

Natural gas transported (BBtu/d)

     11,346      9,542      1,804

Natural gas sold (BBtu/d)

     17      17      —    

Revenues

   $ 1,963    $ 1,682    $ 281

Operating expenses, excluding non-cash compensation, amortization and accretion expenses

     (569      (431      (138

Selling, general and administrative, excluding non-cash compensation, amortization and accretion expenses

     (72      (63      (9

Adjusted EBITDA related to unconsolidated affiliates

     477      492      (15

Other

     (7      —          (7
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 1,792    $ 1,680    $ 112
  

 

 

    

 

 

    

 

 

 

 

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Volumes. For the year ended December 31, 2019 compared to the prior year, transported volumes increased as a result of the addition of new contracted volumes for delivery out of the Haynesville Shale, higher volumes on our Rover pipeline as a result of the full year availability of new supply connections, and higher throughput on Trunkline and Panhandle due to increased utilization of higher contracted capacity.

Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the prior year, Segment Adjusted EBITDA related to our interstate transportation and storage segment increased due to the net impacts of the following:

 

   

an increase in margin of $231 million from the Rover pipeline due to higher reservation and usage resulting from additional connections and utilization of additional compression;

 

   

an increase of $40 million in reservation and usage fees due to improved market conditions allowing us to successfully bring new volumes to the system at improved rates, primarily on our Transwestern, Tiger and Panhandle systems; and

 

   

an increase of $6 million from the Sea Robin pipeline due to higher rates resulting from the rate case filed in June 2019, as well as fewer third-party supply interruptions on the Sea Robin system; partially offset by

 

   

an increase of $138 million in operating expense primarily due to an increase in ad valorem taxes of $126 million on the Rover pipeline system resulting from placing the final portions of this asset into service in November 2018, an increase of $24 million in transportation expense on Rover due to an increase in transportation volumes, an increase of $5 million in allocated overhead costs and additional operating expense of $4 million for assets acquired in June 2019, partially offset by lower gas imbalance and system gas activity of $15 million and lower storage capacity leased on the Panhandle system of $8 million;

 

   

an increase of $9 million in selling, general and administrative expenses primarily due to an increase in insurance expense of $8 million, an increase in employee cost of $4 million, and an increase in allocated overhead costs of $3 million, partially offset by lower Ohio excise tax on our Rover system; and

 

   

a decrease of $15 million in adjusted EBITDA related to unconsolidated affiliates primarily resulting from a $20 million decrease due to lower earnings from MEP as a result of lower capacity being re-contracted at lower rates on expiring contracts, partially offset by a $5 million increase from our Citrus joint venture as we brought new volumes to the system in 2019.

Midstream

 

     Years Ended December 31,         
         2019              2018          Change  

Gathered volumes (BBtu/d):

     13,468      12,126      1,342

NGLs produced (MBbls/d):

     571      540      31

Equity NGLs (MBbls/d):

     31      29      2

Revenues

   $ 6,031    $ 7,522    $ (1,491

Cost of products sold

     3,577      5,145      (1,568
  

 

 

    

 

 

    

 

 

 

Segment margin

     2,454      2,377      77

Operating expenses, excluding non-cash compensation expense

     (791      (705      (86

Selling, general and administrative, excluding non-cash compensation expense

     (90      (81      (9

Adjusted EBITDA related to unconsolidated affiliates

     27      33      (6

Other

     2      3      (1
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 1,602    $ 1,627    $ (25
  

 

 

    

 

 

    

 

 

 

 

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Volumes. For the year ended December 31, 2019 compared to the prior year, gathered volumes increased primarily due to increases in the Northeast, Permian, Ark-La-Tex, South Texas and North Texas regions. NGL production increased due to increases in the Permian and North Texas regions partially offset by ethane rejection in the South Texas region.

Segment Margin. The table below presents the components of our midstream segment margin. For the year ended December 31, 2018, the amounts previously reported for fee-based and non-fee-based margin have been adjusted to reflect reclassification of certain contractual minimum fees from fee-based margin to non-fee-based margin in order to conform to the current period classification.

 

     Years Ended December 31,         
         2019              2018          Change  

Gathering and processing fee-based revenues

   $ 2,132    $ 1,855    $ 277

Non-fee-based contracts and processing (excluding unrealized gains and losses)

     322      522      (200
  

 

 

    

 

 

    

 

 

 

Total segment margin

   $ 2,454    $ 2,377    $ 77
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the prior year, Segment Adjusted EBITDA related to our midstream segment decreased due to the net impacts of the following:

 

   

a decrease of $200 million in non-fee-based margin due to lower NGL prices of $183 million and lower gas prices of $50 million, offset by an increase of $33 million in non-fee-based margin due to increased throughput volume in North Texas and Permian regions;

 

   

an increase of $86 million in operating expenses due to increases of $33 million in outside services, $29 million in maintenance project costs, $17 million in employee costs and $6 million in office expenses and materials; and

 

   

an increase of $9 million in selling, general and administrative expenses primarily due to a decrease of $5 million in capitalized overhead and an increase of $4 million in insurance expense; partially offset by

 

   

an increase of $277 million in fee-based margin due to volume growth in the Northeast, Permian, Ark-La-Tex, North Texas and South Texas regions.

NGL and Refined Products Transportation and Services

 

     Years Ended December 31,         
         2019              2018          Change  

NGL transportation volumes (MBbls/d)

     1,289      1,027      262

Refined products transportation volumes (MBbls/d)

     583      621      (38

NGL and refined products terminal volumes (MBbls/d)

     844      812      32

NGL fractionation volumes (MBbls/d)

     706      527      179

Revenues

   $ 11,641    $ 11,123    $ 518

Cost of products sold

     8,393      8,462      (69
  

 

 

    

 

 

    

 

 

 

Segment margin

     3,248      2,661      587

Unrealized gains (losses) on commodity risk management activities

     81      (86      167

Operating expenses, excluding non-cash compensation expense

     (656      (604      (52

Selling, general and administrative expenses, excluding non-cash compensation expense

     (93      (74      (19

Adjusted EBITDA related to unconsolidated affiliates

     86      82      4
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 2,666    $ 1,979    $ 687
  

 

 

    

 

 

    

 

 

 

 

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Volumes. For the year ended December 31, 2019 compared to the prior year, throughput barrels on our Texas NGL pipeline system increased due to higher receipt of liquids production from both wholly-owned and third-party gas plants primarily in the Permian and North Texas regions. In addition, NGL transportation volumes on our Northeast assets increased due to the initiation of service on the Mariner East 2 pipeline system.

Refined products transportation volumes decreased for the year ended December 31, 2019 compared to prior year due to the closure of a third-party refinery during the third quarter of 2019, negatively impacting supply to our refined products transportation system. These decreases in volumes are partially offset by the initiation of service on the JC Nolan Pipeline in the third quarter of 2019.

NGL and refined products terminal volumes increased for the year ended December 31, 2019 compared to the prior year primarily due to the initiation of service on our Mariner East 2 pipeline system which commenced operations in the fourth quarter of 2018.

Average volumes fractionated at our Mont Belvieu, Texas fractionation facility increased for the year ended December 31, 2019 compared to the prior year primarily due to the commissioning of our fifth and sixth fractionators in July 2018 and February 2019, respectively.

Segment Margin. The components of our NGL and refined products transportation and services segment margin were as follows:

 

     Years Ended December 31,      Change  
         2019              2018      

Fractionators and refinery services margin

   $ 664    $ 511    $ 153

Transportation margin

     1,716      1,233      483

Storage margin

     223      211      12

Terminal Services margin

     630      494      136

Marketing margin

     96      126      (30

Unrealized gains (losses) on commodity risk management activities

     (81      86      (167
  

 

 

    

 

 

    

 

 

 

Total segment margin

   $ 3,248    $ 2,661    $ 587
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the prior year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impacts of the following:

 

   

an increase of $483 million in transportation margin primarily due to a $265 million increase resulting from the initiation of service on our Mariner East 2 pipeline in the fourth quarter of 2018, a $212 million increase resulting from higher throughput volumes received from the Permian region on our Texas NGL pipelines, a $29 million increase due to higher throughput volumes from the Barnett region, a $9 million increase from the Eagle Ford region, and a $9 million increase due to the initiation of service on the JC Nolan Pipeline. These increases were partially offset by a $21 million decrease resulting from Mariner East 1 pipeline downtime, a $13 million decrease due to the closure of a third-party refinery during the third quarter of 2019, negatively impacting refined product supply to our system, and a $5 million decrease due to the timing of deficiency fees on Mariner West;

 

   

an increase of $153 million in fractionation and refinery services margin primarily due to a $167 million increase resulting from the commissioning of our fifth and sixth fractionators in July 2018 and February 2019, respectively, and higher NGL volumes from the Permian region feeding our Mont Belvieu fractionation facility. This increase was partially offset by a reclassification between our fractionation and storage margins;

 

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an increase of $136 million in terminal services margin primarily due to a $171 million increase from the initiation of service of our Mariner East 2 pipeline which commenced operations in the fourth quarter of 2018 and a $7 million increase due to increased tank lease revenue from third-party customers. These increases were partially offset by a $16 million decrease in volumes and expense reimbursements from third parties on Mariner East 1, a $16 million decrease due to lower volumes from third-party pipeline, truck and rail deliveries into our Marcus Hook Terminal, a $5 million decrease due to fewer vessels exported out of our Nederland Terminal, and a $4 million decrease due to the closure of a third-party refinery during the third quarter of 2019; and

 

   

an increase of $12 million in storage margin primarily due to a reclassification between our storage and fractionation margins; partially offset by

 

   

a decrease of $30 million in marketing margin primarily due to capacity lease fees incurred by our marketing affiliate on our Mariner East 2 pipeline, offset by increased gains from our butane blending business due to more favorable market conditions and increased volumes, as well as increased optimization gains from the sale of NGL component products at our Mont Belvieu facility;

 

   

an increase of $52 million in operating expenses primarily due to a $26 million increase in employee and ad valorem tax expenses on our terminals, fractionation, and transportation operations, a $14 million increase in utility costs to operate our pipelines and our fifth and sixth fractionators which commenced July 2018 and February 2019, respectively, and an $8 million increase in maintenance project costs due to the timing of multiple projects on our transportation assets; and

 

   

an increase of $19 million in general and administrative expenses primarily due to a $10 million increase in allocated overhead costs, a $5 million increase in insurance expenses, a $4 million increase in legal fees, and a $2 million increase in employee costs.

Crude Oil Transportation and Services

 

     Years Ended December 31,         
         2019              2018          Change  

Crude Transportation Volumes (MBbls/d)

     4,217      3,713      504

Crude Terminals Volumes (MBbls/d)

     2,513      2,555      (42

Revenue

   $ 18,447    $ 17,332    $ 1,115

Cost of products sold

     14,832      14,384      448
  

 

 

    

 

 

    

 

 

 

Segment margin

     3,615      2,948      667

Unrealized (gains) losses on commodity risk management activities

     (69      55      (124

Operating expenses, excluding non-cash compensation expense

     (570      (547      (23

Selling, general and administrative expenses, excluding non-cash compensation expense

     (85      (86      1

Adjusted EBITDA related to unconsolidated affiliates

     8      15      (7

Other

     (1      —          (1
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 2,898    $ 2,385    $ 513
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the prior year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the net impacts of the following:

 

   

an increase of $543 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $282 million increase resulting from higher throughput on our Texas crude pipeline system primarily due to increased production from the Permian region and

 

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contributions from capacity expansion projects placed into service, a $219 million increase in throughput on our Bakken pipeline, a favorable change due to inventory valuation adjustment of $75 million, partially offset by a $90 million reduction due to lower pipeline basis spreads net of hedges. We also realized a $66 million increase from higher volumes on our Bayou Bridge Pipeline, a $31 million increase due to the inclusion of assets acquired in 2019, and a $26 million increase primarily from higher throughput, ship loading and tank rental fees at our Nederland Terminal; partially offset by a $54 million decrease from our Oklahoma assets resulting from lower volumes to the system as well as from the timing of a deficiency payment made in the prior year, a $12 million decrease due to the closure of a third-party refinery which was the primary customer utilizing one of our northeast crude terminals. The remainder of the offsetting decrease was primarily attributable to a change in the presentation of certain intrasegment transactions, which were eliminated in the current period presentation but were shown on a gross basis in revenues and operating expenses in the prior period; partially offset by

 

   

an increase of $23 million in operating expenses primarily due to a $30 million increase in throughput-related costs on existing assets, partially offset by a $14 million decrease in management fees as well as the impact of certain intrasegment transactions discussed above; and

 

   

a decrease of $7 million in Adjusted EBITDA related to unconsolidated affiliates due to lower margin from jet fuel sales by our joint ventures.

Investment in Sunoco LP

 

     Years Ended December 31,         
         2019              2018          Change  

Revenues

   $ 16,596    $ 16,994    $ (398

Cost of products sold

     15,380      15,872      (492
  

 

 

    

 

 

    

 

 

 

Segment margin

     1,216      1,122      94

Unrealized (gains) losses on commodity risk management activities

     (5      6      (11

Operating expenses, excluding non-cash compensation expense

     (365      (435      70

Selling, general and administrative, excluding non-cash compensation expense

     (123      (129      6

Adjusted EBITDA related to unconsolidated affiliates

     4      —          4

Inventory valuation adjustments

     (79      85      (164

Adjusted EBITDA from discontinued operations

     —          (25      25

Other, net

     17      14      3
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 665    $ 638    $ 27
  

 

 

    

 

 

    

 

 

 

The Investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.

Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the prior year, Segment Adjusted EBITDA related to the Investment in Sunoco LP segment increased due to the net impacts of the following:

 

   

a decrease in operating costs of $76 million, primarily as a result of the conversion of 207 retail sites to commission agent sites during April 2018. These expenses include other operating expense, general and administrative expense and lease expense; and

 

   

an increase of $25 million related to Adjusted EBITDA from discontinued operations related to the divestment of 1,030 company-operated fuel sites to 7-Eleven in January 2018; and

 

   

an increase of $4 million in Adjusted EBITDA related to unconsolidated affiliates due to Sunoco LP’s investment in the JC Nolan joint venture; partially offset by

 

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a decrease in the gross profit on motor fuel sales of $76 million (excluding the change in inventory fair value adjustments and unrealized gains and losses on commodity risk management activities) primarily due to lower fuel margins, a one-time benefit of approximately $25 million related to a cash settlement with a fuel supplier recorded in 2018 and an $8 million one-time charge related to a reserve for an open contractual dispute recorded in 2019, partially offset by an increase in gallons sold.

Investment in USAC

 

     Years Ended December 31,         
         2019              2018          Change  

Revenues

   $ 698    $ 508    $ 190

Cost of products sold

     91      67      24
  

 

 

    

 

 

    

 

 

 

Segment margin

     607      441      166

Operating expenses, excluding non-cash compensation expense

     (134      (110      (24

Selling, general and administrative, excluding non-cash compensation expense

     (53      (50      (3

Other, net

     —          8      (8
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 420    $ 289    $ 131
  

 

 

    

 

 

    

 

 

 

The investment in USAC segment reflects the consolidated results of USAC from April 2, 2018, the date ET obtained control of USAC, through December 31, 2019. Changes between periods are due to the consolidation of USAC beginning April 2, 2018.

All Other

 

     Years Ended December 31,         
         2019              2018          Change  

Revenue

   $ 1,689    $ 2,228    $ (539

Cost of products sold

     1,504      2,006      (502
  

 

 

    

 

 

    

 

 

 

Segment margin

     185      222      (37

Unrealized gains on commodity risk management activities

     (4      (2      (2

Operating expenses, excluding non-cash compensation expense

     (77      (56      (21

Selling, general and administrative expenses, excluding non-cash compensation expense

     (66      (124      58

Adjusted EBITDA related to unconsolidated affiliates

     2      1      1

Other and eliminations

     58      (1      59
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 98    $ 40    $ 58
  

 

 

    

 

 

    

 

 

 

Amounts reflected in our all other segment during the periods presented above primarily include:

 

   

our natural gas marketing operations;

 

   

our wholly-owned natural gas compression operations;

 

   

a noncontrolling interest in PES. Prior to PES’s reorganization in August 2018, ETO’s 33% interest in PES was reflected as an unconsolidated affiliate; for the period subsequent to the August 2018 reorganization through 2019, ETO held an approximately 7.4% interest in PES and no longer reflected PES as an affiliate;

 

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our investment in coal handling facilities; and

 

   

our Canadian operations, which were acquired in the SemGroup acquisition in December 2019 and include natural gas gathering and processing assets.

Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the prior year, Segment Adjusted EBITDA increased due to the net impacts of the following:

 

   

an increase of $8 million in gains from park and loan and storage activity;

 

   

an increase of $11 million in optimized gains on residue gas sales;

 

   

an increase of $7 million from settled derivatives;

 

   

an increase of $15 million from a legal settlement;

 

   

an increase of $12 million from payments related to the PES bankruptcy;

 

   

an increase of $6 million from the recognition of deferred revenue related to a bankruptcy;

 

   

an increase of $3 million from power trading activities;

 

   

an increase of $3 million from the Energy Transfer Canada joint venture for the period subsequent to our acquisition of SemGroup on December 5, 2019, net of an increase due to SemGroup related corporate expenses; and

 

   

a decrease of $21 million in merger and acquisition expenses; partially offset by

 

   

a decrease of $36 million due to the contribution of CDM to USAC in April 2018, subsequent to which CDM is reflected in the Investment in USAC segment;

 

   

a decrease of $8 million due to lower gas prices and increased power costs; and

 

   

a decrease of $11 million due to lower revenue from our compressor equipment business.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Parent Company Only

Subsequent to the Energy Transfer Merger in October 2018, substantially all of the Partnership’s cash flows are derived from distributions related to its investment in ETO, whose cash flows are derived from its subsidiaries, including ETO’s investments in Sunoco LP and USAC.

The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. The Parent Company currently expects to fund its short-term needs for such items with cash flows from its direct and indirect investments in ETO. The Parent Company distributes its available cash remaining after satisfaction of the aforementioned cash requirements to its Unitholders on a quarterly basis.

The Parent Company expects ETO and its respective subsidiaries and investments in Sunoco LP and USAC to utilize their resources, along with cash from their operations, to fund their announced growth capital expenditures and working capital needs; however, the Parent Company may issue debt or equity securities from time to time as it deems prudent to provide liquidity for new capital projects of its subsidiaries or for other partnership purposes.

ETO

ETO’s ability to satisfy its obligations and pay distributions to the Parent Company will depend on its future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond the control of ETO’s management.

 

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ETO currently expects capital expenditures in 2021 to be within the following ranges (excluding capital expenditures related to our investments in Sunoco LP and USAC):

 

     Growth      Maintenance  
     Low      High      Low      High  

Intrastate transportation and storage

   $ 5    $ 10    $ 35    $ 40

Interstate transportation and storage(1)

     25      50      120      125

Midstream

     265      290      110      115

NGL and refined products transportation and services(1)

     700      800      90      100

Crude oil transportation and services(1)

     280      305      100      110

All other (including eliminations)

     75      100      55      60
  

 

 

    

 

 

    

 

 

    

 

 

 

Total capital expenditures

   $ 1,350    $ 1,555    $ 510    $ 550
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)

Includes capital expenditures related to ETO’s proportionate ownership of the Bakken, Rover, and Bayou Bridge pipeline projects and our proportionate ownership of the Orbit Gulf Coast NGL export project.

The assets used in our natural gas and liquids operations, including pipelines, gathering systems and related facilities, are generally long-lived assets and do not require significant maintenance capital expenditures. Accordingly, we do not have any significant financial commitments for maintenance capital expenditures in our businesses. From time to time we experience increases in pipe costs due to a number of reasons, including but not limited to, delays from steel mills, limited selection of mills capable of producing large diameter pipe timely, higher steel prices and other factors beyond our control. However, we include these factors in our anticipated growth capital expenditures for each year.

ETO generally funds maintenance capital expenditures and distributions with cash flows from operating activities. ETO generally expects to funds growth capital expenditures with proceeds of borrowings under our credit facilities, along with cash from operations.

Sunoco LP expects to invest approximately $120 million in growth capital expenditures and approximately $45 million on maintenance capital expenditures in 2021.

USAC currently plans to spend approximately $22 million in maintenance capital expenditures and currently has budgeted between $30 million and $40 million in expansion capital expenditures in 2021.

Cash Flows

Our cash flows may change in the future due to a number of factors, some of which we cannot control. These include regulatory changes, the price of our products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks, the successful integration of our acquisitions, and other factors.

Operating Activities

Changes in cash flows from operating activities between periods primarily result from changes in earnings (as discussed in “Results of Operations” above), excluding the impacts of non-cash items and changes in operating assets and liabilities. Non-cash items include recurring non-cash expenses, such as depreciation, depletion and amortization expense and non-cash compensation expense. The increase in depreciation, depletion and amortization expense during the periods presented primarily resulted from construction and acquisitions of assets, while changes in non-cash compensation expense resulted from changes in the number of units granted and changes in the grant date fair value estimated for such grants. Cash flows from operating activities also differ from earnings as a result of non-cash charges that may not be recurring such as impairment charges and

 

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allowance for equity funds used during construction. The allowance for equity funds used during construction increases in periods when ETO has a significant amount of interstate pipeline construction in progress. Changes in operating assets and liabilities between periods result from factors such as the changes in the value of derivative assets and liabilities, timing of accounts receivable collection, payments on accounts payable, the timing of purchases and sales of inventories, and the timing of advances and deposits received from customers.

Following is a summary of operating activities by period:

Year Ended December 31, 2020

Cash provided by operating activities in 2020 was $7.36 billion and income from continuing operations was $140 million. The difference between net income and cash provided by operating activities in 2020 primarily consisted of non-cash items totaling $7.00 billion offset by net changes in operating assets and liabilities of $47 million. The non-cash activity in 2020 consisted primarily of depreciation, depletion and amortization of $3.68 billion, impairment losses of $2.88 billion, non-cash compensation expense of $121 million, equity in earnings of unconsolidated affiliates of $119 million, inventory valuation adjustments of $82 million, losses on extinguishment of debt of $75 million, and deferred income taxes of $210 million. The Partnership also received distributions of $220 million from unconsolidated affiliates.

Year Ended December 31, 2019

Cash provided by operating activities in 2019 was $8.06 billion and income from continuing operations was $4.83 billion. The difference between net income and cash provided by operating activities in 2019 primarily consisted of non-cash items totaling $3.37 billion offset by net changes in operating assets and liabilities of $391 million. The non-cash activity in 2019 consisted primarily of depreciation, depletion and amortization of $3.15 billion, impairment losses of $74 million, non-cash compensation expense of $113 million, equity in earnings of unconsolidated affiliates of $302 million, inventory valuation adjustments of $79 million, losses on extinguishment of debt of $18 million, and deferred income taxes of $217 million. The Partnership also received distributions of $290 million from unconsolidated affiliates.

Year Ended December 31, 2018

Cash provided by operating activities in 2018 was $7.51 billion and income from continuing operations was $3.69 billion. The difference between net income and cash provided by operating activities in 2018 primarily consisted of non-cash items totaling $3.30 billion and net changes in operating assets and liabilities of $234 million. The non-cash activity in 2018 consisted primarily of depreciation, depletion and amortization of $2.86 billion, impairment losses of $431 million, non-cash compensation expense of $105 million, equity in earnings of unconsolidated affiliates of $344 million, inventory valuation adjustments of $85 million, losses on extinguishment of debt of $112 million, and deferred income taxes of $7 million. The Partnership also received distributions of $328 million from unconsolidated affiliates.

Investing Activities

Cash flows from investing activities primarily consist of cash amounts paid for acquisitions, capital expenditures, cash distributions from our joint ventures, and cash proceeds from sales or contributions of assets or businesses. Changes in capital expenditures between periods primarily result from increases or decreases in our growth capital expenditures to fund our construction and expansion projects.

Following is a summary of investing activities by period:

Year Ended December 31, 2020

Cash used in investing activities in 2020 was $4.90 billion. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) were $5.06 billion.

 

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Additional detail related to our capital expenditures is provided in the table below. We received $19 million of cash proceeds from the sale of assets. The Partnership also received distributions of $187 million from unconsolidated affiliates.

Year Ended December 31, 2019

Cash used in investing activities in 2019 was $6.93 billion. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) were $5.88 billion. Additional detail related to our capital expenditures is provided in the table below. During 2020, we received $93 million of cash proceeds from the sale of a noncontrolling interest in a subsidiary, paid $787 million in net cash for the SemGroup acquisition, and paid $7 million in cash for all other acquisitions. We received $54 million of cash proceeds from the sale of assets. The Partnership also received distributions of $98 million from unconsolidated affiliates.

Year Ended December 31, 2018

Cash used in investing activities in 2018 was $7.08 billion. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) were $7.30 billion. Additional detail related to our capital expenditures is provided in the table below. We recorded a net increase in cash of $461 million related to the USAC acquisition and paid $429 million in cash from all other acquisitions. We received $87 million of cash proceeds from the sale of assets. The Partnership also received distributions of $69 million from unconsolidated affiliates.

The following is a summary of the Partnership’s capital expenditures (including only our proportionate share of the Bakken, Rover, and Bayou Bridge pipeline projects, our proportionate share of the Orbit Gulf Coast NGL export project, and net of contributions in aid of construction costs) by period:

 

     Capital Expenditures Recorded
During Period
 
  

 

 

 
     Growth      Maintenance      Total  

Year Ended December 31, 2020:

        

Intrastate transportation and storage

   $ 13    $ 36    $ 49

Interstate transportation and storage

     52      98      150

Midstream

     376      111      487

NGL and refined products transportation and services

     2,305      98      2,403

Crude oil transportation and services

     209      82      291

Investment in Sunoco LP

     89      35      124

Investment in USAC

     96      23      119

All other (including eliminations)

     99      37      136
  

 

 

    

 

 

    

 

 

 

Total capital expenditures

   $ 3,239    $ 520    $ 3,759
  

 

 

    

 

 

    

 

 

 

Year Ended December 31, 2019:

        

Intrastate transportation and storage

   $ 87    $ 37    $ 124

Interstate transportation and storage

     239      136      375

Midstream

     670      157      827

NGL and refined products transportation and services

     2,854      122      2,976

Crude oil transportation and services

     317      86      403

Investment in Sunoco LP(1)

     108      40      148

Investment in USAC

     170      30      200

All other (including eliminations)

     165      50      215
  

 

 

    

 

 

    

 

 

 

Total capital expenditures

   $ 4,610    $ 658    $ 5,268
  

 

 

    

 

 

    

 

 

 

 

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     Capital Expenditures Recorded
During Period
 
   Growth      Maintenance      Total  

Year Ended December 31, 2018:

        

Intrastate transportation and storage

   $ 311    $ 33    $ 344

Interstate transportation and storage

     695      117      812

Midstream

     1,026      135      1,161

NGL and refined products transportation and services

     2,303      78      2,381

Crude oil transportation and services

     414      60      474

Investment in Sunoco LP(1)

     72      31      103

Investment in USAC

     182      23      205

All other (including eliminations)

     117      33      150
  

 

 

    

 

 

    

 

 

 

Total capital expenditures

   $ 5,120    $ 510    $ 5,630
  

 

 

    

 

 

    

 

 

 

 

(1)

Amounts related to Sunoco LP’s capital expenditures include capital expenditures related to discontinued operations.

Financing Activities

Changes in cash flows from financing activities between periods primarily result from changes in the levels of borrowings and equity issuances, which are primarily used to fund our acquisitions and growth capital expenditures. Distributions to partners increased between the periods as a result of increases in the number of common units outstanding or increases in the distribution rate.

Following is a summary of financing activities by period:

Year Ended December 31, 2020

Cash used in financing activities was $2.39 billion in 2020. In 2020, our subsidiaries received $1.58 billion in proceeds from the issuance of preferred units. In 2020, we had a consolidated increase in our debt level of $307 million, primarily due to the issuance of subsidiary senior notes. During 2020, we paid distributions of $2.80 billion to our partners, we paid distributions of $1.65 billion to noncontrolling interests, and we paid distributions of $49 million to our redeemable noncontrolling interests. In addition, we received capital contributions of $222 million in cash from noncontrolling interests. During 2020, we incurred debt issuance costs of $59 million.

Year Ended December 31, 2019

Cash used in financing activities was $1.25 billion in 2019. Our subsidiaries received $780 million in proceeds from the issuance of preferred units. In 2019, we had a consolidated increase in our debt level of $2.48 billion, primarily due to the issuance of subsidiary notes. During 2019, we paid distributions of $3.05 billion to our partners, we paid distributions of $1.60 billion to noncontrolling interests, and we paid distributions of $53 million to our redeemable noncontrolling interests. In addition, we received capital contributions of $348 million in cash from noncontrolling interests. During 2019, we incurred debt issuance costs of $117 million.

Year Ended December 31, 2018

Cash used in financing activities was $3.08 billion in 2018. Our subsidiaries received $1.40 billion in proceeds from the issuance of common units, including $58 million from the issuance of ETO Common Units and $1.34 billion from the issuance of other subsidiary common units. In 2018, we had a consolidated increase in our debt level of $53 million, primarily due to the issuance of Parent Company and subsidiary senior notes. During 2018, we paid distributions of $1.68 billion to our partners, we paid distributions of $3.12 billion to

 

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noncontrolling interests, and we paid distributions of $24 million to our redeemable noncontrolling interests. In addition, we received capital contributions of $649 million in cash from noncontrolling interests. During 2018, we incurred debt issuance costs of $171 million.

Discontinued Operations

Following is a summary of activities related to discontinued operations by period:

Year Ended December 31, 2018

Cash provided by discontinued operations was $2.73 billion for the year ended December 31, 2018, which reflected the net impact of cash used in operating activities of $484 million, cash provided by investing activities of $3.21 billion and changes in cash included in current assets held for sale of $11 million.

Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:

 

     December 31,  
     2020      2019  

Parent Company Indebtedness:

     

ET Senior Notes due October 2020

   $ —      $ 52

ET Senior Notes due March 2023

     5      5

ET Senior Notes due January 2024

     23      23

ET Senior Notes due June 2027

     44      44

Subsidiary Indebtedness:

     

ETO Senior Notes

     37,783      36,118

Transwestern Senior Notes

     400      575

Panhandle Senior Notes

     235      235

Bakken Senior Notes

     2,500      2,500

Sunoco LP Senior Notes, Term Loan and lease-related obligations

     3,139      2,935

USAC Senior Notes

     1,475      1,475

HFOTCO Tax-Exempt Notes

     225        225  

Revolving Credit Facilities:

     

ETO $2.00 billion Term Loan facility due October 2022

     2,000      2,000

ETO $5.00 billion Revolving Credit Facility due December 2023

     3,103      4,214

Sunoco LP $1.50 billion Revolving Credit Facility due July 2023

     —          162

USAC $1.60 billion Revolving Credit Facility due April 2023

     474      403

Energy Transfer Canada Revolver due February 2024

     57      92

Energy Transfer Canada Revolver Term Loan A due February 2024

     261      269

Other long-term debt

     3      2

Unamortized premiums, net of discounts and fair value adjustments

     (10      4

Deferred debt issuance costs

     (279      (279
  

 

 

    

 

 

 

Total debt

     51,438      51,054

Less: current maturities of long-term debt

     21      26
  

 

 

    

 

 

 

Long-term debt, less current maturities

   $ 51,417    $ 51,028
  

 

 

    

 

 

 

 

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The terms of our consolidated indebtedness and that of our subsidiaries are described in more detail below and in Note 6 to our consolidated financial statements, included in “Item 8. Financial Statements and Supplementary Data.”

Recent Financing Transactions

ETO January 2020 Senior Notes Offering and Redemption

On January 22, 2020, ETO completed a registered offering (the “January 2020 Senior Notes Offering”) of $1.00 billion aggregate principal amount of ETO’s 2.900% Senior Notes due 2025, $1.50 billion aggregate principal amount of ETO’s 3.750% Senior Notes due 2030, and $2.00 billion aggregate principal amount of ETO’s 5.000% Senior Notes due 2050, (collectively, the “Notes”). The Notes are fully and unconditionally guaranteed by the Partnership’s wholly-owned subsidiary, Sunoco Logistics Partners Operations L.P., on a senior unsecured basis.

Utilizing proceeds from the January 2020 Senior Notes Offering, ETO redeemed its $400 million aggregate principal amount of 5.75% Senior Notes due September 1, 2020, its $1.05 billion aggregate principal amount of 4.15% Senior Notes due October 1, 2020, its $1.14 billion aggregate principal amount of 7.50% Senior Notes due October 15, 2020, its $250 million aggregate principal amount of 5.50% Senior Notes due February 15, 2020, ET’s $52 million aggregate principal amount of 7.50% Senior Notes due October 15, 2020 and Transwestern’s $175 million aggregate principal amount of 5.36% Senior Notes due December 9, 2020.

Sunoco LP November 2020 Senior Notes Offering and Repurchase

On November 9, 2020, Sunoco LP completed a private offering of $800 million in aggregate principal amount of 4.500% senior notes due 2029. Sunoco LP used the proceeds to fund the tender offer on its 4.875% $1 billion senior notes due 2023. Approximately 56% of the 2023 senior notes were tendered. On January 15, 2021, Sunoco LP repurchased the remaining outstanding portion of its 2023 senior notes.

Credit Facilities, Term Loan and Commercial Paper

Parent Company

The Parent Company does not currently have any credit facilities.

ETO Credit Facilities

Borrowings under the ETO Credit Facilities (defined as the ETO Term Loan, ETO Five-Year Credit Facility and ETO 364-Day Credit Facility, each of which is described below) are unsecured and initially guaranteed by Sunoco Logistics Operations. Borrowings under the ETO Credit Facilities will bear interest at a eurodollar rate or a base rate, at our option, plus an applicable margin. In addition, we will be required to pay a quarterly commitment fee to each lender equal to the product of the applicable rate and such lender’s applicable percentage of the unused portion of the aggregate commitments under the ETO Credit Facilities.

We typically repay amounts outstanding under the ETO Credit Facilities with proceeds from unit offerings or long-term notes offerings. The timing of borrowings depends on the Partnership’s activities and the cash available to fund those activities. The repayments of amounts outstanding under the ETO Credit Facilities depend on multiple factors, including market conditions and expectations of future working capital needs, and ultimately are a financing decision made by management. Therefore, the balance outstanding under the ETO Credit Facilities may vary significantly between periods. We do not believe that such fluctuations indicate a significant change in our liquidity position, because we expect to continue to be able to repay amounts outstanding under the ETO Credit Facilities with proceeds from unit offerings or long-term note offerings.

 

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ETO Term Loan

On October 17, 2019, ETO entered into a term loan credit agreement (the “ETO Term Loan”) providing for a $2.00 billion three-year term loan credit facility. Borrowings under the term loan agreement mature on October 17, 2022 and are available for working capital purposes and for general partnership purposes. The term loan agreement is unsecured and is guaranteed by our subsidiary, Sunoco Logistics Operations.

As of December 31, 2020, the ETO Term Loan had $2.00 billion outstanding and was fully drawn. The weighted average interest rate on the total amount outstanding as of December 31, 2020 was 1.15%.

ETO Five-Year Credit Facility

ETO’s revolving credit facility (the “ETO Five-Year Credit Facility”) allows for unsecured borrowings up to $5.00 billion and matures on December 1, 2023. The ETO Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to $6.00 billion under certain conditions.

As of December 31, 2020, the ETO Five-Year Credit Facility had $3.10 billion outstanding, of which $1.66 billion was commercial paper. The amount available for future borrowings was $1.79 billion after accounting for outstanding letters of credit in the amount of $109 million. The weighted average interest rate on the total amount outstanding as of December 31, 2020 was 1.12%.

ETO 364-Day Facility

ETO’s 364-day revolving credit facility (the “ETO 364-Day Facility”) allows for unsecured borrowings up to $1.00 billion and matures on November 26, 2021. As of December 31, 2020, the ETO 364-Day Facility had no outstanding borrowings.

Sunoco LP Credit Facility

As of December 31, 2020, the Sunoco LP Credit Facility had no outstanding borrowings and $8 million in standby letters of credit. The amount available for future borrowings was at December 31, 2020 was $1.5 billion.

USAC Credit Facility

As of December 31, 2020, USAC had $474 million of outstanding borrowings and no outstanding letters of credit under the credit agreement. As of December 31, 2020, USAC had $1.13 billion of availability under its credit facility. The weighted average interest rate on the total amount outstanding as of December 31, 2020 was 3.27%.

Energy Transfer Canada Credit Facilities

Energy Transfer Canada is party to a credit agreement providing for a C$350 million (US$275 million at the December 31, 2020 exchange rate) senior secured term loan facility, a C$525 million (US$412 million at the December 31, 2020 exchange rate) senior secured revolving credit facility, and a C$300 million (US$236 million at the December 31, 2020 exchange rate) senior secured construction loan facility (the “KAPS Facility”). The term loan facility and the revolving credit facility mature on February 25, 2024. The KAPS Facility matures on June 13, 2024. Energy Transfer Canada may incur additional term loans and revolving commitments in an aggregate amount not to exceed C$250 million (US$196 million at the December 31, 2020 exchange rate), subject to receiving commitments for such additional term loans or revolving commitments from either new lenders or increased commitments from existing lenders.

 

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Covenants Related to Our Credit Agreements

Covenants Related to the Parent Company

The Term Loan Facility and ET Revolving Credit Facility previously contained customary representations, warranties, covenants, and events of default, including a change of control event of default and limitations on incurrence of liens, new lines of business, merger, transactions with affiliates and restrictive agreements. Both facilities have been paid off and terminated.

Covenants Related to ETO

The agreements relating to the ETO senior notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions.

The ETO Credit Facilities (defined as the ETO Term Loan, ETO Five-Year Credit Facility and ETO 364-Day Credit Facility) contain covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries’ ability to, among other things:

 

   

incur indebtedness;

 

   

grant liens;

 

   

enter into mergers;

 

   

dispose of assets;

 

   

make certain investments;

 

   

make Distributions (as defined in the ETO Credit Facilities) during certain Defaults (as defined in the ETO Credit Facilities) and during any Event of Default (as defined in the ETO Credit Facilities);

 

   

engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries;

 

   

engage in transactions with affiliates; and

 

   

enter into restrictive agreements.

The ETO Credit Facilities applicable margin and rate used in connection with the interest rates and commitment fees, respectively, are based on the credit ratings assigned to our senior, unsecured, non-credit enhanced long-term debt. The applicable margin for eurodollar rate loans under the ETO Five-Year Credit Facility ranges from 1.125% to 2.000% and the applicable margin for base rate loans ranges from 0.125% to 1.000%. The applicable rate for commitment fees under the ETO Five-Year Credit Facility ranges from 0.125% to 0.300%. The applicable margin for eurodollar rate loans under the ETO 364-Day Facility ranges from 1.500% to 2.000% and the applicable margin for base rate loans ranges from 0.500% to 1.000%. The applicable rate for commitment fees under the ETO 364-Day Facility ranges from 0.125% to 0.225%.

The ETO Credit Facilities contain various covenants including limitations on the creation of indebtedness and liens and related to the operation and conduct of our business. The ETO Credit Facilities also limit us, on a rolling four quarter basis, to a maximum Consolidated Funded Indebtedness to Consolidated EBITDA ratio, as defined in the underlying credit agreements, of 5.0 to 1, which can generally be increased to 5.5 to 1 during a Specified Acquisition Period. Our Leverage Ratio was 4.31 to 1 at December 31, 2020, as calculated in accordance with the credit agreements.

The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio.

 

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Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Partnership’s or our subsidiaries’ ability to incur additional debt and/or our ability to pay distributions to Unitholders.

Covenants Related to Panhandle

Panhandle is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of Panhandle’s lending agreements.

Panhandle’s restrictive covenants include restrictions on liens securing debt and guarantees and restrictions on mergers and on the sales of assets. A breach of any of these covenants could result in acceleration of Panhandle’s debt.

Covenants Related to Sunoco LP

The Sunoco LP Credit Facility contains various customary representations, warranties, covenants and events of default, including a change of control event of default, as defined therein. Sunoco LP’s Credit Facility requires Sunoco LP to maintain a Net Leverage Ratio of not more than 5.5 to 1. The maximum Net Leverage Ratio is subject to upwards adjustment of not more than 6.0 to 1 for a period not to exceed three fiscal quarters in the event Sunoco LP engages in certain specified acquisitions of not less than $50 million (as permitted under Sunoco LP’s Credit Facility agreement). The Sunoco LP Credit Facility also requires Sunoco LP to maintain an Interest Coverage Ratio (as defined in the Sunoco LP’s Credit Facility agreement) of not less than 2.25 to 1.

Covenants Related to USAC

The USAC Credit Facility contains covenants that limit (subject to certain exceptions) USAC’s ability to, among other things:

 

   

grant liens;

 

   

make certain loans or investments;

 

   

incur additional indebtedness or guarantee other indebtedness;

 

   

merge or consolidate;

 

   

sell our assets; or

 

   

make certain acquisitions.

The credit facility is also subject to the following financial covenants, including covenants requiring us to maintain:

 

   

a minimum EBITDA to interest coverage ratio of 2.5 to 1.0, determined as of the last day of each fiscal quarter; and

 

   

a maximum funded debt to EBITDA ratio, determined as of the last day of each fiscal quarter, for the annualized trailing three months of (i) 5.75 to 1 through the end of the fiscal quarter ending December 31, 2020 and (ii) 5.5 to 1 for the fiscal quarters ending March 31, 2021 and June 30, 2021, (iii) 5.25 to 1 for the fiscal quarters ending September 30, 2021 and December 31, 2021 and (iv) 5.0 to 1 thereafter, subject to a provision for increases to such thresholds, in the case of any fiscal quarter ending September 30, 2021 or thereafter, by 0.50 in connection with certain future acquisitions for the six consecutive month period following the period in which any such acquisition occurs, provided that, in any event, such ratio shall not exceed 5.5 to 1.

 

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Covenants Related to the HFOTCO Tax Exempt Notes

The indentures covering HFOTCO’s tax exempt notes due 2050 (“IKE Bonds”) include customary representations and warranties and affirmative and negative covenants. Such covenants include limitations on the creation of new liens, indebtedness, making of certain restricted payments and payments on indebtedness, making certain dispositions, making material changes in business activities, making fundamental changes including liquidations, mergers or consolidations, making certain investments, entering into certain transactions with affiliates, making amendments to certain credit or organizational agreements, modifying the fiscal year, creating or dealing with hazardous materials in certain ways, entering into certain hedging arrangements, entering into certain restrictive agreements, funding or engaging in sanctioned activities, taking actions or causing the trustee to take actions that materially adversely affect the rights, interests, remedies or security of the bondholders, taking actions to remove the trustee, making certain amendments to the bond documents, and taking actions or omitting to take actions that adversely impact the tax exempt status of the IKE Bonds.

Compliance with our Covenants

We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2020.

Contractual Obligations

The following table summarizes our long-term debt and other contractual obligations as of December 31, 2020:

 

     Payments Due by Period  

Contractual Obligations

   Total      Less Than
1 Year
     1-3 Years      3-5 Years      More Than
5 Years
 

Long-term debt

   $ 51,727    $ 1,420    $ 13,023    $ 7,029    $ 30,255

Interest on long-term debt(1)

     28,980      2,421      4,330      3,448      18,781

Payments on derivatives

     451      212      239      —          —    

Purchase commitments(2)

     3,731      2,599      703      356      73

Transportation, natural gas storage and fractionation contracts

     286      62      120      104      —    

Operating lease obligations

     1,554      99      164      151      1,140

Service concession arrangement(3)

     364      15      31      32      286

Other(4)

     196      26      50      41      79
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total(5)

   $ 87,289    $ 6,854    $ 18,660    $ 11,161    $ 50,614
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)

Interest payments on long-term debt are based on the principal amount of debt obligations as of December 31, 2020. With respect to variable rate debt, the interest payments were estimated using the interest rate as of December 31, 2020. To the extent interest rates change, our contractual obligations for interest payments will change. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for further discussion.

(2)

We define a purchase commitment as an agreement to purchase goods or services that is enforceable and legally binding (unconditional) on us that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transactions. We have long and short-term product purchase obligations for refined product and energy commodities with third-party suppliers. These purchase obligations are entered into at either variable or fixed prices. The purchase prices that we are obligated to pay under variable price contracts approximate market prices at the time we take delivery of the volumes. Our estimated future variable price contract payment obligations are based on the December 31, 2020 market price of the applicable commodity applied to future volume commitments. Actual future payment obligations may vary depending on market prices at the time of delivery. The purchase prices that we are obligated to pay under fixed price contracts are

 

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  established at the inception of the contract. Our estimated future fixed price contract payment obligations are based on the contracted fixed price under each commodity contract. Obligations shown in the table represent estimated payment obligations under these contracts for the periods indicated.
(3)

Includes minimum guaranteed payments under service concession arrangements with New Jersey Turnpike Authority and New York Thruway Authority.

(4)

Expected contributions to fund our pension and postretirement benefit plans were included in “Other” above. Environmental liabilities, AROs, unrecognized tax benefits, contingency accruals and deferred revenue, which were included in “Other non-current liabilities” in our consolidated balance sheets, were excluded from the table above as the amounts do not represent contractual obligations or, in some cases, the amount and/or timing of the cash payments is uncertain.

(5)

Excludes non-current deferred tax liabilities of $3.43 billion due to uncertainty of the timing of future cash flows for such liabilities.

Cash Distributions

Cash Distributions Paid by the Parent Company

Under the Parent Company Partnership Agreement, the Parent Company will distribute all of its Available Cash, as defined, within 50 days following the end of each fiscal quarter. Available cash generally means, with respect to any quarter, all cash on hand at the end of such quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the General Partner that is necessary or appropriate to provide for future cash requirements.

Distributions declared and paid are as follows:

 

Quarter Ended

  

Record Date

  

Payment Date

  

Rate

December 31, 2017    February 8, 2018    February 20, 2018    $0.3050
March 31, 2018    May 7, 2018    May 21, 2018    0.3050
June 30, 2018    August 6, 2018    August 20, 2018    0.3050
September 30, 2018    November 8, 2018    November 19, 2018    0.3050
December 31, 2018    February 8, 2019    February 19, 2019    0.3050
March 31, 2019    May 7, 2019    May 20, 2019    0.3050
June 30, 2019    August 6, 2019    August 19, 2019    0.3050
September 30, 2019    November 5, 2019    November 19, 2019    0.3050
December 31, 2019    February 7, 2020    February 19, 2020    0.3050
March 31, 2020    May 7, 2020    May 19, 2020    0.3050
June 30, 2020    August 7, 2020    August 19, 2020    0.3050
September 30, 2020    November 6, 2020    November 19, 2020    0.1525
December 31, 2020    February 8, 2021    February 19, 2021    0.1525

Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the distribution for the quarter ended March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received ET Series A Convertible Preferred Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per unit. In May 2018, the ET Series A Convertible Preferred Units converted into ET Common Units. See Note 8 to the Partnership’s consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”

 

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Our distributions declared and paid with respect to ET Series A Convertible Preferred Unit were as follows:

 

Quarter Ended

  

Record Date

  

Payment Date

  

Rate

December 31, 2016    February 7, 2017    February 21, 2017    $0.1100
March 31, 2017    May 10, 2017    May 19, 2017    0.1100
June 30, 2017    August 7, 2017    August 21, 2017    0.1100
September 30, 2017    November 7, 2017    November 20, 2017    0.1100
December 31, 2017    February 8, 2018    February 20, 2018    0.1100
March 31, 2018    May 7, 2018    May 21, 2018    0.1100

The total amounts of distributions declared and paid during the periods presented (all from Available Cash from the Parent Company’s operating surplus and are shown in the period to which they relate) are as follows:

 

     Years Ended December 31,  
     2020      2019      2018  

Limited Partners

   $ 2,468    $ 3,221    $ 2,215

General Partner interest

     3      4      3
  

 

 

    

 

 

    

 

 

 

Total Parent Company distributions

   $ 2,471    $ 3,225    $ 2,218
  

 

 

    

 

 

    

 

 

 

Cash Distributions Paid by Subsidiaries

Certain of our subsidiaries are required by their respective partnership agreements to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by the board of directors of their respective general partners.

ETO Preferred Unit Distributions

Distributions on the ETO’s Series A, Series B, Series C, Series D, Series E, Series F and Series G preferred units declared and/or paid by ETO were as follows:

 

Period Ended

  Record Date   Payment Date   Series A(1)     Series B(1)     Series C     Series D     Series E     Series F(1)     Series G(1)  

June 30, 2018

  August 1, 2018   August 15, 2018   $ 31.2500   $ 33.1250   $ 0.5634   $ —     $ —     $ —     $ —  

September 30, 2018

  November 1, 2018   November 15, 2018     —         —         0.4609     0.5931     —         —         —    

December 31, 2018

  February 1, 2019   February 15, 2019     31.2500     33.1250     0.4609     0.4766     —         —         —    

March 31, 2019

  May 1, 2019   May 15, 2019     —         —         0.4609     0.4766     —         —         —    

June 30, 2019

  August 1, 2019   August 15, 2019     31.2500     33.1250     0.4609     0.4766     0.5806     —         —    

September 30, 2019

  November 1, 2019   November 15, 2019     —         —         0.4609     0.4766     0.4750     —         —    

December 31, 2019

  February 3, 2020   February 18, 2020     31.2500     33.1250     0.4609     0.4766     0.4750     —         —    

March 31, 2020

  May 1, 2020   May 15, 2020     —         —         0.4609     0.4766     0.4750     21.19     22.36

June 30, 2020

  August 3, 2020   August 17, 2020     31.2500     33.1250     0.4609     0.4766     0.4750     —         —    

September 30, 2020

  November 2, 2020   November 15, 2020     —         —         0.4609     0.4766     0.4750     33.75     35.625

December 31, 2020

  February 1, 2021   February 16, 2021     31.2500     33.1250     0.4609     0.4766     0.4750     —         —    

 

*

Represent prorated initial distributions.

(1)

ETO Series A Preferred Unit, ETO Series B Preferred Unit, ETO Series F Preferred Unit and ETO Series G Preferred Unit distributions are paid on a semi-annual basis.

Sunoco LP Cash Distributions

The following table illustrates the percentage allocations of available cash from operating surplus between Sunoco LP’s common unitholders and the holder of its IDRs based on the specified target distribution levels, after the payment of distributions to Class C unitholders. The amounts set forth under “marginal percentage interest in distributions” are the percentage interests of the IDR holder and the common unitholders in any available cash from operating surplus which Sunoco LP distributes up to and including the corresponding amount in the column “total quarterly distribution per unit target amount.” The percentage interests shown for common

 

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unitholders and IDR holder for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

 

          Marginal Percentage Interest in
Distributions
 
     Total Quarterly Distribution Target Amount    Common
Unitholders
    Holder of
IDRs
 

Minimum Quarterly Distribution

   $0.4375      100     —  

First Target Distribution

   $0.4375 to $0.503125      100     —  

Second Target Distribution

   $0.503125 to $0.546875      85     15

Third Target Distribution

   $0.546875 to $0.656250      75     25

Thereafter

   Above $0.656250      50     50

Distributions on Sunoco LP’s units declared and/or paid by Sunoco LP were as follows:

 

Quarter Ended

  

Record Date

  

Payment Date

  

Rate

December 31, 2017    February 6, 2018    February 14, 2018    $0.8255
March 31, 2018    May 7, 2018    May 15, 2018    0.8255
June 30, 2018    August 7, 2018    August 15, 2018    0.8255
September 30, 2018    November 6, 2018    November 14, 2018    0.8255
December 31, 2018    February 6, 2019    February 14, 2019    0.8255
March 31, 2019    May 7, 2019    May 15, 2019    0.8255
June 30, 2019    August 6, 2019    August 14, 2019    0.8255
September 30, 2019    November 5, 2019    November 19, 2019    0.8255
December 31, 2019    February 7, 2020    February 19, 2020    0.8255
March 31, 2020    May 7, 2020    May 19, 2020    0.8255
June 30, 2020    August 7, 2020    August 19, 2020    0.8255
September 30, 2020    November 6, 2020    November 19, 2020    0.8255
December 31, 2020    February 8, 2021    February 19, 2021    0.8255

The total amount of distributions to the Partnership from Sunoco LP for the periods presented below is as follows:

 

     Years Ended December 31,  
     2020      2019      2018  

Distributions from Sunoco LP

        

Limited Partner interests

   $ 94    $ 94    $ 94

General Partner interest and IDRs

     70      70      70

Series A Preferred

     —          —          2
  

 

 

    

 

 

    

 

 

 

Total distributions from Sunoco LP

   $ 164    $ 164    $ 166
  

 

 

    

 

 

    

 

 

 

USAC Cash Distributions

Subsequent to the Energy Transfer Merger and USAC Transactions described in Note 1 and Note 3, respectively, ETO owned approximately 39.7 million USAC common units and 6.4 million USAC Class B units. Subsequent to the conversion of the USAC Class B Units to USAC common units on July 30, 2019, ETO owns approximately 46.1 million USAC common units. As of December 31, 2020, USAC had approximately 97.0 million common units outstanding. USAC currently has a non-economic general partner interest and no outstanding IDRs.

 

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Distributions on USAC’s units declared and/or paid by USAC subsequent to the USAC transaction on April 2, 2018 were as follows:

 

Quarter Ended

  

Record Date

  

Payment Date

  

Rate

March 31, 2018    May 1, 2018    May 11, 2018    $0.5250
June 30, 2018    July 30, 2018    August 10, 2018    0.5250
September 30, 2018    October 29, 2018    November 9, 2018    0.5250
December 31, 2018    January 28, 2019    February 8, 2019    0.5250
March 31, 2019    April 29, 2019    May 10, 2019    0.5250
June 30, 2019    July 29, 2019    August 9, 2019    0.5250
September 30, 2019    October 28, 2019    November 8, 2019    0.5250
December 31, 2019    January 27, 2020    February 7, 2020    0.5250
March 31, 2020    April 27, 2020    May 8, 2020    0.5250
June 30, 2020    July 31, 2020    August 10, 2020    0.5250
September 30, 2020    October 26, 2020    November 6, 2020    0.5250
December 31, 2020    January 25, 2021    February 5, 2021    0.5250

The total amount of distributions to the Partnership from USAC for the periods presented below is as follows:

 

     Years Ended December 31,  
     2020      2019      2018  

Distributions from USAC

        

Limited Partner interests

   $ 97    $ 90    $ 73
  

 

 

    

 

 

    

 

 

 

Total distributions from USAC

   $ 97    $ 90    $ 73
  

 

 

    

 

 

    

 

 

 

Critical Accounting Estimates

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules, and we believe the proper implementation and consistent application of the accounting rules are critical. Our critical accounting policies are discussed below. For further details on our accounting policies see Note 2 to our consolidated financial statements.

Use of Estimates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage segments are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the operating results estimated for the year ended December 31, 2020 represent the actual results in all material respects.

Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation, depletion and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.

 

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Impairment of Long-Lived Assets, Goodwill, Intangible Assets and Investments in Unconsolidated Affiliates. Long-lived assets are required to be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. Goodwill and intangibles with indefinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other than temporary. An impairment loss should be recognized only if the carrying amount of the asset/goodwill is not recoverable and exceeds its fair value.

In order to test for recoverability when performing a quantitative impairment test, we must make estimates of projected cash flows related to the asset, which include, but are not limited to, assumptions about the use or disposition of the asset, estimated remaining life of the asset, and future expenditures necessary to maintain the asset’s existing service potential. In order to determine fair value, we make certain estimates and assumptions, including, among other things, changes in general economic conditions in regions in which our markets are located, the availability and prices of natural gas, our ability to negotiate favorable sales agreements, the risks that natural gas exploration and production activities will not occur or be successful, our dependence on certain significant customers and producers of natural gas, and competition from other companies, including major energy producers. While we believe we have made reasonable assumptions to calculate the fair value, if future results are not consistent with our estimates, we could be exposed to future impairment losses that could be material to our results of operations.

The Partnership determines the fair value of its reporting units using a discounted cash flow method, the guideline company method, or a weighted combination of these methods. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determines fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determines the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimates a reasonable control premium, when appropriate, representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business.

One key assumption for the measurement of an impairment is management’s estimate of future cash flows and EBITDA. These estimates are based on the annual budget for the upcoming year and forecasted amounts for multiple subsequent years. The annual budget process is typically completed near the annual goodwill impairment testing date, and management uses the most recent information for the annual impairment tests. The forecast is also subjected to a comprehensive update annually in conjunction with the annual budget process and is revised periodically to reflect new information and/or revised expectations. The estimates of future cash flows and EBITDA are subjective in nature and are subject to impacts from the business risks described in “Item 1A. Risk Factors.” Therefore, the actual results could differ significantly from the amounts used for goodwill impairment testing, and significant changes in fair value estimates could occur in a given period. Such changes in fair value estimates could result in additional impairments in future periods; therefore, the actual results could

 

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differ significantly from the amounts used for goodwill impairment testing, and significant changes in fair value estimates could occur in a given period, resulting in additional impairments.

In addition, we may change our method of impairment testing, including changing the weight assigned to different valuation models. Such changes could be driven by various factors, including the level of precision or availability of data for our assumptions. Any changes in the method of testing could also result in an impairment or impact the magnitude of an impairment.

During the years ended December 31, 2020, 2019 and 2018, the Partnership recorded impairments totaling $3.01 billion, $74 million and $431 million, respectively, including $129 million in impairments in unconsolidated affiliates in 2020, and $66 million, $53 million and $52 million of long-lived asset impairments in 2020, 2019 and 2018, respectively. Additional information on the impairments recorded during these periods is available in “Item 8. Financial Statements and Supplementary Data.”

The goodwill impairments recorded by the Partnership during the years ended December 31, 2020, 2019 and 2018 represented all of the goodwill within the respective reporting units.

Management does not believe that any of the Partnership’s goodwill balances, long-lived assets or investments in unconsolidated affiliates is currently at significant risk of a material impairment; however, of the $2.39 billion of goodwill on the Partnership’s consolidated balance sheet as of December 31, 2020, approximately $368 million is recorded in reporting units for which the estimated fair value exceeded the carrying value by less than 20% in the most recent quantitative test.

Estimated Useful Lives of Long-Lived Assets. Depreciation and amortization of long-lived assets is provided using the straight-line method based on their estimated useful lives. Changes in the estimated useful lives of the assets could have a material effect on our results of operation. The Partnership’s results of operations have not been significantly impacted by changes in the estimated useful lives of our long-lived assets during the periods presented, and we do not anticipate any such significant changes in the future. However, changes in facts and circumstances could cause us to change the estimated useful lives of the assets, which could significantly impact the Partnership’s results of operations. Additional information on our accounting policies and the estimated useful lives associated with our long-lived assets is available in “Item 8. Financial Statements and Supplementary Data.”

Legal and Regulatory Matters. We are subject to litigation and regulatory proceedings as a result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from claims, orders, judgments or settlements. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. We expense legal costs as incurred, and all recorded legal liabilities are revised, as required, as better information becomes available to us. The factors we consider when recording an accrual for contingencies include, among others: (i) the opinions and views of our legal counsel; (ii) our previous experience; and (iii) the decision of our management as to how we intend to respond to the complaints. As of December 31, 2020 and 2019, accruals of $77 million and $120 million, respectively, were reflected in our consolidated balance sheets related to these contingent obligations.

For more information on our litigation and contingencies, see Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” in this report.

Environmental Remediation Activities. The Partnership’s accrual for environmental remediation activities reflects anticipated work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. The accrual for known claims is undiscounted and is based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. It is often extremely difficult to develop reasonable estimates of future

 

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site remediation costs due to changing regulations, changing technologies and their associated costs, and changes in the economic environment. Engineering studies, historical experience and other factors are used to identify and evaluate remediation alternatives and their related costs in determining the estimated accruals for environmental remediation activities.

Losses attributable to unasserted claims are generally reflected in the accruals on an undiscounted basis, to the extent they are probable of occurrence and reasonably estimable. We have established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.

In general, each remediation site/issue is evaluated individually based upon information available for the site/issue and no pooling or statistical analysis is used to evaluate an aggregate risk for a group of similar items (e.g., service station sites) in determining the amount of probable loss accrual to be recorded. The Partnership’s estimates of environmental remediation costs also frequently involve evaluation of a range of estimates. In many cases, it is difficult to determine that one point in the range of loss estimates is more likely than any other. In these situations, existing accounting guidance requires that the minimum of the range be accrued. Accordingly, the low end of the range often represents the amount of loss which has been recorded. The Partnership’s consolidated balance sheet reflected $306 million and $320 million in environmental accruals as of December 31, 2020 and 2019, respectively.

Total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the nature of operations at each site, the technology available and needed to meet the various existing legal requirements, the nature and terms of cost-sharing arrangements with other potentially responsible parties, the availability of insurance coverage, the nature and extent of future environmental laws and regulations, inflation rates, terms of consent agreements or remediation permits with regulatory agencies and the determination of the Partnership’s liability at the sites, if any, in light of the number, participation level and financial viability of the other parties. The recognition of additional losses, if and when they were to occur, would likely extend over many years. Management believes that the Partnership’s exposure to adverse developments with respect to any individual site is not expected to be material. However, if changes in environmental laws or regulations occur or the assumptions used to estimate losses at multiple sites are adjusted, such changes could impact multiple facilities, formerly owned facilities and third-party sites at the same time. As a result, from time to time, significant charges against income for environmental remediation may occur; however, management does not believe that any such charges would have a material adverse impact on the Partnership’s consolidated financial position.

Deferred Income Taxes. ET recognizes benefits in earnings and related deferred tax assets for net operating loss carryforwards (“NOLs”) and tax credit carryforwards. If necessary, a charge to earnings and a related valuation allowance are recorded to reduce deferred tax assets to an amount that is more likely than not to be realized by the Partnership in the future. Deferred income tax assets attributable to state and federal NOLs and federal excess business interest expense carryforwards totaling $1.047 billion have been included in ET’s consolidated balance sheet as of December 31, 2020. The state NOL carryforward benefits of $220 million ($174 million net of federal benefit) begin to expire in 2021 with a substantial portion expiring between 2033 and 2039. ET’s corporate subsidiaries have federal NOLs of $3.73 billion ($784 million in benefits) of which $1.3 billion will expire between 2031 and 2037. A total of $787 million of the federal net operating loss carryforward is limited under IRC §382. Although we expect to fully utilize the IRC §382 limited federal net operating loss, the amount utilized in a particular year may be limited. Any federal NOL generated in 2018 and future years can be carried forward indefinitely. We have determined that a valuation allowance totaling $113 million ($89 million net of federal income tax effects) is required for state NOLs as of December 31, 2020 primarily due to significant

 

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restrictions on their use in the Commonwealth of Pennsylvania. A separate valuation allowance of $45 million is attributable to foreign tax credits. In making the assessment of the future realization of the deferred tax assets, we rely on future reversals of existing taxable temporary differences, tax planning strategies and forecasted taxable income based on historical and projected future operating results. The potential need for valuation allowances is regularly reviewed by management. If it is more likely than not that the recorded asset will not be realized, additional valuation allowances which increase income tax expense may be recognized in the period such determination is made. Likewise, if it is more likely than not that additional deferred tax assets will be realized, an adjustment to the deferred tax asset will increase income in the period such determination is made.

Forward-Looking Statements

This annual report contains various forward-looking statements and information that are based on our beliefs and those of our General Partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. When used in this annual report, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “could,” “believe,” “may,” “will” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our General Partner believe that the expectations on which such forward-looking statements are based are reasonable, neither we nor our General Partner can give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the key risk factors that may have a direct bearing on our results of operations and financial condition are:

 

   

the ability of our subsidiaries to make cash distributions to us, which is dependent on their results of operations, cash flows and financial condition;

 

   

the actual amount of cash distributions by our subsidiaries to us;

 

   

the volumes transported on our subsidiaries’ pipelines and gathering systems;

 

   

the level of throughput in our subsidiaries’ processing and treating facilities;

 

   

the fees our subsidiaries charge and the margins they realize for their gathering, treating, processing, storage and transportation services;

 

   

the prices and market demand for, and the relationship between, natural gas and NGLs;

 

   

energy prices generally;

 

   

impacts of world health events, including the COVID-19 pandemic;

 

   

the prices of natural gas and NGLs compared to the price of alternative and competing fuels;

 

   

the general level of petroleum product demand and the availability and price of NGL supplies;

 

   

the level of domestic oil, natural gas and NGL production;

 

   

the availability of imported oil, natural gas and NGLs;

 

   

actions taken by foreign oil and gas producing nations;

 

   

the political and economic stability of petroleum producing nations;

 

   

the effect of weather conditions on demand for oil, natural gas and NGLs;

 

   

availability of local, intrastate and interstate transportation systems;

 

   

the continued ability to find and contract for new sources of natural gas supply;

 

   

availability and marketing of competitive fuels;

 

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the impact of energy conservation efforts;

 

   

energy efficiencies and technological trends;

 

   

governmental regulation and taxation;

 

   

changes to, and the application of, regulation of tariff rates and operational requirements related to our subsidiaries’ interstate and intrastate pipelines;

 

   

hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs;

 

   

competition from other midstream companies and interstate pipeline companies;

 

   

loss of key personnel;

 

   

loss of key natural gas producers or the providers of fractionation services;

 

   

reductions in the capacity or allocations of third-party pipelines that connect with our subsidiaries pipelines and facilities;

 

   

the effectiveness of risk-management policies and procedures and the ability of our subsidiaries liquids marketing counterparties to satisfy their financial commitments;

 

   

the nonpayment or nonperformance by our subsidiaries’ customers;

 

   

regulatory, environmental, political and legal uncertainties that may affect the timing and cost of our subsidiaries’ internal growth projects, such as our subsidiaries’ construction of additional pipeline systems;

 

   

risks associated with the construction of new pipelines and treating and processing facilities or additions to our subsidiaries’ existing pipelines and facilities, including difficulties in obtaining permits and rights-of-way or other regulatory approvals and the performance by third-party contractors;

 

   

the availability and cost of capital and our subsidiaries’ ability to access certain capital sources;

 

   

a deterioration of the credit and capital markets;

 

   

risks associated with the assets and operations of entities in which our subsidiaries own a noncontrolling interests, including risks related to management actions at such entities that our subsidiaries may not be able to control or exert influence;

 

   

the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results and to successfully integrate acquired businesses;

 

   

changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations or new interpretations by regulatory agencies concerning such laws and regulations; and

 

   

the costs and effects of legal and administrative proceedings.

You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risks described under “Item 1A. Risk Factors” in this annual report. Any forward-looking statement made by us in this Annual Report on Form 10-K is based only on information currently available to us and speaks only as of the date on which it is made. We undertake no obligation to publicly update any forward-looking statement, whether written or oral, that may be made from time to time, whether as a result of new information, future developments or otherwise.

Inflation

Interest rates on existing and future credit facilities and future debt offerings could be significantly higher than current levels, causing our financing costs to increase accordingly. Although increased financing costs could limit our ability to raise funds in the capital markets, we expect to remain competitive with respect to acquisitions and capital projects since our competitors would face similar circumstances.

 

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Inflation in the United States has been relatively low in recent years and has not had a material effect on our results of operations. It may in the future, however, increase the cost to acquire or replace property, plant and equipment and may increase the costs of labor and supplies. Our operating revenues and costs are influenced to a greater extent by commodity price changes. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along a portion of increased costs to our customers in the form of higher fees.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

(Tabular dollar amounts are in millions)

Market risk includes the risk of loss arising from adverse changes in market rates and prices. We face market risk from commodity variations, risk and interest rate variations, and to a lesser extent, credit risks. From time to time, we may utilize derivative financial instruments as described below to manage our exposure to such risks.

Commodity Price Risk

We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets.

We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized.

We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales on our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes.

We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes.

We utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes.

We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales. These contracts are not designated as hedges for accounting purposes.

We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other segment which are also netted in cost of products sold. As a result of our trading activities and

 

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the use of derivative financial instruments in our transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.

The tables below summarize commodity-related financial derivative instruments, fair values and the effect of an assumed hypothetical 10% change in the underlying price of the commodity as of December 31, 2020 and 2019 for ETO and Sunoco LP, including derivatives related to their respective subsidiaries. Dollar amounts are presented in millions.

 

    December 31, 2020     December 31, 2019  
    Notional
Volume
    Fair Value
Asset
(Liability)
    Effect of
Hypothetical
10% Change
    Notional
Volume
    Fair Value
Asset
(Liability)
    Effect of
Hypothetical
10% Change
 

Mark-to-Market Derivatives

           

(Trading)

           

Natural Gas (BBtu):

           

Fixed Swaps/Futures

    1,603   $ —     $ —       1,483   $ —     $ —  

Basis Swaps IFERC/NYMEX(1)

    (44,225     2     5     (35,208     2     5

Power (Megawatt):

           

Forwards

    1,392,400     4     —         3,213,450     6     8

Futures

    18,706     (1     —         (353,527     1     2

Options—Puts

    519,071     —         —         51,615     1     —    

Options—Calls

    2,343,293     1     —         (2,704,330     1     —    

(Non-Trading)

           

Natural Gas (BBtu):

           

Basis Swaps IFERC/NYMEX

    (29,173     —         1     (18,923     (35     15

Swing Swaps IFERC

    11,208     (2     —         (9,265     —         4

Fixed Swaps/Futures

    (53,575     6     31     (3,085     (1     1

Forward Physical Contracts

    (11,861     4     5     (13,364     3     3

NGL (MBbls)—Forwards/Swaps

    (5,840     (100     39     (1,300     (18     18

Crude (MBbls)—Forwards/Swaps

    —         —         —         4,465     13     2

Refined Products (MBbls)—Futures

    (2,765     (8     3     (2,473     (2     16

Corn (thousand bushels)

    —         —         —         (1,210     —         —    

Fair Value Hedging Derivatives

           

(Non-Trading)

           

Natural Gas (BBtu):

           

Basis Swaps IFERC/NYMEX

    (30,113     (1     —         (31,780     1     7

Fixed Swaps/Futures

    (30,113     (6     8     (31,780     23     7

 

(1)

Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.

The fair values of the commodity-related financial positions have been determined using independent third-party prices, readily available market information and appropriate valuation techniques. Non-trading positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the above tables. Price-risk sensitivities were calculated by assuming a theoretical 10% change (increase or decrease) in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. Results are presented in absolute terms and represent a potential gain or loss in net income or in other comprehensive income. In the event of an actual 10% change in prompt month natural gas prices, the fair value of our total derivative portfolio may not change by 10% due to factors such as when the financial instrument settles and the location to which the financial instrument is tied (i.e., basis swaps) and the relationship between prompt month and forward months.

 

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Interest Rate Risk

As of December 31, 2020, our subsidiaries had $6.72 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of $67 million annually; however, our actual change in interest expense may be less in a given period due to interest rate floors included in our variable rate debt instruments. We manage a portion of our interest rate exposure by utilizing interest rate swaps, including forward-starting interest rate swaps to lock-in the rate on a portion of anticipated debt issuances.

The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes (dollar amounts presented in millions):

 

          Notional Amount Outstanding  

Term

  

Type(1)

   December 31,
2020
     December 31,
2019
 

July 2020(2)(3)

   Forward-starting to pay a fixed rate of 3.52% and receive a floating rate    $ —      $ 400

July 2021(2)

   Forward-starting to pay a fixed rate of 3.55% and receive a floating rate      400      400

July 2022(2)

   Forward-starting to pay a fixed rate of 3.80% and receive a floating rate      400      400

 

(1)

Floating rates are based on 3-month LIBOR.

(2)

Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.

(3)

The July 2020 interest rate swaps were terminated in January 2020.

A hypothetical change of 100 basis points in interest rates for these interest rate swaps would result in a net change in the fair value of interest rate derivatives and earnings (recognized in gains (losses) on interest rate derivatives) of $275 million as of December 31, 2020. For the forward-starting interest rate swaps, a hypothetical change of 100 basis points in interest rates would not affect cash flows until the swaps are settled.

Credit Risk

Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.

The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrial end-users, oil and gas producers, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.

 

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For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The financial statements starting on page F-1 of this report are incorporated by reference.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING

AND FINANCIAL DISCLOSURE

None.

 

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ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

An evaluation was performed under the supervision and with the participation of our management, including Marshall S. McCrea, III and Thomas E. Long, Co-Chief Executive Officers of our General Partner (Co-Principal Executive Officers), and Bradford D. Whitehurst (Principal Financial Officer), of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rules 13a–15(e) and 15d–15(e) of the Exchange Act) as of the end of the period covered by this report. Based upon that evaluation, management, including Messrs. McCrea, Long and Whitehurst, concluded that our disclosure controls and procedures were adequate and effective as of December 31, 2020.

Management’s Report on Internal Control over Financial Reporting

The management of Energy Transfer LP and subsidiaries is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including the Co-Chief Executive Officers and Chief Financial Officer of our General Partner, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal ControlIntegrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO Framework”).

Based on our evaluation under the COSO framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2020.

Grant Thornton LLP, an independent registered public accounting firm, has audited the effectiveness of our internal control over financial reporting as of December 31, 2020, as stated in their report, which is included herein.

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors of LE GP, LLC and

Unitholders of Energy Transfer LP

Opinion on internal control over financial reporting

We have audited the internal control over financial reporting of Energy Transfer LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2020, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Partnership as of and for the year ended December 31, 2020, and our report dated February 19, 2021 expressed unqualified opinion on those financial statements.

Basis for opinion

The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and limitations of internal control over financial reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ GRANT THORNTON LLP

Dallas, Texas

February 19, 2021

 

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Changes in Internal Controls over Financial Reporting

There has been no change in our internal controls over financial reporting (as defined in Rules 13a–15(f) or Rule 15d–15(f)) that occurred in the three months ended December 31, 2020 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

 

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Board of Directors

Our general partner, LE GP, LLC, manages and directs all of our activities. The officers and directors of ET are officers and directors of LE GP, LLC. The members of our general partner elect our general partner’s Board of Directors. The board of directors of our general partner has the authority to appoint our executive officers, subject to provisions in the limited liability company agreement of our general partner. Pursuant to other authority, the board of directors of our general partner may appoint additional management personnel to assist in the management of our operations and, in the event of the death, resignation or removal of our chief executive officer, to appoint a replacement.

As of January 1, 2021, our Board of Directors is comprised of 11 persons, five of whom qualify as “independent” under the NYSE’s corporate governance standards. We have determined that Messrs. Anderson, Brannon, Grimm, Perry and Washburne are all “independent” under the NYSE’s corporate governance standards.

As a limited partnership, we are not required by the rules of the NYSE to seek Unitholder approval for the election of any of our directors. We believe that the members of our general partner have appointed as directors individuals with experience, skills and qualifications relevant to the business of the Parent Company, such as experience in energy or related industries or with financial markets, expertise in natural gas operations or finance, and a history of service in senior leadership positions. We do not have a formal process for identifying director nominees, nor do we have a formal policy regarding consideration of diversity in identifying director nominees, but we believe that the members of our general partner have endeavored to assemble a group of individuals with the qualities and attributes required to provide effective oversight of the Parent Company.

Board Leadership Structure. We have no policy requiring either that the positions of the Chairman of the Board and the Chief Executive Officer, or CEO, be separate or that they be occupied by the same individual. The Board of Directors believes that this issue is properly addressed as part of the succession planning process and that a determination on this subject should be made when it elects a new chief executive officer or at such other times as when consideration of the matter is warranted by circumstances. Previously, the Board of Directors believed that the CEO was best situated to serve as Chairman because he was the director most familiar with the Partnership’s business and industry, and most capable of effectively identifying strategic priorities and leading the discussion and execution of strategy. Beginning in 2021, the Board of Directors has established separate roles for the Executive Chairman and Co-Chief Executive Officers. Independent directors and management have different perspectives and roles in strategy development. Our independent directors bring experience, oversight and expertise from outside the Partnership and from a variety of industries, while the Executive Chairman and Co-Chief Executive Officers bring extensive experience and expertise specifically related to the Partnership’s business.

Risk Oversight. Our Board of Directors generally administers its risk oversight function through the board as a whole. Our Co-CEOs, who report to the Board of Directors, have day-to-day risk management responsibilities. Our Co-CEOs attend the meetings of our Board of Directors, where the Board of Directors routinely receives reports on our financial results, the status of our operations, and other aspects of implementation of our business strategy, with ample opportunity for specific inquiries of management. In addition, at each regular meeting of the Board, management provides a report of the Parent Company’s financial and operational performance, which often prompts questions or feedback from the Board of Directors. The Audit Committee provides additional risk oversight through its quarterly meetings, where it receives a report from the Parent Company’s internal auditor, who reports directly to the Audit Committee, and reviews the Parent Company’s contingencies with management and our independent auditors.

 

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Corporate Governance

The Board of Directors has adopted both a Code of Business Conduct and Ethics applicable to our directors, officers and employees, and Corporate Governance Guidelines for directors and the Board. Current copies of our Code of Business Conduct and Ethics, Corporate Governance Guidelines and charters of the Audit and Compensation Committees of our Board of Directors are available on our website at www.energytransfer.com and will be provided in print form to any Unitholder requesting such information.

Please note that the preceding Internet address is for information purposes only and is not intended to be a hyperlink. Accordingly, no information found and/or provided at such Internet addresses or at our website in general is intended or deemed to be incorporated by reference herein.

Annual Certification

In 2020, our Chief Executive Officer provided to the NYSE the annual CEO certification regarding our compliance with the NYSE’s corporate governance listing standards.

Conflicts Committee

Our Partnership Agreement provides that the Board of Directors may, from time to time, appoint members of the Board to serve on the Conflicts Committee with the authority to review specific matters for which the Board of Directors believes there may be a conflict of interest in order to determine if the resolution of such conflict proposed by the general partner is fair and reasonable to the Parent Company and our Unitholders. As a policy matter, the Conflicts Committee generally reviews any proposed related-party transaction that may be material to the Parent Company to determine if the transaction presents a conflict of interest and whether the transaction is fair and reasonable to the Parent Company. Pursuant to the terms of our partnership agreement, any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to the Parent Company, approved by all partners of the Parent Company and not a breach by the general partner or its Board of Directors of any duties they may owe the Parent Company or the Unitholders. These duties are limited by our Partnership Agreement (see “Risks Related to Conflicts of Interest” in “Item 1A. Risk Factors” in this annual report).

Audit Committee

The Board of Directors has established an Audit Committee in accordance with Section 3(a)(58)(A) of the Exchange Act. The Board of Directors appoints persons who are independent under the NYSE’s standards for audit committee members to serve on its Audit Committee. In addition, the Board determines that at least one member of the Audit Committee has such accounting or related financial management expertise sufficient to qualify such person as the audit committee financial expert in accordance with Item 407(d)(5) of Regulation S-K. The Board determined that based on relevant experience, Audit Committee member Michael K. Grimm qualified as an audit committee financial expert during 2020. A description of the qualifications of Mr. Grimm may be found elsewhere in this Item 10 under “Directors and Executive Officers of the General Partner.”

The Audit Committee meets on a regularly scheduled basis with our independent accountants at least four times each year and is available to meet at their request. The Audit Committee has the authority and responsibility to review our external financial reporting, review our procedures for internal auditing and the adequacy of our internal accounting controls, consider the qualifications and independence of our independent accountants, engage and direct our independent accountants, including the letter of engagement and statement of fees relating to the scope of the annual audit work and special audit work which may be recommended or required by the independent accountants, and to engage the services of any other advisors and accountants as the Audit Committee deems advisable. The Audit Committee reviews and discusses the audited financial statements with management, discusses with our independent auditors matters required to be discussed by auditing standards, and

 

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approves the filing of our Form 10-K, which includes our audited financial statements. The Audit Committee periodically recommends to the Board of Directors any changes or modifications to its charter that may be required. The Audit Committee has received written disclosures and the letter from Grant Thornton required by applicable requirements of the Audit Committee concerning independence and has discussed with Grant Thornton that firm’s independence. The Audit Committee recommended to the Board that the audited financial statements of ET be included in ET’s Annual Report on Form 10-K for the year ended December 31, 2020.

The Board of Directors adopts the charter for the Audit Committee. Steven R. Anderson, Richard D. Brannon and Michael K. Grimm serve as elected members of the Audit Committee.

Compensation and Nominating/Corporate Governance Committees

Although we are not required under NYSE rules to appoint a Compensation Committee or a Nominating/Corporate Governance Committee because we are a limited partnership, the Board of Directors of LE GP, LLC has previously established a Compensation Committee to establish standards and make recommendations concerning the compensation of our officers and directors. In addition, the Compensation Committee determines and establishes the standards for any awards to our employees and officers under the equity compensation plans, including the performance standards or other restrictions pertaining to the vesting of any such awards. Messrs. Anderson, Grimm and Washburne serve as members of the Compensation Committee.

Matters relating to the nomination of directors or corporate governance matters were addressed to and determined by the full Board of Directors for the period ET did not have a compensation committee.

The responsibilities of the ET Compensation Committee include, among other duties, the following:

 

   

annually review and approve goals and objectives relevant to compensation of our CEO and CFO, if applicable;

 

   

annually evaluate the CEO and CFO’s performance in light of these goals and objectives, and make recommendations to the Board of Directors with respect to the CEO and CFO’s compensation levels, if applicable, based on this evaluation;

 

   

make determinations with respect to the grant of equity-based awards to executive officers under ET’s equity incentive plans;

 

   

periodically evaluate the terms and administration of ET’s long-term incentive plans to assure that they are structured and administered in a manner consistent with ET’s goals and objectives;

 

   

periodically evaluate incentive compensation and equity-related plans and consider amendments if appropriate;

 

   

periodically evaluate the compensation of the directors;

 

   

retain and terminate any compensation consultant to be used to assist in the evaluation of director, CEO and CFO or executive officer compensation; and

 

   

perform other duties as deemed appropriate by the Board of Directors.

Code of Business Conduct and Ethics

The Board of Directors has adopted a Code of Business Conduct and Ethics applicable to our officers, directors and employees. Specific provisions are applicable to the co-principal executive officers, principal financial officer, principal accounting officer and controller, or those persons performing similar functions, of our general partner. Amendments to, or waivers from, the Code of Business Conduct and Ethics will be available on our website and reported as may be required under SEC rules. Any technical, administrative or other non-substantive amendments to the Code of Business Conduct and Ethics may not be posted.

 

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Meetings of Non-management Directors and Communications with Directors

Our non-management directors meet in regularly scheduled sessions. Our non-management directors alternate as the presiding director of such meetings.

We have established a procedure by which Unitholders or interested parties may communicate directly with the Board of Directors, any committee of the Board, any of the independent directors, or any one director serving on the Board of Directors by sending written correspondence addressed to the desired person, committee or group to the attention of Sonia Aubé at Energy Transfer LP 8111 Westchester Drive, Suite 600, Dallas, Texas, 75225. Communications are distributed to the Board of Directors, or to any individual director or directors as appropriate, depending on the facts and circumstances outlined in the communication.

Directors and Executive Officers of Our General Partner

The following table sets forth certain information with respect to the executive officers and members of the Board of Directors of our general partner as of February 19, 2021. Executive officers and directors are elected for indefinite terms.

 

Name

  Age    

Position with Our General Partner

Kelcy L. Warren

    65   Executive Chairman of the Board of Directors

Thomas E. Long

    64   Co-Chief Executive Officer and Director (Co-Principal Executive Officer)

Marshall S. (Mackie) McCrea, III

    61   Co-Chief Executive Officer and Director (Co-Principal Executive Officer)

Bradford D. Whitehurst

    46   Chief Financial Officer (Principal Financial Officer)

Matthew S. Ramsey

    65   Chief Operating Officer and Director

Thomas P. Mason

    64   Executive Vice President, General Counsel and President—LNG

A. Troy Sturrock

    50   Senior Vice President and Controller (Principal Accounting Officer)

Steven R. Anderson

    71   Director

Richard D. Brannon

    62   Director

Ray C. Davis

    79   Director

Michael K. Grimm

    66   Director

John W. McReynolds

    70   Director

James R. (Rick) Perry

    70   Director

Ray W. Washburne

    60   Director

Messrs. Warren, McCrea and Ramsey also serve as directors of the board of ETO’s general partner. Mr. Ramsey serves as chairman of the board of the general partner of Sunoco LP, and Mr. Long serves as a director of the board of the general partners of Sunoco LP and of USAC. Mr. Mason and Mr. Whitehurst serve as directors of the general partner of USAC.

Set forth below is biographical information regarding the foregoing officers and directors of our general partner:

Kelcy L. Warren. Mr. Warren serves as Executive Chairman of our general partner. Mr. Warren served as Chief Executive Officer from August 2007 through December 2020. He was appointed Co-Chairman of the Board of Directors of our general partner, effective upon the closing of our IPO, and in August 2007, he became the sole Chairman of the Board of our general partner and the Chief Executive Officer and Chairman of the Board of the general partner of ETO. Prior to that, Mr. Warren had served as Co-Chief Executive Officer and Co-Chairman of the Board of the general partner of ETO since the combination of the midstream and intrastate transportation storage operations of La Grange Acquisition, L.P. and the retail propane operations of Heritage in January 2004. Mr. Warren also served as the Chief Executive Officer of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Prior to the combination of the operations of ETO and Heritage Propane, Mr. Warren served as President of the general partner of ET Company I, Ltd. the entity that operated ETO’s midstream assets before it acquired Aquila, Inc.’s midstream assets, having served in that capacity since 1996. From 1996 to 2000, he also served as a Director of Crosstex Energy, Inc. From 1993 to 1996, he served as

 

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President, Chief Operating Officer and a Director of Cornerstone Natural Gas, Inc. Mr. Warren has more than 30 years of business experience in the energy industry. Mr. Warren was selected to serve as a director and as Executive Chairman because he previously served as Chief Executive Officer and has more than 30 years in the natural gas industry. Mr. Warren also has relationships with chief executives and other senior management at natural gas transportation companies throughout the United States and brings a unique and valuable perspective to the Board of Directors.

Thomas E. Long. Mr. Long has served as the Co-Chief Executive Officer of our general partner since January 2021. Mr. Long served as Chief Financial Officer ET’s general partner from February 2016 until January 2021, and has been a director of our general partner since April 2019. Mr. Long also served as the Chief Financial Officer and as a director of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Long also serves as Chief Financial Officer of ETO and was previously Executive Vice President and Chief Financial Officer of Regency GP LLC from November 2010 to April 2015. From May 2008 to November 2010, Mr. Long served as Vice President and Chief Financial Officer of Matrix Service Company. Prior to joining Matrix, he served as Vice President and Chief Financial Officer of DCP Midstream Partners, LP, a publicly traded natural gas and natural gas liquids midstream business company located in Denver, Colorado. In that position, he was responsible for all financial aspects of the company since its formation in December 2005. From 1998 to 2005, Mr. Long served in several executive positions with subsidiaries of Duke Energy Corp., one of the nation’s largest electric power companies. Mr. Long has served as a director of Sunoco LP since May 2016, and as Executive Chairman of the Board of USAC since April 2018. Mr. Long was selected to serve on our Board of Directors because of his understanding of energy-related corporate finance gained through his extensive experience in the energy industry.

Marshall S. (Mackie) McCrea, III. Mr. McCrea has served as the Co-Chief Executive Officer of our general partner since January 2021. Prior to that he was the President and Chief Commercial Officer of our general partner, having served in that role since October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. Prior to that time, he had been the Group Chief Operating Officer and Chief Commercial Officer of the Energy Transfer family since November 2015. Mr. McCrea has served on the Board of Directors of our general partner since December 2009. Mr. McCrea was appointed as a director of the general partner of ETO in December 2009. Prior to that, he served as President and Chief Operating Officer of ETO’s general partner from June 2008 to November 2015 and President – Midstream from March 2007 to June 2008. Previously he served as the Senior Vice President – Commercial Development since January 2004. In March 2005, Mr. McCrea was named President of La Grange Acquisition LP, ETO’s primary operating subsidiary, after serving as Senior Vice President-Business Development and Producer Services since 1997. Mr. McCrea also served as the Chairman of the Board of Directors of the general partner of Sunoco Logistics Partners L.P. from October 2012 to April 2017. Mr. McCrea was selected to serve as a director because he brings extensive project development and operational experience to the Board. He has held various positions in the natural gas business over the past 25 years and is able to assist the Board of Directors in creating and executing the Partnership’s strategic plan.

Bradford D. Whitehurst. Mr. Whitehurst was appointed Chief Financial Officer of Energy Transfer in January 2021. From August 2014 through December 2020 he served as Executive Vice President – Head of Tax. Prior to joining Energy Transfer, Mr. Whitehurst was a partner in the Washington, DC office of Bingham McCutchen LLP and an attorney in the Washington, DC offices of both McKee Nelson LLP and Hogan & Hartson. Mr. Whitehurst has specialized in partnership taxation and has advised ET and its subsidiaries in his role as outside counsel since 2006. He has served as a member of the board of directors of USAC since April 2018.

Matthew S. Ramsey. Mr. Ramsey was appointed as a director of ET’s general partner in July 2012 and as a director of ETO’s general partner in November 2015. Mr. Ramsey has been the Chief Operating Officer or our general partner since October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P., and currently serves as President and Chief Operating Officer of ETO’s general partner since November 2015. Mr. Ramsey also served as President and Chief Operating Officer and Chairman of the board of directors of

 

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PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Ramsey is also a director of Sunoco LP, having served as chairman of Sunoco LP’s board since April 2015, and of USAC, having served on that board since April 2018. Mr. Ramsey previously served as President of RPM Exploration, Ltd., a private oil and gas exploration partnership, and previously served as a director of RSP Permian, Inc. where he served on the audit and compensation committees. Mr. Ramsey formerly served as President of DDD Energy, Inc. until its sale in 2002. From 1996 to 2000, Mr. Ramsey served as President and Chief Executive Officer of OEC Compression Corporation, Inc., a publicly traded oil field service company, providing gas compression services to a variety of energy clients. Previously, Mr. Ramsey served as Vice President of Nuevo Energy Company, an independent energy company. Additionally, he was employed by Torch Energy Advisors, Inc., a company providing management and operations services to energy companies including Nuevo Energy, last serving as Executive Vice President. Mr. Ramsey joined Torch Energy as Vice President of Land and was named Senior Vice President of Land in 1992. Mr. Ramsey holds a B.B.A. in Marketing from the University of Texas at Austin and a J.D. from South Texas College of Law. Mr. Ramsey is a graduate of Harvard Business School Advanced Management Program. Mr. Ramsey is licensed to practice law in the State of Texas. He is qualified to practice in the Western District of Texas and the United States Court of Appeals for the Fifth Circuit. Mr. Ramsey formerly served as a director of Southern Union Company. Mr. Ramsey was selected to serve based on vast experience in the oil and gas space and ET believes that he provides valuable industry insight as a member of our Board of Directors.

Thomas P. Mason. Mr. Mason became Executive Vice President and General Counsel of the general partner of ET in December 2015, and has served as the Executive Vice President, General Counsel and President—LNG since October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. In February 2021, Mr. Mason assumed leadership responsibility over the Partnership’s new Alternative Energy Group, which focuses on the development of alternative energy projects aimed at continuing to reduce ET’s environmental footprint throughout its operations. Mr. Mason also served as a director of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Mason previously served as Senior Vice President, General Counsel and Secretary of ETO’s general partner from April 2012 to December 2015, as Vice President, General Counsel and Secretary from June 2008 and as General Counsel and Secretary from February 2007. Prior to joining ETO, he was a partner in the Houston office of Vinson & Elkins. Mr. Mason has specialized in securities offerings and mergers and acquisitions for more than 25 years. Mr. Mason also served on the Board of Directors of the general partner of Sunoco Logistics from October 2012 to April 2017 and has served on the Board of Directors of USAC since April 2018.

John W. McReynolds. Mr. McReynolds became Special Advisor to ET in October 2018 and served in that role until February 2021. Prior to that time, Mr. McReynolds served as our President from March 2005 until October 2018. He has served as a Director since August 2005. He served as our Chief Financial Officer from August 2005 to June 2013, and previously served as a Director of ETO’s general partner from August 2001 through May 2010. Mr. McReynolds has been in the energy industry for his entire career. Prior to joining Energy Transfer, Mr. McReynolds was in private law practice for over 20 years, specializing exclusively in energy-related finance, securities, corporations and partnerships, mergers and acquisitions, syndications, and a wide variety of energy-related litigation. His practice dealt with all forms of fossil fuels, and the transportation and handling thereof, together with the financing and structuring of all forms of business entities related thereto. Mr. McReynolds was selected to serve in the indicated roles with the Energy Transfer partnerships because of this extensive background and experience, as well as his many contacts and relationships in the industry.

A. Troy Sturrock. Mr. Sturrock is the Senior Vice President and Controller of our general partner having assumed that role in October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. He has served as the Senior Vice President and Controller of the general partner of ETO since August 2016 and previously served as Vice President and Controller of our General Partner beginning in June 2015. Mr. Sturrock also served as a Senior Vice President of PennTex Midstream Partners, LP’s general partner, from November 2016 until July 2017, and as its Controller and Principal Accounting Officer from January 2017 until July 2017. Mr. Sturrock previously served as Vice President and Controller of Regency GP LLC from February 2008, and in November 2010 was appointed as the principal accounting officer. From June 2006 to

 

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February 2008, Mr. Sturrock served as the Assistant Controller and Director of financial reporting and tax for Regency GP LLC. Mr. Sturrock is a Certified Public Accountant.

Steven R. Anderson. Mr. Anderson was elected to the Board of Directors of our general partner in June 2018 and serves on the audit committee and compensation committee. Mr. Anderson began his career in the energy business in the early 1970’s with Conoco in the Permian Basin area. He then spent some 25 years with ANR Pipeline and its successor, The Coastal Corporation, as a natural gas supply and midstream executive. He later was Vice President of Commercial Operations with Aquila Midstream and, upon the sale of that business to Energy Transfer in 2002, he became a part of the management team there. For the six years prior to his retirement from Energy Transfer in October 2009, he served as Vice President of Mergers and Acquisitions. Since that time, he has been involved in private investments and has served on the boards of directors of the St. John Health System and Saint Simeon’s Episcopal Home in Tulsa, Oklahoma, as well as various other community and civic organizations. Mr. Anderson also served as a member of the board of directors of Sunoco Logistics Partners L.P. from October 2012 until April 2017. Mr. Anderson was selected to serve on our Board of Directors based on his experience in the midstream energy industry generally, and his knowledge of Energy Transfer’s business specifically. Mr. Anderson also brings recent experience on audit and compensation committees of another publicly traded partnership.

Richard D. Brannon. Mr. Brannon was appointed to the Board of Directors of our general partner in March 2016 and has served as the Chairman of the audit committee since April 2016. Mr. Brannon is the CEO of CH4 Energy II, CH4 Energy Six, and CH4 Energy-Finley Utah, LLC, all independent companies focused on horizontal oil and gas development. Mr. Brannon previously served on the board of directors of WildHorse Resource Development from its IPO in December 2016 until June 2018. Mr. Brannon also formerly served on the Board of Directors and as a member of the audit committee and compensation committee of Sunoco LP, Regency, OEC Compression and Cornerstone Natural Gas Corp. He has over 35 years of experience in the energy business, having started his career in 1981 with Texas Oil & Gas. The members of our general partner selected Mr. Brannon to serve as director based on his knowledge of the energy industry and his experience as a director and audit and compensation committee member for other public companies.

Ray C. Davis. Mr. Davis was appointed to the Board of Directors of the general partner of Energy Transfer LP in July 2018 and served on the Board of Directors of Energy Transfer Partners, L.L.C. from February 2018 until July 2018. From February 2013 until February 2018, Mr. Davis was an independent investor. He has also been a principal owner, and served as co-chairman of the board of directors, of the Texas Rangers major league baseball club since August 2010. Mr. Davis previously served on the Board of Directors of Energy Transfer LP (formerly Energy Transfer Equity, L.P.), effective upon the closing of its IPO in February 2006 until his resignation in February 2013. Mr. Davis also served as ETO’s Co-Chief Executive Officer from the combination of the midstream and transportation operations and the retail propane operations in January 2004 until his retirement from these positions in August 2007, and as the Co-Chairman of the Board of Directors of our general partner from January 2004 until June 2011. Mr. Davis also held various executive positions with Energy Transfer prior to 2004. From 1996 to 2000, he served as a Director of Crosstex Energy, Inc. From 1993 to 1996, he served as Chairman of the Board of Directors and Chief Executive Officer of Cornerstone Natural Gas, Inc. Mr. Davis was selected to serve as director based on his over 40 years of business experience in the energy industry and his expertise in the Partnership’s asset portfolio.

Michael K. Grimm. Mr. Grimm was appointed to the Board of Directors of our general partner in October 2018, and has served on the audit committee and compensation committee since that time. Prior to that time, Mr. Grimm served as a director of ETO’s general partner beginning in December 2005, and served on the audit and compensation committee during that time. Mr. Grimm is one of the original founders of Rising Star Energy, L.L.C., a privately held upstream exploration and production company active in onshore continental United States, and served as its President and Chief Executive Officer from 1995 until 2006 when it was sold. Mr. Grimm is currently President of Rising Star Petroleum, LLC. Mr. Grimm was formerly Chairman of the Board of RSP Permian, Inc. (NYSE: RSPP) from January 2014 until June 2018. From November 2018 until it was sold in 2019, Mr. Grimm

 

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served on the Board of Directors of Anadarko Petroleum Corporation. Prior to the formation of Rising Star, Mr. Grimm was Vice President of Worldwide Exploration and Land for Placid Oil Company from 1990 to 1994. Prior to joining Placid Oil Company, Mr. Grimm was employed by Amoco Production Company for thirteen years where he held numerous positions throughout the exploration department in Houston, New Orleans and Chicago. Mr. Grimm has been an active member of the American Association of Professional Landmen, Dallas Wildcat Committee, Dallas Producers Club, and the All-American Wildcatters. He has a B.B.A. from the University of Texas at Austin. Mr. Grimm was selected to serve as a director because of his extensive experience in the energy industry and his service as a senior executive at several energy-related companies, in addition to his contacts in the industry gained through his involvement in energy-related organizations.

James R. (Rick) Perry. Mr. Perry was appointed to the Board of Directors of our general partner in January 2020. He formerly served as U.S. Secretary of Energy from March 2017 until December 2019. Prior to that, he served as the Governor of the State of Texas from 2000 until January 2015. Mr. Perry served as Lieutenant Governor of Texas from 1998 to 2000, and as Agriculture Commissioner from 1991 to 1998. Prior to 1991, he also served in the Texas House of Representatives. Mr. Perry previously served on the Board of Directors of Energy Transfer Operating, L.P. (formerly Energy Transfer Partners, L.P.) from February 2015 until December 2016. Mr. Perry was selected to serve as a director because of his vast experience as an executive in the highest office of state government. In addition, Mr. Perry has been involved in finance and budget planning processes throughout his career in government as a member of the Texas House Appropriations Committee, the Legislative Budget Board and as Governor.

Ray W. Washburne. Mr. Washburne was appointed to the Board of Directors of our general partner in April 2019. He is currently President and Chief Executive Officer of Charter Holdings, Inc., a Dallas-based investment company involved in real estate, restaurants and diversified financial investments. In addition, he currently serves on the President’s Intelligence Advisory Board (PIAB). From August 2017 to February 2019, Mr. Washburne served as the President and Chief Executive Officer of the Overseas Private Investment Corporation (OPIC), the United States government’s development finance institution. From 2000 to 2017, Mr. Washburne served on the board of directors of Veritex Holdings, Inc. (Nasdaq: VBTX), a Texas -based bank holding company that conducts banking activities through its subsidiary, Veritex Community Bank. He has also served as an adjunct professor at the Cox School of Business at Southern Methodist University. Mr. Washburne is also a member of the Republican Governors Association Executive Roundtable, the American Enterprise Institute, the Council on Foreign Relations, and is on the Advisory Board of the United States Southern Command. Mr. Washburne was selected to serve on the Board of Directors because of his expertise in international finance, his relationships in government, and his experience on the board of a publicly traded company.

Compensation of the General Partner

Our general partner does not receive any management fee or other compensation in connection with its management of the Partnership.

Delinquent Section 16(a) Reports

Section 16(a) of the Securities Exchange Act of 1934 requires the directors and executive officers of our general partner, as well as persons who own more than ten percent of the common units representing limited partnership interests in us, to file reports of ownership and changes of ownership on Forms 3, 4 and 5 with the SEC. The SEC regulations also require that copies of these Section 16(a) reports be furnished to us by such reporting persons. Based upon a review of copies of these reports, we believe all applicable Section 16(a) reports were timely filed in 2020.

 

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ITEM 11. EXECUTIVE COMPENSATION

Overview

As a limited partnership, we are managed by our General Partner. Our General Partner is majority owned by Mr. Kelcy Warren.

We own 100% of ETP GP and its general partner, ETP LLC. We refer to ETP GP and ETP LLC together as the “ETP GP Entities.” ETP GP is the general partner of ETO.

Compensation Discussion and Analysis

Named Executive Officers

ET does not have officers or directors. Instead, we are managed by the board of directors of our General Partner, and the executive officers of our General Partner perform all of ET’s management functions. As a result, the executive officers of our General Partner are ET’s executive officers, and their compensation is administered by our General Partner. This Compensation Discussion and Analysis is, therefore, focused on the total compensation of the executive officers of our General Partner as set forth below. The persons we refer to in this discussion as our “named executive officers” are the following:

 

   

Kelcy L. Warren, Executive Chairman and Chief Executive Officer during 2020 (Executive Chairman effective January 1, 2021);

 

   

Thomas E. Long, Chief Financial Officer during 2020 (Co-Chief Executive Officer effective January 1, 2021);

 

   

Marshall S. (Mackie) McCrea, III, President and Chief Commercial Officer during 2020 (Co-Chief Executive Officer effective January 1, 2021);

 

   

Matthew S. Ramsey, Chief Operating Officer; and

 

   

Thomas P. Mason, Executive Vice President, General Counsel and President—LNG.

Effective January 1, 2021, Mr. Warren assumed the role of Executive Chairman, and Messrs. Long and McCrea were appointed Co-Chief Executive Officers.

Bradford D. Whitehurst was appointed Chief Financial Officer of our General Partner effective January 8, 2021. Mr. Whitehurst is excluded from the compensation discussion and analysis and compensation tables herein, as he was not a named executive officer during 2020.

Our Philosophy for Compensation of Executives

In general, our General Partner’s philosophy for executive compensation is based on the premise that a significant portion of each executive’s compensation should be incentive-based or “at-risk” compensation and that executives’ total compensation levels should be highly competitive in the marketplace for executive talent and abilities. Our General Partner seeks a total compensation program for its executive officers, including the named executive officers, that provides for a slightly below the median market annual base compensation (i.e. approximately the 30th to 40th percentile of market) but incentive-based compensation composed of a combination of compensation vehicles to reward both short and long-term performance that are both targeted to pay-out at approximately the top-quartile of market. Our General Partner believes the incentive-based balance is achieved by (i) the payment of annual discretionary cash bonuses that consider the achievement of the Partnership’s financial performance objectives for a fiscal year set at the beginning of such fiscal year and the individual contributions of its executive officers, including the named executive officers to the success of the Partnership and the achievement of the annual financial performance objectives and (ii) the annual grant of time-based restricted unit, phantom unit awards or cash restricted unit awards under the Partnership’s equity incentive

 

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plan(s) or the equity incentive programs of Sunoco LP, as applicable based on the allocation of executive officers awards, including awards to the named executive officers, which awards are intended to provide a longer term incentive and retention value to its key employees to focus their efforts on increasing the market price of its publicly traded units and to increase the cash distribution the Partnership and/or the other affiliated partnerships pay to their respective unitholders.

The Partnership has historically granted restricted unit and/or phantom unit awards (“RSUs”) that vest, based generally upon continued employment, at a rate of 60% after the third year of service and the remaining 40% after the fifth year of service. In 2020, ET also granted cash restricted units (“CRSUs”) that vest, based generally upon continued employment, at a rate of 1/3 annually over a three-year period. For 2020, the awards to employees were generally split equally between RSUs and CRSUs. The Partnership believes that these equity-based incentive arrangements are important in attracting and retaining executive officers and key employees as well as motivating these individuals to achieve stated business objectives. The equity-based compensation reflects the importance our General Partner places on aligning the interests of its named executive officers with those of Unitholders.

As discussed below, our compensation committee and/or the compensation committee of the general partner of Sunoco LP, as applicable, all in consultation with our General Partner, are responsible for the compensation policies and compensation level of our executive officers, including the named executive officers of our General Partner. In this discussion, we refer to our compensation committee as the “ET Compensation Committee.”

For a more detailed description of the compensation to the Partnership’s named executive officers, please see “– Compensation Tables” below.

Distributions to Our General Partner

Our General Partner is majority-owned by Mr. Warren. We pay quarterly distributions to our General Partner in accordance with our partnership agreement with respect to its ownership of its general partner interest as specified in our partnership agreement. The cash distributions we make to our General Partner bear no relationship to the level or components of compensation of our General Partner’s executive officers. Distributions to our General Partner are described in detail in Note 8 to our consolidated financial statements. Our named executive officers also own directly and indirectly certain of our limited partner interests and, accordingly, receive quarterly distributions. Such per unit distributions equal the per unit distributions made to all our limited partners and bear no relationship to the level of compensation of the named executive officers or the services they perform as employees.

For a more detailed description of the compensation of our named executive officers, please see “Compensation Tables” below.

Compensation Philosophy

Our compensation programs are structured to achieve the following:

 

   

reward executives with an industry-competitive total compensation package of base salaries and significant incentive opportunities yielding a total compensation package approaching the top-quartile of the market;

 

   

attract, retain and reward talented executive officers and key management employees by providing total compensation competitive with that of other executive officers and key management employees employed by publicly traded limited partnerships of similar size and in similar lines of business;

 

   

motivate executive officers and key employees to achieve strong financial and operational performance;

 

   

emphasize performance-based, or “at-risk,” compensation; and

 

   

reward individual performance.

 

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Components of Executive Compensation

For the year ended December 31, 2020, the compensation paid to our named executive officers consisted of the following components:

 

   

annual base salary;

 

   

non-equity incentive plan compensation consisting solely of discretionary cash bonuses;

 

   

time-vested restricted/phantom unit awards and cash restricted units under the equity incentive plan(s);

 

   

payment of distribution equivalent rights (“DERs”) on unvested time-based restricted unit awards under our equity incentive plan;

 

   

vesting of previously issued time-based restricted unit and/or phantom unit awards issued pursuant to our equity incentive plans or the equity incentive plans(s) of affiliates; and

 

   

401(k) plan employer contributions.

Methodology

The ET Compensation Committee considers relevant data available to it to assess our competitive position with respect to base salary, annual short-term incentives and long-term incentive compensation for our executive officers, including the named executive officers. The ET Compensation Committee also considers individual performance, levels of responsibility, skills and experience.

Periodically, the ET Compensation Committee engages a third-party independent compensation consultant to provide a full market competitive compensation analysis for compensation levels at peer companies in order to assist in the determination of compensation levels for our executive officers, including the named executive officers. Most recently, Longnecker & Associates (“Longnecker”) evaluated the market competitiveness of total compensation levels of a number of officers of the Partnership to provide market information with respect to compensation of those executives during the year ended December 31, 2019. In particular, the review by Longnecker was designed to (i) evaluate the market competitiveness of total compensation levels for certain members of senior management, including our named executive officers; (ii) assist in the determination of appropriate compensation levels for our senior management, including the named executive officers; and (iii) confirm that our compensation programs were yielding compensation packages consistent with our overall compensation philosophy.

In conducting its review, Longnecker specifically considered the larger size of the combined ET entities from an energy industry perspective. During 2019, Longnecker assisted in the development of the final “peer group” of leading companies in the energy industry that most closely reflect the profile of ET in terms of revenues, assets and market value as well as competition for talent at the senior management level and similarly situated general industry companies with similar revenues, assets and market value. In setting such peer group, the size of ET on a combined basis was considered. As part of the evaluation conducted by Longnecker, a determination was made to focus the analysis specifically on the energy industry peers. This decision was based on a determination that an energy industry peer group provided a more than sufficient amount of comparative data to consider and evaluate total compensation. This focus allowed Longnecker to report on specific industry related data comparing the levels of annual base salary, annual short-term cash bonus and long-term equity incentive awards at industry peer group companies with those of the named executive officers to ensure that compensation of the named executive officers is both consistent with the compensation philosophy and competitive with the compensation for executive officers of these other companies. The identified companies were:

 

Energy Peer Group:

  

•  Conoco Phillips

  

•  Marathon Petroleum Corporation

•  Enterprise Products Partners, L.P.

  

•  Kinder Morgan, Inc.

•  Plains All American Pipeline, L.P.

  

•  The Williams Companies, Inc.

•  Valero Energy Corporation

  

•  Phillips 66

 

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The compensation analysis provided by Longnecker in 2019 covered all major components of total compensation, including annual base salary, annual short-term cash bonus and long-term incentive awards for the senior executives of these companies. In preparing the review materials, Longnecker utilized generally accepted compensation principles as determined by WorldatWork and gathered data from public disclosures of peer companies, including 10-K and proxy data and published survey data from multiple sources that are relevant to ET’s peer group, industry, financial size and operational breadth. The Longnecker review process also included significant engagement with management to fully understand job scope, responsibilities and roles of each of the executive officers, which discussions allow Longnecker the ability to completely evaluate specific aspects of an executive officer’s position to allow for more accurate comparisons.

Following Longnecker’s 2019 review, the ET Compensation Committee reviewed the information provided, including Longnecker’s specific conclusions and recommended considerations for all compensation going forward. The ET Compensation Committee considered and reviewed the results of the study performed by Longnecker to determine if the results indicated that the compensation programs were yielding a competitive total compensation model prioritizing incentive-based compensation and rewarding achievement of short and long-term performance objectives and considered Longnecker’s conclusions and recommendations. While Longnecker found that the Partnership is achieving its stated objectives with respect to the “at-risk” approach, they also found that certain adjustments could be considered moving forward to allow the Partnership to continue to achieve its targeted percentiles on base compensation and incentive compensation (short and long-term). Longnecker’s suggested adjustments as part of the 2019 were not implemented in 2020 as management and the ET Compensation Committee determined to postpone any changes in light of the impacts of the COVID-19 pandemic on ET and on the global energy market.

In addition to the information received as part of Longnecker’s 2019 review, the ET Compensation Committee also utilizes information obtained from other sources in its determination of compensation levels for our named executive officers, such as annual third party surveys, although third party survey data is not used by the ET Compensation Committee to benchmark the amount of total compensation or any specific element of compensation for the named executive officers.

In addition to the 2019 compensation analysis for executive officers, Longnecker also provided advice and feedback on certain other matters, including the appropriateness, targets and composition of the annual equity award pools and the annual bonus awards under the Energy Transfer Annual Bonus Plan (the “Bonus Plan”) and benchmarking on certain non-named executive officer hires and promotions.

In 2020, Longnecker also provided advice and recommendations on the total compensation packages for Messrs. McCrea and Long in connection with their joint appointment as Co-Chief Executive Officers, including with respect to certain one-time equity and cash awards, as applicable.

Base Salary. Base salary is designed to provide for a competitive fixed level of pay that attracts and retains executive officers and compensates them for their level of responsibility and sustained individual performance (including experience, scope of responsibility and results achieved). The salaries of the named executive officers are reviewed on an annual basis. As discussed above, the base salaries of our named executive officers are targeted to yield an annual base salary slightly below the median level of market (i.e. approximately the 30th to 40th percentile of market) and are determined by the ET Compensation Committee after taking into account the recommendations of Mr. Warren.

During the merit review process, the ET Compensation Committee considers the recommendations of Mr. Warren, any relevant compensation study data (with the data aged as appropriate) and the merit increase pool set for all employees of the Partnership and/or its employing affiliates. During 2020, given the challenging conditions within the industry, including the impacts of the COVID-19 pandemic, the ET Compensation Committee did not approve any increases to base salaries of the named executive officers. Thus, 2020 base salaries for the named executive officers were consistent with the prior year amounts: $1,114,555 for

 

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Mr. McCrea; $600,000 for Mr. Long; $696,598 for Mr. Ramsey; and $631,396 for Mr. Mason. Mr. Warren has voluntarily determined that his salary will be $1.00 per year (plus an amount sufficient to cover his allocated payroll deductions for health and welfare benefits).

In connection with their promotions to Co-Chief Executive Officer effective January 1, 2021, the ET Compensation Committee approved increases in the annual base salaries of Messrs. McCrea and Long to $1,300,000.

Annual Bonus. In addition to base salary, the ET Compensation Committee makes determinations whether to make discretionary annual cash bonus awards to executives, including our named executive officers, following the end of the year under the Bonus Plan.

The Bonus Plan is a discretionary annual cash bonus plan available to all employees, including the named executive officers. The purpose of the Bonus Plan is to reward employees for contributions towards the Partnership’s business goals and to aid in motivating employees. The Bonus Plan is administered by the ET Compensation Committee and the ET Compensation Committee has the authority to establish and interpret the rules and regulations relating to the Bonus Plan, to select participants, to determine and approve the size of any actual award amount, to make all determinations, including factual determinations, under the Bonus Plan, and to take all other actions necessary or appropriate for the proper administration of the Bonus Plan.

For each calendar year (the “Performance Period”), the ET Compensation Committee will evaluate and determine an overall funded cash bonus pool based on achievement of (i) an internal Adjusted EBITDA target (“Adjusted EBITDA Target”), (ii) an internal distributable cash flow target (“DCF Target”) and (iii) performance of each department compared to the applicable departmental budget (“Departmental Budget Target”). The Adjusted EBITDA Target and the DCF Target are defined for purposes of the Bonus Plan using the same definitions as used in the Partnership’s audited financial statements included in its annual and quarterly filings on Forms 10-K and 10-Q for the terms Adjusted EBITDA and Distributable Cash Flow. The performance criteria are weighted 60% on the achievement of the Adjusted EBITDA Target, 20% on the achievement of the DCF Target and 20% on the achievement of the Departmental Budget Target (collectively, “Budget Targets”). The total amount of cash to be allocated to the funded bonus pool will range from 0% to 120% for each of the budgeted DCF Target and Adjusted EBITDA Target and will range from 0% to 100% of the Departmental Budget Target. The maximum funding of the bonus pool is 116% of the total pool target and to achieve such funding each of the Adjusted EBITDA and the DCF Target must achieve 120% funding and the Department Budget target must achieve its 100% target. While the funded bonus pool will reflect an aggregation of performance under each target, in the event performance under the Adjusted EBITDA Target is below 80% of its target, no bonus pool will be funded. If the bonus pool is funded, a participant may earn a cash award for the Performance Period based upon the level of attainment of the Budget Targets and his or her individual performance. Awards are paid in cash as soon as practicable after the end of the Performance Period but in no event later than two and one-half months after the end of the Performance Period.

While the achievement of the Budget Targets sets a bonus pool under the Bonus Plan, actual bonus awards are discretionary. These discretionary bonuses, if awarded, are intended to reward our named executive officers for the achievement of the Budget Targets during the Performance Period in light of the contribution of each individual to our profitability and success during such year. The ET Compensation Committee also considers the recommendation of Mr. Warren in determining the specific annual cash bonus amounts for each of the named executive officers. The ET Compensation Committee does not establish its own financial performance objectives in advance for purposes of determining whether to approve any annual bonuses, and it does not utilize any formulaic approach to determine annual bonuses.

For 2020, the ET Compensation Committee approved short-term annual cash bonus pool targets for Mr. McCrea of 160% of his annual base earnings and for Messrs. Long, Ramsey and Mason of 130% of their annual base earnings. The named executive officer bonus pool targets remained the same for the 2020 Performance Period as they were for the 2019 period. In connection with their promotions to Co-Chief Executive Officer effective

 

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January 1, 2021, the ET Compensation Committee established bonus pool targets for Messrs. McCrea and Long of 160% of their annual base earnings.

In respect of a 2020 bonus pool funding, executive management recommended to the Compensation Committee that the bonus be paid at a 0% payout. This recommendation was made in consideration of a number of factors including (i) the challenging conditions within the industry, specifically the impacts of the COVID-19 pandemic on ET and the global energy market; (ii) the impact of market conditions on current capital projects and certain planned future capital growth projects; and (ii) the reduction of quarterly cash distributions payable to ET common unit holders by 50% in 2020. After considering quantitative and qualitative factors, including performance level achieved, the Compensation Committee exercised its negative discretion, to award a 0% payout of the non-equity incentive bonus.

Equity Awards. ET maintains and operates (i) the Second Amended and Restated Energy Transfer LP 2008 Incentive Plan (the “2008 Incentive Plan”); (ii) the Energy Transfer LP 2011 Long-Term Incentive Plan (the “2011 Incentive Plan”); the (iii) Energy Transfer LP 2015 Long-Term Incentive Plan (the “2015 Plan”); (iv) the Amended and Restated Energy Transfer LP Long-Term Incentive Plan (the “ET Plan,” together with the 2008 Incentive Plan, the 2011 Incentive Plan and the 2015 Plan, the “ET Incentive Plans”). The ET Incentive Plans authorize the ET Compensation Committee, in its discretion, to grant awards, as applicable, under each respective plan of RSUs upon such terms and conditions as it may determine appropriate and in accordance with general guidelines as defined by the ET Incentive Plans. ET has generally used time-vested restricted units and/or phantom units as the vehicle for its annual equity awards to eligible employees, including the named executive officers.

In addition, in 2020, ET adopted the Energy Transfer LP Long-Term Cash Restricted Unit Plan (the “CRU Plan”). The CRU Plan authorizes the ET Compensation Committee, in its discretion, to grant awards, as applicable, of CRSUs, upon such terms and conditions as it may determine appropriate and in accordance with general guidelines as defined by the CRU Plan. Like awards from the ET Incentive Plans, awards from the CRU Plan will be used to incentivize and reward eligible employees over a long-term basis, and the CRU Plan is included for purposes of these discussions as an “ET Incentive Plan.”

For 2020, the annual long-term incentive targets set by the ET Compensation Committee for the named executive officers were 900% of annual base salary for Mr. McCrea and 500% of annual base salary for Messrs. Long, Ramsey and Mason. The targets of the named executive officers were the same as the prior year’s targets.

The annual long-term incentive targets are used as the basis to determine the target number of units to be awarded to the eligible participant, including the named executive officers. A multiple of base salary is used to set the pool target, that number is then divided by a weighted average price determined by considering ET’s modified total unitholder return “(TUR”) performance as measured against the average return of ET’s identified peer group over defined time periods. The modified TUR is designed to create a recognition of a performance adjustment to the equity awards based on the prior periods measured to add an element of performance impact in setting grant date value even though the RSUs and CRSUs themselves are a time-vested vehicle. For purposes of establishing an initial price, ET utilizes a 60 trading-day trailing weighted average price of ET common units prior to November 13, 2020. This average trading price is then subject to adjustment when ET’s TUR is more than 5% greater or less than that of its identified peer group. If the TUR analysis yields a result that is within 5% percent of its identified peer group, the ET Compensation Committee will simply use the 60 trading day trailing weighted average price divided by the applicable salary multiple to establish a target pool for each eligible participant, including the named executive officers. If ET’s TUR is outside of the 5% deviation, the 60 trading day trailing weighted average will be adjusted up or down to a maximum of 15% from the trailing weighted average price based on ET’s performance as compared to the identified group. For 2019, the peer group included the following:

 

•  Enterprise Products Partners, L.P.

  

•  Kinder Morgan, Inc.

•  The Williams Companies, Inc.

  

•  Plains All American Pipeline, L.P.

•  Phillips 66 Partners LP

  

•  MPLX LP

 

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For 2020, the Partnership’s TUR underperformed the identified peer group by between 14% and 16% based on the average of the identified three comparison periods: (i) year-to-date 2020, (ii) trailing twelve months, and (iii) full-year 2019. Consequently, the 2020 long-term incentive base price was increased to reduce the total available restricted pool by approximately 15%.

In December 2020, the ET Compensation Committee in consultation with Mr. Warren approved grants of RSUs to Messrs. McCrea, Long, Ramsey and Mason of 746,350 units, 178,550 units, 207,300 units and 234,900 units, respectively. The ET Compensation Committee also approved grants of CRSUs to Messrs. Long, Ramsey and Mason of 178,500, 207,300 and 234,900 units, respectively. As with base salary and annual bonus, Mr. Warren does not accept or receive annual long-term incentive awards.

As more fully described below under “Affiliate and Subsidiary Equity Awards,” for 2020, in discussions between the General Partner, the ET Compensation Committee and the compensation committee of the general partner of Sunoco LP, it was determined that for 2020, Messrs. Long and Ramsey’s awards would be comprised of RSUs and CRSUs under the ET Incentive Plans and RSUs under the Sunoco LP 2018 Long-Term Incentive Plan (the “2018 Sunoco LP Plan”) in consideration of their roles and responsibilities for Sunoco LP and their status, as members of the Boards of Directors of the general partner of Sunoco LP. Messrs. Long and Ramsey’s total 2020 long-term awards were allocated approximately 80% to the ET Incentive Plans and approximately 20% to the 2018 Sunoco LP Plan. The awards of Messrs. McCrea and Mason for 2020 were allocated entirely to the ET Incentive Plans. While Mr. Long likely will not receive future long-term incentive awards under the 2018 Sunoco LP Plan in his role as Co-CEO, it is anticipated that Mr. Ramsey will continue to recognize an aggregation of RSUs and CRSUs under the ET Incentive Plans and the 2018 Sunoco LP Plan, as applicable. For purposes of establishing a pool value for awards to eligible participants, including Messrs. Ramsey and Long, Sunoco LP utilized the same practices in terms of peer group TUR analysis to set a grant date valuation.

The RSUs granted in 2020 provide for incremental vesting over a five-year period, with 60% vesting at the end of the third year and the remaining 40% vesting at the end of the fifth year. Vesting of the awards are generally subject to continued employment through each specified vesting date. The RSU awards entitle the recipients to receive, with respect to each ET unit subject to such award that has not either vested or been forfeited, a DER cash payment promptly following each such distribution by ET to its common unitholders.

The CRSUs granted in 2020 provide for incremental vesting over a three-year period, with 1/3 vesting at the end of each year. Each CRSU entitles the award recipient to receive cash equal to the market value of one ET common unit upon vesting. The CRSU do not include rights to DER cash payments.

In approving the grant of such RSUs and CRSUs, including to the named executive officers, the ET Compensation Committee considered several factors, including the long-term objective of retaining such individuals as key drivers of ET’s future success, the existing level of equity ownership of such individuals and the previous awards to such individuals of equity awards subject to vesting. Vesting of the 2020 awards would accelerate in the event of the death or disability of the recipient, including the named executive officers, or in the event of a change in control of ET as that term is defined under the ET Incentive Plans.

For 2020, Mr. McCrea did not receive an award of CRSUs; instead, he received a special one-time time vested cash award of $5,000,000 payable as follows:

 

   

$1,800,000.00 on December 31, 2020;

 

   

$1,600,000.00 on July 1, 2020; and

 

   

$1,600,00.00 on December 5, 2022.

This amount is intended to approximate 50% of Mr. McCrea’s targeted annual equity award and replace the award of CRSUs made to other named executive officers.

 

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As discussed below under “Potential Payments Upon a Termination or Change of Control,” all outstanding equity awards would automatically accelerate upon a change in control event, which means vesting automatically accelerates upon a change of control irrespective of whether the officer is terminated. In addition, the award agreements for the restricted units and cash restricted units awarded in 2020, as well as other awards outstanding held by Partnership employees, including the named executive officers, also include certain acceleration provisions upon retirement with the ability to accelerate 40% of outstanding unvested awards under the ET Incentive Plans at age 65 and 50% at age 68. These acceleration provisions require that the participant have not less than five (5) years of employment service to the Partnership or an affiliate and require a six (6) month delay in the vesting after retirement pursuant to the requirements of Section 409(A) of the Code.

We believe that permitting the accelerated vesting of equity awards upon a change in control creates an important retention tool for us by enabling employees to realize value from these awards in the event that we undergo a change in control transaction. In addition, we believe permitting acceleration of vesting upon a change in control creates a sense of stability in the course of transactions that could create uncertainty regarding their future employment and encourage these officers to remain focused on their job responsibilities.

Affiliate and Subsidiary Equity Awards. In addition to their roles as officers for ET during 2020, Messrs. Long and Ramsey have certain responsibilities for Sunoco LP, including as members of the Board of Directors of the general partner of Sunoco LP.

The Sunoco LP Compensation Committee in December 2020 approved grants of RSUs to Messrs. Long and Ramsey of 27,800 and 32,300 restricted units, respectively, under the 2018 Sunoco LP Plan. The terms and conditions of the restricted unit to Messrs. Long and Ramsey under the 2018 Sunoco LP Plan, as applicable, were the same and provided for vesting over a five-year period, with 60% vesting at the end of the third year and the remaining 40% vesting at the end of the fifth year, subject generally to continued employment through each specified vesting date. All of the awards would be accelerated in the event of their death, disability, upon a change in control or retirement at ages 65 or 68. The retirement acceleration provisions for these awards under the 2018 Sunoco Plan are the same as the retirement acceleration provisions under ET Incentive Plans with the ability to accelerate at retirement 40% of outstanding unvested awards at age 65 and 50% at age 68.

Special One-Time Awards to Co-Chief Executive Officers. In recognition of their assumption of their new roles as Co-Chief Executive Officers, the ET Compensation Committee approved certain one-time awards to Messrs. McCrea and Long which occurred in 2021 and therefore are not reflected within the executive compensation tables that follow this discussion.

Mr. McCrea received a special one-time award of 241,815 RSUs under the ET Incentive Plans and a special cash payment of $1,625,000 in connection with his appointment as Co-Chief Executive Officer.

Mr. Long received a special one-time award of 483,630 RSUs under the ET Incentive Plans in connection with his appointment as Co-Chief Executive Officer.

The RSU awards to Messrs. McCrea and Long were made at the same grant date valuation and vesting schedules used for the annual equity awards described above under “—Equity Awards” section above. These awards were approved by the ET Compensation Committee on December 30, 2020 to be effective immediately upon Messrs. McCrea and Long assuming their new roles on January 1, 2021 and will be reflected in the 2021 Summary Compensation Tables.

Unit Ownership Guidelines. The Board of Directors of our General Partner has adopted the Executive Unit Ownership Guidelines (the “Guidelines”), which set forth minimum ownership guidelines applicable to certain executives of ET with respect to ET and Sunoco LP common units representing limited partnership interests, as applicable. The applicable Guidelines are denominated as a multiple of base salary, and the amount of common units required to be owned increases with the level of responsibility. Under these Guidelines, the President and

 

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Chief Commercial Officer and the Chief Operating Officer are expected to own common units having a minimum value of five times his base salary, while each of the remaining named executive officers (other than the CEO) are expected to own common units having a minimum value of four times their respective base salary. In addition to the named executive officers, these Guidelines also apply to other covered executives, which executives are expected to own either directly or indirectly in accordance with the terms of the Guidelines, common units having minimum values ranging from two to four times their respective base salary.

The ET Compensation Committee believes that the ownership of ET and/or Sunoco LP common units, as reflected in these Guidelines, is an important means of tying the financial risks and rewards for its executives to ET’s total unitholder return, aligning the interests of such executives with those of Unitholders, and promoting ET’s interest in good corporate governance.

Covered executives are generally required to achieve their ownership level within five years of becoming subject to the Guidelines; however, certain covered executives, based on their tenure as an executive, were required to achieve compliance within two years of the December 2013 effective date of the Guidelines. Thus, compliance with the Guidelines was required for Messrs. McCrea and Mason beginning in December 2015, Mr. Long in December 2018 and Mr. Ramsey in December 2020. As of December 31, 2020, all of the named executive officers were compliant with the Guidelines.

Covered executives may satisfy the Guidelines through direct ownership of ET and/or Sunoco LP common units or indirect ownership by certain immediate family members. Direct or indirect ownership of ET and/or Sunoco LP common units shall count on a one-to-one ratio for purposes of satisfying minimum ownership requirements; however, unvested unit awards may not be used to satisfy the minimum ownership requirements.

Executive officers, including the named executive officers, who have not yet met their respective guideline must retain and hold all common units (less common units sold to cover the executive’s applicable taxes and withholding obligation) received in connection with long-term incentive awards. Once the required ownership level is achieved, ownership of the required common units must be maintained for as long as the covered executive is subject to the Guidelines. However, those individuals who have met or exceeded their applicable ownership level guideline may dispose of the common units in a manner consistent with applicable laws, rules and regulations, including regulations of the SEC and our internal policies, but only to the extent that such individual’s remaining ownership of common units would continue to exceed the applicable ownership level.

Qualified Retirement Plan Benefits. The Energy Transfer LP 401(k) Plan (the “ET 401(k) Plan”) is a defined contribution 401(k) plan, which covers substantially all of our employees, including the named executive officers. Employees may elect to defer up to 100% of their eligible compensation after applicable taxes, as limited under the Internal Revenue Code. We make a matching contribution that is not less than the aggregate amount of matching contributions that would be credited to a participant’s account based on a rate of match equal to 100% of each participant’s elective deferrals up to 5% of covered compensation. During 2020, in response to challenging conditions within the industry, including impacts of the COVID-19 pandemic, ET suspended its 401(k) matching contribution from July 1, 2020 through December 31, 2020. The amounts deferred by the participant are fully vested at all times, and the amounts contributed by the Partnership become vested based on years of service. We provide this benefit as a means to incentivize employees and provide them with an opportunity to save for their retirement.

The Partnership provides a 3% profit sharing contribution to employee 401(k) accounts for all employees with a base compensation below a specified threshold. The contribution is in addition to the 401(k) matching contribution and employees become vested based on years of service. As with the 401(k) matching contributions, ET suspended the profit sharing contribution from July 1, 2020 through December 31, 2020.

Health and Welfare Benefits. All full-time employees, including our named executive officers may participate in ETP GP’s health and welfare benefit programs including medical, dental, vision, flexible spending, life insurance and disability insurance.

 

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Termination Benefits. Our named executive officers do not have any employment agreements that call for payments of termination or severance benefits or that provide for any payments in the event of a change in control of our General Partner; however, the award agreement to the named executive officers under the ET Incentive Plans, the 2018 Sunoco LP Plan and the Sunoco LP 2012 Long-Term Incentive Plan (the “2012 Sunoco LP Plan”) provide for immediate vesting of all unvested restricted unit awards in the event of a (i) change of control, as defined in the plan; (ii) death or (iii) disability, as defined in the applicable plan. Please refer to “Compensation Tables—Potential Payments Upon a Termination or Change of Control” for additional information.

In addition, ETP GP has also adopted the ETP GP Severance Plan and Summary Plan Description effective as of June 12, 2013, (the “Severance Plan”), which provides for payment of certain severance benefits in the event of Qualifying Termination (as that term is defined in the Severance Plan). In general, the Severance Plan provides payment of two weeks of annual base salary for each year or partial year of employment service up to a maximum of fifty-two weeks or one year of annual base salary (with a minimum of four weeks of annual base salary) and up to three months of continued group health insurance coverage. The Severance Plan also provides that we may determine to pay benefits in addition to those provided under the Severance Plan based on special circumstances, which additional benefits shall be unique and non-precedent setting. The Severance Plan is available to all salaried employees on a nondiscriminatory basis; therefore, amounts that would be payable to our named executive officers upon a Qualified Termination have been excluded from “Compensation Tables – Potential Payments Upon a Termination or Change of Control” below.

Energy Transfer LP Non-Qualified Deferred Compensation Plan (the “ET NQDC Plan”) is a deferred compensation plan, which permits eligible highly compensated employees to defer a portion of their salary, bonus, and/or quarterly non-vested phantom unit distribution equivalent income until retirement, termination of employment or other designated distribution event. Each year under the ET NQDC Plan, eligible employees are permitted to make an irrevocable election to defer up to 50% of their annual base salary, 50% of their quarterly non-vested phantom unit distribution income, and/or 50% of their discretionary performance bonus compensation during the following year. Pursuant to the ET NQDC Plan, ET may make annual discretionary matching contributions to participants’ accounts; however, ET has not made any discretionary contributions to participants’ accounts and currently has no plans to make any discretionary contributions to participants’ accounts. All amounts credited under the ET NQDC Plan (other than discretionary credits) are immediately 100% vested. Participant accounts are credited with deemed earnings or losses based on hypothetical investment fund choices made by the participants among available funds.

Participants may elect to have their account balances distributed in one lump sum payment or in annual installments over a period of three or five years upon retirement, and in a lump sum upon other termination events. Participants may also elect to take lump-sum in-service withdrawals five years or longer in the future, and such scheduled in-service withdrawals may be further deferred prior to the withdrawal date. Upon a change in control (as defined in the ET NQDC Plan) of ET, all ET NQDC Plan accounts are immediately vested in full. However, distributions are not accelerated and, instead, are made in accordance with the ET NQDC Plan’s normal distribution provisions unless a participant has elected to receive a change of control distribution pursuant to his deferral agreement. None of our named executive officers currently participate in this plan.

Risk Assessment Related to our Compensation Structure. We believe that the compensation plans and programs for our named executive officers, as well as our other employees, are appropriately structured and are not reasonably likely to result in material risk to us. We believe these compensation plans and programs are structured in a manner that does not promote excessive risk-taking that could harm our value or reward poor judgment. We also believe we have allocated compensation among base salary and short and long-term compensation in such a way as to not encourage excessive risk-taking. In particular, we generally do not adjust base annual salaries for executive officers and other employees significantly from year to year, and therefore the annual base salary of our employees is not generally impacted by our overall financial performance or the financial performance of a portion of our operations. Our subsidiaries generally determine whether, and to what

 

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extent, their respective named executive officers receive a cash bonus based on achievement of specified financial performance objectives as well as the individual contributions of our named executive officers to the Partnership’s success. We and our subsidiaries use restricted units and phantom units rather than unit options for equity awards because restricted units and phantom units retain value even in a depressed market so that employees are less likely to take unreasonable risks to get, or keep, options “in-the-money.” Finally, the time-based vesting over five years for our long-term incentive awards ensures that the interests of employees align with those of Unitholders and our subsidiaries’ unitholders for our long-term performance.

Tax and Accounting Implications of Equity-Based Compensation Arrangements

Deductibility of Executive Compensation

We are a limited partnership and not a corporation for United States federal income tax purposes. Therefore, we believe that the compensation paid to the named executive officers is not subject to the deduction limitations under Section 162(m) of the Internal Revenue Code and therefore is generally fully deductible for United States federal income tax purposes.

Accounting for Non-Cash Compensation

For non-cash compensation arrangements, we record compensation expense over the vesting period of the awards, as discussed further in Note 9 to our consolidated financial statements.

Compensation Committee Interlocks and Insider Participation

Mr. Steven R. Anderson, Mr. Michael K. Grimm and Mr. Ray W. Washburne are the only members of the ET Compensation Committee. During 2020, no member of the ET Compensation Committee was an officer or employee of us or any of our subsidiaries or served as an officer of any company with respect to which any of our executive officers served on such company’s board of directors. Mr. Grimm is not a former employee of ours or any of our subsidiaries. Mr. Anderson was previously an employee of the Partnership until his retirement in October 2009, as discussed in his biographical information included in “Item 10. Directors, Executive Officers and Corporate Governance.”

Report of Compensation Committee

The board of directors of our General Partner has reviewed and discussed the section entitled “Compensation Discussion and Analysis” with the management of ET. Based on this review and discussion, we have recommended that the Compensation Discussion and Analysis be included in this annual report on Form 10-K.

 

  

The Compensation Committee of the

Board of Directors of LE GP, LLC,

general partner of Energy Transfer LP

 

Steven R. Anderson

Michael K. Grimm

Ray W. Washburne

The foregoing report shall not be deemed to be incorporated by reference by any general statement or reference to this annual report on Form 10-K into any filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except to the extent that we specifically incorporate this information by reference, and shall not otherwise be deemed filed under those Acts.

 

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Compensation Tables

Summary Compensation Table

 

Name and Principal Position

  Year     Salary
($)
    Bonus
($)
    Equity
Awards (1)
($)
    Non-Equity
Incentive Plan
Compensation (2)
($)
    Change in
Pension
Value and
Nonqualified
Deferred
Compensation
Earnings ($)
    All Other
Compensation (3)
($)
    Total
($)
 

Kelcy L. Warren (4)

    2020     $ 6,392   $ —     $ —     $ —     $ —     $ —     $ 6,392

Executive Chairman and former Chief Executive Officer

    2019       6,156     —         —         —         —         —         6,156
    2018       6,138     —         —         —         —         —         6,138

Thomas E. Long

    2020       623,077     —         2,781,255     —         —         21,603     3,425,935

Co-Chief Executive Officer and former Chief Financial Officer

    2019       570,869     —         3,352,795     900,000     —         21,544     4,845,208
    2018       537,338     1,000,000     4,251,335     800,000     —         21,294     6,609,967

Marshall S. (Mackie) McCrea, III (5)

    2020       1,157,423     1,800,000     4,597,516     —         —         18,045     7,572,984

Co-Chief Executive Officer and former President and Chief Commercial Officer

    2019       1,094,260     —         8,734,720     1,750,817     —         21,544     11,601,341
    2018       1,059,976     —         7,834,782     1,866,000     —         19,362     10,780,120

Matthew S. Ramsey

    2020       723,390     —         3,229,770     —         —         22,097     3,975,257

Chief Operating Officer

    2019       683,913     —         3,123,186     889,100     —         19,544     4,715,743
    2018       662,486     —         2,818,415     900,000     —         19,294     4,400,195

Thomas P. Mason

    2020       655,680     —         2,609,350     —         —         20,007     3,285,037

Executive Vice President, General Counsel and President—LNG

    2019       619,899     —         2,749,440     805,900     —         19,544     4,194,783
    2018       600,477     —         2,466,882     858,700     —         19,294     3,945,353

 

(1)

Equity award amounts reflect the aggregate grant date fair value of unit awards granted for the periods presented, computed in accordance with FASB ASC Topic 718, disregarding any estimates for forfeitures. For Messrs. Long and Ramsey amounts include equity awards of our subsidiary, Sunoco LP, as reflected in the “Grants of Plan-Based Awards Table.” See Note 9 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for additional assumptions underlying the value of the equity awards. Although the CRSU awards may only be settled in cash, they are based upon the value of ET common units and are accounted for as equity awards within these compensation tables.

(2)

ET maintains the Bonus Plan which provides for discretionary bonuses. Awards of discretionary bonuses are tied to achievement of targeted performance objectives and described in the Compensation Discussion and Analysis.

(3)

The amounts reflected for 2020 in this column include (i) matching contributions to the ET 401(k) Plan made on behalf of the named executive officers of $13,846 for Mr. Long, $10,288 for Mr. McCrea and $14,250 each for Messrs. Ramsey and Mason, and (ii) health savings account contributions made on behalf of the named executive officers of $2,000 each for Messrs. Long and McCrea, and (iii) the dollar value of life insurance premiums paid for the benefit of the named executive officers. The amounts reflected for all periods exclude distribution payments in connection with distribution equivalent rights on unvested unit awards, because the dollar value of such distributions are factored into the grant date fair value reported in the “Equity Awards” column of the Summary Compensation Table at the time that the unit awards and distribution equivalent rights were originally granted. For 2020, distribution payments in connection with distribution equivalent rights totaled $913,658 for Mr. Long, $2,284,899 for Mr. McCrea, $916,013 for Mr. Ramsey, and $774,910 for Mr. Mason.

(4)

Mr. Warren has voluntarily determined that his salary will be reduced to $1.00 per year (plus an amount sufficient to cover his allocated payroll deductions for health and welfare benefits). He also does not accept a cash bonus or any equity or incentive awards under any applicable incentive plans.

(5)

The amounts reflected in the bonus column for Mr. McCrea represents the first payment of Mr. McCrea’s time-vested cash award, which award represents 50% of Mr. McCrea’s total equity award target. This amount was paid on December 31, 2020.

 

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Grants of Plan-Based Awards in 2020

 

Name   Grant Date     All Other Unit
Awards:
Number of Units
(#)
    Grant Date
Fair Value of
Unit
Awards (1)
 

ET Unit Awards:

     

Kelcy L. Warren

    N/A       —       $ —  

Thomas E. Long

    12/30/2020       178,550     1,099,868

Marshal S. (Mackie) McCrea, III

    12/30/2020       746,350     4,597,516

Matthew S. Ramsey

    12/30/2020       207,300     1,276,968

Thomas P. Mason

    12/30/2020       234,900     1,446,984

ET Cash Restricted Unit Awards:

     

Thomas E. Long

    12/30/2020       178,550     883,527

Matthew S. Ramsey

    12/30/2020       207,300     1,025,792

Thomas P. Mason

    12/30/2020       234,900     1,162,366

Sunoco LP Unit Awards:

     

Thomas E. Long

    12/30/2020       27,800     797,860

Matthew S. Ramsey

    12/30/2020       32,300     927,010

 

(1) 

We have computed the grant date fair value of unit awards in accordance with FASB ASC Topic 718, as further described above and in Note 9 to our consolidated financial statements. For ET cash restricted unit awards, the grant date fair value is discounted for the expected distribution yield during the vesting period, as those awards do not include distribution equivalent rights.

Narrative Disclosure to Summary Compensation Table and Grants of the Plan-Based Awards Table

A description of material factors necessary to understand the information disclosed in the tables above with respect to salaries, bonuses, equity awards, and 401(k) plan contributions can be found in the Compensation Discussion and Analysis that precedes these tables.

 

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Outstanding Equity Awards at 2020 Fiscal Year-End

 

Name

   Grant Date (1)      Unit Awards (1)  
   Number of Units That
Have Not Vested (2)

(#)
     Market or Payout Value of Units
That Have Not Vested (3)

($)
 

ET Unit Awards:

        

Kelcy L. Warren

     N/A        —        $ —  

Thomas E. Long

     12/30/2020        178,550      1,103,439
     12/16/2019        215,000      1,328,700
     12/18/2018        136,475      843,416
     10/19/2018        115,200      711,936
     12/20/2017        48,430      299,297
     12/29/2016        30,236      186,858

Marshal S. (Mackie) McCrea, III

     12/30/2020        746,350      4,612,443
     12/16/2019        682,400      4,217,232
     12/18/2018        605,740      3,743,473
     12/20/2017        214,952      1,328,403
     12/29/2016        172,231      1,064,388

Matthew S. Ramsey

     12/30/2020        207,300      1,281,114
     12/16/2019        189,600      1,171,728
     12/18/2018        168,260      1,039,847
     12/20/2017        89,564      553,506
     12/29/2016        73,440      453,859

Thomas P. Mason

     12/30/2020        234,900      1,451,682
     12/16/2019        214,800      1,327,464
     12/18/2018        190,640      1,178,155
     12/20/2017        54,120      334,462
     12/29/2016        40,645      251,186

ET Cash Restricted Unit Awards:

        

Thomas E. Long

     12/30/2020        178,550      887,058

Matthew S. Ramsey

     12/30/2020        207,300      1,029,892

Thomas P. Mason

     12/30/2020        234,900      1,167,012

Sunoco LP Unit Awards:

        

Thomas E. Long

     12/30/2020        27,800      800,084
     12/16/2019        19,500      561,210
     12/19/2018        19,325      556,174
     12/21/2017        6,839      196,826
     12/29/2016        8,884      255,682

Matthew S. Ramsey

     12/30/2020        32,300      929,594
     12/16/2019        22,600      650,428
     12/19/2018        23,825      685,684

Thomas P. Mason

     12/21/2017        7,643      219,966
     12/29/2016        9,320      268,230

 

(1)

Certain of these outstanding awards represent former Energy Transfer Partners, L.P. awards that converted into ET awards upon the merger of Energy Transfer Equity, L.P. (now named Energy Transfer LP) and Energy Transfer Partners, L.P. (now named Energy Transfer Operating, L.P.) in October 2018. Furthermore, some of those converted awards had previously been converted in connection with the merger of Energy Transfer Partners, L.P. and Sunoco Logistics Partners L.P. in April 2017.

(2)

ET and Sunoco LP unit awards outstanding vest as follows:

 

   

at a rate of 60% in December 2023 and 40% in December 2025 for awards granted in December 2020;

 

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at a rate of 60% in December 2022 and 40% in December 2024 for awards granted in December 2019;

 

   

at a rate of 60% in December 2021 and 40% in December 2023 for awards granted in October and December 2018;

 

   

100% in December 2022 for the remaining outstanding portion of awards granted in December 2017; and

 

   

100% in December 2021 for the remaining outstanding portion of awards granted in December 2016.

Such awards may be settled at the election of the ET Compensation Committee in (i) common units of ET (subject to the approval of the ET Incentive Plans prior to the first vesting date by a majority of Unitholders pursuant to the rules of the New York Stock Exchange); (ii) cash equal to the Fair Market Value (as such term is defined in the ET Incentive Plans) of the ET common units that would otherwise be delivered pursuant to the terms of each named executive officers grant agreement; or (iii) other securities or property in an amount equal to the Fair Market Value of ET common units that would otherwise be delivered pursuant to the terms of the grant agreement, or a combination thereof as determined by the ET Compensation Committee in its discretion.

ET cash restricted unit awards granted in December 2020 vest 1/3 per year in December 2021, 2022 and 2023.

 

(3)

Market value was computed as the number of unvested awards as of December 31, 2020 multiplied by the closing price of respective common units of ET and Sunoco LP. For ET cash restricted unit awards, the grant date fair value is discounted for the expected distribution yield during the vesting period, as those awards do not include distribution equivalent rights.

Units Vested in 2020

 

    Unit Awards  

Name

  Number of Units
Acquired on Vesting
(#)
    Value Realized
on Vesting

($) (1)
 

ET Unit Awards:

   

Kelcy L. Warren

    N/A     $ —  

Thomas E. Long

    92,610     641,787

Marshall S. (Mackie) McCrea, III

    465,098     3,223,129

Matthew S. Ramsey

    193,626     1,341,828

Thomas P. Mason

    114,858     795,966

Sunoco LP Unit Awards:

   

Thomas E. Long

    15,908     459,900

Matthew S. Ramsey

    814     25,584

Thomas P. Mason

    18,873     545,618

 

(1)

Amounts presented represent the value realized upon vesting of these awards, which is calculated as the number of units vested multiplied by the applicable closing market price of applicable common units upon the vesting date.

We have not issued option awards.

Potential Payments Upon a Termination or Change of Control

Equity Awards. As discussed in our Compensation Discussion and Analysis above, any unvested equity awards (including cash restricted unit awards) granted pursuant the ET Incentive Plans will automatically become vested upon a change of control, which is generally defined as the occurrence of one or more of the following events: (i) any person or group becomes the beneficial owner of 50% or more of the voting power or voting securities of

 

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ET or its general partner; (ii) LE GP, LLC or an affiliate of LE GP, LLC ceases to be the general partner of ET; or (iii) the sale or other disposition, including by liquidation or dissolution, of all or substantially all of the assets of ET in one or more transactions to anyone other than an affiliate of ET.

In addition, as explained in Equity Awards section of our Compensation Discussion and Analysis above, the restricted unit awards, phantom unit awards and cash restricted unit awards under the ET Incentive Plans, the Sunoco LP Plan and the 2012 Sunoco LP Plan generally require the continued employment of the recipient during the vesting period, provided however, the unvested awards will be accelerated in the event of the death or disability of the award recipient prior to the applicable vesting period being satisfied. All awards outstanding to the named executive officers under the ET Incentive Plans, the 2018 Sunoco LP Plan or the 2012 Sunoco LP Plan would be accelerated in the event of a change in control of the Partnership.

The October 2018 equity award to Mr. Long included a provision in the applicable award agreement for acceleration of unvested restricted unit/restricted phantom unit awards upon a termination of employment by the general partner of the applicable partnership issuing the award without “cause.” For purposes of the awards the term “cause” shall mean: (i) a conviction (treating a nolo contendere plea as a conviction) of a felony (whether or not any right to appeal has been or may be exercised), (ii) willful refusal without proper cause to perform duties (other than any such refusal resulting from incapacity due to physical or mental impairment), (iii) misappropriation, embezzlement or reckless or willful destruction of property of the partnership or any of its affiliates, (iv) knowing breach of any statutory or common law duty of loyalty to the partnership or any of its or their affiliates, (v) improper conduct materially prejudicial to the business of the partnership or any of its or their affiliates, (vi) material breach of the provisions of any agreement regarding confidential information entered into with the partnership or any of its or their affiliates or (vii) the continuing failure or refusal to satisfactorily perform essential duties to the partnership or any of its or their affiliates.

In addition, the ET Compensation Committee and the compensation committee of the general partner of Sunoco LP, have approved a retirement provision, which provides that employees, including the named executive officers with at least ten years of service with the general partner, who leave the respective general partner voluntarily due to retirement (i) after age 65 but prior to age 68 are eligible for accelerated vesting of 40% of his or her award; or (ii) after 68 are eligible for accelerated vesting of 50% his or her award. The acceleration of the awards is subject to the applicable provisions of IRC Section 409(A).

Mr. Mason previously received a one-time special incentive retention bonus, for which he would be obligated to repay $3,150,000 if his employment terminates (other than as a result of (x) a termination without cause by ET or by Mr. Mason for Good Reason; (y) his death; or (z) his permanent disability) prior to February 24, 2021.

Deferred Compensation Plan. As discussed in our Compensation Discussion and Analysis above, all amounts under the ET NQDC Plan (other than discretionary credits) are immediately 100% vested. Upon a change of control (as defined in the ET NQDC Plan), distributions from the respective plan would be made in accordance with the normal distribution provisions of the respective plan. A change of control is generally defined in the ET NQDC Plan as any change of control event within the meaning of Treasury Regulation Section 1.409A-3(i)(5).

CEO Pay Ratio

In accordance with Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) of Regulation S-K, set forth below is information about the relationship of the annual total compensation of Mr. Warren, the Chairman and Chief Executive Officer and the annual total compensation of our employees.

For the 2020 calendar year, the annual total compensation of Mr. Warren, as reported in the Summary Compensation Table of this Item 11 was $6,392.

 

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The median total compensation of the employees supporting the Partnership (other than Mr. Warren) was $110,358 for 2020.

Based on this information, for 2020 the ratio of the annual total compensation of Mr. Warren to the median of the annual total compensation of the 8,149 employees supporting ETO as of December 31, 2020 was approximately 1 to 17 as Mr. Warren has voluntarily elected not to accept any salary, bonus or equity incentive compensation (other than a salary of $1.00 per year plus an amount sufficient to cover his allocated employee premium contributions for health and welfare benefits).

To identify the median of the annual total compensation of the employees supporting the Partnership, the following steps were taken:

 

1.

It was determined that, as of December 31, 2020, the applicable employee populations consisted of 8,149 with all of the identified individuals being employed in the United States. This population consisted of all of our full-time and part-time employees. We did not engage any independent contractors in 2020 that are required to be included in our employee population for the CEO pay ratio evaluation.

 

2.

To identify the “median employee” from our employee population, we compared the total earnings of our employees as reflected in our payroll records as reported on Form W-2 for 2020.

 

3.

We identified our median employee using W-2 reporting and applied this compensation measure consistently to all of our employees required to be included in the calculation. We did not make any cost of living adjustments in identifying the “median employee.”

 

4.

Once we identified our median employee, we combined all elements of the employee’s compensation for 2020 resulting in an annual compensation of $110,358. The difference between such employee’s total earnings and the employee’s total compensation represents the estimated value of the employee’s health care benefits (estimated for the employee and such employee’s eligible dependents at $11,119) and the employee’s 401(k) matching contribution and profit sharing contribution (estimated at $3,130 per employee, includes $1,972 per employee on average matching contribution and $1,158 per employee on average profit sharing contribution (employees earning over $175,000 in base are ineligible for profit sharing)).

 

5.

With respect to Mr. Warren, we used the amount reported in the “Total” column of our 2020 Summary Compensation Table under this Item 11.

Director Compensation

In 2020, the compensation arrangements for outside directors included a $100,000 annual retainer for services on the board. If a director served on the ET Audit Committee, such director would receive an annual cash retainer ($15,000 or $25,000 in the case of the chairman). If a director served on the ET Compensation Committee, such director would receive an annual cash retainer ($7,500 or $15,000 in the case of the chairman). The fees for membership on the Conflicts Committee are determined on a per instance basis for each committee assignment.

The outside directors of our General Partner are also entitled to an annual restricted unit award under the ET Incentive Plans equal to an aggregate of $100,000 divided by the closing price of ET common units on the date of grant. These ET common units will vest 60% after the third year and the remaining 40% after the fifth year after the grant date. The compensation expense recorded is based on the grant-date market value of the ET common units and is recognized over the vesting period. Distributions are paid during the vesting period.

 

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The compensation paid to the non-employee directors of our General Partner in 2020 is reflected in the following table:

 

Name

   Fees Paid in
Cash(1)

($)
     Unit Awards(2)
($)
     All Other
Compensation
($)
     Total
($)
 

Steven R. Anderson

   $ 122,500    $ 99,997    $ —      $ 222,497

Richard D. Brannon

     125,000      99,997      —          224,997

Ray C. Davis

     100,000      99,997      —          199,997

Michael K. Grimm

     130,000      99,997      —          229,997

James R. Perry (3)

     75,000      99,997      —          174,997

Ray W. Washburne

     107,500      99,997      —          207,497

 

(1)

Fees paid in cash are based on amounts paid during the period.

(2)

Equity award amounts reflect the aggregate grant date fair value of unit awards granted for the periods presented, computed in accordance with FASB ASC Topic 718, disregarding any estimates for forfeitures. See Note 9 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for additional assumptions underlying the value of the equity awards.

(3)

Mr. Perry was appointed as a director of our General Partner on January 1, 2020.

As of December 31, 2020, Mr. Anderson had 17,543 unvested ET restricted units outstanding, Mr. Brannon had 23,767 unvested ET restricted units outstanding, Mr. Davis had 17,543 unvested ET restricted units outstanding, Mr. Grimm had 26,259 unvested ET restricted units outstanding, Mr. Perry had 9,996 unvested ET restricted units outstanding and Mr. Washburne had 9,996 unvested ET restricted units outstanding.

 

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

Equity Compensation Plan Information

The following table sets forth in tabular format, a summary of our equity plan information as of December 31, 2020:

 

Plan Category

   Number of securities to
be issued upon exercise
of outstanding options,
warrants and rights
(a)
     Weighted-average
exercise price of
outstanding options,
warrants and rights
(b)
     Number of securities
remaining available for
future issuance under
equity compensation plans
(excluding securities
reflected in column (a))
(c)
 

Equity compensation plans approved by security holders

     —        $ —        —    

Equity compensation plans not approved by security holders:

     29,451,869      —          34,298,844
  

 

 

    

 

 

    

 

 

 

Total

     29,451,869    $ —        34,298,844
  

 

 

    

 

 

    

 

 

 

Energy Transfer LP Units

The following table sets forth certain information as of February 12, 2021, regarding the beneficial ownership of our voting securities by (i) certain beneficial owners of more than 5% of our Common Units, (ii) each director and named executive officer of our General Partner and (iii) all current directors and executive officers of our General Partner as a group. The General Partner knows of no other person not disclosed herein who beneficially owns more than 5% of our Common Units.

 

Name and Address of

Beneficial Owner (1)

   Beneficially
Owned (2)
     Percent of Class  

Kelcy L. Warren (3)

     259,940,845      9.6

Ray C. Davis (4)

     89,974,506      3.3

Thomas E. Long

     395,231                

Marshall S. (Mackie) McCrea, III

     2,430,302                

Matthew S. Ramsey

     428,745                

Thomas P. Mason

     598,760                

Bradford D. Whitehurst (5)

     280,681                

Richard D. Brannon (6)

     396,504                

Steven R. Anderson (7)

     1,544,618                

Michael K. Grimm (8)

     131,573                

John W. McReynolds (9)

     30,225,200      1.1

James R. Perry

     120,020                

Ray W. Washburne (10)

     100,040                

All Directors and Executive Officers as a group (14 persons)

     386,634,279      14.3

 

*

Less than 1%

(1)

The address for Mr. Davis is 5950 Sherry Lane, Dallas, Texas 75225. The address for all other listed beneficial owners is 8111 Westchester Drive, Suite 600, Dallas, Texas 75225.

(2)

Beneficial ownership for the purposes of this table is defined by Rule 13d-3 under the Exchange Act of 1934. Under that rule, a person is generally considered to be the beneficial owner of a security if he has or shares the power to vote or direct the voting thereof or to dispose or direct the disposition thereof or has the

 

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  right to acquire either of those powers within sixty days. The nature of beneficial ownership for all listed persons is direct with sole investment and disposition power unless otherwise noted. The beneficial ownership of each listed person is based on 2,702,436,307 common units outstanding in the aggregate as of February 12, 2021.
(3)

Includes 104,276,511 common units held by Kelcy Warren Partners, L.P. and 10,244,429 common units held by Kelcy Warren Partners II, L.P., the general partners of which are owned by Mr. Warren. Also includes 97,577,803 common units held by Kelcy Warren Partners III, LLC formerly known as Seven Bridges Holdings, LLC, of which Mr. Warren is a member. Also includes 328,383 common units attributable to the interest of Mr. Warren in ET Company Ltd and Three Dawaco, Inc., over which Mr. Warren exercises shared voting and dispositive power with Ray Davis. Also includes 601,076 common units held by LE GP, LLC. Mr. Warren may be deemed to own common units held by LE GP, LLC due to his ownership of 81.2% of its member interests. The voting and disposition of these common units is directly controlled by the board of directors of LE GP, LLC. Mr. Warren disclaims beneficial ownership of common units owned by LE GP, LLC other than to the extent of his interest in such entity. Also includes 104,166 common units held by Mr. Warren’s spouse.

(4)

Includes 51,701 Common Units held by Avatar Holdings LLC, 1,941,721 common units held by Avatar BW, Ltd., 28,203,003 common units held by Avatar ETC Stock Holdings LLC, 3,557,757 common units held by Avatar Investments LP, 121,117 common units held by Avatar Stock Holdings, LP and 1,112,069 common units held by RCD Stock Holdings, LLC, all of which entities are owned or controlled by Mr. Davis. Also includes 15,987,283 common units held by a remainder trust for Mr. Davis’ spouse and 9,536,054 Common Units held by two trusts for the benefit of Mr. Davis’ grandchildren, for which Mr. Davis serves as trustee. Mr. Davis shares voting and dispositive power with his wife with respect to common units held directly. Also includes 328,383 common units attributable to ET Company Ltd. Mr. Davis is a former executive officer and director of ETO and is currently a director of the general partner of ET, LE GP, LLC.

(5)

Includes 186,898 common units held by Mr. Whitehurst in a margin account.

(6)

Includes 337,820 common units held by B4 Capital Investments, LP, a limited partnership of which a limited liability company owned by Mr. Brannon and his wife is the sole general partner and of which Mr. Brannon and his wife are the sole limited partners.

(7)

Includes 1,544,558 common units held by Steven R. Anderson Revocable Trust, for which Mr. Anderson serves as trustee. As of December 31, 2020, 603,100 common units were pledged as collateral.

(8)

Includes 6,660 common units held by two trusts for the benefit of Mr. Grimm’s children, for which Mr. Grimm serves as trustee.

(9)

Includes 17,445,608 common units held by McReynolds Energy Partners L.P. and 12,142,593 common units held by McReynolds Equity Partners L.P., the general partners of which are owned by Mr. McReynolds. Mr. McReynolds disclaims beneficial ownership of common units owned by such limited partnerships other than to the extent of his interest in such entities.

(10)

Includes 2,090 common units held by Mr. Washburne’s wife.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

As of December 31, 2020, our interests in ETO consisted of 100% of the general partner interests and 2,458,702,066 ETO common units.

The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETO, Sunoco LP and USAC, all of which are limited partnerships engaged in diversified energy-related services, and cash flows from the operations of Lake Charles LNG.

Mr. McCrea and Mr. Ramsey, current directors of LE GP, LLC, our general partner, are also directors and executive officers of ETO’s general partner. Mr. Long, also currently a director of LE GP, LLC, is also an

 

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executive officer of ETO’s general partner. In addition, Mr. Warren, our Executive Chairman, is also the Executive Chairman of ETO’s general partner.

For a discussion of director independence, see “Item 10. Directors, Executive Officers and Corporate Governance.”

As a policy matter, our Conflicts Committee generally reviews any proposed related party transaction that may be material to the Partnership to determine whether the transaction is fair and reasonable to the Partnership. The Partnership’s board of directors makes the determinations as to whether there exists a related party transaction in the normal course of reviewing transactions for approval as the Partnership’s board of directors is advised by its management of the parties involved in each material transaction as to which the board of directors’ approval is sought by the Partnership’s management. In addition, the Partnership’s board of directors makes inquiries to independently ascertain whether related parties may have an interest in the proposed transaction. While there are no written policies or procedures for the board of directors to follow in making these determinations, the Partnership’s board makes those determinations in light of its contractually-limited fiduciary duties to the Unitholders. The partnership agreement of ET provides that any matter approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to ET, approved by all the partners of ET and not a breach by the General Partner or its Board of Directors of any duties they may owe ET or the Unitholders (see “Risks Related to Conflicts of Interest” in “Item 1A. Risk Factors” in this annual report).

The Parent Company has agreements with subsidiaries to provide or receive various general and administrative services. The Parent Company pays ETO to provide services on its behalf and the behalf of other subsidiaries of the Parent Company. The Parent Company receives management fees from certain of its subsidiaries, which include the reimbursement of various general and administrative services for expenses incurred by ETO on behalf of those subsidiaries. All such amounts have been eliminated in our consolidated financial statements.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following sets forth fees billed by Grant Thornton LLP for the audit of our annual financial statements and other services rendered (dollars in millions):

 

     Years Ended
December 31,
 
     2020      2019  

Audit fees (1)

   $ 10.7    $ 11.6

Audit-related fees

     —          0.1
  

 

 

    

 

 

 

Total

   $ 10.7    $ 11.7
  

 

 

    

 

 

 

 

(1)

Includes fees for audits of annual financial statements of our companies, reviews of the related quarterly financial statements, and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the SEC and services related to the audit of our internal control over financial reporting.

Pursuant to the charter of the Audit Committee, the Audit Committee is responsible for the oversight of our accounting, reporting and financial practices. The Audit Committee has the responsibility to select, appoint, engage, oversee, retain, evaluate and terminate our external auditors; pre-approve all audit and non-audit services to be provided, consistent with all applicable laws, to us by our external auditors; and establish the fees and other compensation to be paid to our external auditors. The Audit Committee also oversees and directs our internal auditing program and reviews our internal controls.

The Audit Committee has adopted a policy for the pre-approval of audit and permitted non-audit services provided by our principal independent accountants. The policy requires that all services provided by Grant

 

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Thornton LLP including audit services, audit-related services, tax services and other services, must be pre-approved by the Audit Committee. All fees paid or expected to be paid to Grant Thornton LLP for fiscal years 2020 and 2019 were pre-approved by the Audit Committee in accordance with this policy.

The Audit Committee reviews the external auditors’ proposed scope and approach as well as the performance of the external auditors. It also has direct responsibility for and sole authority to resolve any disagreements between our management and our external auditors regarding financial reporting, regularly reviews with the external auditors any problems or difficulties the auditors encountered in the course of their audit work, and, at least annually, uses its reasonable efforts to obtain and review a report from the external auditors addressing the following (among other items):

 

   

the auditors’ internal quality-control procedures;

 

   

any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors;

 

   

the independence of the external auditors;

 

   

the aggregate fees billed by our external auditors for each of the previous two years; and

 

   

the rotation of the lead partner.

 

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

The following documents are filed as a part of this Report:

 

     Page  

(1) Financial Statements—see Index to Financial Statements

     C-198  

(2) Financial Statement Schedules—None

  

(3) Exhibits—see Index to Exhibits

     C-192  

 

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ITEM 16. FORM 10-K SUMMARY

None.

 

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INDEX TO EXHIBITS

The exhibits listed on the following Exhibit Index are filed as part of this report. Exhibits required by Item 601 of Regulation S-K, but which are not listed below, are not applicable.

 

Exhibit

Number

  

Description

   Energy Transfer Equity, L.P.
    2.1    Agreement and Plan of Merger, dated as of September 28, 2015, among Energy Transfer Corp LP, ETE Corp GP, LLC, Energy Transfer Equity, L.P., LE GP, LLC, ETE GP, LLC and The Williams Companies, Inc. (incorporated by reference to Exhibit 2.1 to Form 8-K/A (File No. 1-32740) filed October 2, 2015)
    2.2    Agreement and Plan of Merger, dated as of November 20, 2016, by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Sunoco Logistics Partners L.P., Sunoco Partners LLC and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.1 to Form 8-K (File No. 1-11727) filed November 21, 2016)
    2.3    Amendment No. 1 to Agreement and Plan of Merger, dated as of December 16, 2016, by and among Sunoco Logistics Partners L.P., Sunoco Partners LLC, SXL Acquisition Sub LLC, SXL Acquisition Sub LP, Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., ETP Acquisition Sub, LLC and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.2 to Form 8-K (File No. 1-11727) filed December 21, 2016)
    2.4    Contribution Agreement, dated as of January 15, 2018, by and among USA Compression Partners, LP, Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., ETC Compression, LLC and, solely for certain purposes therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.1 to Form 8-K (File No. 1-32740) filed January 16, 2018)
    2.5    Purchase Agreement, dated as of January 15, 2018, by and among USA Compression Holdings, LLC, Energy Transfer Equity, L.P., Energy Transfer Partners, L.L.C. and, solely for certain purposes therein, R/C IV USACP Holdings, L.P. and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 2.2 to Form 8-K (File No. 1-32740) filed January 16, 2018)
    2.6    Agreement and Plan of Merger, dated as of August 1, 2018, by and among LE GP, LLC, Energy Transfer Equity, L.P., Streamline Merger Sub, LLC, Energy Transfer Partners, L.L.C. and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 2.1 to Form 8-K (File No. 1-32740) filed August 3, 2018)
    2.7    Agreement and Plan of Merger, dated as of September 15, 2019, by and among Energy Transfer LP, Nautilus Merger Sub LLC and SemGroup Corporation (incorporated by reference to Exhibit 2.1 to Form 8-K (File No. 1-32740) filed September 16, 2019)
    2.8    Agreement and Plan of Merger, dated as of February 16, 2021, by and among Energy Transfer LP, Elk Merger Sub LLC, Elk GP Merger Sub LLC, Enable Midstream Partners, LP, Enable GP, LLC, solely for the purpose of Section 21.(a)(i), LE GP, LLC, and, solely for the purpose of Section 1.1(b)(i), CenterPoint Energy, Inc. (incorporated by reference to Exhibit 2.1 to Form 8-K (File No. 1-32740) filed February 17, 2021)
    3.1    Certificate of Limited Partnership of Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 3.2 to Form S-1 (File No. 333-128097) filed September 2, 2005)
    3.1.1    Certificate of Amendment to Certificate of Limited Partnership of Energy Transfer LP (incorporated by reference to Exhibit 3.1 to Form 8-K (File No. 1-32740) filed October 19, 2018)

 

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Exhibit

Number

  

Description

    3.2    Third Amended Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated February 8, 2006 (incorporated by reference to Exhibit 3.1 to Form 8-K (File No. 1-32740) filed February 14, 2006)
    3.3    Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P. dated November 1, 2006 (incorporated by reference to Exhibit 3.3.1 to Form 10-K (File No. 1-32740) filed November 29, 2006)
    3.4    Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated November 9, 2007 (incorporated by reference to Exhibit 3.3.2 to Form 8-K (File No. 1-32740) filed November 13, 2007)
    3.5    Amendment No. 3 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated May 26, 2010 (incorporated by reference to Exhibit 3.1 to Form 8-K (File No. 1-32740) filed June 2, 2010)
    3.6    Amendment No. 4 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated December 23, 2013 (incorporated by reference to Exhibit 3.1 to Form 8-K (File No. 1-32740) filed December 27, 2013)
    3.7    Amendment No. 5 to the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated as of March 8, 2016 (incorporated by reference to Exhibit 3.1 to Form 8-K (File No. 1-32740) filed March 9, 2016)
    3.8    Amendment No. 6 to the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated as of October 19, 2018 (incorporated by reference to Exhibit 3.2 of Form 8-K, File No.1-32740, filed October 19, 2018 (incorporated by reference to Exhibit 3.2 to Form 8-K (File No. 1-32740) filed October 19, 2018)
    3.9    Amendment No. 7 to the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer LP dated as of August 6, 2019 (incorporated by reference to Exhibit 3.10 to Form 10-Q (File No. 1-32740) filed August 8, 2019)
    4.1    Indenture, dated September 20, 2010 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Form 8-K (File No. 1-32740) filed September 20, 2010)
    4.2    Fourth Supplemental Indenture, dated December 2, 2013 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (including form of the Notes) (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-32740) filed December 2, 2013)
    4.3    Fifth Supplemental Indenture, dated May 28, 2014 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-32740) filed May 28, 2014)
    4.4    Sixth Supplemental Indenture, dated May 28, 2014 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to Form 8-K (File No. 1-32740) filed May 28, 2014)
    4.5    Seventh Supplemental Indenture, dated May 22, 2015 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (including form of the Notes) (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-32740) filed May 22, 2015)
    4.6    Eighth Supplemental Indenture dated October 18, 2017 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-32740) filed October 18th, 2017)

 

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Exhibit

Number

 

Description

    4.7   Description of Registrant’s securities registered pursuant to Section 12 of the Securities Exchange Act of 1934 - Description of common units (incorporated by reference to Exhibit 4.10 to Form 10-K (File No. 1-32740) filed February 21, 2020)
    4.8   Ninth Supplemental Indenture, dated as of March 25, 2019, between Energy Transfer LP and U.S. Bank National Association as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-32740) filed March 27, 2019)
  10.1+   Amended and Restated Energy Transfer LP Long-Term Incentive Plan (formerly Amended and Restated Energy Transfer Equity, L.P. Long-Term Incentive Plan) (incorporated by reference to Exhibit 10.1 to Form 10-K (File No. 1-32740) filed February 23, 2018)
  10.2*+   First Amendment to the Amended and Restated Energy Transfer LP Long-Term Incentive Plan
  10.3+   Second Amendment to the Amended and Restated Energy Transfer LP Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 1-32740) filed January 6, 2021)
  10.4+   Energy Transfer LP Long-Term Cash Restricted Unit Plan (incorporated by reference to Exhibit 10.2 to Form 8-K (File No. 1-32740) filed January 6, 2021)
  10.5+   Form of Cash Unit Award Agreement under the Energy Transfer LP Long-Term Cash Restricted Unit Plan (incorporated by reference to Exhibit 10.3 to Form 8-K (File No. 1-32740) filed January 6, 2021)
  10.6+   Second Amended and Restated Energy Transfer LP 2008 Long-Term Incentive Plan (formerly Second Amended and Restated Energy Transfer Partners, L.P. 2008 Long-Term Incentive Plan) (incorporated by reference to Exhibit 4.1 to Form S-8 (File No. 333-229456) filed January 31, 2019)
  10.7+   Energy Transfer LP 2011 Long-Term Incentive Plan (formerly Regency Energy Partners LP 2011 Long-Term Incentive Plan) (incorporated by reference to Exhibit 4.2 to Form S-8 (File No 333-229456) filed January 31, 2019)
  10.8+   Energy Transfer LP 2015 Long-Term Incentive Plan, as amended and restated (formerly Sunoco Partners LLC Long-Term Incentive Plan, as amended and restated) (incorporated by reference to Exhibit 4.3 to Form S-8 (File No. 333-229456) filed January 31, 2019)
  10.9+   Form of Director and Officer Indemnification Agreement (incorporated by reference to Exhibit 10.26 to Form S-1 (File No. 333-128097) filed December 20, 2005)
  10.10   Registration Rights Agreement, dated November 27, 2006, by and among Energy Transfer Equity, L.P. and certain investors named therein (incorporated by reference to Exhibit 99.1 to Form 8-K (File No. 1-32740) filed November 30, 2006)
  10.11+   LE GP, LLC Amended and Restated Outside Director Compensation Policy (incorporated by reference to Exhibit 10.9 to Form 10-K (File No. 1-32740) filed February 22, 2019)
  10.12   Registration Rights Agreement, dated March 2, 2007, by and among Energy Transfer Equity, L.P. and certain investors named therein (incorporated by reference to Exhibit 99.1 to Form 8-K (File No. 1-32740) filed March 5, 2007)
  10.13   Unitholder Rights and Restrictions Agreement, dated as of May 7, 2007, by and among Energy Transfer Equity, L.P., Ray C. Davis, Natural Gas Partners VI, L.P. and Enterprise GP Holdings, L.P. (incorporated by reference to Exhibit 10.45 to Form 8-K (File No. 1-32740) filed May 7, 2007)
  10.14   Shared Services Agreement dated as of August 26, 2005, by and between Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 10.30 to Form S-1/A (File No. 333-128097) filed December 20, 2005)

 

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Exhibit

Number

  

Description

  10.15    Second Amendment, dated April 30, 2013, to the Shared Services Agreement dated as of August 26, 2005, as amended May 26, 2010, by and between Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P.(incorporated by reference to Exhibit 10.2 to Form 8-K (File No. 1-32740) filed May 1, 2013)
  10.16    Third Amendment, dated February 19, 2014, to the Shared Services Agreement dated as of August 26, 2005, as amended May 26, 2010 and April 30, 2013 by and between Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 1-32740) filed February 19, 2014)
  10.17+    Retention Agreement, by and among Energy Transfer Equity, L.P. and Thomas P. Mason, dated February 24, 2016 (incorporated by reference to Exhibit 10.21 to Form 10-K (File No. 1-32740) filed February 29, 2016)
  10.18    Equity Restructuring Agreement, dated as of January 15, 2018, by and among Energy Transfer Equity, L.P., USA Compression Partners, LP and USA Compression GP, LLC. (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 1-32740) filed January 16, 2018)
  10.19    Registration Rights Agreement, dated as of April 2, 2018, by and among Energy Transfer Partners, L.P., Energy Transfer Equity, L.P., USA Compression Partners, LP and USA Compression Holdings, LLC. (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 1-32740) filed April 3, 2018)
  10.20+    Energy Transfer LP Annual Bonus Plan (incorporated by reference to Exhibit 10.23 to Form 10-K (File No. 1-32740) filed February 22, 2019)
  10.21    Support Agreement, dated September 15, 2019, between Energy Transfer LP, Nautilus Merger Sub LLC, WP SemGroup Holdco LLC and SemGroup Corporation (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 1-32740) filed September 15, 2019)
  10.22    Term Loan Credit Agreement dated as of October 17, 2019 among Energy Transfer Operating, L.P., Toronto Dominion (Texas) LLC, as Administrative Agent, the other lenders party thereto and the other parties named therein (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 1-32740) filed October 18, 2019)
  10.23    Guaranty dated as of October 17, 2019 between Sunoco Logistics Partners Operations L.P. and Toronto Dominion (Texas) LLC, as Administrative Agent (incorporated by reference to Exhibit 10.2 to Form 8-K (File No. 1-32740) filed October 18, 2019)
  10.24    Support Agreement, dated as of February 16, 2021, by and among Energy Transfer LP, Elk Merger Sub LLC, Elk GP Merger Sub LLC, Enable Midstream Partners, LP, Enable GP, LLC and CenterPoint Energy, Inc. (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 1-32740) filed February 17, 2021)
  10.25    Support Agreement, dated as of February 16, 2021, by and among Energy Transfer LP, Elk Merger Sub LLC, Elk GP Merger Sub LLC, Enable Midstream Partners, LP, Enable GP, LLC and OGE Energy Corp. (incorporated by reference to Exhibit 10.2 to Form 8-K (File No. 1-32740) filed February 17, 2021)
  21.1*    List of Subsidiaries
  23.1*    Consent of Grant Thornton LLP related to Energy Transfer LP
  31.1*    Certification of Co-Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
  31.2*    Certification of Co-Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

 

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Exhibit

Number

  

Description

  31.3*    Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
  32.1**    Certification of Co-Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
  32.2**    Certification of Co-Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
  32.3**    Certification Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101*    Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Balance Sheets as of December 31, 2020 and 2019; (ii) our Consolidated Statements of Operations for the years ended December 31, 2020, 2019 and 2018; (iii) our Consolidated Statements of Comprehensive Income for years ended December 31, 2020, 2019 and 2018; (iv) our Consolidated Statement of Equity for the years ended December 31, 2020, 2019 and 2018; and (v) our Consolidated Statements of Cash Flows for the years ended December 31, 2020, 2019 and 2018
104    Cover Page Interactive Data File (embedded within the Inline XBRL document)

 

*

Filed herewith.

**

Furnished herewith.

+

Denotes a management contract or compensatory plan or arrangement.

 

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

    ENERGY TRANSFER LP
    By:   LE GP, LLC, its general partner
Date: February 19, 2021     By:   /s/ A. Troy Sturrock
      A. Troy Sturrock
      Senior Vice President, Controller and Principal Accounting Officer (duly authorized to sign on behalf of the registrant)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated:

 

Signature    Title   Date

/s/ Kelcy L. Warren

Kelcy L. Warren

  

Executive Chairman

  February 19, 2021

/s/ Marshall S. McCrea, III

Marshall S. McCrea, III

  

Co-Chief Executive Officer and Director

(Co-Principal Executive Officer)

  February 19, 2021

/s/ Thomas E. Long

Thomas E. Long

  

Co-Chief Executive Officer and Director

(Co-Principal Executive Officer)

  February 19, 2021

/s/ Bradford D. Whitehurst

Bradford D. Whitehurst

  

Chief Financial Officer

(Principal Financial Officer)

  February 19, 2021

/s/ Matthew S. Ramsey

Matthew S. Ramsey

  

Chief Operating Officer and Director

  February 19, 2021

/s/ A. Troy Sturrock

A. Troy Sturrock

  

Senior Vice President and Controller

(Principal Accounting Officer)

  February 19, 2021

/s/ Steven R. Anderson

Steven R. Anderson

  

Director

  February 19, 2021

/s/ Richard D. Brannon

Richard D. Brannon

  

Director

  February 19, 2021

/s/ Ray C. Davis

Ray C. Davis

  

Director

  February 19, 2021

/s/ Michael K. Grimm

Michael K. Grimm

  

Director

  February 19, 2021

/s/ John W. McReynolds

John W. McReynolds

  

Director

  February 19, 2021

/s/ James R. Perry

James R. Perry

  

Director

  February 19, 2021

/s/ Ray W. Washburne

Ray W. Washburne

  

Director

  February 19, 2021

 

C-197


Table of Contents

INDEX TO FINANCIAL STATEMENTS

Energy Transfer LP and Subsidiaries

 

     Page  

Report of Independent Registered Public Accounting Firm

     C-199  

Consolidated Balance Sheets

     C-202  

Consolidated Statements of Operations

     C-204  

Consolidated Statements of Comprehensive Income (Loss)

     C-205  

Consolidated Statements of Equity

     C-206  

Consolidated Statements of Cash Flows

     C-207  

Notes to Consolidated Financial Statements

     C-208  

 

C-198


Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors of LE GP, LLC and

Unitholders of Energy Transfer LP

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Energy Transfer LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2020 and 2019, the related consolidated statements of operations, comprehensive income (loss), equity, and cash flows for each of the three years in the period ended December 31, 2020, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Partnership’s internal control over financial reporting as of December 31, 2020, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 19, 2021 expressed an unqualified opinion thereon.

Change in accounting principle

As discussed in Note 2 to the consolidated financial statements, the Partnership has changed its method of accounting for certain inventories.

Basis for opinion

These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical audit matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

 

C-199


Table of Contents

Goodwill Impairment Assessment

As described in Note 2 to the consolidated financial statements, the Partnership recognized $2.8 billion of goodwill impairment during 2020 and the remaining consolidated goodwill balance was $2.4 billion at December 31, 2020. Annually, or whenever events or changes in circumstances indicate potential asset impairment has occurred, the Partnership evaluates the recoverability of the carrying value of goodwill. The COVID-19 pandemic and the corresponding decrease in demand for crude oil, natural gas liquids and natural gas negatively impacted the Partnership’s current and projected operating results, cash flow and market capitalization. Therefore, the Partnership determined that a triggering event had occurred and completed an interim goodwill impairment assessment of its reporting units during the first and third quarters of 2020 along with the Partnership’s annual impairment assessment during the fourth quarter of 2020. The results of the quantitative impairment tests indicated that certain reporting units had a carrying value that exceeded their fair values. As a result, the Partnership recorded $2.8 billion of impairment charges to goodwill for these reporting units during the year ended December 31, 2020. In addition, as of December 31, 2020, there was $368 million of goodwill that was recorded within a reporting unit for which the estimated fair value exceeded the carrying value by less than 20% in the most recent quantitative test. We identified the Partnership’s determination of the fair value of the reporting units where carrying value exceeded their fair values and the 1 reporting unit where the estimated fair value exceeded the carrying value by less than 20% as a critical audit matter.

The determination of the fair value of the reporting units was a critical audit matter due to the significant judgment required by management when determining the fair value of a reporting unit. In particular, the fair value estimates were sensitive to significant assumptions such as management’s cash flow projections, discount rates, and the inherent uncertainty around the timing of increases or decreases in future projected results utilized to estimate the fair value of reporting units.

Our audit procedures related to the estimation of the fair value of the reporting units included the following procedures, among others. We tested the effectiveness of controls relating to management’s review of the assumptions used to develop the future cash flows, the discount rates used, and valuation methodologies applied. In addition to testing the effectiveness of controls, we also performed the following:

 

  a.

Evaluated the reasonableness of management’s forecasted financial results by:

 

  i.

Assessing the reasonableness of management’s forecast of future projected results and the underlying timing of recovery in comparison to relevant industry data and other supporting evidence obtained,

 

  ii.

Testing forecasted revenues and gross margins by comparing forecasted amounts to actual historical results to identify material changes, corroborating the basis for increases or decreases in forecasted revenues and gross margins, as applicable, and

 

  iii.

Testing significant operating expenses and cash expenditures by comparing to historical trends and evaluating significant deviations from recent actual amounts.

 

  b.

Utilized an internal valuation specialist to evaluate:

 

  i.

The methodologies used and whether they were acceptable for the underlying assets or operations and whether such methodologies were being applied correctly, and

 

  ii.

The appropriateness of the discount rates by recalculating the weighted average costs of capital or developing independent ranges of acceptable discount rates and comparing those ranges to the amounts selected and applied by management.

Environmental Remediation

As discussed in Note 10 to the consolidated financial statements, the Partnership’s operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures

 

C-200


Table of Contents

for remediation at current and former facilities. At December 31, 2020, the Partnership’s consolidated environmental obligations totaled $306 million. We identified the identification, assessment and estimation of the environmental exposure associated with certain sites of ETC Sunoco Holdings LLC as a critical audit matter.

The determination that the identification, assessment and estimation of the environmental exposure was a critical audit matter was due to high estimation uncertainty primarily driven by the complexity of the actuarial methods utilized, the discount rate applied and the potential for changes in the timing and extent of remediation. This required an increased extent of effort when performing audit procedures, related to identification, assessment and estimation of the environmental exposure, including the need to involve an actuarial specialist.

Our audit procedures related to the identification, assessment and estimation of the Partnership’s environmental exposure included the following procedures, among others. We tested the effectiveness of controls relating to the identification and review of the historical claims, payments and reserve data provided to the third-party actuarial specialist and the reconciliation of that data used in the actuary report, and the review of the discount rate and actuarial methods applied. In addition to testing the effectiveness of controls, we performed the following procedures:

 

  a.

Utilized an auditor-engaged actuarial specialist to evaluate:

 

  i.

The methodologies used and whether they were acceptable for the underlying operations, and

 

  ii.

The qualifications of the actuarial specialist engaged by the Partnership based on their credentials and experience.

 

  b.

Evaluated the discount rate used by comparing it to the historical rate of return related to the investment portfolio used to fund the underlying liabilities, and

 

  c.

Evaluated the life-to-date payments, reserves, and payment patterns by agreeing the historical claims and payment amounts to underlying claims or general ledger.

/s/ GRANT THORNTON LLP

We have served as the Partnership’s auditor since 2004.

Dallas, Texas

February 19, 2021

 

C-201


Table of Contents

ENERGY TRANSFER LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

 

     December 31,  
     2020     2019  

ASSETS

    

Current assets:

    

Cash and cash equivalents

   $ 367   $ 291

Accounts receivable, net

     3,875     5,038

Accounts receivable from related companies

     79     159

Inventories

     1,739     1,532

Income taxes receivable

     35     146

Derivative assets

     9     23

Other current assets

     213     275
  

 

 

   

 

 

 

Total current assets

     6,317     7,464

Property, plant and equipment

     94,115     89,790

Accumulated depreciation and depletion

     (19,008     (15,597
  

 

 

   

 

 

 
     75,107     74,193

Investments in unconsolidated affiliates

     3,060     3,460

Lease right-of-use assets, net

     866     964

Other non-current assets, net

     1,657     1,571

Intangible assets, net

     5,746     6,154

Goodwill

     2,391     5,167
  

 

 

   

 

 

 

Total assets

   $ 95,144   $ 98,973
  

 

 

   

 

 

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

C-202


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ENERGY TRANSFER LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

 

     December 31,  
     2020     2019  

LIABILITIES AND EQUITY

    

Current liabilities:

    

Accounts payable

   $ 2,809   $ 4,118

Accounts payable to related companies

     27     31

Derivative liabilities

     238     147

Operating lease current liabilities

     53     60

Accrued and other current liabilities

     2,775     3,342

Current maturities of long-term debt

     21     26
  

 

 

   

 

 

 

Total current liabilities

     5,923     7,724

Long-term debt, less current maturities

     51,417     51,028

Non-current derivative liabilities

     237     273

Non-current operating lease liabilities

     837     901

Deferred income taxes

     3,428     3,208

Other non-current liabilities

     1,152     1,162

Commitments and contingencies

    

Redeemable noncontrolling interests

     762     739

Equity:

    

Limited Partners:

    

Common Unitholders (2,702,372,154 and 2,689,580,631 units authorized, issued and outstanding as of December 31, 2020 and 2019, respectively)

     18,531     21,935

General Partner

     (8     (4

Accumulated other comprehensive income (loss)

     6     (11
  

 

 

   

 

 

 

Total partners’ capital

     18,529     21,920

Noncontrolling interests

     12,859     12,018
  

 

 

   

 

 

 

Total equity

     31,388     33,938
  

 

 

   

 

 

 

Total liabilities and equity

   $ 95,144   $ 98,973
  

 

 

   

 

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

C-203


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ENERGY TRANSFER LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in millions, except per unit data)

 

     Years Ended December 31,  
     2020     2019     2018  

REVENUES:

      

Refined product sales

   $ 10,514   $ 16,752   $ 17,458

Crude sales

     9,442     15,917     14,425

NGL sales

     6,797     8,290     9,986

Gathering, transportation and other fees

     8,982     9,086     6,797

Natural gas sales

     2,633     3,295     4,452

Other

     586     873     969
  

 

 

   

 

 

   

 

 

 

Total revenues

     38,954     54,213     54,087
  

 

 

   

 

 

   

 

 

 

COSTS AND EXPENSES:

      

Cost of products sold

     25,487     39,801     41,603

Operating expenses

     3,218     3,294     3,089

Depreciation, depletion and amortization

     3,678     3,147     2,859

Selling, general and administrative

     711     694     702

Impairment losses

     2,880     74     431
  

 

 

   

 

 

   

 

 

 

Total costs and expenses

     35,974     47,010     48,684
  

 

 

   

 

 

   

 

 

 

OPERATING INCOME

     2,980     7,203     5,403

OTHER INCOME (EXPENSE):

      

Interest expense, net of interest capitalized

     (2,327     (2,331     (2,055

Equity in earnings of unconsolidated affiliates

     119     302     344

Impairment of investments in unconsolidated affiliates

     (129     —         —    

Losses on extinguishments of debt

     (75     (18     (112

Gains (losses) on interest rate derivatives

     (203     (241     47

Other, net

     12     105     62
  

 

 

   

 

 

   

 

 

 

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE

     377     5,020     3,689

Income tax expense from continuing operations

     237     195     4
  

 

 

   

 

 

   

 

 

 

INCOME FROM CONTINUING OPERATIONS

     140     4,825     3,685

Loss from discontinued operations, net of income taxes

     —         —         (265
  

 

 

   

 

 

   

 

 

 

NET INCOME

     140     4,825     3,420

Less: Net income attributable to noncontrolling interests

     739     1,256     1,632

Less: Net income attributable to redeemable noncontrolling interests

     49     51     39
  

 

 

   

 

 

   

 

 

 

NET INCOME (LOSS) ATTRIBUTABLE TO PARTNERS

     (648     3,518     1,749

ET Series A Convertible Preferred Unitholders’ interest in net income

     —         —         33

General Partner’s interest in net income (loss)

     (1     4     3
  

 

 

   

 

 

   

 

 

 

Limited Partners’ interest in net income (loss)

   $ (647   $ 3,514   $ 1,713
  

 

 

   

 

 

   

 

 

 

INCOME (LOSS) FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:

      
  

 

 

   

 

 

   

 

 

 

Basic

   $ (0.24   $ 1.34   $ 1.21
  

 

 

   

 

 

   

 

 

 

Diluted

   $ (0.24   $ 1.33   $ 1.20
  

 

 

   

 

 

   

 

 

 

NET INCOME (LOSS) PER LIMITED PARTNER UNIT:

      

Basic

   $ (0.24   $ 1.34   $ 1.20
  

 

 

   

 

 

   

 

 

 

Diluted

   $ (0.24   $ 1.33   $ 1.19
  

 

 

   

 

 

   

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

C-204


Table of Contents

ENERGY TRANSFER LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Dollars in millions)

 

     Years Ended December 31,  
     2020     2019     2018  

Net income

   $ 140   $ 4,825   $ 3,420

Other comprehensive income (loss), net of tax:

      

Change in value of available-for-sale securities

     5     11     (4

Actuarial gain (loss) relating to pension and other postretirement benefits

     18     24     (43

Foreign currency translation adjustment

     5     6     —    

Change in other comprehensive income from unconsolidated affiliates

     (13     (10     4
  

 

 

   

 

 

   

 

 

 
     15     31     (43
  

 

 

   

 

 

   

 

 

 

Comprehensive income

     155     4,856     3,377

Less: Comprehensive income attributable to noncontrolling interests

     739     1,256     1,632

Less: Comprehensive income attributable to redeemable noncontrolling interests

     49     51     39
  

 

 

   

 

 

   

 

 

 

Comprehensive income (loss) attributable to partners

   $ (633   $ 3,549   $ 1,706
  

 

 

   

 

 

   

 

 

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

C-205


Table of Contents

ENERGY TRANSFER LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(Dollars in millions)

 

    Series A
Convertible
Preferred
Units
    Common
Unitholders
    General
Partner
    Accumulated
Other
Comprehensive
Income (Loss)
    Non-
controlling
Interest
    Total  

Balance, December 31, 2017

  $ 450   $ (1,531   $ (3   $ —       $ 31,176   $ 30,092

Distributions to partners

    —         (1,681     (3     —         —         (1,684

Distributions to noncontrolling interests

    —         —         —         —         (3,117     (3,117

Distributions reinvested

    115     (115     —         —           —    

Subsidiary units repurchased

    (7     (119     —         —         102     (24

Subsidiary units issued

    —         1     —         —         923     924

Energy Transfer Merger

    —         21,869     —         —         (21,869     —    

Capital contributions from noncontrolling interests

    —         —         —         —         649     649

Cumulative effect adjustment due to change in accounting principle

    —         —         —         —         (54     (54

Acquisition of USAC noncontrolling interest

    —         —         —         —         832     832

ET Series A Convertible Preferred Units conversion

    (589     589     —         —         —         —    

Other comprehensive loss, net of tax

    —         —         —         (43     —         (43

Other, net

    (2     47     (2     1     17     61

Net income, excluding amounts attributable to redeemable noncontrolling interests

    33     1,713     3     —         1,632     3,381
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance, December 31, 2018

    —         20,773     (5     (42     10,291     31,017

Distributions to partners

    —         (3,051     (3     —         —         (3,054

Distributions to noncontrolling interests

    —         —         —         —         (1,597     (1,597

Common units repurchased

    —         (25     —         —         —         (25

Subsidiary units issued

    —         —         —         —         780     780

Capital contributions from noncontrolling interests

    —         —         —         —         348     348

Sale of noncontrolling interest in subsidiary

    —         —         —         —         93     93

SemGroup Acquisition

    —         652     —         —         819     1,471

Other comprehensive income, net of tax

    —         —         —         31     —         31

Other, net

    —         72     —         —         28     100

Net income, excluding amounts attributable to redeemable noncontrolling interests

    —         3,514     4     —         1,256     4,774
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance, December 31, 2019

    —         21,935     (4     (11     12,018     33,938

Distributions to partners

    —         (2,799     (3     —         —         (2,802

Distributions to noncontrolling interests

    —         —         —         —         (1,651     (1,651

Subsidiary units issued

    —         —         —         —         1,580     1,580

Capital contributions from noncontrolling interests

    —         —         —         —         222     222

Other comprehensive income (loss), net of tax

    —         —         —         16     (1     15

Other, net

    —         42     —         1     (48     (5

Net income (loss), excluding amounts attributable to redeemable noncontrolling interests

    —         (647     (1     —         739     91
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance, December 31, 2020

  $ —       $ 18,531   $ (8   $ 6   $ 12,859   $ 31,388
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

C-206


Table of Contents

ENERGY TRANSFER LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)

 

     Years Ended December 31,  
     2020     2019     2018  

OPERATING ACTIVITIES:

      

Net income

   $ 140   $ 4,825   $ 3,420

Reconciliation of net income to net cash provided by operating activities:

      

Loss from discontinued operations

     —         —         265

Depreciation, depletion and amortization

     3,678     3,147     2,859

Deferred income taxes

     210     217     (7

Inventory valuation adjustments

     82     (79     85

Non-cash compensation expense

     121     113     105

Impairment losses

     2,880     74     431

Impairment of investments in unconsolidated affiliates

     129     —         —    

Losses on extinguishment of debt

     75     18     112

Distributions on unvested awards

     (41     (38     (38

Equity in earnings of unconsolidated affiliates

     (119     (302     (344

Distributions from unconsolidated affiliates

     220     290     328

Other non-cash

     (61     182     56

Net change in operating assets and liabilities, net of effects of acquisitions

     47     (391     234
  

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

     7,361     8,056     7,506
  

 

 

   

 

 

   

 

 

 

INVESTING ACTIVITIES:

      

Cash proceeds from sale of noncontrolling interest in subsidiary

     —         93     —    

Cash received in USAC acquisition, net of cash paid

     —         —         461

Cash paid for SemGroup Acquisition, net of cash received

     —         (787     —    

Cash paid for all other acquisitions

     —         (7     (429

Capital expenditures, excluding allowance for equity funds used during construction

     (5,130     (5,960     (7,407

Contributions in aid of construction costs

     67     80     109

Contributions to unconsolidated affiliates

     (38     (523     (26

Distributions from unconsolidated affiliates in excess of cumulative earnings

     187     98     69

Proceeds from the sale of assets

     19     54     87

Other

     (3     18     61
  

 

 

   

 

 

   

 

 

 

Net cash used in investing activities

     (4,898     (6,934     (7,075
  

 

 

   

 

 

   

 

 

 

FINANCING ACTIVITIES:

      

Proceeds from borrowings

     24,440     22,583     29,001

Repayments of debt

     (24,133     (20,101     (28,948

Subsidiary units issued for cash

     1,580     780     1,402

Capital contributions from noncontrolling interests

     222     348     649

Distributions to partners

     (2,802     (3,054     (1,684

Distributions to noncontrolling interests

     (1,651     (1,597     (3,117

Distributions to redeemable noncontrolling interests

     (49     (53     (24

Common units repurchased under buyback program

     —         (25     —    

Subsidiary units repurchased

     —         —         (24

Debt issuance costs

     (59     (117     (171

Other

     65     (14     (166
  

 

 

   

 

 

   

 

 

 

Net cash used in financing activities

     (2,387     (1,250     (3,082
  

 

 

   

 

 

   

 

 

 

DISCONTINUED OPERATIONS:

      

Operating activities

     —         —         (484

Investing activities

     —         —         3,207

Changes in cash included in current assets held for sale

     —         —         11
  

 

 

   

 

 

   

 

 

 

Net increase in cash and cash equivalents of discontinued operations

     —         —         2,734
  

 

 

   

 

 

   

 

 

 

Increase (decrease) in cash and cash equivalents

     76     (128     83

Cash and cash equivalents, beginning of period

     291     419     336
  

 

 

   

 

 

   

 

 

 

Cash and cash equivalents, end of period

   $ 367   $ 291   $ 419
  

 

 

   

 

 

   

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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Table of Contents

ENERGY TRANSFER LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Tabular dollar and unit amounts, except per unit data, are in millions)

 

1.

OPERATIONS AND BASIS OF PRESENTATION:

The consolidated financial statements presented herein contain the results of Energy Transfer LP and its subsidiaries (the “Partnership,” “we,” “us,” “our” or “ET”). References to the “Parent Company” mean Energy Transfer LP on a stand-alone basis.

In October 2018, we completed the merger of ETO with a wholly-owned subsidiary of ET in a unit-for-unit exchange (the “Energy Transfer Merger”). In connection with the transaction, the former common unitholders (other than ET and its subsidiaries) received 1.28 common units of ET for each common unit of ETO they owned. Following the closing of the Energy Transfer Merger, Energy Transfer Partners, L.P. was renamed Energy Transfer Operating, L.P. In addition, Energy Transfer Equity, L.P. was renamed Energy Transfer LP, and its common units began trading on the NYSE under the “ET” ticker symbol on Friday, October 19, 2018.

Immediately prior to the closing of the Energy Transfer Merger, the following also occurred:

 

   

the IDRs in Energy Transfer Partners, L.P. were converted into 1,168,205,710 common units;

 

   

the general partner interest in ETO was converted to a non-economic general partner interest and ETO issued 18,448,341 ETO common units to ETP GP;

 

   

ET contributed its 2,263,158 Sunoco LP common units to ETO in exchange for 2,874,275 ETO common units and 100 percent of the limited liability company interests in Sunoco GP LLC, the sole general partner of Sunoco LP, and all of the IDRs in Sunoco LP, to ETO in exchange for 42,812,389 ETO common units;

 

   

ET contributed its 12,466,912 common units representing limited partner interests in USAC and 100 percent of the limited liability company interests in USA Compression GP, LLC, the general partner of USAC, to ETO in exchange for 16,134,903 ETO common units; and

 

   

ET contributed its 100 percent limited liability company interest in Lake Charles LNG and a 60 percent limited liability company interest in each of Energy Transfer LNG Export, LLC, ET Crude Oil Terminals, LLC and ETC Illinois LLC (collectively, “Lake Charles LNG and Other”) to ETO in exchange for 37,557,815 ETO common units.

Subsequent to the Energy Transfer Merger, substantially all of the Partnership’s cash flows are derived from distributions related to its investment in ETO, whose cash flows are derived from its subsidiaries, including ETO’s investments in Sunoco LP and USAC. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. Parent Company-only assets are not available to satisfy the debts and other obligations of ET’s subsidiaries.

Our financial statements reflect the following reportable segments:

 

   

intrastate transportation and storage;

 

   

interstate transportation and storage;

 

   

midstream;

 

   

NGL and refined products transportation and services;

 

   

crude oil transportation and services;

 

   

investment in Sunoco LP;

 

   

investment in USAC; and

 

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corporate and other, including the following:

 

   

activities of the Parent Company; and

 

   

certain operations and investments that are not separately reflected as reportable segments.

The Partnership owns and operates intrastate natural gas pipeline systems and storage facilities that are engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia.

The Partnership owns and operates interstate pipelines, either directly or through equity method investments, that transport natural gas to various markets in the United States.

The Partnership is engaged in the gathering and processing, compression, treating and transportation of natural gas, focusing on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring and Avalon shales.

The Partnership owns and operates a logistics business, consisting of a geographically diverse portfolio of complementary pipeline, terminalling, and acquisition and marketing assets, which are used to facilitate the purchase and sale of crude oil, NGLs and refined products.

The Partnership owns a controlling interest in Sunoco LP which is engaged in the wholesale distribution of motor fuels to convenience stores, independent dealers, commercial customers, and distributors, as well as the retail sale of motor fuels and merchandise through Sunoco LP operated convenience stores and retail fuel sites. As of December 31, 2020, our interest in Sunoco LP consisted of 100% of the general partner and IDRs, as well as 28.5 million common units.

The Partnership owns a controlling interest in USAC which provides compression services to producers, processors, gatherers and transporters of natural gas and crude oil. As of December 31, 2020, our interest in USAC consisted of 100% of the general partner and 46.1 million common units.

Basis of Presentation. The consolidated financial statements of Energy Transfer LP presented herein for the years ended December 31, 2020, 2019 and 2018, have been prepared in accordance with GAAP and pursuant to the rules and regulations of the SEC. We consolidate all majority-owned subsidiaries and limited partnerships, which we control as the general partner or owner of the general partner. All significant intercompany transactions and accounts are eliminated in consolidation.

The consolidated financial statements of ET presented herein include the results of operations of:

 

   

the Parent Company;

 

   

our controlled subsidiary, Energy Transfer Operating, L.P.; and

 

   

Energy Transfer Partners GP, L.P. (“ETP GP”), the general partner of ETO, and Energy Transfer Partners, L.L.C. (“ETP LLC”), the general partner of ETP GP.

For prior periods herein, certain balances have been reclassified to assets and liabilities held for sale and certain revenues and expenses to discontinued operations. These reclassifications had no impact on net income or total equity.

 

2.

ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:

Change in Accounting Policy

Effective January 1, 2020, the Partnership elected to change its accounting policy related to certain barrels of crude oil that were previously accounted for as inventory. Under the revised accounting policy, certain amounts of crude oil that are not available for sale have been reclassified from inventory to non-current assets. These crude oil barrels, which are owned by the Partnership’s crude oil acquisition and marketing

 

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business, include pipeline linefill and tank bottoms and are not considered to be available for sale because the volumes must be maintained in order to continue normal operation of the related pipelines or tanks and because there is no expectation of liquidation or sale of these volumes in the near term.

Under the previous accounting policy, all crude oil barrels were recorded as inventory under the weighted average cost method. Under the revised accounting policy, barrels related to pipeline linefill and tank bottoms are accounted for as long-lived assets and reflected as non-current assets on the consolidated balance sheet. These crude oil barrels will be tested for impairment consistent with the Partnership’s existing accounting policy for impairments of long-lived assets. The Partnership’s management believes that the change in accounting policy is preferable as it more closely aligns the accounting policies across the consolidated entity, given that similar assets in the Partnership’s natural gas, NGLs and refined products businesses are accounted for as non-current assets. In addition, management believes that reflecting these crude oil barrels as non-current assets better represents the economic results of the Partnership’s crude oil acquisition and marketing business by reducing volatility resulting from market price adjustments to crude oil barrels that are not expected to be sold or liquidated in the near term.

As a result of this change in accounting policy, the Partnership’s consolidated balance sheet for the prior period has been retrospectively adjusted as follows:

 

     December 31, 2019  
     As
Originally
Reported
     Effect of
Change
     As
Adjusted
 

Inventories

   $ 1,935    $ (403    $ 1,532

Total current assets

     7,867      (403      7,464

Other non-current assets, net

     1,075      496      1,571

Total assets

     98,880      93      98,973

Total partners’ capital

     21,827      93      21,920

 

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In addition, the Partnership’s consolidated statements of operations, comprehensive income and cash flows for prior periods have been retrospectively adjusted as follows:

 

     Year Ended
December 31,
 
     2019      2018  

As originally reported:

     

Consolidated Statements of Operations and Comprehensive Income

     

Cost of products sold

   $ 39,727    $ 41,658

Operating income

     7,277      5,348

Income from continuing operations before income tax expense

     5,094      3,634

Net income

     4,899      3,365

Net income per limited partner unit

     1.37      1.16

Comprehensive income

     4,930      3,322

Comprehensive income attributable to partners

     3,623      1,651

Consolidated Statements of Cash Flows

     

Net income

     4,899      3,365

Net change in operating assets and liabilities

     (465      289

Effect of change:

     

Consolidated Statements of Operations and Comprehensive Income

     

Cost of products sold

     74      (55

Operating income

     (74      55

Income from continuing operations before income tax expense

     (74      55

Net income

     (74      55

Net income per limited partner unit

     (0.03      0.04

Comprehensive income

     (74      55

Comprehensive income attributable to partners

     (74      55

Consolidated Statements of Cash Flows

     

Net income

     (74      55

Net change in operating assets and liabilities

     74      (55

As adjusted:

     

Consolidated Statements of Operations and Comprehensive Income

     

Cost of products sold

     39,801      41,603

Operating income

     7,203      5,403

Income from continuing operations before income tax expense

     5,020      3,689

Net income

     4,825      3,420

Net income per limited partner unit

     1.34      1.20

Comprehensive income

     4,856      3,377

Comprehensive income attributable to partners

     3,549      1,706

Consolidated Statements of Cash Flows

     

Net income

     4,825      3,420

Net change in operating assets and liabilities

     (391      234

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure

 

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of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects.

Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.

Regulatory Accounting—Regulatory Assets and Liabilities

Our interstate transportation and storage segment is subject to regulation by certain state and federal authorities, and certain subsidiaries in that segment have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.

Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978, it does not currently apply regulatory accounting policies in accounting for its operations. Panhandle does not apply regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs.

Cash, Cash Equivalents and Supplemental Cash Flow Information

Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value.

We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.

 

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The net change in operating assets and liabilities (net of effects of acquisitions) included in cash flows from operating activities is comprised as follows:

 

     Years Ended December 31,  
     2020      2019      2018  

Accounts receivable

   $ 1,163    $ (473    $ 541

Accounts receivable from related companies

     (290      (69      162

Inventories

     (271      (19      237

Other current assets

     172      117      7

Other non-current assets, net

     (7      (102      (102

Accounts payable

     (1,327      146      (766

Accounts payable to related companies

     367      (32      (202

Accrued and other current liabilities

     163      (44      382

Other non-current liabilities

     8      (133      28

Derivative assets and liabilities, net

     69      218      (53
  

 

 

    

 

 

    

 

 

 

Net change in operating assets and liabilities, net of effects of acquisitions

   $ 47    $ (391    $ 234
  

 

 

    

 

 

    

 

 

 

Non-cash investing and financing activities and supplemental cash flow information are as follows:

 

     Years Ended December 31,  
     2020      2019      2018  

NON-CASH INVESTING ACTIVITIES:

        

Accrued capital expenditures

   $ 604    $ 1,334    $ 1,030

Lease assets obtained in exchange for new lease liabilities

     42      68      —    

Net losses from subsidiary common unit transactions

     —          —          (126

SUPPLEMENTAL CASH FLOW INFORMATION:

        

Cash paid for interest, net of interest capitalized

   $ 2,092    $ 1,932    $ 1,870

Cash paid for income taxes (net of refunds)

     (64      31      508

Accounts Receivable

Our operations deal with a variety of counterparties across the energy sector, some of which are investment grade, and most of which are not. Internal credit ratings and credit limits are assigned to all counterparties and limits are monitored against credit exposure. Letters of credit or prepayments may be required from those counterparties that are not investment grade depending on the internal credit rating and level of commercial activity with the counterparty.

We have a diverse portfolio of customers; however, because of the midstream and transportation services we provide, many of our customers are engaged in the exploration and production segment. We manage trade credit risk to mitigate credit losses and exposure to uncollectible trade receivables. Prospective and existing customers are reviewed regularly for creditworthiness to manage credit risk within approved tolerances. Customers that do not meet minimum credit standards are required to provide additional credit support in the form of a letter of credit, prepayment, or other forms of security. We establish an allowance for credit losses on trade receivables based on the expected ultimate recovery of these receivables and consider many factors including historical customer collection experience, general and specific economic trends, and known specific issues related to individual customers, sectors, and transactions that might impact collectability. Changes in the allowance are recorded as a component of operating expenses; reductions in the allowance are recorded when receivables are subsequently collected or written-off. Past due receivable balances are written-off when our efforts have been unsuccessful in collecting the amount due.

 

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Inventories

Inventories consist principally of natural gas held in storage, NGLs and refined products, crude oil and spare parts, all of which are valued at the lower of cost or net realizable value utilizing the weighted-average cost method.

Sunoco LP’s fuel inventories are stated at the lower of cost or market using the last-in-first-out (“LIFO”) method. As of December 31, 2020 and 2019, the carrying value of Sunoco LP’s fuel inventory included lower of cost or market reserves of $311 million and $229 million, respectively, and the inventory carrying value equaled or exceeded its replacement cost. For the years ended December 31, 2020, 2019 and 2018, the Partnership’s consolidated statements of operations did not include any material amounts of income from the liquidation of Sunoco LP’s LIFO fuel inventory.

Inventories consisted of the following:

 

     December 31,  
     2020      2019  

Natural gas, NGLs and refined products (1)

   $ 1,013    $ 833

Crude oil

     287      251

Spare parts and other

     439      448
  

 

 

    

 

 

 

Total inventories

   $ 1,739    $ 1,532
  

 

 

    

 

 

 

 

  (1)

Due to changes in fuel prices, Sunoco LP recorded a write-down on the value of its fuel inventory of $82 million for the year ended December 31, 2020.

We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations.

Other Current Assets

Other current assets consisted of the following:

 

     December 31,  
     2020      2019  

Deposits paid to vendors

   $ 75    $ 95

Prepaid expenses and other

     138      180
  

 

 

    

 

 

 

Total other current assets

   $ 213    $ 275
  

 

 

    

 

 

 

Property, Plant and Equipment

Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC-mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations.

Property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate

 

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that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value.

In 2020, the Partnership recognized a $58 million fixed asset impairment primarily due to decreases in projected future cash flow as a result of the overall market demand decline. USAC recorded an $8 million impairment of compression equipment as a result of its evaluations of the future deployment of its idle fleet.

In 2019, USAC recognized a $6 million fixed asset impairment related to certain idle compressor assets. Sunoco LP recognized a $47 million write-down on assets held for sale related to its ethanol plant in Fulton, New York.

In 2018, USAC recognized a $9 million fixed asset impairment related to certain idle compressor assets.

Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our revolving credit facilities when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts—borrowed funds and equity funds.

Components and useful lives of property, plant and equipment were as follows:

 

     December 31,  
     2020      2019  

Land and improvements

   $ 1,233    $ 1,232

Buildings and improvements (1 to 45 years)

     4,236      2,664

Pipelines and equipment (5 to 83 years)

     69,120      64,678

Product storage and related facilities (2 to 83 years)

     6,393      5,898

Right of way (20 to 83 years)

     5,099      4,859

Other (1 to 48 years)

     2,263      1,964

Construction work-in-process

     5,771      8,495
  

 

 

    

 

 

 
     94,115      89,790

Less—Accumulated depreciation and depletion

     (19,008      (15,597
  

 

 

    

 

 

 

Property, plant and equipment, net

   $ 75,107    $ 74,193
  

 

 

    

 

 

 

We recognized the following amounts for the periods presented:

 

     Years Ended December 31,  
     2020      2019      2018  

Depreciation, depletion and amortization expense

   $ 3,275    $ 2,839    $ 2,538

Capitalized interest

     189      166      294

Investments in Unconsolidated Affiliates

We own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other than temporary. During the year ended December 31, 2020, the Partnership recorded an impairment of its investment in White Cliffs of $129 million during the year ended December 31, 2020 due to a decrease in projected future revenues and cash flows as a result of the overall market demand decline that occurred subsequent to the SemGroup acquisition and related purchase price allocation in December 2019.

 

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Other Non-Current Assets, net

Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following:

 

     December 31,  
     2020      2019  

Crude pipeline linefill and tank bottoms

   $ 517    $ 496

Regulatory assets

     41    $ 42

Pension assets

     103      84

Deferred charges

     188      178

Restricted funds

     179      178

Other

     629      593
  

 

 

    

 

 

 

Total other non-current assets, net

   $ 1,657    $ 1,571
  

 

 

    

 

 

 

Restricted funds include an immaterial amount of restricted cash primarily held in our wholly-owned captive insurance companies.

Intangible Assets

Intangible assets are stated at cost, net of amortization computed on the straight-line method. The Partnership removes the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized.

Components and useful lives of intangible assets were as follows:

 

     December 31, 2020      December 31, 2019  
     Gross Carrying
Amount
     Accumulated
Amortization
     Gross Carrying
Amount
     Accumulated
Amortization
 

Amortizable intangible assets:

           

Customer relationships, contracts and agreements (3 to 46 years)

   $ 7,513    $ (2,117    $ 7,535    $ (1,743

Patents (10 years)

     48      (40      48      (35

Trade names (20 years)

     66      (35      66      (31

Other (5 to 20 years)

     19      (15      19      (12
  

 

 

    

 

 

    

 

 

    

 

 

 

Total amortizable intangible assets

     7,646      (2,207      7,668      (1,821

Non-amortizable intangible assets:

           

Trademarks

     295      —          295      —    

Other

     12      —          12      —    
  

 

 

    

 

 

    

 

 

    

 

 

 

Total non-amortizable intangible assets

     307      —          307      —    
  

 

 

    

 

 

    

 

 

    

 

 

 

Total intangible assets

   $ 7,953    $ (2,207    $ 7,975    $ (1,821
  

 

 

    

 

 

    

 

 

    

 

 

 

Aggregate amortization expense of intangible assets was as follows:

 

     Years Ended December 31,  
     2020      2019      2018  

Reported in depreciation, depletion and amortization expense

   $ 403    $ 308    $ 321

 

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Estimated aggregate amortization of intangible assets for the next five years is as follows:

 

Years Ending December 31:

  

2021

   $ 393

2022

     379

2023

     363

2024

     349

2025

     335

We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate.

Sunoco LP performed impairment tests on its indefinite-lived intangible assets during the fourth quarter of 2018 and recognized a $30 million impairment charge on its contractual rights primarily due to decreases in projected future revenues and cash flows from the date the intangible assets were originally recorded.

Goodwill

Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test is performed during the fourth quarter.

Changes in the carrying amount of goodwill were as follows:

 

    Intrastate
Transportation
and Storage
    Interstate
Transportation
and Storage
    Midstream     NGL and
Refined
Products
Transportation
and Services
    Crude Oil
Transportation
and Services
    Investment
in Sunoco
LP
    Investment
in USAC
    All
Other
    Total  

Balance, December 31, 2018

  $ 10   $ 196   $ 492   $ 693   $ 1,167   $ 1,559   $ 619   $ 149   $ 4,885

Acquired

    —         42     —         —         230     —         —         35     307

Impaired

    —         (12     (9     —         —         —         —         —         (21

Other

    —         —         —         —         —         (4     —         —         (4
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance, December 31, 2019

    10     226     483     693     1,397     1,555     619     184     5,167

Acquired

    —         —         —         —         —         9     —         —         9

Impaired

    (10     (226     (483     —         (1,279     —         (619     (198     (2,815

Other

    —         —         —         —         (66     —         —         96     30
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance, December 31, 2020

  $ —       $ —       $ —       $ 693   $ 52   $ 1,564   $ —       $ 82   $ 2,391
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

During the first quarter of 2020, due to the impacts of the COVID-19 pandemic, the decline in commodity prices and the decreases in the Partnership’s market capitalization, we determined that interim impairment testing should be performed on certain reporting units. The Partnership performed the interim impairment tests consistent with our approach for annual impairment testing, including using similar models, inputs and assumptions. As a result of the interim impairment test, the Partnership recognized goodwill impairments of $483 million related to our Ark-La-Tex and South Texas operations within the midstream segment, $183 million related to our Lake Charles LNG regasification operations within the interstate transportation and storage segment due to contractually scheduled reductions in payments for the remainder of the contract term, and $40 million related to our all other operations primarily due to decreases in projected future revenues and cash flows as a result of the overall market demand decline. In addition, USAC recognized a goodwill impairment of $619 million during the three months ended March 31, 2020, which is included in the Partnership’s consolidated results of operations.

 

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During the third quarter of 2020, the Partnership performed interim impairment testing on certain reporting units within its midstream, interstate, crude, NGL and all other operations. As a result, the Partnership recognized goodwill impairments of $1.28 billion related to our crude operations, $132 million related to our Energy Transfer Canada operations within the all other segment and $43 million related to our interstate operations primarily due to decreases in projected future cash flow as a result of the overall market demand decline.

During the fourth quarter of 2020, the Partnership performed annual impairment testing on certain reporting units within its midstream, interstate, crude, NGL and all other operations. As a result, the Partnership recognized goodwill impairments of $10 million related to our intrastate operations, $11 million related to our PEI operations and $15 million related to our Natural Resources operations within the all other segment primarily due to decreases in projected future cash flow as a result of the overall market demand decline. No other impairments of the Partnership’s goodwill were identified.

Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized. During the fourth quarter of 2019, $265 million goodwill was recorded in conjunction with the acquisition of SemGroup.

During the third quarter of 2019, the Partnership recognized a goodwill impairment of $12 million related to the Southwest Gas operations within the interstate segment primarily due to decreases in projected future revenues and cash flows. During the fourth quarter of 2019, the Partnership recognized a goodwill impairment of $9 million related to our North Central operations within the midstream segment primarily due to changes in assumptions related to projected future revenues and cash flows.

During the fourth quarter of 2018, the Partnership recognized goodwill impairments of $378 million related to our Northeast operations within the midstream segment primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded. These changes in assumptions reflect delays in the construction of third-party takeaway capacity in the Northeast.

The Partnership determines the fair value of our reporting units using the discounted cash flow method, the guideline company method, or a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determines fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determines the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimates a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business.

Management does not believe that any of the goodwill balances in its reporting units is currently at significant risk of impairment; however, of the $2.39 billion of goodwill on the Partnership’s consolidated balance sheet as of December 31, 2020, approximately $368 million is recorded in reporting units for which the estimated fair value exceeded the carrying value by less than 20% in the most recent quantitative test.

 

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Asset Retirement Obligations

We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.

An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an ARO in the periods in which management can reasonably estimate the settlement dates.

As of December 31, 2020 and 2019, other non-current liabilities in the Partnership’s consolidated balance sheets included AROs of $270 million and $247 million, respectively. For the years ended December 31, 2020, 2019 and 2018 aggregate accretion expense related to AROs was $16 million, $5 million and $13 million, respectively.

Except for the AROs discussed above, management was not able to reasonably measure the fair value of AROs as of December 31, 2020 and 2019, in most cases because the settlement dates were indeterminable. Although a number of onshore assets in our systems are subject to agreements or regulations that give rise to an ARO upon discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Our subsidiaries also have legal obligations for several other assets at previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, our subsidiaries are legally or contractually required to abandon in place or remove the asset. We believe we may have additional AROs related to pipeline assets and storage tanks, for which it is not possible to estimate whether or when the AROs will be settled. Consequently, these AROs cannot be measured at this time. Sunoco LP also has AROs related to the estimated future cost to remove underground storage tanks.

Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future. We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely.

As of December 31, 2020 and 2019, other non-current assets on the Partnership’s consolidated balance sheets included $34 million and $31 million, respectively, of funds that were legally restricted for the purpose of settling AROs.

 

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Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:

 

     December 31,  
     2020      2019  

Interest payable

   $ 600    $ 579

Customer advances and deposits

     161      123

Accrued capital expenditures

     604      1,334

Accrued wages and benefits

     109      217

Taxes payable other than income taxes

     446      263

Exchanges payable

     127      67

Other

     728      759
  

 

 

    

 

 

 

Total accrued and other current liabilities

   $ 2,775    $ 3,342
  

 

 

    

 

 

 

Deposits or advances are received from our customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may be required when customers exceed their credit limits or do not qualify for open credit.

Redeemable Noncontrolling Interests

Our redeemable noncontrolling interests relate to certain preferred unitholders of one of our consolidated subsidiaries that have the option to convert their preferred units to such subsidiary’s common units at the election of the holders and the noncontrolling interest holders in one of our consolidated subsidiaries that have the option to sell their interests to us. In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable noncontrolling interests on our consolidated balance sheets. See Note 7 for further information.

Environmental Remediation

We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued.

Fair Value of Financial Instruments

The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value.

Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our debt obligations as of December 31, 2020 was $56.21 billion and $51.44 billion, respectively. As of December 31, 2019, the aggregate fair value and carrying amount of our debt obligations was $54.79 billion and $51.05 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.

We have commodity derivatives, interest rate derivatives and embedded derivatives in our preferred units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities.

 

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We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. During the year ended December 31, 2020, no transfers were made between any levels within the fair value hierarchy.

The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2020 and 2019 based on inputs used to derive their fair values:

 

     Fair Value
Total
     Fair Value Measurements at
December 31, 2020
 
     Level 1      Level 2  

Assets:

        

Commodity derivatives:

        

Natural Gas:

        

Basis Swaps IFERC/NYMEX

   $ 12    $ 12    $ —    

Swing Swaps IFERC

     1      —          1

Fixed Swaps/Futures

     13      13      —    

Forward Physical Contracts

     5      —          5

Power:

        

Forwards

     4      —          4

Futures

     2      2      —    

Options—Calls

     1      1      —    

NGLs—Forwards/Swaps

     127      127      —    

Refined Products—Futures

     3      3      —    

Crude—Forwards/Swaps

     —          —          —    
  

 

 

    

 

 

    

 

 

 

Total commodity derivatives

     168      158      10

Other non-current assets

     34      22      12
  

 

 

    

 

 

    

 

 

 

Total assets

   $ 202    $ 180    $ 22
  

 

 

    

 

 

    

 

 

 

Liabilities:

        

Interest rate derivatives

   $ (448    $ —        $ (448

Commodity derivatives:

        

Natural Gas:

        

Basis Swaps IFERC/NYMEX

     (11      (11      —    

Swing Swaps IFERC

     (3      —          (3

Fixed Swaps/Futures

     (13      (13      —    

Forward Physical Contracts

     (1      —          (1

Power:

        

Futures

     (3      (3      —    

NGLs—Forwards/Swaps

     (227      (227      —    

Refined Products—Futures

     (11      (11      —    
  

 

 

    

 

 

    

 

 

 

Total commodity derivatives

     (269      (265      (4
  

 

 

    

 

 

    

 

 

 

Total liabilities

   $ (717    $ (265    $ (452
  

 

 

    

 

 

    

 

 

 

 

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     Fair Value
Total
     Fair Value Measurements
at December 31, 2019
 
     Level 1      Level 2  

Assets:

        

Commodity derivatives:

        

Natural Gas:

        

Basis Swaps IFERC/NYMEX

   $ 17    $ 17    $ —    

Swing Swaps IFERC

     1      —          1

Fixed Swaps/Futures

     65      65      —    

Forward Physical Contracts

     3      —          3

Power:

        

Power—Forwards

     11      —          11

Futures

     4      4      —    

Options—Puts

     1      1      —    

Options—Calls

     1      1      —    

NGLs—Forwards/Swaps

     260      260      —    

Refined Products—Futures

     8      8      —    

Crude—Forwards/Swaps

     13      13      —    
  

 

 

    

 

 

    

 

 

 

Total commodity derivatives

     384      369      15

Other non-current assets

     31      20      11
  

 

 

    

 

 

    

 

 

 

Total assets

   $ 415    $ 389    $ 26
  

 

 

    

 

 

    

 

 

 

Liabilities:

        

Interest rate derivatives

   $ (399    $ —        $ (399

Commodity derivatives:

        

Natural Gas:

        

Basis Swaps IFERC/NYMEX

     (49      (49      —    

Swing Swaps IFERC

     (1      —          (1

Fixed Swaps/Futures

     (43      (43      —    

Power:

        

Forwards

     (5      —          (5

Futures

     (3      (3      —    

NGLs—Forwards/Swaps

     (278      (278      —    

Refined Products—Futures

     (10      (10      —    
  

 

 

    

 

 

    

 

 

 

Total commodity derivatives

     (389      (383      (6
  

 

 

    

 

 

    

 

 

 

Total liabilities

   $ (788    $ (383    $ (405
  

 

 

    

 

 

    

 

 

 

Contributions in Aid of Construction Costs

On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with pipeline construction and production well tie-ins. Contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received, and any CIAC which exceeds our total project costs, is recognized as other income in the period in which it is realized.

Shipping and Handling Costs

Shipping and handling costs are included in cost of products sold, except for shipping and handling costs related to fuel consumed for compression and treating which are included in operating expenses.

 

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Costs and Expenses

Cost of products sold include actual cost of fuel sold, adjusted for the effects of our hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership, and administrative personnel.

We record the collection of taxes to be remitted to government authorities on a net basis, except for consumer excise taxes collected by Sunoco LP on sales of refined products and merchandise which are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income. For the years ended December 31, 2020, 2019 and 2018, excise taxes collected by Sunoco LP were $301 million, $386 million and $370 million, respectively.

Issuances of Subsidiary Units

We record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or comprehensive income. For example, upon our subsidiary’s issuance of common units in a public offering, we record any difference between the amount of consideration received or paid and the amount by which the noncontrolling interests are adjusted as a change in partners’ capital.

Income Taxes

ET is a publicly traded limited partnership and is not taxable for federal and most state income tax purposes. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and most state purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities, in addition to the allocation requirements related to taxable income under our Third Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”).

As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and Internal Revenue Service (“IRS”) pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, ET would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2020, 2019 and 2018, our qualifying income met the statutory requirement.

The Partnership conducts certain activities through corporate subsidiaries which are subject to federal, state and local income taxes. These corporate subsidiaries include ETP Holdco, Inland Corporation, Sunoco Property Company LLC and Aloha. The Partnership and its corporate subsidiaries account for income taxes under the asset and liability method.

Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.

The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing

 

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and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes.

Accounting for Derivative Instruments and Hedging Activities

For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third-party prices, readily available market information, broker quotes and appropriate valuation techniques.

At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in net income for the period.

If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in our consolidated statements of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statements of operations.

Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged.

If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, the change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.

We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. Certain of our interest rate derivatives are accounted for as either cash flow hedges or fair value hedges. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in “Gains (losses) on interest rate derivatives” in the consolidated statements of operations.

Non-Cash Compensation

For awards of restricted units, we recognize compensation expense over the vesting period based on the grant-date fair value, which is determined based on the market price of the underlying common units on the grant date. For awards of cash restricted units, we remeasure the fair value of the award at the end of each reporting period based on the market price of the underlying common units as of the reporting date, and the fair value is recorded in other non-current liabilities on our consolidated balance sheets.

 

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Pensions and Other Postretirement Benefit Plans

The Partnership recognizes the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans). Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. Changes in the funded status of the plan are recorded in the year in which the change occurs within AOCI in equity or, for entities applying regulatory accounting, as a regulatory asset or regulatory liability.

Allocation of Income

For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests.

 

3.

ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:

Pending Enable Acquisition

On February 17, 2021, the Partnership announced its entry into a definitive merger agreement to acquire Enable. Under the terms of the merger agreement, Enable’s common unitholders will receive 0.8595 of an ET common unit in exchange for each Enable common unit. In addition, each outstanding Enable Series A preferred unit will be exchanged for 0.0265 of an ET Series G preferred unit, and ET will make a $10 million cash payment for Enable’s general partner. The transaction is subject to the approval of Enable’s unitholders and other customary regulatory approvals.

SemGroup Acquisition and ET Contribution of SemGroup Assets to ETO

On December 5, 2019, ET completed the acquisition of SemGroup pursuant to the terms of the Agreement and Plan of Merger, dated as of September 15, 2019 (the “Merger Agreement”). Under the terms of the Merger Agreement, a wholly owned subsidiary of ET merged with and into SemGroup (the “SemGroup Transaction”), with SemGroup surviving the merger. At the effective time of the SemGroup Transaction on December 5, 2019, each share of class A common stock, par value $0.01 per share, of SemGroup issued and outstanding immediately prior to the effective time was converted into the right to receive (i) $6.80 in cash, without interest, and (ii) 0.7275 ET Common Units representing limited partner interests in ET. Each share of Series A Cumulative Perpetual Convertible Preferred Stock, par value $0.01 per share, of SemGroup that was issued and outstanding as of immediately prior to the effective time was redeemed by SemGroup for cash at a price per share equal to 101% of the liquidation preference.

 

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During the first and second quarters of 2020, ET contributed former SemGroup assets to ETO through sale and contribution transactions. The following table represents the fair value, as of December 5, 2019, of the SemGroup assets and liabilities transferred from ET to ETO:

 

     At December 5,
2019
 

Total current assets

   $ 794

Property, plant and equipment

     3,891

Other non-current assets

     617

Goodwill

     295

Intangible assets

     460
  

 

 

 

Total assets

   $ 6,057
  

 

 

 

Total current liabilities

   $ 629

Long-term debt, less current maturities (1)

     2,576

Other non-current liabilities

     197

Energy Transfer Canada Preferred shares

     241
  

 

 

 

Total liabilities

     3,643

Noncontrolling interest

     822

Partners’ capital

     1,592
  

 

 

 

Total liabilities and partners’ capital

   $ 6,057
  

 

 

 

 

  (1) 

Long-term debt at December 5, 2019 includes SemGroup senior notes with an aggregate principal amount of $1.375 billion and SemGroup subsidiary debt of $593 million, all of which was redeemed in December 2019, subsequent to the close of the SemGroup Transaction.

During 2020, the Partnership has recorded impairments on certain of the contributed SemGroup assets. Those impairments include a $244 million impairment of goodwill and a $129 million impairment of other non-current assets.

ET Contribution of Assets to ETO

Immediately prior to the closing of the Energy Transfer Merger discussed in Note 1, ET contributed the following to ETO:

 

   

2,263,158 common units representing limited partner interests in Sunoco LP to ETO in exchange for 2,874,275 ETO common units;

 

   

100 percent of the limited liability company interests in Sunoco GP LLC, the sole general partner of Sunoco LP, and all of the IDRs in Sunoco LP, to ETO in exchange for 42,812,389 ETO common units;

 

   

12,466,912 common units representing limited partner interests in USAC and 100 percent of the limited liability company interests in USA Compression GP, LLC, the general partner of USAC, to ETO in exchange for 16,134,903 ETO common units; and

 

   

a 100 percent limited liability company interest in Lake Charles LNG and a 60 percent limited liability company interest in each of Energy Transfer LNG Export, LLC, ET Crude Oil Terminals, LLC and ETC Illinois LLC to ETO in exchange for 37,557,815 ETO common units.

USAC Acquisition

On April 2, 2018, ET acquired a controlling interest in USAC, a publicly traded partnership that provides compression services in the United States. Specifically, the Partnership acquired (i) all of the outstanding limited liability company interests in USA Compression GP, LLC (“USAC GP”), the general partner of

 

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USAC, and (ii) 12,466,912 USAC common units representing limited partner interests in USAC for cash consideration equal to $250 million (the “USAC Transaction”). Concurrently, USAC cancelled its IDRs and converted its economic general partner interest into a non-economic general partner interest in exchange for the issuance of 8,000,000 USAC common units to USAC GP.

Concurrent with these transactions, ETO contributed to USAC all of the issued and outstanding membership interests of CDM for aggregate consideration of approximately $1.7 billion, consisting of (i) 19,191,351 USAC common units, (ii) 6,397,965 units of a newly authorized and established class of units representing limited partner interests in USAC (“USAC Class B Units”) and (iii) $1.23 billion in cash, including customary closing adjustments (the “CDM Contribution”). The USAC Class B Units are a new class of partnership interests of USAC that have substantially all of the rights and obligations of a USAC common unit, except the USAC Class B Units will not participate in distributions for the first four quarters following the closing date of April 2, 2018. Each USAC Class B Unit will automatically convert into one USAC common unit on the first business day following the record date attributable to the quarter ending June 30, 2019.

Prior to the USAC acquisition, the CDM entities were indirect wholly-owned subsidiaries of ETO. Beginning April 2018, ETE’s consolidated financial statements reflected USAC as a consolidated subsidiary.

Summary of Assets Acquired and Liabilities Assumed

The USAC Transaction was recorded using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date.

The total purchase price was allocated as follows:

 

     At April 2,
2018
 

Total current assets (2)

   $ 786

Property, plant and equipment

     1,332

Other non-current assets

     15

Goodwill (1)

     366

Intangible assets

     222
  

 

 

 

Total assets

   $ 2,721
  

 

 

 

Total current liabilities

   $ 110

Long-term debt, less current maturities

     1,527

Other non-current liabilities

     2
  

 

 

 

Total liabilities

     1,639

Noncontrolling interest

     832

Partners’ capital

     250
  

 

 

 

Total liabilities and partners’ capital

   $ 2,721
  

 

 

 

 

  (1)

None of the goodwill is expected to be deductible for tax purposes. Goodwill recognized from the business combination primarily relates to the value attributed to additional growth opportunities, synergies and operating leverage within USAC’s operations.

  (2)

Includes cash and cash equivalents of $711 million held by USAC as of the acquisition date.

The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.

 

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Sunoco LP Retail Store Divestment

On January 23, 2018, Sunoco LP completed the disposition of assets pursuant to the purchase agreement with 7-Eleven, Inc. (the “7-Eleven Transaction”). As a result of the 7-Eleven Transaction, previously eliminated wholesale motor fuel sales to Sunoco LP’s retail locations are reported as wholesale motor fuel sales to third parties.

In connection with the 7-Eleven Transaction, Sunoco LP entered into a 15-year take-or-pay fuel supply arrangement with 7-Eleven and SEI Fuel. For the period from January 1, 2018 through January 22, 2018, Sunoco LP recorded sales to the sites that were subsequently sold to 7-Eleven of $199 million, which sales were eliminated in consolidation.

The Partnership has concluded that it meets the accounting requirements for reporting the financial position, results of operations and cash flows of the 7-Eleven Transaction and the operations of the related assets as discontinued operations.

There were no results of operations associated with discontinued operations for the year ended December 31, 2019. The results of operations associated with discontinued operations for the years ended December 31, 2018 and 2017 are presented in the following table:

 

     Year Ended
December 31, 2018
 

REVENUES

   $ 349

COSTS AND EXPENSES

  

Cost of products sold

     305

Operating expenses

     61

Selling, general and administrative

     7
  

 

 

 

Total costs and expenses

     373
  

 

 

 

OPERATING LOSS

     (24

OTHER EXPENSE

  

Interest expense, net

     2

Loss on extinguishment of debt

     20

Other, net

     61
  

 

 

 

LOSS FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE

     (107

Income tax expense

     158
  

 

 

 

LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES

     (265
  

 

 

 

LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES ATTRIBUTABLE TO ET

   $ (10
  

 

 

 

 

4.

INVESTMENTS IN UNCONSOLIDATED AFFILIATES:

Citrus

ETO owns CrossCountry Energy, LLC, a wholly-owned subsidiary of ETO, which in turn owns a 50% interest in Citrus. The other 50% interest in Citrus is owned by a subsidiary of KMI. Citrus owns 100% of FGT, an approximately 5,362-mile natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula. Our investment in Citrus is reflected in our interstate transportation and storage segment.

 

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FEP

ETO has a 50% interest in FEP which owns the Fayetteville Express Pipeline, an approximately 185-mile natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline in Panola County, Mississippi. ETO’s investment in FEP is reflected in the interstate transportation and storage segment.

MEP

ETO owns a 50% interest in MEP, which owns the Midcontinent Express Pipeline, an approximately 500-miles natural gas pipeline that extends from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama. ETO’s investment in MEP is reflected in the interstate transportation and storage segment.

White Cliffs

We own a 51% interest in White Cliffs, which was acquired by ET in the SemGroup acquisition and contributed to ETO in January 2020. White Cliffs consists of two parallel, 12-inch common carrier pipelines: one crude oil pipeline and one NGL pipeline. These pipelines transport crude and NGLs from Platteville, Colorado to Cushing, Oklahoma. The Partnership recorded an impairment of its investment in White Cliffs of $129 million during the year ended December 31, 2020 due to a decrease in projected future revenues and cash flows as a result of the overall market demand decline that occurred subsequent to the SemGroup acquisition and related purchase price allocation in December 2019.

The carrying values of the Partnership’s investments in unconsolidated affiliates as of December 31, 2020 and 2019 were as follows:

 

     December 31,  
     2020      2019  

Citrus

   $ 1,867    $ 1,876

FEP

     4      218

MEP

     406      429

White Cliffs

     274      436

Other

     509      501
  

 

 

    

 

 

 

Total

   $ 3,060    $ 3,460
  

 

 

    

 

 

 

The following table presents equity in earnings (losses) of unconsolidated affiliates:

 

     Years Ended December 31,  
     2020      2019      2018  

Citrus

   $ 162    $ 148    $ 141

FEP (1)

     (139      59      55

MEP

     (6      15      31

White Cliffs

     20      4      —    

Other

     82      76      117
  

 

 

    

 

 

    

 

 

 

Total equity in earnings of unconsolidated affiliates

   $ 119    $ 302    $ 344
  

 

 

    

 

 

    

 

 

 

 

  (1) 

For the year ended December 31, 2020, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by FEP, which reduced the Partnership’s equity in earnings by $208 million.

 

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Summarized Financial Information

The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, Citrus, FEP, MEP, and White Cliffs (on a 100% basis) for all periods presented, except as noted below:

 

     December 31,  
     2020      2019  

Current assets

   $ 227    $ 247

Property, plant and equipment, net

     7,339      7,680

Other assets

     58      40
  

 

 

    

 

 

 

Total assets

   $ 7,624    $ 7,967
  

 

 

    

 

 

 

Current liabilities

   $ 600    $ 738

Non-current liabilities

     3,298      3,242

Equity

     3,726      3,987
  

 

 

    

 

 

 

Total liabilities and equity

   $ 7,624    $ 7,967
  

 

 

    

 

 

 

 

     Years Ended December 31,  
     2020      2019      2018  

Revenue

   $ 1,243    $ 1,192    $ 1,249

Operating income

     6      683      723

Net income (loss)

     (199      443      460

In addition to the equity method investments described above we have other equity method investments which are not significant to our consolidated financial statements.

 

5.

NET INCOME PER LIMITED PARTNER UNIT:

Basic net income per limited partner unit is computed by dividing net income, after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding. Diluted net income per limited partner unit is computed by dividing net income (as adjusted as discussed herein), after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding and the assumed conversion of the ET Series A Convertible Preferred Units, as discussed in Note 8. For the diluted earnings per share computation, income allocable to the limited partners is reduced, where applicable, for the decrease in earnings from ET’s limited partner unit ownership in ETO or Sunoco LP that would have resulted assuming the incremental units related to our or Sunoco LP’s equity incentive plans, as applicable, had been issued during the respective periods. Such units have been determined based on the treasury stock method.

 

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A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows:

 

     Years Ended December 31,  
     2020      2019      2018  

Income from continuing operations

   $ 140    $ 4,825    $ 3,685

Less: Net income attributable to redeemable noncontrolling interests

     49      51      39

Less: Income from continuing operations attributable to noncontrolling interests

     739      1,256      1,888
  

 

 

    

 

 

    

 

 

 

Income (loss) from continuing operations, net of noncontrolling interests

     (648      3,518      1,758

Less: General Partner’s interest in income (loss) from continuing operations

     (1      4      3

Less: ET Series A Convertible Preferred Unitholders’ interest in net income from continuing operations

     —          —          33
  

 

 

    

 

 

    

 

 

 

Income (loss) from continuing operations available to Limited Partners

   $ (647    $ 3,514    $ 1,722
  

 

 

    

 

 

    

 

 

 

Basic Income (Loss) from Continuing Operations per Limited Partner Unit:

        

Weighted average limited partner units

     2,695.6      2,628.0      1,423.8
  

 

 

    

 

 

    

 

 

 

Basic income (loss) from continuing operations per Limited Partner unit

   $ (0.24    $ 1.34    $ 1.21
  

 

 

    

 

 

    

 

 

 

Basic loss from discontinued operations per Limited Partner unit

   $ —        $ —        $ (0.01
  

 

 

    

 

 

    

 

 

 

Diluted Income (Loss) from Continuing Operations per Limited Partner Unit:

        

Income (loss) from continuing operations available to Limited Partners

   $ (647    $ 3,514    $ 1,722

Dilutive effect of equity-based compensation of subsidiaries and distributions to convertible units

     —          (1      33
  

 

 

    

 

 

    

 

 

 

Diluted income (loss) from continuing operations available to Limited Partners

     (647      3,513      1,755
  

 

 

    

 

 

    

 

 

 

Weighted average limited partner units

     2,695.6      2,628.0      1,423.8

Dilutive effect of unconverted unit awards and ET Series A Convertible Preferred Units

     —          —          30.3

Dilutive effect of unvested unit awards

     —          9.6      7.3
  

 

 

    

 

 

    

 

 

 

Weighted average limited partner units, assuming dilutive effect of unvested unit awards

     2,695.6      2,637.6      1,461.4
  

 

 

    

 

 

    

 

 

 

Diluted income (loss) from continuing operations per Limited Partner unit

   $ (0.24    $ 1.33    $ 1.20
  

 

 

    

 

 

    

 

 

 

Diluted loss from discontinued operations per Limited Partner unit

   $ —        $ —        $ (0.01
  

 

 

    

 

 

    

 

 

 

 

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6.

DEBT OBLIGATIONS:

Our debt obligations consist of the following:

 

     December 31,  
     2020      2019  

Parent Company Indebtedness:

     

7.50% Senior Notes due October 15, 2020 (1)

   $ —        $ 52

4.25% Senior Notes due March 15, 2023

     5      5

5.875% Senior Notes due January 15, 2024

     23      23

5.50% Senior Notes due June 1, 2027

     44      44
  

 

 

    

 

 

 
     72      124
  

 

 

    

 

 

 

Subsidiary Indebtedness:

     

ETO Debt

     

5.50% Senior Notes due February 15, 2020 (1)

     —          250

5.75% Senior Notes due September 1, 2020 (1)

     —          400

4.15% Senior Notes due October 1, 2020 (1)

     —          1,050

7.50% Senior Notes due October 15, 2020 (1)

     —          1,135

4.40% Senior Notes due April 1, 2021 (2)

     600      600

4.65% Senior Notes due June 1, 2021 (2)

     800      800

5.20% Senior Notes due February 1, 2022

     1,000      1,000

4.65% Senior Notes due February 15, 2022

     300      300

5.875% Senior Notes due March 1, 2022

     900      900

5.00% Senior Notes due October 1, 2022

     700      700

3.45% Senior Notes due January 15, 2023

     350      350

3.60% Senior Notes due February 1, 2023

     800      800

4.25% Senior Notes due March 15, 2023

     995      995

4.20% Senior Notes due September 15, 2023

     500      500

4.50% Senior Notes due November 1, 2023

     600      600

5.875% Senior Notes due January 15, 2024

     1,127      1,127

4.90% Senior Notes due February 1, 2024

     350      350

7.60% Senior Notes due February 1, 2024

     277      277

4.25% Senior Notes due April 1, 2024

     500      500

4.50% Senior Notes due April 15, 2024

     750      750

9.00% Debentures due November 1, 2024

     65      65

4.05% Senior Notes due March 15, 2025

     1,000      1,000

2.90% Senior Notes due May 15, 2025

     1,000      —    

5.95% Senior Notes due December 1, 2025

     400      400

4.75% Senior Notes due January 15, 2026

     1,000      1,000

3.90% Senior Notes due July 15, 2026

     550      550

4.20% Senior Notes due April 15, 2027

     600      600

5.50% Senior Notes due June 1, 2027

     956      956

4.00% Senior Notes due October 1, 2027

     750      750

4.95% Senior Notes due June 15, 2028

     1,000      1,000

5.25% Senior Notes due April 15, 2029

     1,500      1,500

8.25% Senior Notes due November 15, 2029

     267      267

3.75% Senior Note due May 15, 2030

     1,500      —    

4.90% Senior Notes due March 15, 2035

     500      500

6.625% Senior Notes due October 15, 2036

     400      400

5.80% Senior Notes due June 15, 2038

     500      500

7.50% Senior Notes due July 1, 2038

     550      550

6.85% Senior Notes due February 15, 2040

     250      250

 

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6.05% Senior Notes due June 1, 2041

     700      700

6.50% Senior Notes due February 1, 2042

     1,000      1,000

6.10% Senior Notes due February 15, 2042

     300      300

4.95% Senior Notes due January 15, 2043

     350      350

5.15% Senior Notes due February 1, 2043

     450      450

5.95% Senior Notes due October 1, 2043

     450      450

5.30% Senior Notes due April 1, 2044

     700      700

5.15% Senior Notes due March 15, 2045

     1,000      1,000

5.35% Senior Notes due May 15, 2045

     800      800

6.125% Senior Notes due December 15, 2045

     1,000      1,000

5.30% Senior Notes due April 15, 2047

     900      900

5.40% Senior Notes due October 1, 2047

     1,500      1,500

6.00% Senior Notes due June 15, 2048

     1,000      1,000

6.25% Senior Notes due April 15, 2049

     1,750      1,750

5.00% Senior Notes due May 15, 2050

     2,000      —    

Floating Rate Junior Subordinated Notes due November 1, 2066

     546      546

ETO $2.00 billion Term Loan facility due October 2022

     2,000      2,000

ETO $5.00 billion Revolving Credit Facility due December 2023

     3,103      4,214

Unamortized premiums, discounts and fair value adjustments, net

     (17      (5

Deferred debt issuance costs

     (215      (207
  

 

 

    

 

 

 
     42,654      42,120
  

 

 

    

 

 

 

Transwestern Debt

     

5.36% Senior Notes due December 9, 2020 (1)

     —          175

5.89% Senior Notes due May 24, 2022

     150      150

5.66% Senior Notes due December 9, 2024

     175      175

6.16% Senior Notes due May 24, 2037

     75      75

Deferred debt issuance costs

     —          (1
  

 

 

    

 

 

 
     400      574
  

 

 

    

 

 

 

Panhandle Debt

     

7.60% Senior Notes due February 1, 2024

     82      82

7.00% Senior Notes due July 15, 2029

     66      66

8.25% Senior Notes due November 15, 2029

     33      33

Floating Rate Junior Subordinated Notes due November 1, 2066

     54      54

Unamortized premiums, discounts and fair value adjustments, net

     10      11
  

 

 

    

 

 

 
     245      246
  

 

 

    

 

 

 

Bakken Project Debt

     

3.625% Senior Notes due April 1, 2022

     650      650

3.90% Senior Notes due April 1, 2024

     1,000      1,000

4.625% Senior Notes due April 1, 2029

     850      850

Unamortized premiums, discounts and fair value adjustments, net

     (3      (3

Deferred debt issuance costs

     (13      (16
  

 

 

    

 

 

 
     2,484      2,481
  

 

 

    

 

 

 

 

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Sunoco LP Debt

     

4.875% Senior Notes Due January 15, 2023

     436      1,000

5.50% Senior Notes Due February 15, 2026

     800      800

6.00% Senior Notes Due April 15, 2027

     600      600

5.875% Senior Notes Due March 15, 2028

     400      400

4.50% Senior Notes due May 15, 2029

     800      —    

Sunoco LP $1.50 billion Revolving Credit Facility due July 2023

     —          162

Lease-related obligations

     103      135

Deferred debt issuance costs

     (27      (26
  

 

 

    

 

 

 
     3,112      3,071
  

 

 

    

 

 

 

USAC Debt

     

6.875% Senior Notes due April 1, 2026

     725      725

6.875% Senior Notes due September 1, 2027

     750      750

USAC $1.60 billion Revolving Credit Facility due April 2023

     474      403

Deferred debt issuance costs

     (22      (26
  

 

 

    

 

 

 
     1,927      1,852
  

 

 

    

 

 

 

SemGroup Debt

     

HFOTCO Tax Exempt Notes due 2050

     225      225

Energy Transfer Canada Revolver due February 25, 2024

     57      92

Energy Transfer Canada Term Loan A due February 25, 2024

     261      269

Unamortized premiums, discounts and fair value adjustments, net

     —          1

Deferred debt issuance costs

     (2      (3
  

 

 

    

 

 

 
     541      584
  

 

 

    

 

 

 

Other

     3      2
  

 

 

    

 

 

 

Total debt

     51,438      51,054

Less: Current maturities of long-term debt

     21      26
  

 

 

    

 

 

 

Long-term debt, less current maturities

   $ 51,417    $ 51,028
  

 

 

    

 

 

 

 

  (1)

As of December 31, 2019, these notes were classified as long-term as management had the intent and ability to refinance the borrowings on a long-term basis. The notes were redeemed in January 2020.

  (2)

As of December 31, 2020, these notes were classified as long-term as management had the intent and ability to refinance the borrowings on a long-term basis.

 

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The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $289 million in unamortized premiums, fair value adjustments and deferred debt issuance costs, net:

 

2021

   $ 1,420

2022

     5,731

2023

     7,292

2024

     4,621

2025

     2,408

Thereafter

     30,255
  

 

 

 

Total

   $ 51,727
  

 

 

 

Long-term debt reflected on our consolidated balance sheets includes fair value adjustments related to interest rate swaps, which represent fair value adjustments that had been recorded in connection with fair value hedge accounting prior to the termination of the interest rate swap.

Notes and Debentures

ET Senior Notes

The ET Senior Notes are the Parent Company’s senior obligations, ranking equally in right of payment with our other existing and future unsubordinated debt and senior to any of its future subordinated debt. The Parent Company’s obligations under the ET Senior Notes previously were secured on a first-priority basis with its obligations under the Revolver Credit Agreement and the ET Term Loan Facility, by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets, subject to certain exceptions and permitted liens. Subsequent to the termination of the Revolver Credit Agreement and the ET Term Loan Facility, the collateral securing the ET Senior Notes was released. The ET Senior Notes are not guaranteed by any of the Parent Company’s subsidiaries.

The covenants related to the ET Senior Notes include a limitation on liens, a limitation on transactions with affiliates, a restriction on sale-leaseback transactions and limitations on mergers and sales of all or substantially all of the Parent Company’s assets.

ETO Senior Notes

The ETO senior notes were registered under the Securities Act of 1933 (as amended). The Partnership may redeem some or all of the ETO senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the ETO senior notes. The balance is payable upon maturity. Interest on the ETO senior notes is paid semi-annually.

The ETO senior notes are unsecured obligations of the Partnership and as a result, the ETO senior notes effectively rank junior to any future indebtedness of ours or our subsidiaries that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the ETO senior notes effectively rank junior to all indebtedness and other liabilities of our existing and future subsidiaries.

ETO January 2020 Senior Notes Offering and Redemption

On January 22, 2020, ETO completed a registered offering (the “January 2020 Senior Notes Offering”) of $1 billion aggregate principal amount of ETO’s 2.900% Senior Notes due 2025, $1.5 billion aggregate principal amount of ETO’s 3.750% Senior Notes due 2030, and $2 billion aggregate principal amount of ETO’s 5.000% Senior Notes due 2050, (collectively, the “Notes”). The Notes are fully and unconditionally guaranteed by the Partnership’s wholly-owned subsidiary, Sunoco Logistics Partners Operations L.P., on a senior unsecured basis.

 

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Utilizing proceeds from the January 2020 Senior Notes Offering, ETO redeemed its $400 million aggregate principal amount of 5.75% Senior Notes due September 1, 2020, its $1.05 billion aggregate principal amount of 4.15% Senior Notes due October 1, 2020, its $1.14 billion aggregate principal amount of 7.50% Senior Notes due October 15, 2020, its $250 million aggregate principal amount of 5.50% Senior Notes due February 15, 2020, ET’s $52 million aggregate principal amount of 7.50% Senior Notes due October 15, 2020 and Transwestern’s $175 million aggregate principal amount of 5.36% Senior Notes due December 9, 2020.

Transwestern Senior Notes

The Transwestern senior notes are redeemable at any time in whole or pro rata, subject to a premium or upon a change of control event or an event of default, as defined. The balance is payable upon maturity. Interest is paid semi-annually.

Sunoco LP November 2020 Senior Notes Offering and Repurchase

On November 9, 2020, Sunoco LP completed a private offering of $800 million in aggregate principal amount of 4.500% senior notes due 2029. Sunoco LP used the proceeds to fund the tender offer on its 4.875% $1 billion senior notes due 2023. Approximately 56% of the 2023 senior notes were tendered. On January 15, 2021, Sunoco LP repurchased the remaining outstanding portion of its 2023 senior notes.

Term Loans, Credit Facilities and Commercial Paper

ETO Term Loan

On October 17, 2019, ETO entered into a term loan credit agreement (the “ETO Term Loan”) providing for a $2.00 billion three-year term loan credit facility. Borrowings under the term loan agreement mature on October 17, 2022 and are available for working capital purposes and for general partnership purposes. The term loan agreement is unsecured and is guaranteed by our subsidiary, Sunoco Logistics Operations.

As of December 31, 2020, the ETO Term Loan had $2.00 billion outstanding and was fully drawn. The weighted average interest rate on the total amount outstanding as of December 31, 2020 was 1.15%.

ETO Five-Year Credit Facility

ETO’s revolving credit facility (the “ETO Five-Year Credit Facility”) allows for unsecured borrowings up to $5.00 billion and matures on December 1, 2023. The ETO Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to $6.00 billion under certain conditions.

As of December 31, 2020, the ETO Five-Year Credit Facility had $3.10 billion outstanding, of which $1.66 billion was commercial paper. The amount available for future borrowings was $1.79 billion after accounting for outstanding letters of credit in the amount of $109 million. The weighted average interest rate on the total amount outstanding as of December 31, 2020 was 1.12%.

ETO 364-Day Facility

ETO’s 364-day revolving credit facility (the “ETO 364-Day Facility”) allows for unsecured borrowings up to $1.00 billion and matures on November 26, 2021. As of December 31, 2020, the ETO 364-Day Facility had no outstanding borrowings.

Sunoco LP Credit Facility

Sunoco LP maintains a $1.50 billion revolving credit facility (the “Sunoco LP Credit Facility”). As of December 31, 2020, the Sunoco LP Credit Facility had no outstanding borrowings and $8 million in standby letters of credit. The amount available for future borrowings was $1.5 billion at December 31, 2020.

 

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USAC Credit Facility

USAC maintains a $1.60 billion revolving credit facility (the “USAC Credit Facility”), which matures on April 2, 2023 and permits up to $400 million of future increases in borrowing capacity. As of December 31, 2020, USAC had $474 million of outstanding borrowings and no outstanding letters of credit under the credit agreement. As of December 31, 2020, USAC had $1.1 billion of availability under its credit facility. The weighted average interest rate on the total amount outstanding as of December 31, 2020 was 3.27%.

Energy Transfer Canada Credit Facilities

Energy Transfer Canada is party to a credit agreement providing for a C$350 million (US$275 million at the December 31, 2020 exchange rate) senior secured term loan facility, a C$525 million (US$412 million at the December 31, 2020 exchange rate) senior secured revolving credit facility, and a C$300 million (US$236 million at the December 31, 2020 exchange rate) senior secured construction loan facility (the “KAPS Facility”). The term loan facility and the revolving credit facility mature on February 25, 2024. The KAPS Facility matures on June 13, 2024. Energy Transfer Canada may incur additional term loans and revolving commitments in an aggregate amount not to exceed C$250 million (US$196 million at the December 31, 2020 exchange rate), subject to receiving commitments for such additional term loans or revolving commitments from either new lenders or increased commitments from existing lenders.

Covenants Related to Our Credit Agreements

Covenants Related to the Parent Company

The Term Loan Facility and ET Revolving Credit Facility previously contained customary representations, warranties, covenants, and events of default, including a change of control event of default and limitations on incurrence of liens, new lines of business, merger, transactions with affiliates and restrictive agreements. Both facilities have been paid off and terminated.

Covenants Related to ETO

The agreements relating to the ETO senior notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions.

The ETO Credit Facilities (defined as the ETO Term Loan, ETO Five-Year Credit Facility and ETO 364-Day Credit Facility) contain covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries’ ability to, among other things:

 

   

incur indebtedness;

 

   

grant liens;

 

   

enter into mergers;

 

   

dispose of assets;

 

   

make certain investments;

 

   

make Distributions (as defined in the ETO Credit Facilities) during certain Defaults (as defined in the ETO Credit Facilities) and during any Event of Default (as defined in the ETO Credit Facilities);

 

   

engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries;

 

   

engage in transactions with affiliates; and

 

   

enter into restrictive agreements.

 

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The ETO Credit Facilities applicable margin and rate used in connection with the interest rates and commitment fees, respectively, are based on the credit ratings assigned to our senior, unsecured, non-credit enhanced long-term debt. The applicable margin for eurodollar rate loans under the ETO Five-Year Credit Facility ranges from 1.125% to 2.000% and the applicable margin for base rate loans ranges from 0.125% to 1.000%. The applicable rate for commitment fees under the ETO Five-Year Credit Facility ranges from 0.125% to 0.300%. The applicable margin for eurodollar rate loans under the ETO 364-Day Facility ranges from 1.500% to 2.000% and the applicable margin for base rate loans ranges from 0.500% to 1.000%. The applicable rate for commitment fees under the ETO 364-Day Facility ranges from 0.125% to 0.225%.

The ETO Credit Facilities contain various covenants including limitations on the creation of indebtedness and liens and related to the operation and conduct of our business. The ETO Credit Facilities also limit us, on a rolling four quarter basis, to a maximum Consolidated Funded Indebtedness to Consolidated EBITDA ratio, as defined in the underlying credit agreements, of 5.0 to 1, which can generally be increased to 5.5 to 1 during a Specified Acquisition Period. Our Leverage Ratio was 4.31 to 1 at December 31, 2020, as calculated in accordance with the credit agreements.

The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio.

Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Partnership’s or our subsidiaries’ ability to incur additional debt and/or our ability to pay distributions to Unitholders.

Covenants Related to Panhandle

Panhandle is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of Panhandle’s lending agreements.

Panhandle’s restrictive covenants include restrictions on liens securing debt and guarantees and restrictions on mergers and on the sales of assets. A breach of any of these covenants could result in acceleration of Panhandle’s debt.

Covenants Related to Sunoco LP

The Sunoco LP Credit Facility contains various customary representations, warranties, covenants and events of default, including a change of control event of default, as defined therein. Sunoco LP’s Credit Facility requires Sunoco LP to maintain a Net Leverage Ratio of not more than 5.5 to 1. The maximum Net Leverage Ratio is subject to upwards adjustment of not more than 6.0 to 1 for a period not to exceed three fiscal quarters in the event Sunoco LP engages in certain specified acquisitions of not less than $50 million (as permitted under Sunoco LP’s Credit Facility agreement). The Sunoco LP Credit Facility also requires Sunoco LP to maintain an Interest Coverage Ratio (as defined in the Sunoco LP’s Credit Facility agreement) of not less than 2.25 to 1.

Covenants Related to USAC

The USAC Credit Facility contains covenants that limit (subject to certain exceptions) USAC’s ability to, among other things:

 

   

grant liens;

 

   

make certain loans or investments;

 

   

incur additional indebtedness or guarantee other indebtedness;

 

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merge or consolidate;

 

   

sell our assets; or

 

   

make certain acquisitions.

The credit facility is also subject to the following financial covenants, including covenants requiring us to maintain:

 

   

a minimum EBITDA to interest coverage ratio of 2.5 to 1.0, determined as of the last day of each fiscal quarter; and

 

   

a maximum funded debt to EBITDA ratio, determined as of the last day of each fiscal quarter, for the annualized trailing three months of (i) 5.75 to 1 through the end of the fiscal quarter ending December 31, 2020 and (ii) 5.5 to 1 for the fiscal quarters ending March 31, 2021 and June 30, 2021, (iii) 5.25 to 1 for the fiscal quarters ending September 30, 2021 and December 31, 2021 and (iv) 5.0 to 1 thereafter, subject to a provision for increases to such thresholds, in the case of any fiscal quarter ending September 30, 2021 or thereafter, by 0.50 in connection with certain future acquisitions for the six consecutive month period following the period in which any such acquisition occurs, provided that, in any event, such ratio shall not exceed 5.5 to 1.

Covenants Related to the HFOTCO Tax Exempt Notes

The indentures covering HFOTCO’s tax exempt notes due 2050 (“IKE Bonds”) include customary representations and warranties and affirmative and negative covenants. Such covenants include limitations on the creation of new liens, indebtedness, making of certain restricted payments and payments on indebtedness, making certain dispositions, making material changes in business activities, making fundamental changes including liquidations, mergers or consolidations, making certain investments, entering into certain transactions with affiliates, making amendments to certain credit or organizational agreements, modifying the fiscal year, creating or dealing with hazardous materials in certain ways, entering into certain hedging arrangements, entering into certain restrictive agreements, funding or engaging in sanctioned activities, taking actions or causing the trustee to take actions that materially adversely affect the rights, interests, remedies or security of the bondholders, taking actions to remove the trustee, making certain amendments to the bond documents, and taking actions or omitting to take actions that adversely impact the tax exempt status of the IKE Bonds.

Compliance with our Covenants

Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities and note agreements could require us or our subsidiaries to pay debt balances prior to scheduled maturity and could negatively impact the subsidiaries ability to incur additional debt and/or our ability to pay distributions.

We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2020.

 

7.

REDEEMABLE NONCONTROLLING INTERESTS:

Certain redeemable noncontrolling interests in the Partnership’s subsidiaries are reflected as mezzanine equity on the consolidated balance sheet. Redeemable noncontrolling interests as of December 31, 2020 included a balance of $477 million related to the USAC Preferred Units described below and a balance of $15 million related to noncontrolling interest holders in one of the Partnership’s consolidated subsidiaries that have the option to sell their interests to the Partnership. In addition, redeemable noncontrolling interests includes a balance of $270 million in Energy Transfer Canada preferred shares acquired as part of the 2019 merger with SemGroup.

 

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USAC Series A Preferred Units

In 2018, USAC issued 500,000 USAC Preferred Units in a private placement at a price of $1,000 per USAC Preferred Unit, for total gross proceeds of $500 million in a private placement.

The USAC Preferred Units are entitled to receive cumulative quarterly distributions equal to $24.375 per USAC Preferred Unit, subject to increase in certain limited circumstances. The USAC Preferred Units will have a perpetual term, unless converted or redeemed. Certain portions of the USAC Preferred Units will be convertible into USAC common units at the election of the holders beginning in 2021. To the extent the holders of the USAC Preferred Units have not elected to convert their preferred units by the fifth anniversary of the issue date, USAC will have the option to redeem all or any portion of the USAC Preferred Units for cash. In addition, at any time on or after the tenth anniversary of the issue date, the holders of the USAC Preferred Units will have the right to require USAC to redeem all or any portion of the USAC Preferred Units, and the Partnership may elect to pay up to 50% of such redemption amount in USAC common units.

Energy Transfer Canada Redeemable Preferred Stock

Energy Transfer Canada has 300,000 shares of cumulative preferred stock issued and outstanding. The preferred stock is redeemable at Energy Transfer Canada’s option subsequent to January 3, 2021 at a redemption price of C$1,100 (US$864 at the December 31, 2020 exchange rate) per share. The preferred stock is redeemable by the holder contingent upon a change of control or liquidation of Energy Transfer Canada. The preferred stock is convertible to Energy Transfer Canada common shares in the event of an initial public offering by Energy Transfer Canada.

The preferred stock was recorded at fair value in connection with the SemGroup purchase accounting. Dividends on the preferred stock are payable in-kind through the quarter ending June 30, 2020. The dividends paid-in-kind increased the liquidation preference such that as of December 31, 2020, the preferred stock was convertible into 344,419 shares.

 

8.

EQUITY:

Limited Partner Units

Limited partner interests in the Partnership are represented by Common Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. The Partnership’s Common Units are registered under the Securities Exchange Act of 1934 (as amended) and are listed for trading on the NYSE. Each holder of a Common Unit is entitled to one vote per unit on all matters presented to the Limited Partners for a vote. In addition, if at any time any person or group (other than the Partnership’s General Partner and its affiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under the Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described below under “Parent Company Quarterly Distributions of Available Cash.”

As of December 31, 2020, there were issued and outstanding 2.70 billion Common Units representing an aggregate 99.9% limited partner interest in the Partnership.

Our Partnership Agreement contains specific provisions for the allocation of net earnings and losses to the partners for purposes of maintaining the partner capital accounts. For any fiscal year that the Partnership has net profits, such net profits are first allocated to the General Partner until the aggregate amount of net profits for the current and all prior fiscal years equals the aggregate amount of net losses allocated to the General Partner for the current and all prior fiscal years. Second, such net profits shall be allocated to the Limited

 

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Partners pro rata in accordance with their respective sharing ratios. For any fiscal year in which the Partnership has net losses, such net losses shall be first allocated to the Limited Partners in proportion to their respective adjusted capital account balances, as defined by the Partnership Agreement, (before taking into account such net losses) until their adjusted capital account balances have been reduced to zero. Second, all remaining net losses shall be allocated to the General Partner. The General Partner may distribute to the Limited Partners funds of the Partnership that the General Partner reasonably determines are not needed for the payment of existing or foreseeable Partnership obligations and expenditures.

Common Units

The change in ET Common Units during the years ended December 31, 2020, 2019 and 2018 was as follows:

 

     Years Ended December 31,  
     2020      2019      2018  

Number of Common Units, beginning of period

     2,689.6      2,619.4      1,079.1

Conversion of ET Series A Convertible Preferred Units to common units

     —          —          79.1

Common Units issued in mergers and acquisitions

     —          57.6      1,458.9

Common Units repurchased

     —          (1.9      —    

Issuance of Common Units

     12.8      14.5      2.3
  

 

 

    

 

 

    

 

 

 

Number of Common Units, end of period

     2,702.4      2,689.6      2,619.4
  

 

 

    

 

 

    

 

 

 

In October 2018, ET issued 1.46 billion ET Common Units in connection with the Energy Transfer Merger.

In December 2019, ET issued 57.6 million ET Common Units in connection with the SemGroup acquisition.

ET Series A Convertible Preferred Units

In May 2018, the Partnership converted its 329.3 million Series A Convertible Preferred Units into approximately 79.1 million ET common units in accordance with the terms of ET’s partnership agreement.

ET Class A Units

In connection with the Energy Transfer Merger, the Partnership issued 647,745,099 Class A units (“ET Class A Units”) representing limited partner interests in the Partnership to LE GP, LLC (“LE GP”), the general partner of ET. The number of ET Class A Units issued allows LE GP and its affiliates to retain a voting interest in the Partnership that is identical to their voting interest in the Partnership prior to the completion of the Merger. The ET Class A Units are entitled to vote together with the Partnership’s common units, as a single class, except as required by law. Additionally, ET’s partnership agreement provides that, under certain circumstances, upon the issuance by the Partnership of additional common units or any securities that have voting rights that are pari passu with the Partnership common units, the Partnership will issue to any holder of ET Class A Units additional ET Class A Units such that the holder maintains a voting interest in the Partnership that is identical to its voting interest in the Partnership prior to such issuance. The ET Class A Units are not entitled to distributions and otherwise have no economic attributes.

ET Repurchase Program

In February 2015, the Partnership announced a common unit repurchase program, whereby the Partnership may repurchase up to an additional $2 billion of ET Common Units in the open market at the Partnership’s

 

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discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements. The Partnership repurchased no ET Common Units under this program in 2020 and 1.9 million ET Common Units in 2019. As of December 31, 2020, $911 million remained available to repurchase under the current program.

ET Distribution Reinvestment Program

During the year ended December 31, 2020, distributions of $78 million were reinvested under the distribution reinvestment program. As of December 31, 2020, a total of 21 million common units remain available to be issued under the existing registration statement in connection with the distribution reinvestment program.

Sale of Common Units by Subsidiaries

The Parent Company accounts for the difference between the carrying amount of its investment in subsidiaries and the underlying book value arising from issuance of units by subsidiaries (excluding unit issuances to the Parent Company) as a capital transaction. If a subsidiary issues units at a price less than the Parent Company’s carrying value per unit, the Parent Company assesses whether the investment has been impaired, in which case a provision would be reflected in our statement of operations. The Parent Company did not recognize any impairment related to the issuances of subsidiary common units during the periods presented.

ETO Class K Units

As of December 31, 2020, a total of 101.5 million Class K Units were held by wholly-owned subsidiaries of ETO. Each Class K Unit is entitled to a quarterly cash distribution of $0.67275 per Class K Unit prior to ETO making distributions of available cash to any class of units, excluding any cash available distributions or dividends or capital stock sales proceeds received by ETO from ETP Holdco. If the Partnership is unable to pay the Class K Unit quarterly distribution with respect to any quarter, the accrued and unpaid distributions will accumulate until paid and any accumulated balance will accrue 1.5% per annum until paid.

ETO Class L Units

On December 31, 2018, ETO issued a new class of limited partner interests titled Class L Units to two wholly-owned subsidiaries of the Partnership when the Partnership’s previously outstanding Class E units and Class G units held by such subsidiaries were converted into Class L Units. As a result of the conversion, the Class E units and Class G units were cancelled.

The Class L Units generally do not have any voting rights. The Class L Units are entitled to aggregate cash distributions equal to 7.65% per annum of the total amount of cash generated by us and our subsidiaries, other than ETP Holdco, and available for distribution. Distributions shall be paid quarterly, in arrears, within 45 days after the end of each quarter. As the Class L Units are owned by a wholly-owned subsidiary, the cash distributions on those units are eliminated in our consolidated financial statements.

ETO Class M Units

On July 1, 2019, ETO issued a new class of limited partner interests titled Class M Units to ETP Holdco, a wholly-owned subsidiary of the Partnership, in exchange for the contribution of ETP Holdco’s equity ownership interest in Panhandle to the Partnership.

The Class M Units generally do not have any voting rights. The Class M Units are entitled to aggregate cash distributions equal to 8.00% per annum of the total amount of cash generated by us and our subsidiaries, other than ETP Holdco, and available for distribution. Distributions shall be paid quarterly, in arrears, within 45 days after the end of each quarter. As the Class M Units are owned by a wholly-owned subsidiary, the cash distributions on those units are eliminated in our consolidated financial statements.

 

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ETO Class N Units

In April and May, 2020, ETO issued a new class of limited partner interests titles Class N Units in connection with a series of internal transactions to simplify its capital structure. All of the Class N Units are held by ETP Holdco.

The Class N Units generally do not have any voting rights. each Class N Unit is entitled to a quarterly cash distribution of $0.2375 per Class N Unit prior to ETO making distributions of available cash to any class of units, excluding any cash available distributions or dividends or capital stock sales proceeds received by ETO from ETP Holdco. Distributions shall be paid quarterly, in arrears, within 45 days after the end of each quarter. If the Partnership is unable to pay the Class N Unit quarterly distribution with respect to any quarter, the accrued and unpaid distributions will accumulate until paid and any accumulated balance will accrue 1.5% per annum until paid. As the Class N Units are owned by a wholly-owned subsidiary, the cash distributions on those units are eliminated in our consolidated financial statements.

ETO Preferred Units

As of December 31, 2020 and 2019, ETO’s outstanding preferred units included 950,000 Series A Preferred Units, 550,000 Series B Preferred Units, 18,000,000 Series C Preferred Units, 17,800,000 Series D Preferred Units and 32,000,000 Series E Preferred Units. As of December 31, 2020, ETO’s outstanding preferred units also included 500,000 Series F Preferred Units and 1,100,000 Series G Preferred Units.

ETO Series A Preferred Units

Distributions on the ETO Series A Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2023, at a rate of 6.250% per annum of the stated liquidation preference of $1,000. On and after February 15, 2023, distributions on the ETO Series A Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.028% per annum. The ETO Series A Preferred Units are redeemable at ETO’s option on or after February 15, 2023 at a redemption price of $1,000 per ETO Series A Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

ETO Series B Preferred Units

Distributions on the ETO Series B Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2028, at a rate of 6.625% per annum of the stated liquidation preference of $1,000. On and after February 15, 2028, distributions on the ETO Series B Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.155% per annum. The ETO Series B Preferred Units are redeemable at ETO’s option on or after February 15, 2028 at a redemption price of $1,000 per ETO Series B Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

ETO Series C Preferred Units

Distributions on the ETO Series C Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, May 15, 2023, at a rate of 7.375% per annum of the stated liquidation preference of $25. On and after May 15, 2023, distributions on the ETO Series C Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.530% per annum. The ETO Series C Preferred Units are redeemable at ETO’s option on or after May 15, 2023 at a redemption price of $25 per ETO Series C Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

 

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ETO Series D Preferred Units

Distributions on the ETO Series D Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, August 15, 2023, at a rate of 7.625% per annum of the stated liquidation preference of $25. On and after August 15, 2023, distributions on the ETO Series D Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.738% per annum. The ETO Series D Preferred Units are redeemable at ETO’s option on or after August 15, 2023 at a redemption price of $25 per ETO Series D Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

ETO Series E Preferred Units

Distributions on the ETO Series E Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, May 15, 2024, at a rate of 7.600% per annum of the stated liquidation preference of $25. On and after May 15, 2024, distributions on the ETO Series E Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 5.161% per annum. The ETO Series E Preferred Units are redeemable at ETO’s option on or after May 15, 2024 at a redemption price of $25 per ETO Series E Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

ETO Series F Preferred Units

On January 22, 2020, ETO issued 500,000 of its 6.750% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units representing limited partner interest in ETO, at a price to the public of $1,000 per unit. Distributions on the Series F Preferred Units are cumulative from and including the original issue date and will be payable semi-annually in arrears on the 15th day of May and November of each year, commencing on May 15, 2020 to, but excluding, May 15, 2025, at a rate equal to 6.750% per annum of the $1,000 liquidation preference. On and after May 15, 2025, the distribution rate on the ETO Series F Preferred Units will equal a percentage of the $1,000 liquidation preference equal to the five-year U.S. treasury rate plus a spread of 5.134% per annum. The ETO Series F Preferred Units are redeemable at ETO’s option on or after May 15, 2025 at a redemption price of $1,000 per ETO Series F Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

ETO Series G Preferred Units

On January 22, 2020, ETO issued 1,100,000 of its 7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units representing limited partner interest in ETO, at a price to the public of $1,000 per unit. Distributions on the ETO Series G Preferred Units are cumulative from and including the original issue date and will be payable semi-annually in arrears on the 15th day of May and November of each year, commencing on May 15, 2020 to, but excluding, May 15, 2030, at a rate equal to 7.125% per annum of the $1,000 liquidation preference. On and after May 15, 2030, the distribution rate on the ETO Series G Preferred Units will equal a percentage of the $1,000 liquidation preference equal to the five-year U.S. treasury rate plus a spread of 5.306% per annum. The ETO Series G Preferred Units are redeemable at ETO’s option on or after May 15, 2030 at a redemption price of $1,000 per ETO Series G Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

 

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Subsidiary Equity Transactions

Sunoco LP’s Equity Distribution Program

Sunoco LP is party to an equity distribution agreement for an at-the-market (“ATM”) offering pursuant to which Sunoco LP may sell its common units from time to time. For the years ended December 31, 2020, 2019 and 2018, Sunoco LP issued no units under its ATM program. As of December 31, 2020, $295 million of Sunoco LP common units remained available to be issued under the currently effective equity distribution agreement.

USAC’s Distribution Reinvestment Program

During the year ended December 31, 2020 and 2019, distributions of $1.9 million and $1 million, respectively, were reinvested under the USAC distribution reinvestment program resulting in the issuance of approximately 188,695 and 60,584 USAC common units, respectively.

USAC’s Warrant Private Placement

On April 2, 2018, USAC issued two tranches of warrants to purchase USAC common units (the “USAC Warrants”), which included USAC Warrants to purchase 5,000,000 common units with a strike price of $17.03 per unit and USAC Warrants to purchase 10,000,000 common units with a strike price of $19.59 per unit. The USAC Warrants may be exercised by the holders thereof at any time beginning on the one year anniversary of the closing date and before the tenth anniversary of the closing date. Upon exercise of the USAC Warrants, USAC may, at its option, elect to settle the USAC Warrants in common units on a net basis.

USAC’s Class B Units

The USAC Class B Units, all of which are owned by ETO, are a new class of partnership interests of USAC that have substantially all of the rights and obligations of a USAC common unit, except the USAC Class B Units will not participate in distributions for the first four quarters following the closing date of the USAC Transaction on April 2, 2018. Each USAC Class B Unit automatically converted into one USAC common unit on the first business day following the record date attributable to the quarter ending June 30, 2019.

On July 30, 2019, the 6,397,965 USAC Class B units held by the Partnership converted into 6,397,965 common units representing limited partner interests in USAC. These common units participate in distributions declared by USAC.

Parent Company Quarterly Distributions of Available Cash

Our distribution policy is consistent with the terms of our Partnership Agreement, which requires that we distribute all of our available cash quarterly. The Parent Company’s only cash-generating assets currently consist of distributions from its interest in ETO.

 

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Our distributions declared and paid with respect to our common units were as follows:

 

Quarter Ended

   Record Date    Payment Date    Rate  

December 31, 2017 (1)

   February 8, 2018    February 20, 2018    $ 0.3050

March 31, 2018 (1)

   May 7, 2018    May 21, 2018      0.3050

June 30, 2018

   August 6, 2018    August 20, 2018      0.3050

September 30, 2018

   November 8, 2018    November 19, 2018      0.3050

December 31, 2018

   February 8, 2019    February 19, 2019      0.3050

March 31, 2019

   May 7, 2019    May 20, 2019      0.3050

June 30, 2019

   August 6, 2019    August 19, 2019      0.3050

September 30, 2019

   November 5, 2019    November 19, 2019      0.3050

December 31, 2019

   February 7, 2020    February 19, 2020      0.3050

March 31, 2020

   May 7, 2020    May 19, 2020      0.3050

June 30, 2020

   August 7, 2020    August 19, 2020      0.3050

September 30, 2020

   November 6, 2020    November 19, 2020      0.1525

December 31, 2020

   February 8, 2021    February 19, 2021      0.1525

 

  (1)

Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the distribution for the quarter ended March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received ET Series A Convertible Preferred Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per unit. See additional information below.

Our distributions declared and paid with respect to ET Series A Convertible Preferred Unit were as follows:

 

Quarter Ended

   Record Date    Payment Date    Rate  

December 31, 2016

   February 7, 2017    February 21, 2017    $ 0.1100

March 31, 2017

   May 10, 2017    May 19, 2017      0.1100

June 30, 2017

   August 7, 2017    August 21, 2017      0.1100

September 30, 2017

   November 7, 2017    November 20, 2017      0.1100

December 31, 2017

   February 8, 2018    February 20, 2018      0.1100

March 31, 2018

   May 7, 2018    May 21, 2018      0.1100

 

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ETO Preferred Unit Distributions

Distributions on the ETO’s Series A, Series B, Series C, Series D, Series E, Series F and Series G preferred units declared and/or paid by ETO were as follows:

 

Period Ended

  Record Date   Payment Date   Series A (1)     Series B (1)     Series C     Series D     Series E     Series F (1)     Series G (1)  

June 30, 2018

  August 1, 2018   August 15, 2018   $ 31.2500   $ 33.1250   $ 0.5634   $ —       $ —       $ —       $ —    

September 30, 2018

  November 1, 2018   November 15, 2018     —         —         0.4609     0.5931     —         —         —    

December 31, 2018

  February 1, 2019   February 15, 2019     31.2500     33.1250     0.4609     0.4766     —         —         —    

March 31, 2019

  May 1, 2019   May 15, 2019     —         —         0.4609     0.4766     —         —         —    

June 30, 2019

  August 1, 2019   August 15, 2019     31.2500     33.1250     0.4609     0.4766     0.5806     —         —    

September 30, 2019

  November 1, 2019   November 15, 2019     —         —         0.4609     0.4766     0.4750     —         —    

December 31, 2019

  February 3, 2020   February 18, 2020     31.2500     33.1250     0.4609     0.4766     0.4750     —         —    

March 31, 2020

  May 1, 2020   May 15, 2020     —         —         0.4609     0.4766     0.4750     21.19     22.36

June 30, 2020

  August 3, 2020   August 17, 2020     31.2500     33.1250     0.4609     0.4766     0.4750     —         —    

September 30, 2020

  November 2, 2020   November 15, 2020     —         —         0.4609     0.4766     0.4750     33.75     35.625

December 31, 2020

  February 1, 2021   February 16, 2021     31.2500     33.1250     0.4609     0.4766     0.4750     —         —    

 

  *

Represent prorated initial distributions.

  (1) 

ETO Series A Preferred Unit, ETO Series B Preferred Unit, ETO Series F Preferred Unit and ETO Series G Preferred Unit distributions are paid on a semi-annual basis.

Sunoco LP Cash Distributions

The following table illustrates the percentage allocations of available cash from operating surplus between Sunoco LP’s common unitholders and the holder of its IDRs based on the specified target distribution levels, after the payment of distributions to Class C unitholders. The amounts set forth under “marginal percentage interest in distributions” are the percentage interests of the IDR holder and the common unitholders in any available cash from operating surplus which Sunoco LP distributes up to and including the corresponding amount in the column “total quarterly distribution per unit target amount.” The percentage interests shown for common unitholders and IDR holder for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

 

          Marginal Percentage Interest in
Distributions
 
     Total Quarterly Distribution
Target Amount
   Common
Unitholders
    Holder of
IDRs
 

Minimum Quarterly Distribution

   $0.4375      100     —  

First Target Distribution

   $0.4375 to $0.503125      100     —  

Second Target Distribution

   $0.503125 to $0.546875      85     15

Third Target Distribution

   $0.546875 to $0.656250      75     25

Thereafter

   Above $0.656250      50     50

 

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Distributions on Sunoco LP’s units declared and/or paid by Sunoco LP were as follows:

 

Quarter Ended

   Record Date    Payment Date    Rate  

December 31, 2017

   February 6, 2018    February 14, 2018    $ 0.8255

March 31, 2018

   May 7, 2018    May 15, 2018      0.8255

June 30, 2018

   August 7, 2018    August 15, 2018      0.8255

September 30, 2018

   November 6, 2018    November 14, 2018      0.8255

December 31, 2018

   February 6, 2019    February 14, 2019      0.8255

March 31, 2019

   May 7, 2019    May 15, 2019      0.8255

June 30, 2019

   August 6, 2019    August 14, 2019      0.8255

September 30, 2019

   November 5, 2019    November 19, 2019      0.8255

December 31, 2019

   February 7, 2020    February 19, 2020      0.8255

March 31, 2020

   May 7, 2020    May 19, 2020      0.8255

June 30, 2020

   August 7, 2020    August 19, 2020      0.8255

September 30, 2020

   November 6, 2020    November 19, 2020      0.8255

December 31, 2020

   February 8, 2021    February 19, 2021      0.8255

USAC Cash Distributions

Subsequent to the Energy Transfer Merger and USAC Transactions described in Note 1 and Note 3, respectively, ETO owned approximately 39.7 million USAC common units and 6.4 million USAC Class B units. Subsequent to the conversion of the USAC Class B Units to USAC common units on July 30, 2019, ETO owns approximately 46.1 million USAC common units. As of December 31, 2020, USAC had approximately 97.0 million common units outstanding. USAC currently has a non-economic general partner interest and no outstanding IDRs.

Distributions on USAC’s units declared and/or paid by USAC subsequent to the USAC transaction on April 2, 2018 were as follows:

 

Quarter Ended

   Record Date    Payment Date    Rate  

March 31, 2018

   May 1, 2018    May 11, 2018    $ 0.5250

June 30, 2018

   July 30, 2018    August 10, 2018      0.5250

September 30, 2018

   October 29, 2018    November 9, 2018      0.5250

December 31, 2018

   January 28, 2019    February 8, 2019      0.5250

March 31, 2019

   April 29, 2019    May 10, 2019      0.5250

June 30, 2019

   July 29, 2019    August 9, 2019      0.5250

September 30, 2019

   October 28, 2019    November 8, 2019      0.5250

December 31, 2019

   January 27, 2020    February 7, 2020      0.5250

March 31, 2020

   April 27, 2020    May 8, 2020      0.5250

June 30, 2020

   July 31, 2020    August 10, 2020      0.5250

September 30, 2020

   October 26, 2020    November 6, 2020      0.5250

December 31, 2020

   January 25, 2021    February 5, 2021      0.5250

 

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Accumulated Other Comprehensive Income

The following table presents the components of AOCI, net of tax:

 

     December 31,  
     2020      2019  

Available-for-sale securities

   $ 18    $ 13

Foreign currency translation adjustment

     7      2

Actuarial loss related to pensions and other postretirement benefits

     (7      (25

Investments in unconsolidated affiliates, net

     (14      (1
  

 

 

    

 

 

 

Total AOCI, net of tax

     4      (11

Amounts attributable to noncontrolling interests

     2      —    
  

 

 

    

 

 

 

Total AOCI included in partners’ capital, net of tax

   $ 6    $ (11
  

 

 

    

 

 

 

The table below sets forth the tax amounts included in the respective components of other comprehensive income:

 

     December 31,  
     2020      2019  

Available-for-sale securities

   $ (1    $ (1

Foreign currency translation adjustment

     8      2

Actuarial loss relating to pension and other postretirement benefits

     3      8
  

 

 

    

 

 

 

Total

   $ 10    $ 9
  

 

 

    

 

 

 

 

9.

NON-CASH COMPENSATION PLANS:

We, Sunoco LP and USAC, have issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase Common Units, restricted units, phantom units, distribution equivalent rights (“DERs”), common unit appreciation rights, cash restricted units and other non-cash compensation awards. As of December 31, 2020, an aggregate total of 34.3 million ET Common Units remain available to be awarded under our equity incentive plans.

ET Long-Term Incentive Plan

We have granted restricted unit awards to employees that vest over a specified time period, typically a five-year service vesting requirement, with vesting based on continued employment as of each applicable vesting date. Upon vesting, ET Common Units are issued. These unit awards entitle the recipients of the unit awards to receive, with respect to each Common Unit subject to such award that has not either vested or been forfeited, a cash payment equal to each cash distribution per Common Unit made by us on our Common Units promptly following each such distribution by us to our Unitholders. We refer to these rights as “distribution equivalent rights.” Under our equity incentive plans, our non-employee directors each receive grants with a five-year service vesting requirement.

 

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The following table shows the activity of the awards granted to employees and non-employee directors:

 

     Number of Units      Weighted Average
Grant-Date Fair Value
Per Unit
 

Unvested awards as of December 31, 2019

     28.0    $ 13.89

Awards granted

     9.4      6.29

Awards vested

     (6.9      14.78

Awards forfeited

     (1.1      13.85
  

 

 

    

Unvested awards as of December 31, 2020

     29.4      11.26
  

 

 

    

During the years ended December 31, 2020, 2019, and 2018, the weighted average grant-date fair value per unit award granted was $6.29, $12.51 and $13.00, respectively. The total fair value of awards vested was $51 million, $47 million, and $49 million, respectively, based on the market price of the respective Common Units as of the vesting date. As of December 31, 2020, a total of 29.4 million unit awards remain unvested, for which ET expects to recognize a total of $193 million in compensation expense over a weighted average period of 2.8 years.

Cash Restricted Units. The Partnership has also granted cash restricted units, which vest through three year of service. A cash restricted unit entitles the award recipient to receive cash equal to the market value of one one ET Common Unit upon vesting. In December 2020, the Partnership granted a total of 7.7 million cash restricted units.

Subsidiary Long-Term Incentive Plans

Each of Sunoco LP and USAC has granted restricted or phantom unit awards (collectively, the “Subsidiary Unit Awards”) to employees and directors that entitle the grantees to receive common units of the respective subsidiary. In some cases, at the discretion of the respective subsidiary’s compensation committee, the grantee may instead receive an amount of cash equivalent to the value of common units upon vesting. Substantially all of the Subsidiary Unit Awards are time-vested grants, which generally vest over a three or five-year period, that entitles the grantees of the unit awards to receive an amount of cash equal to the per unit cash distributions made by the respective subsidiaries during the period the restricted unit is outstanding.

The following table summarizes the activity of the Subsidiary Unit Awards:

 

    Sunoco LP     USAC  
    Number of
Units
    Weighted Average
Grant-Date Fair Value
Per Unit
    Number of
Units
    Weighted Average
Grant-Date Fair Value
Per Unit
 

Unvested awards as of December 31, 2019

    2.1   $ 29.21     1.8   $ 15.09

Awards granted

    0.7     28.63     0.7     12.55

Awards vested

    (0.5     30.47     (0.2     17.27

Awards forfeited

    (0.2     29.11     (0.2     15.36
 

 

 

     

 

 

   

Unvested awards as of December 31, 2020

    2.1     28.63     2.1     14.88
 

 

 

     

 

 

   

 

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The following table summarizes the weighted average grant-date fair value per unit award granted:

 

     Years Ended December 31,  
     2020      2019      2018  

Sunoco LP

   $ 28.63    $ 30.70    $ 27.67

USAC

     12.55      15.88      15.47

The total fair value of Subsidiary Unit Awards vested for the years ended December 31, 2020, 2019 and 2018 was $16 million, $17 million, and $22 million, respectively, based on the market price of Sunoco LP and USAC common units as of the vesting date for the years ended December 31, 2020. 2019 and 2018. As of December 31, 2020, estimated compensation cost related to Subsidiary Unit Awards not yet recognized was $39 million, and the weighted average period over which this cost is expected to be recognized in expense is 3.6 years.

 

10.

INCOME TAXES:

As a partnership, we are not subject to United States federal income tax and most state income taxes. However, the Partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax expense (benefit) of our taxable subsidiaries were summarized as follows:

 

     Years Ended December 31,  
     2020      2019      2018  

Current expense (benefit):

        

Federal

   $ (6    $ (20    $ (8

State

     32      (2      19

Foreign

     1      —          —    
  

 

 

    

 

 

    

 

 

 

Total

     27      (22      11

Deferred expense (benefit):

        

Federal

     176      174      181

State

     41      43      (188

Foreign

     (7      —          —    
  

 

 

    

 

 

    

 

 

 

Total

     210      217      (7
  

 

 

    

 

 

    

 

 

 

Total income tax expense from continuing operations

   $ 237    $ 195    $ 4
  

 

 

    

 

 

    

 

 

 

Historically, our effective tax rate has differed from the statutory rate primarily due to partnership earnings that are not subject to United States federal and most state income taxes at the partnership level. A reconciliation of income tax expense at the United States statutory rate to the Partnership’s income tax benefit for the years ended December 31, 2020, 2019 and 2018 is as follows:

 

     Years Ended December 31,  
     2020      2019      2018  

Income tax expense at United States statutory rate

   $ 79    $ 1,054    $ 775

Increase (reduction) in income taxes resulting from:

        

Partnership earnings not subject to tax

     88      (866      (647

Noncontrolling interests

     16      —          —    

State tax, net of federal tax benefit

     58      12      (125

Dividend received deduction

     —          (3      (5

Foreign taxes

     (7      —          —    

Other

     3      (2      6
  

 

 

    

 

 

    

 

 

 

Income tax expense from continuing operations

   $ 237    $ 195    $ 4
  

 

 

    

 

 

    

 

 

 

 

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Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows:

 

     December 31,  
     2020      2019  

Deferred income tax assets:

     

Net operating losses, alternative minimum tax credit and other carryforwards

   $ 1,047    $ 936

Pension and other postretirement benefits

     —          7

Other

     34      85
  

 

 

    

 

 

 

Total deferred income tax assets

     1,081      1,028

Valuation allowance

     (134      (95
  

 

 

    

 

 

 

Net deferred income tax assets

     947      933

Deferred income tax liabilities:

     

Property, plant and equipment

     (298      (501

Investments in affiliates

     (3,994      (3,547

Trademarks

     (77      (72

Other

     (6      (21
  

 

 

    

 

 

 

Total deferred income tax liabilities

     (4,375      (4,141
  

 

 

    

 

 

 

Net deferred income taxes

   $ (3,428    $ (3,208
  

 

 

    

 

 

 

As of December 31, 2020, ETP Holdco had a federal net operating loss carryforward of $3.73 billion, of which $1.3 billion will expire in 2031 through 2037 while the remaining can be carried forward indefinitely. A total of $787 million of the federal net operating loss carryforward is limited under IRC §382. Although we expect to fully utilize the IRC §382 limited federal net operating loss, the amount utilized in a particular year may be limited. As of December 31, 2020, Sunoco Property Company LLC, a corporate subsidiary of Sunoco LP, had a state net operating loss carrryforward of $121 million, which we expect to fully utilize. Sunoco Property Company LLC has no federal net operating loss carryforward.

Our corporate subsidiaries have state net operating loss carryforward benefits of $174 million, net of federal tax, some of which expire between 2021 and 2039, while others are carried forward indefinitely. Our corporate subsidiaries have Canadian net operating losses of $7 million that will begin to expire in 2033. Our corporate subsidiaries have cumulative excess business interest expense of $129 million available for carryforward indefinitely. A valuation allowance of $89 million is attributable to state net operating loss carryforward benefits primarily attributable to significant restrictions on their use in the Commonwealth of Pennsylvania. A separate valuation allowance of $45 million is attributable to foreign tax credits.

The following table sets forth the changes in unrecognized tax benefits:

 

     Years Ended December 31,  
     2020      2019      2018  

Balance at beginning of year

   $ 94    $ 624    $ 609

Additions attributable to tax positions taken in the current year

     —          —          8

Additions attributable to tax positions taken in prior years

     —          11      7

Reduction attributable to tax positions taken in prior years

     —          (541      —    

Lapse of statute

     (4      —          —    
  

 

 

    

 

 

    

 

 

 

Balance at end of year

   $ 90    $ 94    $ 624
  

 

 

    

 

 

    

 

 

 

As of December 31, 2020, we had $90 million ($48 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate.

 

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Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2020, we recognized interest and penalties of less than $7 million. At December 31, 2020, we have interest and penalties accrued of $10 million, net of tax.

We appealed the adverse Court of Federal Claims decision against ETC Sunoco regarding the IRS’ denial of ethanol blending credits claims under Section 6426 to the Federal Circuit. The Federal Circuit affirmed the CFC’s denial on November 1, 2018. ETC Sunoco filed a petition for certiorari with the Supreme Court on May 24, 2019 to review the Federal Circuit’s affirmation of the CFC’s ruling, and the Court denied Sunoco’s petition on October 7, 2019. The petition for certiorari applied to ETC Sunoco’s 2004 through 2009 tax years, and 2010 through 2011 remained on extension with the IRS through September 28, 2020. We filed a petition for the 2010 and 2011 years in the Federal District Court for the Northern District of Texas on September 25, 2020. Due to the uncertainty surrounding the litigation, a reserve of $530 million was previously established for the full amount of the pending refund claims, and the receivable and reserve for this issue were netted in the consolidated balance sheet. Subsequent to the Supreme Court’s denial of the petition in October 2019, the receivable and reserve have been reversed, with no impact to the Partnership’s financial position and results of operations.

In November 2015, the Pennsylvania Commonwealth Court determined in Nextel Communications v. Commonwealth (“Nextel”) that the Pennsylvania limitation on NOL carryforward deductions violated the uniformity clause of the Pennsylvania Constitution and struck the NOL limitation in its entirety. In October 2017, the Pennsylvania Supreme Court affirmed the decision with respect to the uniformity clause violation; however, the Court reversed with respect to the remedy and instead severed the flat-dollar limitation, leaving the percentage-based limitation intact. Nextel subsequently filed a petition for writ of certiorari with the United States Supreme Court, and this was denied on June 11, 2018. Now certain Pennsylvania taxpayers are proceeding with litigation in Pennsylvania state courts on issues not addressed by the Pennsylvania Supreme Court in Nextel, specifically, whether the Due Process and Equal Protection Clauses of the United States Constitution and the Remedies Clause of the Pennsylvania Constitution require a court to grant the taxpayer relief. ETC Sunoco has recognized approximately $67 million ($53 million after federal income tax benefits) in tax benefit based on previously filed tax returns and certain previously filed protective claims as relates to its cases currently held pending the Nextel matter. However, based upon the Pennsylvania Supreme Court’s October 2017 decision, and because of uncertainty in the breadth of the application of the decision, we have reserved $34 million ($27 million after federal income tax benefits) against the receivable.

In general, ET and its subsidiaries are no longer subject to examination by the IRS, and most state jurisdictions, for the 2014 and prior tax years.

ET and its subsidiaries also have various state and local income tax returns in the process of examination or administrative appeal in various jurisdictions. We believe the appropriate accruals or unrecognized tax benefits have been recorded for any potential assessment with respect to these examinations.

 

11.

REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:

FERC Proceedings

By order issued January 16, 2019, the FERC initiated a review of Panhandle’s existing rates pursuant to Section 5 of the Natural Gas Act (“NGA”) to determine whether the rates currently charged by Panhandle are just and reasonable and set the matter for hearing. On August 30, 2019, Panhandle filed a general rate proceeding under Section 4 of the NGA. The Natural Gas Act Section 5 and Section 4 proceedings were consolidated by the order of the Chief Judge dated October 1, 2019. A hearing in the combined proceedings commenced on August 25, 2020 and adjourned on September 15, 2020. By an order dated January 19, 2021, the Chief Judge has extended the deadline for the initial decision to March 2021.

 

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Commitments

In the normal course of business, ETO purchases, processes and sells natural gas pursuant to long-term contracts and enters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. ETO believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on its financial position or results of operations.

Our joint venture agreements require that we fund our proportionate share of capital contributions to its unconsolidated affiliates. Such contributions will depend upon our unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.

We have certain non-cancelable rights-of-way (“ROW”) commitments, which require fixed payments and either expire upon our chosen abandonment or at various dates in the future. The table below reflects ROW expense included in operating expenses in the accompanying statements of operations:

 

     Years Ended December 31,  
     2020      2019      2018  

ROW expense

   $ 47    $ 45    $ 46

PES Refinery Fire and Bankruptcy

We previously owned an approximately 7.4% indirect non-operating interest in PES, which owned a former refinery in Philadelphia. In addition, the Partnership previously provided logistics services to PES under commercial contracts and Sunoco LP previously purchased refined products from PES. In June 2019, an explosion and fire occurred at the refinery complex.

On July 21, 2019, PES Holdings, LLC and seven of its subsidiaries (collectively, the “Debtors”) filed voluntary petitions in the United States Bankruptcy Court for the District of Delaware seeking relief under the provisions of Chapter 11 of the United States Bankruptcy Code, as a result of the explosion and fire at the Philadelphia refinery complex. The Debtors have also defaulted on a $75 million note payable to a subsidiary of the Partnership. In June 2020, the Partnership received $12 million from PES on the note payable and recorded a reserve for the remaining $63 million note balance.

In addition, the Partnership’s subsidiaries retained certain environmental remediation liabilities when the refinery was sold to PES. As of December 31, 2020, the Partnership has funded these environmental remediation liabilities through its wholly-owned captive insurance company, based upon actuarially determined estimates for such costs, and these liabilities are included in the total environmental liabilities discussed below under “Environmental Remediation.” It may be necessary for the Partnership to record additional environmental remediation liabilities in the future depending upon the use of such property by the buyer; however, management is not currently able to estimate such additional liabilities.

PES has rejected certain of the Partnership’s commercial contracts pursuant to Section 365 of the Bankruptcy Code; however, the impact of the bankruptcy on the Partnership’s commercial contracts and related revenue loss (temporary or permanent) is unknown at this time. In addition, Sunoco LP has been successful at acquiring alternative supplies to replace fuel volume lost from PES and does not anticipate any material impact to its business going forward.

Litigation and Contingencies

We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and crude oil are flammable and combustible. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are

 

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reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.

We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.

As of December 31, 2020 and 2019, accruals of approximately $77 million and $120 million, respectively, were reflected on our consolidated balance sheets related to contingent obligations that met both the probable and reasonably estimable criteria. In addition, we may recognize additional contingent losses in the future related to (i) contingent matters for which a loss is currently considered reasonably possible but not probable and/or (ii) losses in excess of amounts that have already been accrued for such contingent matters. In some of these cases, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. For such matters where additional contingent losses can be reasonably estimated, the range of additional losses is estimated to be up to approximately $80 million.

The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts or our estimates of reasonably possible losses prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.

Dakota Access Pipeline

On July 27, 2016, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia (“District Court”) that challenged permits issued by the United States Army Corps of Engineers (“USACE”) that allowed Dakota Access, LLC (“Dakota Access”) to cross the Missouri River at Lake Oahe in North Dakota. The case was subsequently amended to challenge an easement issued by the USACE that allowed the pipeline to cross land owned by the USACE adjacent to the Missouri River. Dakota Access and the Cheyenne River Sioux Tribe (“CRST”) intervened. Separate lawsuits filed by the Oglala Sioux Tribe (“OST”) and the Yankton Sioux Tribe (“YST”) were consolidated with this action and several individual tribal members intervened (collectively, with SRST and CRST, the “Tribes”). On March 25, 2020, the District Court remanded the case back to the USACE for preparation of an Environment Impact Statement (“EIS”). On July 6, 2020, the District Court vacated the easement and ordered Dakota Access to be shut down and emptied of oil by August 5, 2020. Dakota Access and the USACE appealed to the United States Court of Appeals for the District of Columbia (“Court of Appeals”), which granted an administrative stay of the District Court’s July 6 order and ordered further briefing on whether to fully stay the July 6 order. On August 5, 2020, the Court of Appeals 1) granted a stay of the portion of the District Court order that required Dakota Access to shut the pipeline down and empty it of oil, 2) denied a motion to stay the March 25 order pending a decision on the merits by the Court of Appeals as to whether the USACE would be required to prepare an EIS, and 3) denied a motion to stay the District Court’s order to vacate the easement during this appeal process. The August 5 order also stated that the Court of Appeals expected the USACE to clarify its position with respect to whether the USACE intended to allow the continued operation of the pipeline notwithstanding the vacatur of the easement and that the District Court may consider additional relief, if necessary.

On August 10, 2020, the District Court ordered the USACE to submit a status report by August 31, 2020, clarifying its position with regard to its decision-making process with respect to the continued operation of

 

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the pipeline. On August 31, 2020, the USACE submitted a status report that indicated that it considered the presence of the pipeline at the Lake Oahe crossing without an easement to constitute an encroachment on federal land, and that it was still considering whether to exercise its enforcement discretion regarding this encroachment. Following the filing of this status report, the District Court ordered briefing on whether to enjoin the operation of the pipeline. That motion was fully briefed as of January 8, 2021. The District Court has yet to rule on this matter.

On January 26, 2021, the Court of Appeals affirmed the District Court’s March 25, 2020 order requiring an EIS and its July 6, 2020 order vacating the easement. In this same January 26 order, the Court of Appeals also overturned the District Court’s July 6, 2020 order that the pipeline shut down and be emptied of oil.

The District Court scheduled a status conference for February 10, 2021 to discuss the effects of the Court of Appeals’ January 26, 2021 order on the pending motion for injunctive relief, as well as USACE’s expectations as to how it will proceed regarding its enforcement discretion regarding the easement. At the request of the USACE, on February 9, 2021 the District Court granted a two-month continuance for the status conference until April 9, 2021.

The pipeline continues to operate pending rulings from the District Court. ET cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access pipelines; however, ET expects after the law and complete record are fully considered, the issues in this litigation will be resolved in a manner that will allow the pipeline to continue to operate.

In addition, lawsuits and/or regulatory proceedings or actions of this or a similar nature could result in interruptions to construction or operations of current or future projects, delays in completing those projects and/or increased project costs, all of which could have an adverse effect on our business and results of operations.

Mont Belvieu Incident

On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL LLC’s (“Lone Star”) facilities in Mont Belvieu, Texas experienced an over-pressurization resulting in a subsurface release. The subsurface release caused a fire at Lone Star’s South Terminal and damage to Lone Star’s storage well operations at its South and North Terminals. Normal operations have resumed at the facilities with the exception of one of Lone Star’s storage wells; however, Lone Star is still quantifying the extent of its incurred and ongoing damages and has obtained, and will continue to seek, reimbursement for these losses.

MTBE Litigation

ETC Sunoco Holdings LLC and Sunoco (R&M), LLC (collectively, “Sunoco Defendants”) are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability, nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices claims. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees.

As of December 31, 2020, Sunoco Defendants are defendants in five cases, including one case each initiated by the States of Maryland and Rhode Island, one by the Commonwealth of Pennsylvania and two by the Commonwealth of Puerto Rico. The more recent Puerto Rico action is a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. The actions brought by the State of Maryland and Commonwealth of Pennsylvania have also named as defendants ETO, ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals L.P. (“SPMT”).

It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during

 

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the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position.

Regency Merger Litigation

On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action complaint related to the Regency-ETO merger (the “Regency Merger”) in the Court of Chancery of the State of Delaware (the “Regency Merger Litigation”), on behalf of Regency’s common unitholders against Regency GP LP, Regency GP LLC, ET, ETO, ETP GP, and the members of Regency’s board of directors.

The Regency Merger Litigation alleges that the Regency Merger breached the Regency partnership agreement. On March 29, 2016, the Delaware Court of Chancery granted the defendants’ motion to dismiss the lawsuit in its entirety. Plaintiff appealed, and the Delaware Supreme Court reversed the judgment of the Court of Chancery. Plaintiff then filed an Amended Verified Class Action Complaint, which defendants moved to dismiss. The Court of Chancery granted in part and denied in part the motions to dismiss, dismissing the claims against all defendants other than Regency GP LP and Regency GP LLC (the “Regency Defendants”). The Court of Chancery later granted plaintiff’s unopposed motion for class certification. Trial was held on December 10-16, 2019, and a post-trial hearing was held on May 6, 2020. On February 15, 2021, the Court of Chancery ruled in favor of the Regency Defendants on both remaining counts at issue in this litigation.

The Regency Defendants cannot predict whether the plaintiff will appeal this decision.

Litigation Filed By or Against Williams

In April and May 2016, the Williams Companies, Inc. (“Williams”) filed two lawsuits (the “Williams Litigation”) against ET, LE GP, and, in one of the lawsuits, Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC (collectively, “ET Defendants”), alleging that ET Defendants breached their obligations under the ET-Williams merger agreement (the “Merger Agreement”). In general, Williams alleges that ET Defendants breached the Merger Agreement by (a) failing to use commercially reasonable efforts to obtain from Latham & Watkins LLP (“Latham”) the delivery of a tax opinion concerning Section 721 of the Internal Revenue Code (“721 Opinion”), (b) issuing the Partnership’s Series A Convertible Preferred Units (the “Issuance”), and (c) making allegedly untrue representations and warranties in the Merger Agreement.

After a two-day trial on June 20 and 21, 2016, the Court ruled in favor of ET Defendants and issued a declaratory judgment that ET could terminate the merger after June 28, 2016 because of Latham’s inability to provide the required 721 Opinion. The Court did not reach a decision regarding Williams’ claims related to the Issuance nor the alleged untrue representations and warranties. On March 23, 2017, the Delaware Supreme Court affirmed the Court’s ruling on the June 2016 trial.

In September 2016, the parties filed amended pleadings. Williams filed an amended complaint seeking a $410 million termination fee based on the alleged breaches of the Merger Agreement listed above. ET Defendants filed amended counterclaims and affirmative defenses, asserting that Williams materially breached the Merger Agreement by, among other things, (a) failing to use its reasonable best efforts to consummate the merger, (b) failing to provide material information to ET for inclusion in the Form S-4 related to the merger, (c) failing to facilitate the financing of the merger, and (d) breaching the Merger Agreement’s forum-selection clause.

In July 2020, the Court denied ET Defendant’s Motion for Summary Judgment and Williams’ Motion for Partial Summary Judgment. ET Defendants cannot predict the outcome of the Williams Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can ET Defendants predict the amount of time and expense that will be required to resolve these lawsuits. ET Defendants believe that Williams’ claims are without merit and intend to defend vigorously against them.

 

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Rover

On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (“Ohio EPA”) filed suit against Rover and other defendants seeking to recover civil penalties allegedly owed and certain injunctive relief related to permit compliance. The defendants filed several motions to dismiss, which were granted on all counts. The Ohio EPA appealed, and on December 9, 2019, the Fifth District Court of Appeals entered a unanimous judgment affirming the trial court. The Ohio EPA sought review from the Ohio Supreme Court, which the defendants opposed in briefs filed in February 2020. On April 22, 2020, the Ohio Supreme Court granted the Ohio EPA’s request for review. Briefing has concluded and oral argument was held on January 26, 2021.

Revolution

On September 10, 2018, a pipeline release and fire (the “Incident”) occurred on the Revolution Pipeline, a natural gas gathering line located in Center Township, Beaver County, Pennsylvania. There were no injuries. On February 8, 2019, the Pennsylvania Department of Environmental Protection (“PADEP”) issued a Permit Hold on any requests for approvals/permits or permit amendments for any project in Pennsylvania pursuant to the state’s water laws. The Partnership filed an appeal of the Permit Hold with the Pennsylvania Environmental Hearing Board. On January 3, 2020, the Partnership entered into a Consent Order and Agreement with the PADEP in which, among other things, the Permit Hold was lifted, the Partnership agreed to pay a $28.6 million civil penalty and fund a $2 million community environmental project, and all related appeals were withdrawn. On November 11, 2020, the PADEP issued an order that required additional approvals and work prior to placing the Revolution Pipeline back in service. The Partnership filed an appeal of this order on December 8, 2020.

The Pennsylvania Office of Attorney General has commenced an investigation regarding the Incident, and the United States Attorney for the Western District of Pennsylvania has issued a federal grand jury subpoena for documents relevant to the Incident. The scope of these investigations is not further known at this time.

Chester County, Pennsylvania Investigation

In December 2018, the former Chester County District Attorney (the “Chester County DA”) sent a letter to the Partnership stating that his office was investigating the Partnership and related entities for “potential crimes” related to the Mariner East pipelines.

Subsequently, the matter was submitted to an Investigating Grand Jury in Chester County, Pennsylvania, which has issued subpoenas seeking documents and testimony. On September 24, 2019, the Chester County DA sent a Notice of Intent to the Partnership of its intent to pursue an abatement action if certain conditions were not remediated. The Partnership responded to the Notice of Intent within the proscribed time period.

In December 2019, the Chester County DA announced charges against a current employee related to the provision of security services. On June 25, 2020, a preliminary hearing was held on the charges against the employee, and the judge dismissed all charges.

Delaware County, Pennsylvania Investigation

On March 11, 2019, the Delaware County District Attorney’s Office (the “Delaware County DA”) announced that the Delaware County DA and the Pennsylvania Attorney General’s Office, at the request of the Delaware County DA, are conducting an investigation of alleged criminal misconduct involving the construction and related activities of the Mariner East pipelines in Delaware County. On March 16, 2020, the Pennsylvania Attorney General Office served a Statewide Investigating Grand Jury subpoena for documents relating to inadvertent returns and water supplies related to the Mariner East pipelines. While the Partnership will cooperate with the subpoena, it intends to vigorously defend itself.

 

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Shareholder Litigation Regarding Pennsylvania Pipeline Construction

Four purported unitholders of ET filed derivative actions against various past and current members of ET’s Board of Directors, LE GP, and ET, as a nominal defendant that assert claims for breach of fiduciary duties, unjust enrichment, waste of corporate assets, breach of ET’s limited partnership agreement, tortious interference, abuse of control, and gross mismanagement related primarily to matters involving the construction of pipelines in Pennsylvania. They also seek damages and changes to ET’s corporate governance structure. See Bettiol v. LE GP, Case No. 3:19-cv-02890-X (N.D. Tex.); Davidson v. Kelcy L. Warren, Cause No. DC-20-02322 (44th Judicial District of Dallas County, Texas); Harris v. Kelcy L. Warren, Case No. 2:20-cv-00364-GAM (E.D. Pa.); and King v. LE GP, Case No. 3:20-cv-00719-X (N.D. Tex.). Another purported unitholder of ET, Allegheny County Employees’ Retirement System (“ACERS”), individually and on behalf of all others similarly situated, filed a suit under the federal securities laws purportedly on behalf of a class, against ET and three of ET’s directors, Kelcy L. Warren, John W. McReynolds, and Thomas E. Long. See Allegheny County Emps.’ Ret. Sys. v. Energy Transfer LP, Case No. 2:20-00200-GAM (E.D. Pa.). On June 15, 2020, ACERS filed an amended complaint and added as additional defendants ET directors Marshall McCrea and Matthew Ramsey, as well as Michael J. Hennigan and Joseph McGinn. The amended complaint asserts claims for violations of Sections 10(b) and 20(a) of the Exchange Act and Rule 10b-5 promulgated thereunder related primarily to matters involving the construction of pipelines in Pennsylvania. On August 14, 2020, the defendants filed a motion to dismiss ACERS’ amended complaint. The Court has not yet ruled on the motion to dismiss. The defendants cannot predict the outcome of these lawsuits or any lawsuits that might be filed subsequent to the date of this filing; nor can the defendants predict the amount of time and expense that will be required to resolve these lawsuits. However, the defendants believe that the claims are without merit and intend to vigorously contest them.

Cline Class Action Lawsuit

On July 7, 2017, Perry Cline filed a class action complaint in the Eastern District of Oklahoma against Sunoco, Inc. (R&M) and Sunoco Partners Marketing & Terminals L.P. (collectively, “SPMT”) that alleged SPMT failed to make timely payments of oil and gas proceeds from Oklahoma wells and to pay statutory interest for those untimely payments. On October 3, 2019, the Court certified a class to include all persons who received untimely payments from Oklahoma wells on or after July 7, 2012 and who have not already been paid statutory interest on the untimely payments (the “Class”). Excluded from the Class are those entitled to payments of proceeds that qualify as “minimum pay,” prior period adjustments, and pass through payments, as well as governmental agencies and publicly traded oil and gas companies.

After a bench trial, on August 17, 2020, Judge John Gibney (sitting from the Eastern District of Virginia) issued an opinion that awarded the Class actual damages of $74.8 million for late payment interest for identified and unidentified royalty owners and interest-on-interest. This amount was later amended to $80.7 million to account for interest accrued from trial (the “Order”). Judge Gibney also awarded punitive damages in the amount of $75 million. The Class is also seeking attorneys’ fees.

On August 27, 2020, SPMT filed its Notice of Appeal with the 10th Circuit and appealed the entirety of the Order. SPMT cannot predict the outcome of the case, nor can SPMT predict the amount of time and expense that will be required to resolve the appeal, but intends to vigorously appeal the entirety of the Order.

Environmental Matters

Our operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material

 

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adverse effect on our business and operating results. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, natural resource damages, the issuance of injunctions in affected areas and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.

Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.

Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs.

In February 2017, we received letters from the DOJ on behalf of EPA and Louisiana Department of Environmental Quality (“LDEQ”) notifying SPLP and Mid-Valley Pipeline Company (“Mid-Valley”) that enforcement actions were being pursued for three separate crude oil releases: (a) an estimated 550 barrels released from the Colmesneil-to-Chester pipeline in Tyler County, Texas (“Colmesneil”) which allegedly occurred in February 2013; (b) an estimated 4,509 barrels released from the Longview-to-Mayersville pipeline in Caddo Parish, Louisiana (a/k/a Milepost 51.5) which allegedly occurred in October 2014; and (c) an estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma which allegedly occurred in January 2015. In January 2019, a Consent Decree approved by all parties as well as an accompanying Complaint was filed in the United States District Court for the Western District of Louisiana seeking public comment and final court approval to resolve all penalties with the DOJ and LDEQ for the three releases. Subsequently, the court approved the Consent Decree and the penalty payment of $5.4 million was satisfied. The Consent Decree requires certain injunctive relief to be completed on the Longview-to-Mayersville pipeline within three years, but the injunctive relief is not expected to have any material impact on operations. In addition to resolution of the civil penalty and injunctive relief, we continue to discuss natural resource damages with the Louisiana trustees related to the Caddo Parish, Louisiana release.

In October 2018, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) issued a notice of proposed safety order (the “Notice”) to SPMT, a wholly-owned subsidiary of ETO. The Notice alleged that conditions exist on certain pipeline facilities owned and operated by SPMT in Nederland, Texas that pose a pipeline integrity risk to public safety, property or the environment. The Notice also made preliminary findings of fact and proposed corrective measures. SPMT responded to the Notice by submitting a timely written response on November 2, 2018, attended an informal consultation held on January 30, 2019 and entered into a consent agreement with PHMSA resolving the issues in the Notice as of March 2019. The Remedial Work Plan was approved by PHMSA on August 28, 2020.

On June 4, 2019, the Oklahoma Corporation Commission’s (“OCC”) Transportation Division filed a complaint against SPLP seeking a penalty of up to $1 million related to a May 2018 rupture near Edmond, Oklahoma. The release occurred on the Noble to Douglas 8” pipeline in an area of external corrosion and caused the release of approximately fifteen barrels of crude oil. SPLP responded immediately to the release and remediated the surrounding environment and pipeline in cooperation with the OCC. The OCC filed the complaint alleging that SPLP failed to provide adequate cathodic protection to the pipeline causing the failure. SPLP is negotiating a settlement agreement with the OCC for a lesser penalty. The OCC has

 

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accepted our counter offer in conjunction with a proposed consent order. The Consent Order was presented to the OCC at a hearing on August 18, 2020, and is awaiting final signature by the OCC Commissioners.

Environmental Remediation

Our subsidiaries are responsible for environmental remediation at certain sites, including the following:

 

   

certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could be contractually responsible for contamination caused by other parties.

 

   

certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.

 

   

legacy sites related to Sunoco that are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that Sunoco no longer operates, closed and/or sold refineries and other formerly owned sites.

 

   

Sunoco is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of December 31, 2020, Sunoco had been named as a PRP at approximately 35 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco is usually one of a number of companies identified as a PRP at a site. Sunoco has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.

To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets.

The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.

 

     December 31,  
     2020      2019  

Current

   $ 44    $ 46

Non-current

     262      274
  

 

 

    

 

 

 

Total environmental liabilities

   $ 306    $ 320
  

 

 

    

 

 

 

We have established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.

During the years ended December 31, 2020 and 2019, the Partnership recorded $29 million and $39 million, respectively, of expenditures related to environmental cleanup programs.

 

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Our pipeline operations are subject to regulation by the United States Department of Transportation under PHMSA, pursuant to which PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures.

Our operations are also subject to the requirements of OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, the Occupational Safety and Health Administration’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our past costs for OSHA required activities, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances have not had a material adverse effect on our results of operations but there is no assurance that such costs will not be material in the future.

 

12.

REVENUE:

Disaggregation of revenue

The major types of revenue within our reportable segments, are as follows:

 

   

intrastate transportation and storage;

 

   

interstate transportation and storage;

 

   

midstream;

 

   

NGL and refined products transportation and services;

 

   

crude oil transportation and services;

 

   

investment in Sunoco LP;

 

   

fuel distribution and marketing;

 

   

all other;

 

   

investment in USAC;

 

   

contract operations;

 

   

retail parts and services; and

 

   

all other.

Note 17 depicts the disaggregation of revenue by segment, with revenue amounts reflected in accordance with ASC Topic 606.

Intrastate transportation and storage revenue

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transportation pipelines or that is injected or withdrawn into or out of our storage facilities. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity they transport or store. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected/withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject/withdraw into or out of our storage facilities. Payment for services under these contracts are typically due the month after the services have been performed.

The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.

The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.

Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from our marketing operations, and from producers at the wellhead.

Interstate transportation and storage revenue

Our interstate transportation and storage segment’s revenues are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected into or withdrawn out of our storage facilities. Our interstate transportation and storage segment’s contracts can be firm or interruptible. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity transported or stored. In exchange for such fees, we must stand ready to perform a contractually agreed-upon minimum volume of services whenever the customer requests such services. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected or withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject into or withdraw out of our storage facilities. Consequently, we are not required to stand ready to provide any contractually agreed-upon volume of service, but instead provides the services based on existing capacity at the time the customer requests the services. Payment for services under these contracts are typically due the month after the services have been performed.

The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated

 

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with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.

The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.

Lake Charles LNG’s revenues are primarily derived from terminalling services for shippers by receiving LNG at the facility for storage and delivering such LNG to shippers, either in liquid state or gaseous state after regasification. Lake Charles LNG derives all of its revenue from a series of long-term contracts with a wholly-owned subsidiary of Shell. Terminalling revenue is generated from fees paid by Shell for storage and other associated services at the terminal. Payment for services under these contracts are typically due the month after the services have been performed.

The terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volumes transported by Shell or services provided at the terminal.

The performance obligation with respect to firm contracts is a promise to provide a single type of service (terminalling) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.

Midstream revenue

Our midstream segment’s revenues are derived primarily from margins we earn for natural gas volumes that are gathered, processed, and/or transported. The various types of revenue contracts our midstream segment enters into include:

Fixed fee gathering and processing: Contracts under which we provide gathering and processing services in exchange for a fixed cash fee per unit of volume. Revenue for cash fees is recognized when the service is performed.

Keepwhole: Contracts under which we gather raw natural gas from a third-party producer, process the gas to convert it to pipeline quality natural gas, and redeliver to the producer a thermal-equivalent volume of pipeline quality natural gas. In exchange for these services, we retain the NGLs extracted from the raw natural gas received from the producer as well as cash fees paid by the producer. The value of NGLs retained as well as cash fees is recognized as revenue when the services are performed.

Percent of Proceeds (“POP”): Contracts under which we provide gathering and processing services in exchange for a specified percentage of the producer’s commodity (“POP percentage”) and also in some cases additional cash fees. The two types of POP revenue contracts are described below:

 

   

In-Kind POP: We retain our POP percentage (non-cash consideration) and also any additional cash fees in exchange for providing the services. We recognize revenue for the non-cash consideration and cash fees at the time the services are performed.

 

   

Mixed POP: We purchase NGLs from the producer and retain a portion of the residue gas as non-cash consideration for services provided. We may also receive cash fees for such services. Under Topic 606, these agreements were determined to be hybrid agreements which were partially supply agreements

 

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(for the NGLs we purchased) and customer agreements (for the services provided related to the product that was returned to the customer). Given that these are hybrid agreements, we split the cash and non-cash consideration between revenue and a reduction of costs based on the value of the service provided vs. the value of the supply received.

Payment for services under these contracts are typically due the month after the services have been performed.

The performance obligations with respect to our midstream segment’s contracts are to provide gathering, transportation and processing services, each of which would be completed on or about the same time, and each of which would be recognized on the same line item on the income statement, therefore identification of separate performance obligations would not impact the timing or geography of revenue recognition.

Certain contracts of our midstream segment include throughput commitments under which customers commit to purchasing a certain minimum volume of service over a specified time period. If such volume of service is not purchased by the customer, deficiency fees are billed to the customer. In some cases, the customer is allowed to apply any deficiency fees paid to future purchases of services. In such cases, we defer revenue recognition until the customer uses the deficiency fees for services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints.

Our midstream segment also generates revenues from the sale of residue gas and NGLs at the tailgate of our processing facilities primarily to affiliates and some third-party customers.

NGL and refined products transportation and services revenue

Our NGL and refined products segment’s revenues are primarily derived from transportation, fractionation, blending, and storage of NGL and refined products as well as acquisition and marketing activities. Revenues are generated utilizing a complementary network of pipelines, storage and blending facilities, and strategic off-take locations that provide access to multiple NGL markets. Transportation, fractionation, and storage revenue is generated from fees charged to customers under a combination of firm and interruptible contracts. Firm contracts are in the form of take-or-pay arrangements where certain fees will be charged to customers regardless of the volume of service they request for any given period. Under interruptible contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of service provided for any given period. Payment for services under these contracts are typically due the month after the services have been performed.

The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation, fractionation, blending, or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.

The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.

Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of NGLs and other related hydrocarbons at market rates. These contracts were not affected by ASC 606.

 

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Crude oil transportation and services revenue

Our crude oil transportation and services segment revenues are primarily derived from providing transportation, terminalling and acquisition and marketing services to crude oil markets throughout the southwest, midwest and northeastern United States. Crude oil transportation revenue is generated from tariffs paid by shippers utilizing our transportation services and is generally recognized as the related transportation services are provided. Crude oil terminalling revenue is generated from fees paid by customers for storage and other associated services at the terminal. Crude oil acquisition and marketing revenue is generated from sale of crude oil acquired from a variety of suppliers to third parties. Payment for services under these contracts are typically due the month after the services have been performed.

Certain transportation and terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volume of crude oil transported by the customer or services provided at the terminal. For these agreements, any fixed fees billed in excess of services provided are not recognized as revenue until the earlier of (i) the time at which the customer applies the fees against cost of service provided in a later period, or (ii) the customer becomes unable to apply the fees against cost of future service due to capacity constraints or contractual terms.

The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or terminalling) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.

The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and/or product and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.

Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of crude oil at market rates. These contracts were not affected by ASC 606.

Sunoco LP’s fuel distribution and marketing revenue

Sunoco LP’s fuel distribution and marketing operations earn revenue from the following channels: sales to dealers, sales to distributors, unbranded wholesale revenue, commission agent revenue, rental income and other income. Motor fuel revenue consists primarily of the sale of motor fuel under supply agreements with third party customers and affiliates. Fuel supply contracts with Sunoco LP’s customers generally provide that Sunoco LP distribute motor fuel at a formula price based on published rates, volume-based profit margin, and other terms specific to the agreement. The customer is invoiced the agreed-upon price with most payment terms ranging less than 30 days. If the consideration promised in a contract includes a variable amount, Sunoco LP estimates the variable consideration amount and factors in such an estimate to determine the transaction price under the expected value method.

Revenue is recognized under the motor fuel contracts at the point in time the customer takes control of the fuel. At the time control is transferred to the customer the sale is considered final, because the agreements do not grant customers the right to return motor fuel. Under the new standard, to determine when control transfers to the customer, the shipping terms of the contract are assessed as shipping terms are considered a primary indicator of the transfer of control. For FOB shipping point terms, revenue is recognized at the time of shipment. The performance obligation with respect to the sale of goods is satisfied at the time of shipment since the customer gains control at this time under the terms. Shipping and/or handling costs that

 

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occur before the customer obtains control of the goods are deemed to be fulfillment activities and are accounted for as fulfillment costs. Once the goods are shipped, Sunoco LP is precluded from redirecting the shipment to another customer and revenue is recognized.

Commission agent revenue consists of sales from commission agent agreements between Sunoco LP and select operators. Sunoco LP supplies motor fuel to sites operated by commission agents and sells the fuel directly to the end customer. In commission agent arrangements, control of the product is transferred at the point in time when the goods are sold to the end customer. To reflect the transfer of control, Sunoco LP recognizes commission agent revenue at the point in time fuel is sold to the end customer.

Sunoco LP receives rental income from leased or subleased properties. Revenue from leasing arrangements for which Sunoco LP is the lessor are recognized ratably over the term of the underlying lease.

Sunoco LP’s all other revenue

Sunoco LP’s all other operations earn revenue from the following channels: motor fuel sales, rental income and other income. Motor fuel sales consist of fuel sales to consumers at company-operated retail stores. Other income includes merchandise revenue that comprises the in-store merchandise and food service sales at company-operated retail stores, and other revenue that represents a variety of other services within Sunoco LP’s all other operations including credit card processing, car washes, lottery, automated teller machines, money orders, prepaid phone cards and wireless services. Revenue from all other operations is recognized when (or as) the performance obligations are satisfied (i.e. when the customer obtains control of the good or the service is provided).

USAC’s contract operations revenue

USAC’s revenue from contracted compression, station, gas treating and maintenance services is recognized ratably under its fixed-fee contracts over the term of the contract as services are provided to its customers. Initial contract terms typically range from six months to five years, however USAC usually continues to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. USAC primarily enters into fixed-fee contracts whereby its customers are required to pay the monthly fee even during periods of limited or disrupted throughput. Services are generally billed monthly, one month in advance of the commencement of the service month, except for certain customers who are billed at the beginning of the service month, and payment is generally due 30 days after receipt of the invoice. Amounts invoiced in advance are recorded as deferred revenue until earned, at which time they are recognized as revenue. The amount of consideration USAC receives and revenue it recognizes is based upon the fixed fee rate stated in each service contract.

Variable consideration exists in select contracts when billing rates vary based on actual equipment availability or volume of total installed horsepower.

USAC’s contracts with customers may include multiple performance obligations. For such arrangements, USAC allocates revenues to each performance obligation based on its relative standalone service fee. USAC generally determines standalone service fees based on the service fees charged to customers or using expected cost plus margin.

The majority of USAC’s service performance obligations are satisfied over time as services are rendered at selected customer locations on a monthly basis and based upon specific performance criteria identified in the applicable contract. The monthly service for each location is substantially the same service month to month and is promised consecutively over the service contract term. USAC measures progress and performance of the service consistently using a straight-line, time-based method as each month passes, because its performance obligations are satisfied evenly over the contract term as the customer simultaneously receives and consumes the benefits provided by its service. If variable consideration exists, it is allocated to the distinct monthly service within the series to which such variable consideration relates.

 

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USAC has elected to apply the invoicing practical expedient to recognize revenue for such variable consideration, as the invoice corresponds directly to the value transferred to the customer based on its performance completed to date.

There are typically no material obligations for returns or refunds. USAC’s standard contracts do not usually include material non-cash consideration.

USAC’s retail parts and services revenue

USAC’s retail parts and service revenue is earned primarily on freight and crane charges that are directly reimbursable by USAC’s customers and maintenance work on units at its customers’ locations that are outside the scope of its core maintenance activities. Revenue from retail parts and services is recognized at the point in time the part is transferred or service is provided and control is transferred to the customer. At such time, the customer has the ability to direct the use of the benefits of such part or service after USAC has performed its services. USAC bills upon completion of the service or transfer of the parts, and payment is generally due 30 days after receipt of the invoice. The amount of consideration USAC receives and revenue it recognizes is based upon the invoice amount. There are typically no material obligations for returns, refunds, or warranties. USAC’s standard contracts do not usually include material variable or non-cash consideration.

All other revenue

Our all other segment primarily includes our compression equipment business which provides full-service compression design and manufacturing services for the oil and gas industry. It also includes the management of coal and natural resources properties and the related collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties. These operations also include end-user coal handling facilities. There were no material changes to the manner in which revenues within this segment are recorded under the new standard.

Contract Balances with Customers

The Partnership satisfies its obligations by transferring goods or services in exchange for consideration from customers. The timing of performance may differ from the timing the associated consideration is paid to or received from the customer, thus resulting in the recognition of a contract asset or a contract liability.

The Partnership recognizes a contract asset when making upfront consideration payments to certain customers or when providing services to customers prior to the time at which the Partnership is contractually allowed to bill for such services.

The Partnership recognizes a contract liability if the customer’s payment of consideration precedes the Partnership’s fulfillment of the performance obligations. Certain contracts contain provisions requiring customers to pay a fixed minimum fee, but allows customers to apply such fees against services to be provided at a future point in time. These amounts are reflected as deferred revenue until the customer applies the deficiency fees to services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. Additionally, Sunoco LP maintains some franchise agreements requiring dealers to make one-time upfront payments for long-term license agreements. Sunoco LP recognizes a contract liability when the upfront payment is received and recognizes revenue over the term of the license.

 

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The following table summarizes the consolidated activity of our contract liabilities:

 

     Contract
Liabilities
 

Balance, December 31, 2019

   $ 394

Additions

     651

Revenue recognized

     (680
  

 

 

 

Balance, December 31, 2019

     365

Additions

     771

Revenue recognized

     (846
  

 

 

 

Balance, December 31, 2020

   $ 290
  

 

 

 

The balances of Sunoco LP’s contract assets and contract liabilities as of December 31, 2020 and 2019 were as follows:

 

     December 31,
2020
     December 31,
2019
 

Contract Balances

     

Contract asset

   $ 121    $ 117

Accounts receivable from contracts with customers

     256      366

Costs to Obtain or Fulfill a Contract

Sunoco LP recognizes an asset from the costs incurred to obtain a contract (e.g. sales commissions) only if it expects to recover those costs. On the other hand, the costs to fulfill a contract are capitalized if the costs are specifically identifiable to a contract, would result in enhancing resources that will be used in satisfying performance obligations in future and are expected to be recovered. These capitalized costs are recorded as a part of other current assets and other non-current assets and are amortized on a systematic basis consistent with the pattern of transfer of the goods or services to which such costs relate. The amount of amortization expense that Sunoco LP recognized for the years ended December 31, 2020, 2019 and 2018 was $18 million, $17 million and $14 million, respectively. Sunoco LP has also made a policy election of expensing the costs to obtain a contract, as and when they are incurred, in cases where the expected amortization period is one year or less.

Performance Obligations

At contract inception, the Partnership assesses the goods and services promised in its contracts with customers and identifies a performance obligation for each promise to transfer a good or service (or bundle of goods or services) that is distinct. To identify the performance obligations, the Partnership considers all the goods or services promised in the contract, whether explicitly stated or implied based on customary business practices. For a contract that has more than one performance obligation, the Partnership allocates the total contract consideration it expects to be entitled to, to each distinct performance obligation based on a standalone-selling price basis. Revenue is recognized when (or as) the performance obligations are satisfied, that is, when the customer obtains control of the good or service. Certain of our contracts contain variable components, which, when combined with the fixed component are considered a single performance obligation. For these types of contracts, only the fixed component of the contracts are included in the table below.

Sunoco LP distributes fuel under long-term contracts to branded distributors, branded and unbranded third-party dealers, and branded and unbranded retail fuel outlets. Sunoco LP branded supply contracts with distributors generally have both time and volume commitments that establish contract duration. These contracts have an initial term of approximately nine years, with an estimated, volume-weighted term remaining of approximately four years.

 

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As part of the asset purchase agreement with 7-Eleven, Sunoco LP and 7-Eleven and SEI Fuel (collectively, the “Distributor”) have entered into a 15-year take-or-pay fuel supply agreement in which the Distributor is required to purchase a volume of fuel that provides Sunoco LP a minimum amount of gross profit annually. Sunoco LP expects to recognize this revenue in accordance with the contract as Sunoco LP transfers control of the product to the customer. However, in case of annual shortfall Sunoco LP will recognize the amount payable by the Distributor at the sooner of the time at which the Distributor makes up the shortfall or becomes contractually or operationally unable to do so. The transaction price of the contract is variable in nature, fluctuating based on market conditions. The Partnership has elected to take the practical expedient not to estimate the amount of variable consideration allocated to wholly unsatisfied performance obligations.

In some contractual arrangements, Sunoco LP grants dealers a franchise license to operate Sunoco LP’s retail stores over the life of a franchise agreement. In return for the grant of the retail store license, the dealer makes a one-time nonrefundable franchise fee payment to Sunoco LP plus sales based royalties payable to Sunoco LP at a contractual rate during the period of the franchise agreement. Under the requirements of ASC Topic 606, the franchise license is deemed to be a symbolic license for which recognition of revenue over time is the most appropriate measure of progress toward complete satisfaction of the performance obligation. Revenue from this symbolic license is recognized evenly over the life of the franchise agreement.

As of December 31, 2020, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations was $40.35 billion, and the Partnership expects to recognize this amount as revenue within the time bands illustrated below:

 

     Years Ending December 31,                
     2021      2022      2023      Thereafter      Total  

Revenue expected to be recognized on contracts with customers existing as of December 31, 2020

   $ 5,120    $ 5,475    $ 5,051    $ 24,701    $ 40,347

Practical Expedients Utilized by the Partnership

The Partnership elected the following practical expedients in accordance with Topic 606:

 

   

Right to invoice: The Partnership elected to utilize an output method to recognize revenue that is based on the amount to which the Partnership has a right to invoice a customer for services performed to date, if that amount corresponds directly with the value provided to the customer for the related performance or its obligation completed to date. As such, the Partnership recognized revenue in the amount to which it had the right to invoice customers.

 

   

Significant financing component: The Partnership elected not to adjust the promised amount of consideration for the effects of significant financing component if the Partnership expects, at contract inception, that the period between the transfer of a promised good or service to a customer and when the customer pays for that good or service will be one year or less.

 

   

Unearned variable consideration: The Partnership elected to only disclose the unearned fixed consideration associated with unsatisfied performance obligations related to our various customer contracts which contain both fixed and variable components.

 

   

Incremental costs of obtaining a contract: The Partnership generally expenses sales commissions when incurred because the amortization period would have been less than one year. We record these costs within general and administrative expenses. The Partnership elected to expense the incremental costs of obtaining a contract when the amortization period for such contracts would have been one year or less.

 

   

Shipping and handling costs: The Partnership elected to account for shipping and handling activities that occur after the customer has obtained control of a good as fulfillment activities (i.e., an expense) rather than as a promised service.

 

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Measurement of transaction price: The Partnership has elected to exclude from the measurement of transaction price all taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction and collected by the Partnership from a customer (i.e., sales tax, value added tax, etc.).

 

   

Variable consideration of wholly unsatisfied performance obligations: The Partnership has elected to exclude the estimate of variable consideration to the allocation of wholly unsatisfied performance obligations.

 

13.

LEASE ACCOUNTING:

Lessee Accounting

The Partnership leases terminal facilities, tank cars, office space, land and equipment under non-cancelable operating leases whose initial terms are typically five to 15 years, with some real estate leases having terms of 40 years or more, along with options that permit renewals for additional periods. At the inception of each, we determine if the arrangement is a lease or contains an embedded lease and review the facts and circumstances of the arrangement to classify lease assets as operating or finance leases under Topic 842. The Partnership has elected not to record any leases with terms of 12 months or less on the balance sheet.

At present, the majority of the Partnership’s active leases are classified as operating in accordance with Topic 842. Balances related to operating leases are included in operating lease ROU assets, accrued and other current liabilities, operating lease current liabilities and non-current operating lease liabilities in our consolidated balance sheets. Finance leases represent a small portion of the active lease agreements and are included in finance lease ROU assets, current maturities of long-term debt and long-term debt, less current maturities in our consolidated balance sheets. The ROU assets represent the Partnership’s right to use an underlying asset for the lease term and lease liabilities represent the obligation of the Partnership to make minimum lease payments arising from the lease for the duration of the lease term.

Most leases include one or more options to renew, with renewal terms that can extend the lease term from one to 20 years or greater. The exercise of lease renewal options is typically at the sole discretion of the Partnership and lease extensions are evaluated on a lease-by-lease basis. Leases containing early termination clauses typically require the agreement of both parties to the lease. At the inception of a lease, all renewal options reasonably certain to be exercised are considered when determining the lease term. Presently, the Partnership does not have leases that include options to purchase or automatic transfer of ownership of the leased property to the Partnership. The depreciable life of lease assets and leasehold improvements are limited by the expected lease term.

To determine the present value of future minimum lease payments, we use the implicit rate when readily determinable. Presently, because many of our leases do not provide an implicit rate, the Partnership applies its incremental borrowing rate based on the information available at the lease commencement date to determine the present value of minimum lease payments. The operating and finance lease ROU assets include any lease payments made and exclude lease incentives.

Minimum rent payments are expensed on a straight-line basis over the term of the lease. In addition, some leases require additional contingent or variable lease payments, which are based on the factors specific to the individual agreement. Variable lease payments the Partnership is typically responsible for include payment of real estate taxes, maintenance expenses and insurance.

For short-term leases (leases that have term of twelve months or less upon commencement), lease payments are recognized on a straight-line basis and no ROU assets are recorded.

 

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The components of operating and finance lease amounts recognized in the accompanying consolidated balance sheet as of December 31, 2020 and 2019 were as follows:

 

     December 31,  
     2020      2019  

Operating leases:

     

Lease right-of-use assets, net

   $ 863    $ 935

Operating lease current liabilities

     53      60

Accrued and other current liabilities

     1      1

Non-current operating lease liabilities

     837      901

Finance leases:

     

Property, plant and equipment, net

   $ 1      1

Lease right-of-use assets, net

     3      29

Accrued and other current liabilities

     1      1

Current maturities of long-term debt

     1      6

Long-term debt, less current maturities

     6      26

Other non-current liabilities

     1      2

The components of lease expense for the years ended December 31, 2020 and 2019 were as follows:

 

         Year Ended
December 31,
 
   

Income Statement Location

   2020      2019  

Operating lease costs:

       

Operating lease cost

  Cost of goods sold    $ 14    $ 28

Operating lease cost

  Operating expenses      75      73

Operating lease cost

  Selling, general and administrative      17      16
    

 

 

    

 

 

 

Total operating lease costs

       106      117

Finance lease costs:

       

Amortization of lease assets

  Depreciation, depletion and amortization      3      6

Interest on lease liabilities

  Interest expense, net of capitalized interest      1      1
    

 

 

    

 

 

 

Total finance lease costs

       4      7
    

 

 

    

 

 

 

Short-term lease cost

  Operating expenses      31      42

Variable lease cost

  Operating expenses      16      17
    

 

 

    

 

 

 

Lease costs, gross

       157      183
    

 

 

    

 

 

 

Less: Sublease income

  Other revenue      48      47
    

 

 

    

 

 

 

Lease costs, net

     $ 109    $ 136
    

 

 

    

 

 

 

The weighted average remaining lease terms and weighted average discount rates as of December 31, 2020 and 2019 were as follows:

 

     December 31,  
     2020     2019  

Weighted-average remaining lease term (years):

    

Operating leases

     22       24  

Finance leases

     9       5  

Weighted-average discount rate (%):

    

Operating leases

     5     5

Finance leases

     8     5

 

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Cash flows and non-cash activity related to leases for the years ended December 31, 2020 and 2019 were as follows:

 

     Year Ended
December 31,
 
     2020      2019  

Operating cash flows from operating leases

   $ (117    $ (159

Lease assets obtained in exchange for new finance lease liabilities

     —          28

Lease assets obtained in exchange for new operating lease liabilities

     42      40

Maturities of lease liabilities as of December 31, 2020 are as follows:

 

     Operating
leases
     Finance
leases
     Total  

2021

   $ 99    $ 2    $ 101

2022

     85      2      87

2023

     79      2      81

2024

     76      1      77

2025

     75      1      76

Thereafter

     1,140      4      1,144
  

 

 

    

 

 

    

 

 

 

Total lease payments

     1,554      12      1,566

Less: present value discount

     664      3      667
  

 

 

    

 

 

    

 

 

 

Present value of lease liabilities

   $ 890    $ 9    $ 899
  

 

 

    

 

 

    

 

 

 

Lessor Accounting

The Partnership leases or subleases a portion of its real estate portfolio to third-party companies as a stable source of long-term revenue. Our lessor and sublease portfolio consists mainly of operating leases with convenience store operators. At this time, most lessor agreements contain five-year terms with renewal options to extend and early termination options based on established terms specific to the individual agreement.

Rental income included in other revenue in our consolidated statement of operations for the years ended December 31, 2020 and 2019 was $144 million and $149 million, respectively.

Future minimum operating lease payments receivable as of December 31, 2020 are as follows:

 

     Lease
Payments
 

2021

   $ 103

2022

     64

2023

     8

2024

     3

2025

     2

Thereafter

     5
  

 

 

 

Total undiscounted cash flows

   $ 185
  

 

 

 

 

14.

DERIVATIVE ASSETS AND LIABILITIES:

Commodity Price Risk

We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument

 

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contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets.

We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized.

We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales on our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes.

We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes.

We utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes.

We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales. These contracts are not designated as hedges for accounting purposes.

We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.

 

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The following table details our outstanding commodity-related derivatives:

 

     December 31, 2020      December 31, 2019  
     Notional
Volume
     Maturity      Notional
Volume
     Maturity  

Mark-to-Market Derivatives

           

(Trading)

           

Natural Gas (BBtu):

           

Fixed Swaps/Futures

     1,603      2021-2022        1,483      2020  

Basis Swaps IFERC/NYMEX (1)

     (44,225      2021-2022        (35,208      2020-2024  

Power (Megawatt):

           

Forwards

     1,392,400      2021-2029        3,213,450      2020-2029  

Futures

     18,706      2021-2022        (353,527      2020  

Options—Puts

     519,071      2021        51,615      2020  

Options—Calls

     2,343,293      2021        (2,704,330      2020-2021  

(Non-Trading)

           

Natural Gas (BBtu):

           

Basis Swaps IFERC/NYMEX

     (29,173      2021-2022        (18,923      2020-2022  

Swing Swaps IFERC

     11,208      2021        (9,265      2020  

Fixed Swaps/Futures

     (53,575      2021-2022        (3,085      2020-2021  

Forward Physical Contracts

     (11,861      2021        (13,364      2020-2021  

NGL (MBbls)—Forwards/Swaps

     (5,840      2021-2022        (1,300      2020-2021  

Crude (MBbls)—Forwards/Swaps

     —          —          4,465      2020  

Refined Products (MBbls)—Futures

     (2,765      2021        (2,473      2020-2021  

Corn (thousand bushels)

     —          —          (1,210      2020  

Fair Value Hedging Derivatives

           

(Non-Trading)

           

Natural Gas (BBtu):

           

Basis Swaps IFERC/NYMEX

     (30,113      2021        (31,780      2020  

Fixed Swaps/Futures

     (30,113      2021        (31,780      2020  

Hedged Item—Inventory

     30,113      2021        31,780      2020  

 

  (1)

Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.

Interest Rate Risk

We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We also manage our interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances.

 

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The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes:

 

        Notional Amount Outstanding  

Term

  Type (1)   December 31,
2020
     December 31,
2019
 

July 2020 (2)(3)

  Forward-starting to pay a fixed rate
of 3.52% and receive a floating
rate
  $ —      $ 400

July 2021 (2)

  Forward-starting to pay a fixed rate
of 3.55% and receive a floating
rate
    400      400

July 2022 (2)

  Forward-starting to pay a fixed rate
of 3.80% and receive a floating
rate
    400      400

 

  (1)

Floating rates are based on 3-month LIBOR.

  (2)

Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.

  (3)

The July 2020 interest rate swaps were terminated in January 2020.

Credit Risk

Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.

The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrial end-users, oil and gas producers, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.

The Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily with independent system operators and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets.

For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.

 

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Derivative Summary

The following table provides a summary of our derivative assets and liabilities:

 

     Fair Value of Derivative Instruments  
     Asset Derivatives      Liability Derivatives  
     December 31,
2020
     December 31,
2019
     December 31,
2020
     December 31,
2019
 

Derivatives designated as hedging instruments:

           

Commodity derivatives (margin deposits)

   $ 25    $ 24    $ (32    $ —    
  

 

 

    

 

 

    

 

 

    

 

 

 
     25      24      (32      —    

Derivatives not designated as hedging instruments:

           

Commodity derivatives (margin deposits)

     90      319      (166      (350

Commodity derivatives

     53      41      (71      (39

Interest rate derivatives

     —          —          (448      (399
  

 

 

    

 

 

    

 

 

    

 

 

 
     143      360      (685      (788
  

 

 

    

 

 

    

 

 

    

 

 

 

Total derivatives

   $ 168    $ 384    $ (717    $ (788
  

 

 

    

 

 

    

 

 

    

 

 

 

The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:

 

          Asset Derivatives     Liability Derivatives  
    

Balance Sheet Location

   December 31,
2020
    December 31,
2019
    December 31,
2020
    December 31,
2019
 

Derivatives without offsetting agreements

   Derivative liabilities    $ —       $ —       $ (448   $ (399

Derivatives in offsetting agreements:

 

OTC contracts

  

Derivative assets

(liabilities)

     53     41     (71     (39

Broker cleared derivative contracts

  

Other current assets

(liabilities)

     115     343     (198     (350
     

 

 

   

 

 

   

 

 

   

 

 

 
     168     384     (717     (788

Offsetting agreements:

 

Counterparty netting

  

Derivative assets

(liabilities)

     (44     (18     44     18

Counterparty netting

  

Other current assets

(liabilities)

     (64     (318     64     318
     

 

 

   

 

 

   

 

 

   

 

 

 

Total net derivatives

      $ 60   $ 48   $ (609   $ (452
     

 

 

   

 

 

   

 

 

   

 

 

 

 

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We disclose the non-exchange traded financial derivative instruments as derivative assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement

The following tables summarize the amounts recognized with respect to our derivative financial instruments:

 

     Location of Gain (Loss)
Recognized in Income on
Derivatives
     Amount of Gain (Loss) Recognized in Income
Representing Hedge Ineffectiveness and Amount
Excluded from the Assessment of
Effectiveness
 
            Years Ended December 31,  
            2020      2019      2018  

Derivatives in fair value hedging relationships (including hedged item):

           

Commodity derivatives

     Cost of products sold      $ —      $ —      $ (3

 

    

Location of Gain (Loss)
Recognized in Income on Derivatives

   Amount of Gain (Loss)
Recognized in Income on
Derivatives
 
          Years Ended December 31,  
          2020     2019     2018  

Derivatives not designated as hedging instruments:

         

Commodity derivatives—Trading

   Revenues    $ —     $ (3   $ —  

Commodity derivatives—Trading

   Cost of products sold      8     21     32

Commodity derivatives—Non-trading

   Cost of products sold      (34     (100     (102

Interest rate derivatives

   Gains (losses) on interest rate derivatives      (203     (241     47
     

 

 

   

 

 

   

 

 

 

Total

      $ (229   $ (323   $ (23
     

 

 

   

 

 

   

 

 

 

 

15.

RETIREMENT BENEFITS:

Savings and Profit Sharing Plans

We and our subsidiaries sponsor defined contribution savings and profit sharing plans, which collectively cover virtually all eligible employees, including those of ETO, Lake Charles LNG, Sunoco LP and USAC. Employer matching contributions are calculated using a formula based on employee contributions. We and our subsidiaries made matching contributions of $35 million, $66 million and $62 million to these 401(k) savings plans for the years ended December 31, 2020, 2019 and 2018, respectively.

As a result of the economic conditions in 2020, effective June 8, 2020, the Partnership ceased employer matching and profit sharing contributions through December 31, 2020. The Partnership resumed all such contributions in 2021.

Pension and Other Postretirement Benefit Plans

Panhandle

Postretirement benefits expense for the years ended December 31, 2020, 2019, and 2018 reflect the impact of changes Panhandle or its affiliates adopted as of September 30, 2013, to modify its retiree medical benefits program, effective January 1, 2014. The modification placed all eligible retirees on a common medical benefit platform, subject to limits on Panhandle’s annual contribution toward eligible retirees’ medical premiums. Prior to January 1, 2013, affiliates of Panhandle offered postretirement health care and life insurance benefit plans (other postretirement plans) that covered substantially all employees. Effective January 1, 2013, participation in the plan was frozen and medical benefits were no longer offered to

 

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non-union employees. Effective January 1, 2014, retiree medical benefits were no longer offered to union employees.

Effective January 1, 2018, the plan was amended to extend coverage to a closed group of former employees based on certain criteria.

ETC Sunoco

ETC Sunoco has a plan which provides health care benefits for substantially all of its current retirees. The cost to provide the postretirement benefit plan is shared by ETC Sunoco. and its retirees. Access to postretirement medical benefits was phased out or eliminated for all employees retiring after July 1, 2010. ETC Sunoco has established a trust for its postretirement benefit liabilities. The funding of the trust eliminated substantially all of ETC Sunoco’s future exposure to variances between actual results and assumptions used to estimate retiree medical plan obligations.

SemGroup

SemGroup sponsors two defined benefit pension plans and a supplemental defined benefit pension plan (collectively, the “Semgroup Plans”) for certain employees. The Semgroup Plans are closed to new participants and do not accrue any additional benefits.

 

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Obligations and Funded Status

Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services. The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis:

 

     December 31, 2020     December 31, 2019  
     Pension Benefits     Pension Benefits  
     Funded
Plans
    Unfunded
Plans
    Other
Postretirement
Benefits
    Funded
Plans
    Unfunded
Plans
    Other
Postretirement
Benefits
 

Change in benefit obligation:

            

Benefit obligation at beginning of period

   $ 52   $ 34   $ 208   $ 1   $ 37   $ 198

Service cost

     —         —         1     —         —         1

Interest cost

     2     1     5     2     1     7

Benefits paid, net

     (2     (5     (16     (1     (7     (16

Actuarial (gain) loss and other

     5     1     10     4     —         18

Settlements

     (2     —         —         (4     —         —    

SemGroup Acquisition

     —         —         —         50     3     —    
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Benefit obligation at end of period

     55     31     208     52     34     208

Change in plan assets:

            

Fair value of plan assets at beginning of period

     43     —         270     1     —         241

Return on plan assets and other

     5     —         28     6     —         35

Employer contributions

     1     —         9     1     —         10

Benefits paid, net

     (2     —         (16     (1     —         (16

Settlements

     (2     —         —         (4     —         —    

SemGroup Acquisition

     —         —         —         40     —         —    
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Fair value of plan assets at end of period

     45     —         291     43     —         270
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Amount underfunded (overfunded) at end of period

   $ 10   $ 31   $ (83   $ 9   $ 34   $ (62
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Amounts recognized in the consolidated balance sheets consist of:

            

Non-current assets

     $ —       $ 108   $ —       $ —       $ 88

Current liabilities

     —         (4     (2     —         (5     (2

Non-current liabilities

     (10     (27     (23     (9     (29     (24
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
   $ (10   $ (31   $ 83   $ (9   $ (34   $ 62
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Amounts recognized in accumulated other comprehensive income (loss) (pre-tax basis) consist of:

            

Net actuarial gain (loss)

   $ —       $ 2   $ (18   $ —       $ 1   $ (5

Prior service cost

     —         —         21     —         —         40
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
   $ —       $ 2   $ 3   $ —       $ 1   $ 35
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets:

 

     December 31, 2020      December 31, 2019  
     Pension Benefits     

 

     Pension Benefits     

 

 
     Funded
Plans
     Unfunded
Plans
     Other
Postretirement
Benefits
     Funded
Plans
     Unfunded
Plans
     Other
Postretirement
Benefits
 

Projected benefit obligation

   $ 55    $ 31      N/A      $ 51    $ 34      N/A  

Accumulated benefit obligation

     55      31      208      52      34      208

Fair value of plan assets

     45      —          291      43      —          270

Components of Net Periodic Benefit Cost

 

     December 31, 2020      December 31, 2019  
     Pension
Benefits
     Other
Postretirement
Benefits
     Pension
Benefits
     Other
Postretirement
Benefits
 

Net periodic benefit cost:

           

Service cost

   $ —        $ 1    $ —        $ 1

Interest cost

     3      5      3      7

Expected return on plan assets

     (2      (11      (2      (10

Prior service cost amortization

     —          19      —          26
  

 

 

    

 

 

    

 

 

    

 

 

 

Net periodic benefit cost

   $ 1    $ 14    $ 1    $ 24
  

 

 

    

 

 

    

 

 

    

 

 

 

Assumptions

The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below:

 

     December 31, 2020     December 31, 2019  
     Pension
Benefits
    Other
Postretirement
Benefits
    Pension
Benefits
    Other
Postretirement
Benefits
 

Discount rate

     2.40     2.04     4.00     2.71

The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below:

 

     December 31, 2020     December 31, 2019  
     Pension
Benefits
    Other
Postretirement
Benefits
    Pension
Benefits
    Other
Postretirement
Benefits
 

Discount rate

     3.05     2.94     3.33     3.76

Expected return on assets:

        

Tax exempt accounts

     4.57     7.00     3.37     7.00

Taxable accounts

     —         4.75     —         4.75

The long-term expected rate of return on plan assets was estimated based on a variety of factors including the historical investment return achieved over a long-term period, the targeted allocation of plan assets and expectations concerning future returns in the marketplace for both equity and fixed income securities. Current market factors such as inflation and interest rates are evaluated before long-term market assumptions are determined. Peer data and historical returns are reviewed to ensure reasonableness and appropriateness.

 

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The assumed health care cost trend weighted-average rates used to measure the expected cost of benefits covered by the plans are shown in the table below:

 

     December 31,  
     2020     2019  

Health care cost trend rate

     7.30     7.25

Rate to which the cost trend is assumed to decline (the ultimate trend rate)

     4.82     4.83

Year that the rate reaches the ultimate trend rate

     2027       2026  

Changes in the health care cost trend rate assumptions are not expected to have a significant impact on postretirement benefits.

Plan Assets

For the Panhandle plans, the overall investment strategy is to maintain an appropriate balance of actively managed investments with the objective of optimizing longer-term returns while maintaining a high standard of portfolio quality and achieving proper diversification. To achieve diversity within its other postretirement plan asset portfolio, Panhandle has targeted the following asset allocations: equity of 25% to 35%, fixed income of 65% to 75%.

The investment strategy of ETC Sunoco funded defined benefit plans is to achieve consistent positive returns, after adjusting for inflation, and to maximize long-term total return within prudent levels of risk through a combination of income and capital appreciation. The objective of this strategy is to reduce the volatility of investment returns and maintain a sufficient funded status of the plans. In anticipation of the pension plan termination, ETC Sunoco targeted the asset allocations to a more stable position by investing in growth assets and liability hedging assets.

The fair value of the pension plan assets by asset category at the dates indicated is as follows:

 

            Fair Value Measurements at December 31, 2020  
     Fair Value Total      Level 1      Level 2      Level 3  

Asset Category:

           

Cash and cash equivalents

   $ 1    $ 1    $ —        $ —    

Mutual funds (1)

     20      20      —          —    

Fixed income securities

     24      —          24      —    
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 45    $ 21    $ 24    $ —    
  

 

 

    

 

 

    

 

 

    

 

 

 

 

  (1)

Comprised of approximately 100% equities as of December 31, 2020.

 

            Fair Value Measurements at December 31, 2019  
     Fair Value Total      Level 1      Level 2      Level 3  

Asset Category:

           

Cash and cash equivalents

   $ 1    $ 1    $ —        $ —    

Mutual funds (1)

     19      19      —          —    

Fixed income securities

     23      —          23      —    
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 43    $ 20    $ 23    $ —    
  

 

 

    

 

 

    

 

 

    

 

 

 

 

  (1)

Comprised of approximately 100% equities as of December 31, 2019.

 

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The fair value of other postretirement plan assets by asset category at the dates indicated is as follows:

 

            Fair Value Measurements at December 31, 2020  
     Fair Value Total      Level 1      Level 2      Level 3  

Asset category:

           

Cash and cash equivalents

   $ 18    $ 18    $ —        $ —    

Mutual funds (1)

     202      202      —          —    

Fixed income securities

     71      —          71      —    
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 291    $ 220    $ 71    $ —    
  

 

 

    

 

 

    

 

 

    

 

 

 

 

  (1)

Primarily comprised of approximately 59% equities, 40% fixed income securities and 1% cash as of December 31, 2020.

 

            Fair Value Measurements at December 31, 2019  
     Fair Value Total      Level 1      Level 2      Level 3  

Asset category:

           

Cash and cash equivalents

   $ 14    $ 14    $ —        $ —    

Mutual funds (1)

     177      177      —          —    

Fixed income securities

     79      —          79      —    
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 270    $ 191    $ 79    $ —    
  

 

 

    

 

 

    

 

 

    

 

 

 

 

  (1)

Primarily comprised of approximately 59% equities, 40% fixed income securities and 1% cash as of December 31, 2019.

The Level 1 plan assets are valued based on active market quotes. The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines.

Contributions

We expect to contribute $6 million to pension plans and $8 million to other postretirement plans in 2021. The cost of the plans are funded in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes.

Benefit Payments

The Partnership’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below:

 

Years

   Pension Benefits -
Funded Plans
     Pension Benefits -
Unfunded Plans
     Other Postretirement Benefits
(Gross, Before Medicare Part D)
 

2021

   $ 3    $ 5    $ 18

2022

     4      4      18

2023

     4      4      16

2024

     4      3      15

2025

     2      3      14

2026 – 2030

     12      9      58

The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (“Medicare Part D”) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.

Panhandle does not expect to receive any Medicare Part D subsidies in any future periods.

 

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16.

RELATED PARTY TRANSACTIONS:

ET previously paid ETO to provide services on its behalf and on behalf of other subsidiaries of ET, which included the reimbursement of various operating and general and administrative expenses incurred by ETO on behalf of ET and its subsidiaries. These agreements expired in 2016.

The Partnership also has related party transactions with several of its equity method investees. In addition to commercial transactions, these transactions include the provision of certain management services and leases of certain assets.

The following table summarizes the revenues from related companies on our consolidated statements of operations:

 

     Years Ended December 31,  
     2020      2019      2018  

Affiliated revenues

   $ 466    $ 492    $ 431

The following table summarizes the related company accounts receivable and accounts payable balances on our consolidated balance sheets:

 

     December 31,  
     2020      2019  

Accounts receivable from related companies:

     

FGT

   $ 12    $ 50

Phillips 66

     30      36

Traverse Rover LLC

     —          42

Other

     37      31
  

 

 

    

 

 

 

Total accounts receivable from related companies

   $ 79    $ 159
  

 

 

    

 

 

 

As of December 31, 2020 and 2019, accounts payable with related companies in the Partnership’s consolidated balance sheets totaled $27 million and $31 million, respectively.

 

17.

REPORTABLE SEGMENTS:

Our reportable segments currently reflect the following segments, which conduct their business primarily in the United States:

 

   

intrastate transportation and storage;

 

   

interstate transportation and storage;

 

   

midstream;

 

   

NGL and refined products transportation and services;

 

   

crude oil transportation and services;

 

   

investment in Sunoco LP;

 

   

investment in USAC; and

 

   

all other.

Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.

The investment in USAC segment reflects the results of USAC beginning April 2018, the date that the Partnership obtained control of USAC.

 

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Revenues from our intrastate transportation and storage segment are primarily reflected in natural gas sales and gathering, transportation and other fees. Revenues from our interstate transportation and storage segment are primarily reflected in gathering, transportation and other fees. Revenues from our midstream segment are primarily reflected in natural gas sales, NGL sales and gathering, transportation and other fees. Revenues from our NGL and refined products transportation and services segment are primarily reflected in NGL sales and gathering, transportation and other fees. Revenues from our crude oil transportation and services segment are reflected in crude sales and gathering, transportation and other fees. Revenues from our investment in Sunoco LP segment are primarily reflected in refined product sales. Revenues from our investment in USAC segment are primarily reflected in gathering, transportation and other fees. Revenues from our all other segment are primarily reflected in natural gas sales.

We report Segment Adjusted EBITDA as a measure of segment performance. We define Segment Adjusted EBITDA as total Partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Segment Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA and consolidated Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. The use of Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.

 

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The following tables present financial information by segment:

 

     Years Ended December 31,  
     2020      2019      2018  

Revenues:

        

Intrastate transportation and storage:

        

Revenues from external customers

   $ 2,312    $ 2,749    $ 3,428

Intersegment revenues

     232      350      309
  

 

 

    

 

 

    

 

 

 
     2,544      3,099      3,737

Interstate transportation and storage:

        

Revenues from external customers

     1,841      1,941      1,664

Intersegment revenues

     20      22      18
  

 

 

    

 

 

    

 

 

 
     1,861      1,963      1,682

Midstream:

        

Revenues from external customers

     1,944      2,280      2,090

Intersegment revenues

     3,082      3,751      5,432
  

 

 

    

 

 

    

 

 

 
     5,026      6,031      7,522

NGL and refined products transportation and services:

        

Revenues from external customers

     8,501      9,920      10,119

Intersegment revenues

     2,012      1,721      1,004
  

 

 

    

 

 

    

 

 

 
     10,513      11,641      11,123

Crude oil transportation and services:

        

Revenues from external customers

     11,674      18,447      17,236

Intersegment revenues

     5      —          96
  

 

 

    

 

 

    

 

 

 
     11,679      18,447      17,332

Investment in Sunoco LP:

        

Revenues from external customers

     10,653      16,590      16,982

Intersegment revenues

     57      6      12
  

 

 

    

 

 

    

 

 

 
     10,710      16,596      16,994

Investment in USAC:

        

Revenues from external customers

     655      678      495

Intersegment revenues

     12      20      13
  

 

 

    

 

 

    

 

 

 
     667      698      508

All other:

        

Revenues from external customers

     1,374      1,608      2,073

Intersegment revenues

     464      81      155
  

 

 

    

 

 

    

 

 

 
     1,838      1,689      2,228

Eliminations

     (5,884      (5,951      (7,039
  

 

 

    

 

 

    

 

 

 

Total revenues

   $ 38,954    $ 54,213    $ 54,087
  

 

 

    

 

 

    

 

 

 

 

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     Years Ended December 31,  
     2020      2019      2018  

Cost of products sold:

        

Intrastate transportation and storage

   $ 1,478    $ 1,909    $ 2,665

Midstream

     2,598      3,577      5,145

NGL and refined products transportation and services

     7,139      8,393      8,462

Crude oil transportation and services

     8,838      14,832      14,384

Investment in Sunoco LP

     9,654      15,380      15,872

Investment in USAC

     82      91      67

All other

     1,527      1,504      2,006

Eliminations

     (5,829      (5,885      (6,998
  

 

 

    

 

 

    

 

 

 

Total cost of products sold

   $ 25,487    $ 39,801    $ 41,603
  

 

 

    

 

 

    

 

 

 

 

     Years Ended December 31,  
     2020      2019      2018  

Depreciation, depletion and amortization:

        

Intrastate transportation and storage

   $ 185    $ 184    $ 169

Interstate transportation and storage

     411      387      334

Midstream

     1,140      1,066      1,006

NGL and refined products transportation and services

     667      613      466

Crude oil transportation and services

     640      437      445

Investment in Sunoco LP

     189      181      167

Investment in USAC

     239      231      169

All other

     207      48      103
  

 

 

    

 

 

    

 

 

 

Total depreciation, depletion and amortization

   $ 3,678    $ 3,147    $ 2,859
  

 

 

    

 

 

    

 

 

 

 

     Years Ended December 31,  
     2020      2019      2018  

Equity in earnings (losses) of unconsolidated affiliates:

        

Intrastate transportation and storage

   $ 18    $ 18    $ 19

Interstate transportation and storage

     17      222      227

Midstream

     24      20      26

NGL and refined products transportation and services

     60      53      64

Crude oil transportation and services

     (2      (1      6

All other

     2      (10      2
  

 

 

    

 

 

    

 

 

 

Total equity in earnings of unconsolidated affiliates

   $ 119    $ 302    $ 344
  

 

 

    

 

 

    

 

 

 

 

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     Years Ended December 31,  
     2020      2019      2018  

Segment Adjusted EBITDA:

        

Intrastate transportation and storage

   $ 863    $ 999    $ 927

Interstate transportation and storage

     1,680      1,792      1,680

Midstream

     1,670      1,602      1,627

NGL and refined products transportation and services

     2,802      2,666      1,979

Crude oil transportation and services

     2,258      2,898      2,385

Investment in Sunoco LP

     739      665      638

Investment in USAC

     414      420      289

All Other

     105      98      40
  

 

 

    

 

 

    

 

 

 

Total Segment Adjusted EBITDA

     10,531      11,140      9,565

Depreciation, depletion and amortization

     (3,678      (3,147      (2,859

Interest expense, net of interest capitalized

     (2,327      (2,331      (2,055

Impairment losses

     (2,880      (74      (431

Gains (losses) on interest rate derivatives

     (203      (241      47

Non-cash compensation expense

     (121      (113      (105

Unrealized losses on commodity risk management activities

     (71      (5      (11

Inventory valuation adjustments

     (82      79      (85

Losses on extinguishments of debt

     (75      (18      (112

Adjusted EBITDA related to unconsolidated affiliates

     (628      (626      (655

Equity in earnings of unconsolidated affiliates

     119      302      344

Impairment of investments in unconsolidated affiliates

     (129      —          —    

Adjusted EBITDA related to discontinued operations

     —          —          25

Other, net

     (79      54      21
  

 

 

    

 

 

    

 

 

 

Income from continuing operations before income tax (expense) benefit

     377      5,020      3,689

Income tax (expense) benefit from continuing operations

     (237      (195      (4
  

 

 

    

 

 

    

 

 

 

Income from continuing operations

     140      4,825      3,685

Loss from discontinued operations, net of income taxes

     —          —          (265
  

 

 

    

 

 

    

 

 

 

Net income

   $ 140    $ 4,825    $ 3,420
  

 

 

    

 

 

    

 

 

 

 

     December 31,  
     2020      2019      2018  

Segment assets:

        

Intrastate transportation and storage

   $ 7,549    $ 6,648    $ 6,365

Interstate transportation and storage

     17,730      18,111      15,081

Midstream

     18,816      20,332      19,745

NGL and refined products transportation and services

     21,578      19,145      18,267

Crude oil transportation and services

     18,335      22,933      18,189

Investment in Sunoco LP

     5,267      5,438      4,879

Investment in USAC

     2,949      3,730      3,775

All other and eliminations

     2,920      2,636      2,112
  

 

 

    

 

 

    

 

 

 

Total segment assets

   $ 95,144    $ 98,973    $ 88,413
  

 

 

    

 

 

    

 

 

 

 

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     Years Ended December 31,  
     2020      2019      2018  

Additions to property, plant and equipment (1):

        

Intrastate transportation and storage

   $ 49    $ 124    $ 344

Interstate transportation and storage

     150      375      812

Midstream

     487      827      1,161

NGL and refined products transportation and services

     2,403      2,976      2,381

Crude oil transportation and services

     291      403      474

Investment in Sunoco LP

     124      148      103

Investment in USAC

     119      200      205

All other

     136      215      150
  

 

 

    

 

 

    

 

 

 

Total additions to property, plant and equipment (1)

   $ 3,759    $ 5,268    $ 5,630
  

 

 

    

 

 

    

 

 

 

 

  (1)

Excluding acquisitions, net of contributions in aid of construction costs (capital expenditures related to the Partnership’s proportionate ownership on an accrual basis).

 

     December 31,  
     2020      2019      2018  

Investments in affiliates:

        

Intrastate transportation and storage

   $ 89    $ 88    $ 83

Interstate transportation and storage

     2,278      2,524      2,070

Midstream

     110      112      124

NGL and refined products transportation and services

     509      461      243

Crude oil transportation and services

     22      242      28

All other

     52      33      94
  

 

 

    

 

 

    

 

 

 

Total investments in affiliates

   $ 3,060    $ 3,460    $ 2,642
  

 

 

    

 

 

    

 

 

 

 

18.

QUARTERLY FINANCIAL DATA (UNAUDITED):

Summarized unaudited quarterly financial data is presented below. Earnings per unit are computed on a stand-alone basis for each quarter and total year.

 

     Quarters Ended         
     March 31     June 30      September 30 (1)     December 31      Total
Year
 

2020:

            

Revenues

   $ 11,627   $ 7,338    $ 9,955   $ 10,034    $ 38,954

Operating income

     61     1,336      244     1,339      2,980

Net income (loss)

     (964     672      (401     833      140

Limited Partners’ interest in net income (loss)

     (854     353      (655     509      (647

Net income (loss) per limited partner unit:

            

Basic

   $ (0.32   $ 0.13    $ (0.24   $ 0.19    $ (0.24

Diluted

   $ (0.32   $ 0.13    $ (0.24   $ 0.19    $ (0.24

 

  (1)

For the three months ended September 30, 2020, the net loss attributable to partners presented above reflects a change from the amount previously reported in the Partnership’s interim financial statements, due to an adjustment to the allocation of income between the general and limited partners and the noncontrolling interest in a less than wholly-owned subsidiary of the Partnership. Basic and diluted net loss per limited partner unit have also been adjusted accordingly.

 

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     Quarters Ended         
     March 31      June 30      September 30      December 31      Total
Year
 

2019:

              

Revenues

   $ 13,121    $ 13,877    $ 13,495    $ 13,720    $ 54,213

Operating income

     1,927      1,819      1,830      1,627      7,203

Income from continuing operations

     1,180      1,208      1,161      1,276      4,825

Net income

     1,180      1,208      1,161      1,276      4,825

Limited Partners’ interest in net income

     869      877      831      937      3,514

Net income per limited partner unit:

              

Basic

   $ 0.31    $ 0.33    $ 0.33    $ 0.37    $ 1.34

Diluted

   $ 0.31    $ 0.33    $ 0.33    $ 0.37    $ 1.33

 

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Annex D

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K

 

 

 

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2020

or

 

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-31219

 

ENERGY TRANSFER OPERATING, L.P.

(Exact name of registrant as specified in its charter)

 

 

Delaware   73-1493906
(state or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer
Identification No.)

8111 Westchester Drive, Suite 600, Dallas, Texas 75225

(Address of principal executive offices) (zip code)

Registrant’s telephone number, including area code: (214) 981-0700

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class

  

Trading Symbol(s)

  

Name of each exchange on which
registered

7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units    ETPprC    New York Stock Exchange
7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units    ETPprD    New York Stock Exchange
7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units    ETPprE    New York Stock Exchange

Securities registered pursuant to section 12(g) of the Act: None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ☒    No  ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ☐    No  ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.    Yes  ☒    No  ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  ☒    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer      Accelerated filer  
Non-accelerated filer      Smaller reporting company  
     Emerging growth company  

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐

Indicate by check mark whether the registrant has filed a report on an attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.  ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐    No  ☒

DOCUMENTS INCORPORATED BY REFERENCE

None

 

 

 

 

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TABLE OF CONTENTS

 

          PAGE  
   PART I   

ITEM 1.

   BUSINESS      D-1  

ITEM 1A.

   RISK FACTORS      D-50  

ITEM 1B.

   UNRESOLVED STAFF COMMENTS      D-94  

ITEM 2.

   PROPERTIES      D-94  

ITEM 3.

   LEGAL PROCEEDINGS      D-95  

ITEM 4.

   MINE SAFETY DISCLOSURES      D-97  
   PART II   

ITEM 5.

   MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES      D-98  

ITEM 6.

   SELECTED FINANCIAL DATA      D-99  

ITEM 7.

   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS      D-100  

ITEM 7A.

   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK      D-148  

ITEM 8.

   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA      D-151  

ITEM 9.

   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE      D-151  

ITEM 9A.

   CONTROLS AND PROCEDURES      D-151  

ITEM 9B.

   OTHER INFORMATION      D-151  
   PART III   

ITEM 10.

   DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE      D-152  

ITEM 11.

   EXECUTIVE COMPENSATION      D-158  

ITEM 12.

   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS      D-175  

ITEM 13.

   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE      D-175  

ITEM 14.

   PRINCIPAL ACCOUNTANT FEES AND SERVICES      D-176  
   PART IV   

ITEM 15.

   EXHIBITS AND FINANCIAL STATEMENT SCHEDULES      D-177  

ITEM 16.

   FORM 10-K SUMMARY      D-177  
   SIGNATURES      D-187  

 

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Definitions

The following is a list of certain acronyms and terms used throughout this document:

 

/d

   per day

AOCI

   accumulated other comprehensive income (loss)

AROs

   asset retirement obligations

Bbls

   barrels

BBtu

   billion British thermal units

Bcf

   billion cubic feet

Btu

   British thermal unit, an energy measurement used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy used

Capacity

   capacity of a pipeline, processing plant or storage facility refers to the maximum capacity under normal operating conditions and, with respect to pipeline transportation capacity, is subject to multiple factors (including natural gas injections and withdrawals at various delivery points along the pipeline and the utilization of compression) which may reduce the throughput capacity from specified capacity levels

CDM

   CDM Resource Management LLC and CDM Environmental & Technical Services LLC, collectively

Citrus

   Citrus, LLC, a 50/50 joint venture which owns FGT

Dakota Access

   Dakota Access, LLC, a less than wholly-owned subsidiary of ETO

DOE

   United States Department of Energy

DOJ

   United States Department of Justice

DOT

   United States Department of Transportation

Energy Transfer Canada

   Energy Transfer Canada ULC (formerly SemCAMS Midstream ULC), a less than wholly-owned subsidiary of ETO

EPA

   United States Environmental Protection Agency

ET

   Energy Transfer LP, the parent company of ETO

ETC Sunoco

   ETC Sunoco Holdings LLC (formerly Sunoco Inc.), a wholly-owned subsidiary of ETO

ETC Tiger

   ETC Tiger Pipeline, LLC, a wholly-owned subsidiary of ETO, which owns the Tiger Pipeline

ETP GP

   Energy Transfer Partners GP, L.P., the general partner of ETO

ETP Holdco

   ETP Holdco Corporation, a wholly-owned subsidiary of ETO

ETP LLC

   Energy Transfer Partners, L.L.C., the general partner of ETP GP

Exchange Act

   Securities Exchange Act of 1934

ExxonMobil

   Exxon Mobil Corporation

FEP

   Fayetteville Express Pipeline LLC

FERC

   Federal Energy Regulatory Commission

FGT

   Florida Gas Transmission Pipeline and/or Florida Gas Transmission Company, LLC, a wholly-owned subsidiary of Citrus

GAAP

   accounting principles generally accepted in the United States of America

 

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HFOTCO

   Houston Fuel Oil Terminal Company, a wholly-owned subsidiary of ETO, which owns the Houston Terminal

IDRs

   incentive distribution rights

KMI

   Kinder Morgan Inc.

Lake Charles LNG

   Lake Charles LNG Company, LLC, a wholly-owned subsidiary of ETO

LCL

   Lake Charles LNG Export Company, LLC, a wholly-owned subsidiary of ETO

LIBOR

   London Interbank Offered Rate

LNG

   liquefied natural gas

Lone Star

   Lone Star NGL LLC, a wholly-owned subsidiary of ETO

MBbls

   thousand barrels

MEP

   Midcontinent Express Pipeline LLC

Mid-Valley

   Mid-Valley Pipeline Company, a wholly-owned subsidiary of ETO

MMBbls

   million barrels

MMcf

   million cubic feet

MTBE

   methyl tertiary butyl ether

NGL

   natural gas liquid, such as propane, butane and natural gasoline

NYMEX

   New York Mercantile Exchange

NYSE

   New York Stock Exchange

ORS

   Ohio River System LLC, a less than wholly-owned subsidiary of ETO

OSHA

   federal Occupational Safety and Health Act

OTC

   over-the-counter

Panhandle

   Panhandle Eastern Pipe Line Company, LP, a wholly-owned subsidiary of ETO

PCBs

   polychlorinated biphenyls

PEP

   Permian Express Partners LLC, a less than wholly-owned subsidiary of ETO

PES

   Philadelphia Energy Solutions Refining and Marketing LLC

Phillips 66

   Phillips 66 Partners LP

PHMSA

   Pipeline Hazardous Materials Safety Administration

Preferred Unitholders

   Unitholders of the Series A Preferred Units, Series B Preferred Units, Series C Preferred Units, Series D Preferred Units, Series E Preferred Units, Series F Preferred Units and Series G Preferred Units, collectively

Regency

   Regency Energy Partners LP, a wholly-owned subsidiary of ETO

RIGS

   Regency Intrastate Gas System, a wholly-owned subsidiary of ETO

Rover

   Rover Pipeline LLC, a less than wholly-owned subsidiary of ETO

Sea Robin

   Sea Robin Pipeline Company, LLC, a wholly-owned subsidiary of Panhandle

SEC

   Securities and Exchange Commission

SemGroup

   SemGroup, LLC (formerly SemGroup Corporation)

Series A Preferred Units

   6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

Series B Preferred Units

   6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

Series C Preferred Units

   7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

 

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Series D Preferred Units

   7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

Series E Preferred Units

   7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

Series F Preferred Units

   6.750% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units

Series G Preferred Units

   7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units

Shell

   Royal Dutch Shell plc

Southwest Gas

   Pan Gas Storage, LLC (d.b.a. Southwest Gas Storage Company)

SPLP

   Sunoco Pipeline L.P., a wholly-owned subsidiary of ETO

Sunoco Logistics Operations

   Sunoco Logistics Partners Operations L.P, a wholly-owned subsidiary of ETO

Sunoco (R&M)

   Sunoco (R&M), LLC

Transwestern

   Transwestern Pipeline Company, LLC, a wholly-owned subsidiary of ETO

TRRC

   Texas Railroad Commission

Trunkline

   Trunkline Gas Company, LLC, a wholly-owned subsidiary of Panhandle

Unitholders

   Preferred Unitholders and our common unitholder (Energy Transfer LP), collectively

USAC

   USA Compression Partners, LP, a subsidiary of ETO

USACE

   United States Army Corps of Engineers

White Cliffs

   White Cliffs Pipeline, L.L.C.

Adjusted EBITDA is a term used throughout this document, which we define as total Partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA and consolidated Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. The use of Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.

Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer Operating, L.P. (the “Partnership,” or “ETO”) in periodic press releases and some oral statements of the Partnership’s officials during presentations about the Partnership, include forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may,” “will” or similar expressions help identify forward-looking statements. Although the Partnership and its General Partner believe such forward-looking statements are based on

 

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Table of Contents

reasonable assumptions and current expectations and projections about future events, no assurance can be given that such assumptions, expectations, or projections will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, the Partnership’s actual results may vary materially from those anticipated, projected or expected, forecasted, estimated or expressed in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see the risk factor summary below and “Item 1A. Risk Factors” included in this annual report and summarized below.

Risk Factor Summary

Summary of Risks Related to the Partnership’s Business

Results of Operations and Financial Condition. Our results of operations and financial condition could be impacted by many risks that are beyond our control, including the following:

 

   

fluctuations in the demand for and price of natural gas, NGLs, crude oil and refined products;

 

   

the outbreak of COVID-19 and recent geopolitical developments in the crude oil market;

 

   

an impairment of goodwill and intangible assets;

 

   

an interruption of supply of crude oil to our facilities;

 

   

the loss of any key producers or customers;

 

   

failure to retain or replace existing customers or volumes due to declining demand or increased competition;

 

   

unfavorable changes in natural gas price spreads between two or more physical locations;

 

   

production declines over time, which we may not be able to replace with production from newly drilled wells;

 

   

our customers’ ability to use our pipelines and third-party pipelines over which we have no control;

 

   

the inability to access or continue to access lands owned by third parties;

 

   

the overall forward market for crude oil and other products we store;

 

   

a natural disaster, catastrophe, terrorist attack or other similar event;

 

   

union disputes and strikes or work stoppages by unionized employees;

 

   

cybersecurity breaches and other disruptions or failures of our information systems;

 

   

failure to establish or maintain adequate corporate governance;

 

   

product liability claims and litigation;

 

   

actions taken by certain of our joint ventures that we do not control;

 

   

increasing levels of congestion in the Houston Ship Channel;

 

   

the costs of providing pension and other postretirement health care benefits and related funding requirements;

 

   

mergers among customers and competitors;

 

   

fraudulent activity or misuse of proprietary data involving our outsourcing partners; and

 

   

failure of the liquefaction project to secure long-term contractual arrangements or necessary approvals.

 

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Indebtedness. Our business, results of operations, cash flows and financial condition, as well as our ability to make distributions, could be impacted by the following:

 

   

our debt level and debt agreements, or increases in interest rates;

 

   

changes in LIBOR reporting practices or the method in which LIBOR is determined;

 

   

the credit and risk profile of our general partner and its owners;

 

   

a downgrade of our credit ratings; and

 

   

losses resulting from the use of derivative financial instruments.

Capital Projects and Future Growth. Our business, results of operations, cash flows, financial condition, and future growth could be impacted by the following:

 

   

failure to make acquisitions on economically acceptable terms, or to successfully integrate acquired assets;

 

   

failure to secure debt and equity financing for capital projects on acceptable terms;

 

   

failure to construct new pipelines or to do so efficiently;

 

   

failure to execute our growth strategy due to increased competition within any of our core businesses; and

 

   

failure to attract and retain qualified employees.

Regulatory Matters. Our business, results of operations, cash flows, financial condition, and future growth could be impacted by the following:

 

   

increased regulation of hydraulic fracturing or produced water disposal;

 

   

legal or regulatory actions related to the Dakota Access Pipeline;

 

   

competition for water resources or limitations on water usage for hydraulic fracturing;

 

   

laws, regulations and policies governing the rates, terms and conditions of our services;

 

   

failure to recover the full amount of increases in the costs of our pipeline operations;

 

   

imposition of regulation on assets not previously subject to regulation;

 

   

costs and liabilities resulting from performance of pipeline integrity programs and related repairs;

 

   

new or more stringent pipeline safety controls or enforcement of legal requirements;

 

   

costs and liabilities associated with environmental and worker health and safety laws and regulations;

 

   

climate change legislation or regulations restricting emissions of greenhouse gases;

 

   

regulatory provisions of the Dodd-Frank Act and the rules adopted thereunder;

 

   

deepwater drilling laws and regulations, delays in the processing and approval of drilling permits and exploration, development, oil spill-response and decommissioning plans, and related developments; and

 

   

laws and regulations governing the specifications of products that we store and transport.

Risks Relating to Our Partnership Structure

Cash Distributions to Unitholders. Our cash distributions could be impacted by the following:

 

   

cash distributions are not guaranteed and may fluctuate with our performance and other external factors;

 

   

limitations on available cash that are imposed by our distribution policy;

 

   

our general partner’s absolute discretion in determining the level of cash reserves; and

 

   

unitholders’ potential liability to repay distributions.

 

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Our General Partner. Our stakeholders could be impacted by risks related to our general partner, including:

 

   

transfer of control of our general partner to a third party without unitholder consent; and

 

   

substantial cost reimbursements due to our general partner.

Our Subsidiaries. Risks that are unique to our subsidiaries and/or our relationship to our subsidiaries could reduce our subsidiaries’ cash available for distributions to us, including:

 

   

the potential issuance of additional common units by Sunoco LP or USAC;

 

   

a significant decrease in demand for or the price of motor fuel in the areas Sunoco LP serves;

 

   

seasonal industry trends, which may cause Sunoco LP’s operating costs to fluctuate;

 

   

disruptions in Sunoco LP’s operations due to dangers inherent in motor fuel transportation;

 

   

adverse publicity for Sunoco LP resulting from negative events or developments;

 

   

increased costs to retain necessary land use, which could disrupt Sunoco LP’s operations; and

 

   

federal, state and local laws and regulations that govern the industries in which our subsidiaries operate.

Risks Related to Conflicts of Interest. Our stakeholders could be impacted by conflicts of interest, including:

 

   

our general partner may favor its own interests to the detriment of our Unitholders;

 

   

fiduciary duties owed to Sunoco LP, USAC and their respective unitholders by their general partners; and

 

   

potential conflicts of interest faced by directors and officers in managing our business.

Tax Risks. Our stakeholders could be impacted by tax risks, including:

 

   

our tax treatment depends on our status as a partnership for federal income tax purposes, and not being subject to a material amount of entity-level taxation;

 

   

our cash available for distribution to Unitholders may be substantially reduced if we become subject to entity-level taxation as a result of the Internal Revenue Service (“IRS”) treating us as a corporation or legislative, judicial or administrative changes, and may also be reduced by any audit adjustments if imposed directly on the partnership;

 

   

even if Unitholders do not receive any cash distributions from us, Unitholders will be required to pay taxes on their share of our taxable income;

 

   

a Unitholder’s share of our taxable income may be increased as a result of the IRS successfully contesting any of the federal income tax positions we take; and

 

   

tax-exempt entities and non-U.S. Unitholders face unique tax issues from owning our common units that may result in adverse tax consequences to them.

 

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PART I

ITEM 1. BUSINESS

Overview

We (Energy Transfer Operating, L.P., a Delaware limited partnership, “ETO” or the “Partnership”) are a consolidated subsidiary of Energy Transfer LP (“ET”). In October 2018, ET completed the merger of ETO with a wholly-owned subsidiary of ET in a unit-for-unit exchange (the “Energy Transfer Merger”), as discussed further below, at which time the Partnership changed its name from Energy Transfer Partners, L.P. to Energy Transfer Operating, L.P.

We are managed by our general partner, Energy Transfer Partners GP, L.P. (our “General Partner” or “ETP GP”), and ETP GP is managed by its general partner, Energy Transfer Partners, L.L.C. (“ETP LLC”), which is wholly owned by ET. The primary activities in which we are engaged, all of which are in the United States and Canada, are as follows:

 

   

natural gas operations, including the following:

 

   

natural gas midstream and intrastate transportation and storage;

 

   

interstate natural gas transportation and storage; and

 

   

crude oil, NGL and refined products transportation, terminalling services and acquisition and marketing activities, as well as NGL storage and fractionation services.

In addition, we own investments in other businesses, including Sunoco LP and USAC, both of which are publicly traded master limited partnerships.

 

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The following chart summarizes our organizational structure as of February 12, 2021. For simplicity, certain immaterial entities and ownership interests have not been depicted.

 

LOGO

 

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Unless the context requires otherwise, the Partnership and its subsidiaries are collectively referred to in this report as “we,” “us,” “ETO,” “Energy Transfer” or “the Partnership.”

Significant Achievements in 2020 and Beyond

 

   

During the third quarter of 2020, the Partnership completed its Lone Star Express expansion under budget and ahead of schedule.

 

   

During this first quarter of 2020, we completed the integration of the recently acquired SemGroup business and we began to realize financial savings from those actions.

 

   

During the fourth quarter of 2020, the Partnership completed construction of the Orbit Gulf Coast export terminal at Nederland and in January of 2021 loaded the first Very Large Ethane Carrier (“VLEC”) with 911,000 barrels of ethane destined for the northeastern Jiangsu Province, China.

Segment Overview

See Note 16 to our consolidated financial statements in “Item 8. Financial Statements and Supplementary Data” for additional financial information about our segments.

Intrastate Transportation and Storage Segment

Natural gas transportation pipelines receive natural gas from other mainline transportation pipelines, storage facilities and gathering systems and deliver the natural gas to industrial end-users, storage facilities, utilities, power generators and other third-party pipelines. Through our intrastate transportation and storage segment, we own and operate (through wholly-owned subsidiaries or through joint venture interests) approximately 9,400 miles of natural gas transportation pipelines with approximately 22 Bcf/d of transportation capacity and three natural gas storage facilities located in the state of Texas.

Energy Transfer operates one of the largest intrastate pipeline systems in the United States providing energy logistics to major trading hubs and industrial consumption areas throughout the United States. Our intrastate transportation and storage segment focuses on the transportation of natural gas to major markets from various prolific natural gas producing areas (Permian, Barnett, Haynesville and Eagle Ford Shale) through our Oasis pipeline, our ETC Katy pipeline, our natural gas pipeline and storage systems that are referred to as the ET Fuel System, and our HPL System, as further described below.

Our intrastate transportation and storage segment’s results are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, our customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay a fee even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly.

We also generate revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and marketing companies on our HPL System. Generally, we purchase natural gas from either the market (including purchases from our marketing operations) or from producers at the wellhead. To the extent the natural gas comes from producers, it is primarily purchased at a discount to a specified market price and typically resold to customers based on an index price. In addition, our intrastate transportation and storage segment generates revenues from fees charged for storing customers’ working natural gas in our storage facilities and from managing natural gas for our own account.

 

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Interstate Transportation and Storage Segment

Natural gas transportation pipelines receive natural gas from supply sources including other transportation pipelines, storage facilities and gathering systems and deliver the natural gas to industrial end-users and other pipelines. Through our interstate transportation and storage segment, we directly own and operate approximately 12,340 miles of interstate natural gas pipelines with approximately 10.7 Bcf/d of transportation capacity and another approximately 6,780 miles and 10.7 Bcf/d of transportation capacity through joint venture interests.

ETO’s vast interstate natural gas network spans the United States from Florida to California and Texas to Michigan, offering a comprehensive array of pipeline and storage services. Our pipelines have the capability to transport natural gas from nearly all Lower 48 onshore and offshore supply basins to customers in the Southeast, Gulf Coast, Southwest, Midwest, Northeast and Canada. Through numerous interconnections with other pipelines, our interstate systems can access virtually any supply or market in the country. As discussed further herein, our interstate segment operations are regulated by the FERC, which has broad regulatory authority over the business and operations of interstate natural gas pipelines.

Lake Charles LNG, our wholly-owned subsidiary, owns an LNG import terminal and regasification facility located on Louisiana’s Gulf Coast near Lake Charles, Louisiana. The import terminal has approximately 9.0 Bcf of above ground storage capacity and the regasification facility has a send out capacity of 1.8 Bcf/d. Lake Charles LNG derives all of its revenue from a series of long-term contracts with a wholly-owned subsidiary of Shell.

LCL, a wholly-owned subsidiary of ETO, is currently developing a natural gas liquefaction facility for the export of LNG. The project would utilize existing dock and storage facilities owned by Lake Charles LNG located on the Lake Charles site. LCL entered into a prior development agreement with Shell in March 2019; however, Shell withdrew from the project in March 2020 due to adverse market factors affecting Shell’s business following the onset of the COVID-19 pandemic. We intend to continue to develop the project, possibly in conjunction with one or more equity partners, and we plan to evaluate a variety of alternatives to advance the project, including the possibility of reducing the size of the project from three trains (16.45 million tonnes per annum of LNG capacity) to two trains (11.0 million tonnes per annum). The project as currently designed is fully permitted by federal, state and local authorities, has all necessary export licenses and benefits from the infrastructure related to the existing regasification facility at the same site, including four LNG storage tanks, two deep water docks and other assets. In light of the existing brownfield infrastructure and the advanced state of the development of the project, we plan to continue to pursue the project on a disciplined, cost effective basis, and ultimately we will determine whether to make a final investment decision to proceed with the project based on market conditions, capital expenditure considerations and our success in securing equity participation by third parties as well as long-term LNG offtake commitments on satisfactory terms.

The results from our interstate transportation and storage segment are primarily derived from the fees we earn from natural gas transportation and storage services.

Midstream Segment

The midstream industry consists of natural gas gathering, compression, treating, processing, storage, and transportation, and is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells and the proximity of storage facilities to production areas and end-use markets. Gathering systems generally consist of a network of small diameter pipelines and, if necessary, compression systems, that collect natural gas from points near producing wells and transports it to larger pipelines for further transportation.

Treating plants remove carbon dioxide and hydrogen sulfide from natural gas that is higher in carbon dioxide, hydrogen sulfide or certain other contaminants, to ensure that it meets pipeline quality specifications. Natural gas

 

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processing involves the separation of natural gas into pipeline quality natural gas, or residue gas, and a mixed NGL stream. Some natural gas produced by a well does not meet the pipeline quality specifications established by downstream pipelines or is not suitable for commercial use and must be processed to remove the mixed NGL stream. In addition, some natural gas can be processed to take advantage of favorable margins for NGLs extracted from the gas stream.

Through our midstream segment, we own and operate natural gas gathering and NGL pipelines, natural gas processing plants, natural gas treating facilities and natural gas conditioning facilities with an aggregate processing capacity of approximately 8.7 Bcf/d. Our midstream segment focuses on the gathering, compression, treating, blending, and processing, and our operations are currently concentrated in major producing basins and shales in South Texas, West Texas, New Mexico, North Texas, East Texas, West Virginia, Pennsylvania, Ohio, Oklahoma, Kansas and Louisiana. Many of our midstream assets are integrated with our intrastate transportation and storage assets.

Our midstream segment also includes a 60% interest in Edwards Lime Gathering, LLC, which operates natural gas gathering, oil pipeline and oil stabilization facilities in South Texas and a 75% membership interest in ORS, which operates a natural gas gathering system in the Utica shale in Ohio.

Our midstream segment results are derived primarily from margins we earn for natural gas volumes that are gathered, transported, purchased and sold through our pipeline systems and the natural gas and NGL volumes processed at our processing and treating facilities.

NGL and Refined Products Transportation and Services Segment

Our NGL operations transport, store and execute acquisition and marketing activities utilizing a complementary network of pipelines, storage and blending facilities, and strategic off-take locations that provide access to multiple NGL markets.

Our NGL and refined products transportation and services segment includes:

 

   

approximately 4,823 miles of NGL pipelines;

 

   

Nederland Terminal and connecting pipelines which provide transportation of ethane, propane, butane and natural gasoline from our Mont Belvieu Facility to our Nederland Terminal where these products can be exported;

 

   

Marcus Hook Terminal which includes fractionation, storage and exporting assets. This facility is connected to our Mariner East pipeline system, which provides for the transportation of ethane and LPG products from western Pennsylvania, West Virginia and eastern Ohio to our Marcus Hook Terminal where these component products can be exported, processed or locally distributed;

 

   

NGL and propane fractionation facilities with an aggregate capacity of 975 MBbls/d;

 

   

NGL storage facility in Mont Belvieu with a working storage capacity of approximately 50 MMBbls; and

 

   

other NGL storage assets, located at our Cedar Bayou and Hattiesburg storage facilities, and our Nederland, Marcus Hook and Inkster NGL terminals with an aggregate storage capacity of approximately 17 MMBbls.

In the first quarter of 2020, we completed and placed into operation a seventh fractionator at our Mont Belvieu facility. In addition, we placed into service the Lone Star Express pipeline in the third quarter of 2020. The NGL pipelines primarily transport NGLs from the Permian and Delaware basins and the Barnett and Eagle Ford Shales to Mont Belvieu.

NGL terminalling services are facilitated by approximately 10 MMBbls of NGL storage capacity. These operations also support our liquids blending activities, including the use of our patented butane blending

 

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technology. Refined products operations provide transportation and terminalling services through the use of approximately 2,918 miles of refined products pipelines and 37 active refined products marketing terminals. Our marketing terminals are located primarily in the northeast, midwest and southwest United States, with approximately 8 MMBbls of refined products storage capacity. Our refined products operations utilize our integrated pipeline and terminalling assets, as well as acquisition and marketing activities, to service refined products markets in several regions throughout the United States. The mix of products delivered through our refined products pipelines varies seasonally, with gasoline demand peaking during the summer months, and demand for heating oil and other distillate fuels peaking in the winter. The products transported in these pipelines include multiple grades of gasoline and middle distillates, such as heating oil, diesel and jet fuel. Rates for shipments on these product pipelines are regulated by the FERC and other state regulatory agencies, as applicable.

Revenues in this segment are principally generated from fees charged to customers under dedicated contracts or take-or-pay contracts. Under a dedicated contract, the customer agrees to deliver the total output from particular processing plants that are connected to the NGL pipeline. Take-or-pay contracts have minimum throughput commitments requiring the customer to pay regardless of whether a fixed volume is transported. Fees are market-based, negotiated with customers and competitive with regional regulated pipelines and fractionators. Storage revenues are derived from base storage and throughput fees. This segment also derives revenues from the marketing of NGLs and processing and fractionating refinery off-gas.

Crude Oil Transportation and Services Segment

Our crude oil operations provide transportation (via pipeline and trucking), terminalling and acquisition and marketing services to crude oil markets throughout the southwest, midwest, northwestern and northeastern United States. Through our crude oil transportation and services segment, we own and operate (through wholly-owned subsidiaries or joint venture interests) approximately 10,850 miles of crude oil trunk and gathering pipelines in the southwest and midwest United States. This segment includes equity ownership interests in four crude oil pipelines, the Bakken Pipeline system, Bayou Bridge Pipeline, White Cliffs Pipeline and Maurepas Pipeline. Our crude oil terminalling services operate with an aggregate storage capacity of approximately 71 MMBbls, including approximately 29 MMBbls at our Gulf Coast terminal in Nederland, Texas, approximately 18.2 MMBbls at our Gulf coast terminal on the Houston Ship Channel and approximately 7.7 MMBbls at our Cushing facility in Cushing, Oklahoma. Our crude oil acquisition and marketing activities utilize our pipeline and terminal assets, our proprietary fleet crude oil tractor trailers and truck unloading facilities, as well as third-party assets, to service crude oil markets principally in the midcontinent United States.

Revenues throughout our crude oil pipeline systems are generated from tariffs paid by shippers utilizing our transportation services. These tariffs are filed with the FERC and other state regulatory agencies, as applicable.

Our crude oil acquisition and marketing activities include the gathering, purchasing, marketing and selling of crude oil. Specifically, the crude oil acquisition and marketing activities include:

 

   

purchasing crude oil at both the wellhead from producers, and in bulk from aggregators at major pipeline interconnections and trading locations;

 

   

storing inventory during contango market conditions (when the price of crude oil for future delivery is higher than current prices);

 

   

buying and selling crude oil of different grades at different locations in order to maximize value;

 

   

transporting crude oil using the pipelines, terminals and trucks or, when necessary or cost effective, pipelines, terminals or trucks owned and operated by third parties; and

 

   

marketing crude oil to major integrated oil companies, independent refiners and resellers through various types of sale and exchange transactions.

 

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Investment in Sunoco LP

Sunoco LP is engaged in the distribution of motor fuels to independent dealers, distributors, and other commercial customers and the distribution of motor fuels to end-user customers at retail sites operated by commission agents. Additionally, it receives rental income through the leasing or subleasing of real estate used in the retail distribution of motor fuel. Sunoco LP also operates 78 retail stores located in Hawaii and New Jersey.

Sunoco LP is a distributor of motor fuels and other petroleum products which Sunoco LP supplies to third-party dealers and distributors, to independent operators of commission agent locations and other commercial consumers of motor fuel. Also included in the wholesale operations are transmix processing plants and refined products terminals. Transmix is the mixture of various refined products (primarily gasoline and diesel) created in the supply chain (primarily in pipelines and terminals) when various products interface with each other. Transmix processing plants separate this mixture and return it to salable products of gasoline and diesel.

Sunoco LP is the exclusive wholesale supplier of the Sunoco-branded motor fuel, supplying an extensive distribution network of approximately 5,556 Sunoco-branded company and third-party operated locations throughout the East Coast, Midwest, South Central and Southeast regions of the United States. Sunoco LP believes it is one of the largest independent motor fuel distributors of Chevron, ExxonMobil and Valero branded motor fuel in the United States. In addition to distributing motor fuels, Sunoco LP also distributes other petroleum products such as propane and lubricating oil, and Sunoco LP receives rental income from real estate that it leases or subleases.

Sunoco LP operations primarily consist of fuel distribution and marketing.

Investment in USAC

USAC provides natural gas compression services throughout the United States, including the Utica, Marcellus, Permian Basin, Delaware Basin, Eagle Ford, Mississippi Lime, Granite Wash, Woodford, Barnett, Haynesville, Niobrara and Fayetteville shales. USAC provides compression services to its customers primarily in connection with infrastructure applications, including both allowing for the processing and transportation of natural gas through the domestic pipeline system and enhancing crude oil production through artificial lift processes. As such, USAC’s compression services play a critical role in the production, processing and transportation of both natural gas and crude oil. As of December 31, 2020, USAC had 3,726,181 horsepower in its fleet.

USAC operates a modern fleet of compression units, with an average age of approximately seven years. USAC’s standard new-build compression units are generally configured for multiple compression stages allowing USAC to operate its units across a broad range of operating conditions. As part of USAC’s services, it engineers, designs, operates, services and repairs its compression units and maintains related support inventory and equipment.

USAC provides compression services to its customers under fixed-fee contracts with initial contract terms typically between six months and five years, depending on the application and location of the compression unit. USAC typically continues to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. USAC primarily enters into fixed-fee contracts whereby its customers are required to pay a monthly fee even during periods of limited or disrupted throughput, which enhances the stability and predictability of its cash flows. USAC is not directly exposed to commodity price risk because it does not take title to the natural gas or crude oil involved in its services and because the natural gas used as fuel by its compression units is supplied by its customers without cost to USAC.

USAC’s assets and operations are all located and conducted in the United States.

 

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All Other Segment

Our “All Other” segment includes the following:

 

   

Our marketing operations in which we market the natural gas that flows through our gathering and intrastate transportation assets, referred to as on-system gas. We also attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other suppliers and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices of natural gas, less the costs of transportation. For the off-system gas, we purchase gas or act as an agent for small independent producers that may not have marketing operations.

 

   

Our natural gas compression equipment business which has operations in Arkansas, California, Colorado, Louisiana, New Mexico, Oklahoma, Pennsylvania and Texas.

 

   

Our wholly-owned subsidiary, Dual Drive Technologies, Ltd. (“DDT”), which provides compression services to customers engaged in the transportation of natural gas, including our other segments.

 

   

Our subsidiaries are involved in the management of coal and natural resources properties and the related collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties. These operations also include end-user coal handling facilities.

 

   

PEI Power LLC and PEI Power II LLC, which own and operate a facility in Pennsylvania that generates a total of 75 megawatts of electrical power.

 

   

Our 51% ownership interest in Energy Transfer Canada, which owns and operates natural gas processing and gathering facilities in Alberta, Canada.

Asset Overview

The descriptions below include summaries of significant assets within the Partnership’s reportable segments. Amounts, such as capacities, volumes and miles included in the descriptions below are approximate and are based on information currently available; such amounts are subject to change based on future events or additional information.

Intrastate Transportation and Storage

The following details our pipelines and storage facilities in the intrastate transportation and storage segment:

 

Description of Assets

   Ownership
Interest
    Miles of
Natural Gas
Pipeline
     Pipeline
Throughput
Capacity
(Bcf/d)
     Working
Storage
Capacity
(Bcf/d)
 

ET Fuel System

     100     3,150      5.2      11.2

Oasis Pipeline (1)

     100     750      2.0      —    

HPL System

     100     3,920      5.3      52.5

ETC Katy Pipeline

     100     460      2.9      —    

Regency Intrastate Gas

     100     450      2.1      —    

Comanche Trail Pipeline

     16     195      1.1      —    

Trans-Pecos Pipeline

     16     143      1.4      —    

Old Ocean Pipeline, LLC

     50     240      0.2      —    

Red Bluff Express Pipeline

     70     108      1.4      —    

 

(1)

Includes bi-directional capabilities

 

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The following information describes our principal intrastate transportation and storage assets:

 

   

The ET Fuel System serves some of the most prolific production areas in the United States and is comprised of intrastate natural gas pipeline and related natural gas storage facilities. The ET Fuel System has many interconnections with pipelines providing direct access to power plants, other intrastate and interstate pipelines, and has bi-directional capabilities. It is strategically located near high-growth production areas and provides access to the three major natural gas trading centers in Texas, the Waha Hub near Pecos, Texas, the Maypearl Hub in Central Texas and the Carthage Hub in East Texas.

The ET Fuel System also includes our Bethel natural gas storage facility, with a working capacity of 6.0 Bcf, an average withdrawal capacity of 300 MMcf/d and an injection capacity of 75 MMcf/d, and our Bryson natural gas storage facility, with a working capacity of 5.2 Bcf, an average withdrawal capacity of 120 MMcf/d and an average injection capacity of 96 MMcf/d. Storage capacity on the ET Fuel System is contracted to third parties under fee-based arrangements that extend through 2023.

In addition, the ET Fuel System is integrated with our Godley processing plant which gives us the ability to bypass the plant when processing margins are unfavorable by blending the untreated natural gas from the North Texas System with natural gas on the ET Fuel System while continuing to meet pipeline quality specifications.

 

   

The Oasis Pipeline is primarily a 36-inch natural gas pipeline. It has bi-directional capabilities with approximately 1.3 Bcf/d of throughput capacity moving west-to-east and greater than 750 MMcf/d of throughput capacity moving east-to-west. The Oasis pipeline connects to the Waha and Katy market hubs and has many interconnections with other pipelines, power plants, processing facilities, municipalities and producers.

The Oasis pipeline is integrated with our gathering system known as the Southeast Texas System and is an important component to maximizing our Southeast Texas System’s profitability. The Oasis pipeline enhances the Southeast Texas System by (i) providing access for natural gas gathered on the Southeast Texas System to other third-party supply and market points and interconnecting pipelines and (ii) allowing us to bypass our processing plants and treating facilities on the Southeast Texas System when processing margins are unfavorable by blending untreated natural gas from the Southeast Texas System with gas on the Oasis pipeline while continuing to meet pipeline quality specifications.

 

   

The HPL System is an extensive network of intrastate natural gas pipelines, an underground Bammel storage reservoir and related transportation assets. The system has access to multiple sources of historically significant natural gas supply reserves from South Texas, the Gulf Coast of Texas, East Texas and the western Gulf of Mexico, and is directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus Christi, Texas City, Beaumont and other cities located along the Gulf Coast of Texas. The HPL System is well situated to gather and transport gas in many of the major gas producing areas in Texas including a strong presence in the key Houston Ship Channel and Katy Hub markets, allowing us to play an important role in the Texas natural gas markets. The HPL System also offers its shippers off-system opportunities due to its numerous interconnections with other pipeline systems, its direct access to multiple market hubs at Katy, the Houston Ship Channel, Carthage and Agua Dulce, as well as our Bammel storage facility.

The Bammel storage facility has a total working gas capacity of approximately 52.5 Bcf, a peak withdrawal rate of 1.3 Bcf/d and a peak injection rate of 0.6 Bcf/d. The Bammel storage facility is located near the Houston Ship Channel market area and the Katy Hub, and is ideally suited to provide a physical backup for on-system and off-system customers. As of December 31, 2020, we had approximately 19.0 Bcf committed under fee-based arrangements with third parties and approximately 28.7 Bcf stored in the facility for our own account.

 

   

The ETC Katy Pipeline connects three treating facilities, one of which we own, with our gathering system known as Southeast Texas System. The ETC Katy pipeline serves producers in East and North Central Texas and provided access to the Katy Hub. The ETC Katy pipeline expansions include the 36-inch East

 

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Texas extension to connect our Reed compressor station in Freestone County to our Grimes County compressor station, the 36-inch Katy expansion connecting Grimes to the Katy Hub, and the 42-inch Southeast Bossier pipeline connecting our Cleburne to Carthage pipeline to the HPL System.

 

   

RIGS is a 450-mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets.

 

   

Comanche Trail Pipeline is a 195-mile intrastate pipeline that delivers natural gas from the Waha Hub near Pecos, Texas to the United States/Mexico border near San Elizario, Texas. The Partnership owns a 16% membership interest in and operates Comanche Trail.

 

   

Trans-Pecos Pipeline is a 143-mile intrastate pipeline that delivers natural gas from the Waha Hub near Pecos, Texas to the United States/Mexico border near Presidio, Texas. The Partnership owns a 16% membership interest in and operates Trans-Pecos.

 

   

Old Ocean is a 240-mile intrastate pipeline system that delivers natural gas from Ellis County, Texas to Brazoria County, Texas. The Partnership owns a 50% membership interest in and operates Old Ocean.

 

   

The Red Bluff Express Pipeline is an approximately 108-mile intrastate pipeline that runs through the heart of the Delaware basin and connects our Orla Plant, as well as third-party plants to the Waha Oasis Header. The Partnership owns a 70% membership interest in and operates Red Bluff Express.

Interstate Transportation and Storage

The following details our pipelines in the interstate transportation and storage segment:

 

Description of Assets

   Ownership
Interest
    Miles of
Natural Gas
Pipeline
     Pipeline
Throughput
Capacity
(Bcf/d)
     Working
Gas
Capacity
(Bcf/d)
 

Florida Gas Transmission

     50     5,362      3.5      —    

Transwestern Pipeline

     100     2,614      2.1      —    

Panhandle Eastern Pipe Line (1)

     100     6,298      2.8      73.4

Trunkline Gas Company

     100     2,190      0.9      13.0

Tiger Pipeline

     100     197      2.4      —    

Fayetteville Express Pipeline

     50     185      2.0      —    

Sea Robin Pipeline

     100     740      2.0      —    

Stingray Pipeline

     100     287      0.4      —    

Rover Pipeline

     32.6     719      3.4      —    

Midcontinent Express Pipeline

     50     512      1.8      —    

Gulf States Transmission

     100     10      0.1      —    

 

(1)

Natural gas storage assets are owned by Southwest Gas.

The following information describes our principal interstate transportation and storage assets:

 

   

Florida Gas Transmission Pipeline (“FGT”) has mainline capacity of 3.5 Bcf/d and approximately 5,362 miles of pipelines extending from south Texas through the Gulf Coast region of the United States to south Florida. The FGT system receives natural gas from various onshore and offshore natural gas producing basins. FGT is the principal transporter of natural gas to the Florida energy market, delivering approximately 60% of the natural gas consumed in the state. In addition, FGT’s system operates and maintains multiple interconnects with major interstate and intrastate natural gas pipelines, which provide FGT’s customers access to diverse natural gas producing regions. FGT’s customers include electric utilities, independent power producers, industrial end-users and local distribution companies. FGT is owned by Citrus, a 50/50 joint venture with KMI.

 

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Transwestern Pipeline transports natural gas supply from the Permian Basin in West Texas and eastern New Mexico, the San Juan Basin in northwestern New Mexico and southern Colorado, and the Anadarko Basin in the Texas and Oklahoma panhandles. The system has bi-directional capabilities and can access Texas and Midcontinent natural gas market hubs, as well as major western markets in Arizona, Nevada and California. Transwestern’s customers include local distribution companies, producers, marketers, electric power generators and industrial end-users.

 

   

Panhandle Eastern Pipe Line’s transmission system consists of four large diameter pipelines with bi-directional capabilities, extending approximately 1,300 miles from producing areas in the Anadarko Basin of Texas, Oklahoma and Kansas through Missouri, Illinois, Indiana, Ohio and into Michigan. Panhandle contracts for over 73 Bcf of natural gas storage.

 

   

Trunkline Gas Company’s transmission system consists of one large diameter pipeline with bi-directional capabilities, extending approximately 1,400 miles from the Gulf Coast areas of Texas and Louisiana through Arkansas, Mississippi, Tennessee, Kentucky, Illinois, Indiana and Michigan. Trunkline has one natural gas storage field located in Louisiana.

 

   

Tiger Pipeline is a bi-directional system that extends through the heart of the Haynesville Shale and ends near Delhi, Louisiana, interconnecting with multiple interstate pipelines.

 

   

Fayetteville Express Pipeline originates near Conway County, Arkansas and continues eastward to Panola County, Mississippi with multiple pipeline interconnections along the route. Fayetteville Express Pipeline is owned by a 50/50 joint venture with KMI.

 

   

Sea Robin Pipeline’s system consists of two offshore Louisiana natural gas supply pipelines extending 120 miles into the Gulf of Mexico.

 

   

Stingray Pipeline is an interstate natural gas pipeline system with related assets located in the western Gulf of Mexico and Johnson Bayou, Louisiana. Stingray has recently filed with the FERC to abandon a portion of its system to be used in non-gas service and the remaining portion to be operated as a non-FERC-regulated gathering system. The proceeding is pending a decision from FERC.

 

   

Rover Pipeline is a large diameter pipeline with total capacity to transport 3.4 Bcf/d natural gas from processing plants in West Virginia, Eastern Ohio and Western Pennsylvania for delivery to other pipeline interconnects in Ohio and Michigan, where the gas is delivered for distribution to markets across the United States, as well as to Ontario, Canada.

 

   

Midcontinent Express Pipeline originates near Bennington, Oklahoma and traverses northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipeline system in Butler, Alabama. The Midcontinent Express Pipeline is owned by a 50/50 joint venture with KMI, the operator of the system.

 

   

Gulf States Transmission is a 10-mile interstate pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana.

Regasification Facility

Lake Charles LNG, our wholly-owned subsidiary, owns an LNG import terminal and regasification facility located on Louisiana’s Gulf Coast near Lake Charles, Louisiana. The import terminal has approximately 9.0 Bcf of above ground LNG storage capacity and the regasification facility has a send out capacity of 1.8 Bcf/d.

Liquefaction Project

LCL, a wholly-owned subsidiary of ETO, is in the process of developing an LNG liquefaction project at the site of our Lake Charles LNG import terminal and regasification facility. The project would utilize existing dock and storage facilities owned by Lake Charles LNG located on the Lake Charles site. LCL entered into a prior development agreement with Shell in March 2019; however, Shell withdrew from the project in March 2020 due

 

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to adverse market factors affecting Shell’s business following the onset of the COVID-19 pandemic. We intend to continue to develop the project, possibly in conjunction with one or more equity partners, and we plan to evaluate a variety of alternatives to advance the project, including the possibility of reducing the size of the project from three trains (16.45 million tonnes per annum of LNG capacity) to two trains (11.0 million tonnes per annum). The project as currently designed is fully permitted by federal, state and local authorities, has all necessary export licenses and benefits from the infrastructure related to the existing regasification facility at the same site, including four LNG storage tanks, two deep water docks and other assets. In light of the existing brownfield infrastructure and the advanced state of the development of the project, we plan to continue to pursue the project on a disciplined, cost effective basis, and ultimately we will determine whether to make a final investment decision to proceed with the project based on market conditions, capital expenditure considerations and our success in securing equity participation by third parties as well as long-term LNG offtake commitments on satisfactory terms. LCL is actively involved in a variety of activities related to the development of the project and has also been marketing LNG offtake to numerous potential customers in Asia and Europe.

The export of LNG produced by the liquefaction project from the United States would be undertaken under long-term export authorizations issued by the DOE to LCL. In March 2013, LCL obtained a DOE authorization to export LNG to countries with which the United States has or will have Free Trade Agreements (“FTA”) for trade in natural gas (the “FTA Authorization”). In July 2016, LCL also obtained a conditional DOE authorization to export LNG to countries that do not have an FTA for trade in natural gas (the “Non-FTA Authorization”). In October 2020, the DOE extended the FTA Authorization and Non-FTA Authorization to 30- and 25-year terms, respectively, following first deliveries on or before December 2025, consistent with the FERC authorization for the project. The FTA Authorization and Non-FTA Authorization have 25- and 20-year terms, respectively, commencing with the completion of construction of the liquefaction facility. In addition, LCL received its wetlands permits from the USACE to perform wetlands mitigation work and to perform modification and dredging work for the temporary and permanent dock facilities at the Lake Charles LNG facilities.

Midstream

The following details our assets in the midstream segment:

 

Description of Assets

   Net Gas
Processing
Capacity
(MMcf/d)
 

South Texas Region:

  

Southeast Texas System

     410

Eagle Ford System

     1,920

Ark-La-Tex Region

     1,442

North Central Texas Region

     700

Permian Region

     2,740

Midcontinent Region

     1,238

Eastern Region

     200

The following information describes our principal midstream assets:

South Texas Region:

 

   

The Southeast Texas System is an integrated system that gathers, compresses, treats, processes, dehydrates and transports natural gas from the Austin Chalk trend and Eagle Ford shale formation. The Southeast Texas System is a large natural gas gathering system covering thirteen counties between Austin and Houston. This system is connected to the Katy Hub through the ETC Katy Pipeline and is also connected to the Oasis Pipeline. The Southeast Texas System includes two natural gas processing plants (La Grange and Alamo) with aggregate capacity of 410 MMcf/d. The La Grange and Alamo processing plants are natural gas

 

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processing plants that process the rich gas that flows through our gathering system to produce residue gas and NGLs. Residue gas is delivered into our intrastate pipelines and NGLs are delivered into our NGL pipelines to Lone Star.

Our treating facilities remove carbon dioxide and hydrogen sulfide from natural gas gathered into our system before the natural gas is introduced to transportation pipelines to ensure that the gas meets pipeline quality specifications.

 

   

The Eagle Ford Gathering System consists of 30-inch and 42-inch natural gas gathering pipelines with over 1.4 Bcf/d of capacity originating in Dimmitt County, Texas, and extending to both our King Ranch gas plant in Kleberg County, Texas and Jackson plant in Jackson County, Texas. The Eagle Ford Gathering System includes four processing plants (Chisholm, Kenedy, Jackson and King Ranch) with aggregate capacity of 1.92 Bcf/d. Our Chisholm, Kenedy, Jackson and King Ranch processing plants are connected to our intrastate transportation pipeline systems for deliveries of residue gas and are also connected with our NGL pipelines for delivery of NGLs to Lone Star.

Ark-La-Tex Region:

 

   

Our Northern Louisiana assets are comprised of several gathering systems in the Haynesville Shale with access to multiple markets through interconnects with several pipelines, including our Tiger Pipeline. Our Northern Louisiana assets include the Bistineau, Creedence, and Tristate Systems, which collectively include three natural gas treating facilities, with aggregate capacity of 1.4 Bcf/d.

 

   

The Ark-La-Tex assets gather, compress, treat and dehydrate natural gas in several parishes in north and west Louisiana and several counties in East Texas. These assets also include cryogenic natural gas processing facilities, a refrigeration plant, a conditioning plant, amine treating plants, a residue gas pipeline that provides market access for natural gas from our processing plants, including connections with pipelines that provide access to the Perryville Hub and other markets in the Gulf Coast region, and an NGL pipeline that provides connections to the Mont Belvieu market for NGLs produced from our processing plants. Collectively, the ten natural gas processing facilities (Dubach, Dubberly, Lisbon, Salem, Elm Grove, Minden, Ada, Brookeland, Lincoln Parish and Mt. Olive) have an aggregate capacity of 1.3 Bcf/d.

 

   

Through the gathering and processing systems described above and their interconnections with RIGS in north Louisiana, as well as other pipelines, we offer producers wellhead-to-market services, including natural gas gathering, compression, processing, treating and transportation.

North Central Texas Region:

 

   

The North Central Texas System is an integrated system located in four counties in North Central Texas that gathers, compresses, treats, processes and transports natural gas from the Barnett and Woodford Shales. Our North Central Texas assets include our Godley and Crescent plants, which process rich gas produced from the Barnett Shale and STACK play, with aggregate capacity of 700 MMcf/d. The Godley plant is integrated with the ET Fuel System.

Permian Region:

 

   

The Permian Basin Gathering System offers wellhead-to-market services to producers in eleven counties in West Texas, as well as two counties in New Mexico which surround the Waha Hub, one of Texas’s developing NGL-rich natural gas market areas. As a result of the proximity of our system to the Waha Hub, the Waha Gathering System has a variety of market outlets for the natural gas that we gather and process, including several major interstate and intrastate pipelines serving California, the midcontinent region of the United States and Texas natural gas markets. The NGL market outlets includes Lone Star’s liquids pipelines. The Permian Basin Gathering System includes eleven processing facilities (Waha, Coyanosa, Red Bluff, Halley, Jal, Keyston, Tippet, Orla, Panther, Rebel and Arrowhead) with an aggregate processing capacity of 2.4 Bcf/d and one natural gas conditioning facility with aggregate capacity of 200 MMcf/d.

 

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We own a 50% membership interest in Mi Vida JV LLC, a joint venture which owns a 200 MMcf/d cryogenic processing plant in West Texas. We operate the plant and related facilities on behalf of the joint venture.

 

   

We own a 50% membership interest in Ranch Westex JV, LLC, which processes natural gas delivered from the NGL-rich Bone Spring and Avalon Shale formations in West Texas. The joint venture owns a 25 MMcf/d refrigeration plant and a 125 MMcf/d cryogenic processing plant.

Midcontinent Region:

 

   

The Midcontinent Systems are located in two large natural gas producing regions in the United States, the Hugoton Basin in southwest Kansas, and the Anadarko Basin in western Oklahoma and the Texas Panhandle and the STACK in central Oklahoma. These mature basins have continued to provide generally long-lived, predictable production volume. Our Midcontinent assets are extensive systems that gather, compress and dehydrate low-pressure gas. The Midcontinent Systems include sixteen natural gas processing facilities (Mocane, Beaver, Antelope Hills, Woodall, Wheeler, Sunray, Hemphill, Phoenix, Hamlin, Spearman, Red Deer, Lefors, Cargray, Gray, Rose Valley, and Hopeton) with an aggregate capacity of approximately 1.2 Bcf/d.

 

   

We operate our Midcontinent Systems at low pressures to maximize the total throughput volumes from the connected wells. Wellhead pressures are therefore adequate to allow for flow of natural gas into the gathering lines without the cost of wellhead compression.

 

   

We also own the Hugoton Gathering System that has 1,900 miles of pipeline extending over nine counties in Kansas and Oklahoma. This system is operated by a third party.

Eastern Region:

 

   

The Eastern Region assets are located in eleven counties in Pennsylvania, four counties in Ohio, three counties in West Virginia, and gather natural gas from the Marcellus and Utica basins. Our Eastern Region assets include approximately 600 miles of natural gas gathering pipeline, natural gas trunklines, fresh-water pipelines, and nine gathering and processing systems, as well as the 200 MMcf/d Revolution processing plant, which feeds into our Mariner East and Rover pipeline systems.

 

   

We also own a 51% membership interest in Aqua – ETC Water Solutions LLC, a joint venture that transports and supplies fresh water to natural gas producers drilling in the Marcellus Shale in Pennsylvania.

 

   

We own a 75% membership interest in ORS. On behalf of ORS, we operate its Ohio Utica River System, which consists of 47 miles of 36-inch, 13 miles of 30-inch and 3 miles of 24-inch gathering trunklines, that delivers up to 3.6 Bcf/d to Rockies Express Pipeline, Texas Eastern Transmission, Leach Xpress, Rover and DEO TPL-18.

 

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NGL and Refined Products Transportation and Services

The following details the assets in our NGL and refined products transportation and services segment:

 

Description of Assets

   Miles of
Liquids
Pipeline (1)
     NGL
Fractionation
/ Processing
Capacity
(MBbls/d)
     Working
Storage
Capacity
(MBbls)
 

Liquids Pipelines:

        

Lone Star Express

     892      —          —    

West Texas Gateway Pipeline

     510      —          —    

Lone Star

     1,400      —          —    

Mariner East

     667      —          —    

Mariner South

     67      —          —    

Mariner West

     398      —          —    

White Cliffs Pipeline(2)

     540      —          —    

Other NGL Pipelines

     279      —          —    

Liquids Fractionation and Services Facilities:

        

Mont Belvieu Facilities

     182      940      50,000

Sea Robin Processing Plant(3)

     —          26      —    

Refinery Services(3)

     100      35      —    

Hattiesburg Storage Facilities

     —          —          5,200

Cedar Bayou

     —          —          1,600

NGL Terminals:

        

Nederland

     —          —          1,900

Orbit Gulf Coast

     70      —          1,200

Marcus Hook Terminal

     —          132      6,000

Inkster

     —          —          860

Refined Products Pipelines:

        

Eastern region pipelines

     1,016      —          —    

Midcontinent region pipelines

     332      —          —    

Southwest region pipelines

     376      —          —    

Inland Pipeline

     690      —          —    

JC Nolan Pipeline

     504      —          —    

Refined Products Terminals:

        

Eagle Point

     —          —          6,700

Marcus Hook Terminal

     —          —          930

Marcus Hook Tank Farm

     —          —          1,900

Marketing Terminals

     —          —          7,700

JC Nolan Terminal

     —          —          134

 

(1)

Miles of pipeline as reported to PHMSA.

(2)

The White Cliffs Pipeline consists of two parallel, 12-inch common carrier pipelines: one crude oil pipeline and one NGL pipeline.

(3)

Additionally, the Sea Robin Processing Plant and Refinery Services have inlet volume capacities of 850 MMcf/d and 54 MMcf/d, respectively.

The following information describes our principal NGL and refined products transportation and services assets:

 

   

The Lone Star Express System is an interstate NGL pipeline consisting of 24-inch and 30-inch long-haul transportation pipeline, with throughput capacity of approximately 500 MBbls/d, that delivers mixed NGLs from processing plants in the Permian Basin, the Barnett Shale, and from East Texas to the Mont Belvieu NGL storage facility. In the third quarter of 2020, we completed an expansion of the pipeline, which added

 

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approximately 400 MBbls/d of NGL pipeline capacity from Lone Star’s pipeline system near Wink, Texas to the Lone Star Express 30-inch pipeline south of Fort Worth, Texas. It is expected to be in service by the fourth quarter of 2020.

 

   

The West Texas Gateway Pipeline transports NGLs produced in the Permian and Delaware Basins and the Eagle Ford Shale to Mont Belvieu, Texas and has a throughput capacity of approximately 240 MBbls/d.

 

   

The Mariner East pipeline transports NGLs from the Marcellus and Utica Shales areas in Western Pennsylvania, West Virginia and Eastern Ohio to destinations in Pennsylvania, including our Marcus Hook Terminal on the Delaware River, where they are processed, stored and distributed to local, domestic and waterborne markets. The first phase of the project, referred to as Mariner East 1, consisted of interstate and intrastate propane and ethane service and commenced operations in the fourth quarter of 2014 and the first quarter of 2016, respectively. The second phase of the project, referred to as Mariner East 2, began service in December 2018. The Mariner East pipeline has a throughput capacity of approximately 345 MBbls/d.

 

   

The Mariner South liquids pipeline system consists of three pipelines and delivers export-grade propane, butane and natural gasoline from Lone Star’s Mont Belvieu, Texas storage and fractionation complex to our marine terminal in Nederland, Texas and has a total throughput capacity of approximately 600 MBbls/d.

 

   

The Mariner West pipeline provides transportation of ethane from the Marcellus shale processing and fractionating areas in Houston, Pennsylvania to Marysville, Michigan and the Canadian border and has a throughput capacity of approximately 50 MBbls/d.

 

   

The White Cliffs NGL pipeline, in which we have 51% ownership interest and was acquired by ET in the SemGroup acquisition and contributed to ETO in January 2020, transports NGLs produced in the DJ Basin to Cushing, where it interconnects with the Southern Hills Pipeline to move NGLs to Mont Belvieu, Texas and has a throughput capacity of approximately 90 MBbls/d.

 

   

Other NGL pipelines include the 127-mile Justice pipeline with capacity of 375 MBbls/d, the 45-mile Freedom pipeline with a capacity of 56 MBbls/d, the 20-mile Spirit pipeline with a capacity of 20 MBbls/d and a 50% interest in the 87-mile Liberty pipeline with a capacity of 140 MBbls/d.

 

   

Our Mont Belvieu storage facility is an integrated liquids storage facility with approximately 50 MMBbls of salt dome capacity providing 100% fee-based cash flows. The Mont Belvieu storage facility has access to multiple NGL and refined products pipelines, the Houston Ship Channel trading hub, and numerous chemical plants, refineries and fractionators.

 

   

Our Mont Belvieu fractionators handle NGLs delivered from several sources, including the Lone Star Express pipeline and the Justice pipeline. Fractionator VI was placed in service in February 2019 and Fractionator VII was placed in service in the first quarter of 2020.

 

   

Sea Robin is a rich gas processing plant located on the Sea Robin Pipeline in southern Louisiana. The plant is connected to nine interstate and four intrastate residue pipelines, as well as various deep-water production fields.

 

   

Refinery Services consists of a refinery off-gas processing unit and an O-grade NGL fractionation / Refinery-Grade Propylene (“RGP”) splitting complex located along the Mississippi River refinery corridor in southern Louisiana. The off-gas processing unit cryogenically processes refinery off-gas, and the fractionation / RGP splitting complex fractionates the streams into higher value components. The O-grade fractionator and RGP splitting complex, located in Geismar, Louisiana, is connected by approximately 100 miles of pipeline to the Chalmette processing plant, which has a processing capacity of 54 MMcf/d.

 

   

The Hattiesburg storage facility is an integrated liquids storage facility with approximately 5.2 MMBbls of salt dome capacity, providing 100% fee-based cash flows.

 

   

The Cedar Bayou storage facility is an integrated liquids storage facility with approximately 1.6 MMBbls of tank storage, generating revenues from fixed fee storage contracts, throughput fees, and revenue from blending butane into refined gasoline.

 

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The Nederland Terminal, in addition to crude oil activities, also provides approximately 1.9 MMBbls of storage and distribution services for NGLs in connection with the Mariner South and Mariner South 2 pipelines, which provide transportation of propane and butane products from the Mont Belvieu region to the Nederland Terminal, where such products can be exported via ship.

 

   

The Orbit Gulf Coast joint venture consists of a 70-mile, 20-inch ethane pipeline with a throughput capacity of approximately 180 MBbls/d, delivering from Lone Star’s Mont Belvieu, Texas storage and fractionation complex to our marine terminal in Nederland, Texas, as well as a 180 MBbls/d ethane refrigeration facility and 1.2 MMBbls of storage capacity.

 

   

The Marcus Hook Terminal includes fractionation, terminalling and storage assets, with a capacity of approximately 2 MMBbls of NGL storage capacity in underground caverns, 4 MMBbls of above-ground refrigerated storage, and related commercial agreements. The terminal has a total active refined products storage capacity of approximately 1 MMBbls. The facility can receive NGLs and refined products via marine vessel, pipeline, truck and rail, and can deliver via marine vessel, pipeline and truck. In addition to providing NGL storage and terminalling services to both affiliates and third-party customers, the Marcus Hook Terminal currently serves as an off-take outlet for our Mariner East 1 and Mariner East 2 pipeline systems.

 

   

The Inkster terminal, located near Detroit, Michigan, consists of multiple salt caverns with a total storage capacity of approximately 860 MBbls of NGLs. We use the Inkster terminal’s storage in connection with the Toledo North pipeline system and for the storage of NGLs from local producers and a refinery in Western Ohio. The terminal can receive and ship by pipeline in both directions and has a truck loading and unloading rack.

 

   

The Eastern region refined products pipelines consist of 6-inch to 16-inch diameters refined product pipelines in Eastern, Central and North Central Pennsylvania, 8-inch refined products pipeline in western New York and various diameters refined products pipeline in New Jersey (including 80 miles of the 16-inch diameter Harbor Pipeline).

 

   

The midcontinent region refined products pipelines primarily consist of 3-inch to 12-inch refined products pipelines in Ohio and 6-inch and 8-inch refined products pipeline in Michigan.

 

   

The Southwest region refined products pipelines are located in Eastern Texas and consist primarily of 8-inch diameter refined products pipeline.

 

   

The Inland refined products pipeline consists of 12, 10, 8 and 6-inch diameter pipelines in the western, northwestern, and northeastern regions of Ohio.

 

   

The JC Nolan Pipeline is a joint venture between a wholly-owned subsidiary of the Partnership and a wholly-owned subsidiary of Sunoco LP, which transports diesel fuel from a tank farm in Hebert, Texas to Midland, Texas, and was placed into service in July 2019 and has a throughput capacity of approximately 36 MBbls/d.

 

   

We have 37 refined products terminals with an aggregate storage capacity of approximately 8 MMBbls that facilitate the movement of refined products to or from storage or transportation systems, such as a pipeline, to other transportation systems, such as trucks or other pipelines. Each facility typically consists of multiple storage tanks and is equipped with automated truck loading equipment that is operational 24 hours a day.

 

   

In addition to crude oil service, the Eagle Point terminal can accommodate three marine vessels (ships or barges) to receive and deliver refined products to outbound ships and barges. The tank farm has a total active refined products storage capacity of approximately 7 MMBbls and provides customers with access to the facility via ship, barge and pipeline. The terminal can deliver via ship, barge, truck or pipeline, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.

 

   

The Marcus Hook Terminal also has a tank farm with total refined products storage capacity of approximately 2 MMBbls of refined products storage. The terminal receives and delivers refined products

 

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via pipeline and primarily provides terminalling services to support movements on our refined products pipelines.

 

   

The JC Nolan Terminal, located in Midland, Texas, is a joint venture between a wholly-owned subsidiary of the Partnership and a wholly-owned subsidiary of Sunoco LP, which provides diesel fuel storage that was placed into service in August 2019.

 

   

This segment also includes the following joint ventures: 15% membership interest in the Explorer Pipeline Company, a 1,850-mile pipeline which originates from refining centers in Beaumont, Port Arthur, and Houston, Texas and extends to Chicago, Illinois; 31% membership interest in the Wolverine Pipe Line Company, a 1,055-mile pipeline that originates from Chicago, Illinois and extends to Detroit, Grand Haven, and Bay City, Michigan; 17% membership interest in the West Shore Pipe Line Company, a 650-mile pipeline which originates in Chicago, Illinois and extends to Madison and Green Bay, Wisconsin; a 14% membership interest in the Yellowstone Pipe Line Company, a 710-mile pipeline which originates from Billings, Montana and extends to Moses Lake, Washington.

Crude Oil Transportation and Services

The following details our pipelines and terminals in the crude oil transportation and services segment:

 

Description of Assets

   Ownership
Interest
    Miles of Crude
Pipeline(1)
     Working
Storage
Capacity
(MBbls)
 

Dakota Access Pipeline

     36.4     1,172      —    

Energy Transfer Crude Oil Pipeline

     36.4     744      —    

Bayou Bridge Pipeline

     60     212      —    

Permian Express Pipelines

     87.7     1,760      —    

Wattenberg Oil Trunkline

     100     75      360

White Cliffs Pipeline(2)

     51     527      100

Maurepas Pipeline

     51     106      —    

Other Crude Oil Pipelines

     100     6,256      —    

Nederland Terminal

     100     —          29,000

Fort Mifflin Terminal

     100     —          3,300

Eagle Point Terminal

     100     —          1,800

Midland Terminal

     100     —          1,000

Marcus Hook Terminal

     100     —          1,000

Houston Terminal

     100     —          18,200

Cushing Facility

     100     —          7,700

Patoka, Illinois Terminal

     87.7     —          1,900

 

(1)

Miles of pipeline as reported to PHMSA.

(2)

The White Cliffs Pipeline consists of two parallel, 12-inch common carrier crude oil pipelines: one crude oil pipeline and one NGL pipeline.

Our crude oil operations consist of an integrated set of pipeline, terminalling, trucking and acquisition and marketing assets that service the movement of crude oil from producers to end-user markets. The following details our assets in the crude oil transportation and services segment:

Crude Oil Pipelines

Our crude oil pipelines consist of approximately 10,850 miles of crude oil trunk and gathering pipelines in the southwest, northwest and midwest United States, including our wholly-owned interests in West Texas Gulf, Permian Express Terminal LLC, Mid-Valley and Wattenberg Oil Trunkline. Additionally, we have equity

 

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ownership interests in two crude oil pipelines. Our crude oil pipelines provide access to several trading hubs, including the largest trading hub for crude oil in the United States located in Cushing, Oklahoma, and other trading hubs located in Midland, Colorado City and Longview, Texas. Our crude oil pipelines also deliver to and connect with other pipelines that deliver crude oil to a number of refineries.

 

   

Bakken Pipeline. The Dakota Access and Energy Transfer Crude Oil pipelines are collectively referred to as the “Bakken Pipeline.” The Bakken Pipeline is a 1,916-mile pipeline with capacity of 570 MBbls/d, that transports domestically produced crude oil from the Bakken/Three Forks production areas in North Dakota to a storage and terminal hub outside of Patoka, Illinois, or to gulf coast connections including our crude terminal in Nederland, Texas.

The pipeline transports light, sweet crude oil from North Dakota to major refining markets in the Midwest and Gulf Coast regions.

The Dakota Access Pipeline went into service on June 1, 2017 and consists of approximately 1,172 miles of 12, 20, 24 and 30-inch diameter pipeline traversing North Dakota, South Dakota, Iowa and Illinois. Crude oil transported on the Dakota Access Pipeline originates at six terminal locations in the North Dakota counties of Mountrail, Williams and McKenzie. The pipeline delivers the crude oil to a hub outside of Patoka, Illinois where it can be delivered to the Energy Transfer Crude Oil Pipeline for delivery to the Gulf Coast or can be transported via other pipelines to refining markets throughout the Midwest.

The Energy Transfer Crude Oil Pipeline went into service on June 1, 2017 and consists of approximately 675 miles of mostly 30-inch converted natural gas pipeline and 69 miles of new 30-inch pipeline from Patoka, Illinois to Nederland, Texas, where the crude oil can be refined or further transported to additional refining markets.

 

   

Bayou Bridge Pipeline. The Bayou Bridge Pipeline is a joint venture between ETO and Phillips 66, in which ETO has a 60% ownership interest and serves as the operator of the pipeline. Phase I of the pipeline, which consists of a 30-inch pipeline from Nederland, Texas to Lake Charles, Louisiana, went into service in April 2016. Phase II of the pipeline, which consists of 24-inch pipe from Lake Charles, Louisiana to St. James, Louisiana, which went into service in March 2019.

With the completion of Phase II, Bayou Bridge Pipeline has a capacity of approximately 480 MBbls/d of light and heavy crude oil from different sources to the St. James crude oil hub, which is home to important refineries located in the Gulf Coast region.

 

   

Permian Express Pipelines. The Permian Express pipelines are part of the PEP joint venture and include the Permian Express 1, Permian Express 2, Permian Express 3, Permian Express 4, Permian Longview, Louisiana Access, Longview to Louisiana and Nederland Access pipelines. These pipelines are comprised of crude oil trunk pipelines and crude oil gathering pipelines in Texas and Oklahoma and provide takeaway capacity from the Permian Basin, with origins in multiple locations in Western Texas.

 

   

White Cliffs Pipeline. White Cliffs Pipeline, which was acquired by ET in the SemGroup acquisition and contributed to ETO in January 2020, owns a 12-inch common carrier, crude oil pipeline, with a throughput capacity of 100 MBbls/d, that transports crude oil from Platteville, Colorado to Cushing, Oklahoma.

 

   

Maurepas Pipeline. The Maurepas Pipeline, which was acquired by ET in the SemGroup acquisition and contributed to ETO in January 2020, consists of three pipelines, with an aggregate throughput capacity of 460 MBbls/d, which service refineries in the Gulf Coast region.

 

   

Other Crude Oil pipelines include the Mid-Valley pipeline system which originates in Longview, Texas and passes through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky and Ohio and terminates in Samaria, Michigan. This pipeline provides crude oil to a number of refineries, primarily in the Midwest United States.

In addition, we own a crude oil pipeline that runs from Marysville, Michigan to Toledo, Ohio, and a truck injection point for local production at Marysville. This pipeline receives crude oil from the Enbridge

 

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pipeline system for delivery to refineries located in Toledo, Ohio and to MPLX’s Samaria, Michigan tank farm, which supplies Marathon Petroleum Corporation’s refinery in Detroit, Michigan.

We also own and operate crude oil pipeline and gathering systems in Oklahoma and Kansas. We have the ability to deliver substantially all of the crude oil gathered on our Oklahoma and Kansas systems to Cushing. We are one of the largest purchasers of crude oil from producers in the area, and our crude oil acquisition and marketing activities business is the primary shipper on our Oklahoma crude oil system.

Crude Oil Terminals

 

   

Nederland. The Nederland Terminal, located on the Sabine-Neches waterway between Beaumont and Port Arthur, Texas, is a large marine terminal providing storage and distribution services for refiners and other large transporters of crude oil and NGLs. The terminal receives, stores, and distributes crude oil, NGLs, feedstocks, petrochemicals and bunker oils (used for fueling ships and other marine vessels). The terminal currently has a total storage capacity of approximately 29 MMBbls in approximately 160 above ground storage tanks with individual capacities of up to 660 MBbls.

The Nederland Terminal can receive crude oil at four of its five ship docks and four barge berths. The four ship docks are capable of receiving over 2 MMBbls/d of crude oil. In addition to our crude oil pipelines, the terminal can also receive crude oil through a number of other pipelines, including the DOE. The DOE pipelines connect the terminal to the United States Strategic Petroleum Reserve’s West Hackberry caverns at Hackberry, Louisiana and Big Hill caverns near Winnie, Texas, which have an aggregate storage capacity of approximately 395 MMBbls.

The Nederland Terminal can deliver crude oil and other petroleum products via pipeline, barge and ship. The terminal has three ship docks and three barge berths that are capable of delivering crude oils for international transport. In total, the terminal is capable of delivering over 2 MMBbls/d of crude oil to our crude oil pipelines or a number of third-party pipelines including the DOE. The Nederland Terminal generates crude oil revenues primarily by providing term or spot storage services and throughput capabilities to a number of customers.

 

   

Fort Mifflin. The Fort Mifflin terminal complex is located on the Delaware River in Philadelphia, Pennsylvania and includes the Fort Mifflin terminal, the Hog Island wharf, the Darby Creek tank farm and connecting pipelines. The Fort Mifflin terminal contains two ship docks with freshwater drafts and a total storage capacity of approximately 570 MBbls. Crude oil and some refined products enter the Fort Mifflin terminal primarily from marine vessels on the Delaware River.

The Hog Island wharf is located next to the Fort Mifflin terminal on the Delaware River and receives crude oil via two ship docks. The Darby Creek tank farm is a primary crude oil storage terminal that receives crude oil from the Fort Mifflin terminal and Hog Island wharf via our pipelines and has a total storage capacity of approximately 2.7 MMBbls.

 

   

Eagle Point. The Eagle Point terminal is located in Westville, New Jersey and consists of docks, truck loading facilities and a tank farm. The docks are located on the Delaware River and can accommodate three marine vessels (ships or barges) to receive and deliver crude oil, intermediate products and refined products to outbound ships and barges. The tank farm has a total active storage capacity of approximately 1.8 MMBbls and can receive crude oil via barge and rail and deliver via ship and barge, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.

 

   

Midland. The Midland terminal is located in Midland, Texas and was acquired in November 2016 from Vitol. The facility includes approximately 1 MMBbls of crude oil storage, a combined 20 lanes of truck loading and unloading, and provides access to the Permian Express 2 transportation system.

 

   

Marcus Hook Terminal. The Marcus Hook Terminal can receive crude oil via marine vessel and can deliver via marine vessel and pipeline. The terminal has a total active crude oil storage capacity of approximately 1 MMBbls.

 

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Patoka, Illinois Terminal. The Patoka, Illinois terminal is a tank farm owned by the PEP joint venture and is located in Marion County, Illinois. The facility includes 234 acres of owned land and provides for approximately 1.9 MMBbls of crude oil storage.

 

   

Houston Terminal. The Houston Terminal, which was acquired by ET in the SemGroup acquisition and contributed to ETO in February 2020, consists of storage tanks located on the Houston Ship Channel with an aggregate storage capacity of 18.2 MMBbls used to store, blend and transport refinery products and refinery feedstocks via pipeline, barge, rail, truck and ship. This facility has five deep-water ship docks on the Houston Ship Channel capable of loading and unloading Suezmax cargo vessels and seven barge docks which can accommodate 23 barges simultaneously, three crude oil pipelines connecting to four refineries and numerous rail and truck loading spots.

 

   

Cushing Facilities. The Cushing Facility, which was acquired by ET in the SemGroup acquisition and contributed to ETO in January 2020, has approximately 7.7 MMBbls of crude oil storage, of which 5.7 MMBbls are leased to customers and 2.0 MMBbls are available for crude oil operations, blending and marketing activities. The storage terminal has inbound connections with the White Cliffs Pipeline from Platteville, Colorado, the Great Salt Plains Pipeline from Cherokee, Oklahoma, the Cimarron Pipeline from Boyer, Kansas, and two-way connections with all of the other major storage terminals in Cushing. The Cushing terminal also includes truck unloading facilities.

Crude Oil Acquisition and Marketing

Our crude oil acquisition and marketing operations are conducted using our assets, which include approximately 363 crude oil transport trucks, 350 trailers and approximately 166 crude oil truck unloading facilities, as well as third-party truck, rail, pipeline and marine assets.

Investment in Sunoco LP

Sunoco LP is a distributor of motor fuels and other petroleum products which Sunoco LP supplies to third-party dealers and distributors, to independent operators of commission agent locations and other commercial consumers of motor fuel. Also included in the wholesale operations are transmix processing plants and refined products terminals. Transmix is the mixture of various refined products (primarily gasoline and diesel) created in the supply chain (primarily in pipelines and terminals) when various products interface with each other. Transmix processing plants separate this mixture and return it to salable products of gasoline and diesel.

Sunoco LP is the exclusive wholesale supplier of the Sunoco-branded motor fuel, supplying an extensive distribution network of approximately 5,556 Sunoco-branded company and third-party operated locations throughout the East Coast, Midwest, South Central and Southeast regions of the United States. Sunoco LP believes it is one of the largest independent motor fuel distributors of Chevron, ExxonMobil and Valero branded motor fuel in the United States. In addition to distributing motor fuels, Sunoco LP also distributes other petroleum products such as propane and lubricating oil, and Sunoco LP receives rental income from real estate that it leases or subleases.

Sunoco LP operations primarily consist of fuel distribution and marketing.

Sunoco LP’s Fuel Distribution and Marketing Operations

Sunoco LP’s fuel distribution and marketing operations are conducted by the following consolidated subsidiaries:

 

   

Sunoco, LLC (“Sunoco LLC”), a Delaware limited liability company, primarily distributes motor fuel in 30 states throughout the East Coast, Midwest, South Central and Southeast regions of the United States. Sunoco LLC also processes transmix and distributes refined product through its terminals in Alabama, Texas, Arkansas and New York;

 

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Sunoco Retail LLC (“Sunoco Retail”), a Pennsylvania limited liability company, owns and operates retail stores that sell motor fuel and merchandise primarily in New Jersey;

 

   

Aloha Petroleum LLC, a Delaware limited liability company, distributes motor fuel and operates terminal facilities on the Hawaiian Islands; and

 

   

Aloha Petroleum, Ltd. (“Aloha”), a Hawaii corporation, owns and operates retail stores on the Hawaiian Islands.

Sunoco LP purchases motor fuel primarily from independent refiners and major oil companies and distributes it across more than 30 states throughout the East Coast, Midwest, South Central and Southeast regions of the United States, as well as Hawaii to approximately:

 

   

78 company owned and operated retail stores;

 

   

539 independently operated consignment locations where Sunoco LP sells motor fuel to customers under commission agent arrangements with such operators;

 

   

6,803 convenience stores and retail fuel outlets operated by independent operators, which are referred to as “dealers” or “distributors,” pursuant to long-term distribution agreements; and

 

   

2,476 other commercial customers, including unbranded convenience stores, other fuel distributors, school districts and municipalities and other industrial customers.

Sunoco LP’s Other Operations

Sunoco LP’s other operations include retail operations in Hawaii and New Jersey, credit card services and franchise royalties.

Investment in USAC

The following details the assets of USAC:

USAC’s modern, standardized compression unit fleet is powered primarily by the Caterpillar, Inc.’s 3400, 3500 and 3600 engine classes, which range from 401 to 5,000 horsepower per unit. These larger horsepower units, which USAC defines as 400 horsepower per unit or greater, represented 86.3% of its total fleet horsepower as of December 31, 2020. The remainder of its fleet consists of smaller horsepower units ranging from 40 horsepower to 399 horsepower that are primarily used in gas lift applications.

The following table provides a summary of USAC’s compression units by horsepower as of December 31, 2020:

 

Unit Horsepower

   Fleet
Horsepower
     Number of
Units
     Percent of
Fleet
Horsepower
    Percent of
Units
 

Small horsepower

          

<400

     510,123      3,001      13.7     55.0

Large horsepower

          

>400 and <1,000

     437,543      751      11.7     13.8

>1,000

     2,778,515      1,702      74.6     31.2
  

 

 

    

 

 

    

 

 

   

 

 

 

Total large horsepower

     3,216,058      2,453      86.3     45.0
  

 

 

    

 

 

    

 

 

   

 

 

 

Total horsepower

     3,726,181      5,454      100.0     100.0
  

 

 

    

 

 

    

 

 

   

 

 

 

All Other

The following details the significant assets in the “All Other” segment.

 

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Contract Services Operations

We own and operate a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and Btu management. Our contract treating services are primarily located in Texas, Louisiana and Arkansas.

Compression

We own DDT, which provides compression services to customers engaged in the transportation of natural gas, including our other segments.

Natural Resources Operations

Our Natural Resources operations primarily involve the management and leasing of coal properties and the subsequent collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants, collecting oil and gas royalties and from coal transportation, or wheelage fees. As of December 31, 2020, we owned or controlled approximately 757 million tons of proven and probable coal reserves in central and northern Appalachia, properties in eastern Kentucky, southwestern Virginia and southern West Virginia, and in the Illinois Basin, properties in southern Illinois, Indiana, and western Kentucky and as the operator of end-user coal handling facilities.

Canadian Operations

Our Canadian operations, which were acquired in the SemGroup acquisition, include a 51% ownership interest in Energy Transfer Canada which owns and operates natural gas processing and gathering facilities in Alberta, Canada. The Canadian operations assets include four sour natural gas processing plants and two sweet natural gas processing plants that have a combined operating capacity of 1,290 MMcf/d and a network of approximately 848 miles of natural gas gathering and transportation pipelines. The principal process performed at the processing plants is to remove contaminants and render the gas salable to downstream pipelines and markets.

Business Strategy

We believe we have engaged, and will continue to engage, in a well-balanced plan for growth through strategic acquisitions, internally generated expansion, measures aimed at increasing the profitability of our existing assets and executing cost control measures where appropriate to manage our operations.

We intend to continue to operate as a diversified, growth-oriented limited partnership. We believe that by pursuing independent operating and growth strategies we will be best positioned to achieve our objectives. We balance our desire for growth with our goal of preserving a strong balance sheet, ample liquidity and investment grade credit metrics.

Following is a summary of the business strategies of our core businesses:

Growth through acquisitions. We intend to continue to make strategic acquisitions that offer the opportunity for operational efficiencies and the potential for increased utilization and expansion of our existing assets while supporting our investment grade credit ratings.

Engage in construction and expansion opportunities. We intend to leverage our existing infrastructure and customer relationships by constructing and expanding systems to meet new or increased demand for midstream and transportation services.

 

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Increase cash flow from fee-based businesses. We intend to increase the percentage of our business conducted with third parties under fee-based arrangements in order to provide for stable, consistent cash flows over long contract periods while reducing exposure to changes in commodity prices.

Enhance profitability of existing assets. We intend to increase the profitability of our existing asset base by adding new volumes under long-term producer commitments, undertaking additional initiatives to enhance utilization and reducing costs by improving operations.

Competition

Natural Gas

The business of providing natural gas gathering, compression, treating, transportation, storage and marketing services is highly competitive. Since pipelines are generally the only practical mode of transportation for natural gas over land, the most significant competitors of our transportation and storage segment are other pipelines. Pipelines typically compete with each other based on location, capacity, price and reliability.

We face competition with respect to retaining and obtaining significant natural gas supplies under terms favorable to us for the gathering, treating and marketing portions of our business. Our competitors include major integrated oil and gas companies, interstate and intrastate pipelines and other companies that gather, compress, treat, process, transport and market natural gas. Many of our competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than ours.

In marketing natural gas, we have numerous competitors, including marketing affiliates of interstate pipelines, major integrated oil and gas companies, and local and national natural gas gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Local utilities and distributors of natural gas are, in some cases, engaged directly, and through affiliates, in marketing activities that compete with our marketing operations.

NGL

In markets served by our NGL pipelines, we face competition with other pipeline companies, including those affiliated with major oil, petrochemical and natural gas companies, and barge, rail and truck fleet operations. In general, our NGL pipelines compete with these entities in terms of transportation fees, reliability and quality of customer service. We face competition with other storage facilities based on fees charged and the ability to receive and distribute the customer’s products. We compete with a number of NGL fractionators in Texas and Louisiana. Competition for such services is primarily based on the fractionation fee charged.

Crude Oil and Refined Products

In markets served by our crude oil and refined products pipelines, we face competition from other pipelines as well as rail and truck transportation. Generally, pipelines are the safest, lowest cost method for long-haul, overland movement of products and crude oil. Therefore, the most significant competitors for large volume shipments in the areas served by our pipelines are other pipelines. In addition, pipeline operations face competition from rail and trucks that deliver products in a number of areas that our pipeline operations serve. While their costs may not be competitive for longer hauls or large volume shipments, rail and trucks compete effectively for incremental and marginal volume in many areas served by our pipelines.

With respect to competition from other pipelines, the primary competitive factors consist of transportation charges, access to crude oil supply and market demand. Competitive factors in crude oil purchasing and marketing include price and contract flexibility, quantity and quality of services, and accessibility to end markets.

 

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Our refined product terminals compete with other independent terminals with respect to price, versatility and services provided. The competition primarily comes from integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading operations.

Wholesale Fuel Distribution and Retail Marketing

In our wholesale fuel distribution business, we compete primarily with other independent motor fuel distributors. The markets for distribution of wholesale motor fuel and the large and growing convenience store industry are highly competitive and fragmented, which results in narrow margins. We have numerous competitors, some of which may have significantly greater resources and name recognition than we do. Significant competitive factors include the availability of major brands, customer service, price, range of services offered and quality of service, among others. We rely on our ability to provide value-added and reliable service and to control our operating costs in order to maintain our margins and competitive position.

In our retail business, we face strong competition in the market for the sale of retail gasoline and merchandise. Our competitors include service stations of large integrated oil companies, independent gasoline service stations, convenience stores, fast food stores, supermarkets, drugstores, dollar stores, club stores and other similar retail outlets, some of which are well-recognized national or regional retail systems. The number of competitors varies depending on the geographical area. It also varies with gasoline and convenience store offerings. The principal competitive factors affecting our retail marketing operations include gasoline and diesel acquisition costs, site location, product price, selection and quality, site appearance and cleanliness, hours of operation, store safety, customer loyalty and brand recognition. We compete by pricing gasoline competitively, combining our retail gasoline business with convenience stores that provide a wide variety of products, and using advertising and promotional campaigns.

Credit Risk and Customers

Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.

The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrial end-users, oil and gas producers, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.

Our natural gas transportation and midstream revenues are derived significantly from companies that engage in exploration and production activities. The discovery and development of new shale formations across the United States has created an abundance of natural gas and crude oil resulting in a negative impact on prices in recent years for natural gas and crude oil. As a result, some of our exploration and production customers have been adversely impacted; however, we are monitoring these customers and mitigating credit risk as necessary.

 

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During the year ended December 31, 2020, none of our customers individually accounted for more than 10% of our consolidated revenues.

Regulation

Regulation of Interstate Natural Gas Pipelines. The FERC has broad regulatory authority over the business and operations of interstate natural gas pipelines. Under the Natural Gas Act of 1938 (“NGA”), the FERC generally regulates the transportation of natural gas in interstate commerce. For FERC regulatory purposes, “transportation” includes natural gas pipeline transmission (forwardhauls and backhauls), storage and other services. The Florida Gas Transmission, Transwestern, Panhandle, Trunkline, Tiger, Fayetteville Express, Rover, Sea Robin, Gulf States and Midcontinent Express pipelines transport natural gas in interstate commerce and thus each qualifies as a “natural-gas company” under the NGA subject to the FERC’s regulatory jurisdiction. We also hold certain natural gas storage facilities that are subject to the FERC’s regulatory oversight under the NGA.

The FERC’s NGA authority includes the power to:

 

   

approve the siting, construction and operation of new facilities;

 

   

review and approve transportation rates;

 

   

determine the types of services our regulated assets are permitted to perform;

 

   

regulate the terms and conditions associated with these services;

 

   

permit the extension or abandonment of services and facilities;

 

   

require the maintenance of accounts and records; and

 

   

authorize the acquisition and disposition of facilities.

Under the NGA, interstate natural gas companies must charge rates that are just and reasonable. In addition, the NGA prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.

The maximum rates to be charged by NGA-jurisdictional natural gas companies and their terms and conditions for service are required to be on file with the FERC. Most natural gas companies are authorized to offer discounts from their FERC-approved maximum just and reasonable rates when competition warrants such discounts. Natural gas companies are also generally permitted to offer negotiated rates different from rates established in their tariff if, among other requirements, such companies’ tariffs offer a cost-based recourse rate to a prospective shipper as an alternative to the negotiated rate. Natural gas companies must make offers of rate discounts and negotiated rates on a basis that is not unduly discriminatory. Existing tariff rates may be challenged by complaint or on the FERC’s own motion, and if found unjust and unreasonable, may be altered on a prospective basis from no earlier than the date of the complaint or initiation of a proceeding by the FERC. The FERC must also approve all rate changes. We cannot guarantee that the FERC will allow us to charge rates that fully recover our costs or continue to pursue its approach of pro-competitive policies.

For two of our NGA-jurisdictional natural gas companies, ETC Tiger and FEP, the large majority of capacity in those pipelines is subscribed for lengthy terms under FERC-approved negotiated rates. However, as indicated above, cost-based recourse rates are also offered under their respective tariffs.

Pursuant to the FERC’s rules promulgated under the Energy Policy Act of 2005, it is unlawful for any entity, directly or indirectly, in connection with the purchase or sale of electric energy or natural gas or the purchase or sale of transmission or transportation services subject to FERC jurisdiction: (i) to defraud using any device, scheme or artifice; (ii) to make any untrue statement of material fact or omit a material fact; or (iii) to engage in any act, practice or course of business that operates or would operate as a fraud or deceit. The Commodity

 

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Futures Trading Commission (“CFTC”) also holds authority to monitor certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act (“CEA”). With regard to our physical purchases and sales of natural gas, NGLs or other energy commodities; our transportation of these energy commodities; and any related hedging activities that we undertake, we are required to observe these anti-market manipulation laws and related regulations enforced by the FERC and/or the CFTC. These agencies hold substantial enforcement authority, including the ability to assess or seek civil penalties of up to $1.3 million per day per violation, to order disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

Failure to comply with the NGA, the Energy Policy Act of 2005, the CEA and the other federal laws and regulations governing our operations and business activities can result in the imposition of administrative, civil and criminal remedies.

Regulation of Intrastate Natural Gas and NGL Pipelines. Intrastate transportation of natural gas and NGLs is largely regulated by the state in which such transportation takes place. To the extent that our intrastate natural gas transportation systems transport natural gas in interstate commerce, the rates and terms and conditions of such services are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act of 1978 (“NGPA”). The NGPA regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of a local distribution company or an interstate natural gas pipeline. The rates and terms and conditions of some transportation and storage services provided on the Oasis pipeline, HPL System, East Texas pipeline, ET Fuel System, Trans-Pecos pipeline and Comanche Trail pipeline are subject to FERC regulation pursuant to Section 311 of the NGPA. Under Section 311, rates charged for intrastate transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. The terms and conditions of service set forth in the intrastate facility’s statement of operating conditions are also subject to FERC review and approval. Should the FERC determine not to authorize rates equal to or greater than our currently approved Section 311 rates, our business may be adversely affected. Failure to observe the service limitations applicable to transportation and storage services under Section 311, failure to comply with the rates approved by the FERC for Section 311 service, and failure to comply with the terms and conditions of service established in the pipeline’s FERC-approved statement of operating conditions could result in an alteration of jurisdictional status, and/or the imposition of administrative, civil and criminal remedies.

Our intrastate natural gas operations are also subject to regulation by various agencies in Texas, principally the TRRC. Our intrastate pipeline and storage operations in Texas are also subject to the Texas Utilities Code, as implemented by the TRRC. Generally, the TRRC is vested with authority to ensure that rates, operations and services of gas utilities, including intrastate pipelines, are just and reasonable and not discriminatory. The rates we charge for transportation services are deemed just and reasonable under Texas law unless challenged in a customer or TRRC complaint. We cannot predict whether such a complaint will be filed against us or whether the TRRC will change its regulation of these rates. Failure to comply with the Texas Utilities Code can result in the imposition of administrative, civil and criminal remedies.

Our NGL pipelines and operations are subject to state statutes and regulations which could impose additional environmental, safety and operational requirements relating to the design, siting, installation, testing, construction, operation, replacement and management of NGL transportation systems. In some jurisdictions, state public utility commission oversight may include the possibility of fines, penalties and delays in construction related to these regulations. In addition, the rates, terms and conditions of service for shipments of NGLs on our pipelines are subject to regulation by the FERC under the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992 (the “EPAct of 1992”) if the NGLs are transported in interstate or foreign commerce whether by our pipelines or other means of transportation. Since we do not control the entire transportation path of all NGLs shipped on our pipelines, FERC regulation could be triggered by our customers’ transportation decisions.

 

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Regulation of Sales of Natural Gas and NGLs. The price at which we buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. The price at which we sell NGLs is not subject to federal or state regulation.

To the extent that we enter into transportation contracts with natural gas pipelines that are subject to FERC regulation, we are subject to FERC requirements related to the use of such capacity. Any failure on our part to comply with the FERC’s regulations and policies, or with an interstate pipeline’s tariff, could result in the imposition of civil and criminal penalties.

Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC frequently proposes and implements new rules and regulations affecting those segments of the natural gas industry. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation. We cannot predict the ultimate impact of these regulatory changes to our natural gas marketing operations, and we note that some of the FERC’s regulatory changes may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any such FERC action in a manner that is materially different from other natural gas marketers with whom we compete.

Regulation of Gathering Pipelines. Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC under the NGA. We own a number of natural gas pipelines in Texas, Louisiana and West Virginia that we believe meet the traditional tests the FERC uses to establish a pipeline’s status as a gathering pipeline not subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of substantial litigation and varying interpretations, so the classification and regulation of our gathering facilities could be subject to change based on future determinations by the FERC, the courts and Congress. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation.

In Texas, our gathering facilities are subject to regulation by the TRRC under the Texas Utilities Code in the same manner as described above for our intrastate pipeline facilities. Louisiana’s Pipeline Operations Section of the Department of Natural Resources’ Office of Conservation is generally responsible for regulating intrastate pipelines and gathering facilities in Louisiana and has authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities.

Historically, apart from pipeline safety, Louisiana has not acted to exercise this jurisdiction respecting gathering facilities. In Louisiana, our Chalkley System is regulated as an intrastate transporter, and the Louisiana Office of Conservation has determined that our Whiskey Bay System is a gathering system.

We are subject to state ratable take and common purchaser statutes in all of the states in which we operate. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting the right of an owner of gathering facilities to decide with whom it contracts to purchase or transport natural gas.

Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels. For example, the TRRC has approved changes to its regulations governing transportation and gathering services performed by intrastate pipelines and gatherers, which prohibit such entities from unduly discriminating in favor of their affiliates. Many of the producing states have adopted some form of complaint-based regulation that generally

 

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allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination allegations. Our gathering operations could be adversely affected should they be subject in the future to the application of additional or different state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Regulation of Interstate Crude Oil, NGL and Products Pipelines. Interstate common carrier pipeline operations are subject to rate regulation by the FERC under the ICA, the EPAct of 1992, and related rules and orders. The ICA requires that tariff rates for petroleum pipelines be “just and reasonable” and not unduly discriminatory and that such rates and terms and conditions of service be filed with the FERC. This statute also permits interested persons to challenge proposed new or changed rates. The FERC is authorized to suspend the effectiveness of such rates for up to seven months, though rates are typically not suspended for the maximum allowable period. If the FERC finds that the new or changed rate is unlawful, it may require the carrier to pay refunds for the period that the rate was in effect. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.

The FERC generally has not investigated interstate rates on its own initiative when those rates, like those we charge, have not been the subject of a protest or a complaint by a shipper. However, the FERC could investigate our rates at the urging of a third party if the third party is either a current shipper or has a substantial economic interest in the tariff rate level. Although no assurance can be given that the tariff rates charged by us ultimately will be upheld if challenged, management believes that the tariff rates now in effect for our pipelines are within the maximum rates allowed under current FERC policies and precedents.

For many locations served by our product and crude pipelines, we are able to establish negotiated rates. Otherwise, we are permitted to charge cost-based rates, or in many cases, grandfathered rates based on historical charges or settlements with our customers. To the extent we rely on cost-of-service ratemaking to establish or support our rates, the issue of the proper allowance for federal and state income taxes could arise. In July 2016, the United States Court of Appeals for the District of Columbia Circuit issued an opinion in United Airlines, Inc., et al. v. FERC, finding that the FERC had acted arbitrarily and capriciously when it failed to demonstrate that permitting an interstate petroleum products pipeline organized as a master limited partnership, or MLP, to include an income tax allowance in the cost of service underlying its rates, in addition to the discounted cash flow return on equity, would not result in the pipeline partnership owners double recovering their income taxes. The court vacated the FERC’s order and remanded to the FERC to consider mechanisms for demonstrating that there is no double recovery as a result of the income tax allowance. In December 2016, the FERC issued a Notice of Inquiry Regarding the Commission’s Policy for Recovery of Income Tax Costs. The FERC requested comments regarding how to address any double recovery resulting from the Commission’s current income tax allowance and rate of return policies. The comment period with respect to the notice of inquiry ended in April 2017.

In March 2018, the FERC issued a Revised Policy Statement on Treatment of Income Taxes in which the FERC found that an impermissible double recovery results from granting an MLP pipeline both an income tax allowance and a return on equity pursuant to the FERC’s discounted cash flow methodology. The FERC revised its previous policy, stating that it would no longer permit an MLP pipeline to recover an income tax allowance in its cost of service. The FERC stated it will address the application of the United Airlines decision to non-MLP partnership forms as those issues arise in subsequent proceedings. The FERC will also apply the revised Policy Statement and the Tax Cuts and Jobs Act of 2017 to initial crude oil pipeline cost-of-service rates and

 

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cost-of-service rate changes on a going-forward basis under the FERC’s existing ratemaking policies, including cost-of-service rate proceedings resulting from shipper-initiated complaints. In July 2018, the FERC dismissed requests for rehearing and clarification of the March 2018 Revised Policy Statement, but provided further guidance, clarifying that a pass-through entity will not be precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double recovery of investors’ income tax costs. On July 31, 2020, the United States Court of Appeals for the District of Columbia Circuit issued an opinion upholding FERC’s decision denying a separate master limited partnership recovery of an income tax allowance and its decision not to require the master limited partnership to refund accumulated deferred income tax balances. In light of the rehearing order’s clarification regarding individual entities’ ability to argue in support of recovery of an income tax allowance and the court’s subsequent opinion upholding denial of an income tax allowance to a master limited partnership, the impacts the FERC’s policy on the treatment of income taxes may have on the rates an interstate pipeline held in a tax-pass-through entity can charge for the FERC regulated transportation services are unknown at this time. Please see “Item 1A. Risk Factors—Regulatory Matters.”

Effective January 2018, the 2017 Tax Cuts and Jobs Act changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. With the lower tax rate, and as discussed immediately above, the maximum tariff rates allowed by the FERC under its rate base methodology may be impacted by a lower income tax allowance component. Many of our interstate pipelines, such as Tiger, Midcontinent Express and Fayetteville Express, have negotiated market rates that were agreed to by customers in connection with long-term contracts entered into to support the construction of the pipelines. Other systems, such as FGT, Transwestern and Panhandle, have a mix of tariff rate, discount rate, and negotiated rate agreements. In addition, several of these pipelines are covered by approved settlements, pursuant to which rate filings will be made in the future. As such, the timing and impact to these systems of any tax-related policy change is unknown at this time.

The EPAct of 1992 required the FERC to establish a simplified and generally applicable methodology to adjust tariff rates for inflation for interstate petroleum pipelines. As a result, the FERC adopted an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods, or PPI-FG. The FERC’s indexing methodology is subject to review every five years.

In December 2020, FERC issued an order setting the indexed rate at PPI-FG plus 0.78% during the five-year period commencing July 1, 2021 and ending June 30, 2026. That order is subject to rehearing and appeal, and several rehearing requests have been filed and are pending before FERC. The indexing methodology is applicable to existing rates, including grandfathered rates, with the exclusion of market-based rates. A pipeline is not required to raise its rates up to the index ceiling, but it is permitted to do so and rate increases made under the index are presumed to be just and reasonable unless a protesting party can demonstrate that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs. Under the indexing rate methodology, in any year in which the index is negative, pipelines must file to lower their rates if those rates would otherwise be above the rate ceiling.

Finally, in November 2017, the FERC responded to a petition for declaratory order and issued an order that may have significant impacts on the way a marketer of crude oil or petroleum products that is affiliated with an interstate pipeline can price its services if those services include transportation on an affiliate’s interstate pipeline. In particular, the FERC’s November 2017 order prohibits buy/sell arrangements by a marketing affiliate if: (i) the transportation differential applicable to its affiliate’s interstate pipeline transportation service is at a discount to the affiliated pipeline’s filed rate for that service; and (ii) the pipeline affiliate subsidizes the loss. Several parties have requested that the FERC clarify its November 2017 order or, in the alternative, grant rehearing of the November 2017 order. The FERC extended the time frame to respond to such requests in January 2018 but has not yet taken final action. We are unable to predict how the FERC will respond to such requests. Depending on how the FERC responds, it could have an impact on the rates we are permitted to charge.

 

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Regulation of Intrastate Crude Oil, NGL and Products Pipelines. Some of our crude oil, NGL and products pipelines are subject to regulation by the TRRC, the Pennsylvania Public Utility Commission and the Oklahoma Corporation Commission. The operations of our joint venture interests are also subject to regulation in the states in which they operate. The applicable state statutes require that pipeline rates be nondiscriminatory and provide no more than a fair return on the aggregate value of the pipeline property used to render services. State commissions generally have not initiated an investigation of rates or practices of petroleum pipelines in the absence of shipper complaints. Complaints to state agencies have been infrequent and are usually resolved informally. Although management cannot be certain that our intrastate rates ultimately would be upheld if challenged, we believe that, given this history, the tariffs now in effect are not likely to be challenged or, if challenged, are not likely to be ordered to be reduced.

In addition, as noted above, the rates, terms and conditions for shipments of crude oil, NGLs or products on our pipelines could be subject to regulation by the FERC under the ICA and the EPAct of 1992 if the crude oil, NGLs or products are transported in interstate or foreign commerce whether by our pipelines or other means of transportation. Since we do not control the entire transportation path of all crude oil, NGLs or products shipped on our pipelines, FERC regulation could be triggered by our customers’ transportation decisions.

Regulation of Pipeline Safety. Our pipeline operations are subject to regulation by the DOT, through PHMSA, pursuant to the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), with respect to natural gas and the Hazardous Liquids Pipeline Safety Act of 1979, as amended (“HLPSA”), with respect to crude oil, NGLs and condensates. The NGPSA and HLPSA, as amended, govern the design, installation, testing, construction, operation, replacement and management of natural gas as well as crude oil, NGL and condensate pipeline facilities. Pursuant to these acts, PHMSA has promulgated regulations governing pipeline wall thickness, design pressures, maximum operating pressures, pipeline patrols and leak surveys, minimum depth requirements, and emergency procedures, as well as other matters intended to ensure adequate protection for the public and to prevent accidents and failures. Additionally, PHMSA has established a series of rules requiring pipeline operators to develop and implement integrity management programs for certain gas and hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect high consequence areas (“HCAs”), which are areas where a release could have the most significant adverse consequences, including high population areas, certain drinking water sources and unusually sensitive ecological areas. Failure to comply with the pipeline safety laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory, remedial or corrective action obligations, the occurrence of delays in permitting or the performance of projects, or the issuance of injunctions limiting or prohibiting some or all of our operations in the affected area.

The HLPSA and NGPSA have been amended by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”) and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (“2016 Pipeline Safety Act”). The 2011 Pipeline Safety Act increased the penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of safety issues that could result in the adoption of new regulatory requirements by PHMSA for existing pipelines. The 2011 Pipeline Safety Act doubled the maximum administrative fines for safety violations from $100,000 to $200,000 for a single violation and from $1 million to $2 million for a related series of violations, but provided that these maximum penalty caps do not apply to certain civil enforcement actions. In January 2021, PHMSA issued a final rule increasing those maximum civil penalties to $222,504 per day, with a maximum of $2,225,034 for a series of violations. Upon reauthorization of PHMSA, Congress often directs the agency to complete certain rulemakings. For example, in the Consolidated Appropriations Bill for Fiscal Year 2021, Congress reauthorized PHMSA through fiscal year 2023 and directed the agency to move forward with several regulatory actions, including the “Pipeline Safety: Class Location Change Requirements” and the “Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines” proposed rulemakings; Congress has also instructed PHMSA to issue final regulations to require operations of non-rural gas gathering lines and new and existing transmission and distribution pipelines to conduct certain leak detection and repair programs to require facility inspection and maintenance plans to align with those regulations. The timing and scope of such future rulemakings is uncertain.

 

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In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. The states in which we conduct operations typically have developed regulatory programs that parallel the federal regulatory scheme and are applicable to intrastate pipelines. Under such state regulatory programs, states have the authority to conduct pipeline inspections, to investigate accidents and to oversee compliance and enforcement, safety programs and record maintenance and reporting. Congress, PHMSA and individual states may pass or implement additional safety requirements that could result in increased compliance costs for us and other companies in our industry. For example, federal construction, maintenance and inspection standards under the NGPSA that apply to pipelines in relatively populated areas may not apply to gathering lines running through rural regions. However, in October 2019, PHMSA published three final rules that create or expand reporting, inspection, maintenance, and other pipeline safety obligations, including, among other things, extending pipeline integrity assessments to pipelines in certain locations, including newly-defined “Moderate Consequence Areas” (“MCAs”).

In another example of how future legal requirements could result in increased compliance costs, notwithstanding the applicability of the federal OSHA’s Process Safety Management (“PSM”) regulations and the EPA’s Risk Management Planning (“RMP”) requirements at regulated facilities, PHMSA and one or more state regulators, including the TRRC, have in recent years, expanded the scope of their regulatory inspections to include certain in-plant equipment and pipelines found within NGL fractionation facilities and associated storage facilities, in order to assess compliance of such equipment and pipelines with hazardous liquid pipeline safety requirements. To the extent that these actions are pursued by PHMSA, midstream operators of NGL fractionation facilities and associated storage facilities subject to such inspection may be required to make operational changes or modifications at their facilities to meet standards beyond current PSM and RMP requirements, which changes or modifications may result in additional capital costs, possible operational delays and increased costs of operation that, in some instances, may be significant.

Environmental Matters

General. Our operation of processing plants, pipelines and associated facilities, including compression, in connection with the gathering, processing, storage and transmission of natural gas and the storage and transportation of NGLs, crude oil and refined products is subject to stringent U.S. federal, tribal, state and local laws and regulations, including those governing, among other things, air emissions, wastewater discharges, the use, management and disposal of hazardous and nonhazardous materials and wastes, and the cleanup of contamination. Similar or more stringent laws also exist in Canada. Noncompliance with such laws and regulations, or incidents resulting in environmental releases, could cause us to incur substantial costs, penalties, fines and criminal sanctions, third-party claims for personal injury or property damage, capital expenditures to retrofit or upgrade our facilities and programs, or curtailment or cancellation of permits on operations. As with the industry generally, compliance with existing and anticipated environmental laws and regulations increases our overall cost of doing business, including our cost of planning, permitting, constructing and operating our plants, pipelines and other facilities. As a result of these laws and regulations, our construction and operation costs include capital, operating and maintenance cost items necessary to maintain or upgrade our equipment and facilities.

We have implemented procedures designed to ensure that governmental environmental approvals for both existing operations and those under construction are updated as circumstances require. Historically, our environmental compliance costs have not had a material adverse effect on our business, results of operations or financial condition; however, there can be no assurance that such costs will not be material in the future. For example, we cannot be certain that identification of presently unidentified conditions, more rigorous enforcement by regulatory agencies, enactment of more stringent environmental laws and regulations or unanticipated events will not arise in the future and give rise to environmental liabilities that could have a material adverse effect on our business, financial condition or results of operations.

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agencies to review and take action to address any federal regulations promulgated during the prior administration that may be inconsistent with the current administration’s policies. As a result, it is unclear the degree to which certain recent regulatory developments may be modified or rescinded. The executive order also established an Interagency Working Group on the Social Cost of Greenhouse Gases (“Working Group”), which is called on to, among other things, develop methodologies for calculating the “social cost of carbon,” “social cost of nitrous oxide” and “social cost of methane.” Recommendations from the Working Group are due beginning June 1, 2021, and final recommendations no later than January 2022. Further regulation of air emissions, as well as uncertainty regarding the future course of regulation, could eventually reduce the demand for oil and natural gas and, in turn, have a material adverse effect on our business, financial condition or results of operations.

Hazardous Substances and Waste Materials. To a large extent, the environmental laws and regulations affecting our operations relate to the release of hazardous substances and waste materials into soils, groundwater and surface water and include measures to prevent, minimize or remediate contamination of the environment. These laws and regulations generally regulate the generation, storage, treatment, transportation and disposal of hazardous substances and waste materials and may require investigatory and remedial actions at sites where such material has been released or disposed. For example, the Comprehensive Environmental Response, Compensation and Liability Act, as amended, (“CERCLA”), also known as the “Superfund” law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct on certain classes of persons that contributed to a release of a “hazardous substance” into the environment. These persons include the owner and operator of the site where a release occurred and companies that disposed or arranged for the disposal of the hazardous substance that has been released into the environment. Under CERCLA, these persons may be subject to strict, joint and several liability, without regard to fault, for, among other things, the costs of investigating and remediating the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA and comparable state law also authorize the federal EPA, its state counterparts, and, in some instances, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Although “petroleum” as well as natural gas and NGLs are excluded from CERCLA’s definition of a “hazardous substance,” in the course of our ordinary operations we generate wastes that may fall within that definition or that may be subject to other waste disposal laws and regulations. We may be responsible under CERCLA or state laws for all or part of the costs required to clean up sites at which such substances or wastes have been disposed.

We also generate both hazardous and nonhazardous wastes that are subject to requirements of the federal Resource Conservation and Recovery Act, as amended, (“RCRA”) and comparable state statutes. We are not currently required to comply with a substantial portion of the RCRA hazardous waste requirements at many of our facilities because the minimal quantities of hazardous wastes generated there make us subject to less stringent non-hazardous management standards. From time to time, the EPA has considered or third parties have petitioned the agency on the adoption of stricter handling, storage and disposal standards for nonhazardous wastes, including certain wastes associated with the exploration, development and production of crude oil and natural gas. For example, in 2016, the EPA entered into an agreement with several environmental groups to analyze certain Subtitle D criteria regulations pertaining to oil and gas wastes and, if necessary, revise them. In response to the decree, in April 2019, the EPA signed a determination that revision of the regulations is not necessary at this time. It is possible that some wastes generated by us that are currently classified as nonhazardous may in the future be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly disposal requirements, or that the full complement of RCRA standards could be applied to facilities that generate lesser amounts of hazardous waste. Changes such as these examples in applicable regulations may result in a material increase in our capital expenditures or plant operating and maintenance expense and, in the case of our oil and natural gas exploration and production customers, could result in increased operating costs for those customers and a corresponding decrease in demand for our processing, transportation and storage services.

 

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We currently own or lease sites that have been used over the years by prior owners and lessees and by us for various activities related to gathering, processing, storage and transmission of natural gas, NGLs, crude oil and refined products. Waste disposal practices within the oil and gas industry have improved over the years with the passage and implementation of various environmental laws and regulations. Nevertheless, some hydrocarbons and wastes have been disposed of or otherwise released on or under various sites during the operating history of those facilities that are now owned or leased by us. Notwithstanding the possibility that these releases may have occurred during the ownership or operation of these assets by others, these sites may be subject to CERCLA, RCRA and comparable state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or contamination (including soil and groundwater contamination) or to prevent the migration of contamination.

As of December 31, 2020 and 2019, accruals of $306 million and $320 million, respectively, were recorded in our consolidated balance sheets as accrued and other current liabilities and other non-current liabilities to cover estimated material environmental liabilities.

The Partnership is subject to extensive and frequently changing federal, tribal, state and local laws and regulations, including those relating to the discharge of materials into the environment or that otherwise relate to the protection of the environment, waste management and the characteristics and composition of fuels. These laws and regulations require environmental assessment and remediation efforts at many of ETC Sunoco’s facilities and at formerly owned or third-party sites. Accruals for these environmental remediation activities amounted to $247 million and $252 million at December 31, 2020 and 2019, respectively, which is included in the total accruals above. These legacy sites that are subject to environmental assessments include formerly owned terminals and other logistics assets, retail sites that are no longer operated by ETC Sunoco, closed and/or sold refineries and other formerly owned sites. We have established a wholly-owned captive insurance company for these legacy sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company. As of December 31, 2020, the captive insurance company held $189 million of cash and investments.

The Partnership’s accrual for environmental remediation activities reflects anticipated work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. The accrual for known claims is undiscounted and is based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. It is often extremely difficult to develop reasonable estimates of future site remediation costs due to changing regulations, changing technologies and their associated costs, and changes in the economic environment. Engineering studies, historical experience and other factors are used to identify and evaluate remediation alternatives and their related costs in determining the estimated accruals for environmental remediation activities.

Under various environmental laws, including the RCRA, the Partnership has initiated corrective remedial action at certain of its facilities, formerly owned facilities and at certain third-party sites. At the Partnership’s major manufacturing facilities, we have typically assumed continued industrial use and a containment/remediation strategy focused on eliminating unacceptable risks to human health or the environment. The remediation accruals for these sites reflect that strategy. Accruals include amounts designed to prevent or mitigate off-site migration and to contain the impact on the facility property, as well as to address known, discrete areas requiring remediation within the plants. Remedial activities include, for example, closure of RCRA waste management units, recovery of hydrocarbons, handling of impacted soil, mitigation of surface water impacts and prevention or mitigation of off-site migration. A change in this approach as a result of changing the intended use of a property or a sale to a third party could result in a comparatively higher cost remediation strategy in the future.

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group of similar items (for example, service station sites) in determining the amount of probable loss accrual to be recorded. The estimates of environmental remediation costs also frequently involve evaluation of a range of estimates. In many cases, it is difficult to determine that one point in the range of loss estimates is more likely than any other. In these situations, existing accounting guidance allows us the minimum amount of the range to accrue. Accordingly, the low end of the range often represents the amount of loss which has been recorded. The Partnership’s consolidated balance sheet reflected $306 million in environmental accruals as of December 31, 2020.

In summary, total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the nature of operations at each site, the technology available and needed to meet the various existing legal requirements, the nature and terms of cost-sharing arrangements with other potentially responsible parties, the availability of insurance coverage, the nature and extent of future environmental laws and regulations, inflation rates, terms of consent agreements or remediation permits with regulatory agencies and the determination of the Partnership’s liability at the sites, if any, in light of the number, participation level and financial viability of the other parties. The recognition of additional losses, if and when they were to occur, would likely extend over many years, but management can provide no assurance that it would be over many years. If changes in environmental laws or regulations occur or the assumptions used to estimate losses at multiple sites are adjusted, such changes could materially and adversely impact multiple facilities, formerly owned facilities and third-party sites at the same time. As a result, from time to time, significant charges against income for environmental remediation may occur. And while management does not believe that any such charges would have a material adverse impact on the Partnership’s consolidated financial position, it can provide no assurance.

Transwestern conducts soil and groundwater remediation at a number of its facilities. Some of the cleanup activities include remediation of several compressor sites on the Transwestern system for contamination by PCBs, and the costs of this work are not eligible for recovery in rates. The total accrued future estimated cost of remediation activities expected to continue through 2025 is $4 million, which is included in the total environmental accruals mentioned above. Transwestern received FERC approval for rate recovery of projected soil and groundwater remediation costs not related to PCBs effective April 1, 2007. Transwestern, as part of ongoing arrangements with customers, continues to incur costs associated with containing and removing potential PCB contamination. Future costs cannot be reasonably estimated because remediation activities are undertaken as potential claims are made by customers and former customers. Such future costs are not expected to have a material impact on our financial position, results of operations or cash flows, but management can provide no assurance.

Air Emissions. Our operations are subject to the federal Clean Air Act, as amended, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our processing plants, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities, such as our processing plants and compression facilities, expected to produce air emissions or to result in the increase of existing air emissions, that we obtain and strictly comply with air permits containing various emissions and operational limitations, or that we utilize specific emission control technologies to limit emissions. We will incur capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. In addition, our processing plants, pipelines and compression facilities are subject to increasingly stringent regulations, including regulations that require the installation of control technology or the implementation of work practices to control hazardous air pollutants. Moreover, the Clean Air Act requires an operating permit for major sources of emissions and this requirement applies to some of our facilities. Historically, our costs for compliance with existing Clean Air Act and comparable state law requirements have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future. The EPA and state agencies are often considering, proposing or finalizing new regulations that could impact our existing operations and the costs and

 

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timing of new infrastructure development. For example, in October 2015, the EPA published a final rule under the Clean Air Act, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone to 70 parts per billion for the 8-hour primary and secondary ozone standards. The EPA completed attainment/non-attainment designations in 2018, and states with moderate or high non-attainment areas must submit state implementation plans to the EPA by October 2021. By law, the EPA must review each NAAQS every five years. In December 2020, the EPA announced that it was retaining without revision the 2015 NAAQS for ozone. However, as mentioned above, in January 2021, the Biden administration issued an executive order directing federal agencies to review and take action to address any federal regulations or similar agency actions during the prior administration that may be inconsistent with the current administration’s stated priorities. The EPA was specifically ordered to, among other things, propose a Federal Implementation Plan for ozone standards for California, Connecticut, New York, Pennsylvania and Texas by January 2022. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Also, states are expected to implement more stringent requirements as a result of this new final rule, which could apply to our customers’ operations. Compliance with this or other new regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact our business.

Clean Water Act. The Federal Water Pollution Control Act of 1972, as amended, (“Clean Water Act”) and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including hydrocarbon-bearing wastes, into state waters and waters of the United States. Pursuant to the Clean Water Act and similar state laws, a National Pollutant Discharge Elimination System, or state permit, or both, must be obtained to discharge pollutants into federal and state waters. In addition, the Clean Water Act and comparable state laws require that individual permits or coverage under general permits be obtained by subject facilities for discharges of storm water runoff. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. In June 2015, the EPA and the USACE published a final rule attempting to clarify the federal jurisdictional reach over “waters of the United States” (“WOTUS”), but legal challenges to this rule followed. In January 2020, a new “waters of the United States” rule was finalized to replace the June 2015 rule, defining the following four categories of waters as WOTUS: traditional navigable waters and territorial seas; perennial and intermittent tributaries to those waters; lakes, ponds and impoundments of jurisdictional waters; and wetlands adjacent to jurisdictional waters. However, legal challenges to this rulemaking are ongoing, and it is possible that the Biden Administration could propose a broader interpretation of WOTUS. As a result of these developments, the scope of jurisdiction under the Clean Water Act is uncertain at this time, but to the extent any rule expands the scope of the Clean Water Act’s jurisdiction, our operations as well as our exploration and production customers’ drilling programs could incur increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.

Additionally, for over 35 years, the USACE has authorized construction, maintenance, and repair of pipelines under a streamlined Nationwide Permit (“NWP”) program. From time to time, environmental groups have challenged the NWP program, and, in April 2020, the U.S. District Court for the District of Montana determined that NWP 12 failed to comply with consultation requirements under the federal Endangered Species Act. The district court vacated NWP 12 and enjoined the issuance of new authorizations for oil and gas pipeline projects under the permit. While the district court’s order has subsequently been limited pending appeal, and NWP 12 authorizations remain available for certain oil and gas pipeline projects, we cannot predict the ultimate outcome of this case and its impacts on the NWP program. Additionally, in response to the vacatur, the Corps has announced a reissuance of NWP 13 for oil and natural gas pipeline activities, including certain revisions to the conditions for the use of NWP 12; however, the rulemaking may be subject to litigation or to further revision under the Biden Administration. While the full extent and impact of the vacatur is unclear at this time, we could face significant delays and financial costs if we must obtain individual permit coverage from USACE for our projects.

 

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Spills. Our operations can result in the discharge of regulated substances, including NGLs, crude oil or other products. The Clean Water Act, as amended by the federal Oil Pollution Act of 1990, as amended, (“OPA”), and comparable state laws impose restrictions and strict controls regarding the discharge of regulated substances into state waters or waters of the United States. The Clean Water Act and comparable state laws can impose substantial administrative, civil and criminal penalties for non-compliance including spills and other non-authorized discharges. The OPA subjects owners of covered facilities to strict joint and potentially unlimited liability for removal costs and other consequences of a release of oil, where the release is into navigable waters, along shorelines or in the exclusive economic zone of the United States. Spill prevention control and countermeasure requirements of the Clean Water Act and some state laws require that containment dikes and similar structures be installed to help prevent the impact on navigable waters in the event of a release of oil. PHMSA, the EPA, or various state regulatory agencies, has approved our oil spill emergency response plans that are to be used in the event of a spill incident.

In addition, some states maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Our management believes that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our results of operations, financial position or expected cash flows.

Endangered Species. The Endangered Species Act, as amended, restricts activities that may affect endangered or threatened species or their habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We may operate in areas that are currently designated as a habitat for endangered or threatened species or where the discovery of previously unidentified endangered species, or the designation of additional species as endangered or threatened may occur in which event such one or more developments could cause us to incur additional costs, to develop habitat conservation plans, to become subject to expansion or operating restrictions, or bans in the affected areas. Moreover, such designation of previously unprotected species as threatened or endangered in areas where our oil and natural gas exploration and production customers operate could cause our customers to incur increased costs arising from species protection measures and could result in delays or limitations in our customers’ performance of operations, which could reduce demand for our services.

Climate Change. Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of greenhouse gases (“GHGs”). These efforts have included consideration of cap-and-trade programs, carbon taxes and GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. In the United States, no comprehensive climate change legislation has been implemented at the federal level to date. However, Canada has implemented a federal carbon pricing regime, and, in the United States, President Biden has announced that he intends to pursue substantial reductions in greenhouse gas emissions, particularly from the oil and gas sector. For example, on January 27, 2021, President Biden signed an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, an increase in the production of offshore wind energy, and an increased emphasis on climate-related risks across government agencies and economic sectors. Additionally, the EPA has adopted rules under authority of the Clean Air Act that, among other things, establish Potential for Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal, or criteria, pollutant emissions, which reviews could require securing PSD permits at covered facilities emitting GHGs and meeting “best available control technology” standards for those GHG emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, including, among others, onshore processing, transmission, storage and distribution facilities. In October 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting facilities and blowdowns of natural gas transmission pipelines.

 

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Federal agencies also have begun directly regulating GHG emissions, such as methane, from oil and natural gas operations. In June 2016, the EPA published New Source Performance Standards (“NSPS”), known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound (“VOC”) emissions. These Subpart OOOOa standards expand previously issued NSPS published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices, requiring additional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations. In September 2020, the EPA removed natural gas transmission and storage operations from this sector and rescinded the methane-specific requirements of the rule for production and processing facilities. However, President Biden has signed an executive order calling for the suspension, revision, or rescission of the September 2020 rule and the reinstatement or issuance of methane emissions standards for new, modified, and existing oil and has facilities, including the transmission and storage segments. Methane emission standards imposed on the oil and gas sector could result in increased costs to our operations as well as result in delays or curtailment in such operations, which costs, delays or curtailment could adversely affect our business. Several states have also adopted, or are considering adopting, regulations related to GHG emissions, some of which are more stringent than those implemented by the federal government. Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France in signing the “Paris Agreement,” a treaty that requires member countries to submit individually-determined, non-binding emission reduction goals every five years beginning in 2020. Although the United States has withdrawn from this agreement, President Biden has signed executive orders recommitting the United States to the Paris Agreement and calling for the federal government to formulate the United States’ emissions reduction goal. However, the impacts of these orders are unclear at this time.

The January 2021 climate change executive order also directed the Secretary of the Interior to pause new oil and natural gas leasing on public lands or in offshore waters pending completion of a comprehensive review of the federal permitting and leasing practices, consider whether to adjust royalties associated with coal, oil, and gas resources extracted from public lands and offshore waters, or take other appropriate action, to account for corresponding climate costs. The executive order also directed the federal government to identify “fossil fuel subsidies” to take steps to ensure that, to the extent consistent with applicable law, federal funding is not directly subsidizing fossil fuels. As noted above, a separate executive order issued in January 2021 established a Working Group that is called on to, among other things, develop methodologies for calculating the “social cost of carbon,” “social cost of nitrous oxide” and “social cost of methane.” Recommendations from the Working Group are due beginning June 1, 2021, and final recommendations no later than January 2022.

The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our services, results of operations, and cash flows. Litigation risks are also increasing, as several oil and gas companies have been sued for allegedly causing climate-related damages due to their production and sale of fossil fuel products or for allegedly being aware of the impacts of climate change for some time but failing to adequately disclose such risks to their investors or customers. There is also a risk that financial institutions could be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. For example, recently, the Federal Reserve announced that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Ultimately, this could make it more difficult to secure funding for exploration and production or midstream activities. Finally, most scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events that could have an adverse effect on our assets.

If such effects were to occur, our operations could be adversely affected in various ways, including damages to our facilities from powerful winds or rising waters, or increased costs for insurance. Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for our NGLs and

 

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natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we transport, and thus demand for our services. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our products could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.

Employee Health and Safety. We are subject to the requirements of the federal OSHA and comparable state laws that regulate the protection of the health and safety of workers. In addition, the Occupational Safety and Health Administration’s hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. Historically, our costs for OSHA required activities, including general industry standards, recordkeeping requirements, and monitoring of occupational exposure to regulated substances, have not had a material adverse effect on our results of operations but there is no assurance that such costs will not be material in the future.

Natural Resource Reviews. The National Environmental Policy Act (“NEPA”) provides for an environmental impact assessment process in connection with certain projects that involve federal lands or require approvals by federal agencies. The NEPA process implicates a number of other environmental laws and regulations, including the Endangered Species Act, Migratory Bird Treaty Act, Rivers and Harbors Act, Clean Water Act, Bald and Golden Eagle Protection Act, Fish and Wildlife Coordination Act, Marine Mammal Protection Act and National Historic Preservation Act, often requiring coordination with numerous governmental authorities. The NEPA review process can be lengthy and subjective, resulting in delays in obtaining federal approvals for projects. Our projects that are subject to the NEPA can include pipeline construction and pipeline integrity projects that involve federal lands or require approvals by federal agencies. More stringent environmental impact analyses under or third-party challenges with respect to the sufficiency of any environmental impact statement or assessment prepared pursuant to NEPA could adversely impact such projects in the form of delays or increased compliance and mitigations costs.

Indigenous Protections. Part of our operations cross land that has historically been apportioned to various Native American/First Nations tribes (“Indigenous Peoples”), who may exercise significant jurisdiction and sovereignty over their lands. Indigenous Peoples may also have certain treaty rights and rights to consultation on projects that may affect such lands. Our operations may be impacted to the extent these tribal governments are found to have and choose to act upon such jurisdiction over lands where we operate. For example, in 2020, the Supreme Court ruled in McGirt v. Oklahoma that the Muscogee (Creek) Nation reservation in Eastern Oklahoma has not been disestablished. Although the court’s ruling indicates that it is limited to criminal law, as applied within the Muscogee (Creek) Nation reservation, the ruling may have significant potential implications for civil law, both in the Muscogee (Creek) Nation reservation and other reservations that may similarly be found to not have been disestablished. State courts in Oklahoma have applied the analysis in McGirt in ruling that the Cherokee, Chickasaw, Seminole, and Choctaw reservations likewise had not been disestablished.

On October 1, 2020, the EPA granted approval to the State of Oklahoma under Section 10211(a) of the Safe, Accountable, Flexible, Efficient Transportation Equity Act of 2005 (the “SAFETE Act”) to administer all of the State’s existing EPA-approved regulatory programs to Indian Country within the state except: Indian allotments to which Indians titles have not been extinguished; lands that are held in trust by the United States on behalf of any Indian or Tribe; lands that are owned in fee by any Tribe where title was acquired through a treaty with the United States to which such tribe is a party and that have never been allotted to any citizen or member of such Tribe. The approval extends the State’s authority for existing EPA-approved regulatory programs to all lands within the State to which the State applied such programs prior to the U.S. Supreme Court’s ruling in McGirt. However, several Tribes have expressed dissatisfaction with the consultation process performed in relation to this approval, and it is possible that EPA’s approval under the SAFETE Act could be challenged. Additionally, the

 

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SAFETE Act provides that any Tribe in Oklahoma may seek “Treatment as a State” by the EPA, and it is possible that one or more of the Tribes in Oklahoma may seek such an approval from EPA. At this time, we cannot predict how these jurisdictional issues may ultimately be resolved.

Human Capital Management

As of December 31, 2020, ETO and its consolidated subsidiaries employed an aggregate of 11,421 employees, 1,217 of which are represented by labor unions. We believe that our relations with our employees are good.

Our employees are our greatest asset, and we seek to attract and retain top talent by fostering a culture that is guided by our core values in a manner that respects all people and cultures, promotes safety, and focuses on the protection of public health and the environment.

Ethics and Values. We are committed to operating our business in a manner that honors and respects all people and the communities in which we do business. We recognize that people are our most valued resource, and we are committed to hiring and investing in employees who strive for excellence and live by our core values: working safely, corporate stewardship, ethics and integrity, entrepreneurial mindset, our people, excellence and results, and social responsibility. We value our employees for what they bring to our organization by embracing those from all backgrounds, cultures, and experiences. We also believe that the keys to our successes have been the cultivation of an atmosphere of inclusion and respect within our family of partnerships and sustaining organizations that promote diversity and provide support across all communities. These are the principles upon which we build and strengthen relationships among our people, our stakeholders, and those within the communities we support.

Respecting All People and All Cultures. We believe strict adherence to our Code of Business Conduct and Ethics is not only right, but is in the best interest of the Partnership, its Unitholders, its customers, and the industry in general. In all instances, the policies of the Partnership require that the business of the Partnership be conducted in a lawful and ethical manner. Every employee acting on behalf of the Partnership must adhere to these policies. Please refer to “Item 10. Directors, Executive Officers and Corporate Governance” for additional information on our Code of Business Conduct and Ethics.

Commitment to Protecting Public Health, Safety and the Environment. Protecting public health and the environment is the primary initiative for our environmental management teams, both in the construction and operation of our assets. These teams consist of environmental engineers, scientists and geologists focused on ensuring that our environmental management systems responsibly and efficiently reduce emissions, protect and preserve the land, water and air around us, and remain in compliance with all applicable regulations. Our environmental, health and safety department’s more than 100 environmental and safety professionals provide environmental and safety training to our field representatives. This group also assists others throughout the organization in identifying continuous training for personnel, including the training that is required by applicable laws, regulations, standards, and permit conditions. Our safety standards and expectations are communicated to all employees and contractors with the expectation that each individual has the obligation to make safety the highest priority. Our safety culture aims to promote an open environment for discovering, resolving, and sharing safety challenges. We strive to eliminate unwanted safety events through a comprehensive process that promotes leadership, employee involvement, communication, personal responsibility to comply with standard operating procedures and regulatory requirements, effective risk reduction processes, maintaining clean facilities, contractor safety, and personal wellness. Energy Transfer’s goal is operational excellence, which means an injury- and incident-free workplace. To achieve this, we strive to hire and maintain the most qualified and dedicated workforce in the industry and make safety and safety accountability part of our daily operations. The OSHA Total Reportable Incident Rate (“TRIR”) is a key performance indicator by which we evaluate the success of our safety programs. TRIR provides companies with a look at their safety record performance for the year by calculating the number of recordable incidents per 200,000 hours worked. Out of more than 17 million hours worked, our TRIR was 0.87 for 2020, compared to 0.94 in 2019. We believe the Partnership’s low TRIR speaks to the investment in and focus on safety and environmental compliance as well as the reliability of our assets.

 

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Regarding COVID-19, as an essential business providing critical energy infrastructure, the safety of our employees and the continued operation of our assets are our top priorities, and we will continue to operate in accordance with federal, state and local health guidelines and safety protocols. We have implemented several new policies and provided employees with training to help maintain the health and safety of our workforce.

For additional information on our Human Capital initiatives, please see our Community Engagement Report available on our website at http://www.energytransfer.com/corporate-responsibility/. Information contained on our website is not part of this report.

SEC Reporting

We file or furnish annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any related amendments and supplements thereto with the SEC. From time to time, we may also file registration and related statements pertaining to equity or debt offerings. The SEC maintains an Internet website at http://www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.

We provide electronic access, free of charge, to our periodic and current reports, and amendments to these reports, on our internet website located at http://www.energytransfer.com. These reports are available on our website as soon as reasonably practicable after we electronically file such materials with the SEC. Information contained on our website is not part of this report.

 

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ITEM 1A. RISK FACTORS

In addition to risks and uncertainties in the ordinary course of business that are common to all businesses, important factors that are specific to our structure as a limited partnership, our industry and our company could materially impact our future performance and results of operations. We have provided below a list of these risk factors that should be reviewed when considering an investment in our securities. Panhandle, Sunoco LP and USAC file Annual Reports on Form 10-K that include risk factors that can be reviewed for further information. The risk factors set forth below, and those included in Panhandle’s, Sunoco LP’s and USAC’s Annual Reports, are not all the risks we face, and other factors currently considered immaterial or unknown to us may impact our future operations.

Risk Relating to the Partnership’s Business

Results of Operations and Financial Condition

Income from our midstream, transportation, terminalling and storage operations is exposed to risks due to fluctuations in the demand for and price of natural gas, NGLs, crude oil and refined products that are beyond our control.

The prices for natural gas, NGLs, crude oil and refined products reflect market demand that fluctuates with changes in global and United States economic conditions and other factors, including:

 

   

the level of domestic natural gas, NGL, refined products and oil production;

 

   

the level of natural gas, NGL, refined products and oil imports and exports, including liquefied natural gas;

 

   

actions taken by natural gas and oil producing nations;

 

   

instability or other events affecting natural gas and oil producing nations;

 

   

the impact of weather, public health crises such as pandemics (including COVID-19), and other events of nature on the demand for natural gas, NGLs, refined products and oil;

 

   

the availability of storage, terminal and transportation systems, and refining, processing and treating facilities;

 

   

the price, availability and marketing of competitive fuels;

 

   

the demand for electricity;

 

   

activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of oil and natural gas and related products;

 

   

the cost of capital needed to maintain or increase production levels and to construct and expand facilities;

 

   

the impact of energy conservation and fuel efficiency efforts; and

 

   

the extent of governmental regulations, taxation, fees and duties.

In the past, the prices of natural gas, NGLs, refined products and oil have been extremely volatile, and we expect this volatility to continue.

Any loss of business from existing customers or our inability to attract new customers due to a decline in demand for natural gas, NGLs, refined products or oil could have a material adverse effect on our revenues and results of operations. In addition, significant price fluctuations for natural gas, NGL, refined products and oil commodities could materially affect our profitability.

 

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The outbreak of COVID-19 and recent geopolitical developments in the crude oil market could adversely impact our business, financial condition and results of operations.

On January 30, 2020, the World Health Organization (“WHO”) announced a global health emergency because of a new strain of coronavirus known as COVID-19 due to the risks it imposes on the international community as the virus spreads globally. In March 2020, the WHO classified the COVID-19 outbreak as a pandemic, based on the rapid increase in exposure globally. The global spread of COVID-19 caused a significant decline in economic activity and a reduced demand for goods and services, particularly in the energy industry, due to reduced operations and/or closures of businesses, “shelter in place” and other similar requirements imposed by government authorities, or other actions voluntarily undertaken by individuals and businesses concerned about exposure to COVID-19. The extent to which the COVID-19 pandemic continues to impact our business, operations and financial results depends on numerous evolving factors that we cannot accurately predict, including: the duration and scope of the pandemic; governmental, business and individuals’ actions taken in response to the pandemic and the associated impact on economic activity; the effect on the level of demand for natural gas, NGLs, refined products and/or crude oil; our ability to procure materials and services from third parties that are necessary for the operation of our business; our ability to provide our services, including as a result of travel restrictions on our employees and employees of third parties that we utilize in connection with our services; the potential for key executives or employees to fall ill with COVID-19; and the ability of our customers to pay for our services if their businesses suffer as a result of the pandemic.

In addition, policy disputes between the Organization of Petroleum Exporting Countries and Russia in the first quarter of 2020 resulted in Saudi Arabia significantly discounting the price of its crude oil, as well as Saudi Arabia and Russia significantly increasing the amount of crude oil they produce. These actions led to significant volatility in crude oil prices. More specifically, the spot price for West Texas Intermediate (WTI) crude oil, for physical delivery at Cushing, Oklahoma, decreased from $63.27 per barrel on January 6, 2020 to $(36.98) per barrel on April 20, 2020 and increased to more than $60 per barrel in February 2021.

Reduced demand for natural gas, NGLs, refined products and/or crude oil caused by the COVID-19 pandemic and a decline in WTI crude oil prices caused by the actions of foreign oil-producing nations or other market factors may result in the shut-in of production from U.S. oil and gas wells, which in turn may result in decreased utilization of our midstream services related to crude oil, NGLs, refined products and natural gas. In addition, reduced demand for crude oil has resulted in an increase in worldwide crude oil storage inventories, which limits our options for end-markets for the products we transport.

The factors discussed above could have a material adverse effect on our business, results of operations and financial condition. In addition, significant price fluctuations for natural gas, NGLs, refined products and oil commodities could materially affect the value of our inventory, as well as the linefill and tank bottoms that we account for as non-current assets. We may be forced to delay some of our capital projects and our customers, who may be in financial distress, may slow down decision-making, delay planned projects or seek to renegotiate or terminate agreements with us. To the extent our counterparties are successful, we may not be able to obtain new contract terms that are favorable to us or to replace contracts that are terminated.

Further, the effects of the pandemic and geopolitical developments have market impacts, such that additional capital may be more difficult for us to obtain or available only on terms less favorable to us. Our inability to fund capital expenditures could have a material impact on our results of operations.

At this time, we cannot estimate the magnitude and duration of potential social, economic and labor instability as a direct result of COVID-19, or of potential industry disruption as a direct result of geopolitical developments in the oil market. Should any of these potential impacts continue for an extended period of time, it will have a negative impact on the demand for our services and an adverse effect on our financial position and results of operations. To the extent these factors adversely affect our business and financial results, they may also have the effect of heightening many of the other risks described in this “Risk Factors” section, as well as the risks

 

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discussed or referenced in any applicable prospectus supplement, including in the documents we incorporate by reference herein or therein, such as those relating to our indebtedness, our need to generate sufficient cash flows to service our indebtedness and our ability to comply with the covenants contained in the agreements that govern our indebtedness.

An impairment of goodwill and intangible assets could reduce our earnings.

As of December 31, 2020, our consolidated balance sheet reflected $2.39 billion of goodwill and $5.75 billion of intangible assets. Goodwill is recorded when the purchase price of a business exceeds the fair value of the tangible and separately measurable intangible net assets. Accounting principles generally accepted in the United States require us to test goodwill for impairment on an annual basis or when events or circumstances occur, indicating that goodwill might be impaired. Long-lived assets such as intangible assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If we determine that any of our goodwill or intangible assets were impaired, we would be required to take an immediate charge to earnings with a correlative effect on partners’ capital and balance sheet leverage as measured by debt to total capitalization.

During the year ended December 31, 2020, the Partnership recognized goodwill impairments of $483 million related to our midstream operations, $1.28 billion related to our crude operations, $198 million related to our all other operations, $10 million related to our intrastate operations and $226 million related to our interstate operations, primarily due to decreases in projected future cash flow as a result of the overall market demand decline. In addition, USAC recognized a goodwill impairment of $619 million during the year ended December 31, 2020, which is included in the Partnership’s consolidated results of operations.

We depend on certain key producers for our supply of natural gas and the loss of any of these key producers could adversely affect our financial results.

Certain producers who are connected to our systems represent a material source of our supply of natural gas. We are not the only option available to these producers for disposition of the natural gas they produce. To the extent that these and other producers may reduce the volumes of natural gas that they supply us, we would be adversely affected unless we were able to acquire comparable supplies of natural gas from other producers.

Our intrastate transportation and storage and interstate transportation and storage operations depend on key customers to transport natural gas through our pipelines and the pipelines of our joint ventures.

During 2020, Trafigura US Inc. accounted for approximately 29% of our intrastate transportation and storage revenues. During 2020, Shell, Ascent Resources LLC and Antero Resources Corporation collectively accounted for 32% of our interstate transportation and storage revenues.

Our joint ventures, FEP and Citrus, also depend on key customers for the transport of natural gas through their pipelines. FEP has a small number of major shippers with one shipper accounting for approximately 64% of its revenues in 2020 while Citrus has long-term agreements with its top two customers which accounted for 54% of its 2020 revenue. For the Trans-Pecos and Comanche Trail pipelines, CFE International LLC is the primary shipper.

The failure of the major shippers on our and our joint ventures’ intrastate and interstate transportation and storage pipelines to fulfill their contractual obligations could have a material adverse effect on our cash flow and results of operations if we or our joint ventures were unable to replace these customers under arrangements that provide similar economic benefits as these existing contracts.

 

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We may be unable to retain or replace existing midstream, transportation, terminalling and storage customers or volumes due to declining demand or increased competition in crude oil, refined products, natural gas and NGL markets, which would reduce our revenues and limit our future profitability.

The retention or replacement of existing customers and the volume of services that we provide at rates sufficient to maintain or increase current revenues and cash flows depends on a number of factors beyond our control, including the price of and demand for crude oil, refined products, natural gas and NGLs in the markets we serve and competition from other service providers.

A significant portion of our sales of natural gas are to industrial customers and utilities. As a consequence of the volatility of natural gas prices and increased competition in the industry and other factors, industrial customers, utilities and other gas customers are increasingly reluctant to enter into long-term purchase contracts. Many customers purchase natural gas from more than one supplier and have the ability to change suppliers at any time. Some of these customers also have the ability to switch between gas and alternate fuels in response to relative price fluctuations in the market. Because there are many companies of greatly varying size and financial capacity that compete with us in the marketing of natural gas, we often compete in natural gas sales markets primarily on the basis of price.

We also receive a substantial portion of our revenues by providing natural gas gathering, processing, treating, transportation and storage services. While a substantial portion of our services are sold under long-term contracts for reserved service, we also provide service on an unreserved or short-term basis. Demand for our services may be substantially reduced due to changing market prices. Declining prices may result in lower rates of natural gas production resulting in less use of services, while rising prices may diminish consumer demand and also limit the use of services. In addition, our competitors may attract our customers’ business. If demand declines or competition increases, we may not be able to sustain existing levels of unreserved service or renew or extend long-term contracts as they expire or we may reduce our rates to meet competitive pressures.

Revenue from our NGL transportation systems and refined products storage is also exposed to risks due to fluctuations in demand for transportation and storage service as a result of unfavorable commodity prices, competition from nearby pipelines, and other factors. We receive substantially all of our transportation revenues through dedicated contracts under which the customer agrees to deliver the total output from particular processing plants that are connected only to our transportation system. Reduction in demand for natural gas or NGLs due to unfavorable prices or other factors, however, may result lower rates of production under dedicated contracts and lower demand for our services. In addition, our refined products storage revenues are primarily derived from fixed capacity arrangements between us and our customers, a portion of our revenue is derived from fungible storage and throughput arrangements, under which our revenue is more dependent upon demand for storage from our customers.

The volume of crude oil and refined products transported through our crude oil and refined products pipelines and terminal facilities depends on the availability of attractively priced crude oil and refined products in the areas serviced by our assets. A period of sustained price reductions for crude oil or refined products could lead to a decline in drilling activity, production and refining of crude oil or import levels in these areas. A period of sustained increases in the price of crude oil or refined products supplied from or delivered to any of these areas could materially reduce demand for crude oil or refined products in these areas. In either case, the volumes of crude oil or refined products transported in our crude oil and refined products pipelines and terminal facilities could decline.

The loss of existing customers by our midstream, transportation, terminalling and storage facilities or a reduction in the volume of the services our customers purchase from us, or our inability to attract new customers and service volumes would negatively affect our revenues, be detrimental to our growth, and adversely affect our results of operations.

 

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We and our subsidiaries, including Sunoco LP and USA Compression Partners, LP (“USAC”), are exposed to the credit risk of our customers and derivative counterparties, and an increase in the nonpayment and nonperformance by our customers or derivative counterparties could reduce our ability to make distributions to our unitholders.

We, Sunoco LP and USAC are subject to risks of loss resulting from nonpayment or nonperformance by our, Sunoco LP’s and USAC’s customers. Commodity price volatility and/or the tightening of credit in the financial markets may make it more difficult for customers to obtain financing and, depending on the degree to which this occurs, there may be a material increase in the nonpayment and nonperformance by our customers. In addition, our risk management activities are subject to the risks that a counterparty may not perform its obligation under the applicable derivative instrument, the terms of the derivative instruments are imperfect, and our risk management policies and procedures are not properly followed. Any material nonpayment or nonperformance by our customers or our derivative counterparties could reduce our ability to make distributions to our unitholders. Any substantial increase in the nonpayment and nonperformance by our customers could have a material effect on our, Sunoco LP’s and USAC’s results of operations and operating cash flows.

Due to recent market disruptions involving the COVID-19 pandemic, some of our counterparties may be forced to file for bankruptcy protection, in which case our existing contracts with those counterparties may be rejected by the bankruptcy court. Following the request of one of our FERC-regulated natural pipelines, the FERC commenced an investigation into whether the public interest requires abrogation or modification of a firm transportation agreement and an interruptible transportation agreement with one of our shippers. By order dated November 9, 2020, FERC held that the record did not support a finding that the public interest presently requires abrogation or modification of the subject firm transportation agreement. However, actual determination regarding the contract will depend upon further action by the counterparty and any further bankruptcy-related proceedings. If a counterparty is successful in rejecting an existing contract in bankruptcy, we expect that we would attempt to negotiate replacement contracts with those counterparties and, depending on the availability of alternatives to our services, these contracts may have terms that are less favorable to us than the contracts rejected in bankruptcy court.

The profitability of certain activities in our natural gas gathering, processing, transportation and storage operations are largely dependent upon natural gas commodity prices, price spreads between two or more physical locations and market demand for natural gas and NGLs.

For a portion of the natural gas gathered on our systems, we purchase natural gas from producers at the wellhead and then gather and deliver the natural gas to pipelines where we typically resell the natural gas under various arrangements, including sales at index prices. Generally, the gross margins we realize under these arrangements decrease in periods of low natural gas prices.

We also enter into percent-of-proceeds arrangements, keep-whole arrangements, and processing fee agreements pursuant to which we agree to gather and process natural gas received from the producers.

Under percent-of-proceeds arrangements, we generally sell the residue gas and NGLs at market prices and remit to the producers an agreed upon percentage of the proceeds based on an index price. In other cases, instead of remitting cash payments to the producer, we deliver an agreed upon percentage of the residue gas and NGL volumes to the producer and sell the volumes we keep to third parties at market prices. Under these arrangements, our revenues and gross margins decline when natural gas prices and NGL prices decrease. Accordingly, a decrease in the price of natural gas or NGLs could have an adverse effect on our revenues and results of operations.

Under keep-whole arrangements, we generally sell the NGLs produced from our gathering and processing operations at market prices. Because the extraction of the NGLs from the natural gas during processing reduces the Btu content of the natural gas, we must either purchase natural gas at market prices for return to producers or make a cash payment to producers equal to the value of this natural gas. Under these arrangements, our gross margins generally decrease when the price of natural gas increases relative to the price of NGLs.

 

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When we process the gas for a fee under processing fee agreements, we may guarantee recoveries to the producer. If recoveries are less than those guaranteed to the producer, we may suffer a loss by having to supply liquids or its cash equivalent to keep the producer whole.

We also receive fees and retain gas in kind from our natural gas transportation and storage customers. Our fuel retention fees and the value of gas that we retain in kind are directly affected by changes in natural gas prices. Decreases in natural gas prices tend to decrease our fuel retention fees and the value of retained gas.

In addition, we receive revenue from our off-gas processing and fractionating system in south Louisiana primarily through customer agreements that are a combination of keep-whole and percent-of-proceeds arrangements, as well as from transportation and fractionation fees. Consequently, a large portion of our off-gas processing and fractionation revenue is exposed to risks due to fluctuations in commodity prices. In addition, a decline in NGL prices could cause a decrease in demand for our off-gas processing and fractionation services and could have an adverse effect on our results of operations.

For our midstream segment, we generally analyze gross margin based on fee-based margin (which includes revenues from processing fee arrangements) and non-fee-based margin (which includes gross margin earned on percent-of-proceeds and keep-whole arrangements). The amount of segment margin earned by our midstream segment from fee-based and non-fee-based arrangements (individually and as a percentage of total revenues) will be impacted by the volumes associated with both types of arrangements, as well as commodity prices; therefore, the dollar amounts and the relative magnitude of gross margin from fee-based and non-fee-based arrangements in future periods may be significantly different from results reported in previous periods.

Our midstream facilities and transportation pipelines provide services related to natural gas wells that experience production declines over time, which we may not be able to replace with natural gas production from newly drilled wells in the same natural gas basins or in other new natural gas producing areas.

In order to maintain or increase throughput levels on our gathering systems and transportation pipeline systems and asset utilization rates at our treating and processing plants, we must continually contract for new natural gas supplies and natural gas transportation services.

A substantial portion of our assets, including our gathering systems and our processing and treating plants, are connected to natural gas reserves and wells that experience declining production over time. Our gas transportation pipelines are also dependent upon natural gas production in areas served by our gathering systems or in areas served by other gathering systems or transportation pipelines that connect with our transportation pipelines. We may not be able to obtain additional contracts for natural gas supplies for our natural gas gathering systems, and we may be unable to maintain or increase the levels of natural gas throughput on our transportation pipelines. The primary factors affecting our ability to connect new supplies of natural gas to our gathering systems include our success in contracting for existing natural gas supplies that are not committed to other systems and the level of drilling activity and production of natural gas near our gathering systems or in areas that provide access to our transportation pipelines or markets to which our systems connect. We have no control over the level of drilling activity in our areas of operation, the amount of reserves underlying the wells and the rate at which production from a well will decline. In addition, we have no control over producers or their production and contracting decisions.

While a substantial portion of our services are provided under long-term contracts for reserved service, we also provide service on an unreserved basis. The reserves available through the supply basins connected to our gathering, processing, treating, transportation and storage facilities may decline and may not be replaced by other sources of supply. A decrease in development or production activity could cause a decrease in the volume of unreserved services we provide and a decrease in the number and volume of our contracts for reserved transportation service over the long run, which in each case would adversely affect our revenues and results of operations.

 

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If we are unable to replace any significant volume declines with additional volumes from other sources, our results of operations and cash flows could be materially and adversely affected.

Our revenues depend on our customers’ ability to use our pipelines and third-party pipelines over which we have no control.

Our natural gas transportation, storage and NGL businesses depend, in part, on our customers’ ability to obtain access to pipelines to deliver gas to us and receive gas from us. Many of these pipelines are owned by parties not affiliated with us. Any interruption of service on our pipelines or third-party pipelines due to testing, line repair, reduced operating pressures, or other causes or adverse change in terms and conditions of service could have a material adverse effect on our ability, and the ability of our customers, to transport natural gas to and from our pipelines and facilities and a corresponding material adverse effect on our transportation and storage revenues. In addition, the rates charged by interconnected pipelines for transportation to and from our facilities affect the utilization and value of our storage services. Significant changes in the rates charged by those pipelines or the rates charged by other pipelines with which the interconnected pipelines compete could also have a material adverse effect on our storage revenues.

Shippers using our oil pipelines and terminals are also dependent upon our pipelines and connections to third-party pipelines to receive and deliver crude oil and products. Any interruptions or reduction in the capabilities of these pipelines due to testing, line repair, reduced operating pressures, or other causes could result in reduced volumes transported in our pipelines or through our terminals. Similarly, if additional shippers begin transporting volume over interconnecting oil pipelines, the allocations of pipeline capacity to our existing shippers on these interconnecting pipelines could be reduced, which also could reduce volumes transported in its pipelines or through our terminals. Allocation reductions of this nature are not infrequent and are beyond our control. Any such interruptions or allocation reductions that, individually or in the aggregate, are material or continue for a sustained period of time could have a material adverse effect on our results of operations, financial position, or cash flows.

The inability to continue to access lands owned by third parties could adversely affect our ability to operate and our financial results.

Our ability to operate our pipeline systems on certain lands owned by third parties will depend on our success in maintaining existing rights-of-way and obtaining new rights-of-way on those lands. We are parties to rights-of-way agreements, permits and licenses authorizing land use with numerous parties, including, private land owners, governmental entities, Native American tribes, rail carriers, public utilities and others. For more information, see our regulatory disclosure titled “Indigenous Protections.” Our ability to secure extensions of existing agreements, permits and licenses is essential to our continuing business operations, and securing additional rights-of-way will be critical to our ability to pursue expansion projects. We cannot provide any assurance that we will be able to maintain access to existing rights-of-way upon the expiration of the current grants, that all of the rights-of-way will be obtained in a timely fashion or that we will acquire new rights-of-way as needed.

Further, whether we have the power of eminent domain for our pipelines varies from state to state, depending upon the type of pipeline and the laws of the particular state and the ownership of the land to which we seek access. When we exercise eminent down rights or negotiate private agreements cases, we must compensate landowners for the use of their property and, in eminent domain actions, such compensation may be determined by a court. The inability to exercise the power of eminent domain could negatively affect our business if we were to lose the right to use or occupy the property on which our pipelines are located. For example, following a decision issued in May 2017 by the federal Tenth Circuit Court of Appeals, tribal ownership of even a very small fractional interest in an allotted land, that is, tribal land owned or at one time owned by an individual Indian landowner, bars condemnation of any interest in the allotment. Consequently, the inability to condemn such allotted lands under circumstances where existing pipeline rights-of-way may soon lapse or terminate serves as

 

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an additional impediment for pipeline operators. Any loss of rights with respect to our real property, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to unitholders.

Our storage operations are influenced by the overall forward market for crude oil and other products we store, and certain market conditions may adversely affect our financial and operating results.

Our storage operations are influenced by the overall forward market for crude oil and other products we store. A contango market (meaning that the price of crude oil or other products for future delivery is higher than the current price) is associated with greater demand for storage capacity, because a party can simultaneously purchase crude oil or other products at current prices for storage and sell at higher prices for future delivery. A backwardated market (meaning that the price of crude oil or other products for future delivery is lower than the current price) is associated with lower demand for storage capacity because a party can capture a premium for prompt delivery of crude oil or other products rather than storing it for future sale. A prolonged backwardated market, or other adverse market conditions, could have an adverse impact on its ability to negotiate favorable prices under new or renewing storage contracts, which could have an adverse impact on our storage revenues. As a result, the overall forward market for crude oil or other products may have an adverse effect on our financial condition or results of operations.

Competition for water resources or limitations on water usage for hydraulic fracturing could disrupt crude oil and natural gas production from shale formations.

Hydraulic fracturing is the process of creating or expanding cracks by pumping water, sand and chemicals under high pressure into an underground formation in order to increase the productivity of crude oil and natural gas wells. Water used in the process is generally fresh water, recycled produced water or salt water. There is competition for fresh water from municipalities, farmers, ranchers and industrial users. In addition, the available supply of fresh water can also be reduced directly by drought. Prolonged drought conditions increase the intensity of competition for fresh water. Limitations on oil and gas producers’ access to fresh water may restrict their ability to use hydraulic fracturing and could reduce new production. Such disruptions could potentially have a material adverse impact on our financial condition or results of operations.

A natural disaster, catastrophe or other event could result in severe personal injury, property damage and environmental damage, which could curtail our operations and otherwise materially adversely affect our cash flow.

Some of our operations involve risks of personal injury, property damage and environmental damage, which could curtail our operations and otherwise materially adversely affect our cash flow. For example, natural gas pipeline and other facilities operate at high pressures. Virtually all of our operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms, floods and/or earthquakes.

If one or more facilities that are owned by us, or that deliver natural gas or other products to us, are damaged by severe weather or any other disaster, accident, catastrophe or event, our operations could be significantly interrupted. Similar interruptions could result from damage to production or other facilities that supply our facilities or other stoppages arising from factors beyond our control. These interruptions might involve significant damage to people, property or the environment, and repairs might take from a week or less for a minor incident to six months or more for a major interruption. Any event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying distributions to Unitholders.

As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, we may not be able to renew existing insurance policies or procure other

 

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desirable insurance on commercially reasonable terms, if at all. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.

Terrorist attacks aimed at our facilities could adversely affect our business, results of operations, cash flows and financial condition.

The United States government has issued warnings that energy assets, including our nation’s pipeline infrastructure, may be the future target of terrorist organizations. Some of our facilities are subject to standards and procedures required by the Chemical Facility Anti-Terrorism Standards. We believe we are in compliance with all material requirements; however, such compliance may not prevent a terrorist attack from causing material damage to our facilities or pipelines. Any such terrorist attack on our facilities or pipelines, those of our customers, or in some cases, those of other pipelines could have a material adverse effect on our business, financial condition and results of operations.

Our business could be affected adversely by union disputes and strikes or work stoppages by unionized employees.

As of December 31, 2020, approximately 11% of our workforce is covered by a number of collective bargaining agreements with various terms and dates of expiration. There can be no assurances that we will not experience a work stoppage in the future as a result of labor disagreements. Any work stoppage could, depending on the affected operations and the length of the work stoppage, have a material adverse effect on our business, financial position, results of operations or cash flows.

Cybersecurity breaches and other disruptions could compromise our information and operations, and expose us to liability, which would cause our business and reputation to suffer.

In the ordinary course of our business, we collect and store sensitive data, including intellectual property, our proprietary business information and that of our customers, suppliers and business partners, and personally identifiable information of our employees, in our data centers and on our networks. The secure processing, maintenance and transmission of this information is critical to our operations and business strategy. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties for divulging shipper information, disruption of our operations, damage to our reputation, and loss of confidence in our products and services, which could adversely affect our business.

Our information technology infrastructure is critical to the efficient operation of our business and essential to our ability to perform day-today operations. Breaches in our information technology infrastructure or physical facilities, or other disruptions, could result in damage to our assets, safety incidents, damage to the environment, potential liability or the loss of contracts, and have a material adverse effect on our operations, financial position and results of operations.

Our operations could be disrupted if our information systems fail, causing increased expenses and loss of sales.

Our business is highly dependent on financial, accounting and other data processing systems and other communications and information systems, including our enterprise resource planning tools. We process a large number of transactions on a daily basis and rely upon the proper functioning of computer systems. If a key system was to fail or experience unscheduled downtime for any reason, even if only for a short period, our

 

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operations and financial results could be affected adversely. Our systems could be damaged or interrupted by a security breach, fire, flood, power loss, telecommunications failure or similar event. We have a formal disaster recovery plan in place, but this plan may not entirely prevent delays or other complications that could arise from an information systems failure. Our business interruption insurance may not compensate us adequately for losses that may occur.

Product liability claims and litigation could adversely affect our business and results of operations.

Product liability is a significant commercial risk. Substantial damage awards have been made in certain jurisdictions against manufacturers and resellers based upon claims for injuries caused by the use of or exposure to various products. There can be no assurance that product liability claims against us would not have a material adverse effect on our business or results of operations.

Along with other refiners, manufacturers and sellers of gasoline, ETC Sunoco Holdings LLC (“ETC Sunoco”) is a defendant in numerous lawsuits that allege methyl tertiary butyl ether (“MTBE”) contamination in groundwater. Plaintiffs, who include water purveyors and municipalities responsible for supplying drinking water and private well owners, are seeking compensatory damages (and in some cases injunctive relief, punitive damages and attorneys’ fees) for claims relating to the alleged manufacture and distribution of a defective product (MTBE-containing gasoline) that contaminates groundwater, and general allegations of product liability, nuisance, trespass, negligence, violation of environmental laws and deceptive business practices. There has been insufficient information developed about the plaintiffs’ legal theories or the facts that would be relevant to an analysis of the ultimate liability to ETC Sunoco. An adverse determination of liability related to these allegations or other product liability claims against ETC Sunoco could have a material adverse effect on our business or results of operations.

We do not control, and therefore may not be able to cause or prevent certain actions by, certain of our joint ventures.

Certain of our operations are conducted through joint ventures, some of which have their own governing boards. With respect to our joint ventures, we share ownership and management responsibilities with partners that may not share our goals and objectives. Consequently, it may be difficult or impossible for us to cause the joint venture entity to take actions that we believe would be in their or the joint venture’s best interests. Likewise, we may be unable to prevent actions of the joint venture. Differences in views among joint venture partners may result in delayed decisions or failures to agree on major matters, such as large expenditures or contractual commitments, the construction or acquisition of assets or borrowing money, among others. Delay or failure to agree may prevent action with respect to such matters, even though such action may serve our best interest or that of the joint venture. Accordingly, delayed decisions and disagreements could adversely affect the business and operations of the joint ventures and, in turn, our business and operations.

The use of derivative financial instruments could result in material financial losses by us.

From time to time, we and/or our subsidiaries have sought to reduce our exposure to fluctuations in commodity prices and interest rates by using derivative financial instruments and other risk management mechanisms and by our trading, marketing and/or system optimization activities. To the extent that we hedge our commodity price and interest rate exposures, we forgo the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor.

The accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions that are effective economically (whether to mitigate our exposure to fluctuations in commodity prices, or to balance our exposure to fixed and variable interest rates), these transactions may not be considered effective for accounting purposes. Accordingly, our consolidated financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at that point. It is also not always

 

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possible for us to engage in a hedging transaction that completely mitigates our exposure to commodity prices. Our consolidated financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge.

In addition, our derivatives activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the derivative arrangement, the hedge is imperfect, commodity prices move unfavorably related to our physical or financial positions or hedging policies and procedures are not followed.

Increasing levels of congestion in the Houston Ship Channel could result in a diversion of business to less busy ports.

Our Gulf Coast facilities are strategically situated on prime real estate located in the Houston Ship Channel, which is in close proximity to both supply sources and demand sources. In recent years, the success of the Port of Houston has led to an increase in vessel traffic driven in part by the growing overseas demand for U.S. crude, gasoline, liquefied natural gas and petrochemicals and in part by the Port of Houston’s recent decision to accept large container vessels, which can restrict the flow of other cargo. Increasing congestion in the Port of Houston could cause our customers or potential customers to divert their business to smaller ports in the Gulf of Mexico, which could result in lower utilization of our facilities.

The costs of providing pension and other postretirement health care benefits and related funding requirements are subject to changes in pension fund values, changing demographics and fluctuating actuarial assumptions and may have a material adverse effect on our financial results.

Certain of our subsidiaries provide pension plan and other postretirement healthcare benefits to certain of their employees. The costs of providing pension and other postretirement health care benefits and related funding requirements are subject to changes in pension and other postretirement fund values, changing demographics and fluctuating actuarial assumptions that may have a material adverse effect on the Partnership’s future consolidated financial results. While certain of the costs incurred in providing such pension and other postretirement healthcare benefits are recovered through the rates charged by the Partnership’s regulated businesses, the Partnership’s subsidiaries may not recover all of the costs and those rates are generally not immediately responsive to current market conditions or funding requirements. Additionally, if the current cost recovery mechanisms are changed or eliminated, the impact of these benefits on operating results could significantly increase.

Mergers among customers and competitors could result in lower volumes being shipped on our pipelines or products stored in or distributed through our terminals, or reduced crude oil marketing margins or volumes.

Mergers between existing customers could provide strong economic incentives for the combined entities to utilize their existing systems instead of our systems in those markets where the systems compete. As a result, we could lose some or all of the volumes and associated revenues from these customers and could experience difficulty in replacing those lost volumes and revenues, which could materially and adversely affect our results of operations, financial position, or cash flows.

Fraudulent activity or misuse of proprietary data involving our outsourcing partners could expose us to additional liability.

We utilize both affiliated entities and third parties in the processing of our information and data. Breaches of security measures or the accidental loss, inadvertent disclosure or unapproved dissemination of proprietary information, or sensitive or confidential data about us or our customers, including the potential loss or disclosure of such information or data as a result of fraud or other forms of deception, could expose us to a risk of loss, or misuse of this information, result in litigation and potential liability, lead to reputational damage, increase our compliance costs, or otherwise harm our business.

 

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We compete with other businesses in our market with respect to attracting and retaining qualified employees.

Our continued success depends on our ability to attract and retain qualified personnel in all areas of our business. We compete with other businesses in our market with respect to attracting and retaining qualified employees. A tight labor market, increased overtime and a higher full-time employee ratio may cause labor costs to increase. A shortage of qualified employees may require us to enhance wage and benefits packages in order to compete effectively in the hiring and retention of such employees or to hire more expensive temporary employees. No assurance can be given that our labor costs will not increase, or that such increases can be recovered through increased prices charged to customers. We are especially vulnerable to labor shortages in oil and gas drilling areas when energy prices drive higher exploration and production activity.

Changes in currency exchange rates could adversely affect our results of operations for our Canadian operations.

A portion of our revenue is generated from operations in Canada, which use the Canadian dollar as the functional currency. Therefore, changes in the exchange rate between the U.S. dollar and the Canadian dollar could adversely affect our results of operations.

We are subject to the risks of doing business outside of the U.S.

The success of our business depends, in part, on continued performance in our non-U.S. operations. We currently have operations in Canada. In addition to the other risks described in this report on Form 10-K, there are numerous risks and uncertainties that specifically affect our non-U.S. operations. These risks and uncertainties include political and economic instability, changes in local governmental laws, regulations and policies, including those related to tariffs, investments, taxation, exchange controls, employment regulations and repatriation of earnings, and enforcement of contract and intellectual property rights. International transactions may also involve increased financial and legal risks due to differing legal systems and customs, including risks of non-compliance with U.S. and local laws affecting our activities abroad, including compliance with the U.S. Foreign Corrupt Practices Act. While these factors and the impact of these factors are difficult to predict, any one or more of them could adversely affect our financial and operational results.

Our trucking fleet operations are subject to the Federal Motor Carrier Safety Regulations which are enacted, reviewed and amended by the FMCSA. Our fleet currently has a “satisfactory” safety rating; however, if our safety rating were downgraded to “unsatisfactory,” our business and results of operations could be adversely affected.

All federally regulated carriers’ safety ratings are measured through a program implemented by the FMCSA known as the Compliance Safety Accountability (“CSA”) program. The CSA program measures a carrier’s safety performance based on violations observed during roadside inspections as opposed to compliance audits performed by the FMCSA. The quantity and severity of any violations are compared to a peer group of companies of comparable size and annual mileage. If a company rises above a threshold established by the FMCSA, it is subject to action from the FMCSA. There is a progressive intervention strategy that begins with a company providing the FMCSA with an acceptable plan of corrective action that the company will implement. If the issues are not corrected, the intervention escalates to on-site compliance audits and ultimately an “unsatisfactory” rating and the revocation of its operating authority by the FMCSA could have an adverse effect on our business, results of operations and financial condition.

 

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Indebtedness

Our debt level and debt agreements may limit our ability to make distributions to Unitholders and may limit our future financial and operating flexibility.

As of December 31, 2020, we had approximately $51.37 billion of consolidated debt, excluding the debt of our unconsolidated joint ventures. Our level of indebtedness affects our operations in several ways, including, among other things:

 

   

a significant portion of our and our subsidiaries’ cash flow from operations will be dedicated to the payment of principal and interest on outstanding debt and will not be available for other purposes, including payment of distributions;

 

   

covenants contained in our and our subsidiaries’ existing debt agreements require us and them, as applicable, to meet financial tests that may adversely affect our flexibility in planning for and reacting to changes in our business;

 

   

our and our subsidiaries’ ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership, corporate or limited liability company purposes, as applicable, may be limited;

 

   

we may be at a competitive disadvantage relative to similar companies that have less debt;

 

   

we may be more vulnerable to adverse economic and industry conditions as a result of our significant debt level; and

 

   

failure by us or our subsidiaries to comply with the various restrictive covenants of our respective debt agreements could negatively impact our ability to incur additional debt, including our ability to utilize the available capacity under our revolving credit facility, and our ability to pay our distributions.

Increases in interest rates could materially adversely affect our business, results of operations, cash flows and financial condition.

In addition to our exposure to commodity prices, we have significant exposure to changes in interest rates. Approximately $6.72 billion of our consolidated debt as of December 31, 2020 bears interest at variable interest rates and the remainder bears interest at fixed rates. To the extent that we have debt with floating interest rates, our results of operations, cash flows and financial condition could be materially adversely affected by increases in interest rates. We manage a portion of our interest rate exposures by utilizing interest rate swaps.

An increase in interest rates could impact demand for our storage capacity.

There is a financing cost for a storage capacity user to own crude oil while it is stored. That financing cost is impacted by the cost of capital or interest rate incurred by the storage user, in addition to the commodity cost of the crude oil in inventory. Absent other factors, a higher financing cost adversely impacts the economics of storing crude oil for future sale. As a result, a significant increase in interest rates could adversely affect the demand for our storage capacity independent of other market factors.

An increase in the LIBOR or a phase-out or replacement of LIBOR with a benchmark rate that is higher or more volatile than the LIBOR rate could increase our cost of borrowing and could adversely affect our financial position.

As of December 31, 2020, we had outstanding approximately $6.40 billion of debt that bears interest at variable interest rates that use the LIBOR as a benchmark rate. Due to the perceived structural risks inherent in unsecured benchmark rates such as LIBOR, in July 2014, the Financial Stability Board (FSB) recommended developing alternative, near risk-free reference rates. In response to the recommendation put forth by the FSB, the Board of Governors of the Federal Reserve System and the Federal Reserve Bank of New York convened the Alternative

 

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Reference Rates Committee (“ARRC”) to identify alternatives to LIBOR. In June 2017, the ARRC selected the secured overnight financing rate (SOFR) as the preferred alternative reference rate to LIBOR. In July 2017, the U.K.’s Financial Conduct Authority (FCA), which oversees the LIBOR submission process for all currencies and regulates the authorized administrator of LIBOR, ICE Benchmark Administration (IBA), announced that it intends to stop persuading or compelling London banks to make these rate submissions after 2021. The cessation date for compulsory submission and publication of rates for certain tenors of LIBOR has since been extended by the IBA and FCA until June 2023. Additionally, the ARRC has published a series of principles for LIBOR fallback contract language which include a methodology for determining fallback rates, which are primarily comprised of SOFR as the replacement benchmark and a replacement benchmark spread.

It is unclear, if certain LIBOR tenors continue to be reported beyond 2021, whether they will be considered representative or whether SOFR as the identified successor benchmark rate will attain market acceptance as a replacement for LIBOR. It is not possible to predict the further effect of the rules, recommendations or administrative practices of the FCA, IBA or ARRC, any changes in the methods by which LIBOR is determined or any other reforms to LIBOR that may be enacted in the United Kingdom, the European Union or elsewhere. Any such developments may cause LIBOR to perform differently than in the past or cease to exist. In addition, any other legal or regulatory changes made by the FCA, the European Commission or any other successor governance or oversight body, or future changes adopted by such body, in the method by which LIBOR is determined or the change from LIBOR to an alternative benchmark rate may result in, among other things, a sudden or prolonged increase or decrease in LIBOR, a delay in the publication of LIBOR, and changes in the rules or methodologies in LIBOR, which may discourage market participants from continuing to administer or to participate in LIBOR’s determination, and, in certain situations, could result in LIBOR no longer being determined and published.

The adoption of SOFR, or any other alternative benchmark rate, may result in interest obligations which are more than or do not otherwise correlate over time with the payments that would have been made on such debt if U.S. dollar LIBOR was available in its current form. Further, the same costs and risks that may lead to the discontinuation or unavailability of U.S. dollar LIBOR may make one or more of the alternative methods impossible or impracticable to determine. Use of SOFR as an alternative benchmark rate and replacement for LIBOR could affect our debt securities, derivative instruments, receivables, debt payments and receipts. At this time, it is not possible to predict the effect of the establishment of any alternative benchmark rate(s). Any new benchmark rate will likely not replicate LIBOR exactly, and any changes to benchmark rates may have an uncertain impact on our cost of funds and our access to the capital markets. Any of these proposals or consequences could have a material adverse effect on our financing costs.

The credit and risk profile of our general partner and its owners could adversely affect our credit ratings and profile.

The credit and business risk profiles of our general partner, and of ET as the indirect owner of our general partner, may be factors in credit evaluations of us due to the significant influence of our general partner and ET over our business activities, including our cash distributions, acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of our general partner and its owners, including the degree of their financial leverage and their dependence on cash flow from the Partnership. ET is dependent principally on the cash distributions from its equity interests in us. Any distributions by us to ET will be made only after satisfying our then current obligations to our creditors. Although we have taken certain steps in our organizational structure, financial reporting and contractual relationships to reflect the separateness of us, ETP GP and ETP LLC from the entities that control ETP GP (ET and its general partner), our credit ratings and business risk profile could be adversely affected if the ratings and risk profiles of such entities were viewed as substantially lower or riskier than ours.

 

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A downgrade of our credit ratings could impact our and our subsidiaries’ liquidity, access to capital and costs of doing business, and maintaining credit ratings is under the control of independent third parties.

A downgrade of our credit ratings may increase our and our subsidiaries’ cost of borrowing and could require us to post collateral with third parties, negatively impacting our available liquidity. Our and our subsidiaries’ ability to access capital markets could also be limited by a downgrade of our credit ratings and other disruptions. Such disruptions could include:

 

   

economic downturns;

 

   

deteriorating capital market conditions;

 

   

declining market prices for crude oil, natural gas, NGLs and other commodities;

 

   

terrorist attacks or threatened attacks on our facilities or those of other energy companies; and

 

   

the overall health of the energy industry, including the bankruptcy or insolvency of other companies.

Credit rating agencies perform independent analysis when assigning credit ratings. The analysis includes a number of criteria including, but not limited to, business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are not recommendations to buy, sell or hold investments in the rated entity. Ratings are subject to revision or withdrawal at any time by the rating agencies, and we cannot assure you that we will maintain our current credit ratings.

Capital Projects and Future Growth

If we and our subsidiaries do not make acquisitions on economically acceptable terms, our future growth could be limited.

Our results of operations and our ability to grow and to make distributions to Unitholders will depend in part on our ability to make acquisitions that are accretive to our distributable cash flow per unit.

We may be unable to make accretive acquisitions for any of the following reasons, among others:

 

   

because we are unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;

 

   

because we are unable to raise financing for such acquisitions on economically acceptable terms; or

 

   

because we are outbid by competitors, some of which are substantially larger than us and have greater financial resources and lower costs of capital then we do.

Furthermore, even if we consummate acquisitions that we believe will be accretive, those acquisitions may in fact adversely affect our results of operations or result in a decrease in distributable cash flow per unit. Any acquisition involves potential risks, including the risk that we may:

 

   

fail to realize anticipated benefits, such as new customer relationships, cost-savings or cash flow enhancements;

 

   

decrease our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;

 

   

significantly increase our interest expense or financial leverage if we incur additional debt to finance acquisitions;

 

   

encounter difficulties operating in new geographic areas or new lines of business;

 

   

incur or assume unanticipated liabilities, losses or costs associated with the business or assets acquired for which we are not indemnified or for which the indemnity is inadequate;

 

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be unable to hire, train or retrain qualified personnel to manage and operate our growing business and assets;

 

   

less effectively manage our historical assets, due to the diversion of management’s attention from other business concerns; or

 

   

incur other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.

If we consummate future acquisitions, our capitalization and results of operations may change significantly. As we determine the application of our funds and other resources, Unitholders will not have an opportunity to evaluate the economic, financial and other relevant information that we will consider.

Capital projects will require significant amounts of debt and equity financing, which may not be available to us on acceptable terms, or at all.

We plan to fund our growth capital expenditures, including any new pipeline construction projects and improvements or repairs to existing facilities that we may undertake, with proceeds from sales of our debt and equity securities and borrowings under our revolving credit facility; however, we cannot be certain that we will be able to issue our debt and equity securities on terms satisfactory to us, or at all. If we are unable to finance our expansion projects as expected, we could be required to seek alternative financing, the terms of which may not be attractive to us, or to revise or cancel our expansion plans.

A significant increase in our indebtedness that is proportionately greater than our issuance of equity could negatively impact our and our subsidiaries’ credit ratings or our ability to remain in compliance with the financial covenants under our revolving credit agreement, which could have a material adverse effect on our financial condition, results of operations and cash flows.

If we do not continue to construct new pipelines, our future growth could be limited.

Our results of operations and ability to grow and to increase distributable cash flow per unit will depend, in part, on our ability to construct pipelines that are accretive to our distributable cash flow. We may be unable to construct pipelines that are accretive to distributable cash flow for any of the following reasons, among others:

 

   

we are unable to identify pipeline construction opportunities with favorable projected financial returns;

 

   

we are unable to obtain necessary governmental approvals and contracts with qualified contractors and vendors on acceptable terms;

 

   

we are unable to raise financing for our identified pipeline construction opportunities; or

 

   

we are unable to secure sufficient transportation commitments from potential customers due to competition from other pipeline construction projects or for other reasons.

Furthermore, even if we construct a pipeline that we believe will be accretive, the pipeline may in fact adversely affect our results of operations or results from those projected prior to commencement of construction and other factors.

Expanding our business by constructing new pipelines and related facilities subjects us to risks.

One of the ways that we have grown our business is through the construction of additions to our existing gathering, compression, treating, processing and transportation systems. The construction of new pipelines and related facilities (or the improvement and repair of existing facilities) involves numerous regulatory, environmental, political and legal uncertainties beyond our control and requires the expenditure of significant amounts of capital that we will be required to finance through borrowings, the issuance of additional equity or

 

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from operating cash flow. If we undertake these projects, they may not be completed on schedule, at all, or at the budgeted cost. A variety of factors outside our control, such as weather, natural disasters and difficulties in obtaining permits and rights-of-way or other regulatory approvals, as well as the performance by third-party contractors, may result in increased costs or delays in construction. For example, in recent years, pipeline projects by many companies have been subject to several challenges by environmental groups, such as challenges to agency reviews under the NEPA and to the USACE NWP program. For more information on the NWP program, see our regulatory disclosure titled “Clean Water Act”. Separately, cost overruns or delays in completing a project could have a material adverse effect on our results of operations and cash flows. Moreover, our revenues may not increase immediately following the completion of a particular project. For instance, if we build a new pipeline, the construction will occur over an extended period of time, but we may not materially increase our revenues until long after the project’s completion. In addition, the success of a pipeline construction project will likely depend upon the level of oil and natural gas exploration and development drilling activity and the demand for pipeline transportation in the areas proposed to be serviced by the project as well as our ability to obtain commitments from producers in the area to utilize the newly constructed pipelines. In this regard, we may construct facilities to capture anticipated future growth in oil or natural gas production in a region in which such growth does not materialize. As a result, new facilities may be unable to attract enough throughput or contracted capacity reservation commitments to achieve our expected investment return, which could adversely affect our results of operations and financial condition.

The liquefaction project is dependent upon securing long-term contractual arrangements for the off-take of LNG on terms sufficient to support the financial viability of the project.

LCL, our wholly-owned subsidiary, is in the process of developing a liquefaction project at the site of our existing regasification facility in Lake Charles, Louisiana. The project would utilize existing dock and storage facilities owned by us located on the Lake Charles site. The parties’ determination as to the feasibility of the project will be particularly dependent upon the prospects for securing long-term contractual arrangements for the off-take of LNG which in turn will be dependent upon supply and demand factors affecting the price of LNG in foreign markets. The financial viability of the project will also be dependent upon a number of other factors, including the expected cost to construct the liquefaction facility, the terms and conditions of the financing for the construction of the liquefaction facility, the cost of the natural gas supply, the costs to transport natural gas to the liquefaction facility, the costs to operate the liquefaction facility and the costs to transport LNG from the liquefaction facility to customers in foreign markets (particularly Europe and Asia). Some of these costs fluctuate based on a variety of factors, including supply and demand factors affecting the price of natural gas in the United States, supply and demand factors affecting the costs for construction services for large infrastructure projects in the United States, and general economic conditions, there can be no assurance that the parties will determine to proceed to develop this project.

The construction of the liquefaction project remains subject to further approvals and some approvals may be subject to further conditions, review and/or revocation.

While LCL has received authorization from the DOE to export LNG to non-Free Trade Agreements (“non-FTA”) countries, the non-FTA authorization is subject to review, and the DOE may impose additional approval and permit requirements in the future or revoke the non-FTA authorization should the DOE conclude that such export authorization is inconsistent with the public interest. The FERC order (issued December 17, 2015) authorizing LCL to site, construct and operate the liquefaction project contains a condition requiring all phases of the liquefaction project to be completed and in-service within five years of the date of the order. The order also requires the modifications to our Trunkline pipeline facilities that connect to our Lake Charles facility and additionally requires execution of a transportation contract for natural gas supply to the liquefaction facility prior to the initiation of construction of the liquefaction facility. On December 5, 2019, the FERC granted an extension of time until and including December 16, 2025, to complete construction of the liquefaction project and pipeline facilities modifications and place the facilities into service.

 

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Integration of assets acquired in past acquisitions or future acquisitions with our existing business will be a complex and time-consuming process. A failure to successfully integrate the acquired assets with our existing business in a timely manner may have a material adverse effect on our business, financial condition, results of operations or cash available for distribution to unitholders.

The difficulties of integrating past and future acquisitions with our business include, among other things:

 

   

operating a larger combined organization in new geographic areas and new lines of business;

 

   

hiring, training or retaining qualified personnel to manage and operate our growing business and assets;

 

   

integrating management teams and employees into existing operations and establishing effective communication and information exchange with such management teams and employees;

 

   

diversion of management’s attention from our existing business;

 

   

assimilation of acquired assets and operations, including additional regulatory programs;

 

   

loss of customers or key employees;

 

   

maintaining an effective system of internal controls in compliance with the Sarbanes-Oxley Act of 2002 as well as other regulatory compliance and corporate governance matters; and

 

   

integrating new technology systems for financial reporting.

If any of these risks or other unanticipated liabilities or costs were to materialize, then desired benefits from past acquisitions and future acquisitions resulting in a negative impact to our future results of operations. In addition, acquired assets may perform at levels below the forecasts used to evaluate their acquisition, due to factors beyond our control. If the acquired assets perform at levels below the forecasts, then our future results of operations could be negatively impacted.

Also, our reviews of proposed business or asset acquisitions are inherently imperfect because it is generally not feasible to perform an in-depth review of each such proposal given time constraints imposed by sellers. Even if performed, a detailed review of assets and businesses may not reveal existing or potential problems and may not provide sufficient familiarity with such business or assets to fully assess their deficiencies and potential. Inspections may not be performed on every asset, and environmental problems, may not be observable even when an inspection is undertaken.

We are affected by competition from other midstream, transportation, terminalling and storage companies.

We experience competition in all of our business segments. With respect to our midstream operations, we compete for both natural gas supplies and customers for our services. Our competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport, store and market natural gas.

Our natural gas and NGL transportation pipelines and storage facilities compete with other interstate and intrastate pipeline companies and storage providers in the transportation and storage of natural gas and NGLs. The principal elements of competition among pipelines are rates, terms of service, access to sources of supply and the flexibility and reliability of service. Natural gas and NGLs also compete with other forms of energy, including electricity, coal, fuel oils and renewable or alternative energy. Competition among fuels and energy supplies is primarily based on price; however, non-price factors, including governmental regulation, environmental impacts, efficiency, ease of use and handling, and the availability of subsidies and tax benefits also affects competitive outcomes.

In markets served by our NGL pipelines, we compete with other pipeline companies and barge, rail and truck fleet operations. We also face competition with other storage and fractionation facilities based on fees charged and the ability to receive, distribute and/or fractionate the customer’s products.

 

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Our crude oil and refined petroleum products pipelines face significant competition from other pipelines for large volume shipments. These operations also face competition from trucks for incremental and marginal volumes in the areas we serve. Further, our crude and refined product terminals compete with terminals owned by integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading operations.

We, Sunoco LP and USAC may not be able to fully execute our growth strategy if we encounter increased competition for qualified assets.

Our strategy contemplates growth through the development and acquisition of a wide range of midstream, transportation, storage and other energy infrastructure assets while maintaining a strong balance sheet. This strategy includes constructing and acquiring additional assets and businesses to enhance our ability to compete effectively and diversify our asset portfolio, thereby providing more stable cash flow. We regularly consider and enter into discussions regarding the acquisition of additional assets and businesses, stand-alone development projects or other transactions that we believe will present opportunities to realize synergies and increase our cash flow.

Consistent with our strategy, we may, from time to time, engage in discussions with potential sellers regarding the possible acquisition of additional assets or businesses. Such acquisition efforts may involve our participation in processes that involve a number of potential buyers, commonly referred to as “auction” processes, as well as situations in which we believe we are the only party or one of a very limited number of potential buyers in negotiations with the potential seller. We cannot give assurance that our acquisition efforts will be successful or that any acquisition will be completed on terms considered favorable to us.

In addition, we are experiencing increased competition for the assets we purchase or contemplate purchasing. Increased competition for a limited pool of assets could result in us losing to other bidders more often or acquiring assets at higher prices, both of which would limit our ability to fully execute our growth strategy. Inability to execute our growth strategy may materially adversely impact our results of operations.

Regulatory Matters

Increased regulation of hydraulic fracturing or produced water disposal could result in reductions or delays in crude oil and natural gas production in our areas of operation, which could adversely impact our business and results of operations.

The hydraulic fracturing process has come under considerable scrutiny from sections of the public as well as environmental and other groups asserting that chemicals used in the hydraulic fracturing process could adversely affect drinking water supplies and may have other detrimental impacts on public health, safety, welfare and the environment. In addition, the water disposal process has come under scrutiny from sections of the public as well as environmental and other groups asserting that the operation of certain water disposal wells has caused increased seismic activity. Additionally, several candidates for political office in both state and federal government have announced intentions to impose greater restrictions on hydraulic fracturing or produced water disposal. For example, the Biden Administration has issued orders temporarily suspending the issuance of new authorizations, and suspending the issuance of new leases pending completion of a review of current practices, for oil and gas development on federal lands and waters (but not tribal lands that the federal government merely holds in trust). Separately, the Colorado Oil and Gas Conservation Commission adopted new rules to cover a variety of matters related to public health, safety, welfare, wildlife, and environmental resources; most significantly, these rule changes establish more stringent setbacks (2,000-foot, instead of the prior 500-foot) on new oil and gas development and eliminate routine flaring and venting of natural gas at new existing wells across the state, each subject to only limited exceptions. While the final impacts of these developments cannot be predicted, the adoption of new laws or regulations imposing additional permitting, disclosures, restrictions or costs related to hydraulic fracturing or produced water disposal or prohibiting hydraulic fracturing in proximity

 

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to areas considered to be environmentally sensitive could make drilling certain wells impossible or less economically attractive. As a result, the volume of crude oil and natural gas we gather, transport and store for our customers could be substantially reduced which could have an adverse effect on our financial condition or results of operations.

Legal or regulatory actions related to the Dakota Access pipeline could cause an interruption to current or future operations, which could have an adverse effect on our business and results of operations.

On July 27, 2016, the Standing Rock Sioux Tribe and other Native American tribes (the “Tribes”) filed a lawsuit in the United States District Court for the District of Columbia (“District Court”) challenging permits issued by the USACE permitting Dakota Access, LLC (“Dakota Access”) to cross the Missouri River at Lake Oahe in North Dakota. The case was subsequently amended to challenge an easement issued by the USACE allowing the pipeline to cross land owned by the USACE adjacent to the Missouri River. As a result of this litigation, the District Court vacated the easement, ordered USACE to prepare an Environmental Impact Statement (“EIS”), and order the pipeline shutdown and drained of oil. Dakota Access and USACE appealed this decision and moved for a stay of the District Court’s orders. On August 5, 2020, the Court of Appeals granted a stay of the portion of the District Court order that required Dakota Access to shut the pipeline down and empty it of oil, but the Court of Appeals denied a stay of the easement vacatur. The August 5 order also stated that the Court of Appeals expected the USACE to clarify its position with respect to whether USACE intends to allow the continued operation of the pipeline notwithstanding the vacatur of the easement and that the District Court may consider additional relief, if necessary. Following this order, the Tribes filed a motion with the District Court seeking an injunction to prevent the continued operation of the pipeline. This motion has been briefed by the Tribes, USACE, and Dakota Access, but the District Court has not yet ruled on this motion. On January 26, 2021, the Court of Appeals affirmed the District Court’s order requiring an EIS and its order vacating the easement. In the same January 26 order, the Court of Appeals also overturned the District Court’s August 5, 2020 order that the pipeline be shut down and emptied of oil because of the lack of findings sufficient to satisfy the legal requirements for injunctive relief, including a finding of irreparable harm to the Tribes in the absence of an injunction. The District Court scheduled a status conference for February 10, 2021 to discuss the impact of the Court of Appeals’ ruling on the pending motion for injunctive relief, as well as USACE’s expectations as to how it will proceed in light of the Court of Appeals’ recent vacatur ruling. USACE filed a motion for a continuance of the status conference until April 9, 2021, and this motion was approved by the District Court on February 9, 2021. For further information, see Note 10 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” in this report.

Our interstate natural gas pipelines are subject to laws, regulations and policies governing the rates they are allowed to charge for their services, which may prevent us from fully recovering our costs.

Laws, regulations and policies governing interstate natural gas pipeline rates could affect the ability of our interstate pipelines to establish rates, to charge rates that would cover future increases in its costs, or to continue to collect rates that cover current costs.

We are required to file tariff rates (also known as recourse rates) with the FERC that shippers may pay for interstate natural gas transportation services. We may also agree to discount these rates on a not unduly discriminatory basis or negotiate rates with shippers who elect not to pay the recourse rates. The FERC must approve or accept all rate filings for us to be allowed to charge such rates.

The FERC may review existing tariff rates on its own initiative or upon receipt of a complaint filed by a third party. The FERC may, on a prospective basis, order refunds of amounts collected if it finds the rates to have been shown not to be just and reasonable or to have been unduly discriminatory. The FERC has recently exercised this authority with respect to several other pipeline companies. If the FERC were to initiate a proceeding against us and find that our rates were not just and reasonable or were unduly discriminatory, the maximum rates we are permitted to charge may be reduced and the reduction could have an adverse effect on our revenues and results of operations.

 

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The costs of our interstate pipeline operations may increase, and we may not be able to recover all of those costs due to FERC regulation of our rates. If we propose to change our tariff rates, our proposed rates may be challenged by the FERC or third parties, and the FERC may deny, modify or limit our proposed changes if we are unable to persuade the FERC that changes would result in just and reasonable rates that are not unduly discriminatory. We also may be limited by the terms of rate case settlement agreements or negotiated rate agreements with individual customers from seeking future rate increases, or we may be constrained by competitive factors from charging our tariff rates.

To the extent our costs increase in an amount greater than our revenues increase, or there is a lag between our cost increases and our ability to file for and obtain rate increases, our operating results would be negatively affected. Even if a rate increase is permitted by the FERC to become effective, the rate increase may not be adequate. We cannot guarantee that our interstate pipelines will be able to recover all of our costs through existing or future rates.

The ability of interstate pipelines held in tax-pass-through entities, like us, to include an allowance for income taxes as a cost-of-service element in their regulated rates has been subject to extensive litigation before the FERC and the courts for a number of years. Effective January 2018, the 2017 Tax Cuts and Jobs Act (the “Tax Act”) changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. On March 15, 2018, in a set of related proposals, the FERC addressed treatment of federal income tax allowances in regulated entity rates. The FERC issued a Revised Policy Statement on Treatment of Income Taxes (“Revised Policy Statement”) stating that it will no longer permit master limited partnerships to recover an income tax allowance in their cost-of-service rates. The FERC issued the Revised Policy Statement in response to a remand from the United States Court of Appeals for the District of Columbia Circuit in United Airlines v. FERC, in which the court determined that the FERC had not justified its conclusion that a pipeline organized as a master limited partnership would not “double recover” its taxes under the current policy by both including an income-tax allowance in its cost of service and earning a return on equity (“ROE”) calculated using the discounted cash flow methodology. On July 18, 2018, the FERC issued an order denying requests for rehearing and clarification of its Revised Policy Statement because it is a non-binding policy and parties will have the opportunity to address the policy as applied in future cases. In the rehearing order, the FERC clarified that a pipeline organized as a master limited partnership will not be precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double-recovery of investors’ income tax costs. On July 31, 2020, the United States Court of Appeals for the District of Columbia Circuit issued an opinion upholding FERC’s decision denying a separate master limited partnership recovery of an income tax allowance and its decision not to require the master limited partnership to refund accumulated deferred income tax balances. In light of the rehearing order’s clarification regarding individual entities’ ability to argue in support of recovery of an income tax allowance and the court’s subsequent opinion upholding denial of an income tax allowance to a master limited partnership, the impacts that FERC’s policy on the treatment of income taxes may have on the rates an interstate pipeline held in a tax-pass-through entity can charge for the FERC regulated transportation services are unknown at this time.

Even without application of FERC’s recent rate making-related policy statements and rulemakings, under the NGA, FERC or our shippers may challenge the cost-of-service rates we charge. The FERC’s establishment of a just and reasonable rate is based on many components, including ROE and tax-related components, including the allowance for income taxes and the amount for accumulated deferred income taxes, but also other pipeline costs that will continue to affect the FERC’s determination of just and reasonable cost-of-service rates. Moreover, we receive revenues from our pipelines based on a variety of rate structures, including cost-of-service rates, negotiated rates, discounted rates and market-based rates. Many of our interstate pipelines, such as ETC Tiger, Midcontinent Express and Fayetteville Express, have negotiated market rates that were agreed to by customers in connection with long-term contracts entered into to support the construction of the pipelines. Other systems, such as FGT, Transwestern and Panhandle, have a mix of tariff rate, discount rate, and negotiated rate agreements. The revenues we receive from natural gas transportation services we provide pursuant to cost-of-service based

 

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rates may decrease in the future as a result of changes to FERC policies, combined with the reduced corporate federal income tax rate established in the Tax Act. The extent of any revenue reduction related to our cost-of-service rates, if any, will depend on a detailed review of all of a pipeline’s cost-of-service components and the outcomes of any challenges to our rates by the FERC or our shippers.

By order issued January 16, 2019, the FERC initiated a review of Panhandle’s existing rates pursuant to Section 5 of the NGA to determine whether the rates currently charged by Panhandle are just and reasonable and set the matter for hearing. Panhandle filed a cost and revenue study on April 1, 2019 and an NGA Section 4 rate case on August 30, 2019. The Section 4 and section 5 proceedings were consolidated by order of the Chief Judge on October 1, 2019. A hearing in the combined proceedings commenced on August 25, 2020 and adjourned on September 15, 2020. By order dated January 19, 2021, the Chief Judge has extended the deadline for the initial decision to March 2021.

Our interstate natural gas pipelines are subject to laws, regulations and policies governing terms and conditions of service, which could adversely affect our business and results of operations.

In addition to rate oversight, the FERC’s regulatory authority extends to many other aspects of the business and operations of our interstate natural gas pipelines, including:

 

   

terms and conditions of service;

 

   

the types of services interstate pipelines may or must offer their customers;

 

   

construction of new facilities;

 

   

acquisition, extension or abandonment of services or facilities;

 

   

reporting and information posting requirements;

 

   

accounts and records; and

 

   

relationships with affiliated companies involved in all aspects of the natural gas and energy businesses.

Compliance with these requirements can be costly and burdensome. In addition, we cannot guarantee that the FERC will authorize tariff changes and other activities we might propose and to undertake in a timely manner and free from potentially burdensome conditions. Future changes to laws, regulations, policies and interpretations thereof may impair our access to capital markets or may impair the ability of our interstate pipelines to compete for business, may impair their ability to recover costs or may increase the cost and burden of operation.

In December 2017, the then-serving FERC Chairman announced that the FERC will review its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. To that end, FERC issued a Notice of Inquiry on April 9, 2018, requesting comments on its certification policies, but no action has been taken in that docket. We are unable to predict what, if any, changes may be proposed that will affect our natural gas pipeline business or when such proposals, if any, might become effective. We do not expect that any change in this policy would affect us in a materially different manner than any other similarly sized natural gas pipeline company operating in the United States.

Rate regulation or market conditions may not allow us to recover the full amount of increases in the costs of our crude oil, NGL and refined products pipeline operations.

Transportation provided on our common carrier interstate crude oil, NGL and refined products pipelines is subject to rate regulation by the FERC, which requires that tariff rates for transportation on these oil pipelines be just and reasonable and not unduly discriminatory. If we propose new or changed rates, the FERC or interested

 

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persons may challenge those rates and the FERC is authorized to suspend the effectiveness of such rates for up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the proposed rate is unjust or unreasonable, it is authorized to require the carrier to refund revenues in excess of the prior tariff during the term of the investigation. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.

The primary ratemaking methodology used by the FERC to authorize increases in the tariff rates of petroleum pipelines is price indexing. The FERC’s ratemaking methodologies may limit our ability to set rates based on our costs or may delay the use of rates that reflect increased costs. On March 25, 2020, the FERC issued a Notice of Inquiry seeking comment on a proposal to change the preliminary screen for complaints against oil pipeline index rate increases to a “Percentage Comparison Test” consistent with the preliminary screen used by the FERC for protests against oil pipeline index rate increases. The FERC also requested comment on whether the appropriate threshold for the screen is a 10% or more differential between a proposed index rate increase and the annual percentage change in cost of service reported by the pipeline. Initial comments were due June 16, 2020, and reply comments were due July 16, 2020. The FERC has not yet taken any further action on the Notice of Inquiry. At this time, we cannot determine the effect of a change in the FERC’s preliminary screen for complaints against index rates changes, however, a revised screen would result in a threshold aligned with the existing threshold for protests against index rate increases. Any complaint or protest raised by a shipper could materially and adversely affect our financial condition, results of operations or cash flows.

On June 18, 2020, FERC issued a Notice of Inquiry requesting comments on a proposed oil pipeline index for the five-year period commencing July 1, 2021 and ending June 30, 2026, and requested comments on whether and how the index should reflect the Revised Policy Statement and FERC’s treatment of accumulated deferred income taxes as well as FERC’s revised ROE methodology. Comments on the indexing rate methodology Notice of Inquiry were due August 17, 2020, with reply comments due September 11, 2020.

On December 17, 2020, FERC issued an order establishing a new index of PPI-FG plus 0.78%. Rehearing of this order has been requested and remains pending before FERC.

Under the Energy Policy Act of 1992 (the “Energy Policy Act”), certain interstate pipeline rates were deemed just and reasonable or “grandfathered.” Revenues are derived from such grandfathered rates on most of our FERC-regulated pipelines. A person challenging a grandfathered rate must, as a threshold matter, establish a substantial change since the date of enactment of the Energy Policy Act, in either the economic circumstances or the nature of the service that formed the basis for the rate. If the FERC were to find a substantial change in circumstances, then the existing rates could be subject to detailed review and there is a risk that some rates could be found to be in excess of levels justified by the pipeline’s costs. In such event, the FERC could order us to reduce pipeline rates prospectively and to pay refunds to shippers.

If the FERC’s petroleum pipeline ratemaking methodologies procedures changes, the new methodology or procedures could adversely affect our business and results of operations.

State regulatory measures could adversely affect the business and operations of our midstream and intrastate pipeline and storage assets.

Our midstream and intrastate transportation and storage operations are generally exempt from FERC regulation under the NGA, but FERC regulation still significantly affects our business and the market for our products. The rates, terms and conditions of service for the interstate services we provide in our intrastate gas pipelines and gas storage are subject to FERC regulation under Section 311 of the NGPA. Our HPL System, East Texas pipeline, Oasis pipeline and ET Fuel System provide such services. Under Section 311, rates charged for transportation and storage must be fair and equitable. Amounts collected in excess of fair and equitable rates are subject to

 

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refund with interest, and the terms and conditions of service, set forth in the pipeline’s statement of operating conditions, are subject to FERC review and approval. Should the FERC determine not to authorize rates equal to or greater than our costs of service, our cash flow would be negatively affected.

Our midstream and intrastate gas and oil transportation pipelines and our intrastate gas storage operations are subject to state regulation. All of the states in which we operate midstream assets, intrastate pipelines or intrastate storage facilities have adopted some form of complaint-based regulation, which allow producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to the fairness of rates and terms of access. The states in which we operate have ratable take statutes, which generally require gatherers to take, without undue discrimination, production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas. Should a complaint be filed in any of these states or should regulation become more active, our business may be adversely affected.

Our intrastate transportation operations located in Texas are also subject to regulation as gas utilities by the Texas Railroad Commission (“TRRC”). Texas gas utilities must publish the rates they charge for transportation and storage services in tariffs filed with the TRRC, although such rates are deemed just and reasonable under Texas law unless challenged in a complaint.

We are subject to other forms of state regulation, including requirements to obtain operating permits, reporting requirements, and safety rules (see description of federal and state pipeline safety regulation below). Violations of state laws, regulations, orders and permit conditions can result in the modification, cancellation or suspension of a permit, civil penalties and other relief.

Certain of our assets may become subject to regulation.

The distinction between federally unregulated gathering facilities and FERC-regulated transmission pipelines under the NGA has been the subject of extensive litigation and may be determined by the FERC on a case-by-case basis, although the FERC has made no determinations as to the status of our facilities. Consequently, the classification and regulation of our gathering facilities could change based on future determinations by the FERC, the courts or Congress. If our gas gathering operations become subject to FERC jurisdiction, the result may adversely affect the rates we are able to charge and the services we currently provide, and may include the potential for a termination of our gathering agreements with our customers.

Intrastate transportation of NGLs is largely regulated by the state in which such transportation takes place. Lone Star’s NGL Pipeline transports NGLs within the state of Texas and is subject to regulation by the TRRC. This NGLs transportation system offers services pursuant to an intrastate transportation tariff on file with the TRRC. In 2013, Lone Star’s NGL pipeline also commenced the interstate transportation of NGLs, which is subject to the FERC’s jurisdiction under the Interstate Commerce Act (“ICA”) and the Energy Policy Act. Both intrastate and interstate NGL transportation services must be provided in a manner that is just, reasonable, and non-discriminatory. The tariff rates established for interstate services were based on a negotiated agreement; however, if the FERC’s ratemaking methodologies were imposed, they may, among other things, delay the use of rates that reflect increased costs and subject us to potentially burdensome and expensive operational, reporting and other requirements. In addition, the rates, terms and conditions for shipments of crude oil, petroleum products and NGLs on our pipelines are subject to regulation by the FERC if the NGLs are transported in interstate or foreign commerce, whether by our pipelines or other means of transportation. Since we do not control the entire transportation path of all crude oil, petroleum products and NGLs on our pipelines, FERC regulation could be triggered by our customers’ transportation decisions.

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and criminal remedies and civil penalties, as well as a requirement to disgorge charges collected for such services in excess of the rate established by the FERC. Any of the foregoing could adversely affect revenues and cash flow related to these assets.

We may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs.

Pursuant to authority under the NGPSA and Hazardous Liquids Pipeline Safety Act of 1979, as amended (“HLPSA”), PHMSA has established a series of rules requiring pipeline operators to develop and implement integrity management programs for natural gas transmission and hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect high consequence areas (“HCAs”) which are areas where a release could have the most significant adverse consequences, including high population areas, certain drinking water sources, and unusually sensitive ecological areas. These regulations require operators of covered pipelines to:

 

   

perform ongoing assessments of pipeline integrity;

 

   

identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

 

   

improve data collection, integration and analysis;

 

   

repair and remediate the pipeline as necessary; and

 

   

implement preventive and mitigating actions.

In addition, states have adopted regulations similar to existing PHMSA regulations for intrastate gathering and transmission lines. At this time, we cannot predict the ultimate cost of compliance with applicable pipeline integrity management regulations, as the cost will vary significantly depending on the number and extent of any repairs found to be necessary as a result of the pipeline integrity testing. We will continue our pipeline integrity testing programs to assess and maintain the integrity of our pipelines. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines. Any changes to pipeline safety laws by Congress and regulations by PHMSA that result in more stringent or costly safety standards could have a significant adverse effect on us and similarly situated midstream operators. For example, in October 2019, PHMSA published the first of three expected regulations relating to new or more stringent requirements for certain natural gas lines and gathering lines, that had originally been proposed in 2016 as part of PHMSA’s “Gas Megarule.” The rulemaking imposed numerous requirements, including, among other things, expanding certain of PHMSA’s current regulatory safety programs for natural gas pipelines in newly defined MCAs that contain as few as five dwellings within a potential impact area. PHMSA is still expected to issue the second and third parts of the Gas Megarule, but we cannot predict the timing of any such action. The safety and hazardous liquid pipelines rule would extend leak detection requirements to all non-gathering hazardous liquid pipelines and require operators to inspect affected pipelines following extreme weather events or natural disasters to address any resulting damage. Finally, the enhanced emergency procedures rule focuses on increased emergency safety measures. In particular, this rule increases the authority of PHMSA to issue an emergency order that addresses unsafe conditions or hazards that pose an imminent threat to pipeline safety. The changes adopted or proposed by these rulemakings or made in future legal requirements could have a material adverse effect on our results of operations and costs of transportation services.

Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.

The NGPSA and HLPSA were amended by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”). Among other things, the 2011 Pipeline Safety Act increased the penalties for safety violations and directed the Secretary of Transportation to promulgate rules or standards relating to

 

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expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, testing to confirm that the material strength of certain pipelines are above 30% of specified minimum yield strength, and operator verification of records confirming the MAOP of certain interstate natural gas transmission pipelines. In January 2021, PHMSA issued a final rule increasing the maximum administrative fines for safety violations were increased to account for inflation, with maximum civil penalties set at $222,504 per day, with a maximum of $2,225,034 for a series of violations. Upon reauthorization of PHMSA, Congress often directs the agency to complete certain rulemakings. For example, in the Consolidated Appropriations Bill for Fiscal Year 2021, Congress reauthorized PHMSA through fiscal year 2023 and directed the agency to move forward with several regulatory actions, including the “Pipeline Safety: Class Location Change Requirements” and the “Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines” proposed rulemakings; Congress has also instructed PHMSA to issue final regulations to require operations of non-rural gas gathering lines and new existing transmission and distribution pipelines to conduct certain leak detection and repair programs to require facility inspection and maintenance plans to align with those regulations. The timing and scope of such future rulemakings is uncertain. The safety enhancement requirements and other provisions of Congressional mandates to PHMSA, as well as any implementation of PHMSA rules thereunder or any issuance or reinterpretation of guidance by PHMSA or any state agencies with respect thereto, could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could be significant and have a material adverse effect on our results of operations or financial condition.

Our business involves the generation, handling and disposal of hazardous substances, hydrocarbons and wastes which activities are subject to environmental and worker health and safety laws and regulations that may cause us to incur significant costs and liabilities.

Our business is subject to stringent federal, tribal, state, and local laws and regulations governing the discharge of materials into the environment, worker health and safety and protection of the environment. These laws and regulations may require the acquisition of permits for the construction and operation of our pipelines, plants and facilities, result in capital expenditures to manage, limit or prevent emissions, discharges or releases of various materials from our pipelines, plants and facilities, impose specific health and safety standards addressing worker protection, and impose substantial liabilities for pollution resulting from our construction and operations activities. Several governmental authorities, such as the United States Environmental Protection Agency (“EPA”) and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them and frequently mandate difficult and costly remediation measures and other actions. Failure to comply with these laws, regulations and permits may result in the assessment of significant administrative, civil and criminal penalties, the imposition of investigatory remedial and corrective action obligations, the occurrence of delays in permitting and completion of projects, and the issuance of injunctive relief. For example, following an inadvertent return that occurred in connection with the construction of our Mariner East 2 pipeline (“Mariner 2”), the Pennsylvania Department of Environmental Protection in September 2020 ordered the rerouting of a section of Mariner 2. We have challenged this order and cannot predict the final outcome; however, any rerouting of Mariner 2 or other of our pipeline projects may result in delays in the completion of these projects.

Certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or wastes have been disposed or released, even under circumstances where the substances, hydrocarbons or wastes have been released by a predecessor operator. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property and natural resource damage allegedly caused by noise, odor or the release of hazardous substances, hydrocarbons or wastes into the environment.

We may incur substantial environmental costs and liabilities because of the underlying risk arising out of our operations. Although we have established financial reserves for our estimated environmental remediation liabilities, additional contamination or conditions may be discovered, resulting in increased remediation costs,

 

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liabilities or natural resource damages that could substantially increase our costs for site remediation projects. Accordingly, we cannot assure you that our current reserves are adequate to cover all future liabilities, even for currently known contamination.

Uncertainty about the future course of regulation exists because of the recent change in U.S. presidential administrations. In January 2021, the current administration issued an executive order directing all federal agencies to review and take action to address any federal regulations promulgated during the prior administration that may be inconsistent with the current administration’s policies. As a result, it is unclear the degree to which certain recent regulatory developments may be modified or rescinded. The executive order also established a Working Group that is called on to, among other things, develop methodologies for calculating the “social cost of carbon,” “social cost of nitrous oxide” and “social cost of methane.” Recommendations from the Working Group are due beginning June 1, 2021, and final recommendations no later than January 2022. Further regulation of air emissions, as well as uncertainty regarding the future course of regulation, could eventually reduce the demand for oil and natural gas and, in turn, have a material adverse effect on our business, financial condition or results of operations.

Changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, emission standards, or storage, transport, disposal or remediation requirements could have a material adverse effect on our operations or financial position. For example, in October 2015, the EPA published a final rule under the Clean Air Act, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone to 70 parts per billion for the 8-hour primary and secondary ozone standards, and the EPA finalized its attainment/non-attainment designations in 2018, though these are subject to change. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Also, states are expected to implement more stringent requirements as a result of this new final rule, which could apply to our customers’ operations. Compliance with this final rule or any other new regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines or new restrictions or prohibitions with respect to permits or projects, and significantly increase our capital expenditures and operating costs, which could adversely impact our business. Historically, we have been able to satisfy the more stringent nitrogen oxide emission reduction requirements that affect our compressor units in ozone non-attainment areas at reasonable cost, but there is no assurance that we will not incur material costs in the future to meet the new, more stringent ozone standard.

Regulations under the Clean Water Act, Oil Pollution Act of 1990, as amended (“OPA”), and state laws impose regulatory burdens on terminal operations. Spill prevention control and countermeasure requirements of federal and state laws require containment to mitigate or prevent contamination of waters in the event of a refined product overflow, rupture, or leak from above-ground pipelines and storage tanks. The Clean Water Act also requires us to maintain spill prevention control and countermeasure plans at our terminal facilities with above-ground storage tanks and pipelines. In addition, OPA requires that most fuel transport and storage companies maintain and update various oil spill prevention and oil spill contingency plans. Facilities that are adjacent to water require the engagement of Federally Certified Oil Spill Response Organizations to be available to respond to a spill on water from above-ground storage tanks or pipelines.

Transportation and storage of refined products over and adjacent to water involves risk and potentially subjects us to strict, joint, and potentially unlimited liability for removal costs and other consequences of an oil spill where the spill is into navigable waters, along shorelines or in the exclusive economic zone of the United States.

In the event of an oil spill into navigable waters, substantial liabilities could be imposed upon us. The Clean Water Act imposes restrictions and strict controls regarding the discharge of pollutants into navigable waters, with the potential of substantial liability for the violation of permits or permitting requirements.

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potentially significant air emissions, and operating permits may be required for sources that are already constructed. If regulations become more stringent, additional emission control technologies.

Climate change legislation or regulations restricting emissions of greenhouse gases (“GHGs”) could result in increased operating costs and reduced demand for the services we provide.

Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes and GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. In the United States, no comprehensive climate change legislation has been implemented at the federal level to date. However, Canada has implemented a federal carbon pricing regime, and, in the United States, President Biden has announced that he intends to pursue substantial reductions in greenhouse gas emissions, particularly from the oil and gas sector. For example, on January 27, 2021, President Biden signed an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, an increase in the production of offshore wind energy, and an increased emphasis on climate-related risks across government agencies and economic sectors. Additionally, the EPA has adopted rules under authority of the Clean Air Act that, among other things, establish Potential for Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal, or criteria, pollutant emissions, which reviews could require securing PSD permits at covered facilities emitting GHGs and meeting “best available control technology” standards for those GHG emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, including, among others, onshore processing, transmission, storage and distribution facilities. In October 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting facilities and blowdowns of natural gas transmission pipelines.

Federal agencies also have begun directly regulating GHG emissions, such as methane, from oil and natural gas operations. In June 2016, the EPA published New Source Performance Standards (“NSPS”), known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound (“VOC”) emissions. These Subpart OOOOa standards expand previously issued NSPS published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices, requiring additional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations. In September 2020, the EPA finalized amendments to Subpart OOOOa that rescind the methane limits for new, reconstructed and modified oil and natural gas production sources while leaving in place the general emission limits for VOCs. In addition, the rulemaking removes from the oil and natural gas category the natural gas transmission and storage segment. However, President Biden has signed an executive order calling for the suspension, revision, or rescission of the September 2020 rule and the reinstatement or issuance of methane emissions standards for new, modified, and existing oil and gas facilities, including the transmission and storage. Methane emission standards imposed on the oil and gas sector could result in increased costs to our operations or those of our customers as well as result in delays or curtailment in such operations, which costs, delays or curtailment could adversely affect our business. Several states have also adopted, or are considering, adopting, regulations related to GHG emissions, some of which are more stringent than those implemented by the federal government.

Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France in signing the “Paris Agreement,” a treaty that requires member countries to submit individually-determined, non-binding GHG emission reduction goals every five years beginning in 2020. Although the United States had withdrawn from

 

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this agreement, President Biden has signed executive orders recommitting the United States to the Paris Agreement and calling for the federal government to formulate the United States’ emissions reduction goal. However, the impacts of these orders are unclear at this time.

The adoption, strengthening and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our services, results of operations, and cash flows. Litigation risks are also increasing, as several oil and gas companies have been sued for allegedly causing climate-related damages due to their production and sale of fossil fuel products or for allegedly being aware of the impacts of climate change for some time but failing to adequately disclose such risks to their investors or customers. There is also a risk that financial institutions could be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. For example, recently, the Federal Reserve announced that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Ultimately, this could make it more difficult to secure funding for exploration and production or midstream activities. Finally, most scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events that could have an adverse effect on our assets.

The swaps regulatory provisions of the Dodd-Frank Act and the rules adopted thereunder could have an adverse effect on our ability to use derivative instruments to mitigate the risks of changes in commodity prices and interest rates and other risks associated with our business.

Provisions of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) and rules adopted by the Commodity Futures Trading Commission (the “CFTC”), the SEC and other prudential regulators establish federal regulation of the physical and financial derivatives, including over-the-counter derivatives market and entities, such as us, participating in that market. While most of these regulations are already in effect, the implementation process is still ongoing and the CFTC continues to review and refine its initial rulemakings through additional interpretations and supplemental rulemakings. As a result, any new regulations or modifications to existing regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability and/or liquidity of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. Any of these consequences could have a material adverse effect on our financial condition, results of operations and cash available for distribution to our Unitholders.

The CFTC has re-proposed speculative position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents, although certain bona fide hedging transactions would be exempt from these position limits provided that various conditions are satisfied. The CFTC has also finalized a related aggregation rule that requires market participants to aggregate their positions with certain other persons under common ownership and control, unless an exemption applies, for purposes of determining whether the position limits have been exceeded. If adopted, the revised position limits rule and its finalized companion rule on aggregation may create additional implementation or operational exposure. In addition to the CFTC federal speculative position limit regime, designated contract markets (“DCMs”) also maintain speculative position limit and accountability regimes with respect to contracts listed on their platform as well as aggregation requirements similar to the CFTC’s final aggregation rule. Any speculative position limit regime, whether imposed at the federal-level or at the DCM-level may impose added operating costs to monitor compliance with such position limit levels, addressing accountability level concerns and maintaining appropriate exemptions, if applicable.

The Dodd-Frank Act requires that certain classes of swaps be cleared on a derivatives clearing organization and traded on a DCM or other regulated exchange, unless exempt from such clearing and trading requirements, which could result in the application of certain margin requirements imposed by derivatives clearing organizations and

 

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their members. The CFTC and prudential regulators have also adopted mandatory margin requirements for uncleared swaps entered into between swap dealers and certain other counterparties. We currently qualify for and rely upon an end-user exception from such clearing and margin requirements for the swaps we enter into to hedge our commercial risks. However, the application of the mandatory clearing and trade execution requirements and the uncleared swaps margin requirements to other market participants, such as swap dealers, may adversely affect the cost and availability of the swaps that we use for hedging.

In addition to the Dodd-Frank Act, the European Union and other foreign regulators have adopted and are implementing local reforms generally comparable with the reforms under the Dodd-Frank Act. Implementation and enforcement of these regulatory provisions may reduce our ability to hedge our market risks with non-U.S. counterparties and may make transactions involving cross-border swaps more expensive and burdensome. Additionally, the lack of regulatory equivalency across jurisdictions may increase compliance costs and make it more difficult to satisfy our regulatory obligations.

Additional deepwater drilling laws and regulations, delays in the processing and approval of drilling permits and exploration, development, oil spill-response and decommissioning plans, and other related developments may have a material adverse effect on our business, financial condition, or results of operations.

The Federal Bureau of Ocean Energy Management (“BOEM”) and the federal Bureau of Safety and Environmental Enforcement (“BSEE”), each agencies of the United States Department of the Interior, have imposed more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. Compliance with these more stringent regulatory requirements and with existing environmental and oil spill regulations, together with any uncertainties or inconsistencies in decisions and rulings by governmental agencies, delays in the processing and approval of drilling permits or exploration, development, oil spill-response and decommissioning plans, and possible additional regulatory initiatives could result in difficult and more costly actions and adversely affect or delay new drilling and ongoing development efforts. For instance, in January 2021, the Biden administration issued an executive order focused on climate change that, among other things, directed the Secretary of the Interior to pause new oil and natural gas leasing on public lands or in offshore waters pending completion of a comprehensive review of the federal permitting and leasing practices, consider whether to adjust royalties associated with coal, oil, and gas resources extracted from public lands and offshore waters, or take other appropriate action, to account for corresponding climate costs.

In addition, new regulatory initiatives may be adopted or enforced by the BOEM or the BSEE in the future that could result in additional costs, delays, restrictions, or obligations with respect to oil and natural gas exploration and production operations conducted offshore by certain of our customers. Separately, in October 2020, BOEM and BSEE published a proposed rule regarding financial assurance requirements for offshore leases, particularly regarding requirements for bonds above base amounts prescribed by regulation. At this time, we cannot determine with any certainty the amount of any additional financial assurance that may be ordered by BOEM and required of us in the future, or that such additional financial assurance amounts can be obtained. The final publication or implementation of this rule, as well as any new rules, regulations, or legal initiatives, could delay or disrupt our customers’ operations, increase the risk of expired leases due to the time required to develop new technology, result in increased supplemental bonding and costs, limit activities in certain areas, or cause our customers’ to incur penalties, or shut-in production or lease cancellation. Also, if material spill events were to occur in the future, the United States or other countries could elect to issue directives to temporarily cease drilling activities offshore and, in any event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil and gas exploration and development. The overall costs imposed on our customers to implement and complete any such spill response activities or any decommissioning obligations could exceed estimated accruals, insurance limits, or supplemental bonding amounts, which could result in the incurrence of additional costs to complete. Separately, in January 2021, the Biden Administration has issued orders temporarily suspending the issuance of new authorizations and suspending the issuance of new leases pending completion of a review of current practices, for oil and gas development on federal lands and waters. The Biden Administration also published an order calling for an increase in the production of offshore wind

 

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energy, which may impact the use of federal waters. We cannot predict with any certainty the full impact of any new laws or regulations on our customers’ drilling operations or on the cost or availability of insurance to cover some or all of the risks associated with such operations. The occurrence of any one or more of these developments could result in decreased demand for our services, which could have a material adverse effect on our business as well as our financial position, results of operation and liquidity.

Our business is subject to federal, state and local laws and regulations that govern the product quality specifications of the petroleum products that we store and transport.

The petroleum products that we store and transport are sold by our customers for consumption into the public market. Various federal, state and local agencies have the authority to prescribe specific product quality specifications to commodities sold into the public market. Changes in product quality specifications could reduce our throughput volume, require us to incur additional handling costs or require the expenditure of significant capital. In addition, different product specifications for different markets impact the fungibility of products transported and stored in our pipeline systems and terminal facilities and could require the construction of additional storage to segregate products with different specifications. We may be unable to recover these costs through increased revenues.

In addition, our patented butane blending services are reliant upon gasoline vapor pressure specifications. Significant changes in such specifications could reduce butane blending opportunities, which would affect our ability to market our butane blending service licenses and which would ultimately affect our ability to recover the costs incurred to acquire and integrate our butane blending assets.

Risks Relating to Our Partnership Structure

Cash Distributions to Unitholders and Governance

Cash distributions are not guaranteed and may fluctuate with our performance and other external factors.

The amount of cash we can distribute to our Unitholders depends upon the amount of cash we generate from our operations and from our subsidiaries, Sunoco LP and USAC. The amount of cash we generate from our operations will fluctuate from quarter to quarter and will depend upon, among other things:

 

   

the amount of natural gas, NGLs, crude oil and refined products transported in our pipelines;

 

   

the level of throughput in our processing and treating operations;

 

   

the fees we charge and the margins we realize for our services;

 

   

the price of natural gas, NGLs, crude oil and refined products;

 

   

the relationship between natural gas, NGL and crude oil prices;

 

   

the weather in our operating areas;

 

   

the level of competition from other midstream, transportation and storage and other energy providers;

 

   

the level of our operating costs;

 

   

prevailing economic conditions; and

 

   

the level and results of our derivative activities.

In addition, the actual amount of cash we and our subsidiaries, including Sunoco LP and USAC, will have available for distribution will also depend on other factors, such as:

 

   

the level of capital expenditures we make;

 

   

the level of costs related to litigation and regulatory compliance matters;

 

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the cost of acquisitions, if any;

 

   

the levels of any margin calls that result from changes in commodity prices;

 

   

our debt service requirements;

 

   

fluctuations in our working capital needs;

 

   

our ability to borrow under our revolving credit facility;

 

   

our ability to access capital markets;

 

   

restrictions on distributions contained in our debt agreements; and

 

   

the amount of cash reserves established by our general partner in its discretion for the proper conduct of our business.

Because of all these factors, we cannot guarantee that we will have sufficient available cash to pay a specific level of cash distributions to our Unitholders.

Furthermore, our Unitholders should be aware that the amount of cash we have available for distribution depends primarily upon our cash flow and is not solely a function of profitability, which is affected by non-cash items. As a result, we may declare and/or pay cash distributions during periods when we record net losses.

Our distribution policy results in us making substantial cash distributions, which may limit cash available for future preferred distributions, debt service or to repay debt at maturity.

Our distribution policy is consistent with our partnership agreement, which requires us to distribute, on a quarterly basis, 100% of our Available Cash (as defined in our partnership agreement) to our Unitholders of record and our general partner. Available Cash is generally all of our cash on hand as of the end of a quarter, adjusted for cash distributions and net changes to reserves. Our general partner will determine the amount and timing of such distributions and has broad discretion to establish and make additions to our reserves or the reserves of our operating subsidiaries in amounts it determines in its reasonable discretion to be necessary or appropriate:

 

   

to provide for the proper conduct of our business and the businesses of our operating subsidiaries (including reserves for future capital expenditures and for our anticipated future credit needs);

 

   

to provide funds for distributions to our preferred unitholders; or

 

   

to comply with applicable law or any of our loan or other agreements.

Our general partner’s absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to our preferred unitholders.

Our partnership agreement permits the general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves may reduce the amount of cash available for distribution to preferred unitholders.

Unitholders may have liability to repay distributions.

Under certain circumstances, Unitholders may have to repay us amounts wrongfully distributed to them. Under Delaware law, we may not make a distribution to Unitholders if the distribution causes our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and non-recourse liabilities are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that a limited partner who receives such a distribution and knew at the time of the distribution that the

 

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distribution violated Delaware law, will be liable to the limited partnership for the distribution amount for three years from the distribution date.

The NYSE does not require a publicly traded partnership like us to comply with certain corporate governance requirements.

We have preferred units that are listed on the NYSE. Because we are a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, our Unitholders do not have the same protections afforded to stockholders of corporations that are subject to all of the corporate governance requirements of the applicable stock exchange.

Our General Partner

The control of our general partner may be transferred to a third party without Unitholder consent.

The general partner may transfer its general partner interest to a third party without the consent of the Unitholders. Furthermore, the general partner of our general partner may transfer its general partner interest in our general partner to a third party without the consent of the Unitholders. Any new owner of the general partner or the general partner of the general partner would be in a position to replace the officers of the general partner with its own choices and to control the decisions taken by such officers.

Cost reimbursements due to our general partner may be substantial and may reduce our ability to pay the distributions to Unitholders.

Prior to making any distributions to our Unitholders, we will reimburse our general partner for all expenses it has incurred on our behalf. In addition, our general partner and its affiliates may provide us with services for which we will be charged reasonable fees as determined by the general partner. The reimbursement of these expenses and the payment of these fees could adversely affect our ability to make distributions to the Unitholders. Our general partner has sole discretion to determine the amount of these expenses and fees.

Our Subsidiaries

We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets.

We are a holding company, and our subsidiaries conduct all of our operations and own all of our operating assets. We do not have significant assets other than the partnership interests and the equity in our subsidiaries. As a result, our ability to pay distributions to our Unitholders and to service our debt depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, credit facilities and applicable state partnership laws and other laws and regulations. If we are unable to obtain funds from our subsidiaries, we may not be able to pay distributions to our Unitholders or to pay interest or principal on our debt when due.

The interruption of distributions to us from our operating subsidiaries and equity investees may affect our ability to satisfy our obligations and to make distributions to our partners.

We are a holding company with no business operations other than that of our operating subsidiaries. Our only significant assets are the equity interests we own in our operating subsidiaries and equity investees. As a result, we depend upon the earnings and cash flow of our operating subsidiaries and equity investees and any interruption of distributions to us may affect our ability to meet our obligations, including any obligations under our debt agreements, and to make distributions to our partners.

 

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Sunoco LP and USAC may issue additional common units, which may increase the risk that either Sunoco LP or USAC will not have sufficient available cash to maintain or increase its per unit distribution level.

The partnership agreements of Sunoco LP and USAC allow each partnership to issue an unlimited number of additional limited partner interests. The issuance of additional common units or other equity securities by each respective partnership will have the following effects:

 

   

unitholders’ current proportionate ownership interest in each partnership will decrease;

 

   

the amount of cash available for distribution on each common unit or partnership security may decrease;

 

   

the ratio of taxable income to distributions may increase;

 

   

the relative voting strength of each previously outstanding common unit may be diminished; and

 

   

the market price of each partnership’s common units may decline.

The payment of distributions on any additional units issued by Sunoco LP and USAC may increase the risk that either partnership may not have sufficient cash available to maintain or increase its per unit distribution level, which in turn may impact the available cash that we have to meet our obligations.

A reduction in Sunoco LP’s distributions will disproportionately affect the amount of cash distributions to which ETO is entitled.

ETO indirectly owns all of the incentive distribution rights (“IDRs”) of Sunoco LP. These IDRs entitle the holder to receive increasing percentages of total cash distributions made by Sunoco LP as such entity reaches established target cash distribution levels as specified in its partnership agreement. ETO currently receives its pro rata share of cash distributions from Sunoco LP based on the highest sharing level of 50% in respect of the Sunoco LP IDRs.

A decrease in the amount of distributions by Sunoco LP to less than $0.65625 per unit per quarter would reduce ETO’s percentage of the incremental cash distributions from Sunoco LP above $0.546875 per unit per quarter from 50% to 25%. As a result, any such reduction in quarterly cash distributions from Sunoco LP would have the effect of disproportionately reducing the amount of all distributions that ETO receives, based on its ownership interest in the IDRs as compared to cash distributions received from its Sunoco LP common units.

A significant decrease in demand for motor fuel, including increased consumer preference for alternative motor fuels or improvements in fuel efficiency, in the areas Sunoco LP serves would reduce their ability to make distributions to its unitholders.

For the year ended December 31, 2020, sales of refined motor fuels accounted for approximately 96% of Sunoco LP’s total revenues and 72% of gross profit. A significant decrease in demand for motor fuel in the areas Sunoco LP serves could significantly reduce revenues and Sunoco LP’s ability to make distributions to its unitholders, including ETO. Sunoco LP revenues are dependent on various trends, such as trends in commercial truck traffic, travel and tourism in their areas of operation, and these trends can change. Regulatory action, including government imposed fuel efficiency standards, may also affect demand for motor fuel. Because certain of Sunoco LP’s operating costs and expenses are fixed and do not vary with the volumes of motor fuel distributed, their costs and expenses might not decrease ratably or at all should they experience such a reduction. As a result, Sunoco LP may experience declines in their profit margin if fuel distribution volumes decrease.

Any technological advancements, regulatory changes or changes in consumer preferences causing a significant shift toward alternative motor fuels could reduce demand for the conventional petroleum based motor fuels Sunoco LP currently sells. Additionally, a shift toward electric, hydrogen, natural gas or other alternative-power vehicles could fundamentally change customers’ shopping habits or lead to new forms of fueling destinations or new competitive pressures.

 

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New technologies have been developed and governmental mandates have been implemented to improve fuel efficiency, which may result in decreased demand for petroleum-based fuel. Any of these outcomes could result in fewer visits to Sunoco LP’s convenience stores or independently operated commission agents and dealer locations, a reduction in demand from their wholesale customers, decreases in both fuel and merchandise sales revenue, or reduced profit margins, any of which could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to its unitholders.

Sunoco LP’s financial condition and results of operations are influenced by changes in the prices of motor fuel, which may adversely impact margins, customers’ financial condition and the availability of trade credit.

Sunoco LP’s operating results are influenced by prices for motor fuel. General economic and political conditions, acts of war or terrorism and instability in oil producing regions, particularly in the Middle East and South America, could significantly impact crude oil supplies and petroleum costs. Significant increases or high volatility in petroleum costs could impact consumer demand for motor fuel and convenience merchandise. Such volatility makes it difficult to predict the impact that future petroleum costs fluctuations may have on Sunoco LP’s operating results and financial condition. Sunoco LP is subject to dealer tank wagon pricing structures at certain locations further contributing to margin volatility. A significant change in any of these factors could materially impact both wholesale and retail fuel margins, the volume of motor fuel distributed or sold at retail, and overall customer traffic, each of which in turn could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to its unitholders.

Significant increases in wholesale motor fuel prices could impact Sunoco LP as some of their customers may have insufficient credit to purchase motor fuel from us at their historical volumes. Higher prices for motor fuel may also reduce access to trade credit support or cause it to become more expensive.

The industries in which Sunoco LP operates are subject to seasonal trends, which may cause its operating costs to fluctuate, affecting its cash flow.

Sunoco LP relies in part on customer travel and spending patterns and may experience more demand for gasoline in the late spring and summer months than during the fall and winter. Travel, recreation and construction are typically higher in these months in the geographic areas in which Sunoco LP or its commission agents and dealers operate, increasing the demand for motor fuel that they sell and distribute. Therefore, Sunoco LP’s revenues and cash flows are typically higher in the second and third quarters of our fiscal year. As a result, Sunoco LP’s results from operations may vary widely from period to period, affecting Sunoco LP’s cash flow.

The dangers inherent in the storage and transportation of motor fuel could cause disruptions in Sunoco LP’s operations and could expose them to potentially significant losses, costs or liabilities.

Sunoco LP stores motor fuel in underground and aboveground storage tanks. Sunoco LP transports the majority of its motor fuel in its own trucks, instead of by third-party carriers. Sunoco LP’s operations are subject to significant hazards and risks inherent in transporting and storing motor fuel. These hazards and risks include, but are not limited to, traffic accidents, fires, explosions, spills, discharges, and other releases, any of which could result in distribution difficulties and disruptions, environmental pollution, governmentally-imposed fines or clean-up obligations, personal injury or wrongful death claims, and other damage to its properties and the properties of others. Any such event not covered by Sunoco LP’s insurance could have a material adverse effect on its business, financial condition, results of operations and cash available for distribution to its unitholders.

Sunoco LP’s fuel storage terminals are subject to operational and business risks which may adversely affect their financial condition, results of operations, cash flows and ability to make distributions to its unitholders.

Sunoco LP’s fuel storage terminals are subject to operational and business risks, the most significant of which include the following:

 

   

the inability to renew a ground lease for certain of their fuel storage terminals on similar terms or at all;

 

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the dependence on third parties to supply their fuel storage terminals;

 

   

outages at their fuel storage terminals or interrupted operations due to weather-related or other natural causes;

 

   

the threat that the nation’s terminal infrastructure may be a future target of terrorist organizations;

 

   

the volatility in the prices of the products stored at their fuel storage terminals and the resulting fluctuations in demand for storage services;

 

   

the effects of a sustained recession or other adverse economic conditions;

 

   

the possibility of federal and/or state regulations that may discourage their customers from storing gasoline, diesel fuel, ethanol and jet fuel at their fuel storage terminals or reduce the demand by consumers for petroleum products;

 

   

competition from other fuel storage terminals that are able to supply their customers with comparable storage capacity at lower prices; and

 

   

climate change legislation or regulations that restrict emissions of GHGs could result in increased operating and capital costs and reduced demand for our storage services.

The occurrence of any of the above situations, amongst others, may affect operations at their fuel storage terminals and may adversely affect Sunoco LP’s business, financial condition, results of operations, cash flows and ability to make distributions to its unitholders.

Negative events or developments associated with Sunoco LP’s branded suppliers could have an adverse impact on its revenues.

Sunoco LP believes that the success of its operations is dependent, in part, on the continuing favorable reputation, market value, and name recognition associated with the motor fuel brands sold at Sunoco LP’s convenience stores and at stores operated by its independent, branded dealers and commission agents. Erosion of the value of those brands could have an adverse impact on the volumes of motor fuel Sunoco LP distributes, which in turn could have a material adverse effect on its business, financial condition, results of operations and ability to make distributions to its unitholders.

Sunoco LP currently depends on a limited number of principal suppliers in each of its operating areas for a substantial portion of its merchandise inventory and its products and ingredients for its food service facilities. A disruption in supply or a change in either relationship could have a material adverse effect on its business.

Sunoco LP currently depends on a limited number of principal suppliers in each of its operating areas for a substantial portion of its merchandise inventory and its products and ingredients for its food service facilities. If any of Sunoco LP’s principal suppliers elect not to renew their contracts, Sunoco LP may be unable to replace the volume of merchandise inventory and products and ingredients currently purchased from them on similar terms or at all in those operating areas. Further, a disruption in supply or a significant change in Sunoco LP’s relationship with any of these suppliers could have a material adverse effect on Sunoco LP’s business, financial condition and results of operations and cash available for distribution to its unitholders.

The wholesale motor fuel distribution industry and convenience store industry are characterized by intense competition and fragmentation and impacted by new entrants. Failure to effectively compete could result in lower margins.

The market for distribution of wholesale motor fuel is highly competitive and fragmented, which results in narrow margins. Sunoco LP has numerous competitors, some of which may have significantly greater resources and name recognition than it does. Sunoco LP relies on its ability to provide value-added, reliable services and to

 

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control its operating costs in order to maintain our margins and competitive position. If Sunoco LP fails to maintain the quality of its services, certain of its customers could choose alternative distribution sources and margins could decrease. While major integrated oil companies have generally continued to divest retail sites and the corresponding wholesale distribution to such sites, such major oil companies could shift from this strategy and decide to distribute their own products in direct competition with Sunoco LP, or large customers could attempt to buy directly from the major oil companies. The occurrence of any of these events could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to its unitholders.

The geographic areas in which Sunoco LP operates and supplies independently operated commission agent and dealer locations are highly competitive and marked by ease of entry and constant change in the number and type of retailers offering products and services of the type we and our independently operated commission agents and dealers sell in stores. Sunoco LP competes with other convenience store chains, independently owned convenience stores, motor fuel stations, supermarkets, drugstores, discount stores, dollar stores, club stores, mass merchants and local restaurants. Over the past two decades, several non-traditional retailers, such as supermarkets, hypermarkets, club stores and mass merchants, have impacted the convenience store industry, particularly in the geographic areas in which Sunoco LP operates, by entering the motor fuel retail business. These non-traditional motor fuel retailers have captured a significant share of the motor fuels market, and Sunoco LP expects their market share will continue to grow.

In some of Sunoco LP’s markets, its competitors have been in existence longer and have greater financial, marketing, and other resources than they or their independently operated commission agents and dealers do. As a result, Sunoco LP’s competitors may be able to better respond to changes in the economy and new opportunities within the industry. To remain competitive, Sunoco LP must constantly analyze consumer preferences and competitors’ offerings and prices to ensure that they offer a selection of convenience products and services at competitive prices to meet consumer demand. Sunoco LP must also maintain and upgrade our customer service levels, facilities and locations to remain competitive and attract customer traffic to our stores. Sunoco LP may not be able to compete successfully against current and future competitors, and competitive pressures faced by Sunoco LP could have a material adverse effect on its business, results of operations and cash available for distribution to its unitholders.

Sunoco LP may be subject to adverse publicity resulting from concerns over food quality, product safety, health or other negative events or developments that could cause consumers to avoid its retail locations or independently operated commission agent or dealer locations.

Sunoco LP may be the subject of complaints or litigation arising from food-related illness or product safety which could have a negative impact on its business. Negative publicity, regardless of whether the allegations are valid, concerning food quality, food safety or other health concerns, food service facilities, employee relations or other matters related to its operations may materially adversely affect demand for its food and other products and could result in a decrease in customer traffic to its retail stores or independently operated commission agent or dealer locations.

It is critical to Sunoco LP’s reputation that they maintain a consistent level of high quality at their food service facilities and other franchise or fast food offerings. Health concerns, poor food quality or operating issues stemming from one store or a limited number of stores could materially and adversely affect the operating results of some or all of their stores and harm the company-owned brands, continuing favorable reputation, market value and name recognition.

 

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Sunoco LP does not own all of the land on which its retail service stations are located, and Sunoco LP leases certain facilities and equipment, and Sunoco LP is subject to the possibility of increased costs to retain necessary land use which could disrupt its operations.

Sunoco LP does not own all of the land on which its retail service stations are located. Sunoco LP has rental agreements for approximately 38% of the company, commission agent or dealer operated retail service stations where Sunoco LP currently controls the real estate. Sunoco LP also has rental agreements for certain logistics facilities. As such, Sunoco LP is subject to the possibility of increased costs under rental agreements with landowners, primarily through rental increases and renewals of expired agreements. Sunoco LP is also subject to the risk that such agreements may not be renewed. Additionally, certain facilities and equipment (or parts thereof) used by Sunoco LP are leased from third parties for specific periods. Sunoco LP’s inability to renew leases or otherwise maintain the right to utilize such facilities and equipment on acceptable terms, or the increased costs to maintain such rights, could have a material adverse effect on its financial condition, results of operations and cash flows.

Sunoco LP is subject to federal laws related to the Renewable Fuel Standard.

New laws, new interpretations of existing laws, increased governmental enforcement of existing laws or other developments could require us to make additional capital expenditures or incur additional liabilities. For example, certain independent refiners have initiated discussions with the EPA to change the way the Renewable Fuel Standard (“RFS”) is administered in an attempt to shift the burden of compliance from refiners and importers to blenders and distributors. Under the RFS, which requires an annually increasing amount of biofuels to be blended into the fuels used by U.S. drivers, refiners/importers are obligated to obtain renewable identification numbers (“RINS”) either by blending biofuel into gasoline or through purchase in the open market. If the obligation was shifted from the importer/refiner to the blender/distributor, the Partnership would potentially have to utilize the RINS it obtains through its blending activities to satisfy a new obligation and would be unable to sell RINS to other obligated parties, which may cause an impact on the fuel margins associated with Sunoco LP’s sale of gasoline. In addition, the RFS regulations are highly complex and evolving, and the RINS market is subject to significant price volatility as a result. The price of RINS to meet compliance obligations under the RFS could be substantial and adversely impact our financial condition.

The occurrence of any of the events described above could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to its unitholders.

Sunoco LP is subject to federal, state and local laws and regulations that govern the product quality specifications of refined petroleum products it purchases, stores, transports, and sells to its distribution customers.

Various federal, state, and local government agencies have the authority to prescribe specific product quality specifications for certain commodities, including commodities that Sunoco LP distributes. Changes in product quality specifications, such as reduced sulfur content in refined petroleum products, or other more stringent requirements for fuels, could reduce Sunoco LP’s ability to procure product, require it to incur additional handling costs and/or require the expenditure of capital. If Sunoco LP is unable to procure product or recover these costs through increased selling price, it may not be able to meet its financial obligations. Failure to comply with these regulations could result in substantial penalties for Sunoco LP.

USAC’s customers may choose to vertically integrate their operations by purchasing and operating their own compression fleet, increasing the number of compression units they currently own or using alternative technologies for enhancing crude oil production.

USAC’s customers that are significant producers, processors, gatherers and transporters of natural gas and crude oil may choose to vertically integrate their operations by purchasing and operating their own compression fleets

 

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in lieu of using USAC’s compression services. The historical availability of attractive financing terms from financial institutions and equipment manufacturers facilitates this possibility by making the purchase of individual compression units increasingly affordable to USAC’s customers. In addition, there are many technologies available for the artificial enhancement of crude oil production, and USAC’s customers may elect to use these alternative technologies instead of the gas lift compression services USAC provides. Such vertical integration, increases in vertical integration or use of alternative technologies could result in decreased demand for USAC’s compression services, which may have a material adverse effect on its business, results of operations, financial condition and reduce its cash available for distribution.

A significant portion of USAC’s services are provided to customers on a month-to-month basis, and USAC cannot be sure that such customers will continue to utilize its services.

USAC’s contracts typically have an initial term of between six months and five years, depending on the application and location of the compression unit. After the expiration of the initial term, the contract continues on a month-to-month or longer basis until terminated by USAC or USAC’s customers upon notice as provided for in the applicable contract. For the year ended December 31, 2020, approximately 30% of USAC’s compression services on a revenue basis were provided on a month-to-month basis to customers who continue to utilize its services following expiration of the primary term of their contracts. These customers can generally terminate their month-to-month compression services contracts on 30-days’ written notice. If a significant number of these customers were to terminate their month-to-month services, or attempt to renegotiate their month-to-month contracts at substantially lower rates, it could have a material adverse effect on USAC’s business, results of operations, financial condition and cash available for distribution.

USAC’s preferred units have rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of its common units.

USAC’s preferred units rank senior to all of its other classes or series of equity securities with respect to distribution rights and rights upon liquidation. These preferences could adversely affect the market price for its common units or could make it more difficult for USAC to sell its common units in the future.

In addition, distributions on USAC’s preferred units accrue and are cumulative, at the rate of 9.75% per annum on the original issue price, which amounts to a quarterly distribution of $24.375 per preferred unit. If USAC does not pay the required distributions on its preferred units, USAC will be unable to pay distributions on its common units. Additionally, because distributions on USAC’s preferred units are cumulative, USAC will have to pay all unpaid accumulated distributions on the preferred units before USAC can pay any distributions on its common units. Also, because distributions on USAC’s common units are not cumulative, if USAC does not pay distributions on its common units with respect to any quarter, USAC’s common unitholders will not be entitled to receive distributions covering any prior periods if USAC later recommences paying distributions on its common units.

USAC’s preferred units are convertible into common units by the holders of USAC’s preferred units or by USAC in certain circumstances. USAC’s obligation to pay distributions on USAC’s preferred units, or on the common units issued following the conversion of USAC’s preferred units, could impact USAC’s liquidity and reduce the amount of cash flow available for working capital, capital expenditures, growth opportunities, acquisitions and other general Partnership purposes. USAC’s obligations to the holders of USAC’s preferred units could also limit its ability to obtain additional financing or increase its borrowing costs, which could have an adverse effect on its financial condition.

 

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Risks Related to Conflicts of Interest

Our general partner has conflicts of interest and limited fiduciary responsibilities that may permit our general partner to favor its own interests to the detriment of Unitholders.

ET indirectly owns our general partner and as a result controls us. The directors and officers of our general partner and its affiliates have fiduciary duties to manage our general partner in a manner that is beneficial to ET, the sole owner of our general partner. At the same time, other than an implied contractual duty of good faith and fair dealing pursuant to our Partnership Agreement, we, and the officers and directors of our general partner, will not owe any duties, including fiduciary duties, to holders of our preferred units. Therefore, our general partner’s duties to us may conflict with the duties of its officers and directors to ET as its sole owner. As a result of these conflicts of interest, our general partner may favor its own interest or those of ET or their owners or affiliates over the interest of our Unitholders.

Such conflicts may arise from, among others, the following:

 

   

our partnership agreement eliminates and replaces the liability and reduces the fiduciary duties of our general partner while also restricting the remedies available to our Unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. Unitholders are deemed to have consented to some actions and conflicts of interest that might otherwise be deemed a breach of fiduciary or other duties under applicable state law.

 

   

our general partner is allowed to take into account the interests of parties in addition to us in resolving conflicts of interest, thereby limiting its fiduciary duties to us.

 

   

our general partner is allowed to take into account the interests of parties in addition to us, including ET, in resolving conflicts of interest, thereby limiting its fiduciary duties to us.

 

   

our general partner’s affiliates, including ET, are not prohibited from engaging in other businesses or activities, including those in direct competition with us.

 

   

our general partner determines the amount and timing of our asset purchases and sales, capital expenditures, borrowings, repayments of debt, issuances of equity and debt securities and cash reserves, each of which can affect the amount of cash that is distributed to Unitholders and to ET.

 

   

neither our partnership agreement nor any other agreement requires ET or its affiliates to pursue a business strategy that favors us. The directors and officers of the general partners of ET have a fiduciary duty to make decisions in the best interest of their members, limited partners and Unitholders, which may be contrary to our best interests.

 

   

some of the directors and officers of ET who provide advice to us also may devote significant time to the businesses of ET and will be compensated by them for their services.

 

   

our general partner determines which costs, including allocated overhead costs, are reimbursable by us.

 

   

our general partner is allowed to resolve any conflicts of interest involving us and our general partner and its affiliates, and any resolution of a conflict of interest by our general partner that is fair and reasonable to us will be deemed approved by all partners and will not constitute a breach of the partnership agreement.

 

   

our general partner controls the enforcement of obligations owed to us by it.

 

   

our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

 

   

our general partner is not restricted from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf.

 

   

our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, may be entitled to be indemnified by us.

 

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in some instances, our general partner may cause us to borrow funds in order to permit the payment of distributions, even if the purpose or effect of the borrowing is to make incentive distributions.

Although we control Sunoco LP and USAC through our ownership of Sunoco LP’s and USAC’s general partners, Sunoco LP’s and USAC’s general partners owe duties to Sunoco LP and Sunoco LP’s unitholders and USAC and USAC’s unitholders, respectively, which may conflict with our interests.

Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, on the one hand, and Sunoco LP and USAC and their respective limited partners, on the other hand. The directors and officers of Sunoco LP’s and USAC’s general partners have duties to manage Sunoco LP and USAC, respectively, in a manner beneficial to us. At the same time, the general partners have fiduciary duties to manage Sunoco LP and USAC in a manner beneficial to Sunoco LP and USAC and their respective limited partners. The boards of directors of Sunoco LP’s and USAC’s general partner will resolve any such conflict and have broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest.

For example, conflicts of interest with Sunoco LP and USAC may arise in the following situations:

 

   

the allocation of shared overhead expenses to Sunoco LP, USAC and us;

 

   

the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and Sunoco LP and USAC, on the other hand;

 

   

the determination of the amount of cash to be distributed to Sunoco LP’s and USAC’s partners and the amount of cash to be reserved for the future conduct of Sunoco LP’s and USAC’s businesses;

 

   

the determination whether to make borrowings under Sunoco LP’s and USAC’s revolving credit facilities to pay distributions to their respective partners;

 

   

the determination of whether a business opportunity (such as a commercial development opportunity or an acquisition) that we may become aware of independently of Sunoco LP and USAC is made available for Sunoco LP and USAC to pursue; and

 

   

any decision we make in the future to engage in business activities independent of Sunoco LP and USAC.

Some of our executive officers and directors face potential conflicts of interest in managing our business.

Certain of our executive officers and directors are also officers and/or directors of ET. These relationships may create conflicts of interest regarding corporate opportunities and other matters. The resolution of any such conflicts may not always be in our or our Unitholders’ best interests. In addition, these overlapping executive officers and directors allocate their time among us and ET. These officers and directors face potential conflicts regarding the allocation of their time, which may adversely affect our business, results of operations and financial condition.

Affiliates of our general partner may compete with us.

Except as provided in our partnership agreement, affiliates and related parties of our general partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us.

 

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Tax Risks to Stakeholders

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation. If the IRS were to treat us as a corporation for federal income tax purposes or if we become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our 6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Series A Preferred Units”), 6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Series B Preferred Units”), Series C Preferred Units, Series D Preferred Units, Series E Preferred Units, 6.750% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units (“Series F Preferred Units”), and 7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units (“Series G Preferred Units,” collectively, the “ETO Preferred Units”) depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS, with respect to our classification as a partnership for federal income tax purposes. Despite the fact that we are a limited partnership under Delaware law, we would be treated as a corporation for federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations and current Treasury Regulations, we believe we satisfy the qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax at the corporate tax rate, and we would likely pay additional state income taxes at varying rates. Distributions to holders of our ETO Preferred Units (“ETO Preferred Unitholders”) would generally be taxed again as corporate distributions and instead of guaranteed payments for the use of capital, as described further below. Because a tax would be imposed upon us as a corporation, our cash available to pay our debt securities and for distribution to ETO Preferred Unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the ETO Preferred Unitholders.

At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, or other forms of taxation. We currently own property or conduct business in many states that impose a margin or franchise tax. In the future, we may expand our operations. Imposition of a similar tax on us in the jurisdictions in which we operate or in other jurisdictions to which we may expand could substantially reduce our cash available to pay our debt securities and for distribution to our ETO Preferred Unitholders. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for U.S. federal, state, local or foreign income tax purposes, the target distribution amounts may be adjusted to reflect the impact of that law or interpretation on us.

The tax treatment of publicly traded partnerships or an investment in our ETO Preferred Units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

The present United States federal income tax treatment of publicly traded partnerships, including us, or an investment in our ETO Preferred Units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. Members of Congress have frequently proposed and considered substantive changes to the existing United States federal income tax laws that affect publicly traded partnerships, including proposals that would eliminate our ability to qualify for partnership tax treatment.

Any modification to the United States federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for United States federal income tax purposes. We are unable to predict whether any changes or other proposals will ultimately be enacted. Any future legislative

 

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changes could negatively impact the value of an investment in us. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in us.

If the IRS contests the federal income tax positions we take, the market for our ETO Preferred Units may be adversely affected and the costs of any such contest will reduce cash available to pay our debt securities and for distributions to our ETO Preferred Unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our ETO Preferred Units and the prices at which they trade. In addition, the costs of any contest between us and the IRS will result in a reduction in our cash available to pay our debt securities and for distribution to our ETO Preferred Unitholders and thus will be borne indirectly by our Unitholders.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us, in which case our cash available to pay our debt securities and for distribution to our ETO Preferred Unitholders might be substantially reduced.

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue an information statement to each ETO Preferred Unitholder and former ETO Preferred Unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our Unitholders and former Unitholders, including ETO Preferred Unitholders and former ETO Preferred Unitholders, take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current ETO Preferred Unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such ETO Preferred Unitholders did not own ETO Preferred Units during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available to pay our debt securities and for distribution to our ETO Preferred Unitholders might be substantially reduced.

ETO Preferred Unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

ETO Preferred Unitholders are required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income whether or not they receive cash distributions from us. ETO Preferred Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our ETO Preferred Units that may result in adverse tax consequences to them.

Investment in the ETO Preferred Units by tax-exempt investors, such as employee benefit plans and individual retirement accounts, and non-United States persons raises issues unique to them. The treatment of guaranteed payments for the use of capital to tax-exempt investors is not certain and such payments may be treated as unrelated business taxable income for federal income tax purposes. Distributions to non-United States ETO

 

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Preferred Unitholders will be subject to withholding taxes. If the amount of withholding exceeds the amount of United States federal income tax actually due, non-United States ETO Preferred Unitholders may be required to file United States federal income tax returns in order to seek a refund of such excess.

The Tax Act imposes a withholding obligation of 10% of the amount realized upon a non-United States ETO Preferred Unitholder’s sale or exchange of an interest in a partnership that is engaged in a United States trade or business. However, due to challenges of administering a withholding obligation applicable to open market trading and other complications, the IRS has temporarily suspended the application of this withholding rule to open market transfers of interests in publicly traded partnerships pending promulgation of regulations or other guidance that resolves the challenges. It is not clear if or when such regulations or other guidance will be finalized. Non-United States ETO Preferred Unitholders should consult a tax advisor before investing in our ETO Preferred Units.

We have subsidiaries that will be treated as corporations for federal income tax purposes and subject to corporate-level income taxes.

Even though we (as a partnership for United States federal income tax purposes) are not subject to United States federal income tax, some of our operations are currently conducted through subsidiaries that are organized as corporations for United States federal income tax purposes. The taxable income, if any, of subsidiaries that are treated as corporations for United States federal income tax purposes, is subject to corporate-level United States federal income taxes, which may reduce the cash available for distribution to us and, in turn, the cash available to pay our debt securities to our ETO Preferred Unitholders. If the IRS or other state or local jurisdictions were to successfully assert that these corporations have more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, the cash available for distribution could be further reduced. The income tax return filings positions taken by these corporate subsidiaries require significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is also required in assessing the timing and amounts of deductible and taxable items. Despite our belief that the income tax return positions taken by these subsidiaries are fully supportable, certain positions may be successfully challenged by the IRS, state or local jurisdictions.

An ETO Preferred Unitholder whose ETO Preferred Units are the subject of a securities loan (e.g. a loan to a “short seller”) to cover a short sale of ETO Preferred Units may be considered as having disposed of those ETO Preferred Units. If so, the ETO Preferred Unitholder would no longer be treated for tax purposes as a partner with respect to those ETO Preferred Units during the period of the loan and may recognize gain or loss from the disposition.

Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, an ETO Preferred Unitholder whose ETO Preferred Units are the subject of a securities loan may be considered as having disposed of the loaned ETO Preferred Units. In that case, the ETO Preferred Unitholder may no longer be treated for tax purposes as a partner with respect to those ETO Preferred Units during the period of the loan and may recognize gain or loss from such disposition. ETO Preferred Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan of their ETO Preferred Units are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their ETO Preferred Units.

ETO Preferred Unitholders will likely be subject to state and local taxes and income tax return filing requirements in jurisdictions where they do not live as a result of investing in our ETO Preferred Units.

In addition to United States federal income taxes, the ETO Preferred Unitholders may be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. ETO Preferred Unitholders may be required to file state and local

 

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income tax returns and pay state and local income taxes in some or all of the jurisdictions. ETO Preferred Unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, ETO Preferred Unitholders may be subject to penalties for failure to comply with those requirements. It is the responsibility of each ETO Preferred Unitholder to file all federal, state and local tax returns.

Treatment of distributions on our ETO Preferred Units as guaranteed payments for the use of capital is uncertain and such distributions may not be eligible for the 20% deduction for qualified publicly traded partnership income.

The tax treatment of distributions on our ETO Preferred Units is uncertain. We will treat ETO Preferred Unitholders as partners for tax purposes and will treat distributions on the ETO Preferred Units as guaranteed payments for the use of capital that will generally be taxable to ETO Preferred Unitholders as ordinary income. ETO Preferred Unitholders will recognize taxable income from the accrual of such a guaranteed payment (even in the absence of a contemporaneous cash distribution). Otherwise, except in the case of our liquidation, ETO Preferred Unitholders are generally not anticipated to share in our items of income, gain, loss or deduction, nor will we allocate any share of our nonrecourse liabilities to ETO Preferred Unitholders. If the ETO Preferred Units were treated as indebtedness for tax purposes, rather than as guaranteed payments for the use of capital, distributions likely would be treated as payments of interest by us to ETO Preferred Unitholders.

Although we expect that much of the income we earn is generally eligible for the 20% deduction for qualified publicly traded partnership income, it is uncertain whether a guaranteed payment for the use of capital may constitute an allocable or distributive share of such income. As a result, the guaranteed payment for use of capital received by our ETO Preferred Units may not be eligible for the 20% deduction for qualified publicly traded partnership income.

An ETO Preferred Unitholder will be required to recognize gain or loss on a sale of ETO Preferred Units equal to the difference between the amount realized by such ETO Preferred Unitholder and such ETO Preferred Unitholder’s tax basis in the ETO Preferred Units sold. The amount realized generally will equal the sum of the cash and the fair market value of other property such ETO Preferred Unitholder receives in exchange for such ETO Preferred Units. Subject to general rules requiring a blended basis among multiple partnership interests, the tax basis of an ETO Preferred Unit will generally be equal to the sum of the cash and the fair market value of other property paid by the ETO Preferred Unitholder to acquire such ETO Preferred Units. Gain or loss recognized by an ETO Preferred Unitholder on the sale or exchange of ETO Preferred Units held for more than one year generally will be taxable as long-term capital gain or loss. Because ETO Preferred Unitholders will generally not be allocated a share of our items of depreciation, depletion or amortization, it is not anticipated that such ETO Preferred Unitholders would be required to recharacterize any portion of their gain as ordinary income as a result of the recapture rules.

All ETO Preferred Unitholders are urged to consult a tax advisor with respect to the consequences of owning our ETO Preferred Units.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

A description of our properties is included in “Item 1. Business.” In addition, we own office buildings for our executive offices in Dallas, Texas and office buildings in Newton Square, Pennsylvania; Houston, Texas and San

 

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Antonio, Texas. While we may require additional office space as our business expands, we believe that our existing facilities are adequate to meet our needs for the immediate future, and that additional facilities will be available on commercially reasonable terms as needed.

We believe that we have satisfactory title to or valid rights to use all of our material properties. Although some of our properties are subject to liabilities and leases, liens for taxes not yet due and payable, encumbrances securing payment obligations under non-competition agreements and immaterial encumbrances, easements and restrictions, we do not believe that any such burdens will materially interfere with our continued use of such properties in our business, taken as a whole. In addition, we believe that we have, or are in the process of obtaining, all required material approvals, authorizations, orders, licenses, permits, franchises and consents of, and have obtained or made all required material registrations, qualifications and filings with, the various state and local government and regulatory authorities which relate to ownership of our properties or the operations of our business.

Substantially all of our pipelines, which are described in “Item 1. Business,” are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained, where necessary, easement agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, railroad properties and state highways, as applicable. In some cases, properties on which our pipelines were built were purchased in fee. We also own and operate multiple natural gas and NGL storage facilities and own or lease other processing, treating and conditioning facilities in connection with our midstream operations.

ITEM 3. LEGAL PROCEEDINGS

ETC Sunoco Holdings LLC and Sunoco (R&M), LLC (collectively, “Sunoco Defendants”) are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability, nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices claims. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees.

As of December 31, 2020, Sunoco Defendants are defendants in five cases, including one case each initiated by the States of Maryland and Rhode Island, one by the Commonwealth of Pennsylvania and two by the Commonwealth of Puerto Rico. The more recent Puerto Rico action is a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. The actions brought by the State of Maryland and Commonwealth of Pennsylvania have also named as defendants ETO, ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals L.P. (“SPMT”).

It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position.

In April 2016, PHMSA issued a Notice of Probable Violation, Proposed Compliance Order, and Proposed Civil Penalty related to certain welding practices and procedures followed during construction of ETO’s Permian Express 2 pipeline system in Texas. PHMSA subsequently issued a Final Order, and the related civil penalty has been paid. Additional penalties could be assessed related to ongoing compliance actions; however, the Partnership does not currently anticipate additional penalties.

In late 2016, FERC Enforcement Staff began a non-public investigation of Rover’s removal of the Stoneman House, a potential historic structure, in connection with Rover’s application for permission to construct a new

 

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interstate natural gas pipeline and related facilities. In mid-2017, FERC Enforcement Staff began a non-public investigation regarding allegations that diesel fuel may have been included in the drilling mud at the Tuscarawas River horizontal directional drilling (“HDD”) operations. Rover and the Partnership are cooperating with the investigations. Enforcement Staff has provided Rover its non-public preliminary findings regarding those investigations. The company disagrees with those findings and intends to vigorously defend against any potential penalty. Given the stage of the proceedings, and the non-public nature of the investigation, the Partnership is unable at this time to provide an assessment of the potential outcome or range of potential liability, if any.

On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (“Ohio EPA”) filed suit against Rover and other defendants (collectively, the “Defendants”) seeking to recover approximately $2.6 million in civil penalties allegedly owed and certain injunctive relief related to permit compliance. The Defendants filed several motions to dismiss, which were granted on all counts. The Ohio EPA appealed, and on December 9, 2019, the Fifth District court of appeals entered a unanimous judgment affirming the trial court. The Ohio EPA sought review from the Ohio Supreme Court. On April 22, 2020, the Ohio Supreme Court granted the review. Briefing has concluded and oral arguments were held on January 26, 2021, but no opinion has yet been issued.

Energy Transfer received an Administrative Compliance Order from the New Mexico Environmental Department on August 28, 2020 to settle the outstanding NOVs at its Jal 3 gas plant. The NOVs covered emission events that occurred January 1, 2017 through August 31, 2018. The Compliance Order includes an assessed civil penalty of $4,023,779.80. The proceedings in this case are stayed until May 17, 2021 to allow the parties to discuss possible settlement of this matter. Negotiations with the NMED are ongoing.

In January 2019, we received notice from the DOJ on behalf of the EPA that a civil penalty enforcement action was being pursued under the Clean Water Act for an estimated 450 barrel crude oil release from the Mid-Valley Pipeline operated by SPLP and owned by Mid-Valley Pipeline Corporation. The release purportedly occurred in October 2014 on a nature preserve located in Hamilton County, Ohio, near Cincinnati, Ohio. After discovery and notification of the release, SPLP conducted substantial emergency response, remedial work and primary restoration in three phases and the primary restoration has been acknowledged to be complete. Operation and maintenance (O&M) activities will continue for several years. In December of 2019, SPLP reached an agreement in principal with the EPA regarding payment of a civil penalty which will be subject to public comment. The DOJ, on behalf of United States Department of Interior Fish and Wildlife, and the Ohio Attorney General, on behalf of the Ohio EPA, along with technical representatives from those agencies have been discussing natural resource damage assessment claims related to state endangered species and compensatory restoration. The timing and outcome of these matters cannot be reasonably determined at this time; however, we do not expect there to be a material impact to our results of operations, cash flows or financial position.

On September 10, 2018, a pipeline release and fire (the “Incident”) occurred on the Revolution pipeline, a natural gas gathering line located in Center Township, Beaver County, Pennsylvania. There were no injuries. On February 8, 2019, the Pennsylvania Department of Environmental Protection (“PADEP”) issued a Permit Hold on any requests for approvals/permits or permit amendments for any project in Pennsylvania pursuant to the state’s water laws. The Partnership filed an appeal of the Permit Hold with the Pennsylvania Environmental Hearing Board. On January 3, 2020, the Partnership entered into a Consent Order and Agreement with the Department in which, among other things, the Permit Hold was lifted, the Partnership agreed to pay a $28.6 million civil penalty and fund a $2 million community environmental project, and all related appeals were withdrawn. On November 11, 2020, the PADEP issued an Order, which requires additional approvals and work prior to placing the Revolution Pipeline back in service. The Partnership filed an appeal of this Order with the Environmental Hearing Board on December 8, 2020.

The Pennsylvania Office of Attorney General has commenced an investigation regarding the Incident, and the United States Attorney for the Western District of Pennsylvania has issued a federal grand jury subpoena for documents relevant to the Incident. The scope of these investigations is not further known at this time.

 

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On June 4, 2019, the Oklahoma Corporation Commission’s (“OCC”) Transportation Division filed a complaint against SPLP seeking a penalty of up to $1 million related to a May 2018 rupture near Edmond, Oklahoma. The rupture occurred on the Noble to Douglas 8” pipeline in an area of external corrosion and caused the release of approximately fifteen barrels of crude oil. SPLP responded immediately to the release and remediated the surrounding environment and pipeline in cooperation with the OCC. The OCC filed the complaint alleging that SPLP failed to provide adequate cathodic protection to the pipeline causing the failure. SPLP is negotiating a settlement agreement with the OCC for a lesser penalty.

Additionally, we have received notices of violations and potential fines under various federal, state and local provisions relating to the discharge of materials into the environment or protection of the environment. While we believe that even if any one or more of the environmental proceedings listed above were decided against us, it would not be material to our financial position, results of operations or cash flows, we are required to report governmental proceedings if we reasonably believe that such proceedings will result in monetary sanctions in excess of $300,000.

For a description of other legal proceedings, see Note 10 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

 

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER

MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Description of Units

ETO Preferred Units

The Partnership currently has the following series of preferred units outstanding:

 

Series of Preferred Units

   Units Issued and
Outstanding
     Liquidation
Preference
per Unit
     Date Issued

6.250% Series A Fixed-to-Floating Rate Cumulative Perpetual Preferred Units

     950,000      $ 1,000      November 2017

6.625% Series B Fixed-to-Floating Rate Cumulative Perpetual Preferred Units

     550,000        1,000      November 2017

7.375% Series C Fixed-to-Floating Rate Cumulative Perpetual Preferred Units

     18,000,000        25      April 2018

7.625% Series D Fixed-to-Floating Rate Cumulative Perpetual Preferred Units

     17,800,000        25      July 2018

7.600% Series E Fixed-to-Floating Rate Cumulative Perpetual Preferred Units

     32,000,000        25      April 2019

6.750% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units

     500,000        1,000      January 2020

7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units

     1,100,000        1,000      January 2020

Additional information for each series of outstanding preferred units, including information on distributions and redemption, is available in Note 7 in the notes to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”

Cash Distribution Policy

General. We will distribute all of our “Available Cash” to our Unitholders within 45 days following the end of each fiscal quarter. Our general partner does not receive a distribution.

Definition of Available Cash. Available Cash is defined in our Partnership Agreement and generally means, with respect to any calendar quarter, all cash on hand at the end of such quarter:

 

   

Less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the General Partner to:

 

   

provide for the proper conduct of our business (including reserves for future capital expenditures and for our future capital needs);

 

   

comply with applicable law and/or debt instrument or other agreement; or

 

   

provide funds for distributions to the Preferred Unitholders.

 

   

Plus all cash on hand on the date of determination of Available Cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our credit facilities and in all cases used solely for working capital purposes or to pay distributions to partners.

 

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Available Cash is more fully defined in our Partnership Agreement, which is an exhibit to this report.

ITEM 6. SELECTED FINANCIAL DATA

The selected financial data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical consolidated financial statements and the accompanying notes thereto included elsewhere in this report. The amounts in the table below, except per unit data, are in millions.

As discussed in Note 2 to the consolidated financial statements in “Item 8. Financial Statements and Supplementary Data” the Partnership’s consolidated financial statements for all periods presented have been retrospectively adjusted to reflect the change in the accounting policy related to certain barrels of crude oil.

As discussed in Note 3 to the consolidated financial statements in “Item 8. Financial Statements and Supplementary Data” the sale and contribution transactions resulted in the retrospective adjustment to consolidate SemGroup and its former subsidiaries beginning December 5, 2019. Accordingly, the selected financial data below reflects the consolidated financial information of legacy ETO, adjusted for the effects of the events above.

 

     Years Ended December 31,  
     2020      2019      2018      2017      2016  

Statement of Operations Data:

              

Total revenues

   $ 38,954    $ 54,213    $ 54,087    $ 40,523    $ 31,792

Operating income

     2,999      7,222      5,457      2,714      1,933

Income from continuing operations

     311      5,115      4,094      2,901      869

Balance Sheet Data (at period end):

              

Assets held for sale

     —          —          —          3,313      3,588

Total assets

     96,742      102,294      88,609      86,596      79,147

Liabilities associated with assets held for sale

     —          —          —          75      48

Long-term debt, less current maturities

     51,345      50,904      37,853      36,971      36,251

Total equity

     32,950      37,425      36,788      37,079      29,101

Other Financial Data:

              

Capital expenditures:

              

Maintenance (accrual basis) (1)

     520      658      510      479      474

Growth (accrual basis) (1)

     3,239      4,610      5,120      5,601      5,775

Cash paid for acquisitions

     —          257      429      583      1,398

 

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

(Tabular dollar and unit amounts, except per unit data, are in millions)

The following discussion of our historical consolidated financial condition and results of operations should be read in conjunction with our historical consolidated financial statements and accompanying notes thereto included in “Item 8. Financial Statements and Supplementary Data” of this report. This discussion includes forward-looking statements that are subject to risk and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in “Item 1A. Risk Factors” included in this report.

References to “we,” “us,” “our,” the “Partnership” and “ETO” shall mean Energy Transfer Operating, L.P. and its subsidiaries.

Overview

The primary activities and operating subsidiaries through which we conduct those activities are as follows:

 

   

natural gas operations, including the following:

 

   

natural gas midstream and intrastate transportation and storage;

 

   

interstate natural gas transportation and storage; and

 

   

crude oil, NGL and refined products transportation, terminalling services and acquisition and marketing activities, as well as NGL storage and fractionation services.

In addition, we own investments in other businesses, including Sunoco LP and USAC, both of which are publicly traded master limited partnerships.

Recent Developments

COVID-19

In 2020, the COVID-19 pandemic prompted several states and municipalities in which we operate to take extraordinary and wide-ranging actions to contain and combat the outbreak and spread of the virus, including mandates for many individuals to substantially restrict daily activities and for many businesses to curtail or cease normal operations. To the extent COVID-19 continues or worsens, governments may impose additional similar restrictions. As a provider of critical energy infrastructure, our business has been designated as a “critical infrastructure sector” and our employees as “essential critical infrastructure workers” pursuant to the Department of Homeland Security Guidance on Essential Critical Infrastructure Workforce(s). To date, our field operations have continued uninterrupted, and remote work and other COVID-19 related conditions have not significantly impacted our ability to maintain operations or caused us to incur significant additional expenses; however, we are unable to predict the magnitude or duration of current and potential future COVID-19 mitigation measures. As an essential business providing critical energy infrastructure, the safety of our employees and the continued operation of our assets are our top priorities and we will continue to operate in accordance with federal and state health guidelines and safety protocols. We have implemented several new policies and provided employee training to help maintain the health and safety of our workforce.

ET Contribution of SemGroup Assets to ETO

On December 5, 2019, ET completed the acquisition of SemGroup. During the first and second quarters of 2020, ET contributed certain SemGroup assets to ETO through sale and contribution transactions. The Partnership and SemGroup are under common control by ET subsequent to ET’s acquisition of SemGroup; therefore, these

 

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transactions were accounted for as reorganizations of entities under common control. Accordingly, the Partnership’s consolidated financial statements have been retrospectively adjusted to reflect the consolidation of the contributed SemGroup businesses beginning December 5, 2019 (the date ET acquired SemGroup).

Series F and Series G Preferred Units Issuance

On January 22, 2020, ETO issued 500,000 of its 6.750% Series F Preferred Units at a price of $1,000 per unit and 1,100,000 of its 7.125% Series G Preferred Units at a price of $1,000 per unit. The net proceeds were used to repay amounts outstanding under ETO’s revolving credit facility and for general partnership purposes.

ETO January 2020 Senior Notes Offering and Redemption

On January 22, 2020, ETO completed a registered offering (the “January 2020 Senior Notes Offering”) of $1.00 billion aggregate principal amount of the Partnership’s 2.900% Senior Notes due 2025, $1.50 billion aggregate principal amount of the Partnership’s 3.750% Senior Notes due 2030 and $2.00 billion aggregate principal amount of the Partnership’s 5.000% Senior Notes due 2050, (collectively, the “Notes”). The Notes are fully and unconditionally guaranteed by the Partnership’s wholly-owned subsidiary, Sunoco Logistics Operations, on a senior unsecured basis.

Utilizing proceeds from the January 2020 Senior Notes Offering, ETO redeemed its $400 million aggregate principal amount of 5.75% Senior Notes due September 1, 2020, its $1.05 billion aggregate principal amount of 4.15% Senior Notes due October 1, 2020, its $1.14 billion aggregate principal amount of 7.50% Senior Notes due October 15, 2020, its $250 million aggregate principal amount of 5.50% Senior Notes due February 15, 2020, ET’s $52 million aggregate principal amount of 7.50% Senior Notes due October 15, 2020 and Transwestern’s $175 million aggregate principal amount of 5.36% Senior Notes due December 9, 2020. See “Liquidity and Capital Resources—Recent Financing Transactions” below for more information on the January 2020 Senior Notes Offering.

Lake Charles LNG

On March 30, 2020, Shell announced that it would not proceed with a proposed equity interest in the Lake Charles LNG liquefaction project due to adverse market factors affecting Shell’s business following the onset of the COVID-19 pandemic. We intend to continue to develop the project, possibly in conjunction with one or more equity partners, and we plan to evaluate a variety of alternatives to advance the project, including the possibility of reducing the size of the project from three trains (16.45 million tonnes per annum of LNG capacity) to two trains (11.0 million tonnes per annum). The project as currently designed is fully permitted by federal, state and local authorities, has all necessary export licenses and benefits from the infrastructure related to the existing regasification facility at the same site, including four LNG storage tanks, two deep water docks and other assets. In light of the existing brownfield infrastructure and the advanced state of the development of the project, we plan to continue to pursue the project on a disciplined, cost effective basis, and ultimately we will determine whether to make a final investment decision to proceed with the project based on market conditions, capital expenditure considerations and our success in securing equity participation by third parties as well as long-term LNG offtake commitments on satisfactory terms.

Sunoco LP November 2020 Senior Notes Offering and Repurchase

On November 9, 2020, Sunoco LP completed a private offering of $800 million in aggregate principal amount of 4.500% senior notes due 2029. Sunoco LP used the proceeds to fund the tender offer on its 4.875% $1 billion senior notes due 2023. Approximately 56% of the 2023 senior notes were tendered. On January 15, 2021, Sunoco LP repurchased the remaining outstanding portion of its 2023 senior notes.

 

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Regulatory Update

Interstate Natural Gas Transportation Regulation

Rate Regulation

Effective January 2018, the 2017 Tax Cuts and Jobs Act (the “Tax Act”) changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. On March 15, 2018, in a set of related proposals, the FERC addressed treatment of federal income tax allowances in regulated entity rates. The FERC issued a Revised Policy Statement on Treatment of Income Taxes (“Revised Policy Statement”) stating that it will no longer permit master limited partnerships to recover an income tax allowance in their cost-of-service rates. The FERC issued the Revised Policy Statement in response to a remand from the United States Court of Appeals for the District of Columbia Circuit in United Airlines v. FERC, in which the court determined that the FERC had not justified its conclusion that a pipeline organized as a master limited partnership would not “double recover” its taxes under the current policy by both including an income-tax allowance in its cost of service and earning a return on equity calculated using the discounted cash flow methodology. On July 18, 2018, the FERC issued an order denying requests for rehearing and clarification of its Revised Policy Statement. In the rehearing order, the FERC clarified that a pipeline organized as a master limited partnership will not be precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double-recovery of investors’ income tax costs. On July 31, 2020, the United States Court of Appeals for the District of Columbia Circuit issued an opinion upholding the FERC’s decision denying a separate master limited partnership recovery of an income tax allowance and its decision not to require the master limited partnership to refund accumulated deferred income tax balances. In light of the rehearing order’s clarification regarding individual entities’ ability to argue in support of recovery of an income tax allowance and the court’s subsequent opinion upholding denial of an income tax allowance to a master limited partnership, the impacts that FERC’s policy on the treatment of income taxes may have on the rates ETO can charge for FERC-regulated transportation services are unknown at this time.

Even without application of the FERC’s recent rate making-related policy statements and rulemakings, the FERC or our shippers may challenge the cost-of-service rates we charge. The FERC’s establishment of a just and reasonable rate is based on many components, including ROE and tax-related components, although changes in these components may tend to decrease our cost-of-service rate, other components in the cost-of-service rate calculation may increase and result in a newly calculated cost-of-service rate that is less than, the same as, or greater than the prior cost-of-service rate. Moreover, we receive revenues from our pipelines based on a variety of rate structures, including cost-of-service rates, negotiated rates, discounted rates and market-based rates. Many of our interstate pipelines, such as ETC Tiger Pipeline, LLC, Midcontinent Express and Fayetteville Express, have negotiated market rates that were agreed to by customers in connection with long-term contracts entered into to support the construction of the pipelines. Other systems, such as FGT, Transwestern and Panhandle, have a mix of tariff rate, discount rate, and negotiated rate agreements. The revenues we receive from natural gas transportation services we provide pursuant to cost-of-service based rates may decrease in the future as a result of the Revised Policy Statement, changes to ROE methodology, or other FERC policies, combined with the reduced corporate federal income tax rate established in the Tax Act. The extent of any revenue reduction related to our cost-of-service rates, if any, will depend on a detailed review of all of ETO’s cost-of-service components and the outcomes of any challenges to our rates by the FERC or our shippers.

On July 18, 2018, the FERC issued a final rule establishing procedures to evaluate rates charged by the FERC-jurisdictional gas pipelines in light of the Tax Act and the FERC’s Revised Policy Statement. By order issued January 16, 2019, the FERC initiated a review of Panhandle’s existing rates pursuant to Section 5 of the NGA to determine whether the rates currently charged by Panhandle are just and reasonable and set the matter for hearing. Panhandle filed a cost and revenue study on April 1, 2019 and an NGA Section 4 rate case on August 30, 2019. The Section 4 and Section 5 proceedings were consolidated by order of the Chief Judge on October 1, 2019. A hearing in the combined proceedings commenced on August 25, 2020 and adjourned on

 

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September 15, 2020. By order dated January 19, 2021, the Chief Judge has extended the deadline for the initial decision to March 26, 2021.

Pipeline Certification

The FERC issued a Notice of Inquiry on April 19, 2018 (“Pipeline Certification NOI”), thereby initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. We are unable to predict what, if any, changes may be proposed as a result of the Pipeline Certification NOI that will affect our natural gas pipeline business or when such proposals, if any, might become effective. Comments in response to the Pipeline Certification NOI were due on or before July 25, 2018. We do not expect that any change in this policy would affect us in a materially different manner than any other natural gas pipeline company operating in the United States.

Interstate Common Carrier Regulation

The FERC utilizes an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods, or PPI-FG. Many existing pipelines utilize the FERC liquids index to change transportation rates annually. The indexing methodology is applicable to existing rates, with the exclusion of market-based rates. The FERC’s indexing methodology is subject to review every five years. In a December 2020 order, FERC determined that during the five-year period commencing July 1, 2021 and ending June 30, 2026, common carriers charging indexed rates will be permitted to adjust their indexed ceilings annually by PPI-FG plus 0.78 percent. Requests for rehearing of the December 2020 order were filed on January 19, 2021, and remain pending before FERC. Accordingly, the FERC’s final determination of the index rate coupled with the anticipated and subsequent appeals of the December 2020 order could adversely impact the final determination of the FERC approved index.

FERC has also implemented changes related to its treatment of federal income taxes. The change in treatment impacts two rate components. Those components are the allowance for income taxes and the amount for accumulated deferred income taxes. These changes will primarily impact any cost-of-service related filing and our revenues associated with any cost-based service could be adversely affected by future FERC or judicial rulings. However, we believe that these impacts, if any, will be minimal.

Trends and Outlook

Recent market disruptions involving the COVID-19 pandemic have negatively impacted our earnings and cash flows from operations and may continue to do so. Reduced demand for natural gas, NGLs, refined products and/or crude oil caused by the COVID-19 pandemic and low WTI crude oil prices may result in the continued shut-in of production from U.S. oil and gas wells, which in turn may result in decreased volumes transported on our pipeline systems and decreased overall utilization of our midstream services.

With respect to commodity prices, natural gas prices have strengthened in recent months as a reduction in crude oil production has led to decreased supplies of associated natural gas from these wells. Meanwhile, crude oil prices saw a sharp decline as a result of actions by foreign oil-producing nations and a decrease in global demand as result of the COVID-19 pandemic but have subsequently risen and stabilized. We cannot predict the future impacts, or the duration of such impacts, from the COVID-19 pandemic.

The outlook for commodity prices is mixed and could have a varying impact on our business. Reduced demand and increased supply of crude oil has resulted in an increase in worldwide crude oil storage inventories, which is expected to keep crude oil prices depressed for the near term. With respect to natural gas markets, a relatively more moderate decrease in demand, coupled with the previously mentioned decreases in gas production

 

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associated with wells drilled to produce crude oil, have more than counterbalanced the reduction in demand. The overall outlook for our midstream services will depend, in part, on the timing and extent of recovery in the commodity markets.

While we anticipate that current and projected commodity prices and the related impact to activity levels in both the upstream and midstream sectors will impact our business, we cannot predict the ultimate magnitude of that impact and expect it to be varied across our operations, depending on the region, customer, type of service, contract term and other factors.

While the vast majority of our counterparties are investment grade rated companies, recent market disruptions increased the likelihood that some of our counterparties may be forced to file for bankruptcy protection. However, we believe that the recent increases in commodity prices, along with recent expense-cutting initiatives by many companies, have generally strengthened the credit profile for the majority of our producer counterparties.

Ultimately, the extent to which our business will be impacted by recent market developments depends on the factors described above as well as future developments beyond our control, which are highly uncertain and cannot be predicted. In response to these market events and uncertainties, we reduced 2020 growth capital spending, and we expect to continue to a lower level of growth capital spending going forward. See “Liquidity and Capital Resources” below for additional information on our forecasted capital expenditures. In 2020, we also reduced operating expenses, and we expect that our operating expenses going forward will continue to be lower relative to pre-2020 levels. While current market volatility makes the near-term unpredictable, we believe that overall the long-term demand for our services will continue given the essential nature of the midstream natural gas, NGLs, refined products and crude oil businesses, although we cannot predict any possible changes in such demand with reasonable certainty.

We currently have ample liquidity to fund our business and we do not anticipate any liquidity concerns in the immediate future (see “Liquidity and Capital Resources” below). In addition, while the trading price of ET common units declined significantly during the first nine months of 2020, thereby making equity capital market transactions less attractive in the near term, we continue to have access to the debt capital markets on generally favorable terms. In the event we seek additional equity or debt capital, our blended cost of capital for equity and debt is expected to be modestly higher in the near term; however, we will continue to evaluate growth projects and acquisitions as such opportunities may be identified in the future in light of this higher cost of capital.

In addition to the trends and outlook discussed above with respect to the Partnership’s existing business and finances, we also anticipate that the Partnership will continue to increase its focus on the development of alternative energy projects aimed at continuing to reduce its environmental footprint throughout its operations. In February 2021, the Partnership announced the creation of a new group focused on these efforts. The Partnership also recently announced its first-ever dedicated solar power contract, which will reduce the Partnership’s environmental footprint by integrating alternative energy sources when economically beneficial.

Results of Operations

We report Segment Adjusted EBITDA and consolidated Adjusted EBITDA as measures of segment performance. We define Segment Adjusted EBITDA and consolidated Adjusted EBITDA as total Partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Segment Adjusted EBITDA and consolidated Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same

 

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items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA and consolidated Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. The use of Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.

Segment Adjusted EBITDA, as reported for each segment in the table below, is analyzed for each segment in the section titled “Segment Operating Results.” Adjusted EBITDA is a non-GAAP measure used by industry analysts, investors, lenders and rating agencies to assess the financial performance and the operating results of the Partnership’s fundamental business activities and should not be considered in isolation or as a substitution for net income, income from operations, cash flows from operating activities or other GAAP measures.

Year Ended December 31, 2020 Compared to the Year Ended December 31, 2019

Consolidated Results

 

     Years Ended December 31,         
         2020              2019          Change  

Segment Adjusted EBITDA:

        

Intrastate transportation and storage

   $ 863    $ 999    $ (136

Interstate transportation and storage

     1,680      1,792      (112

Midstream

     1,670      1,602      68

NGL and refined products transportation and services

     2,802      2,666      136

Crude oil transportation and services

     2,258      2,898      (640

Investment in Sunoco LP

     739      665      74

Investment in USAC

     414      420      (6

All other

     115      106      9
  

 

 

    

 

 

    

 

 

 

Total Segment Adjusted EBITDA

     10,541      11,148      (607

Depreciation, depletion and amortization

     (3,669      (3,136      (533

Interest expense, net of interest capitalized

     (2,323      (2,262      (61

Impairment losses

     (2,880      (74      (2,806

Losses on interest rate derivatives

     (203      (241      38

Non-cash compensation expense

     (121      (113      (8

Unrealized losses on commodity risk management activities

     (71      (5      (66

Inventory valuation adjustments

     (82      79      (161

Losses on extinguishments of debt

     (72      (2      (70

Adjusted EBITDA related to unconsolidated affiliates

     (628      (626      (2

Equity in earnings of unconsolidated affiliates

     119      302      (183

Impairment of investment in an unconsolidated affiliate

     (129      —          (129

Other, net

     68      244      (176
  

 

 

    

 

 

    

 

 

 

Income before income tax expense

     550      5,314      (4,764

Income tax expense

     (239      (199      (40
  

 

 

    

 

 

    

 

 

 

Net income

   $ 311    $ 5,115    $ (4,804
  

 

 

    

 

 

    

 

 

 

 

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Adjusted EBITDA (consolidated). For the year ended December 31, 2020 compared to the prior year, Adjusted EBITDA decreased 5.4%, primarily due to the impacts of lower volumes and market prices among several of our core operating segments resulting primarily from COVID-19 related demand reductions. These decreases were partially offset by an increase of $136 million from our NGL and refined products transportation and services segment primarily due to higher throughput volumes, an increase of $68 million from our midstream segment primarily due to the restructuring and assignment of certain gathering and processing contracts, and an increase of $74 million from our investment in Sunoco LP segment primarily due to increased gross profit per gallon sold and a decrease in operating costs. The decrease in Adjusted EBITDA was also offset by a net increase of approximately $569 million from recent acquisitions and assets placed in service.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased primarily due to additional depreciation from assets recently placed in service and recent acquisitions.

Interest Expense, Net of Interest Capitalized. Interest expense, net of interest capitalized, increased during the year ended December 31, 2020 compared to the prior year primarily due to the following:

 

   

an increase of $57 million recognized by the Partnership (excluding Sunoco LP and USAC) primarily related to an increase in aggregate debt as a result of the SemGroup acquisition and the $4.2 billion of senior notes issued in the ET-ETO senior notes exchange (discussed below under “Description of Indebtedness”), the impact of which was partially offset by higher capitalized interest and lower borrowing costs realized on floating rate and refinanced debt;

 

   

an increase of $2 million recognized by USAC was primarily due to a full year of interest expense incurred in the current period on its senior notes 2027 issued in March 2019, partially offset by reduced borrowings and lower weighted average interest rates under its credit agreement; and

 

   

an increase of $2 million recognized by Sunoco LP due to a slight increase in average long-term debt.

Impairment Losses. During the year ended December 31, 2020, the Partnership recognized goodwill impairments totaling $2.2 billion and fixed asset impairments totaling $58 million, primarily due to decreases in projected future cash flows as a result of overall market demand decline. In addition, USAC recognized a goodwill impairment of $619 million as well as an equipment impairment of $8 million based on changes in market conditions.

During the year ended December 31, 2019, the Partnership recognized goodwill impairments totaling $21 million primarily due to changes in assumptions related to projected future revenues and cash flows. Also during the year ended December 31, 2019, Sunoco LP recognized a $47 million write-down on assets held for sale related to its ethanol plant in Fulton, New York, and USAC recognized a $6 million fixed asset impairment related to certain idle compressor assets.

Losses on Interest Rate Derivatives. Our interest rate derivatives are not designated as hedges for accounting purposes; therefore, changes in fair value are recorded in earnings each period. Losses on interest rate derivatives decreased by $38 million during the year ended December 31, 2020, compared to the prior year primarily due to a $400 million reduction in notional amount of outstanding forward-starting interest rate derivatives, which was partially offset by lower average interest rates and expenses related to the early termination and settlement of forward-starting interest rate derivatives.

Unrealized Losses on Commodity Risk Management Activities. The unrealized losses on our commodity risk management activities include changes in fair value of commodity derivatives and the hedged inventory included in designated fair value hedging relationships. Information on the unrealized gains and losses within each segment are included in “Segment Operating Results” below, and additional information on the commodity-related derivatives, including notional volumes, maturities and fair values, is available in “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and in Note 13 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”

 

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Inventory Valuation Adjustments. Inventory valuation reserve adjustments were recorded for the inventory associated with Sunoco LP primarily driven by changes in fuel prices between periods.

Losses on Extinguishments of Debt. Year ended December 31, 2020 amounts were related to ETO Senior Notes redemption in January 2020. In addition, Sunoco LP recognized a $13 million loss on extinguishment of debt related to the repurchase of its outstanding 2023 senior notes in 2020.

Impairment of Investments in Unconsolidated Affiliate. During the year ended December 31, 2020, the Partnership recorded an impairment to its investment in White Cliffs of $129 million due to a decrease in projected future revenues and cash flows as a result of the overall market demand decline that occurred subsequent to the SemGroup acquisition and related purchase price allocation in December 2019.

Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of Unconsolidated Affiliates. See additional information in “Supplemental Information on Unconsolidated Affiliates” and “Segment Operation Results” below.

Other, net. Other, net primarily includes amortization of regulatory assets and other income and expense amounts.

Income Tax Expense. For the year ended December 31, 2020 compared to the prior year, income tax expense increased due to higher earnings from the Partnership’s consolidated corporate subsidiaries in 2020 and the impact of a current state tax benefit (net of federal benefit) of $17 million in the prior year, which was primarily due to a change in estimate related to state income taxes in 2019.

Supplemental Information on Unconsolidated Affiliates

The following table presents financial information related to unconsolidated affiliates:

 

     Years Ended December 31,         
         2020              2019          Change  

Equity in earnings (losses) of unconsolidated affiliates:

        

Citrus

   $ 162    $ 148    $ 14

FEP (1)

     (139      59      (198

MEP

     (6      15      (21

White Cliffs

     20      4      16

Other

     82      76      6
  

 

 

    

 

 

    

 

 

 

Total equity in earnings of unconsolidated affiliates

   $ 119    $ 302    $ (183
  

 

 

    

 

 

    

 

 

 

Adjusted EBITDA related to unconsolidated affiliates(2):

        

Citrus

   $ 347    $ 342    $ 5

FEP

     76      75      1

MEP

     28      60      (32

White Cliffs

     44      —          44

Other

     133      149      (16
  

 

 

    

 

 

    

 

 

 

Total Adjusted EBITDA related to unconsolidated affiliates

   $ 628    $ 626    $ 2
  

 

 

    

 

 

    

 

 

 

 

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     Years Ended December 31,         
         2020              2019          Change  

Distributions received from unconsolidated affiliates:

        

Citrus

   $ 191    $ 178    $ 13

FEP

     75      73      2

MEP

     26      36      (10

White Cliffs

     29      —          29

Other

     85      101      (16
  

 

 

    

 

 

    

 

 

 

Total distributions received from unconsolidated affiliates

   $ 406    $ 388    $ 18
  

 

 

    

 

 

    

 

 

 

 

(1)

For the year ended December 31, 2020, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by FEP, which reduced the Partnership’s equity in earnings by $208 million.

(2)

These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, depletion, amortization, non-cash items and taxes.

Segment Operating Results

We evaluate segment performance based on Segment Adjusted EBITDA, which we believe is an important performance measure of the core profitability of our operations. This measure represents the basis of our internal financial reporting and is one of the performance measures used by senior management in deciding how to allocate capital resources among business segments.

The tables below identify the components of Segment Adjusted EBITDA, which is calculated as follows:

 

   

Segment margin, operating expenses, and selling, general and administrative expenses. These amounts represent the amounts included in our consolidated financial statements that are attributable to each segment.

 

   

Unrealized gains or losses on commodity risk management activities and inventory valuation adjustments. These are the unrealized amounts that are included in cost of products sold to calculate segment margin. These amounts are not included in Segment Adjusted EBITDA; therefore, the unrealized losses are added back and the unrealized gains are subtracted to calculate the segment measure.

 

   

Non-cash compensation expense. These amounts represent the total non-cash compensation recorded in operating expenses and selling, general and administrative expenses. This expense is not included in Segment Adjusted EBITDA and therefore is added back to calculate the segment measure.

 

   

Adjusted EBITDA related to unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates.

In the following analysis of segment operating results, a measure of segment margin is reported for segments with sales revenues. Segment margin is a non-GAAP financial measure and is presented herein to assist in the analysis of segment operating results and particularly to facilitate an understanding of the impacts that changes in sales revenues have on the segment performance measure of Segment Adjusted EBITDA. Segment margin is similar to the GAAP measure of gross margin, except that segment margin excludes charges for depreciation, depletion and

 

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amortization. Among the GAAP measures reported by the Partnership, the most directly comparable measure to segment margin is Segment Adjusted EBITDA; a reconciliation of segment margin to Segment Adjusted EBITDA is included in the following tables for each segment where segment margin is presented.

In addition, for certain segments, the sections below include information on the components of segment margin by sales type, which components are included in order to provide additional disaggregated information to facilitate the analysis of segment margin and Segment Adjusted EBITDA. For example, these components include transportation margin, storage margin, and other margin. These components of segment margin are calculated consistent with the calculation of segment margin; therefore, these components also exclude charges for depreciation, depletion and amortization.

For additional information regarding our business segments, see “Item 1. Business” and Notes 1 and 16 to our consolidated financial statements in “Item 8. Financial Statements and Supplementary Data.”

Segment Operating Results

Intrastate Transportation and Storage

 

     Years Ended December 31,         
         2020              2019          Change  

Natural gas transported (BBtu/d)

     12,649      12,442      207

Revenues

   $ 2,544    $ 3,099    $ (555

Cost of products sold

     1,478      1,909      (431
  

 

 

    

 

 

    

 

 

 

Segment margin

     1,066      1,190      (124

Unrealized (gains) losses on commodity risk management activities

     (25      2      (27

Operating expenses, excluding non-cash compensation expense

     (177      (190      13

Selling, general and administrative expenses, excluding non-cash compensation expense

     (28      (29      1

Adjusted EBITDA related to unconsolidated affiliates

     25      25      —    

Other

     2      1      1
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 863    $ 999    $ (136
  

 

 

    

 

 

    

 

 

 

Volumes. For the year ended December 31, 2020 compared to the prior year, transported volumes increased primarily due to increased utilization of our Texas pipelines, partially offset by a decrease in volumes as a result of the bankruptcy filing of a transportation customer.

Segment Margin. The components of our intrastate transportation and storage segment margin were as follows:

 

     Years Ended December 31,         
         2020              2019          Change  

Transportation fees

   $ 617    $ 614    $ 3

Natural gas sales and other (excluding unrealized gains and losses)

     317      505      (188

Retained fuel revenues (excluding unrealized gains and losses)

     48      50      (2

Storage margin, including fees (excluding unrealized gains and losses)

     59      23      36

Unrealized gains (losses) on commodity risk management activities

     25      (2      27
  

 

 

    

 

 

    

 

 

 

Total segment margin

   $ 1,066    $ 1,190    $ (124
  

 

 

    

 

 

    

 

 

 

 

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Segment Adjusted EBITDA. For the year ended December 31, 2020 compared to the prior year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment decreased due to the net impacts of the following:

 

   

a decrease of $188 million in realized natural gas sales and other due to lower realized gains from pipeline optimization activity; and

 

   

a decrease of $2 million in retained fuel revenues primarily due to lower natural gas prices; offset by

 

   

an increase of $36 million in realized storage margin primarily due to higher realized gains on financial derivatives used to hedge physical storage gas;

 

   

a decrease of $13 million in operating expenses primarily due to a $5 million decrease in outside services, a $4 million decrease in employee costs, a $3 million decrease in maintenance project costs and a $2 million decrease in ad valorem taxes; and

 

   

an increase of $3 million in transportation fees primarily due to volume ramp-ups on Red Bluff Express pipeline and new contracts partially offset by the expansion of certain contracts on Regency Intrastate Gas Systems,

Interstate Transportation and Storage

 

     Years Ended December 31,         
         2020              2019          Change  

Natural gas transported (BBtu/d)

     10,325      11,346      (1,021

Natural gas sold (BBtu/d)

     16      17      (1

Revenues

   $ 1,861    $ 1,963    $ (102

Operating expenses, excluding non-cash compensation, amortization and accretion expenses

     (567      (569      2

Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses

     (59      (72      13

Adjusted EBITDA related to unconsolidated affiliates

     451      477      (26

Other

     (6      (7      1
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 1,680    $ 1,792    $ (112
  

 

 

    

 

 

    

 

 

 

Volumes. For the year ended December 31, 2020 compared to the prior year, transported volumes decreased primarily due to lower crude production resulting in lower associated gas production and contract expirations on our Tiger Pipeline, as well as multiple weather events and maintenance of third-party facilities impacting our assets along the Gulf Coast.

Segment Adjusted EBITDA. For the year ended December 31, 2020 compared to the prior year, Segment Adjusted EBITDA related to our interstate transportation and storage segment decreased due to the net impacts of the following:

 

   

a decrease of $102 million in revenues primarily due to a decrease of $63 million from a contractual rate adjustment on commitments at our Lake Charles LNG facility effective January 2020, a decrease of $30 million due to additional revenue recognized in 2019 associated with a shipper bankruptcy, a decrease of $28 million due to lower utilization and lower rates on our Panhandle and Trunkline systems, a decrease of $12 million in transportation fees as a result of multiple weather events and maintenance on third-party facilities connected to our systems, and a decrease of $8 million resulting from contract expirations on ETC Tiger. These decreases were partially offset by higher reservation revenue on Transwestern and Rover resulting from higher contracted capacity and higher parking revenue resulting from timing of transactions; and

 

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a decrease of $26 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to lower earnings from our Midcontinent Express Pipeline primarily as a result of lower rates received following the expiration of certain contracts, partially offset by an increase from Citrus primarily due to higher revenues resulting from new contracts, rate increases on existing contracts, the recognition of a contract exit fee and lower operating expenses; partially offset by

 

   

a decrease of $2 million in operating expense primarily due to $22 million in refunds of ad valorem taxes on Transwestern and lower current year assessments, a $13 million decrease in employee costs and a $9 million decrease in maintenance project costs resulting from cost-cutting initiatives, partially offset by $38 million in bad debt expense associated with a shipper bankruptcy and a $5 million increase related to the valuation of inventory on Panhandle; and

 

   

a decrease of $13 million in selling, general and administrative expenses primarily resulting from a $17 million favorable settlement related to excise taxes on Rover and a $5 million decrease in employee costs due to cost-cutting initiatives, partially offset by a $4 million increase in legal and consulting fees related to an ongoing rate case and shipper bankruptcies and a $3 million increase in allocated overhead costs.

Midstream

 

     Years Ended December 31,         
         2020              2019          Change  

Gathered volumes (BBtu/d)

     12,961      13,468      (507

NGLs produced (MBbls/d)

     611      571      40

Equity NGLs (MBbls/d)

     35      31      4

Revenues

   $ 5,026    $ 6,031    $ (1,005

Cost of products sold

     2,598      3,577      (979
  

 

 

    

 

 

    

 

 

 

Segment margin

     2,428      2,454      (26

Operating expenses, excluding non-cash compensation expense

     (705      (791      86

Selling, general and administrative expenses, excluding non-cash compensation expense

     (87      (90      3

Adjusted EBITDA related to unconsolidated affiliates

     31      27      4

Other

     3      2      1
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 1,670    $ 1,602    $ 68
  

 

 

    

 

 

    

 

 

 

Volumes. For the year ended December 31, 2020 compared to the prior year, gathered volumes decreased primarily in the South Texas and Northeast regions, partially offset by the impact of the SemGroup acquisition in the Mid-Continent/Panhandle region and volume growth in the Ark-La-Tex and Permian regions. NGL production increased due to the impact of the SemGroup acquisition in the Mid-Continent/Panhandle region and ethane uplift in the Permian, South Texas and North Texas regions.

Segment Margin. The table below presents the components of our midstream segment margin.

 

     Years Ended December 31,         
         2020              2019          Change  

Gathering and processing fee-based revenues

   $ 2,187    $ 2,132    $ 55

Non-fee-based contracts and processing

     241      322      (81
  

 

 

    

 

 

    

 

 

 

Total segment margin

   $ 2,428    $ 2,454    $ (26
  

 

 

    

 

 

    

 

 

 

 

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Segment Adjusted EBITDA. For the year ended December 31, 2020 compared to the prior year, Segment Adjusted EBITDA related to our midstream segment increased due to the net impacts of the following:

 

   

an increase of $55 million in fee-based margin due to the impact of the SemGroup acquisition in the Mid-Continent/Panhandle region and recognized $103 million related to the restructuring and assignment of certain gathering and processing contracts in the Ark-La-Tex region, which included the recognition of $75 million of deferred revenue received in prior periods. This increase was partially offset by the impact of volume declines in the South Texas region;

 

   

a decrease of $86 million in operating expenses due to cost-saving initiatives, including a decrease of $39 million in outside services, $25 million in materials, $14 million in employee costs and $8 million in office expenses; and

 

   

a decrease of $3 million in selling, general and administrative expenses due to a decrease in allocated overhead costs resulting from overall corporate cost reductions; partially offset by

 

   

a decrease of $70 million in non-fee-based margin due to unfavorable NGL prices of $75 million and favorable natural gas prices of $5 million; and

 

   

a decrease of $11 million in non-fee-based margin due to decreased throughput volume, primarily in the South Texas region.

NGL and Refined Products Transportation and Services

 

     Years Ended December 31,         
         2020              2019          Change  

NGL transportation volumes (MBbls/d)

     1,436      1,289      147

Refined products transportation volumes (MBbls/d)

     461      583      (122

NGL and refined products terminal volumes (MBbls/d)

     825      844      (19

NGL fractionation volumes (MBbls/d)

     835      706      129

Revenues

   $ 10,513    $ 11,641    $ (1,128

Cost of products sold

     7,139      8,393      (1,254
  

 

 

    

 

 

    

 

 

 

Segment margin

     3,374      3,248      126

Unrealized losses on commodity risk management activities

     78      81      (3

Operating expenses, excluding non-cash compensation expense

     (650      (656      6

Selling, general and administrative expenses, excluding non-cash compensation expense

     (82      (93      11

Adjusted EBITDA related to unconsolidated affiliates

     82      86      (4
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 2,802    $ 2,666    $ 136
  

 

 

    

 

 

    

 

 

 

Volumes. For the year ended December 31, 2020 compared to the prior year, NGL transportation volumes increased due to higher throughput volumes on our Mariner East pipeline system. In addition, throughput barrels on our Texas NGL pipeline system increased due to higher receipt of liquids production from both wholly-owned and third-party gas plants primarily in the Permian and North Texas regions, as well as higher export volumes feeding into our Nederland Terminal resulting from the initiation of service on our propane export pipeline in the fourth quarter of 2020.

Refined products transportation volumes decreased for the year ended December 31, 2020 compared to prior year due to the closure of a third-party refinery during the third quarter of 2019, which negatively impacted supply to

 

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our refined products transportation system, and less domestic demand for jet fuel and other refined products. These decreases in volumes were partially offset by the initiation of service of our JC Nolan diesel fuel pipeline in the third quarter of 2019.

NGL and refined products terminal volumes decreased for the year ended December 31, 2020 compared to the prior year primarily due to the closure of a third-party refinery during the third quarter of 2019 and less domestic demand for jet fuel and other refined products. These decreases were partially offset by higher volumes from our Mariner East system, an increase in loaded vessels at our Nederland Terminal, and the initiation of service on our JC Nolan diesel fuel pipeline and natural gasoline export project, both of which commences service in the third quarter of 2019.

Average fractionated volumes at our Mont Belvieu, Texas fractionation facility increased for the year ended December 31, 2020 compared to the prior year primarily due to the commissioning of our sixth and seventh fractionators in February 2019 and February 2020, respectively.

Segment Margin. The components of our NGL and refined products transportation and services segment margin were as follows:

 

     Years Ended December 31,         
         2020              2019          Change  

Fractionators and refinery services margin

   $ 726    $ 664    $ 62

Transportation margin

     1,895      1,716      179

Storage margin

     250      223      27

Terminal Services margin

     541      630      (89

Marketing margin

     40      96      (56

Unrealized gains on commodity risk management activities

     (78      (81      3
  

 

 

    

 

 

    

 

 

 

Total segment margin

   $ 3,374    $ 3,248    $ 126
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA. For the year ended December 31, 2020 compared to the prior year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impacts of the following:

 

   

an increase of $179 million in transportation margin primarily due to a $128 million increase from higher throughput volumes on our Mariner East pipeline system, a $53 million increase from higher throughput volumes received from the Permian region, a $17 million increase due to the initiation of service on our JC Nolan diesel fuel pipeline in the third quarter of 2019, a $14 million increase from higher throughput volumes from the Barnett region, a $12 million increase from higher volumes from the South Texas region and a $3 million increase due to higher throughput on our Mariner West pipeline. These increases were partially offset by a $17 million decrease from lower throughput volumes received from the Eagle Ford region, a $16 million decrease due to less demand for jet fuel and other refined products, and a $13 million decrease resulting from the closure of a third-party refinery during the third quarter of 2019;

 

   

an increase of $62 million in fractionators and refinery services margin primarily due to a $57 million increase resulting from the commissioning of our sixth and seventh fractionators in February 2019 and February 2020, respectively, and higher NGL volumes from the Permian and Barnett regions feeding our Mont Belvieu fractionation facility, and a $9 million increase in rail and truck volumes feeding our refinery services facility. These increases were partially offset by a $7 million decrease due primarily to an expiration of a third-party blending contract during the second quarter of 2020;

 

   

an increase of $27 million in storage margin primarily due to a $16 million increase from throughput fees generated from exported volumes and an $11 million increase from component product storage fees; and

 

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a decrease of $11 million in selling, general and administrative expenses primarily due to lower allocated overhead costs and lower employee costs resulting from cost-cutting initiatives; partially offset by

 

   

a decrease of $89 million in terminal services margin primarily due to a $90 million decrease resulting from an expiration of a third-party contract at our Nederland Terminal in the second quarter of 2020, a $29 million decrease due to lower third-party and intercompany volumes feeding our Marcus Hook Terminal, a $16 million decrease due to lower expense reimbursements in 2020, and a $14 million decrease due to less domestic demand for jet fuel and other refined products. These decreases were partially offset by a $60 million increase due to higher throughput on our Mariner East system; and

 

   

a decrease of $56 million in marketing margin primarily due to an $87 million decrease due to lower margin from our butane blending business, a $37 million decrease in gasoline blending and optimization due primarily to unfavorable market conditions primarily attributable to the COVID-19 pandemic. These decreases were partially offset by a $47 million increase due to higher optimization gains from the sale of NGL component products at our Mont Belvieu facility and a $21 million increase in NGL export and rack volumes.

Crude Oil Transportation and Services

 

     Years Ended December 31,         
         2020              2019          Change  

Crude transportation volumes (MBbls/d)

     3,763      4,217      (454

Crude terminals volumes (MBbls/d)

     2,553      2,513      40

Revenue

   $ 11,679    $ 18,447    $ (6,768

Cost of products sold

     8,838      14,832      (5,994
  

 

 

    

 

 

    

 

 

 

Segment margin

     2,841      3,615      (774

Unrealized (gains) losses on commodity risk management activities

     12      (69      81

Operating expenses, excluding non-cash compensation expense

     (526      (570      44

Selling, general and administrative expenses, excluding non-cash compensation expense

     (118      (85      (33

Adjusted EBITDA related to unconsolidated affiliates

     37      8      29

Other

     12      (1      13
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 2,258    $ 2,898    $ (640
  

 

 

    

 

 

    

 

 

 

Volumes. For the year ended December 31, 2020 compared to the prior year, crude transportation volumes were lower on our Texas pipeline system and our Bakken pipeline, driven by lower production in these regions due to lower crude oil prices as well as lower refinery utilization caused by COVID-19 demand destruction, partially offset by contributions from assets acquired in 2019. Crude terminal volumes were higher due to contributions from assets acquired in 2019, partially offset by lower Permian and Bakken pipeline volumes, reduced refinery utilization, and reduced export demand at our Nederland Terminal.

Segment Adjusted EBITDA. For the year ended December 31, 2020 compared to the prior year, Segment Adjusted EBITDA related to our crude oil transportation and services segment decreased due to the net impacts of the following:

 

   

a decrease of $693 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $430 million decrease from our Texas crude pipeline system due to lower utilization and lower average tariff rates realized, a $286 million decrease (excluding a net change

 

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of $84 million in unrealized gains and losses on commodity risk management activities) from our crude oil acquisition and marketing business primarily due to a significant contraction in spreads in 2020 as compared to 2019 primarily impacting our Permian to Gulf Coast and Bakken to Gulf Coast trading operations, a $224 million decrease due to lower volumes on our Bakken Pipeline due to lower basin production, and a $35 million decrease in throughput at our crude terminals primarily driven by lower Permian and Bakken volumes, reduced refinery utilization from COVID-19 demand destruction, reduced export demand, and hurricanes impacting operations in the third quarter of 2020; partially offset by a $285 million increase related to assets acquired in 2019; and

 

   

an increase of $33 million in selling, general and administrative expenses primarily due to legal expenses, higher insurance expenses, and an increase related to assets acquired in 2019; partially offset by

 

   

a decrease of $44 million in operating expenses primarily due to lower volume-driven pipeline expenses and corporate cost-cutting initiatives, partially offset by increased costs related to assets acquired in 2019; and

 

   

an increase of $29 million in Adjusted EBITDA related to unconsolidated affiliates due to assets acquired in 2019.

Investment in Sunoco LP

 

     Years Ended December 31,         
         2020              2019          Change  

Revenues

   $ 10,710    $ 16,596    $ (5,886

Cost of products sold

     9,654      15,380      (5,726
  

 

 

    

 

 

    

 

 

 

Segment margin

     1,056      1,216      (160

Unrealized (gains) losses on commodity risk management activities

     6      (5      11

Operating expenses, excluding non-cash compensation expense

     (336      (365      29

Selling, general and administrative, excluding non-cash compensation expense

     (98      (123      25

Adjusted EBITDA related to unconsolidated affiliates

     10      4      6

Inventory valuation adjustments

     82      (79      161

Other, net

     19      17      2
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 739    $ 665    $ 74
  

 

 

    

 

 

    

 

 

 

The Investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.

Segment Adjusted EBITDA. For the year ended December 31, 2020 compared to the prior year, Segment Adjusted EBITDA related to the Investment in Sunoco LP segment increased due to the net impacts of the following:

 

   

an increase in the gross profit on motor fuel sales of $32 million, primarily due to a 18% increase in gross profit per gallon sold and the receipt of a $13 million make-up payment under Sunoco LP’s fuel supply agreement with 7-Eleven, Inc., partially offset by a 13% decrease in gallons sold; and

 

   

a decrease in operating expenses and selling, general and administrative expenses, excluding non-cash compensation expense of $54 million, primarily attributable to lower employee costs, maintenance, advertising, credit card fees and utilities, which was partially offset by a $12 million charge for current expected credit losses on Sunoco LP’s accounts receivable in connection with the financial impact from COVID-19; and

 

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an increase of $6 million in Adjusted EBITDA related to unconsolidated affiliates due to Sunoco LP’s investment in the JC Nolan joint venture; partially offset by

 

   

a decrease of $18 million in non-motor fuel sales and lease gross profit primarily due to reduced credit card transactions related to the COVID-19 pandemic and rent concessions in 2020.

Investment in USAC

 

     Years Ended December 31,         
         2020              2019          Change  

Revenues

   $ 667    $ 698    $ (31

Cost of products sold

     82      91      (9
  

 

 

    

 

 

    

 

 

 

Segment margin

     585      607      (22

Operating expenses, excluding non-cash compensation expense

     (124      (134      10

Selling, general and administrative, excluding non-cash compensation expense

     (51      (53      2

Other, net

     4      —          4
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 414    $ 420    $ (6
  

 

 

    

 

 

    

 

 

 

The investment in USAC segment reflects the consolidated results of USAC.

Segment Adjusted EBITDA. For the year ended December 31, 2020 compared to last year, Segment Adjusted EBITDA related to our investment in USAC segment increased due to the net impacts of the following:

 

   

a decrease of $10 million in operating expenses primarily driven by a decrease in average revenue generating horsepower and reduced headcount; partially offset by

 

   

a decrease of $22 million in segment margin primarily driven by a decrease in revenues primarily due to a decrease in average revenue generating horsepower as a result of a decline in demand for compression services primarily driven by a decrease in U.S. crude oil and natural gas activities and a reduction of ancillary maintenance work, offset by a decrease in costs of products sold of $9 million.

All Other

 

     Years Ended December 31,         
         2020              2019          Change  

Revenue

   $ 1,838    $ 1,689    $ 149

Cost of products sold

     1,527      1,504      23
  

 

 

    

 

 

    

 

 

 

Segment margin

     311      185      126

Unrealized (gains) losses on commodity risk management activities

     1      (4      5

Operating expenses, excluding non-cash compensation expense

     (133      (77      (56

Selling, general and administrative expenses, excluding non-cash compensation expense

     (91      (58      (33

Adjusted EBITDA related to unconsolidated affiliates

     2      2      —    

Other and eliminations

     25      58      (33
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 115    $ 106    $ 9
  

 

 

    

 

 

    

 

 

 

 

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Amounts reflected in our all other segment primarily include:

 

   

our natural gas marketing operations;

 

   

our wholly-owned natural gas compression operations;

 

   

our investment in coal handling facilities.

 

   

our Canadian operations, which were acquired in the SemGroup acquisition in December 2019 and include natural gas gathering and processing assets.

Segment Adjusted EBITDA. For the year ended December 31, 2020 compared to the prior year, Segment Adjusted EBITDA increased due to the net impacts of the following:

 

   

an increase of $97 million from the acquisition of Energy Transfer Canada; and

 

   

an increase of $26 million primarily due to insurance proceeds received on settled claims related to our MTBE litigation; partially offset by

 

   

a decrease of $22 million due to lower coal royalties and producer demand from our natural resources business;

 

   

a decrease of $35 million due to lower revenue from our compressor equipment business;

 

   

a decrease of $12 million from adverse market conditions due to COVID-19 related demand destruction;

 

   

a decrease of $25 million due to higher merger and acquisition expenses;

 

   

a decrease of $10 million due to intercompany eliminations; and

 

   

a decrease of $6 million due to the elimination of Sunoco LP’s interest in the JC Nolan Joint Venture.

 

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Year Ended December 31, 2019 Compared to the Year Ended December 31, 2018

Consolidated Results

 

     Years Ended December 31,         
         2019              2018          Change  

Segment Adjusted EBITDA:

        

Intrastate transportation and storage

   $ 999    $ 927    $ 72

Interstate transportation and storage

     1,792      1,680      112

Midstream

     1,602      1,627      (25

NGL and refined products transportation and services

     2,666      1,979      687

Crude oil transportation and services

     2,898      2,385      513

Investment in Sunoco LP

     665      638      27

Investment in USAC

     420      289      131

All other

     106      76      30
  

 

 

    

 

 

    

 

 

 

Total

     11,148      9,601      1,547

Depreciation, depletion and amortization

     (3,136      (2,843      (293

Interest expense, net of interest capitalized

     (2,262      (1,709      (553

Impairment losses

     (74      (431      357

Gains (losses) on interest rate derivatives

     (241      47      (288

Non-cash compensation expense

     (113      (105      (8

Unrealized losses on commodity risk management activities

     (5      (11      6

Inventory valuation adjustments

     79      (85      164

Losses on extinguishments of debt

     (2      (109      107

Adjusted EBITDA related to unconsolidated affiliates

     (626      (655      29

Equity in earnings of unconsolidated affiliates

     302      344      (42

Adjusted EBITDA related to discontinued operations

     —          25      (25

Other, net

     244      30      214
  

 

 

    

 

 

    

 

 

 

Income from continuing operations before income tax expense

     5,314      4,099      1,215

Income tax expense from continuing operations

     (199      (5      (194
  

 

 

    

 

 

    

 

 

 

Income from continuing operations

     5,115      4,094      1,021

Loss from discontinued operations, net of income taxes

     —          (265      265
  

 

 

    

 

 

    

 

 

 

Net income

   $ 5,115    $ 3,829    $ 1,286
  

 

 

    

 

 

    

 

 

 

Adjusted EBITDA (consolidated). For the year ended December 31, 2019 compared to the prior year, Adjusted EBITDA increased approximately $1.55 billion, or 16%. The increase was primarily due to the impact of multiple revenue-generating assets being placed in service and recent acquisitions, as well as increased demand for services on existing assets. The impact of new assets and acquisitions was approximately $784 million, of which the largest increases were from increased volumes to our Mariner East pipeline and terminal assets due to the addition of pipeline capacity in the fourth quarter of 2018 (a $274 million impact to the NGL and refined products transportation and services segment), the commissioning of our fifth and sixth fractionators (a $131 million impact to the NGL and refined products transportation and services segment), the ramp up of volumes on our Bayou Bridge system due to placing phase II in service in the second quarter of 2019 (a $60 million impact to our crude oil transportation and services segment), the Rover pipeline (a $78 million impact to the interstate transportation and storage segment), the addition of gas processing capacity to our Arrowhead gas plant (a $31 million impact to our midstream segment), placing our Permian Express 4 pipeline in

 

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service in October 2019 (a $26 million impact to our crude oil transportation and services segment) and the acquisition of USAC (a net impact of $131 million among the investment in USAC and all other segments). The remainder of the increase in Adjusted EBITDA was primarily due to stronger demand on existing assets, particularly due to increased throughput on our Bakken Pipeline system as well as increased production in the Permian, which impacted multiple segments. Additional discussion of these and other factors affecting Adjusted EBITDA is included in the analysis of Segment Adjusted EBITDA in the “Segment Operating Results” section below.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased primarily due to additional depreciation from assets recently placed in service and recent acquisitions.

Interest Expense, Net of Interest Capitalized. Interest expense, net of interest capitalized, increased during the year ended December 31, 2019 compared to December 31, 2018 primarily due to the following:

 

   

an increase of $475 million recognized by the Partnership (excluding Sunoco LP and USAC) primarily related to an increase in long-term debt, which included $4.2 billion of senior notes issued in the ET-ETO senior note exchange (discussed below under “Description of Indebtedness”), as well as additional senior note issuances and borrowings under our revolving credit facilities;

 

   

an increase of $49 million recognized by USAC primarily attributable to higher overall debt balances and higher interest rates on borrowings under the credit agreement. These increases were partially offset by the decrease in borrowings under the credit agreement; and

 

   

an increase of $29 million recognized by Sunoco LP due to an increase in total long-term debt.

Impairment Losses. During the year ended December 31, 2019, the Partnership recognized goodwill impairments of $12 million related to the Southwest Gas operations within the interstate transportation and storage segment and $9 million related to our North Central operations within the midstream segment, both of which were primarily due to changes in assumptions related to projected future revenues and cash flows. Also during the year ended December 31, 2019, Sunoco LP recognized a $47 million write-down on assets held for sale related to its ethanol plant in Fulton, New York, and USAC recognized a $6 million fixed asset impairment related to certain idle compressor assets.

During the year ended December 31, 2018, the Partnership recognized goodwill impairments of $378 million and asset impairments of $4 million related to our midstream operations and asset impairments of $9 million related to idle leased assets in our crude operations. Sunoco LP recognized a $30 million indefinite-lived intangible asset impairment related to contractual rights. USAC recognized a $9 million fixed asset impairment related to certain idle compressor assets. Additional discussion on these impairments is included in “Critical Accounting Estimates” below.

Gains (Losses) on Interest Rate Derivatives. Our interest rate derivatives are not designated as hedges for accounting purposes; therefore, changes in fair value are recorded in earnings each period. Losses on interest rate derivatives during the year ended December 31, 2019 resulted from a decrease in forward interest rates and gains in 2018 resulted from an increase in forward interest rates.

Unrealized Losses on Commodity Risk Management Activities. The unrealized losses on our commodity risk management activities include changes in fair value of commodity derivatives and the hedged inventory included in designated fair value hedging relationships. Information on the unrealized gains and losses within each segment are included in “Segment Operating Results” below, and additional information on the commodity-related derivatives, including notional volumes, maturities and fair values, is available in “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and in Note 13 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”

 

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Inventory Valuation Adjustments. Inventory valuation reserve adjustments were recorded for the inventory associated with Sunoco LP primarily driven by changes in fuel prices between periods.

Losses on Extinguishments of Debt. Amounts were related to Sunoco LP’s senior note and term loan redemption in January 2018.

Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of Unconsolidated Affiliates. See additional information in “Supplemental Information on Unconsolidated Affiliates” and “Segment Operation Results” below.

Adjusted EBITDA Related to Discontinued Operations. Amounts were related to the operations of Sunoco LP’s retail business that were disposed of in January 2018.

Other, net. Other, net primarily includes amortization of regulatory assets and other income and expense amounts.

Income Tax Expense. For the year ended December 31, 2019 compared to the prior year, income tax expense increased due to an increase in income at our corporate subsidiaries and the recognition of a favorable state tax rate change in the prior period.

Supplemental Information on Unconsolidated Affiliates

The following table presents financial information related to unconsolidated affiliates:

 

     Years Ended December 31,         
         2019              2018          Change  

Equity in earnings of unconsolidated affiliates:

        

Citrus

   $ 148    $ 141    $ 7

FEP

     59      55      4

MEP

     15      31      (16

White Cliffs

     4      —          4

Other

     76      117      (41
  

 

 

    

 

 

    

 

 

 

Total equity in earnings of unconsolidated affiliates

   $ 302    $ 344    $ (42
  

 

 

    

 

 

    

 

 

 

Adjusted EBITDA related to unconsolidated affiliates(1):

        

Citrus

   $ 342    $ 337    $ 5

FEP

     75      74      1

MEP

     60      81      (21

Other

     149      163      (14
  

 

 

    

 

 

    

 

 

 

Total Adjusted EBITDA related to unconsolidated affiliates

   $ 626    $ 655    $ (29
  

 

 

    

 

 

    

 

 

 

Distributions received from unconsolidated affiliates:

        

Citrus

   $ 178    $ 171    $ 7

FEP

     73      68      5

MEP

     36      48      (12

Other

     101      110      (9
  

 

 

    

 

 

    

 

 

 

Total distributions received from unconsolidated affiliates

   $ 388    $ 397    $ (9
  

 

 

    

 

 

    

 

 

 

 

(1)

These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, depletion, amortization, non-cash items and taxes.

 

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Segment Operating Results

Intrastate Transportation and Storage

 

     Years Ended December 31,         
         2019              2018          Change  

Natural gas transported (BBtu/d)

     12,442      10,873      1,569

Revenues

   $ 3,099    $ 3,737    $ (638

Cost of products sold

     1,909      2,665      (756
  

 

 

    

 

 

    

 

 

 

Segment margin

     1,190      1,072      118

Unrealized losses on commodity risk management activities

     2      38      (36

Operating expenses, excluding non-cash compensation expense

     (190      (189      (1

Selling, general and administrative, excluding non-cash compensation expense

     (29      (27      (2

Adjusted EBITDA related to unconsolidated affiliates

     25      32      (7

Other

     1      1      —    
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 999    $ 927    $ 72
  

 

 

    

 

 

    

 

 

 

Volumes. For the year ended December 31, 2019 compared to the prior year, transported volumes increased primarily due to the impact of reflecting RIGS as a consolidated subsidiary beginning April 2018 and the impact of the Red Bluff Express pipeline coming online in May 2018, as well as the impact of favorable market pricing spreads.

Segment Margin. The components of our intrastate transportation and storage segment margin were as follows:

 

     Years Ended December 31,         
         2019              2018          Change  

Transportation fees

   $ 614    $ 525    $ 89

Natural gas sales and other (excluding unrealized gains and losses)

     505      510      (5

Retained fuel revenues (excluding unrealized gains and losses)

     50      59      (9

Storage margin, including fees (excluding unrealized gains and losses)

     23      16      7

Unrealized losses on commodity risk management activities

     (2      (38      36
  

 

 

    

 

 

    

 

 

 

Total segment margin

   $ 1,190    $ 1,072    $ 118
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the prior year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment increased due to the net impacts of the following:

 

   

an increase of $64 million in transportation fees, excluding the impact of consolidating RIGS beginning April 2018 as discussed below, primarily due to the Red Bluff Express pipeline coming online in May 2018, as well as new contracts;

 

   

a net increase of $11 million primarily due to the consolidation of RIGS beginning April 2018, resulting in increases in transportation fees, retained fuel revenues and operating expenses of $24 million, $2 million and $6 million, respectively, partially offset by a decrease in Adjusted EBITDA related to unconsolidated affiliates of $9 million; and

 

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an increase of $7 million in realized storage margin primarily due to a realized adjustment to the Bammel storage inventory of $25 million in 2018 and higher storage fees, partially offset by a $20 million decrease due to lower physical withdrawals; partially offset by

 

   

a decrease of $9 million in retained fuel revenues primarily due to lower gas prices; and

 

   

a decrease of $5 million in realized natural gas sales and other due to lower realized gains from pipeline optimization activity.

Interstate Transportation and Storage

 

     Years Ended December 31,         
         2019              2018          Change  

Natural gas transported (BBtu/d)

     11,346      9,542      1,804

Natural gas sold (BBtu/d)

     17      17      —    

Revenues

   $ 1,963    $ 1,682    $ 281

Operating expenses, excluding non-cash compensation, amortization and accretion expenses

     (569      (431      (138

Selling, general and administrative, excluding non-cash compensation, amortization and accretion expenses

     (72      (63      (9

Adjusted EBITDA related to unconsolidated affiliates

     477      492      (15

Other

     (7      —          (7
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 1,792    $ 1,680    $ 112
  

 

 

    

 

 

    

 

 

 

Volumes. For the year ended December 31, 2019 compared to the prior year, transported volumes increased as a result of the addition of new contracted volumes for delivery out of the Haynesville Shale, higher volumes on our Rover pipeline as a result of the full year availability of new supply connections, and higher throughput on Trunkline and Panhandle due to increased utilization of higher contracted capacity.

Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the prior year, Segment Adjusted EBITDA related to our interstate transportation and storage segment increased due to the net impacts of the following:

 

   

an increase in margin of $231 million from the Rover pipeline due to higher reservation and usage resulting from additional connections and utilization of additional compression;

 

   

an increase of $40 million in reservation and usage fees due to improved market conditions allowing us to successfully bring new volumes to the system at improved rates, primarily on our Transwestern, Tiger and Panhandle systems; and

 

   

an increase of $6 million from the Sea Robin pipeline due to higher rates resulting from the rate case filed in June 2019, as well as fewer third-party supply interruptions on the Sea Robin system; partially offset by

 

   

an increase of $138 million in operating expense primarily due to an increase in ad valorem taxes of $126 million on the Rover pipeline system resulting from placing the final portions of this asset into service in November 2018, an increase of $24 million in transportation expense on Rover due to an increase in transportation volumes, an increase of $5 million in allocated overhead costs and additional operating expense of $4 million for assets acquired in June 2019, partially offset by lower gas imbalance and system gas activity of $15 million and lower storage capacity leased on the Panhandle system of $8 million;

 

   

an increase of $9 million in selling, general and administrative expenses primarily due to an increase in insurance expense of $8 million, an increase in employee cost of $4 million, and an increase in allocated overhead costs of $3 million, partially offset by lower Ohio excise tax on our Rover system; and

 

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a decrease of $15 million in adjusted EBITDA related to unconsolidated affiliates primarily resulting from a $20 million decrease due to lower earnings from MEP as a result of lower capacity being re-contracted at lower rates on expiring contracts, partially offset by a $5 million increase from our Citrus joint venture as we brought new volumes to the system in 2019.

Midstream

 

     Years Ended December 31,         
         2019              2018          Change  

Gathered volumes (BBtu/d):

     13,468      12,126      1,342

NGLs produced (MBbls/d):

     571      540      31

Equity NGLs (MBbls/d):

     31      29      2

Revenues

   $ 6,031    $ 7,522    $ (1,491

Cost of products sold

     3,577      5,145      (1,568
  

 

 

    

 

 

    

 

 

 

Segment margin

     2,454      2,377      77

Operating expenses, excluding non-cash compensation expense

     (791      (705      (86

Selling, general and administrative, excluding non-cash compensation expense

     (90      (81      (9

Adjusted EBITDA related to unconsolidated affiliates

     27      33      (6

Other

     2      3      (1
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 1,602    $ 1,627    $ (25
  

 

 

    

 

 

    

 

 

 

Volumes. For the year ended December 31, 2019 compared to the prior year, gathered volumes increased primarily due to increases in the Northeast, Permian, Ark-La-Tex, South Texas and North Texas regions. NGL production increased due to increases in the Permian and North Texas regions partially offset by ethane rejection in the South Texas region.

Segment Margin. The table below presents the components of our midstream segment margin. For the year ended December 31, 2018, the amounts previously reported for fee-based and non-fee-based margin have been adjusted to reflect reclassification of certain contractual minimum fees from fee-based margin to non-fee-based margin in order to conform to the current period classification.

 

     Years Ended December 31,         
         2019              2018          Change  

Gathering and processing fee-based revenues

   $ 2,132    $ 1,855    $ 277

Non-fee-based contracts and processing (excluding unrealized gains and losses)

     322      522      (200
  

 

 

    

 

 

    

 

 

 

Total segment margin

   $ 2,454    $ 2,377    $ 77
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the prior year, Segment Adjusted EBITDA related to our midstream segment decreased due to the net impacts of the following:

 

   

a decrease of $200 million in non-fee-based margin due to lower NGL prices of $183 million and lower gas prices of $50 million, offset by an increase of $33 million in non-fee-based margin due to increased throughput volume in North Texas and Permian regions;

 

   

an increase of $86 million in operating expenses due to increases of $33 million in outside services, $29 million in maintenance project costs, $17 million in employee costs and $6 million in office expenses and materials; and

 

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an increase of $9 million in selling, general and administrative expenses primarily due to a decrease of $5 million in capitalized overhead and an increase of $4 million in insurance expense; partially offset by

 

   

an increase of $277 million in fee-based margin due to volume growth in the Northeast, Permian, Ark-La-Tex, North Texas and South Texas regions.

NGL and Refined Products Transportation and Services

 

     Years Ended December 31,         
         2019              2018          Change  

NGL transportation volumes (MBbls/d)

     1,289      1,027      262

Refined products transportation volumes (MBbls/d)

     583      621      (38

NGL and refined products terminal volumes (MBbls/d)

     844      812      32

NGL fractionation volumes (MBbls/d)

     706      527      179

Revenues

   $ 11,641    $ 11,123    $ 518

Cost of products sold

     8,393      8,462      (69
  

 

 

    

 

 

    

 

 

 

Segment margin

     3,248      2,661      587

Unrealized (gains) losses on commodity risk management activities

     81      (86      167

Operating expenses, excluding non-cash compensation expense

     (656      (604      (52

Selling, general and administrative expenses, excluding non-cash compensation expense

     (93      (74      (19

Adjusted EBITDA related to unconsolidated affiliates

     86      82      4
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 2,666    $ 1,979    $ 687
  

 

 

    

 

 

    

 

 

 

Volumes. For the year ended December 31, 2019 compared to the prior year, throughput barrels on our Texas NGL pipeline system increased due to higher receipt of liquids production from both wholly-owned and third-party gas plants primarily in the Permian and North Texas regions. In addition, NGL transportation volumes on our Northeast assets increased due to the initiation of service on the Mariner East 2 pipeline system.

Refined products transportation volumes decreased for the year ended December 31, 2019 compared to prior year due to the closure of a third-party refinery during the third quarter of 2019, negatively impacting supply to our refined products transportation system. These decreases in volumes are partially offset by the initiation of service on the JC Nolan Pipeline in the third quarter of 2019.

NGL and refined products terminal volumes increased for the year ended December 31, 2019 compared to the prior year primarily due to the initiation of service on our Mariner East 2 pipeline system which commenced operations in the fourth quarter of 2018.

Average volumes fractionated at our Mont Belvieu, Texas fractionation facility increased for the year ended December 31, 2019 compared to the prior year primarily due to the commissioning of our fifth and sixth fractionators in July 2018 and February 2019, respectively.

 

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Segment Margin. The components of our NGL and refined products transportation and services segment margin were as follows:

 

     Years Ended December 31,         
         2019              2018          Change  

Fractionators and refinery services margin

   $ 664    $ 511    $ 153

Transportation margin

     1,716      1,233      483

Storage margin

     223      211      12

Terminal Services margin

     630      494      136

Marketing margin

     96      126      (30

Unrealized gains (losses) on commodity risk management activities

     (81      86      (167
  

 

 

    

 

 

    

 

 

 

Total segment margin

   $ 3,248    $ 2,661    $ 587
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the prior year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impacts of the following:

 

   

an increase of $483 million in transportation margin primarily due to a $265 million increase resulting from the initiation of service on our Mariner East 2 pipeline in the fourth quarter of 2018, a $212 million increase resulting from higher throughput volumes received from the Permian region on our Texas NGL pipelines, a $29 million increase due to higher throughput volumes from the Barnett region, a $9 million increase from the Eagle Ford region, and a $9 million increase due to the initiation of service on the JC Nolan Pipeline. These increases were partially offset by a $21 million decrease resulting from Mariner East 1 pipeline downtime, a $13 million decrease due to the closure of a third-party refinery during the third quarter of 2019, negatively impacting refined product supply to our system, and a $5 million decrease due to the timing of deficiency fees on Mariner West;

 

   

an increase of $153 million in fractionation and refinery services margin primarily due to a $167 million increase resulting from the commissioning of our fifth and sixth fractionators in July 2018 and February 2019, respectively, and higher NGL volumes from the Permian region feeding our Mont Belvieu fractionation facility. This increase was partially offset by a reclassification between our fractionation and storage margins;

 

   

an increase of $136 million in terminal services margin primarily due to a $171 million increase from the initiation of service of our Mariner East 2 pipeline which commenced operations in the fourth quarter of 2018 and a $7 million increase due to increased tank lease revenue from third-party customers. These increases were partially offset by a $16 million decrease in volumes and expense reimbursements from third parties on Mariner East 1, a $16 million decrease due to lower volumes from third-party pipeline, truck and rail deliveries into our Marcus Hook Terminal, a $5 million decrease due to fewer vessels exported out of our Nederland Terminal, and a $4 million decrease due to the closure of a third-party refinery during the third quarter of 2019; and

 

   

an increase of $12 million in storage margin primarily due to a reclassification between our storage and fractionation margins; partially offset by

 

   

a decrease of $30 million in marketing margin primarily due to capacity lease fees incurred by our marketing affiliate on our Mariner East 2 pipeline, offset by increased gains from our butane blending business due to more favorable market conditions and increased volumes, as well as increased optimization gains from the sale of NGL component products at our Mont Belvieu facility;

 

   

an increase of $52 million in operating expenses primarily due to a $26 million increase in employee and ad valorem tax expenses on our terminals, fractionation, and transportation operations, a $14 million increase in utility costs to operate our pipelines and our fifth and sixth fractionators which commenced July 2018 and

 

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February 2019, respectively, and an $8 million increase in maintenance project costs due to the timing of multiple projects on our transportation assets; and

 

   

an increase of $19 million in general and administrative expenses primarily due to a $10 million increase in allocated overhead costs, a $5 million increase in insurance expenses, a $4 million increase in legal fees, and a $2 million increase in employee costs.

Crude Oil Transportation and Services

 

     Years Ended December 31,         
         2019              2018          Change  

Crude transportation volumes (MBbls/d)

     4,217      3,713      504

Crude terminals volumes (MBbls/d)

     2,513      2,555      (42

Revenue

   $ 18,447    $ 17,332    $ 1,115

Cost of products sold

     14,832      14,384      448
  

 

 

    

 

 

    

 

 

 

Segment margin

     3,615      2,948      667

Unrealized (gains) losses on commodity risk management activities

     (69      55      (124

Operating expenses, excluding non-cash compensation expense

     (570      (547      (23

Selling, general and administrative expenses, excluding non-cash compensation expense

     (85      (86      1

Adjusted EBITDA related to unconsolidated affiliates

     8      15      (7

Other

     (1      —          (1
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 2,898    $ 2,385    $ 513
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the prior year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the net impacts of the following:

 

   

an increase of $543 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $282 million increase resulting from higher throughput on our Texas crude pipeline system primarily due to increased production from the Permian region and contributions from capacity expansion projects placed into service, a $219 million increase in throughput on our Bakken pipeline, a favorable change due to inventory valuation adjustment of $75 million, partially offset by a $90 million reduction due to lower pipeline basis spreads net of hedges. We also realized a $66 million increase from higher volumes on our Bayou Bridge Pipeline, a $31 million increase due to the inclusion of assets acquired in 2019, and a $26 million increase primarily from higher throughput, ship loading and tank rental fees at our Nederland Terminal; partially offset by a $54 million decrease from our Oklahoma assets resulting from lower volumes to the system as well as from the timing of a deficiency payment made in the prior year, a $12 million decrease due to the closure of a third-party refinery which was the primary customer utilizing one of our northeast crude terminals. The remainder of the offsetting decrease was primarily attributable to a change in the presentation of certain intrasegment transactions, which were eliminated in the current period presentation but were shown on a gross basis in revenues and operating expenses in the prior period; partially offset by

 

   

an increase of $23 million in operating expenses primarily due to a $30 million increase in throughput-related costs on existing assets, partially offset by a $14 million decrease in management fees as well as the impact of certain intrasegment transactions discussed above; and

 

   

a decrease of $7 million in Adjusted EBITDA related to unconsolidated affiliates due to lower margin from jet fuel sales by our joint ventures.

 

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Investment in Sunoco LP

 

     Years Ended December 31,         
         2019              2018          Change  

Revenues

   $ 16,596    $ 16,994    $ (398

Cost of products sold

     15,380      15,872      (492
  

 

 

    

 

 

    

 

 

 

Segment margin

     1,216      1,122      94

Unrealized (gains) losses on commodity risk management activities

     (5      6      (11

Operating expenses, excluding non-cash compensation expense

     (365      (435      70

Selling, general and administrative, excluding non-cash compensation expense

     (123      (129      6

Adjusted EBITDA related to unconsolidated affiliates

     4      —          4

Inventory valuation adjustments

     (79      85      (164

Adjusted EBITDA from discontinued operations

     —          (25      25

Other, net

     17      14      3
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 665    $ 638    $ 27
  

 

 

    

 

 

    

 

 

 

The Investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.

Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the prior year, Segment Adjusted EBITDA related to the Investment in Sunoco LP segment increased due to the net impacts of the following:

 

   

a decrease in operating costs of $76 million, primarily as a result of the conversion of 207 retail sites to commission agent sites during April 2018. These expenses include other operating expense, general and administrative expense and lease expense; and

 

   

an increase of $25 million related to Adjusted EBITDA from discontinued operations related to the divestment of 1,030 company-operated fuel sites to 7-Eleven in January 2018; and

 

   

an increase of $4 million in Adjusted EBITDA related to unconsolidated affiliates due to Sunoco LP’s investment in the JC Nolan joint venture; partially offset by

 

   

a decrease in the gross profit on motor fuel sales of $76 million (excluding the change in inventory fair value adjustments and unrealized gains and losses on commodity risk management activities) primarily due to lower fuel margins, a one-time benefit of approximately $25 million related to a cash settlement with a fuel supplier recorded in 2018 and an $8 million one-time charge related to a reserve for an open contractual dispute recorded in 2019, partially offset by an increase in gallons sold.

 

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Investment in USAC

 

     Years Ended December 31,         
         2019              2018          Change  

Revenues

   $ 698    $ 508    $ 190

Cost of products sold

     91      67      24
  

 

 

    

 

 

    

 

 

 

Segment margin

     607      441      166

Operating expenses, excluding non-cash compensation expense

     (134      (110      (24

Selling, general and administrative, excluding non-cash compensation expense

     (53      (50      (3

Other, net

            8      (8
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 420    $ 289    $ 131
  

 

 

    

 

 

    

 

 

 

The investment in USAC segment reflects the consolidated results of USAC from April 2, 2018, the date ET obtained control of USAC, through December 31, 2019. Changes between periods are due to the consolidation of USAC beginning April 2, 2018.

All Other

 

     Years Ended December 31,         
         2019              2018          Change  

Revenue

   $ 1,689    $ 2,228    $ (539

Cost of products sold

     1,504      2,006      (502
  

 

 

    

 

 

    

 

 

 

Segment margin

     185      222      (37

Unrealized gains on commodity risk management activities

     (4      (2      (2

Operating expenses, excluding non-cash compensation expense

     (77      (56      (21

Selling, general and administrative expenses, excluding non-cash compensation expense

     (58      (87      29

Adjusted EBITDA related to unconsolidated affiliates

     2      1      1

Other and eliminations

     58      (2      60
  

 

 

    

 

 

    

 

 

 

Segment Adjusted EBITDA

   $ 106    $ 76    $ 30
  

 

 

    

 

 

    

 

 

 

Amounts reflected in our all other segment during the periods presented above primarily include:

 

   

our natural gas marketing operations;

 

   

our wholly-owned natural gas compression operations;

 

   

a noncontrolling interest in PES. Prior to PES’s reorganization in August 2018, ETO’s 33% interest in PES was reflected as an unconsolidated affiliate; for the period subsequent to the August 2018 reorganization through 2019, ETO held an approximately 7.4% interest in PES and no longer reflected PES as an affiliate;

 

   

our investment in coal handling facilities; and

 

   

our Canadian operations, which were acquired in the SemGroup acquisition in December 2019 and include natural gas gathering and processing assets.

 

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Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the prior year, Segment Adjusted EBITDA increased due to the net impacts of the following:

 

   

an increase of $8 million in gains from park and loan and storage activity;

 

   

an increase of $11 million in optimized gains on residue gas sales;

 

   

an increase of $7 million from settled derivatives;

 

   

an increase of $15 million from a legal settlement;

 

   

an increase of $12 million from payments related to the PES bankruptcy;

 

   

an increase of $6 million from the recognition of deferred revenue related to a bankruptcy;

 

   

an increase of $3 million from power trading activities;

 

   

an increase of $3 million from the Energy Transfer Canada joint venture for the period subsequent to our acquisition of SemGroup on December 5, 2019, net of an increase due to SemGroup related corporate expenses; and

 

   

a decrease of $21 million in merger and acquisition expenses; partially offset by

 

   

a decrease of $36 million due to the contribution of CDM to USAC in April 2018, subsequent to which CDM is reflected in the Investment in USAC segment;

 

   

a decrease of $8 million due to lower gas prices and increased power costs; and

 

   

a decrease of $11 million due to lower revenue from our compressor equipment business.

Liquidity and Capital Resources

Our ability to satisfy our obligations and pay distributions to our preferred unitholders will depend on our future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond management’s control.

The Partnership currently expects capital expenditures in 2021 to be within the following ranges (excluding capital expenditures related to our investments in Sunoco LP and USAC:

 

     Growth      Maintenance  
     Low      High      Low      High  

Intrastate transportation and storage

   $ 5    $ 10    $ 35    $ 40

Interstate transportation and storage (1)

     25      50      120      125

Midstream

     265      290      110      115

NGL and refined products transportation and services (1)

     700      800      90      100

Crude oil transportation and services

     280      305      100      110

All other (including eliminations)

     75      100      55      60
  

 

 

    

 

 

    

 

 

    

 

 

 

Total capital expenditures

   $ 1,350    $ 1,555    $ 510    $ 550
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)

Includes capital expenditures related to our proportionate ownership of the Bakken, Rover, and Bayou Bridge pipeline projects and our proportionate ownership of the Orbit Gulf Coast NGL export project.

The assets used in our natural gas and liquids operations, including pipelines, gathering systems and related facilities, are generally long-lived assets and do not require significant maintenance capital expenditures. Accordingly, we do not have any significant financial commitments for maintenance capital expenditures in our businesses. From time to time we experience increases in pipe costs due to a number of reasons, including but not limited to, delays from steel mills, limited selection of mills capable of producing large diameter pipe timely, higher steel prices and other factors beyond our control. However, we include these factors in our anticipated growth capital expenditures for each year.

 

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We generally fund maintenance capital expenditures and distributions with cash flows from operating activities. We generally expect to fund growth capital expenditures with proceeds of borrowings under our credit facilities, along with cash from operations.

Sunoco LP expects to invest approximately $120 million in growth capital expenditures and approximately $45 million on maintenance capital expenditures in 2021.

USAC currently plans to spend approximately $22 million in maintenance capital expenditures and currently has budgeted between $30 million and $40 million in expansion capital expenditures in 2021.

Cash Flows

Our cash flows may change in the future due to a number of factors, some of which we cannot control. These include regulatory changes, the price of our products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks, the successful integration of our acquisitions, and other factors.

Operating Activities

Changes in cash flows from operating activities between periods primarily result from changes in earnings (as discussed in “Results of Operations” above), excluding the impacts of non-cash items and changes in operating assets and liabilities. Non-cash items include recurring non-cash expenses, such as depreciation, depletion and amortization expense and non-cash compensation expense. The increase in depreciation, depletion and amortization expense during the periods presented primarily resulted from construction and acquisitions of assets, while changes in non-cash compensation expense resulted from changes in the number of units granted and changes in the grant date fair value estimated for such grants. Cash flows from operating activities also differ from earnings as a result of non-cash charges that may not be recurring such as impairment charges and allowance for equity funds used during construction. The allowance for equity funds used during construction increases in periods when we have a significant amount of interstate pipeline construction in progress. Changes in operating assets and liabilities between periods result from factors such as the changes in the value of derivative assets and liabilities, timing of accounts receivable collection, payments on accounts payable, the timing of purchases and sales of inventories, and the timing of advances and deposits received from customers.

Following is a summary of operating activities by period:

Year Ended December 31, 2020

Cash provided by operating activities in 2020 was $7.87 billion and income from continuing operations was $311 million. The difference between net income and cash provided by operating activities in 2020 primarily consisted of non-cash items totaling $7.14 billion offset by net changes in operating assets and liabilities of $212 million. The non-cash activity in 2020 consisted primarily of depreciation, depletion and amortization of $3.67 billion, impairment losses of $2.88 billion, non-cash compensation expense of $121 million, equity in earnings of unconsolidated affiliates of $119 million, inventory valuation adjustments of $82 million, losses on extinguishment of debt of $72 million, and deferred income taxes of $212 million. The Partnership also received distributions of $220 million from unconsolidated affiliates.

Year Ended December 31, 2019

Cash provided by operating activities in 2019 was $8.30 billion and income from continuing operations was $5.12 billion. The difference between net income and cash provided by operating activities in 2019 primarily consisted of non-cash items totaling $3.30 billion offset by net changes in operating assets and liabilities of $395 million. The non-cash activity in 2019 consisted primarily of depreciation, depletion and amortization of

 

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$3.14 billion, impairment losses of $74 million, non-cash compensation expense of $113 million, equity in earnings of unconsolidated affiliates of $302 million, inventory valuation adjustments of $79 million, losses on extinguishment of debt of $2 million and deferred income taxes of $221 million. The Partnership also received distributions of $290 million from unconsolidated affiliates.

Year Ended December 31, 2018

Cash provided by operating activities in 2018 was $7.56 billion and income from continuing operations was $4.09 billion. The difference between net income and cash provided by operating activities in 2018 primarily consisted of non-cash items totaling $3.11 billion offset by net changes in operating assets and liabilities of $62 million. The non-cash activity in 2018 consisted primarily of depreciation, depletion and amortization of $2.84 billion, impairment losses of $431 million, non-cash compensation expense of $105 million, equity in earnings of unconsolidated affiliates of $344 million, inventory valuation adjustments of $85 million, losses on extinguishment of debt of $109 million and deferred income taxes of $8 million. The Partnership also received distributions of $328 million from unconsolidated affiliates.

Investing Activities

Cash flows from investing activities primarily consist of cash amounts paid for acquisitions, capital expenditures, cash distributions from our joint ventures, and cash proceeds from sales or contributions of assets or businesses. Changes in capital expenditures between periods primarily result from increases or decreases in our growth capital expenditures to fund our construction and expansion projects.

Following is a summary of investing activities by period:

Year Ended December 31, 2020

Cash used in investing activities in 2020 was $4.90 billion. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) were $5.06 billion. Additional detail related to our capital expenditures is provided in the table below. We received $19 million of cash proceeds from the sale of assets. The Partnership also received distributions of $186 million from unconsolidated affiliates.

Year Ended December 31, 2019

Cash used in investing activities in 2019 was $6.40 billion. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) were $5.88 billion. Additional detail related to our capital expenditures is provided in the table below. During 2019, we received $93 million of cash proceeds from the sale of a noncontrolling interest in a subsidiary, paid $250 million in net cash for the SemGroup acquisition, and paid $7 million in cash for all other acquisitions. We received $54 million of cash proceeds from the sale of assets. The Partnership also received distributions of $98 million from unconsolidated affiliates.

Year Ended December 31, 2018

Cash used in investing activities in 2018 was $6.90 billion. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) were $7.30 billion. Additional detail related to our capital expenditures is provided in the table below. We received $711 million of net cash proceeds related to the USAC acquisition and paid $429 million in cash for all other acquisitions. We received $87 million of cash proceeds from the sale of assets. The Partnership also received distributions of $69 million from unconsolidated affiliates.

 

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The following is a summary of the Partnership’s capital expenditures (including only our proportionate share of the Bakken, Rover, and Bayou Bridge pipeline projects, our proportionate share of the Orbit Gulf Coast NGL export project, and net of contributions in aid of construction costs) by period:

 

     Capital Expenditures Recorded
During Period
 
   Growth      Maintenance      Total  

Year Ended December 31, 2020:

        

Intrastate transportation and storage

   $ 13    $ 36    $ 49

Interstate transportation and storage

     52      98      150

Midstream

     376      111      487

NGL and refined products transportation and services

     2,305      98      2,403

Crude oil transportation and services

     209      82      291

Investment in Sunoco LP

     89      35      124

Investment in USAC

     96      23      119

All other (including eliminations)

     99      37      136
  

 

 

    

 

 

    

 

 

 

Total capital expenditures

   $ 3,239    $ 520    $ 3,759
  

 

 

    

 

 

    

 

 

 

Year Ended December 31, 2019:

        

Intrastate transportation and storage

   $ 87    $ 37    $ 124

Interstate transportation and storage

     239      136      375

Midstream

     670      157      827

NGL and refined products transportation and services

     2,854      122      2,976

Crude oil transportation and services

     317      86      403

Investment in Sunoco LP (1)

     108      40      148

Investment in USAC

     170      30      200

All other (including eliminations)

     165      50      215
  

 

 

    

 

 

    

 

 

 

Total capital expenditures

   $ 4,610    $ 658    $ 5,268
  

 

 

    

 

 

    

 

 

 

Year Ended December 31, 2018:

        

Intrastate transportation and storage

   $ 311    $ 33    $ 344

Interstate transportation and storage

     695      117      812

Midstream

     1,026      135      1,161

NGL and refined products transportation and services

     2,303      78      2,381

Crude oil transportation and services

     414      60      474

Investment in Sunoco LP (1)

     72      31      103

Investment in USAC

     182      23      205

All other (including eliminations)

     117      33      150
  

 

 

    

 

 

    

 

 

 

Total capital expenditures

   $ 5,120    $ 510    $ 5,630
  

 

 

    

 

 

    

 

 

 

 

(1)

Amounts related to Sunoco LP’s capital expenditures include capital expenditures related to discontinued operations.

Financing Activities

Changes in cash flows from financing activities between periods primarily result from changes in the levels of borrowings and equity issuances, which are primarily used to fund our acquisitions and growth capital expenditures. Distributions to partners increased between the periods as a result of increases in the number of common units outstanding.

 

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Following is a summary of financing activities by period:

Year Ended December 31, 2020

Cash used in financing activities was $2.89 billion in 2020. During 2020, we received net proceeds of $1.58 billion from the issuance of preferred units. Net proceeds from the offering were used to repay outstanding borrowings under our credit facilities, to fund capital expenditures and acquisitions, as well as for general partnership purposes. In 2020, we had a net increase in in our debt level of $1.95 billion. In 2020, we paid distributions of $5.27 billion to our partners, we paid distributions of $1.34 billion to noncontrolling interests, including predecessor distributions, and we paid distributions of $49 million to our redeemable noncontrolling interests. In addition, we received capital contributions of $192 million in cash from noncontrolling interests in 2020. During 2020, we incurred debt issuance costs of $59 million.

Year Ended December 31, 2019

Cash used in financing activities was $2.03 billion in 2019. During 2019, we received net proceeds of $780 million from the issuance of preferred units. Net proceeds from the offerings were used to repay outstanding borrowings under our credit facilities, to fund capital expenditures and acquisitions as well as for general partnership purposes. In 2019, we had a net increase in our debt level of $4.70 billion. In 2019, we paid distributions of $6.28 billion to our partners, we paid distributions of $1.40 billion to noncontrolling interests, and we paid distributions of $53 million to our redeemable noncontrolling interests. In addition, we received capital contributions of $348 million in cash from noncontrolling interests in 2019. During 2019, we incurred debt issuance costs of $117 million.

Year Ended December 31, 2018

Cash used in financing activities was $3.31 billion in 2018. During 2018, we received $58 million in net proceeds from common unit offerings, $867 million in net proceeds from the issuance of preferred units, and our subsidiaries received $465 million related to redeemable noncontrolling interests. Net proceeds from the offerings were used to repay outstanding borrowings under our credit facilities, to fund capital expenditures and acquisitions as well as for general partnership purposes. In 2018, we had a net increase in our debt level of $801 million. In 2018, we paid distributions of $4.83 billion to our partners, including predecessor distributions, we paid distributions of $891 million to noncontrolling interests, and we paid distributions of $24 million to our redeemable noncontrolling interests. In addition, we received capital contributions of $649 million in cash from noncontrolling interests in 2018. During 2018, our subsidiaries repurchased $300 million of common units in cash. During 2018, we incurred debt issuance costs of $162 million.

Discontinued Operations

Cash flows from discontinued operations reflect cash flows related to Sunoco LP’s retail divestment.

Year Ended December 31, 2018

Cash provided by discontinued operations was $2.73 billion for the year ended December 31, 2018, which reflected the net impact of cash used in operating activities of $484 million, cash provided by investing activities of $3.21 billion, and changes in cash included in current assets held for sale of $11 million.

 

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Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:

 

     December 31,  
     2020      2019  

ETO Senior Notes

   $ 37,783    $ 36,118

Transwestern Senior Notes

     400      575

Panhandle Senior Notes

     235      235

Bakken Senior Notes

     2,500      2,500

Sunoco LP Senior Notes, Term Loan and lease-related obligations

     3,139      2,935

USAC Senior Notes

     1,475      1,475

HFOTCO Tax-Exempt Notes

     225      225

Revolving credit facilities:

     

ETO $2.00 billion Term Loan facility due October 2022

     2,000      2,000

ETO $5.00 billion Revolving Credit Facility due December 2023

     3,103      4,214

Sunoco LP $1.50 billion Revolving Credit Facility due July 2023

     —          162

USAC $1.60 billion Revolving Credit Facility due April 2023

     474      403

Energy Transfer Canada Revolver due February 2024

     57      92

Energy Transfer Canada Revolver Term Loan A due February 2024

     261      269

Other long-term debt

     3      2

Unamortized premiums, net of discounts and fair value adjustments

     (10      4

Deferred debt issuance costs

     (279      (279
  

 

 

    

 

 

 

Total debt

     51,366      50,930

Less: current maturities of long-term debt

     21      26
  

 

 

    

 

 

 

Long-term debt, less current maturities

   $ 51,345    $ 50,904
  

 

 

    

 

 

 

The terms of our consolidated indebtedness and that of our subsidiaries are described in more detail below and in Note 5 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”

Recent Financing Transactions

ETO January 2020 Senior Notes Offering and Redemption

On January 22, 2020, ETO completed a registered offering (the “January 2020 Senior Notes Offering”) of $1.00 billion aggregate principal amount of the Partnership’s 2.900% Senior Notes due 2025, $1.50 billion aggregate principal amount of the Partnership’s 3.750% Senior Notes due 2030 and $2.00 billion aggregate principal amount of the Partnership’s 5.000% Senior Notes due 2050, (collectively, the “Notes”). The Notes are fully and unconditionally guaranteed by the Partnership’s wholly-owned subsidiary, Sunoco Logistics Operations, on a senior unsecured basis.

Utilizing proceeds from the January 2020 Senior Notes Offering, ETO redeemed its $400 million aggregate principal amount of 5.75% Senior Notes due September 1, 2020, its $1.05 billion aggregate principal amount of

 

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4.15% Senior Notes due October 1, 2020, its $1.14 billion aggregate principal amount of 7.50% Senior Notes due October 15, 2020, its $250 million aggregate principal amount of 5.50% Senior Notes due February 15, 2020, ET’s $52 million aggregate principal amount of 7.50% Senior Notes due October 15, 2020 and Transwestern’s $175 million aggregate principal amount of 5.36% Senior Notes due December 9, 2020.

Sunoco LP November 2020 Senior Notes Offering and Repurchase

On November 9, 2020, Sunoco LP completed a private offering of $800 million in aggregate principal amount of 4.500% senior notes due 2029. Sunoco LP used the proceeds to fund the tender offer on its 4.875% $1 billion senior notes due 2023. Approximately 56% of the 2023 senior notes were tendered. On January 15, 2021, Sunoco LP repurchased the remaining outstanding portion of its 2023 senior notes.

Credit Facilities, Term Loan and Commercial Paper

ETO Credit Facilities

Borrowings under the ETO Credit Facilities (defined as the ETO Term Loan, ETO Five-Year Credit Facility and ETO 364-Day Credit Facility, each of which is described below) are unsecured and initially guaranteed by Sunoco Logistics Operations. Borrowings under the ETO Credit Facilities will bear interest at a eurodollar rate or a base rate, at our option, plus an applicable margin. In addition, we will be required to pay a quarterly commitment fee to each lender equal to the product of the applicable rate and such lender’s applicable percentage of the unused portion of the aggregate commitments under the ETO Credit Facilities.

We typically repay amounts outstanding under the ETO Credit Facilities with proceeds from unit offerings or long-term notes offerings. The timing of borrowings depends on the Partnership’s activities and the cash available to fund those activities. The repayments of amounts outstanding under the ETO Credit Facilities depend on multiple factors, including market conditions and expectations of future working capital needs, and ultimately are a financing decision made by management. Therefore, the balance outstanding under the ETO Credit Facilities may vary significantly between periods. We do not believe that such fluctuations indicate a significant change in our liquidity position, because we expect to continue to be able to repay amounts outstanding under the ETO Credit Facilities with proceeds from unit offerings or long-term note offerings.

ETO Term Loan

On October 17, 2019, ETO entered into a term loan credit agreement (the “ETO Term Loan”) providing for a $2.00 billion three-year term loan credit facility. Borrowings under the term loan agreement mature on October 17, 2022 and are available for working capital purposes and for general partnership purposes. The term loan agreement is unsecured and is guaranteed by our subsidiary, Sunoco Logistics Operations.

As of December 31, 2020, the ETO Term Loan had $2.00 billion outstanding and was fully drawn. The weighted average interest rate on the total amount outstanding as of December 31, 2020 was 1.15%.

ETO Five-Year Credit Facility

ETO’s revolving credit facility (the “ETO Five-Year Credit Facility”) allows for unsecured borrowings up to $5.00 billion and matures on December 1, 2023. The ETO Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to $6.00 billion under certain conditions.

As of December 31, 2020, the ETO Five-Year Credit Facility had $3.10 billion outstanding, of which $1.66 billion was commercial paper. The amount available for future borrowings was $1.79 billion after accounting for outstanding letters of credit in the amount of $109 million. The weighted average interest rate on the total amount outstanding as of December 31, 2020 was 1.12%.

 

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ETO 364-Day Facility

ETO’s 364-day revolving credit facility (the “ETO 364-Day Facility”) allows for unsecured borrowings up to $1.00 billion and matures on November 26, 2021. As of December 31, 2020, the ETO 364-Day Facility had no outstanding borrowings.

Sunoco LP Credit Facility

As of December 31, 2020, the Sunoco LP Credit Facility had no outstanding borrowings and $8 million in standby letters of credit. The amount available for future borrowings was $1.5 billion at December 31, 2020.

USAC Credit Facility

As of December 31, 2020, USAC had $474 million of outstanding borrowings and no outstanding letters of credit under the credit agreement. As of December 31, 2020, USAC had $1.1 billion of availability under its credit facility. The weighted average interest rate on the total amount outstanding as of December 31, 2020 was 3.27%.

Energy Transfer Canada Credit Facilities

Energy Transfer Canada is party to a credit agreement providing for a C$350 million (US$275 million at the December 31, 2020 exchange rate) senior secured term loan facility, a C$525 million (US$412 million at the December 31, 2020 exchange rate) senior secured revolving credit facility, and a C$300 million (US$236 million at the December 31, 2020 exchange rate) senior secured construction loan facility (the “KAPS Facility”). The term loan facility and the revolving credit facility mature on February 25, 2024. The KAPS Facility matures on June 13, 2024. Energy Transfer Canada may incur additional term loans and revolving commitments in an aggregate amount not to exceed C$250 million (US$196 million at the December 31, 2020 exchange rate), subject to receiving commitments for such additional term loans or revolving commitments from either new lenders or increased commitments from existing lenders.

Covenants Related to Our Credit Agreements

Covenants Related to ETO

The agreements relating to the ETO senior notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions.

The ETO Credit Facilities (defined as the ETO Term Loan, ETO Five-Year Credit Facility and ETO 364-Day Credit Facility) contain covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries’ ability to, among other things:

 

   

incur indebtedness;

 

   

grant liens;

 

   

enter into mergers;

 

   

dispose of assets;

 

   

make certain investments;

 

   

make Distributions (as defined in the ETO Credit Facilities) during certain Defaults (as defined in the ETO Credit Facilities) and during any Event of Default (as defined in the ETO Credit Facilities);

 

   

engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries;

 

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engage in transactions with affiliates; and

 

   

enter into restrictive agreements.

The ETO Credit Facilities applicable margin and rate used in connection with the interest rates and commitment fees, respectively, are based on the credit ratings assigned to our senior, unsecured, non-credit enhanced long-term debt. The applicable margin for eurodollar rate loans under the ETO Five-Year Credit Facility ranges from 1.125% to 2.000% and the applicable margin for base rate loans ranges from 0.125% to 1.000%. The applicable rate for commitment fees under the ETO Five-Year Credit Facility ranges from 0.125% to 0.300%. The applicable margin for eurodollar rate loans under the ETO 364-Day Facility ranges from 1.500% to 2.000% and the applicable margin for base rate loans ranges from 0.500% to 1.000%. The applicable rate for commitment fees under the ETO 364-Day Facility ranges from 0.125% to 0.225%.

The ETO Credit Facilities contain various covenants including limitations on the creation of indebtedness and liens and related to the operation and conduct of our business. The ETO Credit Facilities also limit us, on a rolling four quarter basis, to a maximum Consolidated Funded Indebtedness to Consolidated EBITDA ratio, as defined in the underlying credit agreements, of 5.0 to 1, which can generally be increased to 5.5 to 1 during a Specified Acquisition Period. Our Leverage Ratio was 4.31 to 1 at December 31, 2020, as calculated in accordance with the credit agreements.

The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio.

Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Partnership’s or our subsidiaries’ ability to incur additional debt and/or our ability to pay distributions to Unitholders.

Covenants Related to Panhandle

Panhandle is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of Panhandle’s lending agreements.

Panhandle’s restrictive covenants include restrictions on liens securing debt and guarantees and restrictions on mergers and on the sales of assets. A breach of any of these covenants could result in acceleration of Panhandle’s debt.

Covenants Related to Sunoco LP

The Sunoco LP Credit Facility contains various customary representations, warranties, covenants and events of default, including a change of control event of default, as defined therein. Sunoco LP’s Credit Facility requires Sunoco LP to maintain a Net Leverage Ratio of not more than 5.5 to 1. The maximum Net Leverage Ratio is subject to upwards adjustment of not more than 6.0 to 1 for a period not to exceed three fiscal quarters in the event Sunoco LP engages in certain specified acquisitions of not less than $50 million (as permitted under Sunoco LP’s Credit Facility agreement). The Sunoco LP Credit Facility also requires Sunoco LP to maintain an Interest Coverage Ratio (as defined in the Sunoco LP’s Credit Facility agreement) of not less than 2.25 to 1.

 

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Covenants Related to USAC

The USAC Credit Facility contains covenants that limit (subject to certain exceptions) USAC’s ability to, among other things:

 

   

grant liens;

 

   

make certain loans or investments;

 

   

incur additional indebtedness or guarantee other indebtedness;

 

   

merge or consolidate;

 

   

sell our assets; or

 

   

make certain acquisitions.

The credit facility is also subject to the following financial covenants, including covenants requiring us to maintain:

 

   

a minimum EBITDA to interest coverage ratio of 2.5 to 1.0, determined as of the last day of each fiscal quarter; and

 

   

a maximum funded debt to EBITDA ratio, determined as of the last day of each fiscal quarter, for the annualized trailing three months of (i) 5.75 to 1 through the end of the fiscal quarter ending December 31, 2020 and (ii) 5.5 to 1 for the fiscal quarters ending March 31, 2021 and June 30, 2021, (iii) 5.25 to 1 for the fiscal quarters ending September 30, 2021 and December 31, 2021 and (iv) 5.0 to 1 thereafter, subject to a provision for increases to such thresholds, in the case of any fiscal quarter ending September 30, 2021 or thereafter, by 0.50 in connection with certain future acquisitions for the six consecutive month period following the period in which any such acquisition occurs, provided that, in any event, such ratio shall not exceed 5.5 to 1.

Covenants Related to the HFOTCO Tax Exempt Notes

The indentures covering HFOTCO’s tax exempt notes due 2050 (“IKE Bonds”) include customary representations and warranties and affirmative and negative covenants. Such covenants include limitations on the creation of new liens, indebtedness, making of certain restricted payments and payments on indebtedness, making certain dispositions, making material changes in business activities, making fundamental changes including liquidations, mergers or consolidations, making certain investments, entering into certain transactions with affiliates, making amendments to certain credit or organizational agreements, modifying the fiscal year, creating or dealing with hazardous materials in certain ways, entering into certain hedging arrangements, entering into certain restrictive agreements, funding or engaging in sanctioned activities, taking actions or causing the trustee to take actions that materially adversely affect the rights, interests, remedies or security of the bondholders, taking actions to remove the trustee, making certain amendments to the bond documents, and taking actions or omitting to take actions that adversely impact the tax exempt status of the IKE Bonds.

Compliance with our Covenants

We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2020.

Parent and Subsidiary Guarantee of Senior Notes

Sunoco Logistics Operations is the issuer of multiple series of senior notes that are guaranteed by ETO. Supplemental indentures were previously issued on all of the outstanding ETO senior notes to provide the guaranty by Sunoco Logistics Operations. These guarantees are full and unconditional on a senior unsecured

 

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basis. No other consolidated subsidiaries of the Partnership guarantee the senior notes. Neither Sunoco Logistics Operations nor ETO have material independent assets or operations, other than their investments in and receivables from affiliates which are not subject to these guarantees.

Certain of ETO’s and Sunoco Logistics Operations’ subsidiaries are less than wholly-owned. Consequently, such subsidiaries have noncontrolling interest holders whose rights and obligations are generally similar to ours, except in cases where redeemable and/or preferred noncontrolling interests exist. Additional information and balances related to noncontrolling interests are available in the consolidated financial statements and notes thereto included in “Item 8. Financial Statements and Supplementary Data.”

In addition, because none of ETO’s or Sunoco Logistics Operations’ other subsidiaries guarantee the senior notes, the senior notes are structurally subordinated to the claims of all creditors, including unsecured indebtedness, trade creditors and tort claimants, of those subsidiaries. In the event of the insolvency, bankruptcy, liquidation, reorganization, dissolution or winding up of the business of any of our subsidiaries (except for Sunoco Logistics Operations), creditors of such subsidiaries would generally have the right to be paid in full before any distribution is made to us or the holders of the senior notes. As of December 31, 2020, our subsidiaries (other than Sunoco Logistics Operations) had an aggregate of $8.8 billion of indebtedness outstanding.

Contractual Obligations

The following table summarizes our long-term debt and other contractual obligations as of December 31, 2020:

 

     Payments Due by Period  

Contractual Obligations

   Total      Less Than
1 Year
     1-3 Years      3-5 Years      More Than
5 Years
 

Long-term debt

   $ 51,655    $ 1,420    $ 13,018    $ 7,006    $ 30,211

Interest on long-term debt (1)

     28,960      2,417      4,322      3,444      18,777

Payments on derivatives

     451      212      239      —          —    

Purchase commitments (2)

     3,731      2,599      703      356      73

Transportation, natural gas storage and fractionation contracts

     286      62      120      104      —    

Operating lease obligations

     1,554      99      164      151      1,140

Service concession arrangement(3)

     364      15      31      32      286

Other(4)

     196      26      50      41      79
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total(5)

   $ 87,197    $ 6,850    $ 18,647    $ 11,134    $ 50,566
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)

Interest payments on long-term debt are based on the principal amount of debt obligations as of December 31, 2020. With respect to variable rate debt, the interest payments were estimated using the interest rate as of December 31, 2020. To the extent interest rates change, our contractual obligations for interest payments will change. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for further discussion.

(2)

We define a purchase commitment as an agreement to purchase goods or services that is enforceable and legally binding (unconditional) on us that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transactions. We have long and short-term product purchase obligations for refined product and energy commodities with third-party suppliers. These purchase obligations are entered into at either variable or fixed prices. The purchase prices that we are obligated to pay under variable price contracts approximate market prices at the time we take delivery of the volumes. Our estimated future variable price contract payment obligations are based on the December 31, 2020 market price of the applicable commodity applied to future volume commitments. Actual future payment obligations may vary depending on market prices at the time of delivery. The purchase prices that we are obligated to pay under fixed price contracts are

 

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  established at the inception of the contract. Our estimated future fixed price contract payment obligations are based on the contracted fixed price under each commodity contract. Obligations shown in the table represent estimated payment obligations under these contracts for the periods indicated.
(3)

Includes minimum guaranteed payments under service concession arrangements with New Jersey Turnpike Authority and New York Thruway Authority.

(4)

Expected contributions to fund our pension and postretirement benefit plans were included in “Other” above. Environmental liabilities, AROs, unrecognized tax benefits, contingency accruals and deferred revenue, which were included in “Other non-current liabilities” in our consolidated balance sheets, were excluded from the table above as the amounts do not represent contractual obligations or, in some cases, the amount and/or timing of the cash payments is uncertain.

(5)

Excludes non-current deferred tax liabilities of $3.39 billion due to uncertainty of the timing of future cash flows for such liabilities.

Cash Distributions

ETO Preferred Unit Distributions

Distributions on the Partnership’s Series A, Series B, Series C, Series D, Series E, Series F and Series G preferred units declared and/or paid by the Partnership were as follows:

 

Period Ended

  Record Date   Payment Date   Series A (1)     Series B (1)     Series C     Series D     Series E     Series F (1)     Series G (1)  

December 31, 2018

  February 1, 2019   February 15, 2019   $ 31.2500   $ 33.1250   $ 0.4609   $ 0.4766   $ —       $ —       $ —    

March 31, 2019

  May 1, 2019   May 15, 2019     —         —         0.4609     0.4766     —         —         —    

June 30, 2019

  August 1, 2019   August 15, 2019     31.2500     33.1250     0.4609     0.4766     0.5806     —         —    

September 30, 2019

  November 1, 2019   November 15, 2019     —         —         0.4609     0.4766     0.4750     —         —    

December 31, 2019

  February 3, 2020   February 18, 2020     31.2500     33.1250     0.4609     0.4766     0.4750     —         —    

March 31, 2020

  May 1, 2020   May 15, 2020     —         —         0.4609     0.4766     0.4750     21.19     22.36

June 30, 2020

  August 3, 2020   August 17, 2020     31.2500     33.1250     0.4609     0.4766     0.4750     —         —    

September 30, 2020

  November 2, 2020   November 15, 2020     —         —         0.4609     0.4766     0.4750     33.75     35.625

December 31, 2020

  February 1, 2021   February 16, 2021     31.2500     33.1250     0.4609     0.4766     0.4750     —         —    

 

*

Represent prorated initial distributions. Prorated initial distributions on the recently issued Series F and Series G preferred units will be payable in May 2020.

(1)

ETO Series A Preferred Unit, ETO Series B Preferred Unit, ETO Series F Preferred Unit and ETO Series G Preferred Unit distributions are paid on a semi-annual basis.

Sunoco LP Cash Distributions

The following table illustrates the percentage allocations of available cash from operating surplus between Sunoco LP’s common unitholders and the holder of its IDRs based on the specified target distribution levels, after the payment of distributions to Class C unitholders. The amounts set forth under “marginal percentage interest in distributions” are the percentage interests of the IDR holder and the common unitholders in any available cash from operating surplus which Sunoco LP distributes up to and including the corresponding amount in the column “total quarterly distribution per unit target amount.” The percentage interests shown for common

 

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unitholders and IDR holder for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

 

          Marginal Percentage
Interest in Distributions
 
     Total Quarterly Distribution
Target Amount
   Common
Unitholders
    Holder of
IDRs
 

Minimum Quarterly Distribution

   $0.4375      100     —  

First Target Distribution

   $0.4375 to $0.503125      100     —  

Second Target Distribution

   $0.503125 to $0.546875      85     15

Third Target Distribution

   $0.546875 to $0.656250      75     25

Thereafter

   Above $0.656250      50     50

Distributions on Sunoco LP’s units declared and/or paid by Sunoco LP were as follows:

 

Quarter Ended

   Record Date    Payment Date    Rate  

December 31, 2016

   February 13, 2017    February 21, 2017    $ 0.8255

March 31, 2017

   May 9, 2017    May 16, 2017      0.8255

June 30, 2017

   August 7, 2017    August 15, 2017      0.8255

September 30, 2017

   November 7, 2017    November 14, 2017      0.8255

December 31, 2017

   February 6, 2018    February 14, 2018      0.8255

March 31, 2018

   May 7, 2018    May 15, 2018      0.8255

June 30, 2018

   August 7, 2018    August 15, 2018      0.8255

September 30, 2018

   November 6, 2018    November 14, 2018      0.8255

December 31, 2018

   February 6, 2019    February 14, 2019      0.8255

March 31, 2019

   May 7, 2019    May 15, 2019      0.8255

June 30, 2019

   August 6, 2019    August 14, 2019      0.8255

September 30, 2019

   November 5, 2019    November 19, 2019      0.8255

December 31, 2019

   February 7, 2020    February 19, 2020      0.8255

March 31, 2020

   May 7, 2020    May 19, 2020      0.8255

June 30, 2020

   August 7, 2020    August 19, 2020      0.8255

September 30, 2020

   November 6, 2020    November 19, 2020      0.8255

December 31, 2020

   February 8, 2021    February 19, 2021      0.8255

USAC Cash Distributions

Subsequent to the Energy Transfer Merger and USAC Transactions described in Note 1 and Note 3, respectively, ETO owned approximately 39.7 million USAC common units and 6.4 million USAC Class B units. Subsequent to the conversion of the USAC Class B Units to USAC common units on July 30, 2019, ETO owns approximately 46.1 million USAC common units. As of December 31, 2020, USAC had approximately 97.0 million common units outstanding. USAC currently has a non-economic general partner interest and no outstanding IDRs.

 

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Distributions on USAC’s units declared and/or paid by USAC subsequent to the USAC transaction on April 2, 2018 were as follows:

 

Quarter Ended

   Record Date    Payment Date    Rate  

March 31, 2018

   May 1, 2018    May 11, 2018    $ 0.5250

June 30, 2018

   July 30, 2018    August 10, 2018      0.5250

September 30, 2018

   October 29, 2018    November 9, 2018      0.5250

December 31, 2018

   January 28, 2019    February 8, 2019      0.5250

March 31, 2019

   April 29, 2019    May 10, 2019      0.5250

June 30, 2019

   July 29, 2019    August 9, 2019      0.5250

September 30, 2019

   October 28, 2019    November 8, 2019      0.5250

December 31, 2019

   January 27, 2020    February 7, 2020      0.5250

March 31, 2020

   April 27, 2020    May 8, 2020      0.5250

June 30, 2020

   July 31, 2020    August 10, 2020      0.5250

September 30, 2020

   October 26, 2020    November 6, 2020      0.5250

December 31, 2020

   January 25, 2021    February 5, 2021      0.5250

Critical Accounting Estimates

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules, and we believe the proper implementation and consistent application of the accounting rules are critical. Our critical accounting policies are discussed below. For further details on our accounting policies see Note 2 to our consolidated financial statements.

Use of Estimates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage segments are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the operating results estimated for the year ended December 31, 2020 represent the actual results in all material respects.

Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation, depletion and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.

Impairment of Long-Lived Assets, Goodwill, Intangible Assets and Investments in Unconsolidated Affiliates. Long-lived assets are required to be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. Goodwill and intangibles with indefinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other than temporary. An impairment loss should be recognized only if the carrying amount of the asset/goodwill is not recoverable and exceeds its fair value.

 

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In order to test for recoverability when performing a quantitative impairment test, we must make estimates of projected cash flows related to the asset, which include, but are not limited to, assumptions about the use or disposition of the asset, estimated remaining life of the asset, and future expenditures necessary to maintain the asset’s existing service potential. In order to determine fair value, we make certain estimates and assumptions, including, among other things, changes in general economic conditions in regions in which our markets are located, the availability and prices of natural gas, our ability to negotiate favorable sales agreements, the risks that natural gas exploration and production activities will not occur or be successful, our dependence on certain significant customers and producers of natural gas, and competition from other companies, including major energy producers. While we believe we have made reasonable assumptions to calculate the fair value, if future results are not consistent with our estimates, we could be exposed to future impairment losses that could be material to our results of operations.

The Partnership determines the fair value of its reporting units using a discounted cash flow method, the guideline company method, or a weighted combination of these methods. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determines fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determines the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimates a reasonable control premium, when appropriate, representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business.

One key assumption for the measurement of an impairment is management’s estimate of future cash flows and EBITDA. These estimates are based on the annual budget for the upcoming year and forecasted amounts for multiple subsequent years. The annual budget process is typically completed near the annual goodwill impairment testing date, and management uses the most recent information for the annual impairment tests. The forecast is also subjected to a comprehensive update annually in conjunction with the annual budget process and is revised periodically to reflect new information and/or revised expectations. The estimates of future cash flows and EBITDA are subjective in nature and are subject to impacts from the business risks described in “Item 1A. Risk Factors.” Therefore, the actual results could differ significantly from the amounts used for goodwill impairment testing, and significant changes in fair value estimates could occur in a given period. Such changes in fair value estimates could result in additional impairments in future periods; therefore, the actual results could differ significantly from the amounts used for goodwill impairment testing, and significant changes in fair value estimates could occur in a given period, resulting in additional impairments.

In addition, we may change our method of impairment testing, including changing the weight assigned to different valuation models. Such changes could be driven by various factors, including the level of precision or availability of data for our assumptions. Any changes in the method of testing could also result in an impairment or impact the magnitude of an impairment.

During the years ended December 31, 2020, 2019 and 2018, the Partnership recorded impairments totaling $3.01 billion, $74 million and $431 million, respectively, including $129 million in impairments in

 

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unconsolidated affiliates in 2020, and $66 million, $53 million and $52 million of long-lived asset impairments in 2020, 2019 and 2018, respectively. Additional information on the impairments recorded during these periods is available in “Item 8. Financial Statements and Supplementary Data.”

The goodwill impairments recorded by the Partnership during the years ended December 31, 2020, 2019 and 2018 represented all of the goodwill within the respective reporting units.

Management does not believe that any of the Partnership’s goodwill balances, long-lived assets or investments in unconsolidated affiliates is currently at significant risk of a material impairment; however, of the $2.39 billion of goodwill on the Partnership’s consolidated balance sheet as of December 31, 2020, approximately $368 million is recorded in reporting units for which the estimated fair value exceeded the carrying value by less than 20% in the most recent quantitative test.

Estimated Useful Lives of Long-Lived Assets. Depreciation and amortization of long-lived assets is provided using the straight-line method based on their estimated useful lives. Changes in the estimated useful lives of the assets could have a material effect on our results of operation. The Partnership’s results of operations have not been significantly impacted by changes in the estimated useful lives of our long-lived assets during the periods presented, and we do not anticipate any such significant changes in the future. However, changes in facts and circumstances could cause us to change the estimated useful lives of the assets, which could significantly impact the Partnership’s results of operations. Additional information on our accounting policies and the estimated useful lives associated with our long-lived assets is available in “Item 8. Financial Statements and Supplementary Data.”

Legal and Regulatory Matters. We are subject to litigation and regulatory proceedings as a result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from claims, orders, judgments or settlements. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. We expense legal costs as incurred, and all recorded legal liabilities are revised, as required, as better information becomes available to us. The factors we consider when recording an accrual for contingencies include, among others: (i) the opinions and views of our legal counsel; (ii) our previous experience; and (iii) the decision of our management as to how we intend to respond to the complaints. As of December 31, 2020 and 2019, accruals of $77 million and $120 million, respectively, were reflected in our consolidated balance sheets related to these contingent obligations.

For more information on our litigation and contingencies, see Note 10 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” in this report.

Environmental Remediation Activities. The Partnership’s accrual for environmental remediation activities reflects anticipated work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. The accrual for known claims is undiscounted and is based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. It is often extremely difficult to develop reasonable estimates of future site remediation costs due to changing regulations, changing technologies and their associated costs, and changes in the economic environment. Engineering studies, historical experience and other factors are used to identify and evaluate remediation alternatives and their related costs in determining the estimated accruals for environmental remediation activities.

Losses attributable to unasserted claims are generally reflected in the accruals on an undiscounted basis, to the extent they are probable of occurrence and reasonably estimable. We have established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims

 

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expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.

In general, each remediation site/issue is evaluated individually based upon information available for the site/issue and no pooling or statistical analysis is used to evaluate an aggregate risk for a group of similar items (e.g., service station sites) in determining the amount of probable loss accrual to be recorded. The Partnership’s estimates of environmental remediation costs also frequently involve evaluation of a range of estimates. In many cases, it is difficult to determine that one point in the range of loss estimates is more likely than any other. In these situations, existing accounting guidance requires that the minimum of the range be accrued. Accordingly, the low end of the range often represents the amount of loss which has been recorded. The Partnership’s consolidated balance sheets reflected $306 million and $320 million in environmental accruals as of December 31, 2020 and 2019, respectively.

Total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the nature of operations at each site, the technology available and needed to meet the various existing legal requirements, the nature and terms of cost-sharing arrangements with other potentially responsible parties, the availability of insurance coverage, the nature and extent of future environmental laws and regulations, inflation rates, terms of consent agreements or remediation permits with regulatory agencies and the determination of the Partnership’s liability at the sites, if any, in light of the number, participation level and financial viability of the other parties. The recognition of additional losses, if and when they were to occur, would likely extend over many years. Management believes that the Partnership’s exposure to adverse developments with respect to any individual site is not expected to be material. However, if changes in environmental laws or regulations occur or the assumptions used to estimate losses at multiple sites are adjusted, such changes could impact multiple facilities, formerly owned facilities and third-party sites at the same time. As a result, from time to time, significant charges against income for environmental remediation may occur; however, management does not believe that any such charges would have a material adverse impact on the Partnership’s consolidated financial position.

Deferred Income Taxes. ETO recognizes benefits in earnings and related deferred tax assets for net operating loss carryforwards (“NOLs”) and tax credit carryforwards. If necessary, a charge to earnings and a related valuation allowance are recorded to reduce deferred tax assets to an amount that is more likely than not to be realized by the Partnership in the future. Deferred income tax assets attributable to state and federal NOLs and federal excess business interest expense carryforwards totaling $1.047 billion have been included in ETO’s consolidated balance sheet as of December 31, 2020. The state NOL carryforward benefits of $220 million ($174 million net of federal benefit) begin to expire in 2021 with a substantial portion expiring between 2033 and 2039. ETO’s corporate subsidiaries have federal NOLs of $3.73 billion ($784 million in benefits) of which $1.3 billion will expire between 2031 and 2037. A total of $787 million of the federal net operating loss carryforward is limited under IRC §382. Although we expect to fully utilize the IRC §382 limited federal net operating loss, the amount utilized in a particular year may be limited. Any federal NOL generated in 2018 and future years can be carried forward indefinitely. We have determined that a valuation allowance totaling $113 million ($89 million net of federal income tax effects) is required for the state NOLs at December 31, 2020 primarily due to significant restrictions on their use in the Commonwealth of Pennsylvania. A separate valuation allowance of $45 million is attributable to foreign tax credits. In making the assessment of the future realization of the deferred tax assets, we rely on future reversals of existing taxable temporary differences, tax planning strategies and forecasted taxable income based on historical and projected future operating results. The potential need for valuation allowances is regularly reviewed by management. If it is more likely than not that the recorded asset will not be realized, additional valuation allowances which increase income tax expense may be recognized in the period such determination is made. Likewise, if it is more likely than not that additional deferred tax assets will be realized, an adjustment to the deferred tax asset will increase income in the period such determination is made.

 

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Forward-Looking Statements

This annual report contains various forward-looking statements and information that are based on our beliefs and those of our General Partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. When used in this annual report, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “could,” “believe,” “may,” “will” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our General Partner believe that the expectations on which such forward-looking statements are based are reasonable, neither we nor our General Partner can give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the key risk factors that may have a direct bearing on our results of operations and financial condition are:

 

   

the volumes transported on our pipelines and gathering systems;

 

   

the level of throughput in our processing and treating facilities;

 

   

the fees we charge and the margins we realize for our gathering, treating, processing, storage and transportation services;

 

   

the prices and market demand for, and the relationship between, natural gas and NGLs;

 

   

energy prices generally;

 

   

impacts of world health events, including the COVID-19 pandemic;

 

   

the prices of natural gas and NGLs compared to the price of alternative and competing fuels;

 

   

the general level of petroleum product demand and the availability and price of NGL supplies;

 

   

the level of domestic oil, natural gas and NGL production;

 

   

the availability of imported oil, natural gas and NGLs;

 

   

actions taken by foreign oil and gas producing nations;

 

   

the political and economic stability of petroleum producing nations;

 

   

the effect of weather conditions on demand for oil, natural gas and NGLs;

 

   

availability of local, intrastate and interstate transportation systems;

 

   

the continued ability to find and contract for new sources of natural gas supply;

 

   

availability and marketing of competitive fuels;

 

   

the impact of energy conservation efforts;

 

   

energy efficiencies and technological trends;

 

   

governmental regulation and taxation;

 

   

changes to, and the application of, regulation of tariff rates and operational requirements related to our interstate and intrastate pipelines;

 

   

hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs;

 

   

competition from other midstream companies and interstate pipeline companies;

 

   

loss of key personnel;

 

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loss of key natural gas producers or the providers of fractionation services;

 

   

reductions in the capacity or allocations of third-party pipelines that connect with our pipelines and facilities;

 

   

the effectiveness of risk-management policies and procedures and the ability of our liquids marketing counterparties to satisfy their financial commitments;

 

   

the nonpayment or nonperformance by our customers;

 

   

regulatory, environmental, political and legal uncertainties that may affect the timing and cost of our internal growth projects, such as our construction of additional pipeline systems;

 

   

risks associated with the construction of new pipelines and treating and processing facilities or additions to our existing pipelines and facilities, including difficulties in obtaining permits and rights-of-way or other regulatory approvals and the performance by third-party contractors;

 

   

the availability and cost of capital and our ability to access certain capital sources;

 

   

a deterioration of the credit and capital markets;

 

   

risks associated with the assets and operations of entities in which we own a noncontrolling interests, including risks related to management actions at such entities that we may not be able to control or exert influence;

 

   

the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results and to successfully integrate acquired businesses;

 

   

changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations or new interpretations by regulatory agencies concerning such laws and regulations; and

 

   

the costs and effects of legal and administrative proceedings.

You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risks described under “Item 1A. Risk Factors” in this annual report. Any forward-looking statement made by us in this Annual Report on Form 10-K is based only on information currently available to us and speaks only as of the date on which it is made. We undertake no obligation to publicly update any forward-looking statement, whether written or oral, that may be made from time to time, whether as a result of new information, future developments or otherwise.

Inflation

Interest rates on existing and future credit facilities and future debt offerings could be significantly higher than current levels, causing our financing costs to increase accordingly. Although increased financing costs could limit our ability to raise funds in the capital markets, we expect to remain competitive with respect to acquisitions and capital projects since our competitors would face similar circumstances.

Inflation in the United States has been relatively low in recent years and has not had a material effect on our results of operations. It may in the future, however, increase the cost to acquire or replace property, plant and equipment and may increase the costs of labor and supplies. Our operating revenues and costs are influenced to a greater extent by commodity price changes. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along a portion of increased costs to our customers in the form of higher fees.

 

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risk includes the risk of loss arising from adverse changes in market rates and prices. We face market risk from commodity variations, risk and interest rate variations, and to a lesser extent, credit risks. From time to time, we may utilize derivative financial instruments as described below to manage our exposure to such risks.

Commodity Price Risk

We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets.

We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized.

We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales on our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes.

We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes.

We utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes.

We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales. These contracts are not designated as hedges for accounting purposes.

We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.

 

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The table below summarizes our commodity-related financial derivative instruments and fair values, including derivatives related to our consolidated subsidiaries, as well as the effect of an assumed hypothetical 10% change in the underlying price of the commodity. Dollar amounts are presented in millions.

 

    December 31, 2020     December 31, 2019  
    Notional
Volume
    Fair Value
Asset
(Liability)
    Effect of
Hypothetical
10% Change
    Notional
Volume
    Fair Value
Asset
(Liability)
    Effect of
Hypothetical
10% Change
 

Mark-to-Market Derivatives

           

(Trading)

           

Natural Gas (BBtu):

           

Fixed Swaps/Futures

    1,603   $ —       $ —         1,483   $ —       $ —    

Basis Swaps IFERC/NYMEX(1)

    (44,225     2     5     (35,208     2     5

Power (Megawatt):

           

Forwards

    1,392,400     4     —         3,213,450     6     8

Futures

    18,706     (1     —         (353,527     1     2

Options — Puts

    519,071     —         —         51,615     1     —    

Options — Calls

    2,343,293     1     —         (2,704,330     1     —    

(Non-Trading)

           

Natural Gas (BBtu):

           

Basis Swaps IFERC/NYMEX

    (29,173     —         1     (18,923     (35     15

Swing Swaps IFERC

    11,208     (2     —         (9,265     —         4

Fixed Swaps/Futures

    (53,575     6     31     (3,085     (1     1

Forward Physical Contracts

    (11,861     4     5     (13,364     3     3

NGL (MBbls) — Forwards/Swaps

    (5,840     (100     39     (1,300     (18     18

Crude (MBbls) — Forwards/Swaps

    —         —         —         4,465     13     2

Refined Products (MBbls) — Futures

    (2,765     (8     3     (2,473     (2     16

Corn (thousand bushels)

    —         —         —         (1,210     —         —    

Fair Value Hedging Derivatives

           

(Non-Trading)

           

Natural Gas (BBtu):

           

Basis Swaps IFERC/NYMEX

    (30,113     (1     —         (31,780     1     7

Fixed Swaps/Futures

    (30,113     (6     8     (31,780     23     7

 

(1)

Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.

The fair values of the commodity-related financial positions have been determined using independent third-party prices, readily available market information and appropriate valuation techniques. Non-trading positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the above tables. Price-risk sensitivities were calculated by assuming a theoretical 10% change (increase or decrease) in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. Results are presented in absolute terms and represent a potential gain or loss in net income or in other comprehensive income. In the event of an actual 10% change in prompt month natural gas prices, the fair value of our total derivative portfolio may not change by 10% due to factors such as when the financial instrument settles and the location to which the financial instrument is tied (i.e., basis swaps) and the relationship between prompt month and forward months.

Interest Rate Risk

As of December 31, 2020, we and our subsidiaries had $6.72 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of $67 million annually; however, our actual change in interest expense may be less in a given period due to interest

 

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rate floors included in our variable rate debt instruments. We manage a portion of our interest rate exposure by utilizing interest rate swaps, including forward-starting interest rate swaps to lock-in the rate on a portion of anticipated debt issuances.

The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes (dollar amounts presented in millions):

 

          Notional Amount Outstanding  

Term

  

Type (1)

   December 31,
2020
     December 31,
2019
 

July 2020 (2)(3)

   Forward-starting to pay a fixed rate of 3.52% and receive a floating rate    $ —      $ 400

July 2021 (2)

   Forward-starting to pay a fixed rate of 3.55% and receive a floating rate      400      400

July 2022 (2)

   Forward-starting to pay a fixed rate of 3.80% and receive a floating rate      400      400

 

(1)

Floating rates are based on 3-month LIBOR.

(2)

Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.

(3)

The July 2020 interest rate swaps were terminated in January 2020.

A hypothetical change of 100 basis points in interest rates for these interest rate swaps would result in a net change in the fair value of interest rate derivatives and earnings (recognized in gains (losses) on interest rate derivatives) of $275 million as of December 31, 2020. For the forward-starting interest rate swaps, a hypothetical change of 100 basis points in interest rates would not affect cash flows until the swaps are settled.

Credit Risk

Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.

The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrial end-users, oil and gas producers, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.

For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.

 

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The financial statements starting on page F-1 of this report are incorporated by reference.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING

AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

An evaluation was performed under the supervision and with the participation of our management, including Marshall S. McCrea, III, and Thomas E. Long, Co-Chief Executive Officers of ETP LLC (Co-Principal Executive Officers), and Bradford D. Whitehurst (Principal Financial Officer), of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rules 13a–15(e) and 15d–15(e) of the Exchange Act) as of the end of the period covered by this report. Based upon that evaluation, management, including Messrs. McCrea, Long and Whitehurst, concluded that our disclosure controls and procedures were adequate and effective as of December 31, 2020.

Management’s Report on Internal Control over Financial Reporting

The management of Energy Transfer Operating, L.P. and subsidiaries is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including the Co-Chief Executive Officers and Chief Financial Officer of ETP LLC, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal ControlIntegrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO framework”).

Based on our evaluation under the COSO framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2020.

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting (as defined in Rules 13a–15(f) or Rule 15d–15(f)) that occurred in the three months ended December 31, 2020 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

 

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Board of Directors

Our General Partner, Energy Transfer Partners GP, L.P. (“ETP GP”), manages and directs all of our activities. The activities of ETP GP are managed and directed by its general partner, ETP LLC, which we refer to in this Item as “our General Partner.” Our officers and directors are officers and directors of ETP LLC. ET, as the sole member of ETP LLC, is entitled under the limited liability company agreement of ETP LLC to appoint all of the directors of ETP LLC. This agreement provides that the Board of Directors of ETP LLC shall consist of not more than 13 persons, at least three of whom are required to qualify as independent directors.

As of January 1, 2020, our Board of Directors is comprised of six persons, three of whom qualified as “independent” under the NYSE’s corporate governance standards. Our Board of Directors determined that Messrs. Smith, Skidmore and Williams all met the NYSE’s independence requirements. Our current directors who are not independent consist of Kelcy L. Warren, ETP LLC’s Executive Chairman, Matthew S. Ramsey, ETP LLC’s President and Chief Operating Officer and Marshall S. McCrea, III, ETP LLC’s Chief Commercial Officer.

As a limited partnership, we are not required by the rules of the NYSE to seek Unitholder approval for the election of any of our directors. We believe that ET has appointed as directors individuals with experience, skills and qualifications relevant to the business of the Partnership, such as experience in energy or related industries or with financial markets, expertise in natural gas operations or finance, and a history of service in senior leadership positions. We do not have a formal process for identifying director nominees, nor do we have a formal policy regarding consideration of diversity in identifying director nominees, but we believe ET has endeavored to assemble a group of individuals with the qualities and attributes required to provide effective oversight of the Partnership.

Board Leadership Structure. We have no policy requiring either that the positions of the Chairman of the Board and the Chief Executive Officer, or CEO, be separate or that they be occupied by the same individual. The Board of Directors believes that this issue is properly addressed as part of the succession planning process and that a determination on this subject should be made when it elects a new chief executive officer or at such other times as when consideration of the matter is warranted by circumstances. Previously, the Board of Directors believed that the CEO was best situated to serve as Chairman because he was the director most familiar with the Partnership’s business and industry, and most capable of effectively identifying strategic priorities and leading the discussion and execution of strategy. Beginning in 2021, the Board of Directors has established separate roles for the Executive Chairman and Co-Chief Executive Officers. Independent directors and management have different perspectives and roles in strategy development. Our independent directors bring experience, oversight and expertise from outside the Partnership and from a variety of industries, while the Executive Chairman and Co-Chief Executive Officers bring extensive experience and expertise specifically related to the Partnership’s business.

Risk Oversight. Our Board of Directors generally administers its risk oversight function through the board as a whole. Our Co-CEOs, who report to the Board of Directors, and the other executive officers, who report to our Co-CEOs, have day-to-day risk management responsibilities. Each of these executives attends the meetings of our Board of Directors, where the Board of Directors routinely receives reports on our financial results, the status of our operations, and other aspects of implementation of our business strategy, with ample opportunity for specific inquiries of management. In addition, at each regular meeting of the Board, management provides a report of the Partnership’s financial and operational performance, which often prompts questions or feedback from the Board of Directors. The Audit Committee provides additional risk oversight through its quarterly meetings, where it receives a report from the Partnership’s internal auditor, who reports directly to the Audit Committee, and reviews the Partnership’s contingencies with management and our independent auditors.

 

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Corporate Governance

The Board of Directors has adopted both a Code of Business Conduct and Ethics applicable to our directors, officers and employees, and Corporate Governance Guidelines for directors and the Board. Current copies of our Code of Business Conduct and Ethics, Corporate Governance Guidelines and charters of the Audit and Compensation Committees of our Board of Directors are available on our website at www.energytransfer.com.

Please note that the preceding Internet address is for information purposes only and is not intended to be a hyperlink. Accordingly, no information found and/or provided at such Internet addresses or at our website in general is intended or deemed to be incorporated by reference herein.

Annual Certification

In 2020, our CEO provided to the NYSE the annual CEO certification regarding our compliance with the NYSE corporate governance listing standards.

Conflicts Committee

Our Partnership Agreement provides that the Board of Directors may, from time to time, appoint members of the Board to serve on the Conflicts Committee with the authority to review specific matters for which the Board of Directors believes there may be a conflict of interest in order to determine if the resolution of such conflict proposed by the General Partner is fair and reasonable to the Partnership and its Unitholders. As a policy matter, the Conflicts Committee generally reviews any proposed related-party transaction that may be material to the Partnership to determine if the transaction presents a conflict of interest and whether the transaction is fair and reasonable to the Partnership. Pursuant to the terms of our Partnership Agreement, any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to the Partnership, approved by all partners of the Partnership and not a breach by the General Partner or its Board of Directors of any duties they may owe the Partnership or the Unitholders. These duties are limited by our Partnership Agreement (see “Risks Related to Conflicts of Interest” in “Item 1A. Risk Factors” in this annual report).

Audit Committee

The Board of Directors has established an Audit Committee in accordance with Section 3(a)(58)(A) of the Exchange Act. The Board of Directors appoints persons who are independent under the NYSE’s standards for audit committee members to serve on its Audit Committee. In addition, the Board determines that at least one member of the Audit Committee has such accounting or related financial management expertise sufficient to qualify such person as the audit committee financial expert in accordance with Item 407 (d)(5) of Regulation S-K. The Board has determined that based on relevant experience, Audit Committee member David K. Skidmore qualified as Audit Committee financial expert during 2020. A description of the qualifications of Mr. Skidmore may be found elsewhere in this Item under “Directors and Executive Officers of our General Partner.”

The Audit Committee meets on a regularly scheduled basis with our independent accountants at least four times each year and is available to meet at their request. The Audit Committee has the authority and responsibility to review our external financial reporting, review our procedures for internal auditing and the adequacy of our internal accounting controls, consider the qualifications and independence of our independent accountants, engage and direct our independent accountants, including the letter of engagement and statement of fees relating to the scope of the annual audit work and special audit work which may be recommended or required by the independent accountants, and to engage the services of any other advisors and accountants as the Audit Committee deems advisable. The Audit Committee reviews and discusses the audited financial statements with management, discusses with our independent auditors matters required to be discussed by auditing standards, and makes recommendations to the Board of Directors relating to our audited financial statements. The Audit Committee periodically recommends to the Board of Directors any changes or modifications to its charter that may be required. The Board of Directors adopts the charter for the Audit Committee. Messrs. Skidmore, Smith and Williams currently serve on the Audit Committee.

 

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Compensation and Nominating/Corporate Governance Committees

We are not required under NYSE rules to appoint a compensation committee or a nominating/corporate governance committee because we are a limited partnership; however, our Board of Directors previously established a Compensation Committee to establish standards and make recommendations concerning the compensation of our officers and directors. Following the Energy Transfer Merger, the duties of the ETO compensation committee have been delegated to the Compensation Committee of ET.

Code of Business Conduct and Ethics

The Board of Directors has adopted a Code of Business Conduct and Ethics applicable to our officers, directors and employees. Specific provisions are applicable to the co-principal executive officers, principal financial officer, principal accounting officer and controller, or those persons performing similar functions, of our General Partner. Amendments to, or waivers from, the Code of Business Conduct and Ethics will be available on our website and reported as may be required under SEC rules. Any technical, administrative or other non-substantive amendments to the Code of Business Conduct and Ethics may not be posted.

Meetings of Non-management Directors and Communications with Directors

Our non-management directors meet in regularly scheduled sessions. The Chairman of our Audit Committee acts as the presiding director of such meetings.

We have established a procedure by which interested parties may communicate directly with the Board of Directors, any committee of the Board, any independent directors, or any one director serving on the Board of Directors by sending written correspondence addressed to the desired person or entity to the attention of our General Counsel at Energy Transfer Operating, L.P., 8111 Westchester Drive, Suite 600, Dallas, Texas 75225 or generalcounsel@energytransfer.com. Communications are distributed to the Board of Directors, or to any individual director or directors as appropriate, depending on the facts and circumstances outlined in the communication.

Directors and Executive Officers of Our General Partner

The following table sets forth certain information with respect to the executive officers and members of the Board of Directors of our General Partner as of February 19, 2021. Executive officers and directors are elected for one-year terms.

 

Name

   Age   

Position with Our General Partner

Kelcy L. Warren

   65    Executive Chairman of the Board of Directors

Matthew S. Ramsey

   65    Director, President and Chief Operating Officer

Thomas E. Long

   64    Co-Chief Executive Officer (Co-Principal Executive Officer)

Marshall S. (Mackie) McCrea, III

   61    Co-Chief Executive Officer and Director (Co-Principal Executive Officer)

Bradford D. Whitehurst

   46    Chief Financial Officer (Principal Financial Officer)

James M. Wright, Jr.

   52    General Counsel

A. Troy Sturrock

   50    Senior Vice President and Controller (Principal Accounting Officer)

David K. Skidmore

   65    Director

W. Brett Smith

   61    Director

William P. Williams

   83    Director

 

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Messrs. Warren, McCrea and Ramsey also serve as directors of ET’s general partner. Mr. Ramsey also serves as chairman of the board of the general partner of Sunoco LP, and Mr. Long serves as a director of the board of the general partner of Sunoco LP.

Set forth below is biographical information regarding the foregoing officers and directors of our General Partner:

Kelcy L. Warren. Mr. Warren is the Executive Chairman of the Board of Directors of the general partner of ETO. Mr. Warren also serves as Executive Chairman of the Board of Directors of ET’s general partner. Mr. Warren also served as the Chief Executive Officer of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Prior to the combination of the operations of ETO and Heritage Propane in 2004, Mr. Warren co-founded the entities that acquired and operated the midstream assets that were contributed in the merger. From 1996 to 2000, Mr. Warren served as a Director of Crosstex Energy, Inc. and from 1993 to 1996, he served as President, Chief Operating Officer and a Director of Cornerstone Natural Gas, Inc. Mr. Warren was selected to serve as a director and as Executive Chairman because he previously served as the Partnership’s Chief Executive Officer and has more than 30 years in the natural gas industry. Mr. Warren also has relationships with chief executives and other senior management at natural gas transportation companies throughout the United States and brings a unique and valuable perspective to the Board of Directors.

Matthew S. Ramsey. Mr. Ramsey was appointed as a director of ET’s general partner in July 2012 and as a director of ETO’s general partner in November 2015. Mr. Ramsey was named President and Chief Operating Officer of ETO’s general partner in November 2015. He became the Chief Operating Officer of ET’s general partner in October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. Mr. Ramsey is also a director of Sunoco LP, having served as chairman of Sunoco LP’s board since April 2015, and of USAC, having served on that board since April 2018. Mr. Ramsey also served as President and Chief Operating Officer and Chairman of the board of directors of PennTex Midstream Partners, LP’s general partner, from November 2016 to July 2017. Mr. Ramsey previously served as President of RPM Exploration, Ltd., a private oil and gas exploration partnership, and previously served as a director of RSP Permian, Inc. where he served on the audit and compensation committees. Mr. Ramsey formerly served as President of DDD Energy, Inc. until its sale in 2002. From 1996 to 2000, Mr. Ramsey served as President and Chief Executive Officer of OEC Compression Corporation, Inc., a publicly traded oil field service company, providing gas compression services to a variety of energy clients. Previously, Mr. Ramsey served as Vice President of Nuevo Energy Company, an independent energy company. Additionally, he was employed by Torch Energy Advisors, Inc., a company providing management and operations services to energy companies including Nuevo Energy, last serving as Executive Vice President. Mr. Ramsey joined Torch Energy as Vice President of Land and was named Senior Vice President of Land in 1992. Mr. Ramsey holds a B.B.A. in Marketing from the University of Texas at Austin and a J.D. from South Texas College of Law. Mr. Ramsey is a graduate of Harvard Business School Advanced Management Program. Mr. Ramsey is licensed to practice law in the State of Texas. He is qualified to practice in the Western District of Texas and the United States Court of Appeals for the Fifth Circuit. Mr. Ramsey formerly served as a director of Southern Union Company. ET recognizes Mr. Ramsey’s vast experience in the oil and gas space and believes that he provides valuable industry insight as a member of our Board of Directors.

Thomas E. Long. Mr. Long has served as the Co-Chief Executive Officer of our general partner since January 2021. Mr. Long served as Chief Financial Officer of our general partner from February 2016 until January 2021 and has been a director of ET’s general partner since April 2019. He also joined the Board of Directors of ET’s general partner in April 2019. Mr. Long also served as the Chief Financial Officer and as a director of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Long also served as Chief Financial Officer of ETO and was previously Executive Vice President and Chief Financial Officer of Regency GP LLC from November 2010 to April 2015. From May 2008 to November 2010, Mr. Long served as Vice President and Chief Financial Officer of Matrix Service Company. Prior to joining Matrix, he served as Vice President and Chief Financial Officer of DCP Midstream Partners, LP, a publicly traded natural gas and natural gas liquids midstream business company located in Denver, Colorado. In that position, he was responsible for all

 

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financial aspects of the company since its formation in December 2005. From 1998 to 2005, Mr. Long served in several executive positions with subsidiaries of Duke Energy Corp., one of the nation’s largest electric power companies. Mr. Long has served as a director of Sunoco LP since May 2016, and as Chairman of the Board of USAC since April 2018.

Marshall S. (Mackie) McCrea, III. Mr. McCrea has served as the Co-Chief Executive Officer of our general partner since January 2021. Prior to that, he was the President and Chief Commercial Officer of our general partner, having served in that role since October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. Prior to that time, he had been the Group Chief Operating Officer and Chief Commercial Officer of the Energy Transfer family since November 2015. Mr. McCrea was appointed as a director of the general partner of ETO and as a director of ET’s general partner in December 2009. Prior to that, he served as President and Chief Operating Officer of ETO’s general partner from June 2008 to November 2015 and President—Midstream from March 2007 to June 2008. Previously he served as the Senior Vice President—Commercial Development since January 2004. In March 2005, Mr. McCrea was named President of La Grange Acquisition LP, ETO’s primary operating subsidiary, after serving as Senior Vice President-Business Development and Producer Services since 1997. Mr. McCrea also served as the Chairman of the Board of Directors of the general partner of Sunoco Logistics Partners L.P. from October 2012 to April 2017. Mr. McCrea was selected to serve as a director because he brings extensive project development and operational experience to the Board. He has held various positions in the natural gas business over the past 25 years and is able to assist the Board of Directors in creating and executing the Partnership’s strategic plan.

Bradford D. Whitehurst. Mr. Whitehurst was appointed Chief Financial Officer of Energy Transfer in January 2021. From August 2014 through December 2020 he served as Executive Vice President—Head of Tax. Prior to joining Energy Transfer, Mr. Whitehurst was a partner in the Washington, DC office of Bingham McCutchen LLP and an attorney in the Washington, DC offices of both McKee Nelson LLP and Hogan & Hartson. Mr. Whitehurst has specialized in partnership taxation and has advised ET and its subsidiaries in his role as outside counsel since 2006. He has served as a member of the board of directors of USAC since April 2018.

James M. Wright, Jr. Mr. Wright was elected General Counsel of our general partner in December 2015. He became Executive Vice President—Legal and Chief Compliance Officer of ET’s general partner in October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. Mr. Wright has been a part of the Energy Transfer legal team with increasing levels of responsibility since July 2005, and served as its Deputy General Counsel from May 2008 to December 2015. Prior to joining Energy Transfer, Mr. Wright gained significant experience at Enterprise Products Partners, L.P., El Paso Corp., Sonat Exploration Company and KPMG Peat Marwick LLP. Mr. Wright earned a Bachelor of Business Administration degree in Accounting and Finance from Texas A&M University and a JD from South Texas College of Law.

A. Troy Sturrock. Mr. Sturrock has served as the Senior Vice President and Controller of the general partner of ETO since August 2016 and previously served as Vice President and Controller of our General Partner since June 2015. Mr. Sturrock also served as a Senior Vice President of PennTex Midstream Partners, LP’s general partner, from November 2016 until July 2017, and as its Controller and Principal Accounting Officer from January 2017 until July 2017. He became Senior Vice President, Controller and Principal Accounting Officer of ET’s general partner in October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. Mr. Sturrock previously served as Vice President and Controller of Regency GP LLC from February 2008, and in November 2010 was appointed as the principal accounting officer. From June 2006 to February 2008, Mr. Sturrock served as the Assistant Controller and Director of financial reporting and tax for Regency GP LLC. Mr. Sturrock is a Certified Public Accountant.

David K. Skidmore. Mr. Skidmore has served as a director of our general partner since March 2013. He has been Vice President of Ventex Oil & Gas, Inc. since 1995 and has been actively involved in exploration and production throughout the Gulf Coast and mid-Continent regions for over 35 years. He founded Skidmore Exploration, Inc. in 1981 and has been an independent oil and gas producer since that time. From 1977 to 1981,

 

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he worked for Paraffine Oil Corporation and Texas Oil & Gas in Houston. He holds BS degrees in both Geology and Petroleum Engineering, is a Certified Petroleum Geologist and Registered Professional Engineer, and active member of the AAPG, and SPE. Mr. Skidmore is also a member of ETO’s audit committee. Mr. Skidmore was selected to serve as a director because of his continual involvement in geological, geophysical, legal, engineering and accounting aspects of an active oil and gas exploration company. As an energy professional, active oil and gas producer and successful business owner, Mr. Skidmore possesses valuable first-hand knowledge of the energy transportation business and market conditions affecting its economics.

W. Brett Smith. Mr. Smith was appointed to the Board of Directors of our general partner in February 2018 and has served on the audit committee since that time. He has served as President and Managing Partner of Rubicon Oil & Gas, LLC since October 2000. He has also served as President of Rubicon Oil & Gas II, LP since May 2005, President of Quientesa Royalty LP since February 2005 and President of Action Energy LP since October 2008. Mr. Smith was President of Rubicon Oil & Gas, LP from October 2000 to May 2005. For more than 30 years Mr. Smith has been active in assembling exploration prospects in the Permian Basin, Oklahoma, New Mexico and the Rocky Mountain areas. Mr. Smith previously served on the board of directors of Sunoco LP and was a member of its audit and compensation committees. Mr. Smith was selected to serve on the Board of Directors of our general partner based on his experience as an executive in the oil and gas exploration and production business, which gives him unique insight into the Partnership’s business, as well as his recent experience on the board of another publicly traded limited partnership.

William P. Williams. Mr. Williams began his career in the oil and gas industry in 1967 with Texas Power and Light Company as Manager of Pipeline Construction for Bi-Stone Fuel Company, a predecessor of Texas Utilities Fuel Company. In 1980, he was employed by Endevco as Vice President of Pipeline and Plant Construction, Engineering, and Operations. Prior to Endevco, he worked for Cornerstone Natural Gas followed by Vice President of Engineering and Operations at Energy Transfer Partners, L.P., ending his career as Vice President of Measurement on May 1, 2011. Mr. Williams was selected due to his experience in the pipeline industry and his familiarity with our business.

Compensation of the General Partner

Our General Partner does not receive any management fee or other compensation in connection with its management of the Partnership. Our General Partner and its affiliates performing services for the Partnership are reimbursed at cost for all expenses incurred on behalf of the Partnership, including the costs of employee compensation allocable to, but not paid directly by, the Partnership, if any, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, the Partnership. Our employees are employed by our subsidiaries, and thus, our General Partner does not incur additional reimbursable costs.

Our General Partner is ultimately controlled by the general partner of ET, which general partner entity is partially-owned by certain of our current and prior named executive officers. We pay quarterly distributions to our General Partner in accordance with our Partnership Agreement with respect to its ownership of a general partner interest and the incentive distribution rights specified in our Partnership Agreement. The amount of each quarterly distribution that we must pay to our General Partner is based solely on the provisions of our Partnership Agreement, which agreement specifies the amount of cash we distribute to our General Partner based on the amount of cash that we distribute to our limited partners each quarter. Accordingly, the cash distributions we make to our General Partner bear no relationship to the level or components of compensation of our General Partner’s executive officers. Our General Partner’s distribution rights are described in detail in Note 7 to our consolidated financial statements. Our named executive officers also own directly and indirectly certain of our limited partner interests and, accordingly, receive quarterly distributions. Such per unit distributions equal the per unit distributions made to all our limited partners and bear no relationship to the level of compensation of the named executive officers.

 

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ITEM 11. EXECUTIVE COMPENSATION

Overview

As a limited partnership, we are managed by our General Partner. Our General Partner is owned by ET.

Compensation Discussion and Analysis

Named Executive Officers

ETO does not have officers or directors. Instead, we are managed by the board of directors of our General Partner, and the executive officers of our General Partner perform all of ETO’s management functions. In addition, our executive officers are also executive officers of ET. The board of directors of our General Partner does not have a separate compensation committee. Therefore, we do not administer any policies or programs relating to the compensation of ET’s named executive officers. The compensation of our executive officers is administered by the compensation committee of the board of directors of ET’s general partner (the “ET Compensation Committee”). This Compensation Discussion and Analysis is, therefore, focused on the total compensation of the executive officers of ET’s General Partner as set forth below. Compensation amounts discussed herein include all compensation paid to ET’s named executive officers, including amounts attributable to services performed for us. The persons we refer to in this discussion as the “named executive officers” are the following:

 

   

Kelcy L. Warren, Executive Chairman and former Chief Executive Officer during 2020 (Executive Chairman effective January 1, 2021);

 

   

Thomas E. Long, Chief Financial Officer during 2020 (Co-Chief Executive Officer and effective January 1, 2021);

 

   

Marshall S. (Mackie) McCrea, III, President and Chief Commercial Officer during 2020 (Co-Chief Executive Officer and effective January 1, 2021);

 

   

Matthew S. Ramsey, Chief Operating Officer; and

 

   

Thomas P. Mason, Executive Vice President, General Counsel and President—LNG.

Effective January 1, 2021, Mr. Warren assumed the role of Executive Chairman, and Messrs. Long and McCrea were appointed Co-Chief Executive Officers.

Bradford D. Whitehurst was appointed Chief Financial Officer of our General Partner effective January 8, 2021. Mr. Whitehurst is excluded from the compensation discussion and analysis and compensation tables herein, as he was not a named executive officer during 2020.

ET’s General Partner’s Philosophy for Compensation of Executives

In general, our General Partner’s philosophy for executive compensation is based on the premise that a significant portion of each executive’s compensation should be incentive-based or “at-risk” compensation and that executives’ total compensation levels should be highly competitive in the marketplace for executive talent and abilities. Our General Partner seeks a total compensation program for its executive officers, including the named executive officers, that provides for a slightly below the median market annual base compensation (i.e. approximately the 30th to 40th percentile of market) but incentive-based compensation composed of a combination of compensation vehicles to reward both short and long-term performance that are both targeted to pay-out at approximately the top-quartile of market. Our General Partner believes the incentive-based balance is achieved by (i) the payment of annual discretionary cash bonuses that consider the achievement of the Partnership’s financial performance objectives for a fiscal year set at the beginning of such fiscal year and the individual contributions of its executive officers, including the named executive officers to the success of the

 

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Partnership and the achievement of the annual financial performance objectives and (ii) the annual grant of time-based restricted unit, phantom unit awards or cash restricted unit awards under the Partnership’s equity incentive plan(s) or the equity incentive programs of Sunoco LP, as applicable based on the allocation of executive officers awards, including awards to the named executive officers, which awards are intended to provide a longer term incentive and retention value to its key employees to focus their efforts on increasing the market price of its publicly traded units and to increase the cash distribution the Partnership and/or the other affiliated partnerships pay to their respective unitholders.

ET’s General Partner has historically granted restricted unit and/or phantom unit awards (“RSUs”) that vest, based generally upon continued employment, at a rate of 60% after the third year of service and the remaining 40% after the fifth year of service. In 2020, ET’s General Partner also granted cash restricted units (“CRSUs”) that vest, based generally upon continued employment, at a rate of 1/3 annually over a three-year period. For 2020, the awards to employees were generally split equally between RSUs and CRSUs. ET’s General Partner believes that these equity-based incentive arrangements are important in attracting and retaining executive officers and key employees as well as motivating these individuals to achieve stated business objectives. The equity-based compensation reflects the importance ET’s General Partner places on aligning the interests of its named executive officers with those of unitholders.

As discussed below, the ET Compensation Committee, is responsible for the compensation policies and compensation level of our executive officers, including the named executive officers. In this discussion, we refer to ET Compensation Committee and the ETO Compensation Committee prior to the Energy Transfer Merger as the “ET Compensation Committee.”

For a more detailed description of the compensation to the Partnership’s named executive officers, please see “—Compensation Tables” below.

Compensation Philosophy

ET’s compensation programs are structured to achieve the following:

 

   

reward executives with an industry-competitive total compensation package of base salaries and significant incentive opportunities yielding a total compensation package approaching the top-quartile of the market;

 

   

attract, retain and reward talented executive officers and key management employees by providing total compensation competitive with that of other executive officers and key management employees employed by publicly traded limited partnerships of similar size and in similar lines of business;

 

   

motivate executive officers and key employees to achieve strong financial and operational performance;

 

   

emphasize performance-based, or “at-risk,” compensation; and

 

   

reward individual performance.

Components of Executive Compensation

For the year ended December 31, 2020, the compensation paid to the named executive officers consisted of the following components:

 

   

annual base salary;

 

   

non-equity incentive plan compensation consisting solely of discretionary cash bonuses;

 

   

time-vested restricted/phantom unit awards and cash restricted units under the equity incentive plan(s);

 

   

payment of distribution equivalent rights (“DERs”) on unvested time-based restricted unit awards under our equity incentive plan;

 

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vesting of previously issued time-based restricted unit and/or phantom unit awards issued pursuant to ET’s equity incentive plans or the equity incentive plans(s) of affiliates; and

 

   

401(k) plan employer contributions.

Methodology

The ET Compensation Committee considers relevant data available to it to assess our competitive position with respect to base salary, annual short-term incentives and long-term incentive compensation for the executive officers of its General Partner, including the named executive officers. The ET Compensation Committee also considers individual performance, levels of responsibility, skills and experience.

Periodically, the ET Compensation Committee engages a third-party independent compensation consultant to provide a full market competitive compensation analysis for compensation levels at peer companies in order to assist in the determination of compensation levels for our executive officers, including the named executive officers. Most recently, Longnecker & Associates (“Longnecker”) evaluated the market competitiveness of total compensation levels of a number of officers of the Partnership to provide market information with respect to compensation of those executives during the year ended December 31, 2019. In particular, the review by Longnecker was designed to (i) evaluate the market competitiveness of total compensation levels for certain members of senior management, including the named executive officers; (ii) assist in the determination of appropriate compensation levels for our senior management, including the named executive officers; and (iii) confirm that our compensation programs were yielding compensation packages consistent with our overall compensation philosophy.

In conducting its review, Longnecker specifically considered the larger size of the combined ET entities from an energy industry perspective. During 2019, Longnecker assisted in the development of the final “peer group” of leading companies in the energy industry that most closely reflect the profile of ET in terms of revenues, assets and market value as well as competition for talent at the senior management level and similarly situated general industry companies with similar revenues, assets and market value. In setting such peer group, the size of ET on a combined basis was considered. As part of the evaluation conducted by Longnecker, a determination was made to focus the analysis specifically on the energy industry peers. This decision was based on a determination that an energy industry peer group provided a more than sufficient amount of comparative data to consider and evaluate total compensation. This focus allowed Longnecker to report on specific industry related data comparing the levels of annual base salary, annual short-term cash bonus and long-term equity incentive awards at industry peer group companies with those of the named executive officers to ensure that compensation of the named executive officers is both consistent with the compensation philosophy and competitive with the compensation for executive officers of these other companies. The identified companies were:

 

Energy Peer Group:

  

•  Conoco Phillips

  

•  Marathon Petroleum Corporation

•  Enterprise Products Partners, L.P.

  

•  Kinder Morgan, Inc.

•  Plains All American Pipeline, L.P.

  

•  The Williams Companies, Inc.

•  Valero Energy Corporation

  

•  Phillips 66

The compensation analysis provided by Longnecker in 2019 covered all major components of total compensation, including annual base salary, annual short-term cash bonus and long-term incentive awards for the senior executives of these companies. In preparing the review materials, Longnecker utilized generally accepted compensation principles as determined by WorldatWork and gathered data from public disclosures of peer companies, including 10-K and proxy data and published survey data from multiple sources that are relevant to ET’s peer group, industry, financial size and operational breadth. The Longnecker review process also included significant engagement with management to fully understand job scope, responsibilities and roles of each of the executive officers, which discussions allow Longnecker the ability to completely evaluate specific aspects of an executive officer’s position to allow for more accurate comparisons.

 

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Following Longnecker’s 2019 review, the ET Compensation Committee reviewed the information provided, including Longnecker’s specific conclusions and recommended considerations for all compensation going forward. The ET Compensation Committee considered and reviewed the results of the study performed by Longnecker to determine if the results indicated that the compensation programs were yielding a competitive total compensation model prioritizing incentive-based compensation and rewarding achievement of short and long-term performance objectives and considered Longnecker’s conclusions and recommendations. While Longnecker found that the Partnership is achieving its stated objectives with respect to the “at-risk” approach, they also found that certain adjustments could be considered moving forward to allow the Partnership to continue to achieve its targeted percentiles on base compensation and incentive compensation (short and long-term). Longnecker’s suggested adjustments as part of the 2019 were not implemented in 2020 as management and the ET Compensation Committee determined to postpone any changes in light of the impacts of the COVID-19 pandemic on ET and on the global energy market.

In addition to the information received as part of Longnecker’s 2019 review, the ET Compensation Committee also utilizes information obtained from other sources in its determination of compensation levels for our named executive officers, such as annual third party surveys, although third party survey data is not used by the ET Compensation Committee to benchmark the amount of total compensation or any specific element of compensation for the named executive officers.

In addition to the 2019 compensation analysis for executive officers, Longnecker also provided advice and feedback on certain other matters, including the appropriateness, targets and composition of the annual equity award pools and the annual bonus awards under the Energy Transfer Annual Bonus Plan (the “Bonus Plan”) and benchmarking on certain non-named executive officer hires and promotions.

In 2020, Longnecker also provided advice and recommendations on the total compensation packages for Messrs. McCrea and Long in connection with their joint appointment as Co-Chief Executive Officers, including with respect to certain one-time equity and cash awards, as applicable.

Base Salary. Base salary is designed to provide for a competitive fixed level of pay that attracts and retains executive officers and compensates them for their level of responsibility and sustained individual performance (including experience, scope of responsibility and results achieved). The salaries of the named executive officers are reviewed on an annual basis. As discussed above, the base salaries of our named executive officers are targeted to yield an annual base salary slightly below the median level of market (i.e. approximately the 30th to 40th percentile of market) and are determined by the ET Compensation Committee after taking into account the recommendations of Mr. Warren.

During the merit review process, the ET Compensation Committee considers the recommendations of Mr. Warren, any relevant compensation study data (with the data aged as appropriate) and the merit increase pool set for all employees of the Partnership and/or its employing affiliates. During 2020, given the challenging conditions within the industry, including the impacts of the COVID-19 pandemic, the ET Compensation Committee did not approve any increases to base salaries of the named executive officers. Thus, 2020 base salaries for the named executive officers were consistent with the prior year amounts: $1,114,555 for Mr. McCrea; $600,000 for Mr. Long; $696,598 for Mr. Ramsey; and $631,396 for Mr. Mason. Mr. Warren has voluntarily determined that his salary will be $1.00 per year (plus an amount sufficient to cover his allocated payroll deductions for health and welfare benefits).

In connection with their promotions to Co-Chief Executive Officer effective January 1, 2021, the ET Compensation Committee approved increases in the annual base salaries of Messrs. McCrea and Long to $1,300,000.

Annual Bonus. In addition to base salary, the ET Compensation Committee makes determinations whether to make discretionary annual cash bonus awards to executives, including our named executive officers, following the end of the year under the Bonus Plan.

 

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The Bonus Plan is a discretionary annual cash bonus plan available to all employees, including the named executive officers. The purpose of the Bonus Plan is to reward employees for contributions towards the Partnership’s business goals and to aid in motivating employees. The Bonus Plan is administered by the ET Compensation Committee and the ET Compensation Committee has the authority to establish and interpret the rules and regulations relating to the Bonus Plan, to select participants, to determine and approve the size of any actual award amount, to make all determinations, including factual determinations, under the Bonus Plan, and to take all other actions necessary or appropriate for the proper administration of the Bonus Plan.

For each calendar year (the “Performance Period”), the ET Compensation Committee will evaluate and determine an overall funded cash bonus pool based on achievement of (i) an internal Adjusted EBITDA target (“Adjusted EBITDA Target”), (ii) an internal distributable cash flow target (“DCF Target”) and (iii) performance of each department compared to the applicable departmental budget (“Departmental Budget Target”). The Adjusted EBITDA Target and the DCF Target are defined for purposes of the Bonus Plan using the same definitions as used in the Partnership’s audited financial statements included in its annual and quarterly filings on Forms 10-K and 10-Q for the terms Adjusted EBITDA and Distributable Cash Flow. The performance criteria are weighted 60% on the achievement of the Adjusted EBITDA Target, 20% on the achievement of the DCF Target and 20% on the achievement of the Departmental Budget Target (collectively, “Budget Targets”). The total amount of cash to be allocated to the funded bonus pool will range from 0% to 120% for each of the budgeted DCF Target and Adjusted EBITDA Target and will range from 0% to 100% of the Departmental Budget Target. The maximum funding of the bonus pool is 116% of the total pool target and to achieve such funding each of the Adjusted EBITDA and the DCF Target must achieve 120% funding and the Department Budget target must achieve its 100% target. While the funded bonus pool will reflect an aggregation of performance under each target, in the event performance under the Adjusted EBITDA Target is below 80% of its target, no bonus pool will be funded. If the bonus pool is funded, a participant may earn a cash award for the Performance Period based upon the level of attainment of the Budget Targets and his or her individual performance. Awards are paid in cash as soon as practicable after the end of the Performance Period but in no event later than two and one-half months after the end of the Performance Period.

While the achievement of the Budget Targets sets a bonus pool under the Bonus Plan, actual bonus awards are discretionary. These discretionary bonuses, if awarded, are intended to reward our named executive officers for the achievement of the Budget Targets during the Performance Period in light of the contribution of each individual to our profitability and success during such year. The ET Compensation Committee also considers the recommendation of Mr. Warren in determining the specific annual cash bonus amounts for each of the named executive officers. The ET Compensation Committee does not establish its own financial performance objectives in advance for purposes of determining whether to approve any annual bonuses, and it does not utilize any formulaic approach to determine annual bonuses.

For 2020, the ET Compensation Committee approved short-term annual cash bonus pool targets for Mr. McCrea of 160% of his annual base earnings and for Messrs. Long, Ramsey and Mason of 130% of their annual base earnings. The named executive officer bonus pool targets remained the same for the 2020 Performance Period as they were for the 2019 period. In connection with their promotions to Co-Chief Executive Officer effective January 1, 2021, the ET Compensation Committee established bonus pool targets for Messrs. McCrea and Long of 160% of their annual base earnings.

In respect of a 2020 bonus pool funding, executive management recommended to the Compensation Committee that the bonus be paid at a 0% payout. This recommendation was made in consideration of a number of factors including (i) the challenging conditions within the industry, specifically the impacts of the COVID-19 pandemic on ET and the global energy market; (ii) the impact of market conditions on current capital projects and certain planned future capital growth projects; and (ii) the reduction of quarterly cash distributions payable to ET common unit holders by 50% in 2020. After considering quantitative and qualitative factors, including performance level achieved, the Compensation Committee exercised its negative discretion, to award a 0% payout of the non-equity incentive bonus.

 

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Equity Awards. ET maintains and operates (i) the Second Amended and Restated Energy Transfer LP 2008 Incentive Plan (the “2008 Incentive Plan”); (ii) the Energy Transfer LP 2011 Long-Term Incentive Plan (the “2011 Incentive Plan”); the (iii) Energy Transfer LP 2015 Long-Term Incentive Plan (the “2015 Plan”); (iv) the Amended and Restated Energy Transfer LP Long-Term Incentive Plan (the “ET Plan,” together with the 2008 Incentive Plan, the 2011 Incentive Plan and the 2015 Plan, the “ET Incentive Plans”). The ET Incentive Plans authorize the ET Compensation Committee, in its discretion, to grant awards, as applicable, under each respective plan of RSUs upon such terms and conditions as it may determine appropriate and in accordance with general guidelines as defined by the ET Incentive Plans. ET has generally used time-vested restricted units and/or phantom units as the vehicle for its annual equity awards to eligible employees, including the named executive officers.

In addition, in 2020, ET adopted the Energy Transfer LP Long-Term Cash Restricted Unit Plan (the “CRU Plan”). The CRU Plan authorizes the ET Compensation Committee, in its discretion, to grant awards, as applicable, of CRSUs, upon such terms and conditions as it may determine appropriate and in accordance with general guidelines as defined by the CRU Plan. Like awards from the ET Incentive Plans, awards from the CRU Plan will be used to incentivize and reward eligible employees over a long-term basis, and the CRU Plan is included for purposes of these discussions as an “ET Incentive Plan.”

For 2020, the annual long-term incentive targets set by the ET Compensation Committee for the named executive officers were 900% of annual base salary for Mr. McCrea and 500% of annual base salary for Messrs. Long, Ramsey and Mason. The targets of the named executive officers were the same as the prior year’s targets.

The annual long-term incentive targets are used as the basis to determine the target number of units to be awarded to the eligible participant, including the named executive officers. A multiple of base salary is used to set the pool target, that number is then divided by a weighted average price determined by considering ET’s modified total unitholder return “(TUR”) performance as measured against the average return of ET’s identified peer group over defined time periods. The modified TUR is designed to create a recognition of a performance adjustment to the equity awards based on the prior periods measured to add an element of performance impact in setting grant date value even though the RSUs and CRSUs themselves are a time-vested vehicle. For purposes of establishing an initial price, ET utilizes a 60 trading-day trailing weighted average price of ET common units prior to November 13, 2020. This average trading price is then subject to adjustment when ET’s TUR is more than 5% greater or less than that of its identified peer group. If the TUR analysis yields a result that is within 5% percent of its identified peer group, the ET Compensation Committee will simply use the 60 trading day trailing weighted average price divided by the applicable salary multiple to establish a target pool for each eligible participant, including the named executive officers. If ET’s TUR is outside of the 5% deviation, the 60 trading day trailing weighted average will be adjusted up or down to a maximum of 15% from the trailing weighted average price based on ET’s performance as compared to the identified group. For 2019, the peer group included the following:

 

•  Enterprise Products Partners, L.P.

  

•  Kinder Morgan, Inc.

•  The Williams Companies, Inc.

  

•  Plains All American Pipeline, L.P.

•  Phillips 66 Partners LP

  

•  MPLX LP

For 2020, the Partnership’s TUR underperformed the identified peer group by between 14% and 16% based on the average of the identified three comparison periods: (i) year-to-date 2020, (ii) trailing twelve months, and (iii) full-year 2019. Consequently, the 2020 long-term incentive base price was increased to reduce the total available restricted pool by approximately 15%.

In December 2020, the ET Compensation Committee in consultation with Mr. Warren approved grants of phantom unit awards to Messrs. McCrea, Long, Ramsey and Mason of 746,350 units, 178,550 units, 207,300 units and 234,900 units, respectively. The ET Compensation Committee also approved grants cash restricted units to Messrs. Long, Ramsey and Mason of 178,500, 207,300 and 234,900 units, respectively. As with base salary and annual bonus, Mr. Warren does not accept or receive annual long-term incentive awards.

 

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As more fully described below under “Affiliate and Subsidiary Equity Awards,” for 2020, in discussions between the General Partner, the ET Compensation Committee and the compensation committee of the general partner of Sunoco LP, it was determined that for 2020, Messrs. Long and Ramsey’s awards would be comprised of RSUs and CRSUs under the ET Incentive Plans and RSUs under the Sunoco LP 2018 Long-Term Incentive Plan (the “2018 Sunoco LP Plan”) in consideration of their roles and responsibilities for Sunoco LP and their status, as members of the Boards of Directors of the general partner of Sunoco LP. Messrs. Long and Ramsey’s total 2020 long-term awards were allocated approximately 80% to the ET Incentive Plans and approximately 20% to the 2018 Sunoco LP Plan. The awards of Messrs. McCrea and Mason for 2020 were allocated entirely to the ET Incentive Plans. While Mr. Long likely will not receive future long-term incentive awards under the 2018 Sunoco LP Plan in his role as Co-CEO, it is anticipated that Mr. Ramsey will continue to recognize an aggregation of RSUs and CRSUs under the ET Incentive Plans and the 2018 Sunoco LP Plan, as applicable. For purposes of establishing a pool value for awards to eligible participants, including Messrs. Ramsey and Long, Sunoco LP utilized the same practices in terms of peer group TUR analysis to set a grant date valuation.

The RSUs granted in 2020 provide for incremental vesting over a five-year period, with 60% vesting at the end of the third year and the remaining 40% vesting at the end of the fifth year. Vesting of the awards are generally subject to continued employment through each specified vesting date. The RSU awards entitle the recipients to receive, with respect to each ET unit subject to such award that has not either vested or been forfeited, a DER cash payment promptly following each such distribution by ET to its common unitholders.

The CRSUs granted in 2020 provide for incremental vesting over a three-year period, with 1/3 vesting at the end of each year. Each CRSU entitles the award recipient to receive cash equal to the market value of one ET common unit upon vesting. The CRSU do not include rights to DER cash payments.

In approving the grant of such RSUs and CRSUs, including to the named executive officers, the ET Compensation Committee considered several factors, including the long-term objective of retaining such individuals as key drivers of ET’s future success, the existing level of equity ownership of such individuals and the previous awards to such individuals of equity awards subject to vesting. Vesting of the 2020 awards would accelerate in the event of the death or disability of the recipient, including the named executive officers, or in the event of a change in control of ET as that term is defined under the ET Incentive Plans.

For 2020, Mr. McCrea did not receive an award of CRSUs; instead, he received a special one-time time vested cash award of $5,000,000 payable as follows:

 

   

$1,800,000.00 on December 31, 2020;

 

   

$1,600,000.00 on July 1, 2020; and

 

   

$1,600,00.00 on December 5, 2022.

This amount is intended to approximate 50% of Mr. McCrea’s targeted annual equity award and replace the award of CRSUs made to other named executive officers.

As discussed below under “Potential Payments Upon a Termination or Change of Control,” all outstanding equity awards would automatically accelerate upon a change in control event, which means vesting automatically accelerates upon a change of control irrespective of whether the officer is terminated. In addition, the award agreements for the restricted units and cash restricted units awarded in 2020, as well as other awards outstanding held by Partnership employees, including the named executive officers, also include certain acceleration provisions upon retirement with the ability to accelerate 40% of outstanding unvested awards under the ET Incentive Plans at age 65 and 50% at age 68. These acceleration provisions require that the participant have not less than five (5) years of employment service to the Partnership or an affiliate and require a six (6) month delay in the vesting after retirement pursuant to the requirements of Section 409(A) of the Code.

We believe that permitting the accelerated vesting of equity awards upon a change in control creates an important retention tool for us by enabling employees to realize value from these awards in the event that we undergo a

 

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change in control transaction. In addition, we believe permitting acceleration of vesting upon a change in control creates a sense of stability in the course of transactions that could create uncertainty regarding their future employment and encourage these officers to remain focused on their job responsibilities.

Affiliate and Subsidiary Equity Awards. In addition to their roles for ET and ETO during 2020, Messrs. Long and Ramsey have certain responsibilities for Sunoco LP, including as members of the Board of Directors of the general partner of Sunoco LP.

The Sunoco LP Compensation Committee in December 2020 approved grants of RSUs to Messrs. Long and Ramsey of 27,800 and 32,300 restricted units, respectively, under the 2018 Sunoco LP Plan. The terms and conditions of the restricted unit to Messrs. Long and Ramsey under the 2018 Sunoco LP Plan, as applicable, were the same and provided for vesting over a five-year period, with 60% vesting at the end of the third year and the remaining 40% vesting at the end of the fifth year, subject generally to continued employment through each specified vesting date. All of the awards would be accelerated in the event of their death, disability, upon a change in control or retirement at ages 65 or 68. The retirement acceleration provisions for these awards under the 2018 Sunoco Plan are the same as the retirement acceleration provisions under ET Incentive Plans with the ability to accelerate at retirement 40% of outstanding unvested awards at age 65 and 50% at age 68.

Special One-Time Awards to Co-Chief Executive Officers. In recognition of their assumption of their new roles as Co-Chief Executive Officers, the ET Compensation Committee approved certain one-time awards to Messrs. McCrea and Long which occurred in 2021 and therefore are not reflected within the executive compensation tables that follow this discussion.

Mr. McCrea received a special one-time award of 241,815 RSUs under the ET Incentive Plans and a special cash payment of $1,625,000 in connection with his appointment as Co-Chief Executive Officer.

Mr. Long received a special one-time award of 483,630 RSUs under the ET Incentive Plans in connection with his appointment as Co-Chief Executive Officer.

The RSU awards to Messrs. McCrea and Long were made at the same grant date valuation and vesting schedules used for the annual equity awards described above under “—Equity Awards” section above. These awards were approved by the ET Compensation Committee on December 30, 2020 to be effective immediately upon Messrs. McCrea and Long assuming their new roles on January 1, 2021 and will be reflected in the 2021 Summary Compensation Tables.

Unit Ownership Guidelines. The Board of Directors of our General Partner has adopted the Executive Unit Ownership Guidelines (the “Guidelines”), which set forth minimum ownership guidelines applicable to certain executives of ET with respect to ET and Sunoco LP common units representing limited partnership interests, as applicable. The applicable Guidelines are denominated as a multiple of base salary, and the amount of common units required to be owned increases with the level of responsibility. Under these Guidelines, the President and Chief Commercial Officer and the Chief Operating Officer are expected to own common units having a minimum value of five times his base salary, while each of the remaining named executive officers (other than the CEO) are expected to own common units having a minimum value of four times their respective base salary. In addition to the named executive officers, these Guidelines also apply to other covered executives, which executives are expected to own either directly or indirectly in accordance with the terms of the Guidelines, common units having minimum values ranging from two to four times their respective base salary.

The ET Compensation Committee believes that the ownership of ET and/or Sunoco LP common units, as reflected in these Guidelines, is an important means of tying the financial risks and rewards for its executives to ET’s total unitholder return, aligning the interests of such executives with those of Unitholders, and promoting ET’s interest in good corporate governance.

 

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Covered executives are generally required to achieve their ownership level within five years of becoming subject to the Guidelines; however, certain covered executives, based on their tenure as an executive, were required to achieve compliance within two years of the December 2013 effective date of the Guidelines. Thus, compliance with the Guidelines was required for Messrs. McCrea and Mason beginning in December 2015, Mr. Long in December 2018 and Mr. Ramsey in December 2020. As of December 31, 2020, all of the named executive officers were compliant with the Guidelines.

Covered executives may satisfy the Guidelines through direct ownership of ET and/or Sunoco LP common units or indirect ownership by certain immediate family members. Direct or indirect ownership of ET and/or Sunoco LP common units shall count on a one-to-one ratio for purposes of satisfying minimum ownership requirements; however, unvested unit awards may not be used to satisfy the minimum ownership requirements.

Executive officers, including the named executive officers, who have not yet met their respective guideline must retain and hold all common units (less common units sold to cover the executive’s applicable taxes and withholding obligation) received in connection with long-term incentive awards. Once the required ownership level is achieved, ownership of the required common units must be maintained for as long as the covered executive is subject to the Guidelines. However, those individuals who have met or exceeded their applicable ownership level guideline may dispose of the common units in a manner consistent with applicable laws, rules and regulations, including regulations of the SEC and our internal policies, but only to the extent that such individual’s remaining ownership of common units would continue to exceed the applicable ownership level.

Qualified Retirement Plan Benefits. The Energy Transfer LP 401(k) Plan (the “ET 401(k) Plan”) is a defined contribution 401(k) plan, which covers substantially all of our employees, including the named executive officers. Employees may elect to defer up to 100% of their eligible compensation after applicable taxes, as limited under the Internal Revenue Code. We make a matching contribution that is not less than the aggregate amount of matching contributions that would be credited to a participant’s account based on a rate of match equal to 100% of each participant’s elective deferrals up to 5% of covered compensation. During 2020, in response to challenging conditions within the industry, including impacts of the COVID-19 pandemic, ET suspended its 401(k) matching contribution from July 1, 2020 through December 31, 2020. The amounts deferred by the participant are fully vested at all times, and the amounts contributed by the Partnership become vested based on years of service. We provide this benefit as a means to incentivize employees and provide them with an opportunity to save for their retirement.

The Partnership provides a 3% profit sharing contribution to employee 401(k) accounts for all employees with a base compensation below a specified threshold. The contribution is in addition to the 401(k) matching contribution and employees become vested based on years of service. As with the 401(k) matching contributions, ET suspended the profit sharing contribution from July 1, 2020 through December 31, 2020.

Health and Welfare Benefits. All full-time employees, including our named executive officers may participate in ETP GP’s health and welfare benefit programs including medical, dental, vision, flexible spending, life insurance and disability insurance.

Termination Benefits. Our named executive officers do not have any employment agreements that call for payments of termination or severance benefits or that provide for any payments in the event of a change in control of our General Partner; however, the award agreement to the named executive officers under the ET Incentive Plans, the 2018 Sunoco LP Plan and the Sunoco LP 2012 Long-Term Incentive Plan (the “2012 Sunoco LP Plan”) provide for immediate vesting of all unvested restricted unit awards in the event of a (i) change of control, as defined in the plan; (ii) death or (iii) disability, as defined in the applicable plan. Please refer to “Compensation Tables—Potential Payments Upon a Termination or Change of Control” for additional information.

In addition, ETP GP has also adopted the ETP GP Severance Plan and Summary Plan Description effective as of June 12, 2013, (the “Severance Plan”), which provides for payment of certain severance benefits in the event of

 

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Qualifying Termination (as that term is defined in the Severance Plan). In general, the Severance Plan provides payment of two weeks of annual base salary for each year or partial year of employment service up to a maximum of fifty-two weeks or one year of annual base salary (with a minimum of four weeks of annual base salary) and up to three months of continued group health insurance coverage. The Severance Plan also provides that we may determine to pay benefits in addition to those provided under the Severance Plan based on special circumstances, which additional benefits shall be unique and non-precedent setting. The Severance Plan is available to all salaried employees on a nondiscriminatory basis; therefore, amounts that would be payable to our named executive officers upon a Qualified Termination have been excluded from “Compensation Tables – Potential Payments Upon a Termination or Change of Control” below.

Energy Transfer LP Non-Qualified Deferred Compensation Plan (the “ET NQDC Plan”) is a deferred compensation plan, which permits eligible highly compensated employees to defer a portion of their salary, bonus, and/or quarterly non-vested phantom unit distribution equivalent income until retirement, termination of employment or other designated distribution event. Each year under the ET NQDC Plan, eligible employees are permitted to make an irrevocable election to defer up to 50% of their annual base salary, 50% of their quarterly non-vested phantom unit distribution income, and/or 50% of their discretionary performance bonus compensation during the following year. Pursuant to the ET NQDC Plan, ET may make annual discretionary matching contributions to participants’ accounts; however, ET has not made any discretionary contributions to participants’ accounts and currently has no plans to make any discretionary contributions to participants’ accounts. All amounts credited under the ET NQDC Plan (other than discretionary credits) are immediately 100% vested. Participant accounts are credited with deemed earnings or losses based on hypothetical investment fund choices made by the participants among available funds.

Participants may elect to have their account balances distributed in one lump sum payment or in annual installments over a period of three or five years upon retirement, and in a lump sum upon other termination events. Participants may also elect to take lump-sum in-service withdrawals five years or longer in the future, and such scheduled in-service withdrawals may be further deferred prior to the withdrawal date. Upon a change in control (as defined in the ET NQDC Plan) of ET, all ET NQDC Plan accounts are immediately vested in full. However, distributions are not accelerated and, instead, are made in accordance with the ET NQDC Plan’s normal distribution provisions unless a participant has elected to receive a change of control distribution pursuant to his deferral agreement. None of our named executive officers currently participate in this plan.

Risk Assessment Related to our Compensation Structure. We believe that the compensation plans and programs for our named executive officers, as well as our other employees, are appropriately structured and are not reasonably likely to result in material risk to us. We believe these compensation plans and programs are structured in a manner that does not promote excessive risk-taking that could harm our value or reward poor judgment. We also believe we have allocated compensation among base salary and short and long-term compensation in such a way as to not encourage excessive risk-taking. In particular, we generally do not adjust base annual salaries for executive officers and other employees significantly from year to year, and therefore the annual base salary of our employees is not generally impacted by our overall financial performance or the financial performance of a portion of our operations. Our subsidiaries generally determine whether, and to what extent, their respective named executive officers receive a cash bonus based on achievement of specified financial performance objectives as well as the individual contributions of our named executive officers to the Partnership’s success. We and our subsidiaries use restricted units and phantom units rather than unit options for equity awards because restricted units and phantom units retain value even in a depressed market so that employees are less likely to take unreasonable risks to get, or keep, options “in-the-money.” Finally, the time-based vesting over five years for our long-term incentive awards ensures that the interests of employees align with those of Unitholders and our subsidiaries’ unitholders for our long-term performance.

 

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Tax and Accounting Implications of Equity-Based Compensation Arrangements

Deductibility of Executive Compensation

We are a limited partnership and not a corporation for United States federal income tax purposes. Therefore, we believe that the compensation paid to the named executive officers is not subject to the deduction limitations under Section 162(m) of the Internal Revenue Code and therefore is generally fully deductible for United States federal income tax purposes.

Accounting for Non-Cash Compensation

For non-cash compensation arrangements, we record compensation expense over the vesting period of the awards, as discussed further in Note 8 to our consolidated financial statements.

Compensation Committee Interlocks and Insider Participation

We do not have a compensation committee and have not since the time of the Energy Transfer Merger. Messrs. Anderson, Grimm and Washburne are the members of the ET Compensation Committee. During 2020, no member of the ET Compensation Committee was an officer or employee of ET, ETO or any of our subsidiaries or served as an officer of any company with respect to which any named executive officers served on such company’s board of directors. Mr. Grimm is not a former employee of ours or any of our subsidiaries. Mr. Anderson was previously an employee of the Partnership until his retirement in October 2009.

Board Report on Compensation

Following the Energy Transfer Merger, the duties of the ETO Compensation Committee have been delegated to the ET Compensation Committee. The board of directors of our General Partner has reviewed and discussed the section entitled “Compensation Discussion and Analysis” with the management. Based on this review and discussion, we have recommended that the Compensation Discussion and Analysis be included in this annual report on Form 10-K.

The Board of Directors of Energy Transfer Partners,

L.L.C., the general partner of Energy Transfer

Partners GP, L.P., the general partner of Energy

Transfer Operating, L.P.

Kelcy L. Warren

Matthew S. Ramsey

Marshall S. (Mackie) McCrea, III

David K. Skidmore

W. Brett Smith

William P. Williams

The foregoing report shall not be deemed to be incorporated by reference by any general statement or reference to this annual report on Form 10-K into any filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except to the extent that we specifically incorporate this information by reference, and shall not otherwise be deemed filed under those Acts.

 

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Compensation Tables

Summary Compensation Table

 

Name and Principal Position

  Year     Salary
($)
    Bonus
($)
    Equity
Awards (1)
($)
    Non-Equity
Incentive Plan
Compensation (2)
($)
    Change in
Pension
Value and
Nonqualified
Deferred
Compensation
Earnings ($)
    All Other
Compensation (3)
($)
    Total
($)
 

Kelcy L. Warren (4)

    2020     $ 6,392   $ —     $ —       $ —       $ —       $ —       $ 6,392

Executive Chairman and former Chief Executive Officer

    2019       6,156     —       —         —         —         —         6,156
    2018       6,138     —         —         —         —         —         6,138
               

Thomas E. Long

    2020       623,077     —         2,781,255     —         —         21,603     3,425,935

Co-Chief Executive Officer and former Chief Financial Officer

    2019       570,869     —         3,352,795     900,000     —         21,544     4,845,208
    2018       537,338     1,000,000     4,251,335     800,000     —         21,294     6,609,967
               

Marshall S. (Mackie) McCrea, III

    2020       1,157,423     1,800,000     4,597,516     —         —         18,045     7,572,984

Co-Chief Executive Officer and former President and Chief Commercial Officer

    2019       1,094,260     —         8,734,720     1,750,817     —         21,544     11,601,341
    2018       1,059,976     —         7,834,782     1,866,000     —         19,362     10,780,120
               
               

Matthew S. Ramsey

    2020       723,390     —         3,229,770     —         —         22,097     3,975,257

Chief Operating Officer

    2019       683,913     —         3,123,186     889,100     —         19,544     4,715,743
    2018       662,486     —         2,818,415     900,000     —         19,294     4,400,195

Thomas P. Mason

    2020       655,680     —         2,609,350     —         —         20,007     3,285,037

Executive Vice President, General Counsel and President—LNG

    2019       619,899     —         2,749,440     805,900     —         19,544     4,194,783
    2018       600,477     —         2,466,882     858,700     —         19,294     3,945,353
               
               

 

(1) 

Equity award amounts reflect the aggregate grant date fair value of unit awards granted for the periods presented, computed in accordance with FASB ASC Topic 718, disregarding any estimates for forfeitures. For Messrs. Long and Ramsey amounts include equity awards of our subsidiary, Sunoco LP, as reflected in the “Grants of Plan-Based Awards Table.” See Note 9 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for additional assumptions underlying the value of the equity awards. Although the CRSU awards may only be settled in cash, they are based upon the value of ET common units and are accounted for as equity awards within these compensation tables.

(2) 

ET maintains the Bonus Plan which provides for discretionary bonuses. Awards of discretionary bonuses are tied to achievement of targeted performance objectives and described in the Compensation Discussion and Analysis.

(3) 

The amounts reflected for 2020 in this column include (i) matching contributions to the ET 401(k) Plan made on behalf of the named executive officers of $13,846 for Mr. Long, $10,288 for Mr. McCrea and $14,250 each for Messrs. Ramsey and Mason, and (ii) health savings account contributions made on behalf of the named executive officers of $2,000 each for Messrs. Long and McCrea, and (iii) the dollar value of life insurance premiums paid for the benefit of the named executive officers. The amounts reflected for all periods exclude distribution payments in connection with distribution equivalent rights on unvested unit awards, because the dollar value of such distributions are factored into the grant date fair value reported in the “Equity Awards” column of the Summary Compensation Table at the time that the unit awards and distribution equivalent rights were originally granted. For 2020, distribution payments in connection with distribution equivalent rights totaled $913,658 for Mr. Long, $2,284,899 for Mr. McCrea, $916,013 for Mr. Ramsey, and $774,910 for Mr. Mason.

 

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(4) 

Mr. Warren has voluntarily determined that his salary will be reduced to $1.00 per year (plus an amount sufficient to cover his allocated payroll deductions for health and welfare benefits). He also does not accept a cash bonus or any equity or incentive awards under any applicable incentive plans.

(5) 

The amounts reflected in the bonus column for Mr. McCrea represents the first payment of Mr. McCrea’s time-vested cash award, which award represents 50% of Mr. McCrea’s total equity award target. This amount was paid on December 31, 2020.

Grants of Plan-Based Awards in 2020

 

Name

   Grant Date      All Other
Unit Awards:
Number of
Units
(#)
     Grant Date
Fair Value
of Unit
Awards (1)
 

ET Unit Awards:

        

Kelcy L. Warren

     N/A        —      $ —  

Thomas E. Long

     12/30/2020        178,550      1,099,868

Marshal S. (Mackie) McCrea, III

     12/30/2020        746,350      4,597,516

Matthew S. Ramsey

     12/30/2020        207,300      1,276,968

Thomas P. Mason

     12/30/2020        234,900      1,446,984

Sunoco LP Unit Awards:

        

Thomas E. Long

     12/30/2020        27,800      797,860

Matthew S. Ramsey

     12/30/2020        32,300      927,010

 

(1) 

We have computed the grant date fair value of unit awards in accordance with FASB ASC Topic 718, as further described above and in Note 8 to our consolidated financial statements. For ET cash restricted unit awards, the grant date fair value is discounted for the expected distribution yield during the vesting period, as those awards do not include distribution equivalent rights.

Narrative Disclosure to Summary Compensation Table and Grants of the Plan-Based Awards Table

A description of material factors necessary to understand the information disclosed in the tables above with respect to salaries, bonuses, equity awards and 401(k) plan contributions can be found in the Compensation Discussion and Analysis that precedes these tables.

 

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Outstanding Equity Awards at 2020 Fiscal Year-End

 

Name

  Grant Date(1)     Unit Awards (1)  
  Number of
Units That
Have Not
Vested(2)

(#)
    Market or Payout
Value of Units
That Have Not
Vested (3)

($)
 

ET Unit Awards:

     

Kelcy L. Warren

    N/A       —     $ —  

Thomas E. Long

    12/30/2020       178,550     1,103,439
    12/16/2019       215,000     1,328,700
    12/18/2018       136,475     843,416
    10/19/2018       115,200     711,936
    12/20/2017       48,430     299,297
    12/29/2016       30,236     186,858

Marshal S. (Mackie) McCrea, III

    12/30/2020       746,350     4,612,443
    12/16/2019       682,400     4,217,232
    12/18/2018       605,740     3,743,473
    12/20/2017       214,952     1,328,403
    12/29/2016       172,231     1,064,388

Matthew S. Ramsey

    12/30/2020       207,300     1,281,114
    12/16/2019       189,600     1,171,728
    12/18/2018       168,260     1,039,847
    12/20/2017       89,564     553,506
    12/29/2016       73,440     453,859

Thomas P. Mason

    12/30/2020       234,900     1,451,682
    12/16/2019       214,800     1,327,464
    12/18/2018       190,640     1,178,155
    12/20/2017       54,120     334,462
    12/29/2016       40,645     251,186

ET Cash Restricted Unit Awards:

   

Thomas E. Long

    12/30/2020       178,550     887,058

Matthew S. Ramsey

    12/30/2020       207,300     1,029,892

Thomas P. Mason

    12/30/2020       234,900     1,167,012

Sunoco LP Unit Awards:

   

Thomas E. Long

    12/30/2020       27,800   $ 800,084
    12/16/2019       19,500     561,210
    12/19/2018       19,325     556,174
    12/21/2017       6,839     196,826
    12/29/2016       8,884     255,682

Matthew S. Ramsey

    12/30/2020       32,300     929,594
    12/16/2019       22,600     650,428
    12/19/2018       23,825     685,684

Thomas P. Mason

    12/21/2017       7,643     219,966
    12/29/2016       9,320     268,230

 

(1) 

Certain of these outstanding awards represent former Energy Transfer Partners, L.P. awards that converted into ET awards upon the merger of Energy Transfer Equity, L.P. (now named Energy Transfer LP) and Energy Transfer Partners, L.P. (now named Energy Transfer Operating, L.P.) in October 2018. Furthermore, some of those converted awards had previously been converted in connection with the merger of Energy Transfer Partners, L.P. and Sunoco Logistics Partners L.P. in April 2017.

 

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(2) 

ET and Sunoco LP unit awards outstanding vest as follows:

 

   

at a rate of 60% in December 2023 and 40% in December 2025 for awards granted in December 2020;

 

   

at a rate of 60% in December 2022 and 40% in December 2024 for awards granted in December 2019;

 

   

at a rate of 60% in December 2021 and 40% in December 2023 for awards granted in October and December 2018;

 

   

100% in December 2022 for the remaining outstanding portion of awards granted in December 2017; and

 

   

100% in December 2021 for the remaining outstanding portion of awards granted in December 2016.

Such awards may be settled at the election of the ET Compensation Committee in (i) common units of ET (subject to the approval of the ET Incentive Plans prior to the first vesting date by a majority of ET’s unitholders pursuant to the rules of the New York Stock Exchange); (ii) cash equal to the Fair Market Value (as such term is defined in the ET Incentive Plans) of the ET common units that would otherwise be delivered pursuant to the terms of each named executive officers grant agreement; or (iii) other securities or property in an amount equal to the Fair Market Value of ET common units that would otherwise be delivered pursuant to the terms of the grant agreement, or a combination thereof as determined by the ET Compensation Committee in its discretion.

ET cash restricted unit awards granted in December 2020 vest 1/3 per year in December 2021, 2022 and 2023.

(3) 

Market value was computed as the number of unvested awards as of December 31, 2020 multiplied by the closing price of respective common units of ET and Sunoco LP. For ET cash restricted unit awards, the grant date fair value is discounted for the expected distribution yield during the vesting period, as those awards do not include distribution equivalent rights.

Units Vested in 2020

 

     Unit Awards  

Name

   Number of Units
Acquired on Vesting
(#)
     Value Realized
on Vesting

($) (1)
 

ET Unit Awards:

     

Kelcy L. Warren

     N/A      $ —  

Thomas E. Long

     92,610      641,787

Marshall S. (Mackie) McCrea, III

     465,098      3,223,129

Matthew S. Ramsey

     193,626      1,341,828

Thomas P. Mason

     114,858      795,966

Sunoco LP Unit Awards:

     

Thomas E. Long

     15,908      459,900

Matthew S. Ramsey

     814      25,584

Thomas P. Mason

     18,873      545,618

 

(1) 

Amounts presented represent the value realized upon vesting of these awards, which is calculated as the number of units vested multiplied by the applicable closing market price of applicable common units upon the vesting date.

We have not issued option awards.

Potential Payments Upon a Termination or Change of Control

Equity Awards. As discussed in our Compensation Discussion and Analysis above, any unvested equity awards (including cash restricted unit awards) granted pursuant the ET Incentive Plans will automatically become vested

 

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upon a change of control, which is generally defined as the occurrence of one or more of the following events: (i) any person or group becomes the beneficial owner of 50% or more of the voting power or voting securities of ET or its general partner; (ii) LE GP, LLC or an affiliate of LE GP, LLC ceases to be the general partner of ET; or (iii) the sale or other disposition, including by liquidation or dissolution, of all or substantially all of the assets of ET in one or more transactions to anyone other than an affiliate of ET.

In addition, as explained in Equity Awards section of our Compensation Discussion and Analysis above, the restricted unit awards, phantom unit awards and cash restricted unit awards under the ET Incentive Plans, the Sunoco LP Plan and the 2012 Sunoco LP Plan generally require the continued employment of the recipient during the vesting period, provided however, the unvested awards will be accelerated in the event of the death or disability of the award recipient prior to the applicable vesting period being satisfied. All awards outstanding to the named executive officers under the ET Incentive Plans, the 2018 Sunoco LP Plan or the 2012 Sunoco LP Plan would be accelerated in the event of a change in control of the Partnership.

The October 20108 equity award to Mr. Long included a provision in the applicable award agreement for acceleration of unvested restricted unit/restricted phantom unit awards upon a termination of employment by the general partner of the applicable partnership issuing the award without “cause.” For purposes of the awards the term “cause” shall mean: (i) a conviction (treating a nolo contendere plea as a conviction) of a felony (whether or not any right to appeal has been or may be exercised), (ii) willful refusal without proper cause to perform duties (other than any such refusal resulting from incapacity due to physical or mental impairment), (iii) misappropriation, embezzlement or reckless or willful destruction of property of the partnership or any of its affiliates, (iv) knowing breach of any statutory or common law duty of loyalty to the partnership or any of its or their affiliates, (v) improper conduct materially prejudicial to the business of the partnership or any of its or their affiliates, (vi) material breach of the provisions of any agreement regarding confidential information entered into with the partnership or any of its or their affiliates or (vii) the continuing failure or refusal to satisfactorily perform essential duties to the partnership or any of its or their affiliates.

In addition, the ET Compensation Committee and the compensation committee of the general partner of Sunoco LP, have approved a retirement provision, which provides that employees, including the named executive officers with at least ten years of service with the general partner, who leave the respective general partner voluntarily due to retirement (i) after age 65 but prior to age 68 are eligible for accelerated vesting of 40% of his or her award; or (ii) after 68 are eligible for accelerated vesting of 50% his or her award. The acceleration of the awards is subject to the applicable provisions of IRC Section 409(A).

Mr. Mason previously received a one-time special incentive retention bonus, for which he would be obligated to repay $3,150,000 if his employment terminates (other than as a result of (x) a termination without cause by ET or by Mr. Mason for Good Reason; (y) his death; or (z) his permanent disability) prior to February 24, 2021.

Deferred Compensation Plan. As discussed in our Compensation Discussion and Analysis above, all amounts under the ET NQDC Plan (other than discretionary credits) are immediately 100% vested. Upon a change of control (as defined in the ET NQDC Plan), distributions from the respective plan would be made in accordance with the normal distribution provisions of the respective plan. A change of control is generally defined in the ET NQDC Plan as any change of control event within the meaning of Treasury Regulation Section 1.409A-3(i)(5).

CEO Pay Ratio

In accordance with Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) of Regulation S-K, set forth below is information about the relationship of the annual total compensation of Mr. Warren, the Chairman and Chief Executive Officer and the annual total compensation of our employees.

The annual total compensation of Mr. Warren, as reported in the Summary Compensation Tables of this Item 11was $6,392 for 2020.

 

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The median total compensation of the employees supporting the Partnership (other than Mr. Warren) was $110,358 for 2020.

Based on this information, for 2020 the ratio of the annual total compensation of Mr. Warren to the median of the annual total compensation of the 8,149 employees supporting ETO as of December 31, 2020 was approximately 1 to 17 as Mr. Warren has voluntarily elected not to accept any salary, bonus or equity incentive compensation (other than a salary of $1.00 per year plus an amount sufficient to cover his allocated employee premium contributions for health and welfare benefits).

To identify the median of the annual total compensation of the employees supporting the Partnership, the following steps were taken:

 

1.

It was determined that, as of December 31, 2020, the applicable employee populations consisted of 8,149 with all of the identified individuals being employed in the United States. This population consisted of all of our full-time and part-time employees. We did not engage any independent contractors in 2020 that are required to be included in our employee population for the CEO pay ratio evaluation.

 

2.

To identify the “median employee” from our employee population, we compared the total earnings of our employees as reflected in our payroll records as reported on Form W-2 for 2020.

 

3.

We identified our median employee using W-2 reporting and applied this compensation measure consistently to all of our employees required to be included in the calculation. We did not make any cost of living adjustments in identifying the “median employee.”

 

4.

Once we identified our median employee, we combined all elements of the employee’s compensation for 2020 resulting in an annual compensation of $110,358. The difference between such employee’s total earnings and the employee’s total compensation represents the estimated value of the employee’s health care benefits (estimated for the employee and such employee’s eligible dependents at $11,119) and the employee’s 401(k) matching contribution and profit sharing contribution (estimated at $3,130 per employee, includes $1,972 per employee on average matching contribution and $1,158 per employee on average profit sharing contribution (employees earning over $175,000 in base are ineligible for profit sharing)).

 

5.

With respect to Mr. Warren, we used the amount reported in the “Total” column of our 2020 Summary Compensation Table under this Item 11.

Director Compensation

In 2020, the compensation arrangements for outside directors included a $100,000 annual retainer for services on the board. If a director served on the Audit Committee, such director would receive an annual cash retainer of $15,000 or $25,000 in the case of the chairman. If a director served on the ET Compensation Committee, such director would receive an annual retainer of $7,500 or $15,000 in the case of the chairman. The fees for membership on the Conflicts Committee are determined on a per instance basis for each Conflicts Committee assignment.

The outside directors of our General Partner are also entitled to an annual restricted unit award under the ET Incentive Plans equal to an aggregate of $100,000 divided by the closing price of ET common units on the date of grant. These ET common units will vest 60% after the third year and the remaining 40% after the fifth year after the grant date. The compensation expense recorded is based on the grant-date market value of ET common units and is recognized over the vesting period. Distributions are paid during the vesting period.

 

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The compensation paid to the non-employee directors of our General Partner in 2020 is reflected in the following table:

 

Name

   Fees Paid in
Cash (1)

($)
     Unit Awards (2)

($)
     All Other
Compensation
($)
     Total
($)
 

David K. Skidmore

   $ 125,000    $ 99,997    $ —      $ 224,997

W. Brett Smith

     115,000      99,997      —        214,997

William P. Williams

     115,000      99,997      —        214,997

 

(1) 

Fees paid in cash are based on amounts paid during the period.

(2) 

Equity award amounts reflect the aggregate grant date fair value of unit awards granted for the periods presented, computed in accordance with FASB ASC Topic 718, disregarding any estimates for forfeitures. See Note 8 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for additional assumptions underlying the value of the equity awards.

As of December 31, 2020, Mr. Skidmore had 26,259 unvested ET restricted units outstanding, Mr. Smith had 18,243 unvested ET restricted units outstanding and Mr. Williams had 25,610 unvested ET restricted units outstanding.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

Equity Compensation Plan Information

The Partnership does not currently have any equity compensation plans. In connection with the Energy Transfer Merger in October 2018, all of the Partnership’s equity compensation plans, as well as the Partnership’s obligations under those plans, were assumed by ET.

Energy Transfer Operating, L.P. Units

All of the Partnership’s common units are owned by ET and its subsidiaries as of December 31, 2020. In addition, the Partnership has Class K, Class L, Class M and Class N units issued and outstanding, all of which are held by wholly-owned subsidiaries of the Partnership.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

For a discussion of director independence, see Item 10. “Directors, Executive Officers and Corporate Governance.”

As a policy matter, the Conflicts Committee generally reviews any proposed related-party transaction that may be material to the Partnership to determine whether the transaction is fair and reasonable to the Partnership. The Partnership’s board of directors makes the determinations as to whether there exists a related-party transaction in the normal course of reviewing transactions for approval as the Partnership’s board of directors is advised by its management of the parties involved in each material transaction as to which the board of directors’ approval is sought by the Partnership’s management. In addition, the Partnership’s board of directors makes inquiries to independently ascertain whether related parties may have an interest in the proposed transaction. While there are no written policies or procedures for the board of directors to follow in making these determinations, the Partnership’s board makes those determinations in light of its contractually-limited fiduciary duties to the Unitholders. The Partnership Agreement provides that any matter approved by the Conflicts Committee will be

 

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conclusively deemed to be fair and reasonable to the Partnership, approved by all the partners of the Partnership and not a breach by the General Partner or its Board of Directors of any duties they may owe the Partnership or the Unitholders (see “Risks Related to Conflicts of Interest” in “Item 1A. Risk Factors” in this annual report).

ET owns the general partner interest in ETP GP and all of the outstanding ETO Common Units.

See Note 15 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for a discussion of our related party transactions.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The following sets forth fees billed by Grant Thornton LLP for the audit of our annual financial statements and other services rendered (dollars in millions):

 

     Years Ended December 31,  
     2020      2019  

Audit fees (1)

   $ 10.4    $ 10.8

Audit related fees

          0.1
  

 

 

    

 

 

 

Total

   $ 10.4    $ 10.9
  

 

 

    

 

 

 

 

(1) 

Includes fees for audits of annual financial statements of our companies, reviews of the related quarterly financial statements, and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the SEC and services related to the audit of our internal control over financial reporting.

Pursuant to the charter of the Audit Committee, the Audit Committee is responsible for the oversight of our accounting, reporting and financial practices. The Audit Committee has the responsibility to select, appoint, engage, oversee, retain, evaluate and terminate our external auditors; pre-approve all audit and non-audit services to be provided, consistent with all applicable laws, to us by our external auditors; and establish the fees and other compensation to be paid to our external auditors. The Audit Committee also oversees and directs our internal auditing program and reviews our internal controls.

The Audit Committee has adopted a policy for the pre-approval of audit and permitted non-audit services provided by our principal independent accountants. The policy requires that all services provided by Grant Thornton LLP, including audit services, audit-related services, tax services and other services, must be pre-approved by the Audit Committee. All fees paid or expected to be paid to Grant Thornton LLP for fiscal years 2020 and 2019 were pre-approved by the Audit Committee in accordance with this policy.

The Audit Committee reviews the external auditors’ proposed scope and approach as well as the performance of the external auditors. It also has direct responsibility for and sole authority to resolve any disagreements between our management and our external auditors regarding financial reporting, regularly reviews with the external auditors any problems or difficulties the auditors encountered in the course of their audit work, and, at least annually, uses its reasonable efforts to obtain and review a report from the external auditors addressing the following (among other items):

 

   

the auditors’ internal quality-control procedures;

 

   

any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors;

 

   

the independence of the external auditors;

 

   

the aggregate fees billed by our external auditors for each of the previous two years; and

 

   

the rotation of the lead partner.

 

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

The following documents are filed as a part of this Report:

 

     Page  

(1) Financial Statements – see Index to Financial Statements

     D-187  

(2) Financial Statement Schedules – None

  

(3) Exhibits – see Index to Exhibits

     D-178  

ITEM 16. FORM 10-K SUMMARY

None.

 

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INDEX TO EXHIBITS

The exhibits listed on the following Exhibit Index are filed as part of this report. Exhibits required by Item 601 of Regulation S-K, but which are not listed below, are not applicable.

 

Exhibit
Number

  

Description

2.1    Agreement and Plan of Merger, dated as of January 25, 2015, by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Regency Energy Partners LP, Regency GP LP and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.1 to Form 8-K (File No. 001-11727) filed January 26, 2015)
2.2    Amendment No. 1 to Agreement and Plan of Merger, dated as of February 18, 2015, by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Rendezvous I LLC, Rendezvous II LLC, Regency Energy Partners LP, Regency GP LP, ETE GP Acquirer LLC and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.2 to Form 8-K (File No. 001-11727) filed on February 19, 2015)
2.3    Contribution Agreement, dated October 24, 2016 by and among Energy Transfer Partners, L.P. and NGP X US Holdings, LP, PennTex Midstream Partners, LLC, MRD Midstream LLC, WHR Midstream LLC and certain individual investors and managers named therein (incorporated by reference to Exhibit 2.1 to Form 8-K (File No. 001-11727) filed October 26, 2016)
2.4    Membership Interest Purchase Agreement, dated as of August 2, 2016, by and between Bakken Holdings Company LLC and MarEn Bakken Company LLC (incorporated by reference to Exhibit 2.2 to Form 10-Q (File No. 001-11727) filed November 9, 2016)
2.5    First Amendment, dated December 14, 2016, to the Membership Interest Purchase Agreement, dated as of August 2, 2016, by and between Bakken Holdings Company LLC and MarEn Bakken Company LLC (incorporated by reference to Exhibit 2.12 to Form 10-K (File No. 001-11727) filed February 24, 2017)
2.6    Agreement and Plan of Merger, dated as of November 20, 2016, by and among Energy Transfer Partners, L.P., Energy Transfer Agreement and Plan of Merger, dated as of November 20, 2016, by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Sunoco Logistics Partners L.P., Sunoco Partners LLC and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.1 to Form 8-K (File No. 001-11727) filed November 21, 2016)
2.7    Amendment No. 1 to Agreement and Plan of Merger, dated as of December 16, 2016, by and among Sunoco Logistics Partners L.P., Sunoco Partners LLC, SXL Acquisition Sub LLC, SXL Acquisition Sub LP, Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., ETP Acquisition Sub, LLC and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.2 to Form 8-K (File No. 001-11727) filed December 21, 2016)
2.8    Contribution Agreement, dated as of January 15, 2018, by and among USA Compression Partners, LP, Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., ETC Compression, LLC and, solely for certain purposes therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.1 to Form 8-K (File No. 001-31219) filed January 16, 2018)
2.9    Purchase Agreement, dated as of January 15, 2018, by and among USA Compression Holdings, LLC, Energy Transfer Equity, L.P., Energy Transfer Partners, L.L.C. and, solely for certain purposes therein, R/C IV USACP Holdings, L.P. and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 2.2 to Form 8-K (File No. 001-31219) filed January 16, 2018)

 

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Exhibit
Number

  

Description

2.10    Contribution Agreement, dated as of July 30, 2017, among Energy Transfer Interstate Holdings, LLC, ET Rover Pipeline LLC and BCP Renaissance L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K (File No. 001-31219) filed August 2, 2017)
2.11    Agreement and Plan of Merger, dated as of August 1, 2018, among LE GP, LLC, Energy Transfer Equity, L.P., Streamline Merger Sub, LLC, Energy Transfer Partners, L.L.C. and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 2.1 to Form 8-K (File No. 001-31219) filed August 3, 2018)
3.1    Amended Certificate of Limited Partnership of Energy Transfer Partners, L.P. (formerly known as Sunoco Logistics Partners L.P.) (incorporated by reference to Exhibit 3.3 to Form 8-K (File No. 001-31219) filed April 28, 2017)
3.2    Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners GP, L.P. (incorporated by reference to Exhibit 3.5 to Form 10-Q (File No. 001-11727) filed July 10, 2017)
3.2.1    Amendment No. 2, dated March 26, 2012, to the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners GP, L.P., dated as of April 17, 2007 (incorporated by reference to Exhibit 3.2 to Form 8-K (Filed No. 001-11727) filed March 28, 2012)
3.3    Fourth Amended and Restated Limited Liability Company Agreement of Energy Transfer Partners, L.L.C. (incorporated by reference to Exhibit 3.1 to Form 8-K (File No. 001-11727) filed August 10, 2010)
3.3.1    Amendment No. 1, dated March 26, 2012, to the Fourth Amended and Restated Limited Liability Company Agreement of Energy Transfer Partners, L.L.C., dated as of August 10, 2010 (incorporated by reference to Exhibit 3.3 to Form 8-K (File No. 001-11727) filed March 28, 2012)
3.4    Certificate of Limited Partnership of Sunoco Logistics Partners L.P. (incorporated by reference to Exhibit 3.1 to Form S-1 (File No. 333-71968) filed October 22, 2001)
3.4.1    Amendment to the Certificate of Limited Partnership of Sunoco Logistics Partners L.P., dated as of August 28, 2015 (incorporated by reference to Exhibit 3.1 to Form 8-K (Filed No. 001-31219) filed September 1, 2015)
3.4.2    Amendment to the Certificate of Limited Partnership of Sunoco Logistics Partners L.P. dated as of April 28, 2017 (incorporated by reference to Exhibit 3.3 to Form 8-K (File No. 001-31219) filed April 28, 2017)
3.5    Certificate of Formation of Energy Transfer Partners, L.L.C. (incorporated by reference to Exhibit 3.13 to Form 10-Q (Filed No. 001-11727) filed May 7, 2010)
3.5.1    Certificate of Amendment of Energy Transfer Partners, L.L.C. (incorporated by reference to Exhibit 3.13.1 to Form 10-Q (File No. 001-11727) filed May 7, 2010)
3.6    Restated Certificate of Limited Partnership of Energy Transfer Partners GP, L.P. (incorporated by reference to Exhibit 3.14 to Form 10-Q (Filed No. 001-11727) filed May 7, 2010)
3.7    Certificate of Merger of Streamline Merger Sub, LLC, with and into Energy Transfer Partners, L.P., dated as of October 19, 2018 (incorporated by reference to Exhibit 3.1 to Form 8-K (File No. 001-31219) filed October 19, 2018)
3.8    Fifth Amended and Restated Agreement of Limited Partnership of Energy Transfer Operating, L.P., dated as of October 19, 2018 (incorporated by reference to Exhibit 3.3 to Form 8-K (File No. 001-31219) filed October 19, 2018)

 

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Exhibit
Number

  

Description

3.8.1    Amendment No. 1, dated December 31, 2018, to Fifth Amended and Restated Agreement of Limited Partnership of Energy Transfer Operating, L.P., dated as of October 19, 2018 (incorporated by reference to Exhibit 3.1 to Form 8-K (File No. 001-31219) filed January 4, 2019)
3.8.2    Amendment No. 2, dated as of April 25, 2019, to Fifth Amended and Restated Agreement of Limited Partnership of Energy Transfer Operating, L.P. (incorporated by reference to Exhibit 3.1 to Form 8-K (File No. 001-31219) filed April 25, 2019)
3.8.3    Amendment No. 3, dated as of July 1, 2019, to Fifth Amended and Restated Agreement of Limited Partnership of Energy Transfer Operating, L.P. (incorporated by reference to Exhibit 3.1 to Form 8-K (File No. 001-31219) filed July 2, 2019)
3.8.4    Amendment No. 4, dated as of January 22, 2020, to the Fifth Amended and Restated Agreement of Limited Partnership of Energy Transfer Operating, L.P. (incorporated by reference to Exhibit 3.1 to Form 8-K (File No. 001-31219) filed January 22, 2020)
3.8.5    Amendment No. 5, dated as of April 30, 2020, to the Fifth Amended and Restated Agreement of Limited Partnership of Energy Transfer Operating, L.P. (incorporated by reference to Exhibit 3.1 to Form 8-K (File No. 001-31219) filed May 5, 2020)
4.1    Registration Rights Agreement, dated April 30, 2013, by and between Energy Transfer Partners, L.P. and Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 001-11727) filed May 1, 2013)
4.2    Indenture dated January 18, 2005 among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Form 8-K (File No. 001-11727) filed January 19, 2005)
4.3    Form of Senior Indenture of Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 4.11 to Form S-3 (File No. 333-136429) filed August 9, 2006)
4.4    Form of Subordinated Indenture of Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 4.12 to Form S-3 (File No. 333-136429) filed August 9, 2006)
4.5    Fifth Supplemental Indenture dated as of October 23, 2006 to Indenture dated January 18, 2005, among Energy Transfer Partners, L.P, the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Form 8-K (File No. 001-11727) filed October 25, 2006)
4.6    Sixth Supplemental Indenture dated March 28, 2008, by and between Energy Transfer Partners, L.P., as issuer, and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 001-11727) filed March 31, 2008)
4.7    Ninth Supplemental Indenture, dated as of May 12, 2011, to the Indenture dated January 18, 2005, by and between Energy Transfer Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 001-11727) filed May 12, 2011)
4.8    Tenth Supplemental Indenture, dated as of January 17, 2012, to the Indenture dated January 18, 2005, by and between Energy Transfer Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 001-11727) filed January 17, 2012)

 

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Exhibit
Number

  

Description

4.9    Eleventh Supplemental Indenture dated as of January 22, 2013 by and between Energy Transfer Partners, L.P., as issuer, and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 001-11727) filed January 23, 2013)
4.10    Twelfth Supplemental Indenture, dated as of January 24, 2013, by and between Energy Transfer Partners, L.P., as issuer, and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 001-11727) filed June 26, 2013)
4.11    Thirteenth Supplemental Indenture, dated as of September 19, 2013, by and between Energy Transfer Partners, L.P., as issuer, and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 001-11727) filed September 19, 2013)
4.12    Fourteenth Supplemental Indenture, dated as of March 12, 2015, by and between Energy Transfer Partners, L.P., as issuer, and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 001-11727) filed on March 12, 2015)
4.13    Fifteenth Supplemental Indenture, dated as of June 23, 2015, by and between Energy Transfer Partners, L.P., as issuer, and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.3 to Form 8-K (File No. 001-11727) filed June 23, 2015)
4.14    Sixteenth Supplemental Indenture, dated as of January 17, 2017, between Energy Transfer Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 001-11727) filed January 17, 2017)
4.15    Seventeenth Supplemental Indenture, dated as of December 1, 2017, between Energy Transfer Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 10.8 to Form 8-K (File No. 001-31219) filed December 6, 2017)
4.16    Second Supplemental Indenture, dated December 1, 2017, among Energy Transfer Partners, L.P., and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 10.5 to Form 8-K (File No. 001-31219) filed December 6, 2017)
4.17    Indenture, dated as of May 15, 1994, between Sunoco, Inc. and U.S. Bank National Association, as successor trustee to Citibank, N.A., relating to Sunoco, Inc.’s 9.00% Debentures due 2024 (incorporated by reference to Exhibit 4.8 to Form 8-K (File No. 001-31219) filed October 5, 2012)
4.18    First Supplemental Indenture, dated as of October 5, 2012, among Energy Transfer Partners, L.P., Sunoco, Inc. and U.S. Bank National Association, as successor trustee to Citibank, N.A., to the Indenture, dated as of May 15, 1994 (incorporated by reference to Exhibit 4.9 to Form 8-K (File No. 001-11727) filed October 5, 2012)
4.19    Sixteenth Supplemental Indenture, dated as of September 21, 2017, by and among Sunoco Logistics Partners Operations L.P., as issuer, Energy Transfer Partners, L.P., as guarantor, and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit 4.4 to Form 8-K (File No. 001-31219) filed September 25, 2017)

 

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Exhibit
Number

  

Description

4.20    Fifteenth Supplemental Indenture, dated as of September 21, 2017, by and among Sunoco Logistics Partners Operations L.P., as issuer, Energy Transfer Partners, L.P., as guarantor, and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 001-31219) filed September 25, 2017)
4.21    Third Supplemental Indenture, dated as of December 12, 2017, by and among Energy Transfer Partners, L.P., Sunoco Logistics Partners Operations L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 001-31219) filed December 15, 2017)
4.22    Eighteenth Supplemental Indenture, dated as of December 12, 2017, by and among Energy Transfer Partners, L.P., Sunoco Logistics Partners Operations L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 10.2 to Form 8-K (File No. 001-31219) filed December 15, 2017)
4.23    Tenth Supplemental Indenture, dated as of December 12, 2017, by and among Energy Transfer Partners, L.P., Regency Energy Finance Corp., Sunoco Logistics Partners Operations L.P. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.3 to Form 8-K (File No. 001-31219) filed December 15, 2017)
4.24    Eleventh Supplemental Indenture, dated as of December 12, 2017, by and among Energy Transfer Partners, L.P., Regency Energy Finance Corp., Sunoco Logistics Partners Operations L.P. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.4 to Form 8-K (File No. 001-31219) filed December 15, 2017)
4.25    Second Supplemental Indenture, dated as of December 1, 2017, by and between Energy Transfer Partners, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 10.6 to Form 8-K (File No. 001-31219) filed December 6, 2017)
4.26    Indenture, dated as of June 8, 2018, among Energy Transfer Partners, L.P. as issuer, Sunoco Logistics Partners Operations L.P., as guarantor, and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Form 8-K (File No. 001-31219) filed June 8, 2018)
4.27    First Supplemental Indenture, dated as of June 8, 2018, by and among Energy Transfer Partners, L.P., as issuer, the subsidiary guarantors named therein, and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 001-31219) filed June 8, 2018)
4.28    Forms of Notes (included in Exhibit 4.27 hereto, incorporated by reference to Exhibit 4.3 to Form 8-K (File No. 001-31219) filed June 8, 2018)
4.29    Second Supplemental Indenture, dated as of January 15, 2019, by and among Energy Transfer Operating, L.P., as issuer, the subsidiary guarantors named therein, and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 001-31219) filed January 15, 2019)
4.30    Third Supplemental Indenture, dated as of March 25, 2019, by and among Energy Transfer Operating, L.P., as issuer, the subsidiary guarantors named therein, and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 001-31219) filed March 27, 2019)
4.31    Fourth Supplemental Indenture dated as of January 22, 2020, by and among Energy Transfer Operating, L.P., as issuer, the subsidiary guarantors named therein, U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 001-31219) filed January 22, 2020)

 

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Exhibit
Number

  

Description

4.32    Form of Notes (included in Exhibit 4.31 hereto, incorporated by reference to Exhibit 4.3 to Form 8-K (File No. 001-31219) filed January 22, 2020)
4.33    Description of Registrant’s securities registered pursuant to Section 12 of the Securities Exchange Act of 1934—Description of Listed Senior Notes (incorporated by reference to Exhibit 4.31 to Form 10-K (File No. 001-31219) filed February 21, 2020)
4.34    Description of Registrant’s securities registered pursuant to Section 12 of the Securities Exchange Act of 1934—Description of Series C Preferred Units (incorporated by reference to Exhibit 4.32 to Form 10-K (File No. 001-31219) filed February 21, 2020)
4.35    Description of Registrant’s securities registered pursuant to Section 12 of the Securities Exchange Act of 1934—Description of Series D Preferred Units (incorporated by reference to Exhibit 4.33 to Form 10-K (File No. 001-31219) filed February 21, 2020)
4.36    Description of Registrant’s securities registered pursuant to Section 12 of the Securities Exchange Act of 1934—Description of Series E Preferred Units (incorporated by reference to Exhibit 4.34 to Form 10-K (File No. 001-31219) filed February 21, 2020)
10.1+    Energy Transfer Partners Deferred Compensation Plan (incorporated by reference to Exhibit 10.1 to Form 10-Q (File No. 001-11727) filed May 7, 2010)
10.2    Guarantee of Collection, dated as of April 30, 2013, by and between Regency Energy Partners LP, PEPL Holdings, LLC and Regency Energy Finance Corp. (incorporated by reference to Exhibit 10.3 to Form 8-K (File No. 001-11727) filed on April 30. 2013)
10.3    Cushion Gas Litigation Agreement, dated January 26, 2005, by and among AEP Energy Services Gas Holding Company II, L.L.C. and HPL Storage LP, as Sellers, and La Grange Acquisition, L.P., as Buyer, and AEP Asset Holdings LP, AEP Leaseco LP, Houston Pipe Line Company, LP and HPL Resources Company LP, as Companies (incorporated by reference to Exhibit 10.2 to Form 8-K (File No. 001-11727) filed February 1, 2005)
10.4    Note Purchase Agreement, dated as of May 24, 2007, by and among Transwestern Pipeline Company, LLC and the Purchasers parties thereto (incorporated by reference to Exhibit 10.56 to Form 10-Q (File No. 001-11727) filed July 10, 2007)
10.5    Note Purchase Agreement, dated December 9, 2009, by and among Transwestern Pipeline Company, LLC and the Purchasers parties thereto (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 001-11727) filed December 14, 2009)
10.6    Credit Agreement dated as of December 1, 2017 among Energy Transfer Partners, L.P., Wells Fargo Bank, National Association, as Administrative Agent, the other lenders party thereto and the other parties named therein (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 001-31219) filed December 6, 2017)
10.7    Amendment No. 1 to Five-Year Credit Agreement, Joinder and Increase and Extension Agreement, dated as of October 19, 2018, by and among Energy Transfer Partners, L.P., Sunoco Logistics Partners Operations L.P., and Wells Fargo Bank, National Association, as administrative agent (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 001-31219) filed October 19, 2018)
10.8    364-Day Credit Agreement, dated December 1, 2017, among Energy Transfer Partners, L.P., Wells Fargo Bank, National Association, as Administrative Agent, the other lenders party thereto and other parties thereto (incorporated by referenced to Exhibit 10.2 to Form 8-K (File No. 001-31219) filed December 6, 2017)

 

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Exhibit
Number

  

Description

10.8.1    Amendment No. 1 to 364-Day Credit Agreement, Joinder and Increase and Extension Agreement, dated as of October 19, 2018, by and among Energy Transfer Partners, L.P., Sunoco Logistics Partners Operations L.P., and Wells Fargo Bank, National Association, as administrative agent (incorporated by reference to Exhibit 10.2 to Form 8-K (File No. 001-31219) filed October 19, 2018)
10.8.2    Amendment No. 2 to 364-Day Credit Agreement and Extension Agreement dated as of November 19, 2019 among Energy Transfer Operating, L.P., Sunoco Logistics Partners Operations L.P., Wells Fargo Bank, National Association, as Administrative Agent, the other lenders party thereto and the other parties named therein (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 001-31219) filed November 21, 2019)
10.8.3    Amendment No. 3 to the 364-Day Credit Agreement and Extension Agreement dated November 18, 2020 among Energy Transfer Operating L.P., Sunoco Logistics Partners Operations L.P., Wells Fargo Bank, National Association, as Administrative Agent, the other lenders party thereto and the other parties named therein (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 001-31219) filed November 19, 2020)
10.9    Guaranty dated as of December 1, 2017 by Sunoco Logistics Partners Operations, L.P. and each other Subsidiary from time to time party thereto in favor of Wells Fargo Bank, National Association, as Administrative Agent for the Lenders under that certain Credit Agreement dated as of December 1, 2017 (incorporated by reference to Exhibit 10.3 to Form 8-K (File No. 001-31219) filed December 6, 2017)
10.10    Guaranty, dated as of December 1, 2017, by Sunoco Logistics Partners Operations, L.P. and each other Subsidiary from time to time party thereto in favor of Wells Fargo Bank, National Association, as Administrative Agent for the Lenders under that certain 364-Day Credit Agreement dated as of December 1, 2017 (incorporated by reference to Exhibit 10.4 to Form 8-K (File No. 001-31219) filed December 6, 2017)
10.11    Guarantee of Collection, made as of March 26, 2012, by Citrus ETP Finance LLC, to Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 001-11727) filed March 28, 2012)
10.12    Support Agreement, dated March 26, 2012, by and among PEPL Holdings, LLC, Energy Transfer Partners, L.P., and Citrus ETP Finance LLC (incorporated by reference to Exhibit 10.2 to Form 8-K (File No. 001-11727) filed March 28, 2012)
10.13    Contingent Residual Support Agreement by and among Energy Transfer Partners, L.P., AmeriGas Finance LLC, AmeriGas Finance Corp., AmeriGas Partners, L.P. and, for certain limited purposes, UGI Corporation, dated January 12, 2012 (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 001-11727) filed on January 13, 2012), 2012 (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed January 13, 2012)
10.14    Sixth Supplemental Indenture, dated as of April 30, 2015, by and among Regency Energy Partners LP, Regency Energy Finance Corp., the subsidiary guarantors party thereto, Panhandle Eastern Pipe Line Company, LP, as guarantor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.3 to Form 8-K (File No. 001-11727) filed April 30, 2015)
10.15    Eighth Supplemental Indenture, dated as of April 30, 2015, by and among Regency Energy Partners LP, Regency Energy Finance Corp., the subsidiary guarantors party thereto, Energy Transfer Partners, L.P., as parent guarantor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.4 to Form 8-K (File No. 001-11727) filed April 30, 2015)

 

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Exhibit
Number

  

Description

10.16    Seventh Supplemental Indenture, dated as of May 28, 2015, by and among Regency Energy Partners LP, Regency Energy Finance Corp., the subsidiary guarantors party thereto, Panhandle Eastern Pipe Line Company, LP, Energy Transfer Partners, L.P., as co-obligor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 001-11727) filed June 1, 2015)
10.17    Eighth Supplemental Indenture, dated as of August 10, 2015, by and among Energy Transfer Partners, L.P., Regency Energy Finance Corp. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.2 to Form 8-K (File No. 001-11727) filed August 13, 2015)
10.18    Ninth Supplemental Indenture, dated as of December 1, 2017 by and among Energy Transfer Partners, L.P., Regency Energy Finance Corp. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.9 to Form 8-K (File No. 001-31219) filed December 6, 2017)
10.19    Ninth Supplemental Indenture, dated as of August 10, 2015, by and among Energy Transfer Partners, L.P., Regency Energy Finance Corp. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.3 to Form 8-K (File No. 001-11727) filed August 13, 2015)
10.20    Tenth Supplemental Indenture, dated as of December 1, 2017, by and among Energy Transfer Partners, L.P., Regency Energy Finance Corp. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.10 to Form 8-K (File No. 001-31219) filed December 6, 2017)
10.21    Contribution Agreement, dated as of July 14, 2015, by and among Susser Holdings Corporation, Heritage Holdings, Inc., ETP Holdco Corporation, Sunoco LP, Sunoco GP LLC and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 001-11727) filed July 15, 2015)
10.22    Exchange and Repurchase Agreement, dated as of July 14, 2015, by and among Energy Transfer Equity, L.P., Energy Transfer Partners GP, L.P. and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 10.2 to Form 8-K (File No. 001-11727) filed July 15, 2015)
10.23    Contribution Agreement, dated as of November 15, 2015, by and among Sunoco, LLC, Sunoco, Inc., ETP Retail Holdings, LLC, Sunoco LP, Sunoco GP LLC, and solely with respect to Section 11.19 and other provisions related thereto, Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 001-11727) filed November 19, 2015)
10.24+    Energy Transfer Partners Deferred Compensation Plan for Former Sunoco Executives effective October 5, 2012 (incorporated by reference to Exhibit 10.21 to Form 10-K (File No. 001-31219) filed February 25, 2016)
10.25    Form of Commercial Paper Dealer Agreement between Energy Transfer Partners, L.P., as Issuer, and the Dealer party thereto (incorporated by reference to Exhibit 99.1 to Form 8-K (File No. 001-11727) filed August 22, 2016)
10.26    Registration Rights Agreement, dated as of April 2, 2018, by and among Energy Transfer Partners, L.P., Energy Transfer Equity, L.P., USA Compression Partners, LP and USA Compression Holdings, LLC. (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 001-31219) filed April 3, 2018)
10.27    Transition Services Agreement, dated as of April 2, 2018, by and among USA Compression Partners, LP, CDM Resource Management LLC, CDM Environmental & Technical Services LLC and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 10.2 to Form 8-K (File No. 001-31219) filed April 3, 2018)

 

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Exhibit
Number

  

Description

10.28    Term Loan Credit Agreement dated as of October 17, 2019 among Energy Transfer Operating, L.P., Toronto Dominion (Texas) LLC, as Administrative Agent, the other lenders party thereto and the other parties named therein (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 001-31219) filed October 18, 2019)
10.29    Guaranty dated as of October 17, 2019 between Sunoco Logistics Partners Operations L.P. and Toronto Dominion (Texas) LLC, as Administrative Agent (incorporated by reference to Exhibit 10.2 to Form 8-K (File No. 001-31219) filed October 18, 2019)
21.1*    List of Subsidiaries
22.1    Issuers and Guarantors of Registered Securities (incorporated by reference to Exhibit 22.1 to Form 10-Q (File No. 001-31219) filed May 11, 2020)
23.1*    Consent of Grant Thornton LLP
31.1*    Certification of Co-Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*    Certification of Co-Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.3*    Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1**    Certification of Co-Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2**    Certification of Co-Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.3**    Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101*    Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Balance Sheets as of December 31, 2020 and 2019; (ii) our Consolidated Statements of Operations for the years ended December 31, 2020, 2019 and 2018; (iii) our Consolidated Statements of Comprehensive Income for the years ended December 31, 2020, 2019 and 2018; (iv) our Consolidated Statement of Partners’ Capital for the years ended December 31, 2020, 2019 and 2018; (v) our Consolidated Statements of Cash Flows for the years ended December 31, 2020, 2019 and 2018; and (vi) the notes to our Consolidated Financial Statements
104    Cover Page Interactive Data File (embedded within the Inline XBRL document)

 

*

Filed herewith.

**

Furnished herewith.

+

Denotes a management contract or compensatory plan or arrangement.

 

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Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

  ENERGY TRANSFER OPERATING, L.P.
Dated: February 19, 2021    
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated:  

By:

 

Energy Transfer Partners GP, L.P,

its general partner.

 

By:

 

Energy Transfer Partners, L.L.C.,

its general partner

 

By:

 

/s/ A. Troy Sturrock

    A. Troy Sturrock
    Senior Vice President, Controller and Principal Accounting Officer (duly authorized to sign on behalf of the registrant)

 

Signature

 

Title

 

Date

/s/ Kelcy L. Warren

Kelcy L. Warren

  Executive Chairman   February 19, 2021

/s/ Marshall S. McCrea, III

Marshall S. McCrea, III

 

Co-Chief Executive Officer and Director

(Co-Principal Executive Officer)

  February 19, 2021

/s/ Thomas E. Long

Thomas E. Long

 

Co-Chief Executive Officer

(Co-Principal Executive Officer)

  February 19, 2021

/s/ Bradford D. Whitehurst

Bradford D. Whitehurst

 

Chief Financial Officer

(Principal Financial Officer)

  February 19, 2021

/s/ A. Troy Sturrock

A. Troy Sturrock

 

Senior Vice President and Controller

(Principal Accounting Officer)

  February 19, 2021

/s/ Matthew S. Ramsey

Matthew S. Ramsey

  President, Chief Operating Officer and Director   February 19, 2021

/s/ David K. Skidmore

David K. Skidmore

 

Director

  February 19, 2021

/s/ W. Brett Smith

W. Brett Smith

 

Director

  February 19, 2021

/s/ William P. Williams

William P. Williams

 

Director

  February 19, 2021

 

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INDEX TO FINANCIAL STATEMENTS

Energy Transfer Operating, L.P. and Subsidiaries

 

     Page  

Report of Independent Registered Public Accounting Firm

     D-189  

Consolidated Balance Sheets

     D-192  

Consolidated Statements of Operations

     D-193  

Consolidated Statements of Comprehensive Income (Loss)

     D-194  

Consolidated Statements of Equity

     D-195  

Consolidated Statements of Cash Flows

     D-196  

Notes to Consolidated Financial Statements

     D-197  

 

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Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors of Energy Transfer Partners, L.L.C. and

Unitholders of Energy Transfer Operating, L.P.

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Energy Transfer Operating, L.P. (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2020 and 2019, the related consolidated statements of operations, comprehensive income (loss), equity, and cash flows for each of the three years in the period ended December 31, 2020, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.

Basis for opinion

These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Partnership is not required to have an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical audit matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Goodwill Impairment Assessment

As described in Note 2 to the consolidated financial statements, the Partnership recognized $2.8 billion of goodwill impairment during 2020 and the remaining consolidated goodwill balance was $2.4 billion at December 31, 2020. Annually, or whenever events or changes in circumstances indicate potential asset

 

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impairment has occurred, the Partnership evaluates the recoverability of the carrying value of goodwill. The COVID-19 pandemic and the corresponding decrease in demand for crude oil, natural gas liquids and natural gas negatively impacted the Partnership’s current and projected operating results, cash flow and market capitalization. Therefore, the Partnership determined that a triggering event had occurred and completed an interim goodwill impairment assessment of its reporting units during the first and third quarters of 2020 along with the Partnership’s annual impairment assessment during the fourth quarter of 2020. The results of the quantitative impairment tests indicated that certain reporting units had a carrying value that exceeded their fair values. As a result, the Partnership recorded $2.8 billion of impairment charges to goodwill for these reporting units during the year ended December 31, 2020. In addition, as of December 31, 2020, there was $368 million of goodwill that was recorded within a reporting unit for which the estimated fair value exceeded the carrying value by less than 20% in the most recent quantitative test. We identified the Partnership’s determination of the fair value of the reporting units where carrying value exceeded their fair values and the 1 reporting unit where the estimated fair value exceeded the carrying value by less than 20% as a critical audit matter.

The determination of the fair value of the reporting units was a critical audit matter due to the significant judgments required by management when determining the fair value of a reporting unit. In particular, the fair value estimates were sensitive to significant assumptions such as management’s cash flow projections, discount rates, and the inherent uncertainty around the timing of increases or decreases in future projected results utilized to estimate the fair value of reporting units.

Our audit procedures related to the estimation of the fair value of the reporting units included the following procedures, among others. We tested the effectiveness of controls relating to management’s review of the assumptions used to develop the future cash flows, the discount rates used, and valuation methodologies applied. In addition to testing the effectiveness of controls, we also performed the following:

 

  a.

Evaluated the reasonableness of management’s forecasted financial results by:

 

  i.

Assessing the reasonableness of management’s forecast of future projected results and the underlying timing of recovery in comparison to relevant industry data and other supporting evidence obtained,

 

  ii.

Testing forecasted revenues and gross margins by comparing forecasted amounts to actual historical results to identify material changes, corroborating the basis for increases or decreases in forecasted revenues and gross margins, as applicable, and

 

  iii.

Testing significant operating expenses and cash expenditures by comparing to historical trends and evaluating significant deviations from recent actual amounts.

 

  b.

Utilized an internal valuation specialist to evaluate:

 

  i.

The methodologies used and whether they were acceptable for the underlying assets or operations and whether such methodologies were being applied correctly, and

 

  ii.

The appropriateness of the discount rates by recalculating the weighted average costs of capital or developing independent ranges of acceptable discount rates and comparing those ranges to the amounts selected and applied by management.

Environmental Remediation

As discussed in Note 10 to the consolidated financial statements, the Partnership’s operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures for remediation at current and former facilities. At December 31, 2020, the Partnership’s consolidated environmental obligations totaled $306 million. We identified the identification, assessment and estimation of the environmental exposure associated with certain sites of ETC Sunoco Holdings LLC as a critical audit matter.

 

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The determination that the identification, assessment and estimation of the environmental exposure was a critical audit matter was due to high estimation uncertainty primarily driven by the complexity of the actuarial methods utilized, the discount rate applied and the potential for changes in the timing and extent of remediation. This required an increased extent of effort when performing audit procedures, related to identification, assessment and estimation of the environmental exposure, including the need to involve an actuarial specialist.

Our audit procedures related to the identification, assessment and estimation of the Partnership’s environmental exposure included the following procedures, among others. We tested the effectiveness of controls relating to the identification and review of the historical claims, payments and reserve data provided to the third-party actuarial specialist and the reconciliation of that data used in the actuary report, and the review of the discount rate and actuarial methods applied. In addition to testing the effectiveness of controls, we performed the following procedures:

 

  a.

Utilized an auditor engaged actuarial specialist to evaluate:

 

  i.

The methodologies used and whether they were acceptable for the underlying operations, and

 

  ii.

The qualifications of the actuarial specialist engaged by the Partnership based on their credentials and experience.

 

  b.

Evaluated the discount rate used by comparing it to the historical rate of return related to the investment portfolio used to fund the underlying liabilities, and

 

  c.

Evaluated the life-to-date payments, reserves, and payment patterns by agreeing the historical claims and payment amounts to underlying claims or general ledger.

/s/ GRANT THORNTON LLP

We have served as the Partnership’s auditor since 2004.

Dallas, Texas

February 19, 2021

 

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ENERGY TRANSFER OPERATING, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

 

     December 31,  
     2020     2019  

ASSETS

    

Current assets:

    

Cash and cash equivalents

   $ 366   $ 288

Accounts receivable, net

     3,875     5,038

Accounts receivable from related companies

     79     167

Inventories

     1,739     1,532

Income taxes receivable

     35     146

Derivative assets

     9     23

Other current assets

     222     291
  

 

 

   

 

 

 

Total current assets

     6,325     7,485

Property, plant and equipment

     93,620     89,294

Accumulated depreciation and depletion

     (18,801     (15,398
  

 

 

   

 

 

 
     74,819     73,896

Investments in unconsolidated affiliates

     3,055     3,454

Lease right-of-use assets, net

     866     964

Other non-current assets, net

     1,657     1,571

Long-term affiliate receivable

     1,883     3,603

Intangible assets, net

     5,746     6,154

Goodwill

     2,391     5,167
  

 

 

   

 

 

 

Total assets

   $ 96,742   $ 102,294
  

 

 

   

 

 

 

LIABILITIES AND EQUITY

    

Current liabilities:

    

Accounts payable

   $ 2,809   $ 4,119

Accounts payable to related companies

     177     31

Derivative liabilities

     238     147

Operating lease current liabilities

     53     60

Accrued and other current liabilities

     2,769     3,336

Current maturities of long-term debt

     21     26
  

 

 

   

 

 

 

Total current liabilities

     6,067     7,719

Long-term debt, less current maturities

     51,345     50,904

Non-current derivative liabilities

     237     273

Non-current operating lease liabilities

     837     901

Deferred income taxes

     3,392     3,171

Other non-current liabilities

     1,152     1,162

Commitments and contingencies

    

Redeemable noncontrolling interests

     762     739

Equity:

    

Limited Partners:

    

Series A Preferred Unitholders (950,000 units authorized, issued and outstanding as of December 31, 2020 and 2019, respectively)

     958     958

Series B Preferred Unitholders (550,000 units authorized, issued and outstanding as of December 31, 2020 and 2019, respectively)

     556     556

Series C Preferred Unitholders (18,000,000 units authorized, issued and outstanding as of December 31, 2020 and 2019, respectively)

     440     440

Series D Preferred Unitholders (17,800,000 units authorized, issued and outstanding as of December 31, 2020 and 2019, respectively)

     434     434

Series E Preferred Unitholders (32,000,000 units authorized, issued and outstanding as of December 31, 2020 and 2019, respectively)

     786     786

Series F Preferred Unitholders (500,000 units authorized, issued and outstanding as of December 31, 2020)

     496     —    

Series G Preferred Unitholders (1,100,000 units authorized, issued and outstanding as of December 31, 2020)

     1,094     —    

Common Unitholders and Other

     20,084     24,226

Accumulated other comprehensive income (loss)

     6     (18
  

 

 

   

 

 

 

Total partners’ capital

     24,854     27,382

Noncontrolling interests

     8,096     8,018

Predecessor equity

     —         2,025
  

 

 

   

 

 

 

Total equity

     32,950     37,425
  

 

 

   

 

 

 

Total liabilities and equity

   $ 96,742   $ 102,294
  

 

 

   

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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ENERGY TRANSFER OPERATING, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in millions, except per unit data)

 

     Years Ended December 31,  
     2020     2019     2018  

REVENUES:

      

Refined product sales

   $ 10,514   $ 16,752   $ 17,458

Crude sales

     9,442     15,917     14,425

NGL sales

     6,797     8,290     9,986

Gathering, transportation and other fees

     8,982     9,086     6,797

Natural gas sales

     2,633     3,295     4,452

Other

     586     873     969
  

 

 

   

 

 

   

 

 

 

Total revenues

     38,954     54,213     54,087
  

 

 

   

 

 

   

 

 

 

COSTS AND EXPENSES:

      

Cost of products sold

     25,487     39,801     41,603

Operating expenses

     3,218     3,294     3,089

Depreciation, depletion and amortization

     3,669     3,136     2,843

Selling, general and administrative

     701     686     664

Impairment losses

     2,880     74     431
  

 

 

   

 

 

   

 

 

 

Total costs and expenses

     35,955     46,991     48,630
  

 

 

   

 

 

   

 

 

 

OPERATING INCOME

     2,999     7,222     5,457

OTHER INCOME (EXPENSE):

      

Interest expense, net of interest capitalized

     (2,323     (2,262     (1,709

Equity in earnings of unconsolidated affiliates

     119     302     344

Impairment of investments in unconsolidated affiliates

     (129     —         —    

Losses on extinguishments of debt

     (72     (2     (109

Gains (losses) on interest rate derivatives

     (203     (241     47

Other, net

     159     295     69
  

 

 

   

 

 

   

 

 

 

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE

     550     5,314     4,099

Income tax expense from continuing operations

     239     199     5
  

 

 

   

 

 

   

 

 

 

INCOME FROM CONTINUING OPERATIONS

     311     5,115     4,094

Loss from discontinued operations, net of income taxes

     —         —         (265
  

 

 

   

 

 

   

 

 

 

NET INCOME

     311     5,115     3,829

Less: Net income attributable to noncontrolling interests

     410     1,051     715

Less: Net income attributable to redeemable noncontrolling interests

     49     51     39

Less: Net income (loss) attributable to predecessor

     (6     3     (5
  

 

 

   

 

 

   

 

 

 

NET INCOME (LOSS) ATTRIBUTABLE TO PARTNERS

   $ (142   $ 4,010   $ 3,080
  

 

 

   

 

 

   

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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ENERGY TRANSFER OPERATING, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Dollars in millions)

 

     Years Ended December 31,  
     2020     2019     2018  

Net income

   $ 311   $ 5,115   $ 3,829

Other comprehensive income (loss), net of tax:

      

Change in value of available-for-sale securities

     5     11     (4

Actuarial gain (loss) relating to pension and other postretirement benefits

     21     24     (43

Foreign currency translation adjustment

     69     6     —    

Change in other comprehensive income from unconsolidated affiliates

     (13     (10     4
  

 

 

   

 

 

   

 

 

 
     82     31     (43
  

 

 

   

 

 

   

 

 

 

Comprehensive income

     393     5,146     3,786

Less: Comprehensive income attributable to noncontrolling interests

     410     1,051     715

Less: Comprehensive income attributable to redeemable noncontrolling interests

     49     51     39

Less: Comprehensive income (loss) attributable to predecessor

     (6     3     (5
  

 

 

   

 

 

   

 

 

 

Comprehensive income (loss) attributable to partners

   $ (60   $ 4,041   $ 3,037
  

 

 

   

 

 

   

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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ENERGY TRANSFER OPERATING, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(Dollars in millions)

 

    Limited Partners                                
    Preferred
Unitholders
    Common
Unitholders
and Other
    General
Partner
    AOCI     Non-controlling
Interest
    Predecessor
Equity
    Total  

Balance, December 31, 2017

  $ 1,491   $ 26,643   $ 244   $ 3   $ 5,882   $ 2,816   $ 37,079

Distributions to partners

    (100     (3,376     (1,080     —         —         —         (4,556

Distributions to noncontrolling interests

    —         —         —         —         (891     (276     (1,167

Partnership units issued for cash

    867     58     —         —         —         —         925

Subsidiary units repurchased

    —         —         —         —         —         (300     (300

Energy Transfer Merger

    —         1,370     (340     —         1,474     (2,504     —    

Capital contributions from noncontrolling interests

    —         —         —         —         649     —         649

Cumulative effect adjustment due to change in accounting principle

    —         —         —         —         —         (54     (54

Deemed distribution, net

    —         37     —         —         58     (497     (402

Acquisition of USAC

    —         —         —         —         —         832     832

Other comprehensive loss, net of tax

    —         —         —         (43     —         —         (43

Other, net

    (3     53     (17     (2     16     (12     35

Net income (loss), excluding amounts attributable to redeemable noncontrolling interests

    133     1,754     1,193     —         715     (5     3,790
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance, December 31, 2018

    2,388     26,539     —         (42     7,903     —         36,788

Distributions to partners

    (197     (6,087     —         —         —         —         (6,284

Distributions to noncontrolling interests

    —         —         —         —         (1,399     (2     (1,401

Partnership units issued for cash

    780     —         —         —         —         —         780

SemGroup Acquisition

    —         —         —         —         —         2,008     2,008

Capital contributions from noncontrolling interests

    —         —         —         —         348     —         348

Sale of noncontrolling interest in subsidiary

    —         —         —         —         93     —         93

Other comprehensive income, net of tax

    —         —         —         24     —         15     39

Other, net

    (1     (32     —         —         22     1     (10

Net income, excluding amounts attributable to redeemable noncontrolling interests

    204     3,806     —         —         1,051     3     5,064
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance, December 31, 2019

    3,174     24,226     —         (18     8,018     2,025     37,425

Distributions to partners

    (315     (4,950     —         —         —         —         (5,265

Distributions to noncontrolling interests

    —         —         —         —         (1,311     (25     (1,336

Partnership units issued for cash

    1,580     —         —         —         —         —         1,580

Capital contributions from noncontrolling interests

    —         —         —         —         192     30     222

SemGroup Contribution

    —         1,210     —         (22     788     (1,976     —    

Other comprehensive income (loss), net of tax

    —         —         —         46     36     (38     44

Other, net

    (4     69     —         —         (37     (10     18

Net income (loss), excluding amounts attributable to redeemable noncontrolling interests

    329     (471     —         —         410     (6     262
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance, December 31, 2020

  $ 4,764   $ 20,084   $ —     $ 6   $ 8,096   $ —     $ 32,950
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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ENERGY TRANSFER OPERATING, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)

 

    Years Ended December 31,  
    2020     2019     2018  

OPERATING ACTIVITIES:

     

Net income

  $ 311   $ 5,115   $ 3,829

Reconciliation of net income to net cash provided by operating activities:

     

Loss from discontinued operations

    —         —         265

Depreciation, depletion and amortization

    3,669     3,136     2,843

Deferred income taxes

    212     221     (8

Inventory valuation adjustments

    82     (79     85

Non-cash compensation expense

    121     113     105

Impairment losses

    2,880     74     431

Impairment of investments in unconsolidated affiliates

    129     —         —    

Losses on extinguishment of debt

    72     2     109

Distributions on unvested awards

    (9     (9     (33

Equity in earnings of unconsolidated affiliates

    (119     (302     (344

Distributions from unconsolidated affiliates

    220     290     328

Other non-cash

    89     132     (113

Net change in operating assets and liabilities, net of effects of acquisitions

    212     (395     62
 

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

    7,869     8,298     7,559
 

 

 

   

 

 

   

 

 

 

INVESTING ACTIVITIES:

     

Cash proceeds from sale of noncontrolling interest in subsidiary

    —         93     —    

Cash proceeds from USAC acquisition, net of cash received

    —         —         711

Cash funded in SemGroup Acquisition, net of cash held by SemGroup at acquisition

    —         (250     —    

Cash paid for all other acquisitions

    —         (7     (429

Capital expenditures, excluding allowance for equity funds used during construction

    (5,130     (5,960     (7,407

Contributions in aid of construction costs

    67     80     109

Contributions to unconsolidated affiliates

    (38     (523     (26

Distributions from unconsolidated affiliates in excess of cumulative earnings

    186     98     69

Proceeds from the sale of assets

    19     54     87

Other

    (3     18     (16
 

 

 

   

 

 

   

 

 

 

Net cash used in investing activities

    (4,899     (6,397     (6,902
 

 

 

   

 

 

   

 

 

 

FINANCING ACTIVITIES:

     

Proceeds from borrowings

    24,440     22,583     28,538

Repayments of debt

    (24,081     (18,881     (27,297

Cash received from (paid to) related company

    1,591     995     (440

Common units issued for cash

    —         —         58

Preferred units issued for cash

    1,580     780     867

Redeemable noncontrolling interests issued for cash

    —         —         465

Capital contributions from noncontrolling interests

    192     348     649

Predecessor capital contributions from noncontrolling interests

    30     —         —    

Distributions to partners

    (5,265     (6,284     (4,556

Predecessor distributions to partners

    —         —         (276

Distributions to noncontrolling interests

    (1,311     (1,401     (891

Predecessor distributions to noncontrolling interests

    (25     —         —    

Distributions to redeemable noncontrolling interests

    (49     (53     (24

Repurchases of common units

    —         —         (24

Subsidiary repurchases of common units

    —         —         (300

Debt issuance costs

    (59     (117     (162

Other

    65     (1     85
 

 

 

   

 

 

   

 

 

 

Net cash used in financing activities

    (2,892     (2,031     (3,308
 

 

 

   

 

 

   

 

 

 

DISCONTINUED OPERATIONS:

     

Operating activities

    —         —         (484

Investing activities

    —         —         3,207

Changes in cash included in current assets held for sale

    —         —         11
 

 

 

   

 

 

   

 

 

 

Net increase in cash and cash equivalents of discontinued operations

    —         —         2,734
 

 

 

   

 

 

   

 

 

 

Increase (decrease) in cash and cash equivalents

    78     (130     83

Cash and cash equivalents, beginning of period

    288     418     335
 

 

 

   

 

 

   

 

 

 

Cash and cash equivalents, end of period

  $ 366   $ 288   $ 418
 

 

 

   

 

 

   

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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ENERGY TRANSFER OPERATING, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Tabular dollar and unit amounts are in millions)

 

1.

OPERATIONS AND BASIS OF PRESENTATION:

The consolidated financial statements presented herein contain the results of Energy Transfer Operating, L.P. and its subsidiaries (the “Partnership,” “we,” “us,” “our” or “ETO”).

ETO is a consolidated subsidiary of Energy Transfer LP. In December 2019, ET completed the acquisition of SemGroup. During the first and second quarters of 2020, ET contributed SemGroup and its former subsidiaries to ETO through sale and contribution transactions. The contribution transactions were accounted for as reorganizations of entities under common control; therefore, the contributed entities’ assets and liabilities were not adjusted as of the contribution date. The Partnership’s consolidated financial statements have been retrospectively adjusted to reflect consolidation beginning December 5, 2019 for SemGroup assets contributed (the date ET acquired SemGroup). Predecessor equity included in the consolidated financial statements represents the equity of contributed entities prior to the contribution transactions.

In October 2018, we completed the merger of ETO with a wholly-owned subsidiary of ET in a unit-for-unit exchange (the “Energy Transfer Merger”). In connection with the transaction, the former common unitholders (other than ET and its subsidiaries) received 1.28 common units of ET for each common unit of ETO they owned.

Immediately prior to the closing of the Energy Transfer Merger, the following also occurred:

 

   

the IDRs in ETO were converted into 1,168,205,710 ETO common units; and

 

   

the general partner interest in ETO was converted to a non-economic general partner interest and ETO issued 18,448,341 ETO common units to ETP GP.

The Energy Transfer Merger was a combination of entities under common control; therefore, Sunoco LP, Lake Charles LNG and USAC’s (see Note 3 for more information) assets and liabilities were not adjusted. The Partnership’s consolidated financial statements have been retrospectively adjusted to reflect consolidation beginning January 1, 2018 of Sunoco LP and Lake Charles LNG and April 2, 2018 of USAC (the date ET acquired USAC, see Note 3). Predecessor equity included on the consolidated financial statements represents Sunoco LP, Lake Charles LNG and USAC’s equity prior to the Energy Transfer Merger.

Following the closing of the Energy Transfer Merger, Energy Transfer Equity, L.P. changed its name to “Energy Transfer LP” and its common units began trading on the New York Stock Exchange under the “ET” ticker symbol on Friday, October 19, 2018. In addition, Energy Transfer Partners, L.P. changed its name to “Energy Transfer Operating, L.P.” For purposes of maintaining clarity, the following references are used herein:

 

   

References to “ETO” refer to the entity named Energy Transfer Partners, L.P. prior to the close of the Energy Transfer Merger and Energy Transfer Operating, L.P. subsequent to the close of the Energy Transfer Merger; and

 

   

References to “ET” refer to the entity named Energy Transfer Equity, L.P. prior to the close of the Energy Transfer Merger and Energy Transfer LP subsequent to the close of the Energy Transfer Merger.

Our financial statements reflect the following reportable segments:

 

   

intrastate transportation and storage;

 

   

interstate transportation and storage;

 

   

midstream;

 

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NGL and refined products transportation and services;

 

   

crude oil transportation and services;

 

   

investment in Sunoco LP;

 

   

investment in USAC; and

 

   

all other.

The Partnership owns and operates intrastate natural gas pipeline systems and storage facilities that are engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia.

The Partnership owns and operates interstate pipelines, either directly or through equity method investments, that transport natural gas to various markets in the United States.

The Partnership is engaged in the gathering and processing, compression, treating and transportation of natural gas, focusing on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring and Avalon shales.

The Partnership owns and operates a logistics business, consisting of a geographically diverse portfolio of complementary pipeline, terminalling, and acquisition and marketing assets, which are used to facilitate the purchase and sale of crude oil, NGLs and refined products.

The Partnership owns a controlling interest in Sunoco LP which is engaged in the wholesale distribution of motor fuels to convenience stores, independent dealers, commercial customers, and distributors, as well as the retail sale of motor fuels and merchandise through Sunoco LP operated convenience stores and retail fuel sites. As of December 31, 2020, our interest in Sunoco LP consisted of 100% of the general partner and IDRs, as well as 28.5 million common units.

The Partnership owns a controlling interest in USAC which provides compression services to producers, processors, gatherers and transporters of natural gas and crude oil. As of December 31, 2020, our interest in USAC consisted of 100% of the general partner and 46.1 million common units.

Basis of Presentation. The consolidated financial statements of the Partnership have been prepared in accordance with GAAP and include the accounts of all controlled subsidiaries after the elimination of all intercompany accounts and transactions. Certain prior year amounts have been conformed to the current year presentation. These reclassifications had no impact on net income or total equity.

The consolidated financial statements of the Partnership presented herein include the results of operations of our controlled subsidiaries, including Sunoco LP and USAC.

For prior periods herein, certain balances have been reclassified to assets and liabilities held for sale and certain revenues and expenses to discontinued operations. These reclassifications had no impact on net income or total equity.

 

2.

ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:

Change in Accounting Policy

Effective January 1, 2020, the Partnership elected to change its accounting policy related to certain barrels of crude oil that were previously accounted for as inventory. Under the revised accounting policy, certain amounts of crude oil that are not available for sale have been reclassified from inventory to non-current assets. These crude oil barrels, which are owned by the Partnership’s crude oil acquisition and marketing business, include pipeline linefill and tank bottoms and are not considered to be available for sale because the volumes must be maintained in order to continue normal operation of the related pipelines or tanks and because there is no expectation of liquidation or sale of these volumes in the near term.

 

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Under the previous accounting policy, all crude oil barrels were recorded as inventory under the weighted average cost method. Under the revised accounting policy, barrels related to pipeline linefill and tank bottoms are accounted for as long-lived assets and reflected as non-current assets on the consolidated balance sheet. These crude oil barrels will be tested for impairment consistent with the Partnership’s existing accounting policy for impairments of long-lived assets. The Partnership’s management believes that the change in accounting policy is preferable as it more closely aligns the accounting policies across the consolidated entity, given that similar assets in the Partnership’s natural gas, NGLs and refined products businesses are accounted for as non-current assets. In addition, management believes that reflecting these crude oil barrels as non-current assets better represents the economic results of the Partnership’s crude oil acquisition and marketing business by reducing volatility resulting from market price adjustments to crude oil barrels that are not expected to be sold or liquidated in the near term.

As a result of this change in accounting policy, the Partnership’s consolidated balance sheet for the prior period has been retrospectively adjusted as follows:

 

     December 31, 2019  
     As
Originally
Reported*
     Effect of
Change
     As
Adjusted
 

Inventories

   $ 1,935    $ (403    $ 1,532

Total current assets

     7,888      (403      7,485

Other non-current assets, net

     1,075      496      1,571

Total assets

     102,201      93      102,294

Total partners’ capital

     27,289      93      27,382

 

  *

Amounts reflect the retrospective consolidation of the SemGroup entities as discussed in Note 3.

In addition, the Partnership’s consolidated statements of operations, comprehensive income and cash flows for prior periods have been retrospectively adjusted as follows:

 

     Year Ended
December 31,
 
     2019*      2018  

As originally reported:

     

Consolidated Statements of Operations and Comprehensive Income

     

Cost of products sold

   $ 39,727    $ 41,658

Operating income

     7,296      5,402

Income from continuing operations before income tax expense

     5,388      4,044

Net income

     5,189      3,774

Comprehensive income

     5,220      3,731

Comprehensive income attributable to partners

     4,115      2,982

Consolidated Statements of Cash Flows

     

Net income

     5,189      3,774

Net change in operating assets and liabilities

     (469      117

Effect of change:

     

Consolidated Statements of Operations and Comprehensive Income

     

Cost of products sold

     74      (55

Operating income

     (74      55

Income from continuing operations before income tax expense

     (74      55

Net income

     (74      55

Comprehensive income

     (74      55

Comprehensive income attributable to partners

     (74      55

 

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     Year Ended
December 31,
 
     2019*      2018  

Consolidated Statements of Cash Flows

     

Net income

     (74      55

Net change in operating assets and liabilities

     74      (55

As adjusted:

     

Consolidated Statements of Operations and Comprehensive Income

     

Cost of products sold

     39,801      41,603

Operating income

     7,222      5,457

Income from continuing operations before income tax expense

     5,314      4,099

Net income

     5,115      3,829

Comprehensive income

     5,146      3,786

Comprehensive income attributable to partners

     4,041      3,037

Consolidated Statements of Cash Flows

     

Net income

     5,115      3,829

Net change in operating assets and liabilities

     (395      62

 

  *

Amounts reflect the retrospective consolidation of the SemGroup entities as discussed in Note 3.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects.

Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.

Regulatory Accounting—Regulatory Assets and Liabilities

Our interstate transportation and storage segment is subject to regulation by certain state and federal authorities, and certain subsidiaries in that segment have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory

 

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commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.

Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978, it does not currently apply regulatory accounting policies in accounting for its operations. Panhandle does not apply regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs.

Cash, Cash Equivalents and Supplemental Cash Flow Information

Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value.

We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.

The net change in operating assets and liabilities (net of effects of acquisitions) included in cash flows from operating activities is comprised as follows:

 

     Years Ended December 31,  
         2020              2019              2018      

Accounts receivable

   $ 1,163    $ (473    $ 506

Accounts receivable from related companies

     (290      (17      128

Inventories

     (271      (20      237

Other current assets

     189      107      7

Other non-current assets, net

     (7      (155      (119

Accounts payable

     (1,327      148      (769

Accounts payable to related companies

     517      (92      (206

Accrued and other current liabilities

     161      23      365

Other non-current liabilities

     8      (134      (34

Price risk management assets and liabilities, net

     69      218      (53
  

 

 

    

 

 

    

 

 

 

Net change in operating assets and liabilities, net of effects of acquisitions

   $ 212    $ (395    $ 62
  

 

 

    

 

 

    

 

 

 

Non-cash investing and financing activities and supplemental cash flow information are as follows:

 

     Years Ended December 31,  
     2020      2019      2018  

NON-CASH INVESTING ACTIVITIES:

        

Accrued capital expenditures

   $ 604    $ 1,334    $ 1,030

Lease assets obtained in exchange for new lease liabilities

     42      68      —    

Net gains (losses) from subsidiary common unit transactions

     —          —          (127

SUPPLEMENTAL CASH FLOW INFORMATION:

        

Cash paid for interest, net of interest capitalized

   $ 2,086    $ 1,799    $ 1,537

Cash paid for income taxes (net of refunds)

     (64      30      508

 

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Accounts Receivable

Our operations deal with a variety of counterparties across the energy sector, some of which are investment grade, and most of which are not. Internal credit ratings and credit limits are assigned to all counterparties and limits are monitored against credit exposure. Letters of credit or prepayments may be required from those counterparties that are not investment grade depending on the internal credit rating and level of commercial activity with the counterparty.

We have a diverse portfolio of customers; however, because of the midstream and transportation services we provide, many of our customers are engaged in the exploration and production segment. We manage trade credit risk to mitigate credit losses and exposure to uncollectible trade receivables. Prospective and existing customers are reviewed regularly for creditworthiness to manage credit risk within approved tolerances. Customers that do not meet minimum credit standards are required to provide additional credit support in the form of a letter of credit, prepayment, or other forms of security. We establish an allowance for credit losses on trade receivables based on the expected ultimate recovery of these receivables and consider many factors including historical customer collection experience, general and specific economic trends, and known specific issues related to individual customers, sectors, and transactions that might impact collectability. Changes in the allowance are recorded as a component of operating expenses; reductions in the allowance are recorded when receivables are subsequently collected or written-off. Past due receivable balances are written-off when our efforts have been unsuccessful in collecting the amount due.

Inventories

Inventories consist principally of natural gas held in storage, NGLs and refined products, crude oil and spare parts, all of which are valued at the lower of cost or net realizable value utilizing the weighted-average cost method.

Sunoco LP’s fuel inventories are stated at the lower of cost or market using the last-in-first-out (“LIFO”) method. As of December 31, 2020 and 2019, the carrying value of Sunoco LP’s fuel inventory included lower of cost or market reserves of $311 million and $229 million, respectively, and the inventory carrying value equaled or exceeded its replacement cost. For the years ended December 31, 2020, 2019 and 2018, the Partnership’s consolidated statements of operations did not include any material amounts of income from the liquidation of Sunoco LP’s LIFO fuel inventory.

Inventories consisted of the following:

 

     December 31,  
     2020      2019  

Natural gas, NGLs and refined products (1)

   $ 1,013    $ 833

Crude oil

     287      251

Spare parts and other

     439      448
  

 

 

    

 

 

 

Total inventories

   $ 1,739    $ 1,532
  

 

 

    

 

 

 

 

  (1)

Due to changes in fuel prices, Sunoco LP recorded a write-down on the value of its fuel inventory of $82 million for the year ended December 31, 2020.

We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations.

 

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Other Current Assets

Other current assets consisted of the following:

 

     December 31,  
     2020      2019  

Deposits paid to vendors

   $ 75    $ 95

Prepaid expenses and other

     147      196
  

 

 

    

 

 

 

Total other current assets

   $ 222    $ 291
  

 

 

    

 

 

 

Property, Plant and Equipment

Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC-mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations.

Property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value.

In 2020, the Partnership recognized a $58 million fixed asset impairment primarily due to decreases in projected future cash flow as a result of the overall market demand decline. USAC recorded an $8 million impairment of compression equipment as a result of its evaluations of the future deployment of its idle fleet.

In 2019, USAC recognized a $6 million fixed asset impairment related to certain idle compressor assets. Sunoco LP recognized a $47 million write-down on assets held for sale related to its ethanol plant in Fulton, New York.

In 2018, USAC recognized a $9 million fixed asset impairment related to certain idle compressor assets.

Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our revolving credit facilities when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts—borrowed funds and equity funds.

 

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Components and useful lives of property, plant and equipment were as follows:

 

     December 31,  
     2020      2019  

Land and improvements

   $ 1,233    $ 1,232

Buildings and improvements (1 to 45 years)

     4,204      2,631

Pipelines and equipment (5 to 83 years)

     69,120      64,678

Product storage and related facilities and equipment (2 to 83 years)

     6,393      5,898

Right of way (20 to 83 years)

     5,091      4,851

Other (1 to 48 years)

     1,808      1,509

Construction work-in-process

     5,771      8,495
  

 

 

    

 

 

 

Property, plant and equipment, gross

     93,620      89,294

Less: Accumulated depreciation and depletion

     (18,801      (15,398
  

 

 

    

 

 

 

Property, plant and equipment, net

   $ 74,819    $ 73,896
  

 

 

    

 

 

 

We recognized the following amounts for the periods presented:

 

     Years Ended December 31,  
     2020      2019      2018  

Depreciation, depletion and amortization expense

   $ 3,266    $ 2,828    $ 2,522

Capitalized interest

     189      166      294

Investments in Unconsolidated Affiliates

We own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other than temporary. During the year ended December 31, 2020, the Partnership recorded an impairment of its investment in White Cliffs of $129 million due to a decrease in projected future revenues and cash flows as a result of the overall market demand decline that occurred subsequent to the SemGroup acquisition and related purchase price allocation in December 2019.

Other Non-Current Assets, net

Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following:

 

     December 31,  
     2020      2019  

Crude pipeline linefill and tank bottoms

   $ 517    $ 496

Regulatory assets

     41      42

Pension assets

     103      84

Deferred charges

     188      178

Restricted funds

     179      178

Other

     629      593
  

 

 

    

 

 

 

Total other non-current assets, net

   $ 1,657    $ 1,571
  

 

 

    

 

 

 

Restricted funds includes an immaterial amount of restricted cash primarily held in our wholly-owned captive insurance companies.

 

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Intangible Assets

Intangible assets are stated at cost, net of amortization computed on the straight-line method. The Partnership removes the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized.

Components and useful lives of intangible assets were as follows:

 

     December 31, 2020      December 31, 2019  
     Gross Carrying
Amount
     Accumulated
Amortization
     Gross Carrying
Amount
     Accumulated
Amortization
 

Amortizable intangible assets:

           

Customer relationships, contracts and agreements (3 to 46 years)

   $ 7,513    $ (2,117    $ 7,535    $ (1,743

Patents (10 years)

     48      (40      48      (35

Trade Names (20 years)

     66      (35      66      (31

Other (5 to 20 years)

     19      (15      19      (12
  

 

 

    

 

 

    

 

 

    

 

 

 

Total amortizable intangible assets

     7,646      (2,207      7,668      (1,821

Non-amortizable intangible assets:

           

Trademarks

     295      —          295      —    

Other

     12      —          12      —    
  

 

 

    

 

 

    

 

 

    

 

 

 

Total non-amortizable intangible assets

     307      —          307      —    
  

 

 

    

 

 

    

 

 

    

 

 

 

Total intangible assets

   $ 7,953    $ (2,207    $ 7,975    $ (1,821
  

 

 

    

 

 

    

 

 

    

 

 

 

Aggregate amortization expense of intangible assets was as follows:

 

     Years Ended December 31,  
         2020              2019              2018      

Reported in depreciation, depletion and amortization expense

   $ 403    $ 308    $ 321

Estimated aggregate amortization of intangible assets for the next five years is as follows:

 

Years Ending December 31:

  

2021

   $ 393

2022

     379

2023

     363

2024

     349

2025

     335

We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate.

Sunoco LP performed impairment tests on its indefinite-lived intangible assets during the fourth quarter of 2018 and recognized a $30 million impairment charge on its contractual rights, included in other in the table above, primarily due to decreases in projected future revenues and cash flows from the date the intangible assets were originally recorded.

 

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Goodwill

Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test is performed during the fourth quarter.

Changes in the carrying amount of goodwill were as follows:

 

    Intrastate
Transportation
and Storage
    Interstate
Transportation
and Storage
    Midstream     NGL and
Refined
Products
Transportation
and Services
    Crude Oil
Transportation
and Services
    Investment
in Sunoco
LP
    Investment
in USAC
    All
Other
    Total  

Balance, December 31, 2018

  $ 10   $ 196   $ 492   $ 693   $ 1,167   $ 1,559   $ 619   $ 149   $ 4,885

Acquired

    —         42     —         —         230     —         —         35     307

Impaired

    —         (12     (9     —         —         —         —         —         (21

Other

    —         —         —         —         —         (4     —         —         (4
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance, December 31, 2019

    10     226     483     693     1,397     1,555     619     184     5,167

Acquired

    —         —         —         —         —         9     —         —         9

Impaired

    (10     (226     (483     —         (1,279     —         (619     (198     (2,815

Other

    —         —         —         —         (66     —         —         96     30
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance, December 31, 2020

  $ —     $ —     $ —     $ 693   $ 52   $ 1,564   $ —     $ 82   $ 2,391
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized.

During the first quarter of 2020, due to the impacts of the COVID-19 pandemic, the decline in commodity prices and the decreases in the Partnership’s market capitalization, we determined that interim impairment testing should be performed on certain reporting units. The Partnership performed the interim impairment tests consistent with our approach for annual impairment testing, including using similar models, inputs and assumptions. As a result of the interim impairment test, the Partnership recognized goodwill impairments of $483 million related to our Ark-La-Tex and South Texas operations within the midstream segment, $183 million related to our Lake Charles LNG regasification operations within the interstate transportation and storage segment due to contractually scheduled reductions in payments for the remainder of the contract term, and $40 million related to our all other operations primarily due to decreases in projected future revenues and cash flows as a result of the overall market demand decline. In addition, USAC recognized a goodwill impairment of $619 million during the three months ended March 31, 2020, which is included in the Partnership’s consolidated results of operations.

During the third quarter of 2020, the Partnership performed interim impairment testing on certain reporting units within its midstream, interstate, crude, NGL and all other operations. As a result, the Partnership recognized goodwill impairments of $1.28 billion related to our crude operations, $132 million related to our Energy Transfer Canada operations within the all other segment and $43 million related to our interstate operations primarily due to decreases in projected future cash flow as a result of the overall market demand decline.

During the fourth quarter of 2020, the Partnership performed annual impairment testing on certain reporting units within its midstream, interstate, crude, NGL and all other operations. As a result, the Partnership recognized goodwill impairments of $10 million related to our intrastate operations, $11 million related to our PEI operations and $15 million related to our Natural Resources operations within the all other segment primarily due to decreases in projected future cash flow as a result of the overall market demand decline. No other impairments of the Partnership’s goodwill were identified.

During the third quarter of 2019, the Partnership recognized a goodwill impairment of $12 million related to the Southwest Gas operations within the interstate segment primarily due to decreases in projected future revenues and cash flows. During the fourth quarter of 2019, the Partnership recognized a goodwill

 

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impairment of $9 million related to our North Central operations within the midstream segment primarily due to changes in assumptions related to projected future revenues and cash flows.

During the fourth quarter of 2018, the Partnership recognized goodwill impairments of $378 million related to our Northeast operations within the midstream segment primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded. These changes in assumptions reflect delays in the construction of third-party takeaway capacity in the Northeast.

The Partnership determines the fair value of our reporting units using the discounted cash flow method, the guideline company method, or a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determines fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determines the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimates a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business.

Management does not believe that any of the goodwill balances in its reporting units is currently at significant risk of impairment; however, of the $2.39 billion of goodwill on the Partnership’s consolidated balance sheet as of December 31, 2020, approximately $368 million is recorded in reporting units for which the estimated fair value exceeded the carrying value by less than 20% in the most recent quantitative test.

Asset Retirement Obligations

We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.

An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an ARO in the periods in which management can reasonably estimate the settlement dates.

As of December 31, 2020 and 2019, other non-current liabilities in the Partnership’s consolidated balance sheets included AROs of $270 million and $247 million, respectively. For the years ended December 31, 2020, 2019 and 2018 aggregate accretion expense related to AROs was $16 million, $5 million and $13 million, respectively.

Except for the AROs discussed above, management was not able to reasonably measure the fair value of AROs as of December 31, 2020 and 2019, in most cases because the settlement dates were indeterminable.

 

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Although a number of onshore assets in our systems are subject to agreements or regulations that give rise to an ARO upon discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Our subsidiaries also have legal obligations for several other assets at previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, our subsidiaries are legally or contractually required to abandon in place or remove the asset. We believe we may have additional AROs related to pipeline assets and storage tanks, for which it is not possible to estimate whether or when the AROs will be settled. Consequently, these AROs cannot be measured at this time. Sunoco LP also has AROs related to the estimated future cost to remove underground storage tanks.

Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future. We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely.

As of December 31, 2020 and 2019, other non-current assets on the Partnership’s consolidated balance sheets included $34 million and $31 million, respectively, of funds that were legally restricted for the purpose of settling AROs.

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:

 

     December 31,  
     2020      2019  

Interest payable

   $ 598    $ 576

Customer advances and deposits

     161      123

Accrued capital expenditures

     604      1,334

Accrued wages and benefits

     109      217

Taxes payable other than income taxes

     446      263

Exchanges payable

     127      67

Other

     724      756
  

 

 

    

 

 

 

Total accrued and other current liabilities

   $ 2,769    $ 3,336
  

 

 

    

 

 

 

Deposits or advances are received from our customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may be required when customers exceed their credit limits or do not qualify for open credit.

Redeemable Noncontrolling Interests

Our redeemable noncontrolling interests relate to certain preferred unitholders of one of our consolidated subsidiaries that have the option to convert their preferred units to such subsidiary’s common units at the election of the holders and the noncontrolling interest holders in one of our consolidated subsidiaries that have the option to sell their interests to us. In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable noncontrolling interests on our consolidated balance sheets. See Note 6 for further information.

 

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Environmental Remediation

We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued.

Fair Value of Financial Instruments

The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value.

Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our debt obligations as of December 31, 2020 was $56.13 billion and $51.37 billion, respectively. As of December 31, 2019, the aggregate fair value and carrying amount of our debt obligations was $54.66 billion and $50.93 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.

We have commodity derivatives, interest rate derivatives and embedded derivatives in our preferred units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. During the year ended December 31, 2020, no transfers were made between any levels within the fair value hierarchy.

 

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The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2020 and 2019 based on inputs used to derive their fair values:

 

     Fair Value
Total
     Fair Value Measurements at
December 31, 2020
 
       Level 1          Level 2    

Assets:

        

Commodity derivatives:

        

Natural Gas:

        

Basis Swaps IFERC/NYMEX

   $ 12    $ 12    $ —  

Swing Swaps IFERC

     1      —          1

Fixed Swaps/Futures

     13      13      —    

Forward Physical Contracts

     5      —          5

Power:

        

Forwards

     4      —          4

Futures

     2      2      —    

Options – Calls

     1      1      —    

NGLs – Forwards/Swaps

     127      127      —    

Refined Products – Futures

     3      3      —    

Crude – Forwards/Swaps

     —          —          —    
  

 

 

    

 

 

    

 

 

 

Total commodity derivatives

     168      158      10

Other non-current assets

     34      22      12
  

 

 

    

 

 

    

 

 

 

Total assets

   $ 202    $ 180    $ 22
  

 

 

    

 

 

    

 

 

 

Liabilities:

        

Interest rate derivatives

   $ (448    $ —      $ (448

Commodity derivatives:

        

Natural Gas:

        

Basis Swaps IFERC/NYMEX

     (11      (11      —    

Swing Swaps IFERC

     (3      —          (3

Fixed Swaps/Futures

     (13      (13      —    

Forward Physical Contracts

     (1      —          (1

Power:

        

Forwards

     —          —          —    

Futures

     (3      (3      —    

NGLs – Forwards/Swaps

     (227      (227      —    

Refined Products – Futures

     (11      (11      —    
  

 

 

    

 

 

    

 

 

 

Total commodity derivatives

     (269      (265      (4
  

 

 

    

 

 

    

 

 

 

Total liabilities

   $ (717    $ (265    $ (452
  

 

 

    

 

 

    

 

 

 

 

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     Fair Value
Total
     Fair Value Measurements at
December 31, 2019
 
     Level 1      Level 2  

Assets:

        

Commodity derivatives:

        

Natural Gas:

        

Basis Swaps IFERC/NYMEX

   $ 17    $ 17    $ —  

Swing Swaps IFERC

     1      —          1

Fixed Swaps/Futures

     65      65      —    

Forward Physical Contracts

     3      —          3

Power:

        

Power – Forwards

     11      —          11

Futures

     4      4      —    

Options – Puts

     1      1      —    

Options – Calls

     1      1      —    

NGLs – Forwards/Swaps

     260      260      —    

Refined Products – Futures

     8      8      —    

Crude – Forwards/Swaps

     13      13      —    
  

 

 

    

 

 

    

 

 

 

Total commodity derivatives

     384      369      15

Other non-current assets

     31      20      11
  

 

 

    

 

 

    

 

 

 

Total assets

   $ 415    $ 389    $ 26
  

 

 

    

 

 

    

 

 

 

Liabilities:

        

Interest rate derivatives

   $ (399    $ —      $ (399

Commodity derivatives:

        

Natural Gas:

        

Basis Swaps IFERC/NYMEX

     (49      (49      —    

Swing Swaps IFERC

     (1      —          (1

Fixed Swaps/Futures

     (43      (43      —    

Power:

        

Forwards

     (5      —          (5

Futures

     (3      (3      —    

NGLs – Forwards/Swaps

     (278      (278      —    

Refined Products – Futures

     (10      (10      —    
  

 

 

    

 

 

    

 

 

 

Total commodity derivatives

     (389      (383      (6
  

 

 

    

 

 

    

 

 

 

Total liabilities

   $ (788    $ (383    $ (405
  

 

 

    

 

 

    

 

 

 

Contributions in Aid of Construction Costs

On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with pipeline construction and production well tie-ins. Contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received, and any CIAC which exceeds our total project costs, is recognized as other income in the period in which it is realized.

Shipping and Handling Costs

Shipping and handling costs are included in cost of products sold, except for shipping and handling costs related to fuel consumed for compression and treating which are included in operating expenses.

 

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Costs and Expenses

Cost of products sold include actual cost of fuel sold, adjusted for the effects of our hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership, and administrative personnel.

We record the collection of taxes to be remitted to government authorities on a net basis, except for consumer excise taxes collected by Sunoco LP on sales of refined products and merchandise which are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income. For the years ended December 31, 2020, 2019 and 2018, excise taxes collected by Sunoco LP were $301 million, $386 million and $370 million, respectively.

Issuances of Subsidiary Units

We record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or comprehensive income. For example, upon our subsidiary’s issuance of common units in a public offering, we record any difference between the amount of consideration received or paid and the amount by which the noncontrolling interests are adjusted as a change in partners’ capital.

Income Taxes

ETO is a publicly traded limited partnership and is not taxable for federal and most state income tax purposes. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and most state purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to our preferred unitholders as a result of differences between the tax basis and financial basis of assets and liabilities, differences between the tax accounting and financial accounting treatment of certain items, and due to allocation requirements related to taxable income under our Fifth Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”).

As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and Internal Revenue Service (“IRS”) pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, ETO would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2020, 2019 and 2018, our qualifying income met the statutory requirement.

The Partnership conducts certain activities through corporate subsidiaries which are subject to federal, state and local income taxes. These corporate subsidiaries include ETP Holdco, Inland Corporation, Sunoco Property Company LLC and Aloha. The Partnership and its corporate subsidiaries account for income taxes under the asset and liability method.

Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.

The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing

 

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and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes.

Accounting for Derivative Instruments and Hedging Activities

For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third-party prices, readily available market information, broker quotes and appropriate valuation techniques.

At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in net income for the period.

If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in our consolidated statements of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statements of operations.

Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged.

If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, the change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.

We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. Certain of our interest rate derivatives are accounted for as either cash flow hedges or fair value hedges. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in “Gains (losses) on interest rate derivatives” in the consolidated statements of operations.

Non-Cash Compensation

For awards of restricted units, we recognize compensation expense over the vesting period based on the grant-date fair value, which is determined based on the market price of the underlying common units on the grant date. For awards of cash restricted units, we remeasure the fair value of the award at the end of each reporting period based on the market price of the underlying common units as of the reporting date, and the fair value is recorded in other non-current liabilities on our consolidated balance sheets.

 

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Pensions and Other Postretirement Benefit Plans

The Partnership recognizes the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans). Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. Changes in the funded status of the plan are recorded in the year in which the change occurs within AOCI in equity or, for entities applying regulatory accounting, as a regulatory asset or regulatory liability.

Allocation of Income

For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests. The capital account provisions of our Partnership Agreement incorporate principles established for United States Federal income tax purposes and may not be comparable to the partners’ capital balances reflected under GAAP in our consolidated financial statements. Subsequent to the Energy Transfer Merger, our general partner owns a non-economic interest in us and, therefore, our net income for partners’ capital and statement of operations presentation purposes is allocated entirely to the Limited Partners.

 

3.

ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:

ET Contribution of SemGroup Assets to ETO

As discussed in Note 1, former SemGroup subsidiaries were transferred from ET to ETO during the first and second quarters of 2020. The following table represents the fair value, as of December 5, 2019, of the SemGroup assets and liabilities transferred from ET to ETO:

 

     At December 5,
2019
 

Total current assets

   $ 794

Property, plant and equipment

     3,891

Other non-current assets

     617

Goodwill

     295

Intangible assets

     460
  

 

 

 

Total assets

   $ 6,057
  

 

 

 

Total current liabilities

   $ 629

Long-term debt, less current maturities (1)

     2,576

Other non-current liabilities

     197

Energy Transfer Canada Preferred shares

     241
  

 

 

 

Total liabilities

     3,643

Noncontrolling interest

     822

Partners’ capital

     1,592
  

 

 

 

Total liabilities and partners’ capital

   $ 6,057
  

 

 

 

 

  (1)

Long-term debt at December 5, 2019 includes SemGroup senior notes with an aggregate principal amount of $1.375 billion and SemGroup subsidiary debt of $593 million, all of which was redeemed in December 2019, subsequent to the close of the SemGroup Transaction.

During 2020, the Partnership has recorded impairments on certain of the contributed SemGroup assets. Those impairments include a $244 million impairment of goodwill and a $129 million impairment of other non-current assets.

 

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ET Contribution of Assets to ETO

Immediately prior to the closing of the Energy Transfer Merger discussed in Note 1, ET contributed the following to ETO:

 

   

2,263,158 common units representing limited partner interests in Sunoco LP to ETO in exchange for 2,874,275 ETO common units;

 

   

100 percent of the limited liability company interests in Sunoco GP LLC, the sole general partner of Sunoco LP, and all of the IDRs in Sunoco LP, to ETO in exchange for 42,812,389 ETO common units;

 

   

12,466,912 common units representing limited partner interests in USAC and 100 percent of the limited liability company interests in USA Compression GP, LLC, the general partner of USAC, to ETO in exchange for 16,134,903 ETO common units; and

 

   

a 100 percent limited liability company interest in Lake Charles LNG and a 60 percent limited liability company interest in each of Energy Transfer LNG Export, LLC, ET Crude Oil Terminals, LLC and ETC Illinois LLC to ETO in exchange for 37,557,815 ETO common units.

USAC Acquisition

On April 2, 2018, ET acquired a controlling interest in USAC, a publicly traded partnership that provides compression services in the United States. Specifically, the Partnership acquired (i) all of the outstanding limited liability company interests in USA Compression GP, LLC (“USAC GP”), the general partner of USAC, and (ii) 12,466,912 USAC common units representing limited partner interests in USAC for cash consideration equal to $250 million (the “USAC Transaction”). Concurrently, USAC cancelled its IDRs and converted its economic general partner interest into a non-economic general partner interest in exchange for the issuance of 8,000,000 USAC common units to USAC GP.

Concurrent with these transactions, ETO contributed to USAC all of the issued and outstanding membership interests of CDM for aggregate consideration of approximately $1.7 billion, consisting of (i) 19,191,351 USAC common units, (ii) 6,397,965 units of a newly authorized and established class of units representing limited partner interests in USAC (“USAC Class B Units”) and (iii) $1.23 billion in cash, including customary closing adjustments (the “CDM Contribution”). The USAC Class B Units are a new class of partnership interests of USAC that have substantially all of the rights and obligations of a USAC common unit, except the USAC Class B Units will not participate in distributions for the first four quarters following the closing date of April 2, 2018. Each USAC Class B Unit will automatically convert into one USAC common unit on the first business day following the record date attributable to the quarter ending June 30, 2019.

As noted above, ET contributed its interests in USAC to ETO in October 2018. ET’s contribution of its interests in USAC was a transaction between entities under common control; therefore, the Partnership’s consolidated financial statements reflect USAC on a consolidated basis beginning April 2, 2018, the date that ET obtained control of USAC. The Partnership had previously deconsolidated CDM upon its contribution to USAC on April 2, 2018; however, due to the retrospective consolidation of USAC as of that date, CDM is reflected as a consolidated subsidiary for all periods presented herein.

Summary of Assets Acquired and Liabilities Assumed

The USAC Transaction was recorded using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date.

 

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The total purchase price was allocated as follows:

 

     At April 2,
2018
 

Total current assets (2)

   $ 786

Property, plant and equipment

     1,332

Other non-current assets

     15

Goodwill (1)

     366

Intangible assets

     222
  

 

 

 

Total assets

   $ 2,721
  

 

 

 

Total current liabilities

   $ 110

Long-term debt, less current maturities

     1,527

Other non-current liabilities

     2
  

 

 

 

Total liabilities

     1,639

Noncontrolling interest

     832

Partners’ capital

     250
  

 

 

 

Total liabilities and partners’ capital

   $ 2,721
  

 

 

 

 

  (1)

None of the goodwill is expected to be deductible for tax purposes. Goodwill recognized from the business combination primarily relates to the value attributed to additional growth opportunities, synergies and operating leverage within USAC’s operations.

  (2)

Includes cash and cash equivalents of $711 million held by USAC as of the acquisition date.

The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.

Sunoco LP Retail Store Divestment

On January 23, 2018, Sunoco LP completed the disposition of assets pursuant to the purchase agreement with 7-Eleven, Inc. (the “7-Eleven Transaction”). As a result of the 7-Eleven Transaction, previously eliminated wholesale motor fuel sales to Sunoco LP’s retail locations are reported as wholesale motor fuel sales to third parties.

In connection with the 7-Eleven Transaction, Sunoco LP entered into a 15-year take-or-pay fuel supply arrangement with 7-Eleven and SEI Fuel. For the period from January 1, 2018 through January 22, 2018, Sunoco LP recorded sales to the sites that were subsequently sold to 7-Eleven of $199 million, which sales were eliminated in consolidation.

The Partnership has concluded that it meets the accounting requirements for reporting the financial position, results of operations and cash flows of the 7-Eleven Transaction and the operations of the related assets as discontinued operations.

 

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There were no results of operations associated with discontinued operations for the years ended December 31, 2020 and 2019. The results of operations associated with discontinued operations for the year ended December 31, 2018 are presented in the following table:

 

     Year Ended
December 31, 2018
 

REVENUES

   $ 349

COSTS AND EXPENSES

  

Cost of products sold

     305

Operating expenses

     61

Selling, general and administrative

     7
  

 

 

 

Total costs and expenses

     373
  

 

 

 

OPERATING LOSS

     (24

OTHER EXPENSE

  

Interest expense, net

     2

Loss on extinguishment of debt

     20

Other, net

     61
  

 

 

 

LOSS FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE

     (107

Income tax expense

     158
  

 

 

 

LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES

   $ (265
  

 

 

 

 

4.

INVESTMENTS IN UNCONSOLIDATED AFFILIATES:

Citrus

We own CrossCountry Energy, LLC, a wholly-owned subsidiary of ETO, which in turn owns a 50% interest in Citrus. The other 50% interest in Citrus is owned by a subsidiary of KMI. Citrus owns 100% of FGT, an approximately 5,362-mile natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula. Our investment in Citrus is reflected in our interstate transportation and storage segment.

FEP

We have a 50% interest in FEP which owns the Fayetteville Express Pipeline, an approximately 185-mile natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline in Panola County, Mississippi. Our investment in FEP is reflected in the interstate transportation and storage segment.

MEP

We own a 50% interest in MEP, which owns the Midcontinent Express Pipeline, an approximately 500-miles natural gas pipeline that extends from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama. Our investment in MEP is reflected in the interstate transportation and storage segment.

White Cliffs

We own a 51% interest in White Cliffs, which was acquired by ET in the SemGroup acquisition and contributed to ETO in January 2020. White Cliffs consists of two parallel, 12-inch common carrier pipelines: one crude oil pipeline and one NGL pipeline. These pipelines transport crude and NGLs from

 

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Platteville, Colorado to Cushing, Oklahoma. The Partnership recorded an impairment of its investment in White Cliffs of $129 million during the year ended December 31, 2020 due to a decrease in projected future revenues and cash flows as a result of the overall market demand decline that occurred subsequent to the SemGroup acquisition and related purchase price allocation in December 2019.

The carrying values of the Partnership’s investments in unconsolidated affiliates as of December 31, 2020 and 2019 were as follows:

 

     December 31,  
     2020      2019  

Citrus

   $ 1,867    $ 1,876

FEP

     4      218

MEP

     406      429

White Cliffs

     274      436

Others

     504      495
  

 

 

    

 

 

 

Total

   $ 3,055    $ 3,454
  

 

 

    

 

 

 

The following table presents equity in earnings (losses) of unconsolidated affiliates:

 

     Years Ended December 31,  
     2020      2019      2018  

Citrus

   $ 162    $ 148    $ 141

FEP (1)

     (139      59      55

MEP

     (6      15      31

White Cliffs

     20      4      —    

Other

     82      76      117
  

 

 

    

 

 

    

 

 

 

Total equity in earnings of unconsolidated affiliates

   $ 119    $ 302    $ 344
  

 

 

    

 

 

    

 

 

 

 

  (1)

For the year ended December 31, 2020, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by FEP, which reduced the Partnership’s equity in earnings by $208 million.

Summarized Financial Information

The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, Citrus, FEP, MEP and White Cliffs (on a 100% basis) for all periods presented, except as noted below:

 

     December 31,  
     2020      2019  

Current assets

   $ 227    $ 247

Property, plant and equipment, net

     7,339      7,680

Other assets

     58      40
  

 

 

    

 

 

 

Total assets

   $ 7,624    $ 7,967
  

 

 

    

 

 

 

Current liabilities

   $ 600    $ 738

Non-current liabilities

     3,298      3,242

Equity

     3,726      3,987
  

 

 

    

 

 

 

Total liabilities and equity

   $ 7,624    $ 7,967
  

 

 

    

 

 

 

 

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     Years Ended December 31,  
     2020      2019      2018  

Revenue

   $ 1,243    $ 1,192    $ 1,249

Operating income

     6      683      723

Net income (loss)

     (199      443      460

In addition to the equity method investments described above we have other equity method investments which are not significant to our consolidated financial statements.

 

5.

DEBT OBLIGATIONS:

Our debt obligations consist of the following:

 

     December 31,  
     2020      2019  

ETO Debt

     

5.50% Senior Notes due February 15, 2020 (1)

   $ —      $ 250

5.75% Senior Notes due September 1, 2020 (1)

     —          400

4.15% Senior Notes due October 1, 2020 (1)

     —          1,050

7.50% Senior Notes due October 15, 2020 (1)

     —          1,135

4.40% Senior Notes due April 1, 2021 (2)

     600      600

4.65% Senior Notes due June 1, 2021 (2)

     800      800

5.20% Senior Notes due February 1, 2022

     1,000      1,000

4.65% Senior Notes due February 15, 2022

     300      300

5.875% Senior Notes due March 1, 2022

     900      900

5.00% Senior Notes due October 1, 2022

     700      700

3.45% Senior Notes due January 15, 2023

     350      350

3.60% Senior Notes due February 1, 2023

     800      800

4.25% Senior Notes due March 15, 2023

     995      995

4.20% Senior Notes due September 15, 2023

     500      500

4.50% Senior Notes due November 1, 2023

     600      600

5.875% Senior Notes due January 15, 2024

     1,127      1,127

4.90% Senior Notes due February 1, 2024

     350      350

7.60% Senior Notes due February 1, 2024

     277      277

4.25% Senior Notes due April 1, 2024

     500      500

4.50% Senior Notes due April 15, 2024

     750      750

9.00% Debentures due November 1, 2024

     65      65

4.05% Senior Notes due March 15, 2025

     1,000      1,000

2.90% Senior Notes due May 15, 2025

     1,000      —    

5.95% Senior Notes due December 1, 2025

     400      400

4.75% Senior Notes due January 15, 2026

     1,000      1,000

3.90% Senior Notes due July 15, 2026

     550      550

4.20% Senior Notes due April 15, 2027

     600      600

5.50% Senior Notes due June 1, 2027

     956      956

4.00% Senior Notes due October 1, 2027

     750      750

4.95% Senior Notes due June 15, 2028

     1,000      1,000

5.25% Senior Notes due April 15, 2029

     1,500      1,500

8.25% Senior Notes due November 15, 2029

     267      267

3.75% Senior Note due May 15, 2030

     1,500      —    

4.90% Senior Notes due March 15, 2035

     500      500

6.625% Senior Notes due October 15, 2036

     400      400

5.80% Senior Notes due June 15, 2038

     500      500

 

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7.50% Senior Notes due July 1, 2038

     550      550

6.85% Senior Notes due February 15, 2040

     250      250

6.05% Senior Notes due June 1, 2041

     700      700

6.50% Senior Notes due February 1, 2042

     1,000      1,000

6.10% Senior Notes due February 15, 2042

     300      300

4.95% Senior Notes due January 15, 2043

     350      350

5.15% Senior Notes due February 1, 2043

     450      450

5.95% Senior Notes due October 1, 2043

     450      450

5.30% Senior Notes due April 1, 2044

     700      700

5.15% Senior Notes due March 15, 2045

     1,000      1,000

5.35% Senior Notes due May 15, 2045

     800      800

6.125% Senior Notes due December 15, 2045

     1,000      1,000

5.30% Senior Notes due April 15, 2047

     900      900

5.40% Senior Notes due October 1, 2047

     1,500      1,500

6.00% Senior Notes due June 15, 2048

     1,000      1,000

6.25% Senior Notes due April 15, 2049

     1,750      1,750

5.00% Senior Notes due May 15, 2050

     2,000      —    

Floating Rate Junior Subordinated Notes due November 1, 2066

     546      546

ETO $2.00 billion Term Loan facility due October 2022

     2,000      2,000

ETO $5.00 billion Revolving Credit Facility due December 2023

     3,103      4,214

Unamortized premiums, discounts and fair value adjustments, net

     (17      (5

Deferred debt issuance costs

     (215      (207
  

 

 

    

 

 

 
     42,654      42,120
  

 

 

    

 

 

 

Transwestern Debt

     

5.36% Senior Notes due December 9, 2020 (1)

     —          175

5.89% Senior Notes due May 24, 2022

     150      150

5.66% Senior Notes due December 9, 2024

     175      175

6.16% Senior Notes due May 24, 2037

     75      75

Deferred debt issuance costs

     —          (1
  

 

 

    

 

 

 
     400      574
  

 

 

    

 

 

 

Panhandle Debt

     

7.60% Senior Notes due February 1, 2024

     82      82

7.00% Senior Notes due July 15, 2029

     66      66

8.25% Senior Notes due November 15, 2029

     33      33

Floating Rate Junior Subordinated Notes due November 1, 2066

     54      54

Unamortized premiums, discounts and fair value adjustments, net

     10      11
  

 

 

    

 

 

 
     245      246
  

 

 

    

 

 

 

Bakken Project Debt

     

3.625% Senior Notes due April 1, 2022

     650      650

3.90% Senior Notes due April 1, 2024

     1,000      1,000

4.625% Senior Notes due April 1, 2029

     850      850

Unamortized premiums, discounts and fair value adjustments, net

     (3      (3

Deferred debt issuance costs

     (13      (16
  

 

 

    

 

 

 
     2,484      2,481
  

 

 

    

 

 

 

 

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Sunoco LP Debt

     

4.875% Senior Notes Due January 15, 2023

     436      1,000

5.50% Senior Notes Due February 15, 2026

     800      800

6.00% Senior Notes Due April 15, 2027

     600      600

5.875% Senior Notes Due March 15, 2028

     400      400

4.50% Senior Notes due May 15, 2029

     800      —    

Sunoco LP $1.50 billion Revolving Credit Facility due July 2023

     —          162

Lease-related obligations

     103      135

Deferred debt issuance costs

     (27      (26
  

 

 

    

 

 

 
     3,112      3,071
  

 

 

    

 

 

 

USAC Debt

     

6.875% Senior Notes due April 1, 2026

     725      725

6.875% Senior Notes due September 1, 2027

     750      750

USAC $1.60 billion Revolving Credit Facility due April 2023

     474      403

Deferred debt issuance costs

     (22      (26
  

 

 

    

 

 

 
     1,927      1,852
  

 

 

    

 

 

 

SemGroup Debt

     

HFOTCO Tax Exempt Notes due 2050

     225      225

Energy Transfer Canada Revolver due February 25, 2024

     57      92

Energy Transfer Canada Term Loan A due February 25, 2024

     261      269

Unamortized premiums, discounts and fair value adjustments, net

     —          1

Deferred debt issuance costs

     (2      (3
  

 

 

    

 

 

 
     541      584
  

 

 

    

 

 

 

Other

     3      2
  

 

 

    

 

 

 

Total debt

     51,366      50,930

Less: Current maturities of long-term debt

     21      26
  

 

 

    

 

 

 

Long-term debt, less current maturities

   $ 51,345    $ 50,904
  

 

 

    

 

 

 

 

  (1)

As of December 31, 2019, these notes were classified as long-term as management had the intent and ability to refinance the borrowings on a long-term basis. The notes were redeemed in January 2020.

  (2)

As of December 31, 2020, these notes were classified as long-term as management had the intent and ability to refinance the borrowings on a long-term basis.

The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $289 million in unamortized net premiums, fair value adjustments and deferred debt issuance costs:

 

2021

   $ 1,420

2022

     5,731

2023

     7,287

2024

     4,598

2025

     2,408

Thereafter

     30,211
  

 

 

 

Total

   $ 51,655
  

 

 

 

 

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Long-term debt reflected on our consolidated balance sheets includes fair value adjustments related to interest rate swaps, which represent fair value adjustments that had been recorded in connection with fair value hedge accounting prior to the termination of the interest rate swap.

Notes and Debentures

ETO Senior Notes

The ETO senior notes were registered under the Securities Act of 1933 (as amended). The Partnership may redeem some or all of the ETO senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the ETO senior notes. The balance is payable upon maturity. Interest on the ETO senior notes is paid semi-annually.

The ETO senior notes are unsecured obligations of the Partnership and as a result, the ETO senior notes effectively rank junior to any future indebtedness of ours or our subsidiaries that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the ETO senior notes effectively rank junior to all indebtedness and other liabilities of our existing and future subsidiaries.

ETO January 2020 Senior Notes Offering and Redemption

On January 22, 2020, ETO completed a registered offering (the “January 2020 Senior Notes Offering”) of $1.00 billion aggregate principal amount of the Partnership’s 2.900% Senior Notes due 2025, $1.50 billion aggregate principal amount of the Partnership’s 3.750% Senior Notes due 2030 and $2.00 billion aggregate principal amount of the Partnership’s 5.000% Senior Notes due 2050, (collectively, the “Notes”). The Notes are fully and unconditionally guaranteed by the Partnership’s wholly-owned subsidiary, Sunoco Logistics Operations, on a senior unsecured basis.

Utilizing proceeds from the January 2020 Senior Notes Offering, ETO redeemed its $400 million aggregate principal amount of 5.75% Senior Notes due September 1, 2020, its $1.05 billion aggregate principal amount of 4.15% Senior Notes due October 1, 2020, its $1.14 billion aggregate principal amount of 7.50% Senior Notes due October 15, 2020, its $250 million aggregate principal amount of 5.50% Senior Notes due February 15, 2020, ET’s $52 million aggregate principal amount of 7.50% Senior Notes due October 15, 2020 and Transwestern’s $175 million aggregate principal amount of 5.36% Senior Notes due December 9, 2020.

Transwestern Senior Notes

The Transwestern senior notes are redeemable at any time in whole or pro rata, subject to a premium or upon a change of control event or an event of default, as defined. The balance is payable upon maturity. Interest is paid semi-annually.

Sunoco LP November 2020 Senior Notes Offering and Repurchase

On November 9, 2020, Sunoco LP completed a private offering of $800 million in aggregate principal amount of 4.500% senior notes due 2029. Sunoco LP used the proceeds to fund the tender offer on its 4.875% $1 billion senior notes due 2023. Approximately 56% of the 2023 senior notes were tendered. On January 15, 2021, Sunoco LP repurchased the remaining outstanding portion of its 2023 senior notes.

Credit Facilities, Term Loan and Commercial Paper

ETO Term Loan

On October 17, 2019, ETO entered into a term loan credit agreement (the “ETO Term Loan”) providing for a $2.00 billion three-year term loan credit facility. Borrowings under the term loan agreement mature on October 17, 2022 and are available for working capital purposes and for general partnership purposes. The term loan agreement is unsecured and is guaranteed by our subsidiary, Sunoco Logistics Operations.

 

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As of December 31, 2020, the ETO Term Loan had $2.00 billion outstanding and was fully drawn. The weighted average interest rate on the total amount outstanding as of December 31, 2020 was 1.15%.

ETO Five-Year Credit Facility

ETO’s revolving credit facility (the “ETO Five-Year Credit Facility”) allows for unsecured borrowings up to $5.00 billion and matures on December 1, 2023. The ETO Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to $6.00 billion under certain conditions.

As of December 31, 2020, the ETO Five-Year Credit Facility had $3.10 billion outstanding, of which $1.66 billion was commercial paper. The amount available for future borrowings was $1.79 billion after accounting for outstanding letters of credit in the amount of $109 million. The weighted average interest rate on the total amount outstanding as of December 31, 2020 was 1.12%.

ETO 364-Day Facility

ETO’s 364-day revolving credit facility (the “ETO 364-Day Facility”) allows for unsecured borrowings up to $1.00 billion and matures on November 26, 2021. As of December 31, 2020, the ETO 364-Day Facility had no outstanding borrowings.

Sunoco LP Credit Facility

Sunoco LP maintains a $1.50 billion revolving credit facility (the “Sunoco LP Credit Facility”). As of December 31, 2020, the Sunoco LP Credit Facility had no outstanding borrowings and $8 million in standby letters of credit. The amount available for future borrowings was $1.5 billion at December 31, 2020.

USAC Credit Facility

USAC maintains a $1.60 billion revolving credit facility (the “USAC Credit Facility”), which matures on April 2, 2023 and permits up to $400 million of future increases in borrowing capacity. As of December 31, 2020, USAC had $474 million of outstanding borrowings and no outstanding letters of credit under the credit agreement. As of December 31, 2020, USAC had $1.1 billion of availability under its credit facility. The weighted average interest rate on the total amount outstanding as of December 31, 2020 was 3.27%.

Energy Transfer Canada Credit Facilities

Energy Transfer Canada is party to a credit agreement providing for a C$350 million (US$275 million at the December 31, 2020 exchange rate) senior secured term loan facility, a C$525 million (US$412 million at the December 31, 2020 exchange rate) senior secured revolving credit facility, and a C$300 million (US$236 million at the December 31, 2020 exchange rate) senior secured construction loan facility (the “KAPS Facility”). The term loan facility and the revolving credit facility mature on February 25, 2024. The KAPS Facility matures on June 13, 2024. Energy Transfer Canada may incur additional term loans and revolving commitments in an aggregate amount not to exceed C$250 million (US$196 million at the December 31, 2020 exchange rate), subject to receiving commitments for such additional term loans or revolving commitments from either new lenders or increased commitments from existing lenders.

Covenants Related to Our Credit Agreements

Covenants Related to ETO

The agreements relating to the ETO senior notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions.

 

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The ETO Credit Facilities (defined as the ETO Term Loan, ETO Five-Year Credit Facility and ETO 364-Day Credit Facility) contain covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries’ ability to, among other things:

 

   

incur indebtedness;

 

   

grant liens;

 

   

enter into mergers;

 

   

dispose of assets;

 

   

make certain investments;

 

   

make Distributions (as defined in the ETO Credit Facilities) during certain Defaults (as defined in the ETO Credit Facilities) and during any Event of Default (as defined in the ETO Credit Facilities);

 

   

engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries;

 

   

engage in transactions with affiliates; and

 

   

enter into restrictive agreements.

The ETO Credit Facilities applicable margin and rate used in connection with the interest rates and commitment fees, respectively, are based on the credit ratings assigned to our senior, unsecured, non-credit enhanced long-term debt. The applicable margin for eurodollar rate loans under the ETO Five-Year Credit Facility ranges from 1.125% to 2.000% and the applicable margin for base rate loans ranges from 0.125% to 1.000%. The applicable rate for commitment fees under the ETO Five-Year Credit Facility ranges from 0.125% to 0.300%. The applicable margin for eurodollar rate loans under the ETO 364-Day Facility ranges from 1.500% to 2.000% and the applicable margin for base rate loans ranges from 0.500% to 1.000%. The applicable rate for commitment fees under the ETO 364-Day Facility ranges from 0.125% to 0.225%.

The ETO Credit Facilities contain various covenants including limitations on the creation of indebtedness and liens and related to the operation and conduct of our business. The ETO Credit Facilities also limit us, on a rolling four quarter basis, to a maximum Consolidated Funded Indebtedness to Consolidated EBITDA ratio, as defined in the underlying credit agreements, of 5.0 to 1, which can generally be increased to 5.5 to 1 during a Specified Acquisition Period. Our Leverage Ratio was 4.31 to 1 at December 31, 2020, as calculated in accordance with the credit agreements.

The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio.

Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Partnership’s or our subsidiaries’ ability to incur additional debt and/or our ability to pay distributions to Unitholders.

Covenants Related to Panhandle

Panhandle is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of Panhandle’s lending agreements.

Panhandle’s restrictive covenants include restrictions on liens securing debt and guarantees and restrictions on mergers and on the sales of assets. A breach of any of these covenants could result in acceleration of Panhandle’s debt.

 

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Covenants Related to Sunoco LP

The Sunoco LP Credit Facility contains various customary representations, warranties, covenants and events of default, including a change of control event of default, as defined therein. Sunoco LP’s Credit Facility requires Sunoco LP to maintain a Net Leverage Ratio of not more than 5.5 to 1. The maximum Net Leverage Ratio is subject to upwards adjustment of not more than 6.0 to 1 for a period not to exceed three fiscal quarters in the event Sunoco LP engages in certain specified acquisitions of not less than $50 million (as permitted under Sunoco LP’s Credit Facility agreement). The Sunoco LP Credit Facility also requires Sunoco LP to maintain an Interest Coverage Ratio (as defined in the Sunoco LP’s Credit Facility agreement) of not less than 2.25 to 1.

Covenants Related to USAC

The USAC Credit Facility contains covenants that limit (subject to certain exceptions) USAC’s ability to, among other things:

 

   

grant liens;

 

   

make certain loans or investments;

 

   

incur additional indebtedness or guarantee other indebtedness;

 

   

merge or consolidate;

 

   

sell our assets; or

 

   

make certain acquisitions.

The credit facility is also subject to the following financial covenants, including covenants requiring us to maintain:

 

   

a minimum EBITDA to interest coverage ratio of 2.5 to 1.0, determined as of the last day of each fiscal quarter; and

 

   

a maximum funded debt to EBITDA ratio, determined as of the last day of each fiscal quarter, for the annualized trailing three months of (i) 5.75 to 1 through the end of the fiscal quarter ending December 31, 2020 and (ii) 5.5 to 1 for the fiscal quarters ending March 31, 2021 and June 30, 2021, (iii) 5.25 to 1 for the fiscal quarters ending September 30, 2021 and December 31, 2021 and (iv) 5.0 to 1 thereafter, subject to a provision for increases to such thresholds, in the case of any fiscal quarter ending September 30, 2021 or thereafter, by 0.50 in connection with certain future acquisitions for the six consecutive month period following the period in which any such acquisition occurs, provided that, in any event, such ratio shall not exceed 5.5 to 1.

Covenants Related to the HFOTCO Tax Exempt Notes

The indentures covering HFOTCO’s tax exempt notes due 2050 (“IKE Bonds”) include customary representations and warranties and affirmative and negative covenants. Such covenants include limitations on the creation of new liens, indebtedness, making of certain restricted payments and payments on indebtedness, making certain dispositions, making material changes in business activities, making fundamental changes including liquidations, mergers or consolidations, making certain investments, entering into certain transactions with affiliates, making amendments to certain credit or organizational agreements, modifying the fiscal year, creating or dealing with hazardous materials in certain ways, entering into certain hedging arrangements, entering into certain restrictive agreements, funding or engaging in sanctioned activities, taking actions or causing the trustee to take actions that materially adversely affect the rights, interests, remedies or security of the bondholders, taking actions to remove the trustee, making certain amendments to the bond documents, and taking actions or omitting to take actions that adversely impact the tax exempt status of the IKE Bonds.

 

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Compliance with our Covenants

We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2020.

 

6.

REDEEMABLE NONCONTROLLING INTERESTS

Certain redeemable noncontrolling interests in the Partnership’s subsidiaries are reflected as mezzanine equity on the consolidated balance sheet. Redeemable noncontrolling interests as of December 31, 2020 included a balance of $477 million related to the USAC Preferred Units described below and a balance of $15 million related to noncontrolling interest holders in one of the Partnership’s consolidated subsidiaries that have the option to sell their interests to the Partnership. In addition, redeemable noncontrolling interests includes a balance of $270 million in Energy Transfer Canada preferred shares contributed by ET subsequent to its acquisition of SemGroup.

USAC Series A Preferred Units

In 2018, USAC issued 500,000 USAC Preferred Units in a private placement at a price of $1,000 per USAC Preferred Unit, for total gross proceeds of $500 million in a private placement.

The USAC Preferred Units are entitled to receive cumulative quarterly distributions equal to $24.375 per USAC Preferred Unit, subject to increase in certain limited circumstances. The USAC Preferred Units will have a perpetual term, unless converted or redeemed. Certain portions of the USAC Preferred Units will be convertible into USAC common units at the election of the holders beginning in 2021. To the extent the holders of the USAC Preferred Units have not elected to convert their preferred units by the fifth anniversary of the issue date, USAC will have the option to redeem all or any portion of the USAC Preferred Units for cash. In addition, at any time on or after the tenth anniversary of the issue date, the holders of the USAC Preferred Units will have the right to require USAC to redeem all or any portion of the USAC Preferred Units, and the Partnership may elect to pay up to 50% of such redemption amount in USAC common units.

Energy Transfer Canada Redeemable Preferred Stock

Energy Transfer Canada has 300,000 shares of cumulative preferred stock issued and outstanding. The preferred stock is redeemable at Energy Transfer Canada’s option subsequent to January 3, 2021 at a redemption price of C$1,100 (US$864 at the December 31, 2020 exchange rate) per share. The preferred stock is redeemable by the holder contingent upon a change of control or liquidation of Energy Transfer Canada. The preferred stock is convertible to Energy Transfer Canada common shares in the event of an initial public offering by Energy Transfer Canada.

The preferred stock was recorded at fair value in connection with the SemGroup purchase accounting. Dividends on the preferred stock are payable in-kind through the quarter ending June 30, 2020. The dividends paid-in-kind increased the liquidation preference such that as of December 31, 2020, the preferred stock was convertible into 344,419 shares.

 

7.

EQUITY:

Limited Partner interests are represented by Common Units and other classes of units described below, as well as Series A Preferred Units, Series B Preferred Units, Series C Preferred Units, Series D Preferred Units, Series E Preferred Units, Series F Preferred Units, and Series G Preferred Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. No person is entitled to preemptive rights in respect of issuances of equity securities by us, except that ETP GP has the right, in connection with the issuance of any equity security by us, to purchase equity securities on the same terms as

 

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equity securities are issued to third parties sufficient to enable ETP GP and its affiliates to maintain the aggregate percentage equity interest in us as ETP GP and its affiliates owned immediately prior to such issuance.

Class K Units

As of December 31, 2020, a total of 101.5 million Class K Units were held by wholly-owned subsidiaries of ETO. Each Class K Unit is entitled to a quarterly cash distribution of $0.67275 per Class K Unit prior to ETO making distributions of available cash to any class of units, excluding any cash available distributions or dividends or capital stock sales proceeds received by ETO from ETP Holdco. If the Partnership is unable to pay the Class K Unit quarterly distribution with respect to any quarter, the accrued and unpaid distributions will accumulate until paid and any accumulated balance will accrue 1.5% per annum until paid.

Class L Units

On December 31, 2018, ETO issued a new class of limited partner interests titled Class L Units to two wholly-owned subsidiaries of the Partnership when the Partnership’s previously outstanding Class E units and Class G units held by such subsidiaries were converted into Class L Units. As a result of the conversion, the Class E units and Class G units were cancelled.

The Class L Units generally do not have any voting rights. The Class L Units are entitled to aggregate cash distributions equal to 7.65% per annum of the total amount of cash generated by us and our subsidiaries, other than ETP Holdco, and available for distribution. Distributions shall be paid quarterly, in arrears, within 45 days after the end of each quarter. As the Class L Units are owned by a wholly-owned subsidiary, the cash distributions on those units are eliminated in our consolidated financial statements.

Class M Units

On July 1, 2019, ETO issued a new class of limited partner interests titled Class M Units to ETP Holdco, a wholly-owned subsidiary of the Partnership, in exchange for the contribution of ETP Holdco’s equity ownership interest in Panhandle to the Partnership.

The Class M Units generally do not have any voting rights. The Class M Units are entitled to aggregate cash distributions equal to 8.00% per annum of the total amount of cash generated by us and our subsidiaries, other than ETP Holdco, and available for distribution. Distributions shall be paid quarterly, in arrears, within 45 days after the end of each quarter. As the Class M Units are owned by a wholly-owned subsidiary, the cash distributions on those units are eliminated in our consolidated financial statements.

Class N Units

In April and May, 2020, ETO issued a new class of limited partner interests titles Class N Units in connection with a series of internal transactions to simplify its capital structure. All of the Class N Units are held by ETP Holdco.

The Class N Units generally do not have any voting rights. each Class N Unit is entitled to a quarterly cash distribution of $0.2375 per Class N Unit prior to ETO making distributions of available cash to any class of units, excluding any cash available distributions or dividends or capital stock sales proceeds received by ETO from ETP Holdco. Distributions shall be paid quarterly, in arrears, within 45 days after the end of each quarter. If the Partnership is unable to pay the Class N Unit quarterly distribution with respect to any quarter, the accrued and unpaid distributions will accumulate until paid and any accumulated balance will accrue 1.5% per annum until paid. As the Class N Units are owned by a wholly-owned subsidiary, the cash distributions on those units are eliminated in our consolidated financial statements.

 

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ETO Preferred Units

As of December 31, 2020 and 2019, our outstanding preferred units included 950,000 Series A Preferred Units, 550,000 Series B Preferred Units, 18,000,000 Series C Preferred Units, 17,800,000 Series D Preferred Units and 32,000,000 Series E Preferred Units. As of December 31, 2020, our outstanding preferred units also included 500,000 Series F Preferred Units and 1,100,000 Series G Preferred Units.

The following table summarizes changes in the amounts of our Series A, Series B, Series C, Series D, Series E, Series F and Series G preferred units for the years ended December 31, 2020, 2019 and 2018 were as follows:

 

     Preferred Unitholders  
     Series A     Series B     Series C     Series D     Series E     Series F     Series G     Total  

Balance, December 31, 2017

   $ 944   $ 547   $ —     $ —     $ —     $ —     $ —     $ 1,491

Distributions to partners

     (44     (27     (18     (11     —         —         —         (100

Units issued for cash

     —         —         436     431     —         —         —         867

Other, net

     (1     —         (1     (1     —         —         —         (3

Net income

     59     36     23     15     —         —         —         133
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance, December 31, 2018

     958     556     440     434     —         —         —         2,388

Distributions to partners

     (59     (37     (33     (34     (34     —         —         (197

Units issued for cash

     —         —         —         —         780     —         —         780

Other, net

     —         —         —         —         (1     —         —         (1

Net income

     59     37     33     34     41     —         —         204
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance, December 31, 2019

     958     556     440     434     786     —         —         3,174

Distributions to partners

     (59     (37     (33     (34     (61     (27     (64     (315

Units issued for cash

     —         —         —         —         —         494     1,086     1,580

Other, net

     —         —         —         —         —         (2     (2     (4

Net income

     59     37     33     34     61     31     74     329
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance, December 31, 2020

   $ 958   $ 556   $ 440   $ 434   $ 786   $ 496   $ 1,094   $ 4,764
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

ETO Series A Preferred Units

Distributions on the Series A Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2023, at a rate of 6.250% per annum of the stated liquidation preference of $1,000. On and after February 15, 2023, distributions on the Series A Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.028% per annum. The Series A Preferred Units are redeemable at ETO’s option on or after February 15, 2023 at a redemption price of $1,000 per Series A Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

ETO Series B Preferred Units

Distributions on the Series B Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2028, at a rate of 6.625% per annum of the stated liquidation preference of $1,000. On and after February 15, 2028, distributions on the Series B Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.155% per annum. The Series B Preferred Units are redeemable at ETO’s option on or after February 15, 2028 at a redemption price of $1,000 per Series B Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

 

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ETO Series C Preferred Units

Distributions on the Series C Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, May 15, 2023, at a rate of 7.375% per annum of the stated liquidation preference of $25. On and after May 15, 2023, distributions on the Series C Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.530% per annum. The Series C Preferred Units are redeemable at ETO’s option on or after May 15, 2023 at a redemption price of $25 per Series C Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

ETO Series D Preferred Units

Distributions on the Series D Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, August 15, 2023, at a rate of 7.625% per annum of the stated liquidation preference of $25. On and after August 15, 2023, distributions on the Series D Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.738% per annum. The Series D Preferred Units are redeemable at ETO’s option on or after August 15, 2023 at a redemption price of $25 per Series D Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

ETO Series E Preferred Units

Distributions on the Series E Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, May 15, 2024, at a rate of 7.600% per annum of the stated liquidation preference of $25. On and after May 15, 2024, distributions on the Series E Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 5.161% per annum. The Series E Preferred Units are redeemable at ETO’s option on or after May 15, 2024 at a redemption price of $25 per Series E Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

ETO Series F Preferred Units

On January 22, 2020, the Partnership issued 500,000 of its 6.750% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units representing limited partner interest in the Partnership, at a price to the public of $1,000 per unit. Distributions on the Series F Preferred Units are cumulative from and including the original issue date and will be payable semi-annually in arrears on the 15th day of May and November of each year, commencing on May 15, 2020 to, but excluding, May 15, 2025, at a rate equal to 6.750% per annum of the $1,000 liquidation preference. On and after May 15, 2025, the distribution rate on the Series F Preferred Units will equal a percentage of the $1,000 liquidation preference equal to the five-year U.S. treasury rate plus a spread of 5.134% per annum. The Series F Preferred Units are redeemable at ETO’s option on or after May 15, 2025 at a redemption price of $1,000 per Series F Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

ETO Series G Preferred Units

On January 22, 2020, the Partnership issued 1,100,000 of its 7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units representing limited partner interest in the Partnership, at a price to the public of $1,000 per unit. Distributions on the Series G Preferred Units are cumulative from and including the original issue date and will be payable semi-annually in arrears on the 15th day of May and November of each year, commencing on May 15, 2020 to, but excluding, May 15, 2030, at a rate equal to 7.125% per annum of the $1,000 liquidation preference. On and after May 15, 2030, the distribution rate on

 

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the Series G Preferred Units will equal a percentage of the $1,000 liquidation preference equal to the five-year U.S. treasury rate plus a spread of 5.306% per annum. The Series G Preferred Units are redeemable at ETO’s option on or after May 15, 2030 at a redemption price of $1,000 per Series G Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

Subsidiary Equity Transactions

Sunoco LP’s Equity Distribution Program

Sunoco LP is party to an equity distribution agreement for an at-the-market (“ATM”) offering pursuant to which Sunoco LP may sell its common units from time to time. For the years ended December 31, 2020, 2019 and 2018, Sunoco LP issued no units under its ATM program. As of December 31, 2020, $295 million of Sunoco LP common units remained available to be issued under the currently effective equity distribution agreement.

USAC’s Distribution Reinvestment Program

During the year ended December 31, 2020 and 2019, distributions of $1.9 million and $1 million, respectively, were reinvested under the USAC distribution reinvestment program resulting in the issuance of approximately 188,695 and 60,584 USAC common units, respectively.

USAC’s Warrant Private Placement

On April 2, 2018, USAC issued two tranches of warrants to purchase USAC common units (the “USAC Warrants”), which included USAC Warrants to purchase 5,000,000 common units with a strike price of $17.03 per unit and USAC Warrants to purchase 10,000,000 common units with a strike price of $19.59 per unit. The USAC Warrants may be exercised by the holders thereof at any time beginning on the one year anniversary of the closing date and before the tenth anniversary of the closing date. Upon exercise of the USAC Warrants, USAC may, at its option, elect to settle the USAC Warrants in common units on a net basis.

USAC’s Class B Units

The USAC Class B Units, all of which are owned by ETO, are a new class of partnership interests of USAC that have substantially all of the rights and obligations of a USAC common unit, except the USAC Class B Units will not participate in distributions for the first four quarters following the closing date of the USAC Transaction on April 2, 2018. Each USAC Class B Unit automatically converted into one USAC common unit on the first business day following the record date attributable to the quarter ending June 30, 2019.

On July 30, 2019, the 6,397,965 USAC Class B units held by the Partnership converted into 6,397,965 common units representing limited partner interests in USAC. These common units participate in distributions declared by USAC.

 

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Cash Distributions

ETO Preferred Unit Distributions

Distributions on the ETO’s Series A, Series B, Series C, Series D and Series E preferred units declared and/or paid by ETO were as follows:

 

Period Ended

 

Record Date

 

Payment Date

  Series A (1)     Series B (1)     Series C     Series D     Series E     Series F (1)     Series G (1)  

June 30, 2018

  August 1, 2018   August 15, 2018   $ 31.2500   $ 33.1250   $ 0.5634   $ —     $ —     $ —     $ —  

September 30, 2018

  November 1, 2018   November 15, 2018     —         —         0.4609     0.5931     —         —         —    

December 31, 2018

  February 1, 2019   February 15, 2019     31.2500     33.1250     0.4609     0.4766     —         —         —    

March 31, 2019

  May 1, 2019   May 15, 2019     —         —         0.4609     0.4766     —         —         —    

June 30, 2019

  August 1, 2019   August 15, 2019     31.2500     33.1250     0.4609     0.4766     0.5806     —         —    

September 30, 2019

  November 1, 2019   November 15, 2019     —         —         0.4609     0.4766     0.4750     —         —    

December 31, 2019

  February 3, 2020   February 18, 2020     31.2500     33.1250     0.4609     0.4766     0.4750     —         —    

March 31, 2020

  May 1, 2020   May 15, 2020     —         —         0.4609     0.4766     0.4750     21.19     22.36

June 30, 2020

  August 3, 2020   August 17, 2020     31.2500     33.1250     0.4609     0.4766     0.4750     —         —    

September 30, 2020

  November 2, 2020   November 15, 2020     —         —         0.4609     0.4766     0.4750     33.75     35.625

December 31, 2020

  February 1, 2021   February 16, 2021     31.2500     33.1250     0.4609     0.4766     0.4750     —         —    

 

*

Represent prorated initial distributions.

(1) 

ETO Series A Preferred Unit, ETO Series B Preferred Unit, ETO Series F Preferred Unit and ETO Series G Preferred Unit distributions are paid on a semi-annual basis.

Sunoco LP Cash Distributions

The following table illustrates the percentage allocations of available cash from operating surplus between Sunoco LP’s common unitholders and the holder of its IDRs based on the specified target distribution levels, after the payment of distributions to Class C unitholders. The amounts set forth under “marginal percentage interest in distributions” are the percentage interests of the IDR holder and the common unitholders in any available cash from operating surplus which Sunoco LP distributes up to and including the corresponding amount in the column “total quarterly distribution per unit target amount.” The percentage interests shown for common unitholders and IDR holder for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

 

          Marginal Percentage
Interest in Distributions
 
     Total Quarterly Distribution
Target Amount
   Common
Unitholders
    Holder of
IDRs
 

Minimum Quarterly Distribution

   $0.4375      100     —  

First Target Distribution

   $0.4375 to $0.503125      100     —  

Second Target Distribution

   $0.503125 to $0.546875      85     15

Third Target Distribution

   $0.546875 to $0.656250      75     25

Thereafter

   Above $0.656250      50     50

 

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Distributions on Sunoco LP’s units declared and/or paid by Sunoco LP were as follows:

 

Quarter Ended

  

Record Date

  

Payment Date

  

Rate

 

December 31, 2017

   February 6, 2018    February 14, 2018    $ 0.8255

March 31, 2018

   May 7, 2018    May 15, 2018      0.8255

June 30, 2018

   August 7, 2018    August 15, 2018      0.8255

September 30, 2018

   November 6, 2018    November 14, 2018      0.8255

December 31, 2018

   February 6, 2019    February 14, 2019      0.8255

March 31, 2019

   May 7, 2019    May 15, 2019      0.8255

June 30, 2019

   August 6, 2019    August 14, 2019      0.8255

September 30, 2019

   November 5, 2019    November 19, 2019      0.8255

December 31, 2019

   February 7, 2020    February 19, 2020      0.8255

March 31, 2020

   May 7, 2020    May 19, 2020      0.8255

June 30, 2020

   August 7, 2020    August 19, 2020      0.8255

September 30, 2020

   November 6, 2020    November 19, 2020      0.8255

December 31, 2020

   February 8, 2021    February 19, 2021      0.8255

USAC Cash Distributions

Subsequent to the Energy Transfer Merger and USAC Transactions described in Note 1 and Note 3, respectively, ETO owned approximately 39.7 million USAC common units and 6.4 million USAC Class B units. Subsequent to the conversion of the USAC Class B Units to USAC common units on July 30, 2019, ETO owns approximately 46.1 million USAC common units. As of December 31, 2020, USAC had approximately 97.0 million common units outstanding. USAC currently has a non-economic general partner interest and no outstanding IDRs.

Distributions on USAC’s units declared and/or paid by USAC subsequent to the USAC transaction on April 2, 2018 were as follows:

 

Quarter Ended

  

Record Date

  

Payment Date

  

Rate

 

March 31, 2018

   May 1, 2018    May 11, 2018    $ 0.5250

June 30, 2018

   July 30, 2018    August 10, 2018      0.5250

September 30, 2018

   October 29, 2018    November 9, 2018      0.5250

December 31, 2018

   January 28, 2019    February 8, 2019      0.5250

March 31, 2019

   April 29, 2019    May 10, 2019      0.5250

June 30, 2019

   July 29, 2019    August 9, 2019      0.5250

September 30, 2019

   October 28, 2019    November 8, 2019      0.5250

December 31, 2019

   January 27, 2020    February 7, 2020      0.5250

March 31, 2020

   April 27, 2020    May 8, 2020      0.5250

June 30, 2020

   July 31, 2020    August 10, 2020      0.5250

September 30, 2020

   October 26, 2020    November 6, 2020      0.5250

December 31, 2020

   January 25, 2021    February 5, 2021      0.5250

 

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Accumulated Other Comprehensive Income

The following table presents the components of AOCI, net of tax:

 

     December 31,  
     2020      2019  

Available-for-sale securities

   $ 18    $ 13

Foreign currency translation adjustment

     7      (5

Actuarial loss related to pensions and other postretirement benefits

     (7      (25

Investments in unconsolidated affiliates, net

     (14      (1
  

 

 

    

 

 

 

Subtotal

     4      (18

Amounts attributable to noncontrolling interest

     2      —    
  

 

 

    

 

 

 

Total AOCI, net of tax

   $ 6    $ (18
  

 

 

    

 

 

 

The table below sets forth the tax amounts included in the respective components of other comprehensive income:

 

     December 31,  
     2020      2019  

Available-for-sale securities

   $ (1    $ (1

Foreign currency translation adjustment

     8      2

Actuarial loss relating to pension and other postretirement benefits

     3      8
  

 

 

    

 

 

 

Total

   $ 10    $ 9
  

 

 

    

 

 

 

 

8.

NON-CASH COMPENSATION PLANS:

ETO Long-Term Incentive Plan

We have previously issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase ETO Common Units, restricted units, phantom units, distribution equivalent rights (“DERs”), Common Unit appreciation rights, and other unit-based awards.

The Partnership does not currently have any equity compensation plans. In connection with the Energy Transfer Merger in October 2018, all of the Partnership’s equity compensation plans, as well as the Partnership’s obligations under those plans, were assumed by ET. The Partnership recorded stock compensation expense of $121 million, $113 million, and $105 million for the years ended December 31, 2020, 2019 and 2018, respectively.

Subsidiary Long-Term Incentive Plans

Each of Sunoco LP and USAC has granted restricted or phantom unit awards (collectively, the “Subsidiary Unit Awards”) to employees and directors that entitle the grantees to receive common units of the respective subsidiary. In some cases, at the discretion of the respective subsidiary’s compensation committee, the grantee may instead receive an amount of cash equivalent to the value of common units upon vesting. Substantially all of the Subsidiary Unit Awards are time-vested grants, which generally vest over a three or five-year period, that entitles the grantees of the unit awards to receive an amount of cash equal to the per unit cash distributions made by the respective subsidiaries during the period the restricted unit is outstanding.

 

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The following table summarizes the activity of the Subsidiary Unit Awards:

 

     Sunoco LP      USAC  
     Number of
Units
     Weighted
Average
Grant-Date
Fair Value
Per Unit
     Number of
Units
     Weighted
Average
Grant-Date
Fair Value
Per Unit
 

Unvested awards as of December 31, 2019

     2.1    $ 29.21      1.8    $ 15.09

Awards granted

     0.7      28.63      0.7      12.55

Awards vested

     (0.5      30.47      (0.2      17.27

Awards forfeited

     (0.2      29.11      (0.2      15.36
  

 

 

       

 

 

    

Unvested awards as of December 31, 2020

     2.1      28.63      2.1      14.88
  

 

 

       

 

 

    

The following table summarizes the weighted average grant-date fair value per unit award granted:

 

     Years Ended December 31,  
     2020      2019      2018  

Sunoco LP

   $ 28.63    $ 30.70    $ 27.67

USAC

     12.55      15.88      15.47

The total fair value of Subsidiary Unit Awards vested for the years ended December 31, 2020, 2019 and 2018 was $16 million, $17 million and $22 million, respectively, based on the market price of Sunoco LP and USAC common units as of the vesting date for the years ended December 31, 2020, 2019 and 2018. As of December 31, 2020, estimated compensation cost related to Subsidiary Unit Awards not yet recognized was $39 million, and the weighted average period over which this cost is expected to be recognized in expense is 3.6 years.

 

9.

INCOME TAXES:

As a partnership, we are not subject to United States federal income tax and most state income taxes. However, the Partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax expense (benefit) of our taxable subsidiaries were summarized as follows:

 

     Years Ended December 31,  
     2020      2019      2018  

Current expense (benefit):

        

Federal

   $ (6    $ (20    $ (7

State

     32      (2      20

Foreign

     1      —          —    
  

 

 

    

 

 

    

 

 

 

Total

     27      (22      13

Deferred expense (benefit):

        

Federal

     178      176      183

State

     41      45      (191

Foreign

     (7      —          —    
  

 

 

    

 

 

    

 

 

 

Total

     212      221      (8
  

 

 

    

 

 

    

 

 

 

Total income tax expense

   $ 239    $ 199    $ 5
  

 

 

    

 

 

    

 

 

 

Historically, our effective tax rate has differed from the statutory rate primarily due to Partnership earnings that are not subject to United States federal and most state income taxes at the partnership level. A

 

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reconciliation of income tax expense at the United States statutory rate to the Partnership’s income tax benefit for the years ended December 31, 2020, 2019 and 2018 is as follows:

 

     Years Ended December 31,  
     2020      2019      2018  

Income tax expense at United States statutory rate

   $ 116    $ 1,116    $ 861

Increase (reduction) in income taxes resulting from:

        

Partnership earnings not subject to tax

     54      (925      (730

Noncontrolling interests

     16      —          —    

State income taxes (net of federal income tax effects)

     58      14      (125

Dividend received deduction

     —          (3      (5

Foreign

     (7      —          —    

Other

     2      (3      4
  

 

 

    

 

 

    

 

 

 

Income tax expense

   $ 239    $ 199    $ 5
  

 

 

    

 

 

    

 

 

 

Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows:

 

     December 31,  
     2020      2019  

Deferred income tax assets:

     

Net operating losses, alternative minimum tax credit and other carryforwards

   $ 1,047    $ 936

Pension and other postretirement benefits

     —          7

Other

     34      85
  

 

 

    

 

 

 

Total deferred income tax assets

     1,081      1,028

Valuation allowance

     (134      (95
  

 

 

    

 

 

 

Net deferred income tax assets

   $ 947    $ 933
  

 

 

    

 

 

 

Deferred income tax liabilities:

     

Property, plant and equipment

   $ (263    $ (464

Investments in affiliates

     (3,994      (3,547

Trademarks

     (77      (72

Other

     (5      (21
  

 

 

    

 

 

 

Total deferred income tax liabilities

     (4,339      (4,104
  

 

 

    

 

 

 

Net deferred income taxes

   $ (3,392    $ (3,171
  

 

 

    

 

 

 

As of December 31, 2020, ETP Holdco had a federal net operating loss carryforward of $3.73 billion, of which $1.3 billion will expire in 2031 through 2037 while the remaining can be carried forward indefinitely. A total of $787 million of the federal net operating loss carryforward is limited under IRC §382. Although we expect to fully utilize the IRC §382 limited federal net operating loss, the amount utilized in a particular year may be limited. As of December 31, 2020, Sunoco Property Company LLC, a corporate subsidiary of Sunoco LP, had a state net operating loss carrryforward of $121 million, which we expect to fully utilize. Sunoco Property Company LLC has no federal net operating loss carryforward.

Our corporate subsidiaries have state net operating loss carryforward benefits of $174 million, net of federal tax, some of which will expire between 2021 and 2039, while others are carried forward indefinitely. Our corporate subsidiaries have Canadian net operating losses of $7 million that will begin to expire in 2033. Our corporate subsidiaries have cumulative excess business interest expense of $129 million available for carryforward indefinitely. A valuation allowance of $89 million is applicable to the state net operating loss

 

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carryforward benefits primarily attributable to significant restrictions on their use in the Commonwealth of Pennsylvania. A separate valuation allowance of $45 million is attributable to foreign tax credits.

The following table sets forth the changes in unrecognized tax benefits:

 

     Years Ended December 31,  
     2020      2019      2018  

Balance at beginning of year

   $ 94    $ 624    $ 609

Additions attributable to tax positions taken in the current year

     —          —          8

Additions attributable to tax positions taken in prior years

     —          11      7

Reduction attributable to tax positions taken in prior years

     —          (541      —    

Lapse of statute

     (4      —          —    
  

 

 

    

 

 

    

 

 

 

Balance at end of year

   $ 90    $ 94    $ 624
  

 

 

    

 

 

    

 

 

 

As of December 31, 2020, we have $90 million ($48 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate.

Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2020, we recognized interest and penalties of $7 million. At December 31, 2020, we have interest and penalties accrued of $10 million, net of tax.

We appealed the adverse Court of Federal Claims decision against ETC Sunoco regarding the IRS’ denial of ethanol blending credits claims under Section 6426 to the Federal Circuit. The Federal Circuit affirmed the CFC’s denial on November 1, 2018. ETC Sunoco filed a petition for certiorari with the Supreme Court on May 24, 2019 to review the Federal Circuit’s affirmation of the CFC’s ruling, and the Court denied Sunoco’s petition on October 7, 2019. The petition for certiorari applied to ETC Sunoco’s 2004 through 2009 tax years, and 2010 through 2011 remained on extension with the IRS through September 28, 2020. We filed a petition for the 2010 and 2011 years in the Federal District Court for the Northern District of Texas on September 25, 2020. Due to the uncertainty surrounding the litigation, a reserve of $530 million was previously established for the full amount of the pending refund claims, and the receivable and reserve for this issue were netted in the consolidated balance sheet. Subsequent to the Supreme Court’s denial of the petition in October 2019, the receivable and reserve have been reversed, with no impact to the Partnership’s financial position and results of operations.

In November 2015, the Pennsylvania Commonwealth Court determined in Nextel Communications v. Commonwealth (“Nextel”) that the Pennsylvania limitation on NOL carryforward deductions violated the uniformity clause of the Pennsylvania Constitution and struck the NOL limitation in its entirety. In October 2017, the Pennsylvania Supreme Court affirmed the decision with respect to the uniformity clause violation; however, the Court reversed with respect to the remedy and instead severed the flat-dollar limitation, leaving the percentage-based limitation intact. Nextel subsequently filed a petition for writ of certiorari with the United States Supreme Court, and this was denied on June 11, 2018. Now certain Pennsylvania taxpayers are proceeding with litigation in Pennsylvania state courts on issues not addressed by the Pennsylvania Supreme Court in Nextel, specifically, whether the Due Process and Equal Protection Clauses of the United States Constitution and the Remedies Clause of the Pennsylvania Constitution require a court to grant the taxpayer relief. ETC Sunoco has recognized approximately $67 million ($53 million after federal income tax benefits) in tax benefit based on previously filed tax returns and certain previously filed tax returns and certain previously filed protective claims as relates to its cases currently held pending the Nextel matter. However, based upon the Pennsylvania Supreme Court’s October 2017 decision, and because of uncertainty in the breadth of the application of the decision, we have reserved $34 million ($27 million after federal income tax benefits) against the receivable.

In general, ETO and its subsidiaries are no longer subject to examination by the IRS, and most state jurisdictions, for the 2014 and prior tax years.

 

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ETO and its subsidiaries also have various state and local income tax returns in the process of examination or administrative appeal in various jurisdictions. We believe the appropriate accruals or unrecognized tax benefits have been recorded for any potential assessment with respect to these examinations.

 

10.

REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:

FERC Proceedings

By order issued January 16, 2019, the FERC initiated a review of Panhandle’s existing rates pursuant to Section 5 of the Natural Gas Act (“NGA”) to determine whether the rates currently charged by Panhandle are just and reasonable and set the matter for hearing. On August 30, 2019, Panhandle filed a general rate proceeding under Section 4 of the NGA. The Natural Gas Act Section 5 and Section 4 proceedings were consolidated by the order of the Chief Judge dated October 1, 2019. A hearing in the combined proceedings commenced on August 25, 2020 and adjourned on September 15, 2020. By an order dated January 19, 2021, the Chief Judge has extended the deadline for the initial decision to March 2021.

Commitments

In the normal course of business, ETO purchases, processes and sells natural gas pursuant to long-term contracts and enters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. ETO believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on its financial position or results of operations.

Our joint venture agreements require that we fund our proportionate share of capital contributions to its unconsolidated affiliates. Such contributions will depend upon our unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.

We have certain non-cancelable rights-of-way (“ROW”) commitments, which require fixed payments and either expire upon our chosen abandonment or at various dates in the future. The table below reflects ROW expense included in operating expenses in the accompanying statements of operations:

 

     Years Ended December 31,  
     2020      2019      2018  

ROW expense

   $ 47    $ 45    $ 46

PES Refinery Fire and Bankruptcy

We previously owned an approximately 7.4% indirect non-operating interest in PES, which owned a former refinery in Philadelphia. In addition, the Partnership previously provided logistics services to PES under commercial contracts and Sunoco LP previously purchased refined products from PES. In June 2019, an explosion and fire occurred at the refinery complex.

On July 21, 2019, PES Holdings, LLC and seven of its subsidiaries (collectively, the “Debtors”) filed voluntary petitions in the United States Bankruptcy Court for the District of Delaware seeking relief under the provisions of Chapter 11 of the United States Bankruptcy Code, as a result of the explosion and fire at the Philadelphia refinery complex. The Debtors have also defaulted on a $75 million note payable to a subsidiary of the Partnership. In June 2020, the Partnership received $12 million from PES on the note payable and recorded a reserve for the remaining $63 million note balance.

In addition, the Partnership’s subsidiaries retained certain environmental remediation liabilities when the refinery was sold to PES. As of December 31, 2020, the Partnership has funded these environmental remediation liabilities through its wholly-owned captive insurance company, based upon actuarially determined estimates for such costs, and these liabilities are included in the total environmental liabilities

 

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discussed below under “Environmental Remediation.” It may be necessary for the Partnership to record additional environmental remediation liabilities in the future depending upon the use of such property by the buyer; however, management is not currently able to estimate such additional liabilities.

PES has rejected certain of the Partnership’s commercial contracts pursuant to Section 365 of the Bankruptcy Code; however, the impact of the bankruptcy on the Partnership’s commercial contracts and related revenue loss (temporary or permanent) is unknown at this time. In addition, Sunoco LP has been successful at acquiring alternative supplies to replace fuel volume lost from PES and does not anticipate any material impact to its business going forward.

Litigation and Contingencies

We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and crude oil are flammable and combustible. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.

We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.

As of December 31, 2020 and 2019, accruals of approximately $77 million and $120 million, respectively, were reflected on our consolidated balance sheets related to contingent obligations that met both the probable and reasonably estimable criteria. In addition, we may recognize additional contingent losses in the future related to (i) contingent matters for which a loss is currently considered reasonably possible but not probable and/or (ii) losses in excess of amounts that have already been accrued for such contingent matters. In some of these cases, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. For such matters where additional contingent losses can be reasonably estimated, the range of additional losses is estimated to be up to approximately $80 million.

The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts or our estimates of reasonably possible losses prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.

Dakota Access Pipeline

On July 27, 2016, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia (“District Court”) that challenged permits issued by the United States Army Corps of Engineers (“USACE”) that allowed Dakota Access, LLC (“Dakota Access”) to cross the Missouri River at Lake Oahe in North Dakota. The case was subsequently amended to challenge an easement issued by the USACE that allowed the pipeline to cross land owned by the USACE adjacent to the Missouri River. Dakota Access and the Cheyenne River Sioux Tribe (“CRST”) intervened. Separate

 

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lawsuits filed by the Oglala Sioux Tribe (“OST”) and the Yankton Sioux Tribe (“YST”) were consolidated with this action and several individual tribal members intervened (collectively, with SRST and CRST, the “Tribes”). On March 25, 2020, the District Court remanded the case back to the USACE for preparation of an Environment Impact Statement (“EIS”). On July 6, 2020, the District Court vacated the easement and ordered Dakota Access to be shut down and emptied of oil by August 5, 2020. Dakota Access and the USACE appealed to the United States Court of Appeals for the District of Columbia (“Court of Appeals”), which granted an administrative stay of the District Court’s July 6 order and ordered further briefing on whether to fully stay the July 6 order. On August 5, 2020, the Court of Appeals 1) granted a stay of the portion of the District Court order that required Dakota Access to shut the pipeline down and empty it of oil, 2) denied a motion to stay the March 25 order pending a decision on the merits by the Court of Appeals as to whether the USACE would be required to prepare an EIS, and 3) denied a motion to stay the District Court’s order to vacate the easement during this appeal process. The August 5 order also stated that the Court of Appeals expected the USACE to clarify its position with respect to whether the USACE intended to allow the continued operation of the pipeline notwithstanding the vacatur of the easement and that the District Court may consider additional relief, if necessary.

On August 10, 2020, the District Court ordered the USACE to submit a status report by August 31, 2020, clarifying its position with regard to its decision-making process with respect to the continued operation of the pipeline. On August 31, 2020, the USACE submitted a status report that indicated that it considered the presence of the pipeline at the Lake Oahe crossing without an easement to constitute an encroachment on federal land, and that it was still considering whether to exercise its enforcement discretion regarding this encroachment. Following the filing of this status report, the District Court ordered briefing on whether to enjoin the operation of the pipeline. That motion was fully briefed as of January 8, 2021. The District Court has yet to rule on this matter.

On January 26, 2021, the Court of Appeals affirmed the District Court’s March 25, 2020 order requiring an EIS and its July 6, 2020 order vacating the easement. In this same January 26 order, the Court of Appeals also overturned the District Court’s July 6, 2020 order that the pipeline shut down and be emptied of oil.

The District Court scheduled a status conference for February 10, 2021 to discuss the effects of the Court of Appeals’ January 26, 2021 order on the pending motion for injunctive relief, as well as USACE’s expectations as to how it will proceed regarding its enforcement discretion regarding the easement. At the request of the USACE, on February 9, 2021 the District Court granted a two-month continuance for the status conference until April 9, 2021.

The pipeline continues to operate pending rulings from the District Court. ET cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access pipelines; however, ET expects after the law and complete record are fully considered, the issues in this litigation will be resolved in a manner that will allow the pipeline to continue to operate.

In addition, lawsuits and/or regulatory proceedings or actions of this or a similar nature could result in interruptions to construction or operations of current or future projects, delays in completing those projects and/or increased project costs, all of which could have an adverse effect on our business and results of operations.

Mont Belvieu Incident

On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL LLC’s (“Lone Star”) facilities in Mont Belvieu, Texas experienced an over-pressurization resulting in a subsurface release. The subsurface release caused a fire at Lone Star’s South Terminal and damage to Lone Star’s storage well operations at its South and North Terminals. Normal operations have resumed at the facilities with the exception of one of Lone Star’s storage wells; however, Lone Star is still quantifying the extent of its incurred and ongoing damages and has obtained, and will continue to seek, reimbursement for these losses.

 

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MTBE Litigation

ETC Sunoco Holdings LLC and Sunoco (R&M), LLC (collectively, “Sunoco Defendants”) are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability, nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices claims. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees.

As of December 31, 2020, Sunoco Defendants are defendants in five cases, including one case each initiated by the States of Maryland and Rhode Island, one by the Commonwealth of Pennsylvania and two by the Commonwealth of Puerto Rico. The more recent Puerto Rico action is a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. The actions brought by the State of Maryland and Commonwealth of Pennsylvania have also named as defendants ETO, ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals L.P. (“SPMT”).

It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position.

Regency Merger Litigation

On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action complaint related to the Regency-ETO merger (the “Regency Merger”) in the Court of Chancery of the State of Delaware (the “Regency Merger Litigation”), on behalf of Regency’s common unitholders against Regency GP LP, Regency GP LLC, ET, ETO, ETP GP, and the members of Regency’s board of directors.

The Regency Merger Litigation alleges that the Regency Merger breached the Regency partnership agreement. On March 29, 2016, the Delaware Court of Chancery granted the defendants’ motion to dismiss the lawsuit in its entirety. Plaintiff appealed, and the Delaware Supreme Court reversed the judgment of the Court of Chancery. Plaintiff then filed an Amended Verified Class Action Complaint, which defendants moved to dismiss. The Court of Chancery granted in part and denied in part the motions to dismiss, dismissing the claims against all defendants other than Regency GP LP and Regency GP LLC (the “Regency Defendants”). The Court of Chancery later granted plaintiff’s unopposed motion for class certification. Trial was held on December 10-16, 2019, and a post-trial hearing was held on May 6, 2020. On February 15, 2021, the Court of Chancery ruled in favor of the Regency Defendants on both remaining counts at issue in this litigation.

The Regency Defendants cannot predict whether the plaintiff will appeal this decision.

Rover

On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (“Ohio EPA”) filed suit against Rover and other defendants seeking to recover civil penalties allegedly owed and certain injunctive relief related to permit compliance. The defendants filed several motions to dismiss, which were granted on all counts. The Ohio EPA appealed, and on December 9, 2019, the Fifth District Court of Appeals entered a unanimous judgment affirming the trial court. The Ohio EPA sought review from the Ohio Supreme Court, which the defendants opposed in briefs filed in February 2020. On April 22, 2020, the Ohio Supreme Court granted the Ohio EPA’s request for review. Briefing has concluded and oral argument was held on January 26, 2021.

Revolution

On September 10, 2018, a pipeline release and fire (the “Incident”) occurred on the Revolution Pipeline, a natural gas gathering line located in Center Township, Beaver County, Pennsylvania. There were no

 

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injuries. On February 8, 2019, the Pennsylvania Department of Environmental Protection (“PADEP”) issued a Permit Hold on any requests for approvals/permits or permit amendments for any project in Pennsylvania pursuant to the state’s water laws. The Partnership filed an appeal of the Permit Hold with the Pennsylvania Environmental Hearing Board. On January 3, 2020, the Partnership entered into a Consent Order and Agreement with the PADEP in which, among other things, the Permit Hold was lifted, the Partnership agreed to pay a $28.6 million civil penalty and fund a $2 million community environmental project, and all related appeals were withdrawn. On November 11, 2020, the PADEP issued an order that required additional approvals and work prior to placing the Revolution Pipeline back in service. The Partnership filed an appeal of this order on December 8, 2020.

The Pennsylvania Office of Attorney General has commenced an investigation regarding the Incident, and the United States Attorney for the Western District of Pennsylvania has issued a federal grand jury subpoena for documents relevant to the Incident. The scope of these investigations is not further known at this time.

Chester County, Pennsylvania Investigation

In December 2018, the former Chester County District Attorney (the “Chester County DA”) sent a letter to the Partnership stating that his office was investigating the Partnership and related entities for “potential crimes” related to the Mariner East pipelines.

Subsequently, the matter was submitted to an Investigating Grand Jury in Chester County, Pennsylvania, which has issued subpoenas seeking documents and testimony. On September 24, 2019, the Chester County DA sent a Notice of Intent to the Partnership of its intent to pursue an abatement action if certain conditions were not remediated. The Partnership responded to the Notice of Intent within the proscribed time period.

In December 2019, the Chester County DA announced charges against a current employee related to the provision of security services. On June 25, 2020, a preliminary hearing was held on the charges against the employee, and the judge dismissed all charges.

Delaware County, Pennsylvania Investigation

On March 11, 2019, the Delaware County District Attorney’s Office (the “Delaware County DA”) announced that the Delaware County DA and the Pennsylvania Attorney General’s Office, at the request of the Delaware County DA, are conducting an investigation of alleged criminal misconduct involving the construction and related activities of the Mariner East pipelines in Delaware County. On March 16, 2020, the Pennsylvania Attorney General Office served a Statewide Investigating Grand Jury subpoena for documents relating to inadvertent returns and water supplies related to the Mariner East pipelines. While the Partnership will cooperate with the subpoena, it intends to vigorously defend itself.

Cline Class Action Lawsuit

On July 7, 2017, Perry Cline filed a class action complaint in the Eastern District of Oklahoma against Sunoco, Inc. (R&M) and Sunoco Partners Marketing & Terminals L.P. (collectively, “SPMT”) that alleged SPMT failed to make timely payments of oil and gas proceeds from Oklahoma wells and to pay statutory interest for those untimely payments. On October 3, 2019, the Court certified a class to include all persons who received untimely payments from Oklahoma wells on or after July 7, 2012 and who have not already been paid statutory interest on the untimely payments (the “Class”). Excluded from the Class are those entitled to payments of proceeds that qualify as “minimum pay,” prior period adjustments, and pass through payments, as well as governmental agencies and publicly traded oil and gas companies.

After a bench trial, on August 17, 2020, Judge John Gibney (sitting from the Eastern District of Virginia) issued an opinion that awarded the Class actual damages of $74.8 million for late payment interest for identified and unidentified royalty owners and interest-on-interest. This amount was later amended to $80.7 million to account for interest accrued from trial (the “Order”). Judge Gibney also awarded punitive damages in the amount of $75 million. The Class is also seeking attorneys’ fees.

 

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On August 27, 2020, SPMT filed its Notice of Appeal with the 10th Circuit and appealed the entirety of the Order. SPMT cannot predict the outcome of the case, nor can SPMT predict the amount of time and expense that will be required to resolve the appeal, but intends to vigorously appeal the entirety of the Order.

Environmental Matters

Our operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on our business and operating results. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, natural resource damages, the issuance of injunctions in affected areas and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.

Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.

Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs.

In February 2017, we received letters from the DOJ on behalf of EPA and Louisiana Department of Environmental Quality (“LDEQ”) notifying SPLP and Mid-Valley Pipeline Company (“Mid-Valley”) that enforcement actions were being pursued for three separate crude oil releases: (a) an estimated 550 barrels released from the Colmesneil-to-Chester pipeline in Tyler County, Texas (“Colmesneil”) which allegedly occurred in February 2013; (b) an estimated 4,509 barrels released from the Longview-to-Mayersville pipeline in Caddo Parish, Louisiana (a/k/a Milepost 51.5) which allegedly occurred in October 2014; and (c) an estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma which allegedly occurred in January 2015. In January 2019, a Consent Decree approved by all parties as well as an accompanying Complaint was filed in the United States District Court for the Western District of Louisiana seeking public comment and final court approval to resolve all penalties with the DOJ and LDEQ for the three releases. Subsequently, the court approved the Consent Decree and the penalty payment of $5.4 million was satisfied. The Consent Decree requires certain injunctive relief to be completed on the Longview-to-Mayersville pipeline within three years, but the injunctive relief is not expected to have any material impact on operations. In addition to resolution of the civil penalty and injunctive relief, we continue to discuss natural resource damages with the Louisiana trustees related to the Caddo Parish, Louisiana release.

In October 2018, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) issued a notice of proposed safety order (the “Notice”) to SPMT, a wholly-owned subsidiary of ETO. The Notice alleged that conditions exist on certain pipeline facilities owned and operated by SPMT in Nederland, Texas that pose a pipeline integrity risk to public safety, property or the environment. The Notice also made preliminary findings of fact and proposed corrective measures. SPMT responded to the Notice by submitting

 

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a timely written response on November 2, 2018, attended an informal consultation held on January 30, 2019 and entered into a consent agreement with PHMSA resolving the issues in the Notice as of March 2019. The Remedial Work Plan was approved by PHMSA on August 28, 2020.

On June 4, 2019, the Oklahoma Corporation Commission’s (“OCC”) Transportation Division filed a complaint against SPLP seeking a penalty of up to $1 million related to a May 2018 rupture near Edmond, Oklahoma. The release occurred on the Noble to Douglas 8” pipeline in an area of external corrosion and caused the release of approximately fifteen barrels of crude oil. SPLP responded immediately to the release and remediated the surrounding environment and pipeline in cooperation with the OCC. The OCC filed the complaint alleging that SPLP failed to provide adequate cathodic protection to the pipeline causing the failure. SPLP is negotiating a settlement agreement with the OCC for a lesser penalty. The OCC has accepted our counter offer in conjunction with a proposed consent order. The Consent Order was presented to the OCC at a hearing on August 18, 2020, and is awaiting final signature by the OCC Commissioners.

Environmental Remediation

Our subsidiaries are responsible for environmental remediation at certain sites, including the following:

 

   

certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could be contractually responsible for contamination caused by other parties.

 

   

certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.

 

   

legacy sites related to Sunoco that are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that Sunoco no longer operates, closed and/or sold refineries and other formerly owned sites.

Sunoco is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of December 31, 2020, Sunoco had been named as a PRP at approximately 35 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco is usually one of a number of companies identified as a PRP at a site. Sunoco has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.

To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets.

The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.

 

     December 31,  
     2020      2019  

Current

   $ 44    $ 46

Non-current

     262      274
  

 

 

    

 

 

 

Total environmental liabilities

   $ 306    $ 320
  

 

 

    

 

 

 

 

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We have established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.

During the years ended December 31, 2020 and 2019, the Partnership recorded $29 million and $39 million, respectively, of expenditures related to environmental cleanup programs.

Our pipeline operations are subject to regulation by the United States Department of Transportation under PHMSA, pursuant to which PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures.

Our operations are also subject to the requirements of OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, the Occupational Safety and Health Administration’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our past costs for OSHA required activities, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances have not had a material adverse effect on our results of operations but there is no assurance that such costs will not be material in the future.

 

11.

REVENUE:

Disaggregation of revenue

The major types of revenue within our reportable segments, are as follows:

 

   

intrastate transportation and storage;

 

   

interstate transportation and storage;

 

   

midstream;

 

   

NGL and refined products transportation and services;

 

   

crude oil transportation and services;

 

   

investment in Sunoco LP;

 

   

fuel distribution and marketing;

 

   

all other;

 

   

investment in USAC;

 

   

contract operations;

 

   

retail parts and services; and

 

   

all other.

 

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Note 16 depicts the disaggregation of revenue by segment, with revenue amounts reflected in accordance with ASC Topic 606.

Intrastate transportation and storage revenue

Our intrastate transportation and storage segment’s revenues are determined primarily by the volume of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected or withdrawn into or out of our storage facilities. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity they transport or store. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected/withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject/withdraw into or out of our storage facilities. Payment for services under these contracts are typically due the month after the services have been performed.

The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.

The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.

Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from our marketing operations, and from producers at the wellhead.

Interstate transportation and storage revenue

Our interstate transportation and storage segment’s revenues are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected into or withdrawn out of our storage facilities. Our interstate transportation and storage segment’s contracts can be firm or interruptible. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity transported or stored. In exchange for such fees, we must stand ready to perform a contractually agreed-upon minimum volume of services whenever the customer requests such services. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected or withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject into or withdraw out of our storage facilities. Consequently, we are not required to stand ready to provide any contractually agreed-upon volume of service, but instead provides the services based on existing capacity at the time the customer requests the services. Payment for services under these contracts are typically due the month after the services have been performed.

 

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The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.

The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.

Lake Charles LNG’s revenues are primarily derived from terminalling services for shippers by receiving LNG at the facility for storage and delivering such LNG to shippers, either in liquid state or gaseous state after regasification. Lake Charles LNG derives all of its revenue from a series of long-term contracts with a wholly-owned subsidiary of Shell. Terminalling revenue is generated from fees paid by Shell for storage and other associated services at the terminal. Payment for services under these contracts are typically due the month after the services have been performed.

The terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volumes transported by Shell or services provided at the terminal.

The performance obligation with respect to firm contracts is a promise to provide a single type of service (terminalling) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.

Midstream revenue

Our midstream segment’s revenues are derived primarily from margins we earn for natural gas volumes that are gathered, processed, and/or transported. The various types of revenue contracts our midstream segment enters into include:

Fixed fee gathering and processing: Contracts under which we provide gathering and processing services in exchange for a fixed cash fee per unit of volume. Revenue for cash fees is recognized when the service is performed.

Keepwhole: Contracts under which we gather raw natural gas from a third-party producer, process the gas to convert it to pipeline quality natural gas, and redeliver to the producer a thermal-equivalent volume of pipeline quality natural gas. In exchange for these services, we retain the NGLs extracted from the raw natural gas received from the producer as well as cash fees paid by the producer. The value of NGLs retained as well as cash fees is recognized as revenue when the services are performed.

 

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Percent of Proceeds (“POP”): Contracts under which we provide gathering and processing services in exchange for a specified percentage of the producer’s commodity (“POP percentage”) and also in some cases additional cash fees. The two types of POP revenue contracts are described below:

 

   

In-Kind POP: We retain our POP percentage (non-cash consideration) and also any additional cash fees in exchange for providing the services. We recognize revenue for the non-cash consideration and cash fees at the time the services are performed.

 

   

Mixed POP: We purchase NGLs from the producer and retain a portion of the residue gas as non-cash consideration for services provided. We may also receive cash fees for such services. Under Topic 606, these agreements were determined to be hybrid agreements which were partially supply agreements (for the NGLs we purchased) and customer agreements (for the services provided related to the product that was returned to the customer). Given that these are hybrid agreements, we split the cash and non-cash consideration between revenue and a reduction of costs based on the value of the service provided vs. the value of the supply received.

Payment for services under these contracts are typically due the month after the services have been performed.

The performance obligations with respect to our midstream segment’s contracts are to provide gathering, transportation and processing services, each of which would be completed on or about the same time, and each of which would be recognized on the same line item on the income statement, therefore identification of separate performance obligations would not impact the timing or geography of revenue recognition.

Certain contracts of our midstream segment include throughput commitments under which customers commit to purchasing a certain minimum volume of service over a specified time period. If such volume of service is not purchased by the customer, deficiency fees are billed to the customer. In some cases, the customer is allowed to apply any deficiency fees paid to future purchases of services. In such cases, we defer revenue recognition until the customer uses the deficiency fees for services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints.

Our midstream segment also generates revenues from the sale of residue gas and NGLs at the tailgate of our processing facilities primarily to affiliates and some third-party customers.

NGL and refined products transportation and services revenue

Our NGL and refined products segment’s revenues are primarily derived from transportation, fractionation, blending, and storage of NGL and refined products as well as acquisition and marketing activities. Revenues are generated utilizing a complementary network of pipelines, storage and blending facilities, and strategic off-take locations that provide access to multiple NGL markets. Transportation, fractionation, and storage revenue is generated from fees charged to customers under a combination of firm and interruptible contracts. Firm contracts are in the form of take-or-pay arrangements where certain fees will be charged to customers regardless of the volume of service they request for any given period. Under interruptible contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of service provided for any given period. Payment for services under these contracts are typically due the month after the services have been performed.

The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation, fractionation, blending, or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service.

 

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Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.

The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.

Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of NGLs and other related hydrocarbons at market rates. These contracts were not affected by ASC 606.

Crude oil transportation and services revenue

Our crude oil transportation and services segment revenues are primarily derived from providing transportation, terminalling and acquisition and marketing services to crude oil markets throughout the southwest, midwest and northeastern United States. Crude oil transportation revenue is generated from tariffs paid by shippers utilizing our transportation services and is generally recognized as the related transportation services are provided. Crude oil terminalling revenue is generated from fees paid by customers for storage and other associated services at the terminal. Crude oil acquisition and marketing revenue is generated from sale of crude oil acquired from a variety of suppliers to third parties. Payment for services under these contracts are typically due the month after the services have been performed.

Certain transportation and terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volume of crude oil transported by the customer or services provided at the terminal. For these agreements, any fixed fees billed in excess of services provided are not recognized as revenue until the earlier of (i) the time at which the customer applies the fees against cost of service provided in a later period, or (ii) the customer becomes unable to apply the fees against cost of future service due to capacity constraints or contractual terms.

The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or terminalling) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.

The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and/or product and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.

Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of crude oil at market rates. These contracts were not affected by ASC 606.

Sunoco LP’s fuel distribution and marketing revenue

Sunoco LP’s fuel distribution and marketing operations earn revenue from the following channels: sales to dealers, sales to distributors, unbranded wholesale revenue, commission agent revenue, rental income and other income. Motor fuel revenue consists primarily of the sale of motor fuel under supply agreements with third party customers and affiliates. Fuel supply contracts with Sunoco LP’s customers generally provide that Sunoco LP distribute motor fuel at a formula price based on published rates, volume-based profit margin, and other terms specific to the agreement. The customer is invoiced the agreed-upon price with

 

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most payment terms ranging less than 30 days. If the consideration promised in a contract includes a variable amount, Sunoco LP estimates the variable consideration amount and factors in such an estimate to determine the transaction price under the expected value method.

Revenue is recognized under the motor fuel contracts at the point in time the customer takes control of the fuel. At the time control is transferred to the customer the sale is considered final, because the agreements do not grant customers the right to return motor fuel. Under the new standard, to determine when control transfers to the customer, the shipping terms of the contract are assessed as shipping terms are considered a primary indicator of the transfer of control. For FOB shipping point terms, revenue is recognized at the time of shipment. The performance obligation with respect to the sale of goods is satisfied at the time of shipment since the customer gains control at this time under the terms. Shipping and/or handling costs that occur before the customer obtains control of the goods are deemed to be fulfillment activities and are accounted for as fulfillment costs. Once the goods are shipped, Sunoco LP is precluded from redirecting the shipment to another customer and revenue is recognized.

Commission agent revenue consists of sales from commission agent agreements between Sunoco LP and select operators. Sunoco LP supplies motor fuel to sites operated by commission agents and sells the fuel directly to the end customer. In commission agent arrangements, control of the product is transferred at the point in time when the goods are sold to the end customer. To reflect the transfer of control, Sunoco LP recognizes commission agent revenue at the point in time fuel is sold to the end customer.

Sunoco LP receives rental income from leased or subleased properties. Revenue from leasing arrangements for which Sunoco LP is the lessor are recognized ratably over the term of the underlying lease.

Sunoco LP’s all other revenue

Sunoco LP’s all other operations earn revenue from the following channels: motor fuel sales, rental income and other income. Motor fuel sales consist of fuel sales to consumers at company-operated retail stores. Other income includes merchandise revenue that comprises the in-store merchandise and food service sales at company-operated retail stores, and other revenue that represents a variety of other services within Sunoco LP’s all other operations including credit card processing, car washes, lottery, automated teller machines, money orders, prepaid phone cards and wireless services. Revenue from all other operations is recognized when (or as) the performance obligations are satisfied (i.e. when the customer obtains control of the good or the service is provided).

USAC’s contract operations revenue

USAC’s revenue from contracted compression, station, gas treating and maintenance services is recognized ratably under its fixed-fee contracts over the term of the contract as services are provided to its customers. Initial contract terms typically range from six months to five years, however USAC usually continues to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. USAC primarily enters into fixed-fee contracts whereby its customers are required to pay the monthly fee even during periods of limited or disrupted throughput. Services are generally billed monthly, one month in advance of the commencement of the service month, except for certain customers who are billed at the beginning of the service month, and payment is generally due 30 days after receipt of the invoice. Amounts invoiced in advance are recorded as deferred revenue until earned, at which time they are recognized as revenue. The amount of consideration USAC receives and revenue it recognizes is based upon the fixed fee rate stated in each service contract.

Variable consideration exists in select contracts when billing rates vary based on actual equipment availability or volume of total installed horsepower.

USAC’s contracts with customers may include multiple performance obligations. For such arrangements, USAC allocates revenues to each performance obligation based on its relative standalone service fee. USAC generally determines standalone service fees based on the service fees charged to customers or using expected cost plus margin.

 

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The majority of USAC’s service performance obligations are satisfied over time as services are rendered at selected customer locations on a monthly basis and based upon specific performance criteria identified in the applicable contract. The monthly service for each location is substantially the same service month to month and is promised consecutively over the service contract term. USAC measures progress and performance of the service consistently using a straight-line, time-based method as each month passes, because its performance obligations are satisfied evenly over the contract term as the customer simultaneously receives and consumes the benefits provided by its service. If variable consideration exists, it is allocated to the distinct monthly service within the series to which such variable consideration relates. USAC has elected to apply the invoicing practical expedient to recognize revenue for such variable consideration, as the invoice corresponds directly to the value transferred to the customer based on its performance completed to date.

There are typically no material obligations for returns or refunds. USAC’s standard contracts do not usually include material non-cash consideration.

USAC’s retail parts and services revenue

USAC’s retail parts and service revenue is earned primarily on freight and crane charges that are directly reimbursable by USAC’s customers and maintenance work on units at its customers’ locations that are outside the scope of its core maintenance activities. Revenue from retail parts and services is recognized at the point in time the part is transferred or service is provided and control is transferred to the customer. At such time, the customer has the ability to direct the use of the benefits of such part or service after USAC has performed its services. USAC bills upon completion of the service or transfer of the parts, and payment is generally due 30 days after receipt of the invoice. The amount of consideration USAC receives and revenue it recognizes is based upon the invoice amount. There are typically no material obligations for returns, refunds, or warranties. USAC’s standard contracts do not usually include material variable or non-cash consideration.

All other revenue

Our all other segment primarily includes our compression equipment business which provides full-service compression design and manufacturing services for the oil and gas industry. It also includes the management of coal and natural resources properties and the related collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties. These operations also include end-user coal handling facilities. There were no material changes to the manner in which revenues within this segment are recorded under the new standard.

Contract Balances with Customers

The Partnership satisfies its obligations by transferring goods or services in exchange for consideration from customers. The timing of performance may differ from the timing the associated consideration is paid to or received from the customer, thus resulting in the recognition of a contract asset or a contract liability.

The Partnership recognizes a contract asset when making upfront consideration payments to certain customers or when providing services to customers prior to the time at which the Partnership is contractually allowed to bill for such services.

The Partnership recognizes a contract liability if the customer’s payment of consideration precedes the Partnership’s fulfillment of the performance obligations. Certain contracts contain provisions requiring customers to pay a fixed minimum fee, but allows customers to apply such fees against services to be provided at a future point in time. These amounts are reflected as deferred revenue until the customer applies the deficiency fees to services provided or becomes unable to use the fees as payment for future

 

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services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. Additionally, Sunoco LP maintains some franchise agreements requiring dealers to make one-time upfront payments for long-term license agreements. Sunoco LP recognizes a contract liability when the upfront payment is received and recognizes revenue over the term of the license.

The following table summarizes the consolidated activity of our contract liabilities:

 

     Contract
Liabilities
 

Balance, December 31, 2018

   $ 394

Additions

     651

Revenue recognized

     (680
  

 

 

 

Balance, December 31, 2019

     365

Additions

     771

Revenue recognized

     (846
  

 

 

 

Balance, December 31, 2020

   $ 290
  

 

 

 

The balances of Sunoco LP’s contract assets and contract liabilities as of December 31, 2020 and 2019 were as follows:

 

     December 31,
2020
     December 31,
2019
 

Contract balances:

     

Contract asset

   $ 121    $ 117

Accounts receivable from contracts with customers

     256      366

Costs to Obtain or Fulfill a Contract

Sunoco LP recognizes an asset from the costs incurred to obtain a contract (e.g. sales commissions) only if it expects to recover those costs. On the other hand, the costs to fulfill a contract are capitalized if the costs are specifically identifiable to a contract, would result in enhancing resources that will be used in satisfying performance obligations in future and are expected to be recovered. These capitalized costs are recorded as a part of other current assets and other non-current assets and are amortized on a systematic basis consistent with the pattern of transfer of the goods or services to which such costs relate. The amount of amortization expense that Sunoco LP recognized for the years ended December 31, 2020, 2019 and 2018 was $18 million, $17 million and $14 million, respectively. Sunoco LP has also made a policy election of expensing the costs to obtain a contract, as and when they are incurred, in cases where the expected amortization period is one year or less.

Performance Obligations

At contract inception, the Partnership assesses the goods and services promised in its contracts with customers and identifies a performance obligation for each promise to transfer a good or service (or bundle of goods or services) that is distinct. To identify the performance obligations, the Partnership considers all the goods or services promised in the contract, whether explicitly stated or implied based on customary business practices. For a contract that has more than one performance obligation, the Partnership allocates the total contract consideration it expects to be entitled to, to each distinct performance obligation based on a standalone-selling price basis. Revenue is recognized when (or as) the performance obligations are satisfied, that is, when the customer obtains control of the good or service. Certain of our contracts contain variable components, which, when combined with the fixed component are considered a single performance obligation. For these types of contracts, only the fixed component of the contracts are included in the table below.

 

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Sunoco LP distributes fuel under long-term contracts to branded distributors, branded and unbranded third-party dealers, and branded and unbranded retail fuel outlets. Sunoco LP branded supply contracts with distributors generally have both time and volume commitments that establish contract duration. These contracts have an initial term of approximately nine years, with an estimated, volume-weighted term remaining of approximately four years.

As part of the asset purchase agreement with 7-Eleven, Sunoco LP and 7-Eleven and SEI Fuel (collectively, the “Distributor”) have entered into a 15-year take-or-pay fuel supply agreement in which the Distributor is required to purchase a volume of fuel that provides Sunoco LP a minimum amount of gross profit annually. Sunoco LP expects to recognize this revenue in accordance with the contract as Sunoco LP transfers control of the product to the customer. However, in case of annual shortfall Sunoco LP will recognize the amount payable by the Distributor at the sooner of the time at which the Distributor makes up the shortfall or becomes contractually or operationally unable to do so. The transaction price of the contract is variable in nature, fluctuating based on market conditions. The Partnership has elected to take the practical expedient not to estimate the amount of variable consideration allocated to wholly unsatisfied performance obligations.

In some contractual arrangements, Sunoco LP grants dealers a franchise license to operate Sunoco LP’s retail stores over the life of a franchise agreement. In return for the grant of the retail store license, the dealer makes a one-time nonrefundable franchise fee payment to Sunoco LP plus sales based royalties payable to Sunoco LP at a contractual rate during the period of the franchise agreement. Under the requirements of ASC Topic 606, the franchise license is deemed to be a symbolic license for which recognition of revenue over time is the most appropriate measure of progress toward complete satisfaction of the performance obligation. Revenue from this symbolic license is recognized evenly over the life of the franchise agreement.

As of December 31, 2020, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations was $40.35 billion, and the Partnership expects to recognize this amount as revenue within the time bands illustrated below:

 

     Years Ending December 31,                
     2021      2022      2023      Thereafter      Total  

Revenue expected to be recognized on contracts with customers existing as of December 31, 2020

   $ 5,120    $ 5,475    $ 5,051    $ 24,701    $ 40,347

Practical Expedients Utilized by the Partnership

The Partnership elected the following practical expedients in accordance with Topic 606:

 

   

Right to invoice: The Partnership elected to utilize an output method to recognize revenue that is based on the amount to which the Partnership has a right to invoice a customer for services performed to date, if that amount corresponds directly with the value provided to the customer for the related performance or its obligation completed to date. As such, the Partnership recognized revenue in the amount to which it had the right to invoice customers.

 

   

Significant financing component: The Partnership elected not to adjust the promised amount of consideration for the effects of significant financing component if the Partnership expects, at contract inception, that the period between the transfer of a promised good or service to a customer and when the customer pays for that good or service will be one year or less.

 

   

Unearned variable consideration: The Partnership elected to only disclose the unearned fixed consideration associated with unsatisfied performance obligations related to our various customer contracts which contain both fixed and variable components.

 

   

Incremental costs of obtaining a contract: The Partnership generally expenses sales commissions when incurred because the amortization period would have been less than one year. We record these costs

 

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within general and administrative expenses. The Partnership elected to expense the incremental costs of obtaining a contract when the amortization period for such contracts would have been one year or less.

 

   

Shipping and handling costs: The Partnership elected to account for shipping and handling activities that occur after the customer has obtained control of a good as fulfillment activities (i.e., an expense) rather than as a promised service.

 

   

Measurement of transaction price: The Partnership has elected to exclude from the measurement of transaction price all taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction and collected by the Partnership from a customer (i.e., sales tax, value added tax, etc.).

 

   

Variable consideration of wholly unsatisfied performance obligations: The Partnership has elected to exclude the estimate of variable consideration to the allocation of wholly unsatisfied performance obligations.

 

12.

LEASE ACCOUNTING:

Lessee Accounting

The Partnership leases terminal facilities, tank cars, office space, land and equipment under non-cancelable operating leases whose initial terms are typically five to 15 years, with some real estate leases having terms of 40 years or more, along with options that permit renewals for additional periods. At the inception of each, we determine if the arrangement is a lease or contains an embedded lease and review the facts and circumstances of the arrangement to classify lease assets as operating or finance leases under Topic 842. The Partnership has elected not to record any leases with terms of 12 months or less on the balance sheet.

At present, the majority of the Partnership’s active leases are classified as operating in accordance with Topic 842. Balances related to operating leases are included in operating lease ROU assets, accrued and other current liabilities, operating lease current liabilities and non-current operating lease liabilities in our consolidated balance sheets. Finance leases represent a small portion of the active lease agreements and are included in finance lease ROU assets, current maturities of long-term debt and long-term debt, less current maturities in our consolidated balance sheets. The ROU assets represent the Partnership’s right to use an underlying asset for the lease term and lease liabilities represent the obligation of the Partnership to make minimum lease payments arising from the lease for the duration of the lease term.

Most leases include one or more options to renew, with renewal terms that can extend the lease term from one to 20 years or greater. The exercise of lease renewal options is typically at the sole discretion of the Partnership and lease extensions are evaluated on a lease-by-lease basis. Leases containing early termination clauses typically require the agreement of both parties to the lease. At the inception of a lease, all renewal options reasonably certain to be exercised are considered when determining the lease term. Presently, the Partnership does not have leases that include options to purchase or automatic transfer of ownership of the leased property to the Partnership. The depreciable life of lease assets and leasehold improvements are limited by the expected lease term.

To determine the present value of future minimum lease payments, we use the implicit rate when readily determinable. Presently, because many of our leases do not provide an implicit rate, the Partnership applies its incremental borrowing rate based on the information available at the lease commencement date to determine the present value of minimum lease payments. The operating and finance lease ROU assets include any lease payments made and exclude lease incentives.

Minimum rent payments are expensed on a straight-line basis over the term of the lease. In addition, some leases require additional contingent or variable lease payments, which are based on the factors specific to the individual agreement. Variable lease payments the Partnership is typically responsible for include payment of real estate taxes, maintenance expenses and insurance.

 

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For short-term leases (leases that have term of twelve months or less upon commencement), lease payments are recognized on a straight-line basis and no ROU assets are recorded.

The components of operating and finance lease amounts recognized in the accompanying consolidated balance sheet as of December 31, 2020 and 2019 were as follows:

 

     December 31,  
     2020      2019  

Operating leases:

     

Lease right-of-use assets, net

   $ 863    $ 935

Operating lease current liabilities

     53      60

Accrued and other current liabilities

     1      1

Non-current operating lease liabilities

     837      901

Finance leases:

     

Property, plant and equipment, net

   $ 1      1

Lease right-of-use assets, net

     3      29

Accrued and other current liabilities

     1      1

Current maturities of long-term debt

     1      6

Long-term debt, less current maturities

     6      26

Other non-current liabilities

     1      2

The components of lease expense for the years ended December 31, 2020 and 2019 were as follows:

 

          Year Ended
December 31,
 
    

Income Statement Location

   2020      2019  

Operating lease costs:

        

Operating lease cost

   Cost of goods sold    $ 14    $ 28

Operating lease cost

   Operating expenses      75      73

Operating lease cost

   Selling, general and administrative      17      16
     

 

 

    

 

 

 

Total operating lease costs

        106      117

Finance lease costs:

        

Amortization of lease assets

   Depreciation, depletion and amortization      3      6

Interest on lease liabilities

   Interest expense, net of capitalized interest      1      1
     

 

 

    

 

 

 

Total finance lease costs

        4      7
     

 

 

    

 

 

 

Short-term lease cost

   Operating expenses      31      42

Variable lease cost

   Operating expenses      16      17
     

 

 

    

 

 

 

Lease costs, gross

        157      183
     

 

 

    

 

 

 

Less: Sublease income

   Other revenue      48      47
     

 

 

    

 

 

 

Lease costs, net

      $ 109    $ 136
     

 

 

    

 

 

 

The weighted average remaining lease terms and weighted average discount rates as of December 31, 2020 and 2019 were as follows:

 

     December 31,  
     2020     2019  

Weighted-average remaining lease term (years):

    

Operating leases

     22       24  

Finance leases

     9       5  

Weighted-average discount rate (%):

    

Operating leases

     5     5

Finance leases

     8     5

 

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Cash flows and non-cash activity related to leases for the years ended December 31, 2020 and 2019 were as follows:

 

     Year Ended
December 31,
 
     2020      2019  

Operating cash flows from operating leases

   $ (117    $ (159

Lease assets obtained in exchange for new finance lease liabilities

     —          28

Lease assets obtained in exchange for new operating lease liabilities

     42      40

Maturities of lease liabilities as of December 31, 2020 are as follows:

 

     Operating
leases
     Finance
leases
     Total  

2021

   $ 99    $ 2    $ 101

2022

     85      2      87

2023

     79      2      81

2024

     76      1      77

2025

     75      1      76

Thereafter

     1,140      4      1,144
  

 

 

    

 

 

    

 

 

 

Total lease payments

     1,554      12      1,566

Less: present value discount

     664      3      667
  

 

 

    

 

 

    

 

 

 

Present value of lease liabilities

   $ 890    $ 9    $ 899
  

 

 

    

 

 

    

 

 

 

Lessor Accounting

The Partnership leases or subleases a portion of its real estate portfolio to third-party companies as a stable source of long-term revenue. Our lessor and sublease portfolio consists mainly of operating leases with convenience store operators. At this time, most lessor agreements contain five-year terms with renewal options to extend and early termination options based on established terms specific to the individual agreement.

Rental income included in other revenue in our consolidated statement of operations for the years ended December 31, 2020 and 2019 was $144 million and $149 million, respectively.

Future minimum operating lease payments receivable as of December 31, 2020 are as follows:

 

     Lease
Payments
 

2021

   $ 103

2022

     64

2023

     8

2024

     3

2025

     2

Thereafter

     5
  

 

 

 

Total undiscounted cash flows

   $ 185
  

 

 

 

 

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13.

DERIVATIVE ASSETS AND LIABILITIES:

Commodity Price Risk

We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets.

We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized.

We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales on our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes.

We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes.

We utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes.

We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales. These contracts are not designated as hedges for accounting purposes.

We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.

 

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The following table details our outstanding commodity-related derivatives:

 

     December 31, 2020      December 31, 2019  
     Notional
Volume
     Maturity      Notional
Volume
     Maturity  

Mark-to-Market Derivatives

           

(Trading)

           

Natural Gas (BBtu):

           

Fixed Swaps/Futures

     1,603      2021-2022        1,483      2020  

Basis Swaps IFERC/NYMEX (1)

     (44,225      2021-2022        (35,208      2020-2024  

Power (Megawatt):

           

Forwards

     1,392,400      2021-2029        3,213,450      2020-2029  

Futures

     18,706      2021-2022        (353,527      2020  

Options – Puts

     519,071      2021        51,615      2020  

Options – Calls

     2,343,293      2021        (2,704,330      2020-2021  

(Non-Trading)

           

Natural Gas (BBtu):

           

Basis Swaps IFERC/NYMEX

     (29,173      2021-2022        (18,923      2020-2022  

Swing Swaps IFERC

     11,208      2021        (9,265      2020  

Fixed Swaps/Futures

     (53,575      2021-2022        (3,085      2020-2021  

Forward Physical Contracts

     (11,861      2021        (13,364      2020-2021  

NGL (MBbls) – Forwards/Swaps

     (5,840      2021-2022        (1,300      2020-2021  

Crude (MBbls) – Forwards/Swaps

     —          —          4,465      2020  

Refined Products (MBbls) – Futures

     (2,765      2021        (2,473      2020-2021  

Corn (thousand bushels)

     —          —          (1,210      2020  

Fair Value Hedging Derivatives

           

(Non-Trading)

           

Natural Gas (BBtu):

           

Basis Swaps IFERC/NYMEX

     (30,113      2021        (31,780      2020  

Fixed Swaps/Futures

     (30,113      2021        (31,780      2020  

Hedged Item – Inventory

     30,113      2021        31,780      2020  

 

  (1)

Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.

Interest Rate Risk

We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We also manage our interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances.

The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes:

 

Term

  

Type (1)

   Notional Amount Outstanding  
   December 31,
2020
     December 31,
2019
 

July 2020 (2)(3)

   Forward-starting to pay a fixed rate of 3.52% and receive a floating rate    $ —        $ 400

July 2021 (2)

   Forward-starting to pay a fixed rate of 3.55% and receive a floating rate      400      400

July 2022 (2)

  

Forward-starting to pay a fixed rate of 3.80% and receive a floating rate

     400      400

 

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  (1)

Floating rates are based on 3-month LIBOR.

  (2)

Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.

  (3)

The July 2020 interest rate swaps were terminated in January 2020.

Credit Risk

Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.

The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrial end-users, oil and gas producers, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.

The Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily with independent system operators and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets.

For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.

 

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Derivative Summary

The following table provides a summary of our derivative assets and liabilities:

 

    Fair Value of Derivative Instruments  
    Asset Derivatives     Liability Derivatives  
    December 31,
2020
    December 31,
2019
    December 31,
2020
    December 31,
2019
 

Derivatives designated as hedging instruments:

       

Commodity derivatives (margin deposits)

  $ 25   $ 24   $ (32   $ —    
 

 

 

   

 

 

   

 

 

   

 

 

 
    25     24     (32     —    

Derivatives not designated as hedging instruments:

       

Commodity derivatives (margin deposits)

    90     319     (166     (350

Commodity derivatives

    53     41     (71     (39

Interest rate derivatives

    —         —         (448     (399
 

 

 

   

 

 

   

 

 

   

 

 

 
    143     360     (685     (788
 

 

 

   

 

 

   

 

 

   

 

 

 

Total derivatives

  $ 168   $ 384   $ (717   $ (788
 

 

 

   

 

 

   

 

 

   

 

 

 

The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:

 

        Asset Derivatives     Liability Derivatives  
    Balance Sheet Location   December 31,
2020
    December 31,
2019
    December 31,
2020
    December 31,
2019
 

Derivatives without offsetting agreements

  Derivative liabilities   $ —       $ —       $ (448   $ (399

Derivatives in offsetting agreements:

         

OTC contracts

  Derivative assets
(liabilities)
    53     41     (71     (39

Broker cleared derivative contracts

 

Other current assets
(liabilities)

    115     343     (198     (350
   

 

 

   

 

 

   

 

 

   

 

 

 
    168     384     (717     (788

Offsetting agreements:

 

Counterparty netting

  Derivative assets
(liabilities)
    (44     (18     44     18

Counterparty netting

  Other current assets
(liabilities)
    (64     (318     64     318
   

 

 

   

 

 

   

 

 

   

 

 

 

Total net derivatives

  $ 60   $ 48   $ (609   $ (452
 

 

 

   

 

 

   

 

 

   

 

 

 

We disclose the non-exchange traded financial derivative instruments as derivative assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.

 

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The following tables summarize the amounts recognized with respect to our derivative financial instruments:

 

   

Location of Gain (Loss)
Recognized in Income

on Derivatives

  Amount of Gain (Loss) Recognized
in Income Representing Hedge
Ineffectiveness and Amount Excluded
from the Assessment of Effectiveness
 
            Years Ended December 31,      
        2020     2019     2018  

Derivatives in fair value hedging relationships (including hedged item):

       

Commodity derivatives

  Cost of products sold   $ —       $ —       $ (3
   

Location of Gain (Loss)

Recognized in Income

on Derivatives

  Amount of Gain (Loss) Recognized
in Income on Derivatives
 
            Years Ended December 31,      
        2020     2019     2018  

Derivatives not designated as hedging instruments:

       

Commodity derivatives – Trading

  Revenues   $ —       $ (3   $ —    

Commodity derivatives – Trading

  Cost of products sold     8     21     32

Commodity derivatives – Non-trading

  Cost of products sold     (34     (100     (102

Interest rate derivatives

  Gains (losses) on interest rate derivatives     (203     (241     47
   

 

 

   

 

 

   

 

 

 

Total

    $ (229   $ (323   $ (23
   

 

 

   

 

 

   

 

 

 

 

14.

RETIREMENT BENEFITS:

Savings and Profit Sharing Plans

We and our subsidiaries sponsor defined contribution savings and profit sharing plans, which collectively cover virtually all eligible employees, including those of ETO, Lake Charles LNG, Sunoco LP and USAC. Employer matching contributions are calculated using a formula based on employee contributions. We and our subsidiaries made matching contributions of $35 million, $66 million and $62 million to these 401(k) savings plans for the years ended December 31, 2020, 2019 and 2018, respectively.

As a result of the economic conditions in 2020, effective June 8, 2020, the Partnership ceased employer matching and profit sharing contributions through December 31, 2020. The Partnership resumed all such contributions in 2021.

Pension and Other Postretirement Benefit Plans

Panhandle

Postretirement benefits expense for the years ended December 31, 2020, 2019, and 2018 reflect the impact of changes Panhandle or its affiliates adopted as of September 30, 2013, to modify its retiree medical benefits program, effective January 1, 2014. The modification placed all eligible retirees on a common medical benefit platform, subject to limits on Panhandle’s annual contribution toward eligible retirees’ medical premiums. Prior to January 1, 2013, affiliates of Panhandle offered postretirement health care and life insurance benefit plans (other postretirement plans) that covered substantially all employees. Effective

 

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January 1, 2013, participation in the plan was frozen and medical benefits were no longer offered to non-union employees. Effective January 1, 2014, retiree medical benefits were no longer offered to union employees.

Effective January 1, 2018, the plan was amended to extend coverage to a closed group of former employees based on certain criteria.

ETC Sunoco

ETC Sunoco has a plan which provides health care benefits for substantially all of its current retirees. The cost to provide the postretirement benefit plan is shared by ETC Sunoco. and its retirees. Access to postretirement medical benefits was phased out or eliminated for all employees retiring after July 1, 2010. ETC Sunoco has established a trust for its postretirement benefit liabilities. The funding of the trust eliminated substantially all of ETC Sunoco’s future exposure to variances between actual results and assumptions used to estimate retiree medical plan obligations.

SemGroup

SemGroup sponsors two defined benefit pension plans and a supplemental defined benefit pension plan (collectively, the “Semgroup Plans”) for certain employees. The Semgroup Plans are closed to new participants and do not accrue any additional benefits.

 

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Obligations and Funded Status

Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services. The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis:

 

     December 31, 2020     December 31, 2019  
     Pension Benefits           Pension Benefits        
     Funded
Plans
    Unfunded
Plans
    Other
Postretirement
Benefits
    Funded
Plans
    Unfunded
Plans
    Other
Postretirement
Benefits
 

Change in benefit obligation:

            

Benefit obligation at beginning of period

   $ 52   $ 34   $ 208   $ 1   $ 37   $ 198

Service cost

     —         —         1     —         —         1

Interest cost

     2     1     5     2     1     7

Benefits paid, net

     (2     (5     (16     (1     (7     (16

Actuarial (gain) loss and other

     5     1     10     4     —         18

Settlements

     (2     —         —         (4     —         —    

SemGroup Acquisition

     —         —         —         50     3     —    
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Benefit obligation at end of period

     55     31     208     52     34     208

Change in plan assets:

            

Fair value of plan assets at beginning of period

     43     —         270     1     —         241

Return on plan assets and other

     5     —         28     6     —         35

Employer contributions

     1     —         9     1     —         10

Benefits paid, net

     (2     —         (16     (1     —         (16

Settlements

     (2     —         —         (4     —         —    

SemGroup Acquisition

     —         —         —         40     —         —    
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Fair value of plan assets at end of period

     45     —         291     43     —         270
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Amount underfunded (overfunded) at end of period

   $ 10   $ 31   $ (83   $ 9   $ 34   $ (62
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Amounts recognized in the consolidated balance sheets consist of:

            

Non-current assets

   $ —       $ —       $ 108   $ —       $ —       $ 88

Current liabilities

     —         (4     (2     —         (5     (2

Non-current liabilities

     (10     (27     (23     (9     (29     (24
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
   $ (10   $ (31   $ 83   $ (9   $ (34   $ 62
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Amounts recognized in accumulated other comprehensive income (loss) (pre-tax basis) consist of:

            

Net actuarial gain (loss)

   $ —       $ 2   $ (18   $ —       $ 1   $ (5

Prior service cost

     —         —         21     —         —         40
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
   $ —       $ 2   $ 3   $ —       $ 1   $ 35
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets:

 

     December 31, 2020      December 31, 2019  
     Pension Benefits     

 

     Pension Benefits     

 

 
     Funded
Plans
     Unfunded
Plans
     Other
Postretirement
Benefits
     Funded
Plans
     Unfunded
Plans
     Other
Postretirement
Benefits
 

Projected benefit obligation

   $ 55    $ 31      N/A      $ 51    $ 34      N/A  

Accumulated benefit obligation

     55      31      208      52      34      208

Fair value of plan assets

     45      —          291      43      —          270

Components of Net Periodic Benefit Cost

 

     December 31, 2020      December 31, 2019  
     Pension
Benefits
     Other
Postretirement
Benefits
     Pension
Benefits
     Other
Postretirement
Benefits
 

Net periodic benefit cost:

           

Service cost

   $ —        $ 1    $ —        $ 1

Interest cost

     3      5      3      7

Expected return on plan assets

     (2      (11      (2      (10

Prior service cost amortization

     —          19      —          26
  

 

 

    

 

 

    

 

 

    

 

 

 

Net periodic benefit cost

   $ 1    $ 14    $ 1    $ 24
  

 

 

    

 

 

    

 

 

    

 

 

 

Assumptions

The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below:

 

     December 31, 2020     December 31, 2019  
     Pension
Benefits
    Other
Postretirement
Benefits
    Pension
Benefits
    Other
Postretirement
Benefits
 

Discount rate

     2.40     2.04     4.00     2.71

The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below:

 

     December 31, 2020     December 31, 2019  
     Pension
Benefits
    Other
Postretirement
Benefits
    Pension
Benefits
    Other
Postretirement
Benefits
 

Discount rate

     3.05     2.94     3.33     3.76

Expected return on assets:

        

Tax exempt accounts

     4.57     7.00     3.37     7.00

Taxable accounts

     —         4.75     —         4.75

The long-term expected rate of return on plan assets was estimated based on a variety of factors including the historical investment return achieved over a long-term period, the targeted allocation of plan assets and expectations concerning future returns in the marketplace for both equity and fixed income securities. Current market factors such as inflation and interest rates are evaluated before long-term market

 

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assumptions are determined. Peer data and historical returns are reviewed to ensure reasonableness and appropriateness.

The assumed health care cost trend weighted-average rates used to measure the expected cost of benefits covered by the plans are shown in the table below:

 

     December 31,  
     2020     2019  

Health care cost trend rate

     7.30     7.25

Rate to which the cost trend is assumed to decline (the ultimate trend rate)

     4.82     4.83

Year that the rate reaches the ultimate trend rate

     2027       2026  

Changes in the health care cost trend rate assumptions are not expected to have a significant impact on postretirement benefits.

Plan Assets

For the Panhandle plans, the overall investment strategy is to maintain an appropriate balance of actively managed investments with the objective of optimizing longer-term returns while maintaining a high standard of portfolio quality and achieving proper diversification. To achieve diversity within its other postretirement plan asset portfolio, Panhandle has targeted the following asset allocations: equity of 25% to 35%, fixed income of 65% to 75%.

The investment strategy of ETC Sunoco funded defined benefit plans is to achieve consistent positive returns, after adjusting for inflation, and to maximize long-term total return within prudent levels of risk through a combination of income and capital appreciation. The objective of this strategy is to reduce the volatility of investment returns and maintain a sufficient funded status of the plans. In anticipation of the pension plan termination, ETC Sunoco targeted the asset allocations to a more stable position by investing in growth assets and liability hedging assets.

The fair value of the pension plan assets by asset category at the dates indicated is as follows:

 

     Fair
Value Total
     Fair Value Measurements at December 31, 2020  
     Level 1      Level 2      Level 3  

Asset category:

           

Cash and cash equivalents

   $ 1    $ 1    $ —        $ —    

Mutual funds (1)

     20      20      —          —    

Fixed income securities

     24      —          24      —    
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 45    $ 21    $ 24    $ —  
  

 

 

    

 

 

    

 

 

    

 

 

 

 

  (1)

Comprised of approximately 100% equities as of December 31, 2020.

 

     Fair
Value Total
     Fair Value Measurements at December 31, 2019  
     Level 1      Level 2      Level 3  

Asset category:

           

Cash and cash equivalents

   $ 1    $ 1    $ —        $ —    

Mutual funds (1)

     19      19      —          —    

Fixed income securities

     23      —          23      —    
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 43    $ 20    $ 23    $ —    
  

 

 

    

 

 

    

 

 

    

 

 

 

 

  (1)

Comprised of approximately 100% equities as of December 31, 2019.

 

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The fair value of other postretirement plan assets by asset category at the dates indicated is as follows:

 

     Fair
Value Total
     Fair Value Measurements at December 31, 2020  
     Level 1      Level 2      Level 3  

Asset category:

           

Cash and cash equivalents

   $ 18    $ 18    $ —        $ —    

Mutual funds (1)

     202      202      —          —    

Fixed income securities

     71      —          71      —    
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 291    $ 220    $ 71    $ —  
  

 

 

    

 

 

    

 

 

    

 

 

 

 

  (1)

Primarily comprised of approximately 59% equities, 40% fixed income securities and 1% cash as of December 31, 2020.

 

     Fair
Value Total
     Fair Value Measurements at December 31, 2019  
     Level 1      Level 2      Level 3  

Asset category:

           

Cash and cash equivalents

   $ 14    $ 14    $ —        $ —    

Mutual funds (1)

     177      177      —          —    

Fixed income securities

     79      —          79      —    
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 270    $ 191    $ 79    $ —    
  

 

 

    

 

 

    

 

 

    

 

 

 

 

  (1)

Primarily comprised of approximately 59% equities, 40% fixed income securities and 1% cash as of December 31, 2019.

The Level 1 plan assets are valued based on active market quotes. The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines.

Contributions

We expect to contribute $6 million to pension plans and $8 million to other postretirement plans in 2021. The cost of the plans are funded in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes.

Benefit Payments

Panhandle and ETC Sunoco’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below:

 

Years

   Pension Benefits -
Funded Plans
     Pension Benefits -
Unfunded Plans
     Other
Postretirement Benefits
(Gross, Before
Medicare Part D)
 

2021

   $ 3    $ 5    $ 18

2022

     4      4      18

2023

     4      4      16

2024

     4      3      15

2025

     2      3      14

2026 - 2030

     12      9      58

The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (“Medicare Part D”) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.

 

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Panhandle does not expect to receive any Medicare Part D subsidies in any future periods.

 

15.

RELATED PARTY TRANSACTIONS:

ET-ETO Promissory Note

As of December 31, 2020 and 2019, ETO’s promissory note receivable from ET had an outstanding balance of $1.9 billion and $3.7 billion, respectively. ETO had a long-term intercompany payable to ET with a balance of $104 million as of December 31, 2019. The balance of the intercompany payable to ET was paid off in 2020. The outstanding promissory note receivable and intercompany payable are reflected on a net basis in the Partnership’s consolidated balance sheets.

Interest income attributable to the promissory note receivable from ET, included in other, net in our consolidated statements of operations, for the years ended December 31, 2020 and 2019 was $147 million and $184 million, respectively.

The Partnership also has related party transactions with several of its equity method investees. In addition to commercial transactions, these transactions include the provision of certain management services and leases of certain assets.

The following table summarizes the revenues from related companies on our consolidated statements of operations:

 

     Years Ended December 31,  
     2020      2019      2018  

Revenues from related companies

   $ 466    $ 492    $ 431

The following table summarizes the related company accounts receivable and accounts payable balances on our consolidated balance sheets:

 

     December 31,  
     2020      2019  

Accounts receivable from related companies:

     

ET

   $ —        $ 8

FGT

     12      50

Phillips 66

     30      36

Traverse Rover LLC

     —          42

Other

     37      31
  

 

 

    

 

 

 

Total accounts receivable from related companies

   $ 79    $ 167
  

 

 

    

 

 

 

Accounts payable to related companies:

     

ET

   $ 150    $ —    

Other

     27      31
  

 

 

    

 

 

 

Total accounts payable to related companies

   $ 177    $ 31
  

 

 

    

 

 

 

 

16.

REPORTABLE SEGMENTS:

Our reportable segments currently reflect the following segments, which conduct their business primarily in the United States:

 

   

intrastate transportation and storage;

 

   

interstate transportation and storage;

 

   

midstream;

 

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NGL and refined products transportation and services;

 

   

crude oil transportation and services;

 

   

investment in Sunoco LP;

 

   

investment in USAC; and

 

   

all other.

Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.

The investment in USAC segment reflects the results of USAC beginning April 2018, the date that the Partnership obtained control of USAC.

Revenues from our intrastate transportation and storage segment are primarily reflected in natural gas sales and gathering, transportation and other fees. Revenues from our interstate transportation and storage segment are primarily reflected in gathering, transportation and other fees. Revenues from our midstream segment are primarily reflected in natural gas sales, NGL sales and gathering, transportation and other fees. Revenues from our NGL and refined products transportation and services segment are primarily reflected in NGL sales and gathering, transportation and other fees. Revenues from our crude oil transportation and services segment are reflected in crude sales and gathering, transportation and other fees. Revenues from our investment in Sunoco LP segment are primarily reflected in refined product sales. Revenues from our investment in USAC segment are primarily reflected in gathering, transportation and other fees. Revenues from our all other segment are primarily reflected in natural gas sales.

We report Segment Adjusted EBITDA as a measure of segment performance. We define Segment Adjusted EBITDA as total Partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Segment Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA and consolidated Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. The use of Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.

 

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The following tables present financial information by segment:

 

     Years Ended December 31,  
     2020      2019      2018  

Revenues:

        

Intrastate transportation and storage:

        

Revenues from external customers

   $ 2,312    $ 2,749    $ 3,428

Intersegment revenues

     232      350      309
  

 

 

    

 

 

    

 

 

 
     2,544      3,099      3,737

Interstate transportation and storage:

        

Revenues from external customers

     1,841      1,941      1,664

Intersegment revenues

     20      22      18
  

 

 

    

 

 

    

 

 

 
     1,861      1,963      1,682

Midstream:

        

Revenues from external customers

     1,944      2,280      2,090

Intersegment revenues

     3,082      3,751      5,432
  

 

 

    

 

 

    

 

 

 
     5,026      6,031      7,522

NGL and refined products transportation and services:

        

Revenues from external customers

     8,501      9,920      10,119

Intersegment revenues

     2,012      1,721      1,004
  

 

 

    

 

 

    

 

 

 
     10,513      11,641      11,123

Crude oil transportation and services:

        

Revenues from external customers

     11,674      18,447      17,236

Intersegment revenues

     5      —          96
  

 

 

    

 

 

    

 

 

 
     11,679      18,447      17,332

Investment in Sunoco LP:

        

Revenues from external customers

     10,653      16,590      16,982

Intersegment revenues

     57      6      12
  

 

 

    

 

 

    

 

 

 
     10,710      16,596      16,994

Investment in USAC:

        

Revenues from external customers

     655      678      495

Intersegment revenues

     12      20      13
  

 

 

    

 

 

    

 

 

 
     667      698      508

All other:

        

Revenues from external customers

     1,374      1,608      2,073

Intersegment revenues

     464      81      155
  

 

 

    

 

 

    

 

 

 
     1,838      1,689      2,228

Eliminations

     (5,884      (5,951      (7,039
  

 

 

    

 

 

    

 

 

 

Total revenues

   $ 38,954    $ 54,213    $ 54,087
  

 

 

    

 

 

    

 

 

 

 

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     Years Ended December 31,  
     2020      2019      2018  

Cost of products sold:

        

Intrastate transportation and storage

   $ 1,478    $ 1,909    $ 2,665

Midstream

     2,598      3,577      5,145

NGL and refined products transportation and services

     7,139      8,393      8,462

Crude oil transportation and services

     8,838      14,832      14,384

Investment in Sunoco LP

     9,654      15,380      15,872

Investment in USAC

     82      91      67

All other

     1,527      1,504      2,006

Eliminations

     (5,829      (5,885      (6,998
  

 

 

    

 

 

    

 

 

 

Total cost of products sold

   $ 25,487    $ 39,801    $ 41,603
  

 

 

    

 

 

    

 

 

 

 

     Years Ended December 31,  
     2020      2019      2018  

Depreciation, depletion and amortization:

        

Intrastate transportation and storage

   $ 185    $ 184    $ 169

Interstate transportation and storage

     411      387      334

Midstream

     1,140      1,066      1,006

NGL and refined products transportation and services

     667      613      466

Crude oil transportation and services

     640      437      445

Investment in Sunoco LP

     189      181      167

Investment in USAC

     239      231      169

All other

     198      37      87
  

 

 

    

 

 

    

 

 

 

Total depreciation, depletion and amortization

   $ 3,669    $ 3,136    $ 2,843
  

 

 

    

 

 

    

 

 

 

 

     Years Ended December 31,  
     2020      2019      2018  

Equity in earnings (losses) of unconsolidated affiliates:

        

Intrastate transportation and storage

   $ 18    $ 18    $ 19

Interstate transportation and storage

     17      222      227

Midstream

     24      20      26

NGL and refined products transportation and services

     60      53      64

Crude oil transportation and services

     (2      (1      6

All other

     2      (10      2
  

 

 

    

 

 

    

 

 

 

Total equity in earnings of unconsolidated affiliates

   $ 119    $ 302    $ 344
  

 

 

    

 

 

    

 

 

 

 

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    Years Ended December 31,  
    2020     2019     2018  

Segment Adjusted EBITDA:

     

Intrastate transportation and storage

  $ 863   $ 999   $ 927

Interstate transportation and storage

    1,680     1,792     1,680

Midstream

    1,670     1,602     1,627

NGL and refined products transportation and services

    2,802     2,666     1,979

Crude oil transportation and services

    2,258     2,898     2,385

Investment in Sunoco LP

    739     665     638

Investment in USAC

    414     420     289

All other

    115     106     76
 

 

 

   

 

 

   

 

 

 

Total Segment Adjusted EBITDA

    10,541     11,148     9,601

Depreciation, depletion and amortization

    (3,669     (3,136     (2,843

Interest expense, net of interest capitalized

    (2,323     (2,262     (1,709

Impairment losses

    (2,880     (74     (431

Gains (losses) on interest rate derivatives

    (203     (241     47

Non-cash compensation expense

    (121     (113     (105

Unrealized losses on commodity risk management activities

    (71     (5     (11

Inventory valuation adjustments

    (82     79     (85

Losses on extinguishments of debt

    (72     (2     (109

Adjusted EBITDA related to unconsolidated affiliates

    (628     (626     (655

Equity in earnings of unconsolidated affiliates

    119     302     344

Impairment of investments in unconsolidated affiliates

    (129     —         —    

Adjusted EBITDA related to discontinued operations

    —         —         25

Other, net

    68     244     30
 

 

 

   

 

 

   

 

 

 

Income from continuing operations before income tax expense

    550     5,314     4,099

Income tax expense from continuing operations

    (239     (199     (5
 

 

 

   

 

 

   

 

 

 

Income from continuing operations

    311     5,115     4,094

Loss from discontinued operations, net of income taxes

    —         —         (265
 

 

 

   

 

 

   

 

 

 

Net income

  $ 311   $ 5,115   $ 3,829
 

 

 

   

 

 

   

 

 

 

 

    December 31,  
    2020     2019     2018  

Segment assets:

     

Intrastate transportation and storage

  $ 7,549   $ 6,648   $ 6,365

Interstate transportation and storage

    17,730     18,111     15,081

Midstream

    18,816     20,332     19,745

NGL and refined products transportation and services

    21,578     19,145     18,267

Crude oil transportation and services

    18,335     22,933     18,189

Investment in Sunoco LP

    5,267     5,438     4,879

Investment in USAC

    2,949     3,730     3,775

All other and eliminations

    4,518     5,957     2,308
 

 

 

   

 

 

   

 

 

 

Total segment assets

  $ 96,742   $ 102,294   $ 88,609
 

 

 

   

 

 

   

 

 

 

 

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    Years Ended December 31,  
    2020     2019     2018  

Additions to property, plant and equipment (1):

     

Intrastate transportation and storage

  $ 49   $ 124   $ 344

Interstate transportation and storage

    150     375     812

Midstream

    487     827     1,161

NGL and refined products transportation and services

    2,403     2,976     2,381

Crude oil transportation and services

    291     403     474

Investment in Sunoco LP

    124     148     103

Investment in USAC

    119     200     205

All other

    136     215     150
 

 

 

   

 

 

   

 

 

 

Total additions to property, plant and equipment(1)

  $ 3,759   $ 5,268   $ 5,630
 

 

 

   

 

 

   

 

 

 

 

(1)

Excluding acquisitions, net of contributions in aid of construction costs (capital expenditures related to the Partnership’s proportionate ownership on an accrual basis).

 

     December 31,  
     2020      2019      2018  

Investments in unconsolidated affiliates:

        

Intrastate transportation and storage

   $ 89    $ 88    $ 83

Interstate transportation and storage

     2,278      2,524      2,070

Midstream

     110      112      124

NGL and refined products transportation and services

     509      461      243

Crude oil transportation and services

     22      242      28

All other

     47      27      88
  

 

 

    

 

 

    

 

 

 

Total investments in unconsolidated affiliates

   $ 3,055    $ 3,454    $ 2,636
  

 

 

    

 

 

    

 

 

 

 

17.

QUARTERLY FINANCIAL DATA (UNAUDITED):

Summarized unaudited quarterly financial data is presented below.

 

     Quarters Ended         
     March 31     June 30      September 30 (1)     December 31      Total Year  

2020:

            

Revenues

   $ 11,627   $ 7,338    $ 9,955   $ 10,034    $ 38,954

Operating income

     65     1,342      248     1,344      2,999

Net income (loss)

     (914     719      (362     868      311

Net income (loss) attributable to partners

     (720     481      (530     627      (142

 

(1)

For the three months ended September 30, 2020, the net loss attributable to partners presented above reflects a change from the amount previously reported in the Partnership’s interim financial statements, due to an adjustment to the allocation of income between the general and limited partners and the noncontrolling interest in a less than wholly-owned subsidiary of the Partnership.

 

     Quarters Ended         
     March 31      June 30      September 30      December 31      Total Year  

2019:

              

Revenues

   $ 13,121    $ 13,877    $ 13,495    $ 13,720    $ 54,213

Operating income

     1,866      1,828      1,860      1,668      7,222

Income from continuing operations

     1,219      1,282      1,250      1,364      5,115

Net income

     1,219      1,282      1,250      1,364      5,115

Net income attributable to partners

     950      1,003      977      1,080      4,010

 

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PART II

Item 20. Indemnification of Directors and Officers.

As provided in ET’s Third Amended and Restated Agreement of Limited Partnership, as amended (the “Partnership Agreement”), ET will generally indemnify its general partner, officers, directors and affiliates of the general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events; provided, that the indemnitee will not be indemnified and held harmless if there has been a final and non-appealable judgement entered by a court of competent jurisdiction determining that, in respect of the matter for which the indemnitee is seeking indemnification, the indemnitee acted in bad faith or engaged in fraud, willful misconduct, or in the case of a criminal matter, acted with knowledge that the indemnitee’s conduct was unlawful. Subject to any terms, conditions or restrictions set forth in the Partnership Agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and against all claims and demands whatsoever subject to such standards and restrictions as are set forth in the Partnership Agreement.

To the extent that the indemnification provisions of the Partnership Agreement purport to include indemnification for liabilities arising under the Securities Act of 1933, as amended, in the opinion of the SEC, such indemnification is contrary to public policy and is therefore unenforceable.

ET also maintains insurance coverage under a policy insuring its directors and officers against certain liabilities which they may incur in their capacity as such.

Item 21. Exhibits

 

Exhibit
No.

  

Description

  2.1    Agreement and Plan of Merger, dated as of March 5, 2021, by and among Energy Transfer LP, Energy Transfer Operating, L.P. and ETO Merger Sub LLC (included as Annex A to the prospectus included in this Registration Statement on Form S-4).
  2.2    Agreement and Plan of Merger, dated as of February 16, 2021, by and among Energy Transfer LP, Elk Merger Sub LLC, Elk GP Merger Sub LLC, Enable Midstream Partners, LP, Enable GP, LLC, solely for the purpose of Section 2.1(a)(i), LE GP, LLC, and, solely for the purpose of Section 1.1(b)(i), CenterPoint Energy, Inc.
  3.1    Certificate of Limited Partnership of Energy Transfer Equity, L.P.
  3.2    Certificate of Amendment to Certificate of Limited Partnership of Energy Transfer LP.
  3.3    Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated February 8, 2006.
  3.4    Amendment No. 1 to the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated November 1, 2006.
  3.5    Amendment No. 2 to the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated November 9, 2007.
  3.6    Amendment No. 3 to the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated May 26, 2010.
  3.7    Amendment No. 4 to the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated December 23, 2013.

 

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Exhibit
No.

  

Description

  3.8    Amendment No. 5 to the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated March 8, 2016.
  3.9    Amendment No. 6 to the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated October 19, 2018.
  3.10    Amendment No. 7 to the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated as of August 6, 2019.
  3.11    Form of Amendment No. 8 to the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P. (included as Annex B to the prospectus included in this Registration Statement on Form S-4).
  5.1    Opinion of Latham & Watkins LLP as to the legality of the issuance of the preferred units of Energy Transfer LP.
  8.1    Opinion of Latham & Watkins LLP as to certain tax matters.
23.1    Consent of Grant Thornton LLP related to Energy Transfer LP.
23.2    Consent of Grant Thornton LLP related to Energy Transfer Operating, L.P.
23.3    Consent of Latham & Watkins LLP (included in Exhibit 5.1).
23.4    Consent of Latham & Watkins LLP (included in Exhibit 8.1).
24.1    Powers of Attorney (included on signature page contained in Part II of this Registration Statement on Form S-4).

Item 22. Undertakings

 

(a)

The undersigned registrant hereby undertakes:

 

  (1)

To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

 

   

to include any prospectus required by Section 10(a)(3) of the Securities Act of 1933;

 

   

to reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of a prospectus filed with the SEC pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than 20% change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement; and

 

   

to include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement.

 

  (2)

That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

 

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  (3)

To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

 

  (4)

That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

 

  (5)

That, for the purpose of determining liability of the registrant under the Securities Act of 1933 to any purchaser in the initial distribution of the securities, the undersigned registrant undertakes that in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

 

   

any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

 

   

any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

 

   

the portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

 

   

any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

 

(b)

The undersigned registrant hereby undertakes that, for purposes of determining any liability under the Securities Act of 1933, each filing of the registrant’s annual report pursuant to Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934 (and, where applicable, each filing of an employee benefit plan’s annual report pursuant to Section 15(d) of the Securities Exchange Act of 1934) that is incorporated by reference in the registration statement shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

 

(c)

The undersigned registrant hereby undertakes as follows: that prior to any public reoffering of the securities registered hereunder through use of a prospectus which is a part of this registration statement, by any person or party who is deemed to be an underwriter within the meaning of Rule 145(c), the issuer undertakes that such reoffering prospectus will contain the information called for by the applicable registration form with respect to reofferings by persons who may be deemed underwriters, in addition to the information called for by the other items of the applicable form.

 

(d)

The registrant undertakes that every prospectus (i) that is filed pursuant to the paragraph immediately preceding, or (ii) that purports to meet the requirements of Section 10(a)(3) of the Securities Act of 1933 and is used in connection with an offering of securities subject to Rule 415, will be filed as a part of an amendment to the registration statement and will not be used until such amendment is effective, and that, for purposes of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

 

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(e)

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act of 1933 and will be governed by the final adjudication of such issue.

 

(f)

The undersigned registrant hereby undertakes to respond to requests for information that is incorporated by reference into the prospectus pursuant to Item 4, 10(b), 11, or 13 of this Form, within one business day of receipt of such request, and to send the incorporated documents by first class mail or other equally prompt means. This includes information contained in documents filed subsequent to the effective date of the registration statement through the date of responding to the request.

 

(g)

The undersigned registrant hereby undertakes to supply by means of a post-effective amendment all information concerning a transaction, and the company being acquired involved therein, that was not the subject of and included in the registration statement when it became effective.

 

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this Registration Statement, or amendment thereto, to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Dallas, State of Texas, on March 5, 2021.

 

ENERGY TRANSFER LP
By:   LE GP, LLC, its General Partner

By:

  /s/ Thomas E. Long
 

Thomas E. Long

 

Co-Chief Executive Officer

KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints Thomas E. Long, Thomas P. Mason and William J. Healy, and each of them, any of whom may act without the joinder of the other, as his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution for him in any and all capacities, to sign any or all amendments or post-effective amendments to this Registration Statement, and to file the same, with exhibits hereto and other documents in connection therewith or in connection with the registration of the securities under the Securities Act of 1933, as amended, with the Securities and Exchange Commission, granting unto such attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary in connection with such matters and hereby ratifying and confirming all that such attorneys-in-fact and agents or his substitutes may do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed by the following persons in the capacities indicated, which are with LE GP, LLC, the general partner of Energy Transfer LP, on March 5, 2021.

 

Signature

  

Title

/s/ Kelcy L. Warren

Kelcy L. Warren

  

Executive Chairman

/s/ Marshall S. McCrea, III

Marshall S. McCrea, III

  

Co-Chief Executive Officer and Director
(Co-Principal Executive Officer)

/s/ Thomas E. Long

Thomas E. Long

  

Co-Chief Executive Officer and Director
(Co-Principal Executive Officer)

/s/ Bradford D. Whitehurst

Bradford D. Whitehurst

  

Chief Financial Officer
(Principal Financial Officer)

/s/ Matthew S. Ramsey

Matthew S. Ramsey

  

Chief Operating Officer and Director

/s/ A. Troy Sturrock

A. Troy Sturrock

  

Senior Vice President and Controller
(Principal Accounting Officer)

 

II-5


Table of Contents

Signature

  

Title

/s/ Steven R. Anderson

Steven R. Anderson

  

Director

/s/ Richard D. Brannon

Richard D. Brannon

  

Director

 

Ray C. Davis

  

Director

/s/ Michael K. Grimm

Michael K. Grimm

  

Director

/s/ John W. McReynolds

John W. McReynolds

  

Director

 

James R. Perry

  

Director

/s/ Ray W. Washburne

Ray W. Washburne

  

Director

 

II-6

EX-2.2

Exhibit 2.2

AGREEMENT AND PLAN OF MERGER

by and among

ENERGY TRANSFER LP,

ELK MERGER SUB LLC,

ELK GP MERGER SUB LLC,

ENABLE MIDSTREAM PARTNERS, LP

ENABLE GP, LLC,

AND

SOLELY FOR PURPOSES OF SECTION 2.1(a)(i),

LE GP, LLC

AND

SOLELY FOR PURPOSES OF Section 1.1(b)(i)

CENTERPOINT ENERGY, INC.

Dated as of February 16, 2021


TABLE OF CONTENTS

 

ARTICLE I.

 

THE MERGERS

 

Section 1.1

  Pre-Closing Transactions; The Mergers      2  

Section 1.2

  Closing      3  

Section 1.3

  Effective Time      3  

Section 1.4

  Effects of the Mergers      4  

Section 1.5

  Organizational Documents of the Surviving Entities      4  

Section 1.6

  Directors and Officers      4  
ARTICLE II.   
CONVERSION OF UNITS; EXCHANGE OF CERTIFICATES   

Section 2.1

  Effect of the Mergers      5  

Section 2.2

  Exchange of Certificates      7  

Section 2.3

  Withholding      9  
ARTICLE III.

 

REPRESENTATIONS AND WARRANTIES OF THE PARTNERSHIP AND THE GENERAL PARTNER

 

Section 3.1

  Qualification, Organization, Subsidiaries, etc.      10  

Section 3.2

  Capitalization      11  

Section 3.3

  Authority; Noncontravention      14  

Section 3.4

  Reports and Financial Statements      16  

Section 3.5

  Internal Controls and Procedures      16  

Section 3.6

  No Undisclosed Liabilities      17  

Section 3.7

  Compliance with Law; Permits      17  

Section 3.8

  Environmental Laws and Regulations      18  

Section 3.9

  Employee Benefit Plans      19  

Section 3.10

  Absence of Certain Changes or Events      21  

Section 3.11

  Investigations; Litigation      22  

Section 3.12

  Information Supplied      22  

Section 3.13

  Regulatory Matters      23  

Section 3.14

  Tax Matters      23  

Section 3.15

  Employment and Labor Matters      25  

Section 3.16

  Intellectual Property      26  

Section 3.17

  Real Property      26  

Section 3.18

  Insurance      28  

Section 3.19

  Opinion of Financial Advisor      28  

Section 3.20

  Material Contracts      28  

Section 3.21

  Finders or Brokers      29  

 

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Section 3.22

  State Takeover Statute      29  

Section 3.23

  Export Controls and Economic Sanctions.      30  

Section 3.24

  No Additional Representations or Warranties; Non-Reliance      31  
ARTICLE IV.

 

REPRESENTATIONS AND WARRANTIES OF PARENT, MERGER SUB AND GP MERGER SUB

 

Section 4.1

  Qualification, Organization, Subsidiaries, etc.      32  

Section 4.2

  Capitalization      34  

Section 4.3

  Authority; Noncontravention      36  

Section 4.4

  Reports and Financial Statements      38  

Section 4.5

  Internal Controls and Procedures      38  

Section 4.6

  No Undisclosed Liabilities      39  

Section 4.7

  Compliance with Law; Permits      39  

Section 4.8

  Environmental Laws and Regulations      40  

Section 4.9

  Employee Benefit Plans      41  

Section 4.10

  Absence of Certain Changes or Events      41  

Section 4.11

  Investigations; Litigation      41  

Section 4.12

  Information Supplied      41  

Section 4.13

  Regulatory Matters      42  

Section 4.14

  Tax Matters      42  

Section 4.15

  Employment and Labor Matters      44  

Section 4.16

  Real Property      44  

Section 4.17

  Insurance      46  

Section 4.18

  Material Contracts      46  

Section 4.19

  Finders or Brokers      47  

Section 4.20

  State Takeover Statute      47  

Section 4.21

  Export Controls and Economic Sanctions      47  

Section 4.22

  Availability of Funds      48  

Section 4.23

  No Additional Representations or Warranties; Non-Reliance      48  
ARTICLE V.

 

COVENANTS AND AGREEMENTS

 

Section 5.1

  Conduct of Business by the Partnership      49  

Section 5.2

  Conduct of Business by Parent      54  

Section 5.3

  Mutual Access      56  

Section 5.4

  Non-Solicitation      57  

Section 5.5

  Filings; Other Actions      58  

Section 5.6

  Equity-Based Awards      59  

Section 5.7

  Employee Matters      60  

Section 5.8

  Regulatory Approvals; Efforts      64  

Section 5.9

  Takeover Statutes      66  

Section 5.10

  Public Announcements      66  

 

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Section 5.11

  Indemnification and Insurance      66  

Section 5.12

  Control of Operations      69  

Section 5.13

  Section 16 Matters      69  

Section 5.14

  Tax Matters      69  

Section 5.15

  NYSE Listing      71  

Section 5.16

  Financing Assistance      71  

Section 5.17

  Obligations of Merger Subs and the Surviving Entities      74  

Section 5.18

  Termination of Certain Agreements      74  

Section 5.19

  Resignations      74  

Section 5.20

  Distributions      74  

Section 5.21

  Conflicts Committees      75  

Section 5.22

  Treatment of SESH      75  
ARTICLE VI.

 

CONDITIONS TO THE MERGERS

 

Section 6.1

  Conditions to Each Party’s Obligation to Effect the Mergers      75  

Section 6.2

  Conditions to Obligation of the Partnership to Effect the Mergers      76  

Section 6.3

  Conditions to Obligation of Parent to Effect the Mergers      77  

Section 6.4

  Frustration of Closing Conditions      78  
ARTICLE VII.

 

TERMINATION

 

Section 7.1

  Termination or Abandonment      78  

Section 7.2

  Effect of Termination      80  

Section 7.3

  Breakup Fee      80  
ARTICLE VIII.

 

MISCELLANEOUS

 

Section 8.1

  No Survival      81  

Section 8.2

  Expenses      81  

Section 8.3

  Counterparts; Effectiveness      81  

Section 8.4

  Governing Law      81  

Section 8.5

  Jurisdiction; Specific Enforcement      81  

Section 8.6

  WAIVER OF JURY TRIAL      82  

Section 8.7

  Notices      82  

Section 8.8

  Assignment; Binding Effect      84  

Section 8.9

  Severability      84  

Section 8.10

  Entire Agreement      84  

Section 8.11

  Amendments; Waivers      84  

Section 8.12

  Headings      85  

Section 8.13

  Third-Party Beneficiaries      85  

 

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Section 8.14

  Interpretation      85  

Section 8.15

  Definitions      86  

 

Exhibit A    Form of Registration Rights Agreement
Exhibit B    Sponsor Written Consent

 

- iv -


AGREEMENT AND PLAN OF MERGER

This AGREEMENT AND PLAN OF MERGER (this “Agreement”), dated as of February 16, 2021 is by and among Energy Transfer LP, a Delaware limited partnership (“Parent”), Elk Merger Sub LLC, a Delaware limited liability company and a direct wholly owned subsidiary of Parent (“Merger Sub”), Elk GP Merger Sub LLC, a Delaware limited liability company and a direct wholly owned subsidiary of Parent (“GP Merger Sub” and together with Merger Sub, the “Merger Subs”), Enable Midstream Partners, L.P., a Delaware limited partnership(the “Partnership”), Enable GP, LLC, a Delaware limited liability company (the “General Partner”), solely for the purposes of Section 2.1(a)(i), LE GP, LLC, a Delaware limited liability company and sole general partner of Parent (“Parent GP”), and, solely for purposes of Section 1.1(b)(i) herein, CenterPoint Energy, Inc., a Texas corporation (“Caribou”).

WITNESSETH:

WHEREAS, the parties intend that (i) Merger Sub be merged with and into the Partnership (the “LP Merger”), with the Partnership surviving the LP Merger as a wholly owned subsidiary of Parent, and (ii) GP Merger Sub be merged with and into the General Partner (the “GP Merger” and, together with the LP Merger, the “Mergers”), with the General Partner surviving the GP Merger as a direct wholly owned subsidiary of Parent;

WHEREAS, the Conflicts Committee (the “Conflicts Committee”) of the Board of Directors of the General Partner (the “GP Board”), by unanimous vote, in good faith, has, among other things, (a) determined that this Agreement and the transactions contemplated hereby, including the LP Merger, are in the best interests of the Partnership, its Subsidiaries and the holders of each common unit representing a limited partner interest in the Partnership (such units, collectively, “Partnership Common Units”) excluding the General Partner and its affiliates, (b) approved this Agreement and the transactions contemplated hereby, including the LP Merger (the foregoing constituting Special Approval (as defined in the Fifth Amended and Restated Agreement of Limited Partnership of the Partnership, dated as of November 14, 2017 (the “Partnership Agreement”)) and (c) recommended to the GP Board approval of this Agreement and the consummation of the transactions contemplated hereby, including the LP Merger;

WHEREAS, upon the receipt of such approval and recommendation of the Conflicts Committee, the GP Board has, by unanimous vote, in good faith, (a) determined that this Agreement and the transactions contemplated hereby, including the Mergers, are in the best interests of the Partnership, its Subsidiaries and, with respect to the GP Merger, the General Partner, (b) approved and declared advisable this Agreement and the transactions contemplated hereby, including the Mergers, (c) approved the execution, delivery and performance of this Agreement and the consummation of the transactions contemplated hereby, including the Mergers, and (d) authorized and directed that the approval of this Agreement and the transactions contemplated hereby be submitted to the Partnership’s unitholders to act by written consent pursuant to Section 13.11 of the Partnership Agreement;

WHEREAS, Parent has required, as a condition to its willingness to enter into this Agreement, that the Partnership and each of Caribou and OGE Energy Corp., an Oklahoma corporation (“Ox” and, together with Caribou, the “Sponsors”)), simultaneously herewith, enter into a Support Agreement, dated as of the date hereof (together, as may be amended, the “Support Agreements”);

 

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WHEREAS, the Board of Directors of Parent GP, has (a) determined that it is in the best interests of Parent and the unitholders of Parent, and declared it advisable, for Parent to enter into this Agreement and (b) approved this Agreement, the execution, delivery and performance of this Agreement and the consummation of the transactions contemplated hereby, including the Mergers;

WHEREAS, Parent, as the sole member of each of the Merger Subs, has determined that it is in the best interests of each Merger Sub, and declared it advisable, for each Merger Sub to enter into this Agreement, and has approved this Agreement, the execution, delivery and performance of this Agreement and the consummation of the transactions contemplated hereby, including the Mergers; and

WHEREAS, Parent, Merger Sub, GP Merger Sub, the Partnership and the General Partner desire to make certain representations, warranties, covenants and agreements specified herein in connection with this Agreement.

NOW, THEREFORE, in consideration of the foregoing and the representations, warranties, covenants and agreements contained herein, and intending to be legally bound hereby, Parent, Merger Sub, GP Merger Sub, the Partnership and the General Partner agree as follows:

ARTICLE I.

THE MERGERS

Section 1.1 Pre-Closing Transactions; The Mergers.

(a) Pre-Closing Transactions. Prior to the Effective Time, Parent shall cause the transactions set forth on Section 1.1(a) of the Parent Disclosure Schedule (collectively, the “Pre-Closing Transactions”) to occur.

(b) Preferred Contributions.

(i) Following the Pre-Closing Transactions and immediately prior to the Effective Time, Caribou shall contribute, assign, transfer, convey and deliver to Parent, and Parent shall acquire, assume, accept and receive from Caribou, all of Caribou’s right, title and interest in and to each 10% Series A Fixed-to-Floating Non-Cumulative Redeemable Perpetual Preferred Unit representing a limited partner interest in the Partnership (the “Series A Preferred Units”) issued and outstanding at such time in exchange for 0.0265 Series G Preferred Units issued by Parent per Series A Preferred Unit (the “Preferred Contribution and Issuance”).

 

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(ii) Immediately thereafter, but prior to the Effective Time, Parent shall contribute, assign, transfer, convey and deliver to a Subsidiary of Parent that is treated as a corporation for U.S. federal income tax purposes all (or, if less than all, a number of Series A Preferred Units with a principal amount equal to one percent of the then equity market capitalization of the Partnership) (the “Requisite Corporate Preferred Portion”) of such Series A Preferred Units (the “Preferred Corporate Contribution” together with the Preferred Contribution and Issuance, the “Preferred Contributions”).

(c) At the Effective Time, upon the terms and subject to the conditions set forth in this Agreement and in accordance with the applicable provisions of the Delaware Limited Liability Company Act (the “Delaware LLC Act”), GP Merger Sub shall be merged with and into the General Partner, whereupon the separate limited liability company existence of GP Merger Sub shall cease, and the General Partner shall continue its limited liability company existence under Delaware law as the surviving entity in the GP Merger (the “GP Surviving Entity”) and a direct wholly owned subsidiary of Parent.

(d) At the Effective Time, upon the terms and subject to the conditions set forth in this Agreement and in accordance with the applicable provisions of the Delaware Revised Uniform Limited Partnership Act (the “Delaware LP Act”) and the Delaware LLC Act, Merger Sub shall be merged with and into the Partnership, whereupon the separate limited liability company existence of Merger Sub shall cease, and the Partnership shall continue its limited partnership existence under Delaware law as the surviving entity in the LP Merger (the “Surviving Entity”) with all limited partner interests in the Surviving Entity owned directly and indirectly by Parent and all general partner interests in the Surviving Entity owned directly by the GP Surviving Entity.

Section 1.2 Closing. The closing of the Mergers (the “Closing”) shall take place at the offices of Latham & Watkins LLP (“Latham & Watkins”), 811 Main Street, Suite 3700, Houston, Texas 77002, at 10:00 a.m., local time, or remotely by exchange of documents and signatures (or their electronic counterparts) as soon as practicable on the second business day after the satisfaction or waiver (to the extent permitted by applicable Law) of the conditions set forth in Article VI (other than those conditions that by their nature are to be satisfied at the Closing, but subject to the satisfaction or waiver of such conditions), or at such other place, date and time as the Partnership and Parent may agree in writing. The date on which the Closing actually occurs is referred to as the “Closing Date.”

Section 1.3 Effective Time. On the Closing Date, (a) the General Partner shall file with the Secretary of State of the State of Delaware (the “Secretary of State”) a certificate of merger (the “GP Certificate of Merger”), executed in accordance with, and containing such information as is required by, the relevant provisions of the Delaware LLC Act in order to effect the GP Merger, and make any other filings or recordings as may be required by Delaware law in connection with the GP Merger, and (b) the Partnership shall file with the Secretary of State a certificate of merger (the “LP Certificate of Merger” and, together with the GP Certificate of Merger, the “Certificates of Merger”), executed in accordance with, and containing such information as is required by, the relevant provisions of the Delaware LP Act and the Delaware LLC Act in order to effect the LP Merger, and make any other filings or recordings as may be required by Delaware law in connection with the LP Merger. The Certificates shall be filed with the Secretary of State simultaneously and the Mergers shall become effective concurrently at the time of filing or at such later time as is agreed to by Parent and the Partnership and set forth in each of the GP Certificate of Merger and LP Certificate of Merger in accordance with the relevant provisions of the Delaware LLC Act and the Delaware LP Act (such date and time is hereinafter referred to as the “Effective Time”).

 

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Section 1.4 Effects of the Mergers. The effects of the Mergers shall be as provided in this Agreement and in the applicable provisions of the Delaware LLC Act and the Delaware LP Act. Without limiting the generality of the foregoing, and subject thereto, (a) at the Effective Time, all of the property, rights, privileges, powers and franchises of the General Partner and GP Merger Sub shall vest in the GP Surviving Entity, and all debts, liabilities and duties of the General Partner and GP Merger Sub shall become the debts, liabilities and duties of the GP Surviving Entity, all as provided under the Delaware LLC Act, and (b) at the Effective Time, all of the property, rights, privileges, powers and franchises of the Partnership and Merger Sub shall vest in the Surviving Entity, and all debts, liabilities and duties of the Partnership and Merger Sub shall become the debts, liabilities and duties of the Surviving Entity, all as provided under the Delaware LP Act and the Delaware LLC Act.

Section 1.5 Organizational Documents of the Surviving Entities.

(a) At the Effective Time, the certificate of formation of the General Partner, as in effect immediately prior to the Effective Time shall remain unchanged and shall be the certificate of formation of the GP Surviving Entity from and after the Effective Time until thereafter amended in accordance with the provisions thereof and applicable Law, in each case consistent with the obligations set forth in Section 5.11.

(b) At the Effective Time, the limited liability company agreement of the General Partner, as in effect immediately prior to the Effective Time, shall remain unchanged and shall be the limited liability company agreement of the GP Surviving Entity from and after the Effective Time until thereafter amended in accordance with the provisions thereof and applicable Law, in each case consistent with the obligations set forth in Section 5.11.

(c) At the Effective Time, the certificate of limited partnership of the Partnership, as in effect immediately prior to the Effective Time shall remain unchanged and shall be the certificate of limited partnership of the Surviving Entity from and after the Effective Time until thereafter amended in accordance with the provisions thereof and applicable Law, in each case consistent with the obligations set forth in Section 5.11.

(d) At the Effective Time, the partnership agreement of the Partnership, as in effect immediately prior to the Effective Time, shall remain unchanged and shall be the partnership agreement of the Surviving Entity from and after the Effective Time until thereafter amended in accordance with the provisions thereof and applicable Law, in each case consistent with the obligations set forth in Section 5.11.

Section 1.6 Directors and Officers. The persons listed on Section 1.6 of the Parent Disclosure Schedule shall be the initial directors and officers of the GP Surviving Entity and shall hold office until their respective successors are duly elected and qualified, or their earlier death, resignation or removal in accordance with the terms of the limited liability company agreement of the GP Surviving Entity.

 

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ARTICLE II.

CONVERSION OF UNITS; EXCHANGE OF CERTIFICATES

Section 2.1 Effect of the Mergers.

(a) Merger Consideration.

(i) LP Merger. Subject in each case to Section 2.1(h) and Section 2.1(i), at the Effective Time, by virtue of the LP Merger and without any action on the part of the parties or the holders of any securities of the parties, each Partnership Common Unit issued and outstanding immediately prior to the Effective Time (other than Cancelled Units) shall be converted into and shall thereafter represent the right to receive 0.8595 (the “Exchange Ratio”) Parent Common Units (the “LP Merger Consideration”). Upon the exchange of Partnership Common Units for the LP Merger Consideration in accordance with this Article II, each person that receives Parent Common Units shall be deemed to have made a capital contribution to Parent, shall be admitted as a limited partner of Parent and Parent GP hereby consents to such admission.

(ii) GP Merger. At the Effective Time, by virtue of the GP Merger and without any action on the part of the parties or the holders of any securities of the parties, (A) all of the limited liability company interests of the General Partner issued and outstanding as of immediately prior to the Effective Time shall be converted into and shall thereafter represent the right to receive $10,000,000 in the aggregate (the “GP Merger Consideration”), which shall be allocated among the members of the General Partner as set forth on Section 2.1(a)(ii) of the Partnership Disclosure Schedule and (B) Parent shall be admitted to the GP Surviving Entity, such that following the Effective Time, Parent shall be the sole member of the GP Surviving Entity. Payment of the GP Merger Consideration shall be made on the Closing Date by wire transfer of immediately available funds in the amounts and to the accounts set forth on Section 2.1(a)(ii) of the Partnership Disclosure Schedule.

(b) Treatment of Partnership Preferred Units. The Series A Preferred Units shall be unchanged and remain outstanding and wholly owned, directly and indirectly by Parent.

(c) Partnership Incentive Distribution Rights. In exchange for the transactions contemplated by the GP Merger, at the Effective Time, the Partnership Incentive Distribution Rights outstanding immediately prior to the Effective Time shall, by virtue of this Agreement and without any action on the part of the parties or the holder thereof, be automatically canceled and shall cease to exist.

(d) Partnership GP Interest. The Partnership GP Interest shall be unchanged and remain outstanding as a non-economic general partner interest in the GP Surviving Entity and the General Partner shall continue as the general partner of the Surviving Entity.

(e) Cancelled Units. At the Effective Time, each Partnership Common Unit that is held directly by Parent, Merger Sub or GP Merger Sub immediately prior to the Effective Time (such Partnership Common Units, the “Cancelled Units”) shall, by virtue of the LP Merger and without any action on the part of the holder thereof, be cancelled and retired and shall cease to exist, and no consideration shall be delivered in exchange for such cancellation and retirement.

 

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(f) Conversion of Merger Sub Interests. At the Effective Time, by virtue of the LP Merger and without any action on the part of the holder thereof, the limited liability company interests of Merger Sub issued and outstanding immediately prior to the Effective Time shall be converted into, in the aggregate, Partnership Common Units in an amount equal to the number of Partnership Common Units issued and outstanding immediately prior to the Effective Time pursuant to Section 2.1(a)(i) and the holder of the limited liability company interests of Merger Sub shall be admitted as a limited partner of the Surviving Entity.

(g) Conversion of GP Merger Sub Interests. At the Effective Time, by virtue of the GP Merger and without any action on the part of the holder thereof, the limited liability company interests of GP Merger Sub issued and outstanding immediately prior to the Effective Time shall be converted into 100% of the limited liability company interests of the GP Surviving Entity and the holder of the limited liability company interests of GP Merger Sub shall be admitted as a member of the GP Surviving Entity.

(h) No Fractional Units. No certificates or scrip representing fractional Parent Common Units shall be issued in the LP Merger. Notwithstanding any other provision of this Agreement, in lieu of receiving a fraction of a Parent Common Unit, all fractional Parent Common Units that a holder of Partnership Common Units would otherwise be entitled to receive pursuant to and in accordance with Section 2.1(a)(i) as LP Merger Consideration will be aggregated and then, if a fractional Parent Common Unit results from that aggregation, be rounded up to the nearest whole Parent Common Unit.

(i) Adjustments. If at any time during the period between the date of this Agreement and the Effective Time, any change in the outstanding Partnership Common Units or outstanding Parent Common Units shall occur by reason of the occurrence or record date of any unit dividend, subdivision, reclassification, recapitalization, split, split-up, unit distribution, combination, exchange of units or other similar transaction, the LP Merger Consideration, the Exchange Ratio and any other similarly dependent items shall be equitably adjusted to provide to Parent, Merger Sub and the holders of Partnership Common Units the same economic effect as contemplated by this Agreement prior to such action, and thereafter, all references in this Agreement to the LP Merger Consideration, the Exchange Ratio and any other similarly dependent items shall be references to the LP Merger Consideration, the Exchange Ratio and any other similarly dependent items as so adjusted; provided, however, that nothing in this Section 2.1(i) shall be deemed to permit or authorize any party hereto to effect any such change that it is not otherwise authorized or permitted to undertake pursuant to this Agreement.

(j) No Dissenters Rights. No dissenters’ or appraisal rights shall be available with respect to the LP Merger, GP Merger or the other transactions contemplated hereby.

 

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Section 2.2 Exchange of Certificates.

(a) Exchange Agent. Prior to the Closing Date, Parent shall appoint an exchange agent mutually acceptable to Parent and the Partnership (the “Exchange Agent”) for the purpose of exchanging Certificates for LP Merger Consideration. Prior to the Effective Time, Parent shall deposit, or shall cause to be deposited, with the Exchange Agent, in trust for the benefit of holders of the Partnership Common Units (other than the Cancelled Units), Parent Common Units (which shall be in non-certificated book-entry form) issuable pursuant to Article II sufficient to effect the delivery of the LP Merger Consideration to the holders of the Partnership Common Units (other than Cancelled Units). Following the Effective Time, Parent agrees to make available to the Exchange Agent, from time to time as needed, Parent Common Units issuable and cash sufficient to make any distributions pursuant to Section 2.2(c). All Parent Common Units and cash deposited with the Exchange Agent from time to time is hereinafter referred to as the “Exchange Fund.”

(b) Exchange Procedures. As soon as reasonably practicable after the Effective Time and in any event not later than the fifth business day following the Effective Time, Parent shall cause the Exchange Agent to mail to each holder of Partnership Common Units, which at the Effective Time were converted into the right to receive the LP Merger Consideration pursuant to Section 2.1(a)(i), (i) a letter of transmittal (which shall specify that delivery shall be effected, and that risk of loss and title to the Certificates shall pass, only upon surrender of the Certificates (including by delivery of the Partnership Common Units, book-entry notation, or affidavits of loss in lieu of delivery thereof as provided in Section 2.2(f)), to the Exchange Agent) and (ii) instructions for use in effecting the surrender of the certificates or book-entry notations representing Partnership Common Units (in each case, “Certificates”) in exchange for, the LP Merger Consideration and any distributions payable pursuant to Section 2.2(c). Upon surrender of Certificates for cancellation to the Exchange Agent, together with such letter of transmittal, duly completed and validly executed in accordance with the instructions thereto, and such other documents as may reasonably be required by the Exchange Agent, the holder of such Partnership Common Units shall be entitled to receive in exchange therefor (subject to withholding tax as specified in Section 2.3), as applicable, that number of whole Parent Common Units (after taking into account all Partnership Common Units surrendered by such holder) to which such holder is entitled pursuant to Section 2.1(a)(i) and a check in an amount equal to the aggregate amount of cash that such holder has a right to receive pursuant to Section 2.2(c) to which such holder is entitled, and the Partnership Common Units represented by the Certificates so surrendered shall forthwith be cancelled. If any cash payment is to be made to, or any Parent Common Units constituting any part of the LP Merger Consideration is to be registered in the name of, a person other than the person in whose name the applicable surrendered Partnership Common Unit is registered, it shall be a condition to the payment or registration thereof that the surrendered Certificate be in proper form for transfer and that the person requesting such payment or delivery of the LP Merger Consideration pay any transfer or other similar Taxes required as a result of such registration in the name of a person other than the registered holder of such Certificate or establish to the satisfaction of the Exchange Agent that such Tax has been paid or is not payable. Until surrendered as contemplated by this Section 2.2(b), each Certificate shall be deemed at any time after the Effective Time to represent only the right to receive the LP Merger Consideration (and any amounts to be paid pursuant to Section 2.2(c)) upon such surrender. No interest shall be paid or shall accrue on any amount payable pursuant to Section 2.2(c).

 

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(c) Distributions with Respect to Parent Common Units. All Parent Common Units to be issued pursuant to the LP Merger shall be deemed issued and outstanding as of the Effective Time and whenever a distribution is declared by Parent in respect of the Parent Common Units, the record date for which is at or after the Effective Time, that declaration shall include distributions in respect of all Parent Common Units to be issued pursuant to the LP Merger. No distributions with respect to Parent Common Units shall be paid to the holder of any unsurrendered Certificates with respect to the Partnership Common Units represented thereby until such Certificate has been surrendered in accordance with this Article II. Subject to applicable Laws, following surrender of any such Certificate, there shall be paid to the record holder thereof, without interest, (i) promptly after such surrender, the amount of distributions with a record date at or after the Effective Time and a payment date on or prior to the date of such surrender and not theretofore paid with respect to such Parent Common Units and (ii) at the appropriate payment date, the amount of distributions with a record date at or after the Effective Time and a payment date subsequent to the date of such surrender payable with respect to such Parent Common Units.

(d) No Further Ownership Rights in Partnership Common Units; Closing of Transfer Books. All LP Merger Consideration issued upon the surrender for exchange of Certificates representing Partnership Common Units in accordance with the terms of this Article II and any cash paid pursuant to Section 2.2(c) shall be deemed to have been issued (or paid) in full satisfaction of all rights pertaining to the Partnership Common Units previously represented by such Certificates. After the Effective Time, the transfer books of the Partnership shall be closed, and there shall be no further registration of transfers on the transfer books of the Surviving Entity of the Partnership Common Units that were outstanding immediately prior to the Effective Time. If, after the Effective Time, Certificates are presented to the Surviving Entity or the Exchange Agent for any reason, they shall be cancelled and exchanged as provided in this Article II.

(e) Termination of Exchange Fund. Any portion of the Exchange Fund (including the proceeds of any investments thereof) that remains undistributed to the former holders of Partnership Common Units for one year after the Effective Time shall be delivered to Parent upon demand, and any holders of Partnership Common Units who have not theretofore complied with this Article II shall thereafter look only to Parent for payment of their claim for the LP Merger Consideration and any distributions pursuant to Section 2.2(c). Any amounts remaining unclaimed by holders of Partnership Common Units immediately prior to such time as such amounts would otherwise escheat to or become the property of any federal, state of the United States, local, foreign, domestic, tribal or multinational government, regulatory or administrative agency, bureau, commission, commissioner, legislature, court, arbitrator, body, entity or other authority or governmental instrumentality (each, a “Governmental Entity”) will, to the extent permitted by applicable Law, become the property of Parent.

(f) Lost, Stolen or Destroyed Certificates. If any Certificate shall have been lost, stolen or destroyed, upon the making of an affidavit of that fact by the person claiming such Certificate to be lost, stolen or destroyed and, if required by Parent, the posting by such person of a bond, in such reasonable amount as Parent may direct, as indemnity against any claim that may be made against it with respect to such Certificate, the Exchange Agent will issue and pay in exchange for such lost, stolen or destroyed Certificate the LP Merger Consideration and distributions to be paid in respect of the Partnership Common Units represented by such Certificate as contemplated by this Article II.

 

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(g) No Liability. Notwithstanding anything in this Agreement to the contrary, none of the Partnership, the General Partner, Parent, Merger Sub, GP Merger Sub, the Surviving Entity, the GP Surviving Entity, the Exchange Agent or any other person shall be liable to any former holder of Partnership Common Units for any amount properly delivered to a public official pursuant to any applicable abandoned property, escheat or similar Law.

Section 2.3 Withholding. Each of Parent, Merger Sub, GP Merger Sub and the Exchange Agent shall be entitled to deduct and withhold from the consideration otherwise payable pursuant to this Agreement such amounts as Parent, Merger Sub, GP Merger Sub and the Exchange Agent are required to deduct and withhold under the Internal Revenue Code of 1986, as amended (the “Code”), or any Tax Law, with respect to the making of such payment (and to the extent deduction and withholding is required, such deduction and withholding may be taken in Parent Common Units). To the extent that amounts are so withheld and paid over to the applicable Governmental Entity, such withheld amounts shall be treated for all purposes of this Agreement as having been paid to the person in respect of whom such deduction and withholding was made. If withholding is taken in Parent Common Units, Parent, Merger Sub or the Exchange Agent (as applicable) shall be treated as having sold such Parent Common Units for an amount of cash equal to the fair market value of such Parent Common Units at the time of such deemed sale.

ARTICLE III.

REPRESENTATIONS AND WARRANTIES OF THE PARTNERSHIP AND THE GENERAL PARTNER

Except as disclosed in (a) the Partnership SEC Documents (excluding any disclosure set forth in any such Partnership SEC Document under the heading “Risk Factors” or in any section relating to forward-looking statements) or (b) the disclosure schedule delivered by the Partnership to Parent immediately prior to the execution of this Agreement (the “Partnership Disclosure Schedule”) each section of which qualifies the correspondingly numbered representation, warranty or covenant if specified therein (provided that (i) disclosure in any section of the Partnership Disclosure Schedule shall be deemed to be disclosed with respect to any other representations, warranties or covenants where its relevance as an exception to (or disclosure for purposes of) such other representation, warranty or covenant is reasonably apparent on the face of such disclosure notwithstanding the omission of a reference or a cross reference thereto and (ii) the mere inclusion of an item in such Partnership Disclosure Schedule as an exception to a representation or warranty shall not be deemed an admission that such item represents a material exception or material fact, event or circumstance or that such item has had, or would reasonably be expected to have a Partnership Material Adverse Effect), each of the Partnership and the General Partner, jointly and severally, represents and warrants to Parent, Merger Sub and GP Merger Sub as follows:

 

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Section 3.1 Qualification, Organization, Subsidiaries, etc.

(a) Each of the Partnership, the General Partner and their respective Subsidiaries is a legal entity duly organized or formed, validly existing and in good standing under the Laws of its jurisdiction of organization or formation and has all requisite limited partnership, limited liability company or other applicable power and authority to own, lease and operate its properties and assets and to carry on its business as presently conducted, except where the failure to have such power or authority would not have, individually or in the aggregate, a Partnership Material Adverse Effect. Each of the Partnership, the General Partner and their respective Subsidiaries is qualified to do business and is in good standing as a foreign entity in each jurisdiction where the ownership, leasing or operation of its assets or properties or conduct of its business requires such qualification, except where the failure to be so qualified or in good standing would not have, individually or in the aggregate, a Partnership Material Adverse Effect.

(b) As used in this Agreement, a “Partnership Material Adverse Effect” means an event, change, effect, development or occurrence that has had, or is reasonably likely to have, a material adverse effect on the business financial condition or continuing results of operations of the Partnership and its Subsidiaries, taken as a whole; provided, however, that none of the following, and no change, event, occurrence or effect, individually or in the aggregate, to the extent arising out of, resulting from or attributable to any of the following, shall constitute or be taken into account in determining whether a Partnership Material Adverse Effect has occurred or is reasonably likely to occur: any event, change, effect, development or occurrence (i) disclosed in the Partnership SEC Documents filed or furnished prior to the date of this Agreement (excluding any disclosure set forth in any risk factor section, in any section relating to forward-looking statements or in any disclosure related to litigation or regulatory matters that caveats the uncertainty or likelihood of any particular outcome or the general unpredictability of an outcome to such litigation or regulatory matter) or as disclosed in the Partnership Disclosure Schedule, (ii) in or generally affecting the economy, the financial or securities markets, or political, legislative or regulatory conditions, in each case in the United States or elsewhere in the world, including any changes in supply, demand, currency exchange rates, interest rates, tariff policy, monetary policy or inflation, so long as such event, change, effect, development or occurrence does not disproportionately affect the Partnership and its Subsidiaries, taken as a whole, relative to other similarly situated companies in the industries in which the Partnership and its Subsidiaries operate, or (iii) resulting from or arising out of (A) any changes or developments in the industries in which the Partnership or any of its Subsidiaries conducts its business, (B) any changes or developments in prices for oil, natural gas or other commodities or for the Partnership’s raw material inputs and end products, including general market prices and regulatory changes generally affecting the industries in which the Partnership and its Subsidiaries operate, (C) resulting from the negotiation, execution, announcement, pendency or the existence of, compliance with or performance under, this Agreement or the transactions contemplated hereby (including the impact thereof on the relationships, contractual or otherwise, of the Partnership or any of its Subsidiaries with employees, labor unions, customers, suppliers or partners, and including any lawsuit, action or other proceeding with respect to the Mergers or any of the other transactions contemplated by this Agreement), (D) any taking of any action required by this Agreement, the Support Agreements or at the request of Parent, Merger Sub or GP Merger Sub, (E) any adoption, implementation, promulgation, repeal, modification, reinterpretation or proposal of any rule, regulation, ordinance, order, protocol or any other Law of or by any national, regional, state or local Governmental Entity, or market administrator, (F) any changes in United States generally accepted accounting principles (“GAAP”) or accounting standards or interpretations thereof, (G)(1) earthquakes, any weather-related or other force majeure event, hurricanes, tsunamis, tornadoes, floods, mudslides, wildfires, pandemics (including the existence, response to and impact of the COVID-19 pandemic) or outbreak or other natural

 

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disasters or (2) hostilities or acts of war or terrorism, sabotage, civil disobedience, cyber-attack or any escalation or general worsening of the foregoing, (H) any failure by the Partnership to meet any internal or external projections, forecasts, estimates, milestones or budgets or financial or operating predictions of revenues, earnings or other financial or operating metrics for any period (provided that the exception in this clause (H) shall not prevent or otherwise affect a determination that any event, change, effect, development or occurrence underlying such failure has resulted in, or contributed to, a Partnership Material Adverse Effect so long as it is not otherwise excluded by this definition), or (I) any changes in the unit price or trading volume of the Partnership Common Units or in the Partnership’s credit rating (provided that the exception in this clause (I) shall not prevent or otherwise affect a determination that any event, change, effect, development or occurrence underlying such change has resulted in, or contributed to, a Partnership Material Adverse Effect so long as it is not otherwise excluded by this definition); except, in each case with respect to subclauses (A)-(B) and (E)-(G) of this clause (iii), to the extent disproportionately affecting the Partnership and its Subsidiaries, taken as a whole, relative to other similarly situated companies in the industries in which the Partnership and its Subsidiaries operate.

(c) The Partnership has made available to Parent prior to the date of this Agreement a true and complete copy of (i) the Certificate of Limited Partnership of the Partnership (the “Partnership Certificate of Limited Partnership” and, together with the Partnership Agreement, the “Partnership Organizational Documents”) and (ii) the Partnership Agreement, in each case, as amended through the date hereof, and promptly upon request by Parent, the Partnership will make available to Parent the certificate of incorporation, certificate of limited partnership, certificate of formation, bylaws, limited partnership agreement, limited liability company agreement or comparable constituent or organizational documents of each material Subsidiary of the Partnership.

Section 3.2 Capitalization.

(a) As of February 15, 2021, the issued and outstanding limited partner interests and general partner interests of the Partnership consisted of (A) 435,572,436 Partnership Common Units, (B) 14,520,000 Series A Preferred Units, (C) the Partnership Incentive Distribution Rights; and (D) the non-economic general partner interest (the “Partnership GP Interest”). All outstanding Partnership Common Units, Series A Preferred Units, Partnership Incentive Distribution Rights and the Partnership GP Interest are duly authorized, validly issued, fully paid (to the extent required by the Partnership Agreement) and nonassessable (except as such nonassessability may be affected by matters described in Sections 17-303, 17-607 and 17-804 of the Delaware LP Act) and free of preemptive rights (except as set forth in the Partnership Agreement and the GP Organizational Documents). As of February 15,, 2021, the issued and outstanding equity interests of the General Partner consisted of 1,000 economic units and 1,000 management units, each representing limited liability company interests in the General Partner, and all such economic units and management units have been duly authorized, and validly issued, and are fully paid and nonassessable (except as such nonassessability may be affected by matters described in Sections 18-607 and 18-804 of the Delaware LLC Act) and free of preemptive rights (except as set forth in the Partnership Agreement and the GP Organizational Documents).

 

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(b) As of February 15, 2021, there were (i) 1,697,980 outstanding Partnership Phantom Units (excluding long-term incentive awards held by Seconded Employees), (ii) 1,752,822 outstanding Partnership Performance Awards (assuming target level performance) and 3,505,644 outstanding Partnership Performance Awards (assuming maximum level performance), in each case excluding long-term incentive awards held by Seconded Employees, (iii) outstanding time-based, cash-settled long-term incentive awards held by Seconded Employees (“Seconded Employee Phantom Awards”) relating to 122,096 Partnership Common Units, and (iv) outstanding performance-based cash-settled long-term incentive awards held by Seconded Employees (“Seconded Employee Performance Awards”) relating to 149,559 Partnership Common Units (assuming target level performance) and 299,118 outstanding Partnership Common Units (assuming maximum level performance). Except as set forth in Section 3.2(a) and Section 3.2(b) of the Partnership Disclosure Schedule, there are no outstanding subscriptions, options, warrants, calls, convertible securities, exchangeable securities or other similar rights, agreements or commitments to which the Partnership, the General Partner or any of their respective Subsidiaries is a party (A) obligating the Partnership, the General Partner or any of their respective Subsidiaries to (v) issue, transfer, exchange, sell or register for sale any partnership interests, limited liability company interests or other equity interests of the Partnership, the General Partner or such Subsidiary or securities convertible into or exchangeable for such partnership interests, limited liability company interests or other equity interests, (w) grant, extend or enter into any such subscription, option, warrant, call, convertible securities or other similar right, agreement or arrangement, (x) redeem or otherwise acquire any such partnership interests, limited liability company interests or other equity interests, (y) provide a material amount of funds to, or make any material investment (in the form of a loan, capital contribution or otherwise) in, any Subsidiary or (z) make any payment to any person the value of which is derived from or calculated based on the value of Partnership Common Units or Series A Preferred Units, or (B) granting any preemptive or antidilutive or similar rights with respect to any security issued by the Partnership, General Partner or any of their respective Subsidiaries.

(c) Neither the Partnership, the General Partner nor any of their respective Subsidiaries has outstanding bonds, debentures, notes or other indebtedness, the holders of which have the right to vote (or which are convertible or exchangeable into or exercisable for securities having the right to vote) with the unitholders of the Partnership on any matter.

(d) Other than the Support Agreements, there are no voting trusts or other agreements or understandings to which the Partnership, the General Partner or any of their respective Subsidiaries is a party with respect to the voting or registration of partnership interests, limited liability company interests or other equity interests of the Partnership, the General Partner or any of their respective Subsidiaries.

(e) The Partnership or a Subsidiary of the Partnership owns, directly or indirectly, all of the issued and outstanding partnership interests, limited liability company interests or other equity interests of each Subsidiary of the Partnership, free and clear of any preemptive rights and any Liens other than Partnership Permitted Liens, and all of such partnership interests, limited liability company interests or other equity interests are duly authorized, validly issued, fully paid and nonassessable (except as such nonassessability may be affected by matters described in Sections 17-303, 17-607 and 17-804 of the Delaware LP Act, Sections 18-607 and 18-804 of the Delaware LLC Act or other similar Laws in any jurisdiction

 

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in which such Subsidiary is organized) and free of preemptive rights. Except for partnership interests, limited liability company interests or other equity interests in the Partnership’s Subsidiaries and except as set forth in Section 3.2(e) of the Partnership Disclosure Schedule, neither the General Partner, the Partnership nor any of its Subsidiaries owns, directly or indirectly, any partnership interest, limited liability company interest or other equity interest in any person (or any security or other right, agreement or commitment convertible or exercisable into, or exchangeable for, any partnership interest, limited liability company interest or other equity interest in any person), or has any obligation to acquire any such partnership interest, limited liability company interest or other equity interest, security, right, agreement or commitment or to provide funds to or make any investment (in the form of a loan, capital contribution or otherwise) in, any person.

(f) The General Partner is the sole general partner of the Partnership. The General Partner is the sole record and beneficial owner of the Partnership GP Interest and the Partnership Incentive Distribution Rights. The General Partner owns the Partnership GP Interest and the Partnership Incentive Distribution Rights free and clear of any Liens other than Partnership Permitted Liens. The General Partner has no assets, liabilities or obligations of any nature other than those incident to serving as the general partner of the Partnership.

(g) As used in this Agreement, “Partnership Permitted Lien” means (i) any Lien (A) for Taxes or governmental assessments, charges or claims of payment not yet delinquent, being contested in good faith and for which adequate accruals or reserves have been established, (B) that is a carriers’, warehousemen’s, mechanics’, materialmen’s, repairmen’s or other similar liens arising in the ordinary course of business, (C) arising under conditional sales contracts, tenders, statutory obligations, surety and appeals bonds, bids, government contracts, performance and return of money bonds, equipment leases and similar obligations, in each case so long as each of the aforementioned documents are with third parties entered into in the ordinary course of business, (D) not created by the Partnership or its Subsidiaries that affect the underlying fee interest of Partnership Leased Real Property, (E) that is disclosed on the most recent consolidated balance sheet of the Partnership included in the Partnership SEC Documents or notes thereto or securing liabilities reflected on such balance sheet, (F) arising under or pursuant to the Partnership Organizational Documents or the organizational documents of any Subsidiary of the Partnership, (G) created pursuant to the agreements set forth on Section 3.2(g) of the Partnership Disclosure Schedule, (H) which an accurate, up to date survey would show, (I) resulting from any facts or circumstances relating to Parent or its affiliates, or (J) that does not and would not reasonably be expected to materially impair the continued use of Partnership Owned Real Property or Partnership Leased Real Property as currently operated, taken as whole; (ii) grants to others of Rights-of-Way, surface leases, crossing rights and amendments, modifications, and releases of Rights-of-Way, easements and surface leases in the ordinary course of business; (iii) with respect to Rights-of-Way, restrictions on the exercise of any of the rights under a granting instrument that are set forth therein or in another executed agreement, that is of public record or to which the Partnership or any of its Subsidiaries otherwise has access, between the parties thereto; (iv) with respect to any Partnership Leased Real Property, Liens and other rights reserved by or in favor of any landlord under a Partnership Real Property Lease; or (v) zoning, entitlement, building and other land use regulations imposed by any Governmental Entity having jurisdiction over the Partnership Real Property, and not violated by the current use and operation of the Partnership Real Property.

 

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(h) As used in this Agreement, “Rights-of-Way” means easements, licenses, rights-of-way, permits, servitudes, leasehold estates, instruments creating an interest in real property, and other similar real estate interests.

Section 3.3 Authority; Noncontravention.

(a) Each of the Partnership and the General Partner has the requisite limited partnership or limited liability company power and authority, as applicable, to enter into this Agreement and, subject to the adoption of this Agreement by holders of a majority of the outstanding Partnership Common Units, voting as a single class, entitled to vote thereon (the “Requisite Unitholder Approval”), to consummate the transactions contemplated hereby. The execution, delivery and performance of this Agreement and the consummation of the transactions contemplated hereby, including the Mergers, have been duly and validly authorized by the GP Board on behalf of the Partnership and the General Partner and, except for the Requisite Unitholder Approval, no other actions or proceedings on the part of the Partnership are necessary to authorize the consummation of the transactions contemplated hereby. The Requisite Unitholder Approval represents the only vote or consent of the holders of any class or series of the Partnership’s limited partner interests or other equity securities necessary to approve the transactions contemplated hereby. This Agreement has been duly and validly executed and delivered by the Partnership and the General Partner, and, assuming this Agreement constitutes the legal, valid and binding agreement of the counterparties hereto, this Agreement constitutes the legal, valid and binding agreement of the Partnership and the General Partner and is enforceable against the Partnership and the General Partner in accordance with its terms, subject to bankruptcy, insolvency, fraudulent transfer, reorganization, moratorium and similar Laws of general applicability relating to or affecting creditors’ rights and to general equity principles (the “Equitable Exception”).

(b) Other than in connection with or in compliance with (i) the Delaware LP Act, (ii) the Delaware LLC Act, (iii) the Securities Exchange Act of 1934, as amended, and the rules promulgated thereunder (the “Exchange Act”), (iv) the Securities Act of 1933, as amended, and the rules promulgated thereunder (the “Securities Act”), (v) applicable state securities, takeover and “blue sky” laws, (vi) the filing of the Certificates of Merger with the Secretary of State, (vii) the rules and regulations of the New York Stock Exchange (the “NYSE”), (viii) the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and the rules and regulations promulgated thereunder (the “HSR Act”), (ix) rules and regulations of the Securities and Exchange Commission (the “SEC”) in connection with the filing with the SEC of a combined consent solicitation statement/prospectus in preliminary and definitive form in connection with the solicitation by the Partnership of written consents from the unitholders of the Partnership Common Units (the “Combined Consent Statement/Prospectus”), which shall include a form of consent that may be executed by the public unitholders of the Partnership Common Units in connection with the Requisite Unitholder Approval, and (x) the approvals set forth in Section 3.3(b) of the Partnership Disclosure Schedule (collectively, the “Partnership Approvals”), and, subject to the accuracy of the representations and warranties of Parent and each of the Merger Subs in Section 4.3(b), no authorization, consent, order, license, permit or approval of, or registration, declaration, notice or filing with, any Governmental Entity is necessary, under applicable Law, for the consummation by the Partnership or the General Partner of the transactions contemplated by this Agreement, except for such authorizations, consents, orders, licenses, permits, approvals or filings that are not required to be obtained or made prior to consummation of such transactions or that, if not obtained or made, would not materially impede or delay the consummation of the Mergers and the other transactions contemplated by this Agreement or have, individually or in the aggregate, a Partnership Material Adverse Effect.

 

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(c) The execution and delivery by the Partnership and the General Partner of this Agreement do not, and, assuming the Partnership Approvals are obtained, the consummation of the transactions contemplated hereby and compliance with the provisions hereof will not (i) result in any loss, or suspension, limitation or impairment of any right of the Partnership or any of its Subsidiaries (other than SESH) to own or use any assets required for the conduct of their business or result in any violation of, or default (with or without notice or lapse of time, or both) under, or give rise to a right of termination, cancellation or acceleration of any material obligation or to the loss of a material benefit under any loan, guarantee of indebtedness or credit agreement (except to the extent contemplated by the Partnership Credit Facilities), note, bond, mortgage, indenture, lease, agreement, contract, instrument, permit, or license binding upon the Partnership, the General Partner or any of their respective Subsidiaries (other than SESH) or result in the creation of any liens, claims, mortgages, encumbrances, covenants, conditions, restrictions, easements, pledges, security interests, or charges of any kind (each, a “Lien”) other than Partnership Permitted Liens, in each case, upon any of the properties or assets of the Partnership, the General Partner or any of their respective Subsidiaries (other than SESH), (ii) conflict with or result in any violation of any provision of the agreement of limited partnership, limited liability company agreement, certificate of incorporation or bylaws or other equivalent organizational document, in each case as amended or restated, of the Partnership, the General Partner or any of their respective Subsidiaries (other than SESH) or (iii) conflict with or violate any applicable Laws, except in the case of clauses (i) and (iii) for such losses, suspensions, limitations, impairments, conflicts, violations, defaults, terminations, cancellation, accelerations, or Liens as would not have, individually or in the aggregate, a Partnership Material Adverse Effect;

(d) Simultaneously with the execution of this Agreement, the Partnership and the General Partner have executed and delivered each of the Support Agreements;

(e) The Conflicts Committee, at a meeting duly called and held, by unanimous vote, in good faith, has, among other things, (i) determined that this Agreement and the transactions contemplated hereby, including the LP Merger, are in the best interests of the Partnership, its Subsidiaries and the holders of Partnership Common Units excluding the General Partner and its affiliates, (ii) approved this Agreement and the transactions contemplated hereby, including the LP Merger (the foregoing constituting Special Approval (as defined in the Partnership Agreement)) and (iii) recommended to the GP Board approval of this Agreement and the consummation of the transactions contemplated hereby, including the LP Merger; and

(f) The GP Board (acting, in part, based upon the receipt of the approval and recommendation of the Conflicts Committee), has, by unanimous vote, in good faith, among other things, (i) determined that this Agreement and the transactions contemplated hereby, including the Mergers, are in the best interests of the Partnership, its Subsidiaries and the General Partner (ii) approved and declared advisable this Agreement and the transactions contemplated hereby, including the Mergers, (iii) approved the execution, delivery and performance of this Agreement and the consummation of the transactions contemplated hereby, including the Mergers, and (iv) authorized and directed that the approval of this Agreement and the transactions contemplated hereby be submitted to the Partnership’s unitholders to act by written consent pursuant to Section 13.11 of the Partnership Agreement.

 

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Section 3.4 Reports and Financial Statements.

(a) The Partnership and each of its Subsidiaries has filed or furnished all forms, documents, reports, schedules certifications, prospectuses, registration and other statements required to be filed or furnished prior to the date hereof by it with the SEC since January 1, 2018 (collectively with all documents filed on a voluntary basis on Form 8-K, and in each case including all exhibits and schedules thereto and documents incorporated by reference therein, the “Partnership SEC Documents”). As of their respective dates or, if amended, as of the date of the last such amendment, the Partnership SEC Documents complied in all material respects with the requirements of the Securities Act and the Exchange Act, as the case may be, and the applicable rules and regulations promulgated thereunder, and none of the Partnership SEC Documents contained any untrue statement of a material fact or omitted to state any material fact required to be stated therein or necessary to make the statements therein, in light of the circumstances under which they were made, not misleading, except that information set forth in the Partnership SEC Documents as of a later date (but before the date of this Agreement) will be deemed to modify information as of an earlier date.

(b) The consolidated financial statements (including all related notes and schedules) of the Partnership included in the Partnership SEC Documents fairly present in all material respects the consolidated financial position of the Partnership and its consolidated Subsidiaries, as at the respective dates thereof (if amended, as of the date of the last such amendment), and the consolidated results of their operations and their consolidated cash flows for the respective periods then ended (subject, in the case of the unaudited statements, to normal year-end audit adjustments and to any other adjustments described therein, including the notes thereto) in conformity with GAAP (except, in the case of the unaudited statements, as permitted by the SEC) applied on a consistent basis during the periods involved (except as may be indicated therein or in the notes thereto).

Section 3.5 Internal Controls and Procedures. The Partnership has established and maintains disclosure controls and procedures and internal control over financial reporting (as such terms are defined in paragraphs (e) and (f), respectively, of Rule 13a-15 under the Exchange Act) as required by Rule 13a-15 under the Exchange Act. The Partnership’s disclosure controls and procedures are reasonably designed to ensure that all material information required to be disclosed by the Partnership in the reports that it files or furnishes under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and that all such material information is accumulated and communicated to the General Partner’s management as appropriate to allow timely decisions regarding required disclosure and to make the certifications required pursuant to Sections 302 and 906 of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”). The General Partner’s management has completed an assessment of the effectiveness of the Partnership’s internal control over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act for the year ended December 31, 2020, and such assessment concluded that

 

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such controls were effective. Based on its most recent evaluation of internal controls over financial reporting prior to the date hereof, management of the General Partner has disclosed to the Partnership’s auditors and the audit committee of the GP Board (i) any significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting that are reasonably likely to adversely affect in any material respect the Partnership’s ability to report financial information and (ii) any fraud, whether or not material, that involves management or other employees who have a significant role in the Partnership’s internal control over financial reporting, and each such deficiency, weakness and fraud so disclosed to auditors, if any, has been disclosed to Parent prior to the date hereof.

Section 3.6 No Undisclosed Liabilities. Except (a) as reflected or reserved against in the Partnership’s consolidated balance sheet as of September 30, 2020 (the “Balance Sheet Date”) (including the notes thereto) included in the Partnership SEC Documents, (b) for liabilities and obligations incurred under or in accordance with this Agreement or in connection with the transactions contemplated by this Agreement, (c) for liabilities and obligations incurred since the Balance Sheet Date in the ordinary course of business and (d) for liabilities and obligations that have been discharged or paid in full, neither the Partnership nor any Subsidiary of the Partnership has any liabilities or obligations of any nature, whether or not accrued, contingent or otherwise, that would be required by GAAP to be reflected on a consolidated balance sheet of the Partnership and its consolidated Subsidiaries (including the notes thereto), other than those that would not have, individually or in the aggregate, a Partnership Material Adverse Effect.

Section 3.7 Compliance with Law; Permits.

(a) The Partnership and its Subsidiaries are in compliance with, and are not in default under or in violation of, any applicable federal, state, local or foreign or multinational law, statute, ordinance, rule, regulation, judgment, order, injunction, decree or agency requirement of any Governmental Entity, including common law (collectively, “Laws” and each, a “Law”), except where such non-compliance, default or violation would not have, individually or in the aggregate, a Partnership Material Adverse Effect. Since January 1, 2018, neither the Partnership nor any of its Subsidiaries has received any written notice from any Governmental Entity regarding any actual or possible violation of, or failure to comply with, any Law, except as would not have, individually or in the aggregate, a Partnership Material Adverse Effect.

(b) The Partnership and its Subsidiaries are in possession of all franchises, grants, authorizations, licenses, permits, easements, variances, exceptions, consents, certificates, approvals, and orders of all applicable Governmental Entities, and all rights under any Partnership Material Contract with all Governmental Entities, and have filed all tariffs, reports, notices and other documents with all Governmental Entities necessary for the Partnership and its Subsidiaries to own, lease and operate their properties and assets and to carry on their businesses as they are now being conducted (the “Partnership Permits”), except where the failure to have obtained or filed any of the Partnership Permits would not have, individually or in the aggregate, a Partnership Material Adverse Effect. All Partnership Permits are valid and in full force and effect except where the failure to be in full force and effect, would not have, individually or in the aggregate, a Partnership Material Adverse Effect No administrative, judicial or other proceeding is pending or, to the knowledge of the Partnership, threatened, that could reasonably

 

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be expected to result in the adverse modification, suspension, termination, or cancellation of any Partnership Permit, except where such modification, suspension, termination or cancellation would not have, individually or in the aggregate, a Partnership Material Adverse Effect. The Partnership and each of its Subsidiaries is and, except for matters that have been fully resolved with the applicable Governmental Entity, since January 1, 2018 have been, in compliance with the terms and requirements of all Partnership Permits, except where the failure to be in compliance would not have, individually or in the aggregate, a Partnership Material Adverse Effect.

(c) Without limiting the generality of Section 3.7(a), the Partnership, each of its Subsidiaries, and, to the knowledge of the Partnership, each joint interest owner, consultant, agent, or representative of any of the foregoing (in their respective capacities as such), (i) has not violated the U.S. Foreign Corrupt Practices Act (the “FCPA”), and any other U.S. and foreign anti-corruption Laws that are applicable to the Partnership or its Subsidiaries; (ii) has not, to the knowledge of the Partnership, been given written notice by any Governmental Entity of any facts which, if true, would constitute a violation of the FCPA or any other U.S. or foreign anti-corruption Laws by any such person; and (iii) to the knowledge of the Partnership, is not being (and has not been) investigated by any Governmental Entity except, in each case of the foregoing clauses (i) through (iii), as would not have, individually or in the aggregate, a Partnership Material Adverse Effect.

Section 3.8 Environmental Laws and Regulations.

(a) Except as would not have, individually or in the aggregate, a Partnership Material Adverse Effect: (i) there are no investigations, actions, suits or proceedings (whether administrative or judicial) pending or, to the knowledge of the Partnership, threatened in writing against or affecting the Partnership, any of its Subsidiaries, or any of their respective assets or operations, or to the knowledge of the Partnership, against any person or entity whose liability the Partnership or any of its Subsidiaries has retained or assumed either contractually or by operation of law, alleging non-compliance with or other liability under any Environmental Law, (ii) the Partnership and its Subsidiaries are, and except for matters that have been fully resolved with the applicable Governmental Entity, since January 1, 2019 have been, in compliance with all Environmental Laws, (iii) there has been no release of Hazardous Materials at any Partnership Real Property or, to the knowledge of the Partnership, formerly owned, leased or operated by the Partnership or any Subsidiary of the Partnership that has given rise or could reasonably be expected to give rise to the Partnership or any Subsidiary of the Partnership incurring any remedial obligation or corrective action requirement under applicable Environmental Law, (iv) to the knowledge of the Partnership, no Hazardous Material has been disposed of or transported in violation of any applicable Environmental Law from any property currently or formerly owned, leased or operated by the Partnership or any Subsidiary of the Partnership or as a result of any operations or activities of the Partnership or any Subsidiary of the Partnership, (v) the Partnership is not party to any order or subject to any judgment or decree relating to compliance with Environmental Laws or the investigation, sampling, monitoring, treatment, remediation, removal or cleanup of Hazardous Materials that imposes any obligation on the Partnership or any of its Subsidiaries under any Environmental Law, (vi) there have been no ruptures or explosions in the Partnership’s Systems resulting in claims for personal injury, loss of life or material property damage, except to the extent any claims related to such ruptures or explosions have been fully resolved, and (vii) to the Partnership’s knowledge, there are no defects, corrosion or other damage to any of the Partnership’s Systems that would reasonably be expected to result in a pipeline integrity failure.

 

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(b) As used in this Agreement:

(i) “Environmental Law” means any Law relating to the protection, preservation or restoration of the environment (including air, surface water, groundwater, drinking water supply, surface land, subsurface land, plant and animal life or any other natural resource), pipeline safety, or any exposure to, release of, or the use, storage, recycling, treatment, generation, transportation, processing, handling, labeling, production or disposal of any Hazardous Materials, in each case as in effect as of the date of this Agreement.

(ii) “Hazardous Materials” means any substance, material or waste that is listed, defined, designated, classified, or regulated as hazardous, toxic, radioactive, or dangerous, or as a “pollutant” or “contaminant,” or words of similar meaning under any Environmental Law, including without limitation petroleum or any derivative or byproduct thereof, radon, radioactive material, asbestos or asbestos containing material, urea formaldehyde, foam insulation, polychlorinated biphenyls or per- and polyfluoroalkyl substances (PFAS).

(iii) “Systems” means the refined petroleum product, crude oil, natural gas, liquefied natural gas, natural gas liquid and other pipelines, lateral lines, pumps, pump stations, storage facilities, terminals, processing plants and other related operations, assets, machinery and equipment that are owned by the Partnership or Parent or any of their Subsidiaries, as applicable, and used for the conduct of the business of the Partnership or Parent or any of their Subsidiaries as presently conducted.

(c) Notwithstanding any other language in this Agreement, this Section 3.8 contains the Partnership’s sole representations with respect to Environmental Law or Hazardous Materials.

Section 3.9 Employee Benefit Plans.

(a) Section 3.9(a)(i) of the Partnership Disclosure Schedule lists all material Partnership Benefit Plans. With respect to each material Partnership Benefit Plan and each Seller Plan, the Partnership has made available to Parent complete and accurate copies of (A) such Partnership Benefit Plan, including any amendment thereto, (B) a written description of any such Partnership Benefit Plan if such plan is not set forth in a written document, (C) each trust, insurance, annuity or other funding Contract related thereto (if any), (D) the most recent audited financial statements and actuarial or other valuation reports prepared with respect thereto (if any), (E) the most recent Internal Revenue Service determination letter (if any), (F) the two most recent annual reports on Form 5500 required to be filed with the Internal Revenue Service with respect thereto (if any) and (G) all material correspondence to or from any Governmental Entity received in the last three years with respect to any such Partnership Benefit Plan. For

 

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purposes of this Agreement, (i) “Partnership Benefit Plans” means all Benefit Plans sponsored, maintained, contributed to or required to be contributed to by the Partnership, the General Partner or any of their Subsidiaries (other than SESH), or under which the Partnership, the General Partner or any of their Subsidiaries (other than SESH) has any material liability (contingent or otherwise), and (ii) “ERISA Affiliate” means, with respect to any person, trade or business, any other person, trade or business (whether or not incorporated), that together with such first person, trade or business, is, or was at a relevant time, treated as a single employer or under common control, in either case, under or within the meaning of Section 414(b), (c), (m) or (o) of the Code or Section 4001 of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”). Section 3.9(a)(ii) of the Partnership Disclosure Schedule lists all material Benefit Plans maintained, sponsored or contributed to by any holder of Partnership Common Units and in which any Partnership Employee currently participates as an active employee (the “Seller Plans”).

(b) Except as would not have, individually or in the aggregate, a Partnership Material Adverse Effect, (A) each Partnership Benefit Plan (and any related trust or other funding vehicle) has been maintained, operated and administered in compliance with its terms and with applicable Law, including ERISA and the Code to the extent applicable thereto, (B) all contributions required to be made under the terms of any Partnership Benefit Plan have been timely made or, if not yet due, have been properly reflected in the Partnership’s financial statements in accordance with GAAP, (C) each of the Partnership, the General Partner and their Subsidiaries (other than SESH) are in compliance in all material respects with ERISA, the Code and all other Laws applicable to Partnership Benefit Plans, and (D) any Partnership Benefit Plan intended to be qualified under Section 401(a) of the Code has received a favorable determination letter or equivalent opinion letter from the Internal Revenue Service, and the Partnership has made available to Parent a copy of the most recent such letter for each such Partnership Benefit Plan and, to the knowledge of the Partnership and the General Partner, nothing has occurred since the date of such determination or opinion letter that would reasonably be expected to adversely affect such qualification.

(c) Neither the Partnership, the General Partner nor any of their Subsidiaries (other than SESH) maintains, contributes to or is required to contribute to or has any liability to any plan or arrangement which provides retiree health, medical, life or other welfare benefits, except pursuant to the continuation coverage requirements of Section 601 et seq. of ERISA or Section 4980B of the Code.

(d) Except as set forth on Section 3.9(d) of the Partnership Disclosure Schedule, neither the Partnership, the General Partner nor their Subsidiaries (other than SESH) maintains, contributes to or is required to contribute to, or has any liability (including on behalf of or in respect of an ERISA Affiliate) with respect to, any Benefit Plan that is subject to Title IV or Section 302 of ERISA or Section 412 or 4971 of the Code or a multiemployer plan (as defined in Section 3(37) of ERISA).

(e) None of the Partnership Benefit Plans is a “multiple employer welfare arrangement” (as defined in Section 3(40) of ERISA) or a “multiple employer plan” (as defined in Section 413(c) of the Code).

 

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(f) Except as set forth in Section 5.6 and Section 5.7, the consummation of the transactions contemplated by this Agreement will not, either alone or in combination with another event, pursuant to any Partnership Benefit Plan (i) entitle any current or former employee, consultant, officer or other service provider of the Partnership, the General Partner or their Subsidiaries (or, to the knowledge of the Partnership and the General Partner, Seconded Employees), other than SESH, to severance pay, unemployment compensation or any other payment, (ii) accelerate the time of payment or vesting, or increase the amount of compensation due any such employee, consultant, officer or other service provider, (iii) trigger any payment or funding (through a grantor trust or otherwise) of compensation or benefits, or (iv) trigger any other material obligation, benefit (including loan forgiveness), requirement or restriction.

(g) No amount or benefit that would be, or has been, received (whether in cash or property or the vesting of property or the cancellation of indebtedness) by any current or former employee or other service provider of the Partnership, the General Partner or their Subsidiaries (other than SESH) who is a “disqualified individual” within the meaning of Section 280G of the Code would reasonably be expected to be characterized as an “excess parachute payment” (as defined in Section 280G(b)(1) of the Code) as a result of the consummation of the transactions contemplated by this Agreement.

(h) Except as would not have, individually or in the aggregate, a Partnership Material Adverse Effect, each Partnership Benefit Plan and any award thereunder that constitutes non-qualified deferred compensation under Section 409A of the Code has been operated and documented in all material respects in compliance with Section 409A of the Code. No director, officer, employee or service provider of the Partnership, the General Partner or their Subsidiaries (other than SESH) is entitled to a gross-up, make-whole, reimbursement or indemnification payment with respect to taxes imposed under Section 409A or Section 4999 of the Code.

(i) Except as would not have, individually or in the aggregate, a Partnership Material Adverse Effect, each Partnership Benefit Plan that provides benefits or compensation to any employees or other service providers who reside or provide services primarily outside of the United States has been registered, listed, administered, funded and maintained in good standing, as applicable, in accordance with its terms and all applicable Laws.

(j) Except as would not have, individually or in the aggregate, a Partnership Material Adverse Effect, there are no pending or, to the Partnership’s knowledge, threatened claims by or on behalf of any Partnership Benefit Plan, by any employee or beneficiary covered under any Partnership Benefit Plan or otherwise involving any Partnership Benefit Plan (other than routine claims for benefits).

Section 3.10 Absence of Certain Changes or Events.

(a) From the Balance Sheet Date through the date of this Agreement, except for discussions and activities pertaining to this Agreement and the transactions contemplated hereby, and except with respect to COVID-19 and any COVID-19 Actions, the businesses of the Partnership and its Subsidiaries (other than SESH) have been conducted in all material respects in the ordinary course of business.

 

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(b) From the Balance Sheet Date through the date of this Agreement, there has not been a Partnership Material Adverse Effect.

(c) From the date of this Agreement, there has not been a Partnership Material Adverse Effect.

Section 3.11 Investigations; Litigation. Except as would not, individually or in the aggregate, have a Partnership Material Adverse Effect, (a) there is no investigation or review pending (or, to the knowledge of the Partnership, threatened) by any Governmental Entity with respect to the Partnership or any of its Subsidiaries, (b) there are no actions, suits, inquiries, investigations, proceedings, subpoenas, civil investigative demands or other requests for information relating to potential violations of law pending (or, to the knowledge of the Partnership, threatened) against or affecting the Partnership or any of its Subsidiaries, or any of their respective assets or operations, and (c) there are no orders, judgments or decrees of, or before, any Governmental Entity against or affecting the Partnership or any of its Subsidiaries or any of their respective assets or operations; provided, that to the extent any such representations or warranties in the foregoing clauses (a), (b) and (c) pertain to investigations, reviews, actions, suits, inquiries, proceedings, subpoenas, civil investigative demands, other requests, orders, judgements or decrees that relate to the execution, delivery, performance or consummation of this Agreement or any of the transactions contemplated by this Agreement, such representations and warranties are made only as of the date hereof.

Section 3.12 Information Supplied. None of the information provided in writing by the Partnership specifically for inclusion or incorporation by reference in (a) the registration statement on Form S-4 to be filed with the SEC by Parent in connection with the issuance of Parent Common Units in the LP Merger and in which the Combined Consent Statement/Prospectus will be included as a prospectus (including any amendments or supplements, the “Form S-4”) will, at the time the Form S-4 is filed with the SEC and becomes effective under the Securities Act, contain any untrue statement of a material fact or omit to state any material fact required to be stated therein or necessary to make the statements therein, in light of the circumstances in which they are made, not misleading or (b) the Combined Consent Statement/Prospectus will, on the date it is first mailed to the Partnership’s unitholders, contain any untrue statement of a material fact or omit to state any material fact required to be stated therein or necessary in order to make the statements therein, in light of the circumstances under which they were made, not misleading. The Combined Consent Statement/Prospectus and the Form S-4 (solely with respect to the portion thereof based on information supplied by the Partnership or the General Partner or any of their respective Subsidiaries for inclusion or incorporation by reference therein, but excluding any portion thereof based on information supplied by or on behalf of Parent or the Merger Subs for inclusion or incorporation by reference therein, with respect to which no representation is made by the Partnership or any of its Subsidiaries) will comply as to form in all material respects with the requirements of the Securities Act and the Exchange Act. Notwithstanding the foregoing provisions of this Section 3.12, no representation or warranty is made by the Partnership with respect to information or statements made or incorporated by reference in the Form S-4 or the Combined Consent Statement/Prospectus that were not specifically supplied in writing by or on behalf of the Partnership.

 

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Section 3.13 Regulatory Matters.

(a) Except as would not, individually or in the aggregate, have a Partnership Material Adverse Effect, there are no proceedings pending, or to the knowledge of Partnership, threatened in writing, alleging that Partnership or any of its Subsidiaries is in material violation of the Natural Gas Act, 15 U.S.C. § 717, et seq. (the “NGA”), the Natural Gas Policy Act of 1978, 15 U.S.C. § 3301, et seq. (the “NGPA”), the Interstate Commerce Act, 49 U.S.C. App. § 1, et seq. (1988) (the “ICA”), the Federal Power Act, 16 U.S.C. § 791a, et seq. (the “FPA”), or the Public Utility Holding Company Act of 2005, 42 U.S.C. §§ 16451-16453 (“PUHCA”), or the rules and regulations promulgated thereunder, or the laws, rules and regulations of any state public utility commission or department in a state within which the Partnership or any of its Subsidiaries operates, as the case may be.

(b) Except as would not, individually or in the aggregate, have a Partnership Material Adverse Effect, all filings (other than immaterial filings) required to be made by the Partnership or any of its Subsidiaries during the three years preceding the date hereof, with the (i) Federal Energy Regulatory Commission (“FERC”) under the NGA, the NGPA, the ICA, the FPA, PUHCA, or the rules and regulations promulgated thereunder, (ii) the Department of Energy, (iii) the Federal Communications Commission (the “FCC”), or (iv) any state public utility commission or department in a state within which the Partnership or any of its Subsidiaries operates, as the case may be, have been made, including all forms, statements, reports, notices, agreements and all documents, exhibits, amendments and supplements appertaining thereto, including all rates, tariffs and related documents, and all such filings complied, as of their respective dates, and, as amended or supplemented, with all applicable requirements of applicable statutes and the rules and regulations promulgated thereunder.

Section 3.14 Tax Matters. Except as would not have, individually or in the aggregate, a Partnership Material Adverse Effect:

(a) all Tax Returns that were required to be filed by or with respect to the General Partner, the Partnership or any of the Partnership’s Subsidiaries have been duly and timely filed, and all such Tax Returns are complete and accurate;

(b) all Taxes owed by the General Partner, the Partnership or any of the Partnership’s Subsidiaries, or for which the General Partner, the Partnership or any such Subsidiaries may be liable, that are or have become due have been timely paid in full or an adequate reserve for the payment of such Taxes has been established;

(c) all Tax withholding and deposit requirements imposed on or with respect to the General Partner, the Partnership or any of the Partnership’s Subsidiaries have been satisfied in full in all respects;

(d) there are no Liens (other than Partnership Permitted Liens) on any of the assets of the General Partner, the Partnership or any of the Partnership’s Subsidiaries that arose in connection with any failure (or alleged failure) to pay any Tax;

 

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(e) there are no audits, examinations, investigations or other proceedings pending or threatened in writing in respect of Taxes or Tax matters of the General Partner, the Partnership or any of the Partnership’s Subsidiaries;

(f) there is no written claim against the General Partner, the Partnership or any of the Partnership’s Subsidiaries for any Taxes, and no assessment, deficiency or adjustment has been asserted, proposed, or threatened in writing with respect to any Tax Return of or with respect to the General Partner, the Partnership or any such Subsidiaries;

(g) no claim has ever been made by an authority in a jurisdiction where the General Partner, the Partnership or any of the Partnership’s Subsidiaries does not file Tax Returns that the General Partner, the Partnership or such Subsidiary is or may be subject to taxation in that jurisdiction;

(h) there is not in force any extension of time (other than customary extensions) with respect to the due date for the filing of any Tax Return of or with respect to the General Partner, the Partnership or any of the Partnership’s Subsidiaries or any waiver or agreement for any extension of time for the assessment or payment of any Tax of or with respect to any of the General Partner, the Partnership or any such Subsidiaries;

(i) none of the General Partner, the Partnership or any of the Partnership’s Subsidiaries will be required to include any amount in income for any taxable period as a result of a change in accounting method or adjustment under Section 482 of the Code for any taxable period ending on or before the Closing Date, pursuant to any agreement with any Tax authority with respect to any such taxable period, or as a result of an intercompany transaction, an installment sale or open transaction disposition entered into on or prior to the Closing Date, or the cash method of accounting or long-term contract method of accounting utilized prior to the Closing Date;

(j) none of the General Partner, the Partnership or any of the Partnership’s Subsidiaries is a party to a Tax allocation or sharing agreement, and no payments are due or will become due by the General Partner, Partnership or any such Subsidiaries pursuant to any such agreement or arrangement or any Tax indemnification agreement;

(k) none of the General Partner, the Partnership or any of the Partnership’s Subsidiaries has been a member of an affiliated, combined, consolidated, unitary or similar group with respect to Taxes (including any affiliated group within the meaning of Section 1504 of the Code and any similar group under state, local or non-U.S. law) or has any liability for the Taxes of any person (other than the General Partner, the Partnership or any such Subsidiaries), as a transferee or successor, by contract, or otherwise (other than Taxes arising in ordinary course commercial arrangements not primarily related to Taxes);

(l) none of the General Partner, the Partnership or any of the Partnership’s Subsidiaries has participated in a “listed transaction” within the meaning of Treasury Regulation Section 1.6011-4;

(m) the General Partner, the Partnership and each of the Partnership’s Subsidiaries that is classified as a partnership for U.S. federal income tax purposes has in effect a valid election under Section 754 of the Code;

 

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(n) each of the General Partner and the Partnership is properly classified as a partnership for U.S. federal income tax purposes, and not as an association or a publicly traded partnership taxable as a corporation under Section 7704 of the Code, and has been properly treated as such since its formation; and

(o) neither the General Partner nor the Partnership is aware of the existence of any fact, or has taken or agreed to take any action, that could reasonably be expected to prevent or impede the Mergers, taken together, from properly being treated in accordance with the Intended Tax Treatment for U.S. federal income tax purposes.

Notwithstanding any other language in this Agreement, Section 3.9 and Section 3.14 contain the Partnership’s sole representations with respect to Tax matters.

Section 3.15 Employment and Labor Matters

(a) Except as set forth on Section 3.15(a) of the Partnership Disclosure Schedule, (i) neither the Partnership, the General Partner nor any of their Subsidiaries is a party to or bound by any collective bargaining or similar agreement with any labor union, labor organization or employee association applicable to employees of, or individuals who provide services primarily with respect to, the Partnership, the General Partner or any of their Subsidiaries, (ii) there are no existing or, to the knowledge of the Partnership, threatened strikes or lockouts with respect to any employees of, or individuals who provide services primarily with respect to, the Partnership, the General Partner or any of their Subsidiaries, (iii) to the knowledge of the Partnership, there is no union organizing effort pending or threatened with respect to any employees of the Partnership, the General Partner, or their respective Subsidiaries (such individuals, other than the Seconded Employees, are referred to herein as the “Partnership Employees”) or the Seconded Employees, (iv) there is no unfair labor practice, labor dispute (other than, in each case, routine individual grievances) or labor arbitration proceeding pending or, to the knowledge of the Partnership, threatened with respect to Partnership Employees or, to the knowledge of the Partnership and the General Partner, the Seconded Employees and (v) there is no slowdown or work stoppage in effect or, to the knowledge of the Partnership, threatened with respect to Partnership Employees or individuals who provide services primarily with respect to the Partnership or, to the knowledge of the Partnership and the General Partner, the Seconded Employees, the General Partner or any of their respective Subsidiaries. The Seconded Employees are not covered by any collective bargaining or similar agreement with any labor union, labor organization or similar employee association.

(b) Except for such matters that would not, individually or in the aggregate, have a Partnership Material Adverse Effect, the Partnership, the General Partner and their Subsidiaries are, and for the past three years have been, in compliance with all applicable Laws respecting (i) employment and employment practices, (ii) terms and conditions of employment and wages and hours, and (iii) unfair labor practices. Neither the Partnership, the General Partner nor any of their Subsidiaries has any material liabilities under the Worker Adjustment and Retraining Notification Act of 1998 as a result of any action taken in the past three years.

 

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Section 3.16 Intellectual Property.

(a) Except as would not have, individually or in the aggregate, a Partnership Material Adverse Effect, either the Partnership or a Subsidiary of the Partnership owns, or is licensed or otherwise possesses subsisting rights to use, free and clear of Liens other than Partnership Permitted Liens, all trademarks, trade names, service marks, service names, mark registrations, logos, assumed names, domain names, registered and unregistered copyrights, patents or applications and registrations, trade secrets and other intellectual property rights used in and necessary to their respective businesses as currently conducted (collectively, the “Partnership Intellectual Property”). Except as would not have, individually or in the aggregate, a Partnership Material Adverse Effect, (i) there are no pending or, to the knowledge of the Partnership, threatened claims by any person alleging infringement, misappropriation or other violation by the Partnership or any of its Subsidiaries of any intellectual property rights of any person, (ii) to the knowledge of the Partnership, the conduct of the business of the Partnership and its Subsidiaries does not infringe, misappropriate or otherwise violate any intellectual property rights of any person, (iii) neither the Partnership nor any of its Subsidiaries has made any claim of a violation, infringement or misappropriation by others of the Partnership’s or any its Subsidiaries’ rights to Partnership Intellectual Property that is owned by the Partnership or a Subsidiary of the Partnership, and (iv) to the knowledge of the Partnership, no person is infringing, misappropriating or otherwise violating any Partnership Intellectual Property that is owned by the Partnership or a Subsidiary of the Partnership.

(b) Except as would not have, individually or in the aggregate, a Partnership Material Adverse Effect, the Partnership and its Subsidiaries have implemented (i) commercially reasonable measures, consistent with industry standards, to protect the confidentiality, integrity and security of the IT Assets (and all information and transactions stored or contained therein or transmitted thereby); and (ii) commercially reasonable data backup, data storage, system redundancy and disaster avoidance and recovery procedures, as well as a commercially reasonable business continuity plan, in each case consistent with customary industry practices.

(c) As used in this Agreement, “IT Assets” means the computers, servers, routers, hubs, switches, circuits, networks, data communications lines and all other information technology infrastructure and equipment owned or controlled by the Partnership and its Subsidiaries that are required in connection with the operation of the business of the Partnership and its Subsidiaries.

Section 3.17 Real Property.

(a) Except as would not have, individually or in the aggregate, a Partnership Material Adverse Effect, (i) either the Partnership or a Subsidiary of the Partnership has good and valid title to each material real property (and each real property at which material operations of the Partnership or any of its Subsidiaries are conducted) owned by the Partnership or any Subsidiary, other than Partnership Real Property Leases and Rights-of-Way (such owned real property collectively, the “Partnership Owned Real Property”) and (ii) either the Partnership or a Subsidiary of the Partnership has a good and valid leasehold interest in each material lease, sublease and other agreement under which the Partnership or any of its Subsidiaries uses or occupies or has the right to use or occupy any material real property (or real property at which material operations of the Partnership or any of its Partnership are conducted) (any property subject to such lease, sublease or other agreement, the “Partnership Leased Real Property”;

 

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together with the Partnership Owned Real Property, collectively, the “Partnership Real Property” and such leases, subleases and other agreements are, collectively, the “Partnership Real Property Leases”), in each case, free and clear of all Liens other than any Partnership Permitted Liens, and other than any conditions, encroachments, easements, rights-of-way, restrictions and other encumbrances that do not adversely affect the existing use of the real property subject thereto by the owner (or lessee to the extent a leased property) thereof in the operation of its business (“Permitted Encumbrances”). Except as would not have, individually or in the aggregate, a Partnership Material Adverse Effect, (A) each Partnership Real Property Lease is valid, binding and in full force and effect in accordance with its terms, subject to the limitation of such enforcement by (i) the effect of bankruptcy, insolvency, reorganization, receivership, conservatorship, arrangement, moratorium or other Laws affecting or relating to creditors’ rights generally or (ii) the rules governing the availability of specific performance, injunctive relief or other equitable remedies and general principles of equity, regardless of whether considered in a proceeding in equity or at law (the “Remedies Exceptions”) and (B) no uncured default of a material nature on the part of the Partnership or, if applicable, its Subsidiary or, to the knowledge of the Partnership, the lessor thereunder, exists under any Partnership Real Property Lease, and to the knowledge of the Partnership, no event has occurred or circumstance exists that, with the giving of notice, the passage of time, or both, would constitute a material breach or default under a Partnership Real Property Lease.

(b) Except as would not have, individually or in the aggregate, a Partnership Material Adverse Effect, (i) there are no leases, subleases, licenses, rights or other agreements affecting any portion of the Partnership Owned Real Property or the Partnership Leased Real Property that would reasonably be expected to adversely affect the existing use of such Partnership Owned Real Property or Partnership Leased Real Property by the Partnership or its Subsidiaries in the operation of its business thereon, (ii) except for such arrangements solely among the Partnership and its Subsidiaries or among the Partnership’s Subsidiaries, there are no outstanding options or rights of first refusal in favor of any other party to purchase any Partnership Owned Real Property or any portion thereof or interest therein that would reasonably be expected to adversely affect the existing use of the Partnership Owned Real Property by the Partnership or its Subsidiaries in the operation of its business thereon, and (iii) neither the Partnership nor any of its Subsidiaries is currently subleasing, licensing or otherwise granting any person the right to use or occupy a material portion of Partnership Owned Real Property or Partnership Leased Real Property that would reasonably be expected to adversely affect the existing use of such Partnership Owned Real Property or Partnership Leased Real Property by the Partnership or its Subsidiaries in the operation of its business thereon.

(c) Except as would not, individually or in the aggregate, have a Partnership Material Adverse Effect: (i) each of the Partnership and its Subsidiaries has such Rights-of-Way that are necessary for the Partnership and its Subsidiaries to use and operate their respective assets and properties in the manner that such assets and properties are currently used and operated, and each such Right-of-Way is valid and free and clear of all Liens (other than Partnership Permitted Liens); (ii) the Partnership and its Subsidiaries conduct their businesses in a manner that does not violate any of the Rights-of-Way; (iii) the Partnership and its Subsidiaries have fulfilled and performed all of their obligations with respect to such Rights-of-Way; and (iv) neither the Partnership nor any of its Subsidiaries has received written notice of, and, to the knowledge of the Partnership, there does not exist, the occurrence of any ongoing event or

 

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circumstance that allows, or after the giving of notice or the passage of time, or both, would allow the revocation or termination of any Right-of-Way or would result in any impairment of the rights of the Partnership and its Subsidiaries in and to any such Rights-of-Way. Except as would not, individually or in the aggregate, have a Partnership Material Adverse Effect, all pipelines operated by the Partnership and its Subsidiaries have or are otherwise entitled to the benefits of all Rights-of-Way that are necessary for the Partnership and its Subsidiaries to use and operate their respective assets and properties in the manner that such assets and properties are currently used and operated, and there are no gaps (including any gap arising as a result of any breach by the Partnership or any of its Subsidiaries of the terms of any Rights-of-Way) in such Rights-of-Way that would prevent the Partnership and its Subsidiaries to use and operate their respective assets and properties in the manner that such assets and properties are currently used and operated.

Section 3.18 Insurance. Except as would not have, individually or in the aggregate, a Partnership Material Adverse Effect, the Partnership and its Subsidiaries maintain, or are entitled to the benefits of, insurance in such amounts and against such risks substantially as the Partnership believes to be customary for the industries in which it and its Subsidiaries operate. Except as would not have, individually or in the aggregate, a Partnership Material Adverse Effect, neither the Partnership nor any of its Subsidiaries has received notice of any pending or, to the knowledge of the Partnership, threatened cancellation or premium increase (retroactive or otherwise) with respect to any such insurance policy, and each of its Subsidiaries is in compliance with all conditions contained therein.

Section 3.19 Opinion of Financial Advisor. The Conflicts Committee has received the opinion of Intrepid Partners, LLC to the effect that, as of the date of such opinion and based upon and subject to the assumptions, limitations, qualifications and other matters set forth therein, the Exchange Ratio is fair, from a financial point of view, to the holders of Partnership Common Units other than the General Partner and its affiliates (which affiliates include but are not limited to the Sponsors).

Section 3.20 Material Contracts.

(a) Except for this Agreement, the Partnership Benefit Plans and agreements filed as exhibits to the Partnership SEC Documents, as of the date of this Agreement, none of the Partnership, the General Partner or any of their Subsidiaries is a party to or bound by:

(i) any “material contract” (as such term is defined in Item 601(b)(10) of Regulation S-K of the SEC);

(ii) any Contract that (A) expressly imposes any material restriction on the right or ability of the Partnership or any of its Subsidiaries to compete with any other person or acquire or dispose of the securities of any other person or (B) contains an exclusivity or “most favored nation” clause that restricts the business of the Partnership or any of its Subsidiaries in a material manner;

 

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(iii) any mortgage, note, debenture, indenture, security agreement, guaranty, pledge or other agreement or instrument evidencing indebtedness for borrowed money or any guarantee of such indebtedness of the Partnership or any of its Subsidiaries in an amount in excess of $25 million, other than (A) such indebtedness among the Partnership and its wholly-owned Subsidiaries or (B) such indebtedness obligations of SESH;

(iv) any joint venture, partnership or limited liability company agreement or other similar Contract relating to the formation, creation, operation, management or control of any joint venture, partnership or limited liability company, other than any such Contract solely between the Partnership and its Subsidiaries or among the Partnership’s Subsidiaries;

(v) any Contract expressly limiting or restricting the ability of the Partnership or any of its Subsidiaries to make distributions or declare or pay dividends in respect of their capital stock, partnership interests, limited liability company interests or other equity interests, as the case may be;

(vi) any acquisition Contract that contains “earn out” or other contingent payment obligations, or remaining indemnity or similar obligations, that could reasonably be expected to result in payments after the date hereof by the Partnership or any of its Subsidiaries in excess of $25 million; and

(vii) any material lease or sublease with respect to a Partnership Leased Real Property.

All contracts of the types referred to in clauses (i) through (vii) above are referred to herein as “Partnership Material Contracts.” “Contract” means any agreement, contract, obligation, promise, understanding or undertaking (whether written or oral) that is legally binding.

(b) Except as would not have, individually or in the aggregate, a Partnership Material Adverse Effect: (i) none of the Partnership, the General Partner or any of their Subsidiaries is in breach of or default under the terms of any Partnership Material Contract, (ii) no other party to any Partnership Material Contract, to the knowledge of the Partnership is in breach of or default under the terms of any Partnership Material Contract, and (iii) each Partnership Material Contract is a valid and binding obligation of the Partnership or the Subsidiary of the Partnership that is party thereto and, to the knowledge of the Partnership, of each other party thereto, and is in full force and effect, subject to the Remedies Exceptions.

Section 3.21 Finders or Brokers. Except as set forth on Section 3.21 of the Partnership Disclosure Schedule, none of the Partnership, the General Partner or any of their Subsidiaries has employed any investment banker, broker or finder in connection with the transactions contemplated by this Agreement who would be entitled to any fee or any commission in connection with or upon consummation of the LP Merger.

Section 3.22 State Takeover Statute. The action of the GP Board in approving this Agreement and the transactions contemplated hereby is sufficient to render inapplicable to this Agreement and the transactions contemplated hereby any state takeover laws. There is no unitholder rights plan in effect, to which the Partnership is a party or otherwise bound.

 

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Section 3.23 Export Controls and Economic Sanctions.

(a) None of the Partnership, the General Partner any of their Subsidiaries, any of their respective owners, directors, officers, or employees or, to the knowledge of the Partnership, any other person working on behalf of any of the foregoing has directly or indirectly during the past five years taken any action in violation of any applicable Export Control and Economic Sanctions Laws in any material respect. To the extent that the Partnership’s activities are subject to Export Control and Economic Sanctions Laws, the Partnership has devised and maintained internal control systems and policies reasonably designed to detect and prevent violations of applicable Export Control and Economic Sanctions Laws. None of the Partnership, the General Partner, any of their Subsidiaries, or any of their respective owners, directors, officers, or employees, or, to the knowledge of the Partnership, any other person working on behalf of any of the foregoing is (A) a Sanctioned Party, (B) controlled by a Sanctioned Party, or (C) located in, organized under the Laws of, or resident in a Sanctioned Jurisdiction. No proceeding by or before any Governmental Entity involving the Partnership, the General Partner or any of their Subsidiaries or their respective directors, officers, employees, agents, distributors or Representatives relating to the Export Control and Economic Sanctions Laws is pending or, to the knowledge of the Partnership, threatened.

(b) As used in this Agreement, “Export Control and Economic Sanctions Laws” means the Export Control Reform Act of 2018 (50 U.S.C. Chapter 58), the Export Administration Act of 1979 (50 U.S.C. Chapter 56), the Export Administration Regulations (15 C.F.R. Parts 730-774), Section 3 of the Natural Gas Act (15 U.S.C. § 717b), the Administrative Procedures With Respect to the Import And Export of Natural Gas (10 C.F.R. Part 590), regulations promulgated by the Office of Foreign Assets Control (31 C.F.R. Parts 500-599) and corresponding enabling statutes, and any similar export control or economic sanctions Laws of any country in which a person is performing activities, to the extent that such person is subject to such Laws. “Sanctioned Jurisdiction” means a country, state, territory, or region which is subject to comprehensive economic or trade restrictions under applicable Export Control and Economic Sanctions Laws, which may change from time to time (currently Cuba, Iran, North Korea, Syria, and the Crimea region of Ukraine). “Sanctioned Party” means (i) any individual, entity, or government that is designated under or the subject of any sanctions, export restrictions, restricted party list, or blocking measures administered by a Governmental Entity with jurisdiction over a person, including but not limited to the Specially Designated Nationals and Blocked Persons List (“SDN List”), Foreign Sanctions Evaders List, or Sectoral Sanctions Identifications List (“SSI List”) of the U.S. Department of the Treasury’s Office of Foreign Assets Control; the Denied Persons, Entity, or Unverified Lists of the U.S. Department of Commerce’s Bureau of Industry and Security; the Debarred List of the U.S. Department of State’s Directorate of Defense Trade Controls; any list of sanctioned persons administered and maintained by the U.S. Department of State relating to nonproliferation, terrorism, Cuba, Iran, or Russia; and any similar lists of other jurisdictions to the extent applicable to a person; or (ii) any individual or entity that is 50% or more owned, directly or indirectly, by one or more individuals or entities that is designated on the SDN List or SSI List.

 

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Section 3.24 No Additional Representations or Warranties; Non-Reliance.

(a) The Partnership acknowledges that none of Parent, Merger Sub or GP Merger Sub makes any representation or warranty as to any matter whatsoever except as expressly set forth in Article IV or in any certificate delivered by Parent, Merger Sub or GP Merger Sub to the Partnership in accordance with the terms hereof, and specifically (but without limiting the generality of the foregoing) that none of Parent, Merger Sub or GP Merger Sub makes any representation or warranty with respect to (a) any projections, estimates or budgets delivered or made available to the Partnership (or any of their respective affiliates, officers, directors, employees or Representatives) of future revenues, results of operations (or any component thereof), cash flows or financial condition (or any component thereof) of Parent and its Subsidiaries or (b) the future business and operations of Parent and its Subsidiaries, and the Partnership has not relied on such information or any other representation or warranty not set forth in Article IV.

(b) The Partnership has conducted its own independent review and analysis of the business, operations, assets, liabilities, results of operations, financial condition and prospects of Parent and its Subsidiaries and acknowledges that the Partnership has been provided access for such purposes. Except for the representations and warranties expressly set forth in Article IV or in any certificate delivered by Parent or Merger Sub to the Partnership in accordance with the terms hereof, in entering into this Agreement, the Partnership has relied solely upon its independent investigation and analysis of Parent and its Subsidiaries, and the Partnership acknowledges and agrees that it has not been induced by and has not relied upon any representations, warranties or statements, whether express or implied, made by Parent, its Subsidiaries, or any of their respective affiliates, unitholders, controlling persons or representatives that are not expressly set forth in Article IV or in any certificate delivered by Parent, Merger Sub, or GP Merger Sub to the Partnership, whether or not such representations, warranties or statements were made in writing or orally. The Partnership acknowledges and agrees that, except for the representations and warranties expressly set forth in Article IV or in any certificate delivered by Parent, Merger Sub or GP Merger Sub to the Partnership, (i) Parent, Merger Sub and GP Merger Sub do not make, and have not made, any representations or warranties relating to themselves or their businesses or otherwise in connection with the transactions contemplated hereby and the Partnership is not relying on any representation or warranty except for those expressly set forth in this Agreement, (ii) no person has been authorized by Parent, Merger Sub or GP Merger Sub to make any representation or warranty relating to themselves or their business or otherwise in connection with the transactions contemplated hereby, and if made, such representation or warranty must not be relied upon by the Partnership as having been authorized by such party, and (iii) any estimates, projections, predictions, data, financial information, memoranda, presentations or any other materials or information provided or addressed to the Partnership or any of its representatives are not and shall not be deemed to be or include representations or warranties unless any such materials or information is the subject of any express representation or warranty set forth in Article IV.

 

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ARTICLE IV.

REPRESENTATIONS AND WARRANTIES OF PARENT, MERGER SUB AND GP MERGER SUB

Except as disclosed in (a) the Parent SEC Documents (excluding any disclosure set forth in any such Parent SEC Document under the heading “Risk Factors” or in any section relating to forward-looking statements) or (b) the disclosure schedule delivered by Parent to the Partnership immediately prior to the execution of this Agreement (the “Parent Disclosure Schedule”), each section of which qualifies the correspondingly numbered representation, warranty or covenant if specified therein (provided that (i) disclosure in any section of such Parent Disclosure Schedule shall be deemed to be disclosed with respect to any other representations, warranties or covenants where its relevance as an exception to (or disclosure for purposes of) such other representation, warranty or covenant is reasonably apparent on the face of such disclosure notwithstanding the omission of a reference or a cross reference thereto and (ii) the mere inclusion of an item in such Parent Disclosure Schedule as an exception to a representation or warranty shall not be deemed an admission that such item represents a material exception or material fact, event or circumstance or that such item has had, or would reasonably be expected to have a Parent Material Adverse Effect), each of Parent, Merger Sub and GP Merger Sub, jointly and severally, represents and warrants to the Partnership and the General Partner as follows:

Section 4.1 Qualification, Organization, Subsidiaries, etc.

(a) Each of Parent, Merger Sub, GP Merger Sub and their respective Subsidiaries is a legal entity duly organized or formed, validly existing and in good standing under the Laws of its jurisdiction of organization or formation and has all requisite limited partnership, limited liability company or other applicable power and authority to own, lease and operate its properties and assets and to carry on its business as presently conducted, except where the failure to have such power or authority would not have, individually or in the aggregate, a Parent Material Adverse Effect. Each of Parent, Merger Sub, GP Merger Sub and their respective Subsidiaries is qualified to do business and is in good standing as a foreign entity in each jurisdiction where the ownership, leasing or operation of its assets or properties or conduct of its business requires such qualification, except where the failure to be so qualified or in good standing would not have, individually or in the aggregate, a Parent Material Adverse Effect.

(b) As used in this Agreement, a “Parent Material Adverse Effect” means an event, change, effect, development or occurrence that has had, or is reasonably likely to have, a material adverse effect on the business financial condition or continuing results of operations of Parent and its Subsidiaries, taken as a whole; provided, however, that none of the following, and no change, event, occurrence or effect, individually or in the aggregate, to the extent arising out of, resulting from or attributable to any of the following, shall constitute or be taken into account in determining whether a Parent Material Adverse Effect has occurred or is reasonably likely to occur: change, effect, development or occurrence: (i) disclosed in the Parent SEC Documents filed or furnished prior to the date of this Agreement (excluding any disclosure set forth in any risk factor section or in any section relating to forward-looking statements or in any disclosure related to litigation or regulatory matters that caveats the uncertainty or likelihood of any

 

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particular outcome or the general unpredictability of an outcome to such litigation or regulatory matter) or as disclosed in the Parent Disclosure Schedule, (ii) in or generally affecting the economy, the financial or securities markets, or political, legislative or regulatory conditions, in each case in the United States or elsewhere in the world, including any changes in supply, demand, currency exchange rates, interest rates, tariff policy, monetary policy or inflation, so long as such event, change, effect, development or occurrence does not disproportionately affect Parent and its Subsidiaries, taken as a whole, relative to other similarly situated companies in the industries in which Parent and its Subsidiaries operate, or (iii) resulting from or arising out of (A) any changes or developments in the industries in which Parent or any of its Subsidiaries conducts its business, (B) any changes or developments in prices for oil, natural gas or other commodities or for Parent’s raw material inputs and end products, including general market prices and regulatory changes generally affecting the industries in which Parent and its Subsidiaries operate, (C) resulting from the negotiation, execution, announcement or the existence of, compliance with or performance under, this Agreement or the transactions contemplated hereby (including the impact thereof on the relationships, contractual or otherwise, of the Partnership or any of its Subsidiaries with employees, labor unions, customers, suppliers or partners, and including any lawsuit, action or other proceeding with respect to the Mergers or any of the other transactions contemplated by this Agreement), (D) any taking of any action required by this Agreement, the Support Agreements (to the extent applicable) or at the request of the Partnership, (E) any adoption, implementation, promulgation, repeal, modification, reinterpretation or proposal of any rule, regulation, ordinance, order, protocol or any other Law of or by any national, regional, state or local Governmental Entity, or market administrator, (F) any changes in GAAP or accounting standards or interpretations thereof, (G)(1) earthquakes, any weather-related or other force majeure event or natural disasters, hurricanes, tsunamis, pandemics (including the existence, response to and impact of the COVID-19 pandemic) or outbreak or other natural disasters or (2) hostilities or acts of war or terrorism, sabotage, civil disobedience, cyber-attack or any escalation or general worsening of the foregoing, (H) any failure by Parent to meet any internal or external projections, forecasts, estimates, milestones or budgets or financial or operating predictions of revenues, earnings or other financial or operating metrics for any period (provided that the exception in this clause (H) shall not prevent or otherwise affect a determination that any event, change, effect, development or occurrence underlying such failure has resulted in, or contributed to, a Parent Material Adverse Effect so long as it is not otherwise excluded by this definition) or (I) any changes in the unit price or trading volume of the Parent Common Units or in the credit rating of Parent or any of its Subsidiaries (provided that the exception in this clause (I) shall not prevent or otherwise affect a determination that any event, change, effect, development or occurrence underlying such change has resulted in, or contributed to, a Parent Material Adverse Effect so long as it is not otherwise excluded by this definition); except, in each case with respect to subclauses (A)-(B) and (E)-(G) of this clause (iii), to the extent disproportionately affecting Parent and its Subsidiaries, taken as a whole, relative to other similarly situated companies in the industries in which Parent and its Subsidiaries operate.

(c) Parent has made available to the Partnership prior to the date of this Agreement a true and complete copy of (i) the Certificate of Limited Partnership of Parent (the “Parent Certificate of Limited Partnership”), and (ii) the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer LP, dated as of February 8, 2006 (the “Parent Partnership Agreement” and, together with the Parent Certificate of Limited Partnership, the “Parent Organizational Documents”), in each case, as amended through the date hereof, and promptly upon request by the Partnership, Parent will make available to the Partnership the certificate of incorporation, certificate of limited partnership, certificate of formation, bylaws, limited partnership agreement, limited liability company agreement or comparable constituent or organizational documents of each material Subsidiary of Parent.

 

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Section 4.2 Capitalization.

(a) As of February 15, 2021, the issued and outstanding limited partner interests and general partner interests of Parent consisted of (i) 2,702,436,307 Parent Common Units, (ii) 668,871,738 Class A Units representing limited partner interests in Parent (the “Class A Units”) and (iii) a non-economic general partner interest (the “Parent GP Interest”). As of February 15, 2021 34,123,485 Parent Common Units were issuable pursuant to employee and director equity plans of Parent (the “Parent Equity Plans”) and 29,627,228 Parent Common Units were subject to outstanding awards under the Parent Equity Plans. All outstanding limited partner interests and Parent GP Interest are duly authorized, validly issued, fully paid (to the extent required by the Parent Partnership Agreement) and nonassessable (except as such nonassessability may be affected by matters described in Sections 17-303, 17-607 and 17-804 of the Delaware LP Act) and free of preemptive rights (except as set forth in the Parent Partnership Agreement).

(b) Except as set forth in Section 4.2(a) or as set forth in Section 4.2(b) of the Parent Disclosure Schedule, there are no outstanding subscriptions, options, warrants, calls, convertible securities, exchangeable securities or other similar rights, agreements or commitments to which Parent or any of its Subsidiaries is a party (i) obligating Parent or any of its Subsidiaries to (A) issue, transfer, exchange, sell or register for sale any partnership interests, limited liability interests or other equity interests of Parent or any Subsidiary of Parent or securities convertible into or exchangeable for such partnership interests, limited liability company interests or other equity interests (B) grant, extend or enter into any such subscription, option, warrant, call, convertible securities or other similar right, agreement or arrangement, (C) redeem or otherwise acquire any such partnership interests, limited liability interests or other equity interests, (D) provide a material amount of funds to, or make any material investment (in the form of a loan, capital contribution or otherwise) in, any Subsidiary or (E) make any payment to any person the value of which is derived from or calculated based on the value of Parent Common Units, Class A Units, Series G Preferred Units or other equity interests of Parent, or (ii) granting any preemptive or antidilutive or similar rights with respect to any security issued or issuable in connection with the Mergers by Parent or its Subsidiaries.

(c) Neither Parent nor any of its Subsidiaries has outstanding bonds, debentures, notes or other indebtedness, the holders of which have the right to vote (or which are convertible or exchangeable into or exercisable for securities having the right to vote) with the unitholders of Parent on any matter.

(d) There are no voting trusts or other agreements or understandings to which Parent or any of its Subsidiaries is a party with respect to the voting or registration of partnership interests, limited liability company interests or any other equity interests of Parent or any of its Subsidiaries.

 

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(e) As of the date of this Agreement, all of the issued and outstanding limited liability company interests of each of Merger Sub and GP Merger Sub are duly authorized, validly issued, fully paid and nonassessable (except as such nonassessability may be affected by matters described in Sections 18-607 and 18-804 of the Delaware LLC Act). All of the issued and outstanding limited liability company interests of each of Merger Sub and GP Merger Sub are, and at the Effective Time will be, solely owned, beneficially and of record, by Parent. Neither Merger Sub nor GP Merger Sub has any outstanding subscription, option, warrant, call, convertible security, exchangeable security or other similar right, agreement or commitment pursuant to which any person other than Parent may acquire any equity security of Merger Sub or GP Merger Sub. Merger Sub and GP Merger Sub have been formed solely for the purpose of engaging in the Mergers and the other transactions contemplated by this Agreement. Neither Merger Sub nor GP Merger Sub has conducted or engaged in any business activities of any kind or type whatsoever or entered into any agreements or arrangements with any person prior to the date hereof and neither has, and prior to the Effective Time will not have, any assets, and has not and prior to the Effective Time, will not incur, directly or indirectly, liabilities or obligations of any nature other than those incident to their respective formation and pursuant to this Agreement and the LP Merger and the GP Merger and the other transactions contemplated by this Agreement.

(f) When issued pursuant to the terms hereof, all outstanding Parent Common Units constituting any part of the LP Merger Consideration will be duly authorized, validly issued, fully paid (to the extent required under the Parent Partnership Agreement) and nonassessable (except as such nonassessability may be affected by matters described in Sections 17-303, 17-607 and 17-804 of the Delaware LP Act) and free of preemptive rights (except as set forth in the Parent Partnership Agreement). When issued pursuant to the terms hereof, the Series G Preferred Units to be issued to the holders of the Series A Preferred Units will be duly authorized, validly issued, fully paid (to the extent required under the Parent Partnership Agreement) and nonassessable (except as such nonassessability may be affected by matters described in Section 17-303, 17-607 and 17-807 of the Delaware LP Act) and free of preemptive rights (except as set forth in the Parent Partnership Agreement).

(g) Parent or a Subsidiary of Parent owns, directly or indirectly, all of the issued and outstanding partnership interests, limited liability company interests or other equity interests of each Subsidiary of Parent, free and clear of any preemptive rights and any Liens other than Parent Permitted Liens, and all of such partnership interests, limited liability company interests or other equity interests are duly authorized, validly issued, fully paid and nonassessable (except as such nonassessability may be affected by matters described in Sections 17-303, 17-607 and 17-804 of the Delaware LP Act, Sections 18-607 and 18-804 of the Delaware LLC Act or other similar Laws in any jurisdiction in which such Subsidiary is organized) and free of preemptive rights. Except for partnership interests, limited liability company interests or other equity interests in Parent’s Subsidiaries and except as set forth in Section 4.2(g) of the Parent Disclosure Schedule, neither Parent nor any of its Subsidiaries owns, directly or indirectly, any partnership interest, limited liability company interest or other equity interest in any person (or any security or other right, agreement or commitment convertible or exercisable into, or exchangeable for, any partnership interest, limited liability company interest or other equity interest in any person), or has any obligation to acquire any such partnership interest, limited liability company interest or other equity interest, security, right, agreement or commitment or to provide funds to or make any investment (in the form of a loan, capital contribution or otherwise) in, any person.

 

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(h) As used in this Agreement, “Parent Permitted Lien” means (i) any Lien (A) for Taxes or governmental assessments, charges or claims of payment not yet delinquent, being contested in good faith and for which adequate accruals or reserves have been established, (B) that is a carriers’, warehousemen’s, mechanics’, materialmen’s, repairmen’s or other similar lien arising in the ordinary course of business, (C) arising under conditional sales contracts, tenders, statutory obligations, surety and appeals bonds, bids, government contracts, performance and return of money bonds, equipment leases and similar obligations, in each case so long as each of the aforementioned documents are with third parties entered into in the ordinary course of business, (D) not created by Parent or its Subsidiaries that affect the underlying fee interest of a Parent Leased Real Property, (E) that is disclosed on the most recent consolidated balance sheet of Parent included in the Parent SEC Documents or notes thereto or securing liabilities reflected on such balance sheet, (F) arising under or pursuant to the Parent Organizational Documents or the organizational documents of any Subsidiary of Parent, (G) created pursuant to the agreements set forth on Section 4.2(h) of the Parent Disclosure Schedule, (H) which an accurate up to date survey would show, (I) resulting from any facts or circumstances relating to the Partnership or its affiliates (other than Caribou and Ox and their respective affiliates (other than the Partnership and its Subsidiaries)), or (J) that does not and would not reasonably be expected to materially impair the continued use of a Parent Owned Real Property or a Parent Leased Real Property as currently operated, taken as a whole; (ii) grants to others of Rights-of-Way, surface leases, crossing rights and amendments, modifications, and releases of Rights-of-Way, easements and surface leases in the ordinary course of business; (iii) with respect to Rights-of-Way, restrictions on the exercise of any of the rights under a granting instrument that are set forth therein or in another executed agreement, that is of public record or to which Parent or any of its Subsidiaries otherwise has access, between the parties thereto; (iv) with respect to any Parent Leased Real Property, Liens and other rights reserved by or in favor of any landlord under a Parent Real Property Lease; or (v) zoning, entitlement, building and other land use regulations imposed by any Governmental Entity having jurisdiction over the Parent Real Property, and not violated by the current use and operation of the Parent Real Property.

Section 4.3 Authority; Noncontravention.

(a) Each of Parent, Merger Sub and GP Merger Sub has the requisite limited partnership or limited liability company power and authority to enter into this Agreement and to consummate the transactions contemplated hereby. (i) This Agreement and the execution, delivery and performance of this Agreement and the consummation of the transactions contemplated hereby, including the Mergers, have been duly and validly authorized by the Board of Directors of Parent GP (the “Parent GP Board”) and Parent, as the sole member of Merger Sub and GP Merger Sub, and (ii) no other entity or equity-holder proceedings on the part of Parent, Merger Sub, GP Merger Sub or their respective equity holders are necessary to authorize the consummation of the transactions contemplated hereby. The Parent GP Board has approved this Agreement and the execution, delivery and performance of this Agreement and the transactions contemplated hereby, including the Mergers, the issuance of Parent Common Units in connection with the LP Merger and the issuance of the Series G Preferred Units in connection with the Preferred Contribution and Issuance. This Agreement has been duly and validly

 

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executed and delivered by Parent, Merger Sub and GP Merger Sub and, assuming this Agreement constitutes the legal, valid and binding agreement of the counterparties hereto, this Agreement constitutes the legal, valid and binding agreement of Parent, Merger Sub and GP Merger Sub and is enforceable against Parent, Merger Sub and GP Merger Sub in accordance with its terms, subject to Equitable Exceptions. Prior to the issuance of the Series G Preferred Units to Caribou, all partnership and limited liability company action, as the case may be, required to be taken by Parent, Parent GP or any of their equityholders, partners or members for (A) the authorization, execution and delivery of the Series G Preferred Units, (B) the authorization, execution and delivery of an amendment to the Parent Partnership Agreement to authorize and establish the terms of the Series G Preferred Units and (C) the consummation of the transactions contemplated by this Agreement, shall have been validly taken.

(b) Other than in connection with or in compliance with (i) the Delaware LP Act, (ii) the Delaware LLC Act, (iii) the Exchange Act, and the rules promulgated thereunder, (iv) the Securities Act, and the rules promulgated thereunder, (v) applicable state securities, takeover and “blue sky” laws, (vi) the filing of the Certificates of Merger with the Secretary of State, (vii) the rules and regulations of the NYSE, (viii) the HSR Act, (ix) rules and regulations of the SEC in connection with the filing with the SEC of the Combined Consent Statement/Prospectus, which shall include a form of consent that may be executed by the public unitholders of the Partnership Common Units in connection with the Requisite Unitholder Approval, and (x) the approvals set forth in Section 4.3(b) of the Parent Disclosure Schedule (collectively, the “Parent Approvals”), and, subject to the accuracy of the representations and warranties of the Partnership and the General Partner in Section 3.3(b), no authorization, consent, order, license, permit or approval of, or registration, declaration, notice or filing with, any Governmental Entity is necessary, under applicable Law, for the consummation by Parent, Merger Sub or GP Merger Sub of the transactions contemplated by this Agreement, except for such authorizations, consents, orders, licenses, permits, approvals or filings that are not required to be obtained or made prior to consummation of such transactions or that, if not obtained or made, would not materially impede or delay the consummation of the Mergers and the other transactions contemplated by this Agreement or have, individually or in the aggregate, a Parent Material Adverse Effect.

(c) The execution and delivery by Parent, Merger Sub and GP Merger Sub of this Agreement do not and, assuming the Parent Approvals are obtained, the consummation of the transactions contemplated hereby and compliance with the provisions hereof will not (i) result in any loss, or suspension, limitation or impairment of any right of the Partnership or any of its Subsidiaries to own or use any assets required for the conduct of their business or result in any violation of, or default (with or without notice or lapse of time, or both) under, or give rise to a right of termination, cancellation or acceleration of any material obligation or to the loss of a material benefit under any loan, guarantee of indebtedness or credit agreement, note, bond, mortgage, indenture, lease, agreement, contract, instrument, permit, or license binding upon Parent or any of its Subsidiaries or result in the creation of any Liens other than Parent Permitted Liens, in each case, upon any of the properties or assets of Parent or any of its Subsidiaries, (ii) conflict with or result in any violation of any provision of the agreement of limited partnership, limited liability company agreement, certificate of incorporation or by-laws or other equivalent organizational document, in each case as amended or restated, of Parent or any of its Subsidiaries or (iii) conflict with or violate any applicable Laws, except in the case of clauses (i) and (iii) for such losses, suspensions, limitations, impairments, conflicts, violations, defaults, terminations, cancellation, accelerations, or Liens as would not have, individually or in the aggregate, a Parent Material Adverse Effect.

 

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(d) Simultaneously with the execution of this Agreement, each of Parent, Merger Sub and GP Merger Sub have executed and delivered each of the Support Agreements.

Section 4.4 Reports and Financial Statements.

(a) Parent and each of its Subsidiaries has filed or furnished all forms, documents, reports, schedules, certifications, prospectuses, registration and other statements required to be filed or furnished prior to the date hereof by it with the SEC since January 1, 2018 (collectively with all documents filed on a voluntary basis on Form 8-K, and in each case including all exhibits and schedules thereto and documents incorporated by reference therein, the “Parent SEC Documents”). As of their respective dates or, if amended, as of the date of the last such amendment, the Parent SEC Documents complied in all material respects with the requirements of the Securities Act and the Exchange Act, as the case may be, and the applicable rules and regulations promulgated thereunder, and none of the Parent SEC Documents contained any untrue statement of a material fact or omitted to state any material fact required to be stated therein or necessary to make the statements therein, in light of the circumstances under which they were made, not misleading, except that information set forth in the Parent SEC Documents as of a later date (but before the date of this Agreement) will be deemed to modify information as of an earlier date.

(b) The consolidated financial statements (including all related notes and schedules) of Parent included in the Parent SEC Documents fairly present in all material respects the consolidated financial position of Parent and its consolidated Subsidiaries, as at the respective dates thereof (if amended, as of the date of the last such amendment), and the consolidated results of their operations and their consolidated cash flows for the respective periods then ended (subject, in the case of the unaudited statements, to normal year-end audit adjustments and to any other adjustments described therein, including the notes thereto) in conformity with GAAP (except, in the case of the unaudited statements, as permitted by the SEC) applied on a consistent basis during the periods involved (except as may be indicated therein or in the notes thereto).

Section 4.5 Internal Controls and Procedures. Parent has established and maintains disclosure controls and procedures and internal control over financial reporting (as such terms are defined in paragraphs (e) and (f), respectively, of Rule 13a-15 under the Exchange Act) as required by Rule 13a-15 under the Exchange Act. Parent’s disclosure controls and procedures are reasonably designed to ensure that all material information required to be disclosed by Parent in the reports that it files or furnishes under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and that all such material information is accumulated and communicated to the management of Parent GP as appropriate to allow timely decisions regarding required disclosure and to make the certifications required pursuant to Sections 302 and 906 of the Sarbanes-Oxley Act. Management of Parent GP has completed an assessment of the effectiveness of Parent’s internal control over financial reporting in compliance with the requirements of Section 404 of

 

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the Sarbanes-Oxley Act for the year ended December 31, 2020, and such assessment concluded that such controls were effective. Based on its most recent evaluation of internal controls over financial reporting prior to the date hereof, management of Parent GP has disclosed to Parent’s auditors and the audit committee of the Parent GP Board (i) any significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting that are reasonably likely to adversely affect in any material respect Parent’s ability to report financial information and (ii) any fraud, whether or not material, that involves management or other employees who have a significant role in Parent’s internal control over financial reporting, and each such deficiency, weakness and fraud so disclosed to auditors, if any, has been disclosed to the Partnership prior to the date hereof.

Section 4.6 No Undisclosed Liabilities. Except (a) as reflected or reserved against in Parent’s consolidated balance sheet as of the Balance Sheet Date (including the notes thereto) included in the Parent SEC Documents, (b) for liabilities and obligations incurred under or in accordance with this Agreement or in connection with the transactions contemplated by this Agreement, (c) for liabilities and obligations incurred since the Balance Sheet Date in the ordinary course of business and (d) for liabilities and obligations that have been discharged or paid in full, neither Parent nor any Subsidiary of Parent has any liabilities or obligations of any nature, whether or not accrued, contingent or otherwise, that would be required by GAAP to be reflected on a consolidated balance sheet of Parent and its consolidated Subsidiaries (including the notes thereto), other than those that would not have, individually or in the aggregate, a Parent Material Adverse Effect.

Section 4.7 Compliance with Law; Permits.

(a) Parent and its Subsidiaries are in compliance with, and are not in default under or in violation of, any applicable Law, except where such non-compliance, default or violation would not have, individually or in the aggregate, a Parent Material Adverse Effect. Since January 1, 2018, neither Parent nor any of its Subsidiaries has received any written notice from any Governmental Entity regarding any actual or possible violation of, or failure to comply with, any Law, except as would not have, individually or in the aggregate, a Parent Material Adverse Effect.

(b) Parent and its Subsidiaries are in possession of all franchises, grants, authorizations, licenses, permits, easements, variances, exceptions, consents, certificates, approvals, and orders of all applicable Governmental Entities, and all rights under any Parent Material Contract with all Governmental Entities, and have filed all tariffs, reports, notices and other documents with all Governmental Entities necessary for Parent and its Subsidiaries to own, lease and operate their properties and assets and to carry on their businesses as they are now being conducted (the “Parent Permits”), except where the failure to have obtained or filed any of the Parent Permits would not have, individually or in the aggregate, a Parent Material Adverse Effect. All Parent Permits are valid and in full force and effect, except where the failure to be in full force and effect would not have, individually or in the aggregate, a Parent Material Adverse Effect. No administrative, judicial or other proceeding is pending or, to the knowledge of Parent, threatened, that could reasonably be expected to result in the adverse modification, suspension, termination, or cancellation of any Parent Permit, except where such modification, suspension, termination or cancellation would not have, individually or in the aggregate, a Parent Material

 

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Adverse Effect. Parent and each of its Subsidiaries is, and except for matters that have been fully resolved with the applicable Governmental Entity, since January 1, 2019 have been, in compliance in all respects with the terms and requirements of all Parent Permits, except where the failure to be in compliance would not have, individually or in the aggregate, a Parent Material Adverse Effect.

(c) Without limiting the generality of Section 4.7(a), Parent, each of its Subsidiaries, and, to the knowledge of Parent, each joint interest owner, consultant, agent, or representative of any of the foregoing (in their respective capacities as such), (i) has not violated the FCPA, and any other U.S. and foreign anti-corruption Laws that are applicable to Parent or its Subsidiaries; (ii) has not, to the knowledge of Parent, been given written notice by any Governmental Entity of any facts which, if true, would constitute a violation of the FCPA or any other U.S. or foreign anti-corruption Laws by any such person; and (iii) to the knowledge of Parent, is not being (and has not been) investigated by any Governmental Entity except, in each case of the foregoing clauses (i) through (iii), as would not have, individually or in the aggregate, a Parent Material Adverse Effect.

Section 4.8 Environmental Laws and Regulations.

(a) Except as would not have, individually or in the aggregate, a Parent Material Adverse Effect: (i) there are no investigations, actions, suits or proceedings (whether administrative or judicial) pending or, to the knowledge of Parent, threatened in writing against or affecting Parent or any of its Subsidiaries, any of their respective assets or operations, or against any person or entity whose liability Parent or any of its Subsidiaries has retained or to the knowledge of Parent, assumed either contractually or by operation of law, alleging non-compliance with or other liability under any Environmental Law, (ii) Parent and its Subsidiaries are, and except for matters that have been fully resolved with the applicable Governmental Entity, since January 1, 2019 have been, in compliance with all Environmental Laws, (iii) there has been no release of Hazardous Materials at any Parent Real Property or, to the knowledge of Parent, formerly owned, leased or operated by Parent or any Subsidiary of Parent, that has given rise or could reasonably be expected to give rise to Parent or any Subsidiary incurring any remedial obligation or corrective action requirement under applicable Environmental Law, (iv) to the knowledge of Parent, no Hazardous Material has been disposed of or transported in violation of any applicable Environmental Law from any Parent Real Property, (v) Parent is not party to any order or subject to any judgment or decree relating to compliance with Environmental Laws or the investigation, sampling, monitoring, treatment, remediation, removal or cleanup of Hazardous Materials that imposes any obligation on Parent or any of its Subsidiaries under any Environmental Law, (vi) there have been no ruptures or explosions in Parent’s Systems resulting in claims for personal injury, loss of life or material property damage, except to the extent any claims related to such ruptures or explosions have been fully resolved and (vii) to Parent’s knowledge, there are no defects, corrosion or other damage to any of Parent’s Systems that would reasonably be expected to result in a pipeline integrity failure.

(b) Notwithstanding any other language in this Agreement, this Section 4.8 contains Parent’s sole representations with respect to Environmental Law or Hazardous Materials.

 

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Section 4.9 Employee Benefit Plans. Except as would not have, individually or in the aggregate, a Parent Material Adverse Effect, (i) each Benefit Plan sponsored, maintained, contributed to or required to be contributed to by Parent or any of its Subsidiaries, or under which Parent or any of its Subsidiaries has any material liability (contingent or current) (the “Parent Benefit Plans”) has been maintained and administered in compliance with its terms and with applicable Law, including ERISA and the Code to the extent applicable thereto, and (ii) all contributions required to be made under the terms of any Parent Benefit Plan have been timely made or, if not yet due, have been properly reflected in Parent’s financial statements in accordance with GAAP. Except as set forth on Section 4.9 of the Parent Disclosure Schedule, neither Parent nor any of its Subsidiaries maintains, contributes to or is required to contribute to, or has any liability (including on behalf of or in respect of an ERISA Affiliate) with respect to, any Benefit Plan that is subject to Title IV or Section 302 of ERISA or Section 412 or 4971 of the Code or a multiemployer plan (as defined in Section 3(37) of ERISA).

Section 4.10 Absence of Certain Changes or Events.

(a) From the Balance Sheet Date through the date of this Agreement, except for discussions and activities pertaining to this Agreement and the transactions contemplated hereby, and except with respect to COVID-19 and any COVID-19 Actions the businesses of Parent and its Subsidiaries have been conducted in all material respects in the ordinary course of business.

(b) From the Balance Sheet Date through the date of this Agreement, there has not been a Parent Material Adverse Effect.

(c) From the date of this Agreement, there has not been a Parent Material Adverse Effect.

Section 4.11 Investigations; Litigation. Except as would not, individually or in the aggregate, have a Parent Material Adverse Effect, (a) there are no civil, criminal or administrative actions, suits, litigation, claims, causes of actions, inquiries, investigations, arbitrations proceedings, subpoenas, civil investigative demands or other requests for information pending (or, to the knowledge of Parent, threatened) against or affecting Parent or any of its Subsidiaries or any of their respective assets or operations and (b) there are no orders, judgments or decrees of, or before, any Governmental Entity against Parent or any of its Subsidiaries or any of their respective assets or operations; provided, that to the extent any such representations or warranties in the foregoing clauses (a) and (b) pertain to investigations, reviews, actions, suits, inquiries, proceedings, subpoenas, civil investigative demands, other requests, orders, judgements or decrees that relate to the execution, delivery, performance or consummation of this Agreement or any of the transactions contemplated by this Agreement, such representations and warranties are made only as of the date hereof.

Section 4.12 Information Supplied. None of the information provided in writing by Parent or its Subsidiaries specifically for inclusion or incorporation by reference in (a) the Form S-4 will, at the time the Form S-4 is filed with the SEC and becomes effective under the Securities Act, contain any untrue statement of a material fact or omit to state any material fact required to be stated therein or necessary to make the statements therein, in light of the

 

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circumstances under which they were made, not misleading or (b) the Combined Consent Statement/Prospectus will, on the date it is first mailed to the Partnership’s unitholders and the holder of the Series A Preferred Unit, contain any untrue statement of a material fact or omit to state any material fact required to be stated therein or necessary in order to make the statements therein, in light of the circumstances under which they were made, not misleading. The Combined Consent Statement/Prospectus and the Form S-4 (solely with respect to the portion thereof based on information supplied by Parent or its Subsidiaries for inclusion or incorporation by reference therein, but excluding any portion thereof based on information supplied by or on behalf of the Partnership for inclusion or incorporation by reference therein, with respect to which no representation is made by Parent or any of its Subsidiaries) will comply as to form in all material respects with the requirements of the Securities Act and the Exchange Act. Notwithstanding the foregoing provisions of this Section 4.12, no representation or warranty is made by Parent with respect to information or statements made or incorporated by reference in the Form S-4 or the Combined Consent Statement/Prospectus that were not specifically supplied in writing by or on behalf of Parent.

Section 4.13 Regulatory Matters.

(a) Except as would not, individually or in the aggregate, have a Parent Material Adverse Effect, none of Parent or its Subsidiaries is, or has been in the past three years a holding company or a public-utility company as defined in PUHCA.

(b) Except as would not, individually or in the aggregate, have a Parent Material Adverse Effect, there are no proceedings pending, or to the knowledge of Parent, threatened in writing, alleging that Parent or any of its Subsidiaries is in material violation of the NGA, the NGPA, the ICA, the FPA, or the PUHCA, or the rules and regulations promulgated thereunder, or the laws, rules and regulations of any state public utility commission or department in a state within which Parent or any of its Subsidiaries operates, as the case may be.

(c) Except as would not, individually or in the aggregate, have a Parent Material Adverse Effect, all filings (other than immaterial filings) required to be made by Parent or any of its Subsidiaries during the three years preceding the date hereof, with the (i) FERC under the NGA, the NGPA, the ICA, the PUHCA, or the rules and regulations promulgated thereunder, (ii) the Department of Energy, (iii) the FCC, or (iv) any state public utility commission or department in a state within which Parent or any of its Subsidiaries operates, as the case may be, have been made, including all forms, statements, reports, notices, agreements and all documents, exhibits, amendments and supplements appertaining thereto, including all rates, tariffs and related documents, and all such filings complied, as of their respective dates, and, as amended or supplemented, with all applicable requirements of applicable statutes and the rules and regulations promulgated thereunder.

Section 4.14 Tax Matters. Except as would not have, individually or in the aggregate, a Parent Material Adverse Effect:

(a) all Tax Returns that were required to be filed by or with respect to Parent or any of its Subsidiaries have been duly filed, and all such Tax Returns are complete and accurate;

 

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(b) all Taxes owed by Parent or any of its Subsidiaries, or for which Parent or any of its Subsidiaries may be liable, that are or have become due have been timely paid in full or an adequate reserve for the payment of such Taxes has been established;

(c) all Tax withholding and deposit requirements imposed on or with respect to Parent or any of its Subsidiaries have been satisfied in full in all respects;

(d) there are no Liens (other than Parent Permitted Liens) on any of the assets of Parent or any of its Subsidiaries that arose in connection with any failure (or alleged failure) to pay any Tax;

(e) there are no audits, examinations, investigations or other proceedings pending or threatened in writing in respect of Taxes or Tax matters of Parent or any of its Subsidiaries;

(f) there is no written claim against Parent or any of its Subsidiaries for any Taxes, and no assessment, deficiency or adjustment has been asserted, proposed, or threatened in writing with respect to any Tax Return of or with respect to Parent or any of its Subsidiaries;

(g) no claim has ever been made by an authority in a jurisdiction where Parent or any of its Subsidiaries does not file Tax Returns that Parent or such Subsidiary is or may be subject to taxation in that jurisdiction;

(h) there is not in force any extension of time (other than customary extensions) with respect to the due date for the filing of any Tax Return of or with respect to Parent or any of its Subsidiaries or any waiver or agreement for any extension of time for the assessment or payment of any Tax of or with respect to any of Parent or any of its Subsidiaries;

(i) none of Parent or any of its Subsidiaries will be required to include any amount in income for any taxable period as a result of a change in accounting method or adjustment under Section 482 of the Code for any taxable period ending on or before the Closing Date or pursuant to any agreement with any Tax authority with respect to any such taxable period, or as a result of an intercompany transaction, an installment sale or open transaction disposition entered into on or prior to the Closing Date, or the cash method of accounting or long-term contract method of accounting utilized prior to the Closing Date;

(j) none of Parent or any of its Subsidiaries is a party to a Tax allocation or sharing agreement, and no payments are due or will become due by Parent or any of its Subsidiaries pursuant to any such agreement or arrangement or any Tax indemnification agreement;

(k) none of Parent or any of its Subsidiaries has been a member of an affiliated, combined, consolidated, unitary or similar group with respect to Taxes (including any affiliated group within the meaning of Section 1504 of the Code and any similar group under state, local or non-U.S. law), other than the members of the consolidated group of which ETP Holdco Corporation is the common parent, or has any liability for the Taxes of any person (other than Parent or any of its Subsidiaries), as a transferee or successor, by contract, or otherwise (other than Taxes arising in ordinary course commercial arrangements not primarily related to Taxes)

 

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(l) none of Parent or any of its Subsidiaries has participated in a “listed transaction” within the meaning of Treasury Regulation Section 1.6011-4;

(m) Parent and each of its Subsidiaries that is classified as a partnership for U.S. federal income tax purposes has in effect a valid election under Section 754 of the Code;

(n) Parent is properly classified as a partnership for U.S. federal income tax purposes, and not as an association or a publicly traded partnership taxable as a corporation under Section 7704 of the Code, and has been properly treated as such since its formation; and

(o) Parent is not aware of the existence of any fact, nor has taken or agreed to take any action, that could reasonably be expected to prevent or impede the Mergers, taken together, from properly being treated in accordance with the Intended Tax Treatment for U.S. federal income tax purposes.

Notwithstanding any other language in this Agreement, Section 4.9 and Section 4.14 contain Parent’s sole representations with respect to Tax matters.

Section 4.15 Employment and Labor Matters.

(a) Except for such matters as would not have, individually or in the aggregate, a Parent Material Adverse Effect, (i) neither Parent nor any of its Subsidiaries is a party to or bound by any material collective bargaining or similar agreement or work rules or practices with any labor union, labor organization or employee association applicable to employees of Parent or any of its Subsidiaries, (ii) there are no existing or, to the knowledge of Parent, threatened strikes or lockouts with respect to any employees of Parent or any of its Subsidiaries (“Parent Employees”), (iii) to the knowledge of Parent, there is no union organizing effort pending or threatened against Parent or any of its Subsidiaries, (iv) there is no unfair labor practice, labor dispute (other than, in each case, routine individual grievances) or labor arbitration proceeding pending or, to the knowledge of Parent, threatened with respect to Parent or any of its Subsidiaries, and (v) there is no slowdown or work stoppage in effect or, to the knowledge of Parent, threatened with respect to any Parent Employees.

(b) Except for such matters that would not, individually or in the aggregate, have a Parent Material Adverse Effect, Parent and its Subsidiaries are, and for the past three years have been, in compliance with all applicable Laws respecting (i) employment and employment practices, (ii) terms and conditions of employment and wages and hours, and (iii) unfair labor practices. Neither Parent nor any of its Subsidiaries has any material liabilities under the Worker Adjustment and Retraining Notification Act of 1998 as a result of any action taken by Parent or its Subsidiaries in the past three years.

Section 4.16 Real Property.

(a) Except as would not have, individually or in the aggregate, a Parent Material Adverse Effect, (i) either Parent or a Subsidiary of Parent has good and valid title to each material real property (and each real property at which material operations of Parent or any of its Subsidiaries are conducted) owned by Parent or any Subsidiary other than Parent Real Property Leases and Rights-of-Way (such owned real property collectively, the “Parent Owned

 

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Real Property”) and (ii) either Parent or a Subsidiary of Parent has a good and valid leasehold interest in each material lease, sublease and other agreement under which Parent or any of its Subsidiaries uses or occupies or has the right to use or occupy any material real property (or real property at which material operations of Parent or any of its Subsidiaries are conducted) (any property subject to such lease, sublease or other agreement, the “Parent Leased Real Property,”; together with the Parent Owned Real Property, the “Parent Real Property”) and such leases subleases and other agreements are, collectively, the “Parent Real Property Leases”), in each case, free and clear of all Liens other than any Parent Permitted Liens and Permitted Encumbrances. Except as would not have, individually or in the aggregate, a Parent Material Adverse Effect, (A) each Parent Real Property Lease is valid, binding and in full force and effect, subject to the Remedies Exceptions and (B) no uncured default of a material nature on the part of Parent or, if applicable, its Subsidiary or, to the knowledge of Parent, the landlord thereunder, exists under any Parent Real Property Lease, and to the knowledge of Parent, no event has occurred or circumstance exists that, with the giving of notice, the passage of time, or both, would constitute a material breach or default under a Parent Real Property Lease.

(b) Except as would not have, individually or in the aggregate, a Parent Material Adverse Effect, (i) there are no leases, subleases, licenses, rights or other agreements affecting any portion of the Parent Owned Real Property or the Parent Leased Real Property that would reasonably be expected to adversely affect the existing use of such Parent Owned Real Property or Parent Leased Real Property by Parent or its Subsidiaries in the operation of its business thereon, (ii) except for such arrangements solely among Parent and its Subsidiaries or among Parent’s Subsidiaries, there are no outstanding options or rights of first refusal in favor of any other party to purchase any Parent Owned Real Property or any portion thereof or interest therein that would reasonably be expected to adversely affect the existing use of the Parent Owned Real Property by Parent in the operation of its business thereon, and (iii) neither Parent nor any of its Subsidiaries is currently subleasing, licensing or otherwise granting any person the right to use or occupy a material portion of a Parent Owned Real Property or Parent Leased Real Property that would reasonably be expected to adversely affect the existing use of such Parent Owned Real Property or Parent Leased Real Property by Parent or its Subsidiaries in the operation of its business thereon.

(c) Except as would not, individually or in the aggregate, have a Parent Material Adverse Effect: (i) each of Parent and its Subsidiaries has such Rights-of-Way that are necessary for Parent and its Subsidiaries to use and operate their respective assets and properties in the manner that such assets and properties are currently used and operated and each such Right-of-Way is valid and free and clear of all Liens (other than Parent Permitted Liens); (ii) Parent and its Subsidiaries conduct their businesses in a manner that does not violate any of the Rights-of-Way; (iii) Parent and its Subsidiaries have fulfilled and performed all of their obligations with respect to such Rights-of-Way; and (iv) neither Parent nor any of its Subsidiaries have received written notice of, and to the knowledge of Parent there does not exist, the occurrence of any ongoing event or circumstance that allows, or after the giving of notice or the passage of time, or both, would allow the revocation or termination of any Right-of-Way or would result in any impairment of the rights of Parent and its Subsidiaries in and to any such Rights-of-Way. Except as would not, individually or in the aggregate, have a Parent Material Adverse Effect, all pipelines operated by Parent and its Subsidiaries have and are entitled to the benefits of all Rights-of-Way that are necessary for Parent and its Subsidiaries to use and operate

 

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their respective assets and properties in the manner that such assets and properties are currently used and operated, and there are no gaps (including any gap arising as a result of any breach by Parent or any of its Subsidiaries of the terms of any Rights-of-Way) in such Rights-of-Way that would prevent Parent and its Subsidiaries to use and operate their respective assets and properties in the manner that such assets and properties are currently used and operated.

Section 4.17 Insurance. Except as would not have, individually or in the aggregate, a Parent Material Adverse Effect, Parent and its Subsidiaries maintain, or are entitled to the benefits of, insurance in such amounts and against such risks substantially as Parent believes to be customary for the industries in which it and its Subsidiaries operate. Except as would not have, individually or in the aggregate, a Parent Material Adverse Effect, neither Parent nor any of its Subsidiaries has received notice of any pending or, to the knowledge of Parent, threatened cancellation or premium increase (retroactive or otherwise) with respect to any such insurance policy, and each of its Subsidiaries is in compliance with all conditions contained therein.

Section 4.18 Material Contracts.

(a) Except for this Agreement, Parent’s Benefit Plans and agreements filed as exhibits to the Parent SEC Documents, as of the date of this Agreement, none of Parent, Merger Sub, GP Merger Sub or any of their Subsidiaries is a party to or bound by:

(i) any “material contract” (as such term is defined in Item 601(b)(10) of Regulation S-K of the SEC);

(ii) any Contract that (A) expressly imposes any material restriction on the right or ability of Parent or any of its Subsidiaries to compete with any other person or acquire or dispose of the securities of any other person or (B) contains an exclusivity or “most favored nation” clause that restricts the business of Parent or any of its Subsidiaries in a material manner;

(iii) any mortgage, note, debenture, indenture, security agreement, guaranty, pledge or other agreement or instrument evidencing indebtedness for borrowed money or any guarantee of such indebtedness of Parent or any of its Subsidiaries in an amount in excess of $200 million;

(iv) any joint venture, partnership or limited liability company agreement or other similar Contract relating to the formation, creation, operation, management or control of any joint venture, partnership or limited liability company, other than any such Contract solely between Parent and its Subsidiaries or among Parent’s Subsidiaries;

(v) any Contract expressly limiting or restricting the ability of Parent or any of its Subsidiaries to make distributions or declare or pay dividends in respect of their capital stock, partnership interests, limited liability company interests or other equity interests, as the case may be;

 

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(vi) any acquisition Contract that contains “earn out” or other contingent payment obligations, or remaining indemnity or similar obligations, that could reasonably be expected to result in payments after the date hereof by Parent or any of its Subsidiaries in excess of $200 million; and

(vii) any material lease or sublease with respect to a Parent Leased Real Property.

All contracts of the types referred to in clauses (i) through (vii) above are referred to herein as “Parent Material Contracts.”

(b) Except as would not have, individually or in the aggregate, a Parent Material Adverse Effect, (i) neither Parent nor any Subsidiary of Parent is in breach of or default under the terms of any Parent Material Contract, (ii) no other party to any Parent Material Contract, to the knowledge of Parent, is in breach of or default under the terms of any Parent Material Contract and (iii) each Parent Material Contract is a valid and binding obligation of Parent or the Subsidiary of Parent that is party thereto and, to the knowledge of Parent, of each other party thereto, and is in full force and effect, subject to the Remedies Exceptions.

Section 4.19 Finders or Brokers. Except for Citigroup Global Markets Inc. and RBC Capital Markets, LLC, neither Parent nor any of its Subsidiaries has employed any investment banker, broker or finder in connection with the transactions contemplated by this Agreement who would be entitled to any fee or any commission in connection with or upon consummation of the LP Merger.

Section 4.20 State Takeover Statute. The action of the Parent GP Board in approving this Agreement and the transactions contemplated hereby is sufficient to render inapplicable to this Agreement and the transactions contemplated hereby any state takeover laws. There is no unitholder rights plan in effect, to which Parent is a party or otherwise bound.

Section 4.22 Ownership of Partnership Common Units. Neither Parent nor any affiliate of Parent “beneficially owns” (as such term is defined for purposes of Section 13(d) of the Exchange Act) any Partnership Common Units.

Section 4.21 Export Controls and Economic Sanctions. None of Parent, any of its Subsidiaries, any of their respective owners, directors, officers, or employees or, to the knowledge of Parent, any other person working on behalf of any of the foregoing has directly or indirectly during the past five years taken any action in violation of any applicable Export Control and Economic Sanctions Laws in any material respect. Parent has devised and maintained internal control systems and policies reasonably designed to detect and prevent violations of applicable Export Control and Economic Sanctions Laws. None of Parent, any of its Subsidiaries, or any of their respective owners, directors, officers, or employees, or, to the knowledge of Parent, any other person working on behalf of any of the foregoing is (A) a Sanctioned Party, (B) controlled by a Sanctioned Party, or (C) located in, organized under the Laws of, or resident in a Sanctioned Jurisdiction. No proceeding by or before any Governmental Entity involving Parent or its Subsidiaries or their respective directors, officers, employees, agents, distributors or Representatives relating to the Export Control and Economic Sanctions Laws is pending or, to the knowledge of Parent, threatened.

 

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Section 4.22 Availability of Funds. Parent has, and at the Closing will have, sufficient cash, available lines of credit or other sources of immediately available funds to pay the GP Merger Consideration and to refinance the Partnership’s indebtedness or otherwise satisfy requirements of such obligations in connection with the consummation of the transactions contemplated by this Agreement.

Section 4.23 No Additional Representations or Warranties; Non-Reliance.

(a) Each of Parent, Merger Sub and GP Merger Sub acknowledge that the Partnership and the General Partner do not make any representation or warranty as to any matter whatsoever except as expressly set forth in Article III or in any certificate delivered by the Partnership or General Partner to Parent, Merger Sub or GP Merger Sub in accordance with the terms hereof, and specifically (but without limiting the generality of the foregoing) that the Partnership and the General Partner make no representation or warranty with respect to (i) any projections, estimates or budgets delivered or made available to Parent, Merger Sub or GP Merger Sub (or any of their respective affiliates, officers, directors, employees or Representatives) of future revenues, results of operations (or any component thereof), cash flows or financial condition (or any component thereof) of the Partnership and its Subsidiaries or (ii) the future business and operations of the Partnership and its Subsidiaries, and neither Parent, Merger Sub nor GP Merger Sub has relied on such information or any other representations or warranties not set forth in Article III.

(b) Each of Parent, Merger Sub and GP Merger Sub have conducted their own independent review and analysis of the business, operations, assets, liabilities, results of operations, financial condition and prospects of the Partnership and its Subsidiaries and acknowledge that Parent, Merger Sub and GP Merger Sub have been provided access for such purposes. Except for the representations and warranties expressly set forth in Article III or in any certificate delivered by the Partnership or the General Partner to Parent and/or the Merger Subs in accordance with the terms hereof, in entering into this Agreement, each of Parent, Merger Sub and GP Merger Sub have relied solely upon its independent investigation and analysis of the Partnership and the Partnership’s Subsidiaries, and Parent, Merger Sub and GP Merger Sub acknowledge and agree that they have not been induced by and has not relied upon any representations, warranties or statements, whether express or implied, made by the Partnership, the General Partner or their Subsidiaries, or any of their respective affiliates, equityholders, controlling persons or representatives that are not expressly set forth in Article III or in any certificate delivered by the Partnership or the General Partner to Parent, Merger Sub or GP Merger Sub, whether or not such representations, warranties or statements were made in writing or orally. Each of Parent, Merger Sub and GP Merger Sub acknowledge and agree that, except for the representations and warranties expressly set forth in Article III or in any certificate delivered by the Partnership or the General Partner do to Parent, Merger Sub or GP Merger Sub, (i) the Partnership does not make, and has not made, any representations or warranties relating to itself or its business or otherwise in connection with the transactions contemplated hereby and Parent, Merger Sub and GP Merger Sub are not relying on any representation or warranty except for those expressly set forth in this Agreement, (ii) no person has been authorized by the

 

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Partnership or the General Partner to make any representation or warranty relating to itself or its business or otherwise in connection with the transactions contemplated hereby, and if made, such representation or warranty must not be relied upon by Parent, Merger Sub or GP Merger Sub as having been authorized by the Partnership, and (iii) any estimates, projections, predictions, data, financial information, memoranda, presentations or any other materials or information provided or addressed to Parent, Merger Sub or GP Merger Sub or any of their representatives are not and shall not be deemed to be or include representations or warranties of the Partnership unless any such materials or information is the subject of any express representation or warranty set forth in Article III.

ARTICLE V.

COVENANTS AND AGREEMENTS

Section 5.1 Conduct of Business by the Partnership.

(a) From and after the date hereof until the earlier of the Effective Time or the date, if any, on which this Agreement is terminated pursuant to Section 7.1 (the “Termination Date”), and except (i) as may be required by applicable Law or the regulations or requirements of any stock exchange or regulatory organization applicable to the Partnership or any of its Subsidiaries, (ii) as may be consented to in writing by Parent (which consent shall not be unreasonably withheld, delayed or conditioned), (iii) as may be contemplated or required by this Agreement (including the Pre-Closing Transactions and the Preferred Contributions), or (iv) as set forth in Section 5.1(a) of the Partnership Disclosure Schedule, the Partnership covenants and agrees that the Partnership shall and shall cause its Subsidiaries to use commercially reasonable efforts to (x) conduct their businesses in the ordinary course, and (y) preserve substantially intact their present lines of business and preserve their relationships with significant customers and suppliers; provided, however, that no action by the Partnership or its Subsidiaries with respect to matters specifically addressed by any provision of Section 5.1(b) shall be deemed a breach of this covenant unless such action would constitute a breach of such other provision.

(b) Each of the Partnership and the General Partner agrees with Parent, on behalf of itself and its Subsidiaries, that from the date hereof and prior to the earlier of the Effective Time and the Termination Date, except (w) as may be required by applicable Law or the regulations or requirements of any stock exchange or regulatory organization applicable to the Partnership or any of its Subsidiaries, (x) as may be consented to by Parent (which consent shall not be unreasonably withheld, delayed or conditioned), (y) as may be contemplated or required by this Agreement or (z) as set forth in Section 5.1(b) of the Partnership Disclosure Schedule, each of the Partnership and the General Partner:

(i) shall not adopt any amendments to the Partnership Organizational Documents or the GP Organizational Documents and shall not permit any of the Partnership’s Subsidiaries to adopt any amendments to its certificate of limited partnership, partnership agreement, certificate of formation, limited liability company agreement, certificate of incorporation, bylaws or similar organizational documents;

 

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(ii) shall not, and shall not permit any of its Subsidiaries to, issue, sell, pledge, dispose of, encumber, split, combine or reclassify or authorize the issuance, sale, pledge, disposition, encumbrance, split, combination or reclassification of any of its partnership interests, limited liability company interests or other equity interests of the Partnership, General Partner or any of their Subsidiaries or any securities convertible into or exchangeable for any such partnership interests, limited liability company interests or other equity interests, or any rights, warrants or options to acquire any such partnership interests, limited liability company interests, equity interests or convertible or exchangeable securities or take any action to cause to be exercisable any otherwise unexercisable option under any existing Partnership Benefit Plans (except as otherwise provided by the terms of this Agreement or the express terms of any unexercisable or unexercised options or warrants outstanding on the date hereof), other than (1) issuances of Partnership Common Units in respect of the vesting, exercise or settlement of any Partnership Equity Awards outstanding on the date hereof or as may be granted after the date hereof as permitted under Section 5.2(b)(viii) or (2) for transactions among the Partnership and its Subsidiaries or among the Partnership’s Subsidiaries which remain Subsidiaries after the consummation of such transaction;

(iii) except in the ordinary course of business, shall not, and shall not permit any of its Subsidiaries that is not wholly owned by the Partnership or wholly owned Subsidiaries of any such Subsidiaries to, authorize or pay any dividends on or make any distribution with respect to its outstanding partnership interests, limited liability company interests or other equity interests (whether in cash, assets, stock or other securities of the Partnership or its Subsidiaries), except (1) dividends or distributions by any Subsidiaries only to the Partnership or to any Subsidiary of the Partnership in the ordinary course of business, (2) regular quarterly cash distributions with customary record and payment dates on the Series A Preferred Units not in excess of the quarterly cash distribution amount set forth in the Partnership Agreement (3) dividends or distributions required under applicable organizational documents of the Partnership’s non-wholly owned Subsidiaries to the equityholders of such Subsidiaries, in effect on the date of this Agreement, and (4) regular quarterly cash distributions with customary record and payment dates on the Partnership Common Units not in excess of $0.16525 per Partnership Common Unit per quarter;

(iv) shall not, and shall not permit any of its material Subsidiaries to, adopt a plan of complete or partial liquidation, dissolution, merger, consolidation, restructuring, recapitalization or other reorganization, or enter into a letter of intent or agreement in principle with respect thereto, other than the LP Merger and other than any mergers, consolidations, restructurings or reorganizations solely among the Partnership and its Subsidiaries or among the Partnership’s Subsidiaries or in connection with an acquisition not prohibited by Section 5.1(b)(v);

(v) shall not, and shall not permit any of its Subsidiaries to, make any acquisition of any other person or business or make any loans, advances or capital contributions to, or investments in, any other person with a value in excess of $25 million in the aggregate, except (1) as set forth in Section 5.1(b)(vii) – CapEx of the Partnership Disclosure Schedule (whether or not such acquisition, loan, advance, capital contribution

 

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or investment is made in the same fiscal years as set forth in the Section 5.1(b)(vii) – CapEx of the Partnership Disclosure Schedule) or (2) as made in connection with any transaction among the Partnership and its wholly owned Subsidiaries or among the Partnership’s wholly owned Subsidiaries or (3) capital contributions made in response to any emergency, whether caused by war, terrorism, weather events, public health events (including pandemics and COVID-19), outages or otherwise; provided, however, that the Partnership shall not, and shall not permit any of its Subsidiaries to, make any acquisition of any other person or business or make loans, advances or capital contributions to, or investments in, any other person that would reasonably be expected to prevent, materially impede or materially delay the consummation of the LP Merger;

(vi) shall not, and shall not permit any of its Subsidiaries to, sell, lease, license, transfer, exchange or swap, or otherwise dispose of any properties or non-cash assets with a value in excess of $25 million in the aggregate, except (1) sales, transfers and dispositions of obsolete or worthless equipment, (2) sales, transfers and dispositions of inventory, commodities and produced hydrocarbons, crude oil and refined products in the ordinary course of business or (3) sales, leases, transfers or other dispositions made in connection with any transaction among the Partnership and its wholly owned Subsidiaries or among the Partnership’s wholly owned Subsidiaries;

(vii) shall not, and shall not permit any of its Subsidiaries to, authorize any capital expenditures in excess of $25 million in the aggregate, except for (1) expenditures set forth in Section 5.1(b)(vii) – CapEx of the Partnership Disclosure Schedule (whether or not such capital expenditure is made in the same fiscal years as set forth in the Section 5.1(b)(vii) – CapEx of the Partnership Disclosure Schedule)or (2) expenditures made in response to any emergency, whether caused by war, terrorism, weather events, public health events (including pandemics and COVID-19), outages or otherwise;

(viii) except as required by Law or any Partnership Benefit Plan as in effect on the date of this Agreement, shall not, and shall not permit any of its Subsidiaries to, (1) increase the compensation or other benefits payable or provided to the Partnership’s or General Partner’s directors or officers, except for (A) increases set forth in Section 5.1(b)(viii) of the Partnership Disclosure Schedule, and (B) if (y) the Closing occurs before July 1, 2021, customary increases in the ordinary course of business consistent with past practice for non-officer level employees, not to exceed $450,000 in the aggregate, and (z) the Closing occurs after July 1, 2021, customary increases in the ordinary course of business consistent with past practice for non-officer level employees, not to exceed 2% in the aggregate of base compensation paid to non-officer level employees in 2020, (2) enter into or amend any employment, change of control, severance or retention agreement with any director, officer or employee of the General Partner, the Partnership, (3) establish, adopt, enter into, terminate or amend any Partnership Benefit Plan (or any other employee benefit plan that would be a Partnership Benefit Plan if in effect on the date hereof), (4) enter into, terminate or amend any collective bargaining agreement, (5) make any change in the key management structure of the Partnership or any of its material Subsidiaries, including the hiring of additional officers or the termination of existing officers (other than for cause), (6) grant any

 

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Partnership Equity Awards except for grants set forth in Section 5.1(b)(viii) of the Partnership Disclosure Schedule, or (7) enter into or make any loans or advances to any of its officers, directors, employees, agents, or consultants (other than loans or advances for travel or reasonable business expenses or such loans or advances otherwise made in the ordinary course of business);

(ix) shall not, and shall not permit any of its Subsidiaries to, materially change financial accounting policies or procedures or any of its methods of reporting income, deductions or other material items for financial accounting purposes, except as required by GAAP, SEC rule or policy or applicable Law;

(x) shall not, and shall not permit any of its Subsidiaries to, directly or indirectly, purchase, redeem or otherwise acquire any shares of the capital stock of any of them or any rights, warrants or options to acquire any such shares, except for transactions among the Partnership and its Subsidiaries or among the Partnership’s Subsidiaries;

(xi) shall not, and shall not permit any of its Subsidiaries to, incur, assume, guarantee or otherwise become liable for any indebtedness for borrowed money or any guarantee of such indebtedness, except (1) for any indebtedness among the Partnership and its wholly owned Subsidiaries or among the Partnership’s wholly owned Subsidiaries, (2) for any indebtedness incurred to replace, renew, extend, refinance or refund any existing indebtedness on substantially the same or more favorable terms to the Partnership than such existing indebtedness, (3) for any guarantees by the Partnership of indebtedness of Subsidiaries of the Partnership or guarantees by the Partnership’s Subsidiaries of indebtedness of the Partnership or any Subsidiary of the Partnership, which indebtedness is incurred in compliance with this Section 5.1(b)(xi), (4)indebtedness incurred made in response to any emergency, whether caused by war, terrorism, weather events, public health events (including pandemics and COVID-19), outages or otherwise and (5) any indebtedness incurred pursuant to that Amended and Restated Revolving Credit Agreement dated April 6, 2018 (as amended, restated, or otherwise modified from time to time) by and among the Partnership, Citibank, N.A., as administrative agent, and the lenders party thereto and/or pursuant to the Partnership’s commercial paper program, in the case of this clause (5), not to exceed $125 million in the aggregate; provided, however, that in the case of each of clauses (1) through (5) such indebtedness does not impose or result in any additional restrictions or limitations that would be material to the Partnership and its Subsidiaries, or, following the Closing, Parent and its Subsidiaries, other than any obligation to make payments on such indebtedness and other than any restrictions or limitations to which the Partnership or any Subsidiary is currently subject under the terms of any indebtedness outstanding as of the date hereof;

(xii) other than in the ordinary course of business, shall not, and shall not permit any of its Subsidiaries to, modify, amend or terminate, or waive any rights under any Partnership Material Contract or under any Partnership Permit, in a manner or with an effect that is materially adverse to the Partnership and its Subsidiaries, taken as a whole;

 

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(xiii) other than agreements, arrangements or Contracts made in the ordinary course of business, on terms no less favorable to the Partnership and its Subsidiaries than those generally being proved to or available from unrelated third parties, and in each case involving aggregate payments of less than $50 million, shall not, and shall not permit any of its Subsidiaries to, enter into any agreement, arrangement, Contract or other transaction with any Affiliate, including Caribou, Ox or any of their respective Affiliates or Subsidiaries;

(xiv) shall not, and shall not permit any of its Subsidiaries to, waive, release, assign, settle or compromise any claim, action or proceeding, other than waivers, releases, assignments, settlements or compromises (1) equal to or lesser than the amounts reserved with respect thereto on the balance sheet as of the Balance Sheet Date included in the Partnership SEC Documents or (2) that do not exceed $25 million in the aggregate;

(xv) shall not, and shall not permit any of its Subsidiaries to (except in the ordinary course of business), (1) change its fiscal year or any material method of Tax accounting, (2) make, change or revoke any material Tax election, (3) enter into any closing agreement with respect to, or otherwise settle or compromise, any material liability for Taxes, (4) file any material amended Tax Return or (5) surrender a claim for a material refund of Taxes;

(xvi) except as otherwise permitted by this Agreement or for transactions between the Partnership and its Subsidiaries or among the Partnership’s Subsidiaries, shall not, and shall not permit any of its Subsidiaries, to prepay, redeem, repurchase, defease, cancel or otherwise acquire any indebtedness or guarantees thereof of the Partnership or any Subsidiary, other than (1) at stated maturity, (2) prepayment and repayment of existing indebtedness in connection with any replacement, renewal, extension, refinancing or refund thereof in accordance with Section 5.1(b)(xi), (3) prepayment and repayment of revolving loans (including the Partnership’s commercial paper program) in the ordinary course of business, and (4) any required amortization payments and mandatory prepayments (including mandatory prepayments arising from any change of control put rights to which holders of such indebtedness or guarantees thereof may be entitled), in each case in accordance with the terms of the instrument governing such indebtedness as in effect on the date hereof;

(xvii) shall not, and shall not permit any of its Subsidiaries to, engage in any activity or conduct its business in a manner that would cause less than 90% of the gross income of the Partnership for any calendar quarter since its formation and prior to the Effective Time to be treated as “qualifying income” within the meaning of Section 7704(d) of the Code; and

(xviii) shall not, and shall not permit any of its Subsidiaries to, agree, in writing or otherwise, to take any of the foregoing actions that are prohibited pursuant to clauses (i) through (xvii) of this Section 5.1(b).

 

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(c) Notwithstanding the provisions of this Section 5.1, from the date of this Agreement until the earlier of the Effective Time and the Termination Date, the Partnership and its Subsidiaries may take or refrain from taking any COVID-19 Action so long as (i) prior thereto, the Partnership consults with, and considers in good faith, Parent’s suggestions and/or feedback, or (ii) such COVID-19 Action would not reasonably be expected to materially impact the Partnership’s ability to operate in the ordinary course of business or materially delay or impede the consummation of the LP Merger.

Section 5.2 Conduct of Business by Parent.

(a) From and after the date hereof until the earlier of the Effective Time and the Termination Date, and except (i) as may be required by applicable Law or the regulations or requirements of any stock exchange or regulatory organization applicable to Parent or any of its Subsidiaries, (ii) as may be consented to in writing by the Partnership (which consent shall not be unreasonably withheld, delayed or conditioned), (iii) as may be contemplated or required by this Agreement (including the Pre-Closing Transactions and the Preferred Contribution) or (iv) as set forth in Section 5.2(a) of the Parent Disclosure Schedule, Parent covenants and agrees that the Parent shall and shall cause its Subsidiaries to use commercially reasonable efforts to (x) conduct its businesses in the ordinary course, and (y) preserve substantially intact their present lines of business and preserve their relationships with significant customers and suppliers; provided, however, that no action by Parent or its Subsidiaries with respect to matters specifically addressed by any provision of Section 5.2(b) shall be deemed a breach of this covenant unless such action would constitute a breach of such other provision.

(b) Parent agrees with the Partnership, on behalf of itself and its Subsidiaries, that from the date hereof and prior to the earlier of the Effective Time and the Termination Date, except (w) as may be required by applicable Law or the regulations or requirements of any stock exchange or regulatory organization applicable to Parent or any of its Subsidiaries, (x) as may be consented to by the Partnership (which consent shall not be unreasonably withheld, delayed or conditioned), (y) as may be contemplated or required by this Agreement, including the Pre-Closing Transactions and the Preferred Contributions, or (z) as set forth in Section 5.2(b) of the Parent Disclosure Schedule, Parent:

(i) shall not adopt any material amendments to the Parent Organizational Documents or the certificate of formation, limited liability company agreement or similar organizational documents of Parent GP;

(ii) shall not, and shall not permit any of its Subsidiaries to, issue, sell, pledge, dispose of, encumber, split, combine or reclassify or authorize the issuance, sale, pledge, disposition, encumbrance, split, combination or reclassification of any of its partnership interests, limited liability company interests or other equity interests of Parent or its Subsidiaries or any securities convertible into or exchangeable for any such partnership interests, limited liability company interests or other equity interests, or any rights, warrants or options to acquire any such partnership interests, limited liability company interests, equity interests or convertible or exchangeable securities or take any action to cause to be exercisable any otherwise unexercisable option under any existing Parent Benefit Plans (except as otherwise provided by the terms of this Agreement or the express terms of any unexercisable or unexercised options or warrants outstanding on the date hereof), other than (1) as set forth in Section 5.2(b) of the Parent Disclosure

 

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Schedule, (2) issuances of Parent Common Units in respect of any vesting or exercise of Parent equity awards and settlement of any Parent equity awards outstanding on the date hereof or as may be granted after the date hereof or as may be granted as permitted under this Section 5.2(b), (3) the sale of Parent Common Units pursuant to the exercise of options to purchase Parent Common Units if necessary to effectuate an option direction upon exercise or for withholding of Taxes, (4) the grant of equity compensation awards under the Parent Equity Plans, or (5) for transactions among Parent and its Subsidiaries or among Parent’s Subsidiaries;

(iii) except in the ordinary course of business, shall not, and shall not permit any of its Subsidiaries that is not wholly owned by Parent or wholly owned Subsidiaries of any such Subsidiaries to, authorize or pay any dividends on or make any distribution with respect to its outstanding partnership interests, limited liability company interests or other equity securities (whether in cash, assets, partnership units, stock or other securities of Parent or its Subsidiaries), except (1) dividends or distributions by any Subsidiaries only to Parent or any Subsidiary of Parent in the ordinary course of business, (2) dividends or distributions required under the applicable organizational documents of such entity in effect on the date of this Agreement, and (3) regular quarterly cash distributions with respect to the Parent Common Units and the Eagle Operating Preferred Units as set forth in Section 5.2(b)(iii) of the Parent Disclosure Schedule;

(iv) shall not, and shall not permit any of its material Subsidiaries to, adopt a plan of complete or partial liquidation, dissolution, merger, consolidation, restructuring, recapitalization or other reorganization, other than the LP Merger and other than any merger, consolidation, restructuring or reorganization solely among Parent and its Subsidiaries or among Parent’s Subsidiaries or in connection with an acquisition not prohibited by Section 5.2(b)(v);

(v) shall not, and shall not permit any of its Subsidiaries to, make any acquisition of any other person or business or make loans, advances or capital contributions to, or investments in, any other person that would reasonably be expected to prevent, materially impede or materially delay the consummation of the LP Merger;

(vi) shall not directly or indirectly, purchase, redeem or otherwise acquire any equity securities of Parent or any rights, warrants or options to acquire any such equity securities, except (1) as set forth on Section 5.2(b)(vi) of the Parent Disclosure Schedule or (2) for transactions among Parent and its Subsidiaries or among Parent’s Subsidiaries;

(vii) shall not, and shall not permit any of its Subsidiaries to (except in the ordinary course of business), (1) change its fiscal year or any material method of Tax accounting, (2) make, change or revoke any material Tax election, (3) enter into any closing agreement with respect to, or otherwise settle or compromise, any material liability for Taxes, (4) file any material amended Tax Return or (5) surrender a claim for a material refund of Taxes;

 

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(viii) shall not, and shall not permit any of its Subsidiaries to, engage in any activity or conduct its business in a manner that would cause less than 90% of the gross income of Parent for any calendar quarter since its formation and prior to the Effective Time to be treated as “qualifying income” within the meaning of Section 7704(d) of the Code; and

(ix) shall not, and shall not permit any of its Subsidiaries to, agree, in writing or otherwise, to take any of the foregoing actions that are prohibited pursuant to clauses (i) through (viii) of this Section 5.2(b).

(x) Notwithstanding the provisions of this Section 5.2, from the date of this Agreement until the earlier of the Effective Time and the Termination Date, Parent and its Subsidiaries may take or refrain from taking any COVID-19 Action so long as (i) prior thereto, Parent consults with, and considers in good faith, the Partnership’s suggestions and/or feedback, or (ii) such COVID-19 Action would not reasonably be expected to materially impact Parent’s ability to operate in the ordinary course of business or materially delay or impede the consummation of the LP Merger.

Section 5.3 Mutual Access.

(a) For purposes of furthering the transactions contemplated hereby, each of the Partnership and Parent shall afford the other party and (i) the officers and employees and (ii) the accountants, consultants, legal counsel, financial advisors, financing sources and agents and other representatives (such persons described in this clause (ii), collectively, “Representatives”) of such other party reasonable access during normal business hours, throughout the period prior to the earlier of the Effective Time and the Termination Date, to its and its Subsidiaries’ key employees and properties, contracts, commitments, books and records and any report, schedule or other document filed or received by it pursuant to the requirements of applicable Laws and with such additional accounting, financing, operating, environmental and other data and information regarding the Partnership and its Subsidiaries, as Parent may reasonably request, and Parent and its Subsidiaries, as the Partnership may reasonably request, as the case may be (including information necessary to prepare the Combined Consent Statement/Prospectus). Notwithstanding the foregoing, neither the Partnership nor Parent shall be required to afford such access to the extent it would unreasonably disrupt the operations of such party or any of its Subsidiaries, would cause a violation of any agreement to which such party or any of its Subsidiaries is a party, would cause a risk of a loss of privilege to such party or any of its Subsidiaries, would constitute a violation of any applicable Law or would interfere with the ability of such party or any of its Subsidiaries’ ability to comply with any COVID-19 Measures. Neither the Partnership nor Parent, nor any of their respective officers, employees or Representatives, shall be permitted to perform any onsite procedures (including an onsite study or any Phase II environmental site assessment or other invasive or subsurface testing, sampling, monitoring or analysis) with respect to any property of the other party or any of the other party’s Subsidiaries without the other party’s prior written consent, which consent shall not be unreasonably withheld, conditioned or delayed.

 

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(b) The parties hereto hereby agree that all information provided to them or their respective officers, directors, employees or Representatives in connection with this Agreement and the consummation of the transactions contemplated hereby shall be governed in accordance with the confidentiality agreement, dated as of November 30, 2020, between the Partnership and Parent (the “Confidentiality Agreement”).

Section 5.4 Non-Solicitation.

(a) From the date hereof and prior to the earlier of the Effective Time and the Termination Date, each of the Partnership and the General Partner shall not, and each of them shall cause their respective Subsidiaries, and the respective directors, officers, employees of the Partnership, the General Partner and such Subsidiaries not to, and shall use its reasonable best efforts to cause the Representatives of the Partnership, the General Partner and such Subsidiaries not to: (i) solicit, initiate, knowingly encourage or knowingly facilitate any inquiries or the making of any proposal or offer that constitutes, or would reasonably be expected to lead to, an Acquisition Proposal, (ii) furnish any non-public information regarding the Partnership or any of its Subsidiaries or afford access to the business, properties, books or records of the Partnership or any of its Subsidiaries, to any person (other than Parent, Merger Sub, GP Merger Sub or their respective directors, officers, employees, affiliates or Representatives) in connection with or in response to an Acquisition Proposal or any inquiries regarding an Acquisition Proposal, (iii) engage or participate in any discussions or negotiations with any person (other than Parent, Merger Sub, GP Merger Sub or their respective directors, officers, employees, affiliates or Representatives) with respect to an Acquisition Proposal, (iv) enter into any letter of intent, term sheet, memorandum of understanding, merger agreement, acquisition agreement, exchange agreement or any other agreement (whether binding or not) with respect to any inquiry, proposal or offer that constitutes, or would reasonably be expected to lead to, an Acquisition Proposal or requiring the Partnership to abandon, terminate or fail to consummate the Merger or any other transaction contemplated by this Agreement or (v) agree to do any of the foregoing. Nothing in this Section 5.4 shall prohibit the Partnership, or the GP Board, directly or indirectly through any officer, employee or Representative, from informing any person that the Partnership is party to this Agreement and informing such person of the restrictions that are set forth in this Section 5.4.

(b) Following the execution of this Agreement, each of the Partnership and the General Partner shall, and each of them shall cause their respective Subsidiaries, and the respective directors, officers, employees of the Partnership, the General Partner and such Subsidiaries to, and shall use its reasonable best efforts to cause the Representatives of the Partnership, the General Partner and such Subsidiaries to, immediately cease and terminate any discussions existing as of the date of this Agreement between the Partnership or any of its Subsidiaries or any of their respective officers, directors, employees or Representatives and any person (other than Parent, Merger Sub, GP Merger Sub or any of their respective officers, directors, employees or Representatives) that relate to any Acquisition Proposal.

(c) As used in this Agreement:

(i) “Acquisition Proposal” means any bona fide offer or proposal, whether or not in writing, received from or made public by a third party (other than an offer, proposal by Parent, Merger Sub, GP Merger Sub or their respective affiliates) relating to any Acquisition Transaction; and

 

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(ii) “Acquisition Transaction” means any transaction or series of related transactions (other than the transactions contemplated by this Agreement) pursuant to which any person, other than Parent, Merger Sub or their respective affiliates, (A) directly or indirectly acquires (whether in a single transaction or a series of related transactions, and whether through merger, tender offer, exchange offer, business combination, consolidation or otherwise) assets of the Partnership and its Subsidiaries equal to 25% or more of the Partnership’s consolidated assets (based on their fair market value thereof) or to which 25% or more of the Partnership’s revenues or earnings on a consolidated basis are attributable, or (B) directly or indirectly acquires (whether in a single transaction or a series of related transactions, and whether through merger, tender offer, exchange offer, business combination, consolidation or otherwise) beneficial ownership (within the meaning of Section 13 under the Exchange Act) 25% or more of any class of equity securities of the Partnership entitled to vote with respect to the approval of this Agreement.

Section 5.5 Filings; Other Actions.

(a) As promptly as reasonably practicable following the date of this Agreement, Parent and the Partnership shall prepare and file with the SEC the Form S-4, which will include the Combined Consent Statement/Prospectus. Each of Parent and the Partnership shall use reasonable best efforts to have the Form S-4 declared effective under the Securities Act as promptly as reasonably practicable after such filing and to keep the Form S-4 effective as long as necessary to consummate the LP Merger and the other transactions contemplated hereby. Parent shall also take any action required to be taken under any applicable state or provincial securities laws in connection with the issuance and reservation of Parent Common Units in the LP Merger, and the Partnership shall furnish all information concerning the Partnership and the holders of Partnership Common Units, or holders of a beneficial interest therein, as may be reasonably requested in connection with any such action. No filing of, or amendment or supplement to, the Form S-4 or the Combined Consent Statement/Prospectus will be made by Parent or the Partnership, as applicable, without the other’s prior consent (which shall not be unreasonably withheld, conditioned or delayed) and without providing the other party a reasonable opportunity to review and comment thereon. Parent or the Partnership, as applicable, will advise the other promptly after it receives oral or written notice of the time when the Form S-4 has become effective or any supplement or amendment has been filed, the issuance of any stop order, the suspension of the qualification of the Parent Common Units issuable in connection with the LP Merger for offering or sale in any jurisdiction, or any oral or written request by the SEC for amendment of the Combined Consent Statement/Prospectus or the Form S-4 or comments thereon and responses thereto or requests by the SEC for additional information, and will promptly provide the other with copies of any written communication from the SEC or any state securities commission. If at any time prior to the Effective Time any information relating to Parent or the Partnership, or any of their respective affiliates, officers or directors, is discovered by Parent or the Partnership that should be set forth in an amendment or supplement to any of the Form S-4 or the Combined Consent Statement/Prospectus, so that any of such documents would not include any misstatement of a material fact or omit to state any material fact necessary to make the statements therein, in light of the circumstances under which they were made, not misleading, the party that discovers such information shall promptly notify the other parties hereto and an appropriate amendment or supplement describing such information shall be promptly filed with the SEC and, to the extent required by law, disseminated to the unitholders of the Partnership. For the avoidance of doubt, the Combined Consent Statement/Prospectus shall not be required to include a recommendation by the GP Board or the Conflicts Committee to the Partnership’s unitholders regarding this Agreement.

 

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(b) The General Partner shall distribute to the Partnership’s unitholders the Combined Consent Statement/Prospectus as promptly as practicable after the Form S-4 is declared effective under the Securities Act. The Partnership shall (i) in accordance with the Partnership Organizational Documents, including Sections 13.6 and 13.11 of the Partnership Agreement, and applicable Law, take all actions to establish a record date (which will be as soon as reasonably practicable after the date upon which the Form S-4 is declared effective) for the purpose of determining Partnership unitholders entitled to deliver written consents, and (ii) in accordance with the Partnership Organizational Documents and applicable Law, distribute to the Partnership’s unitholders, the Combined Consent Statement/Prospectus, which shall include a form of consent that may be executed by the public unitholders of the Partnership Common Units in connection with the Requisite Unitholder Approval, as soon as reasonably practicable after the date upon which the Form S-4 becomes effective (and, in the case of the Sponsors, within 24 hours of the Form S-4 being declared effective).

Section 5.6 Equity-Based Awards.

(a) Each award of phantom units that corresponds to Partnership Common Units and vests solely based on the passage of time (including any Seconded Employee Phantom Awards), whether vested or unvested (“Partnership Phantom Units”), that is outstanding immediately prior to the Effective Time, shall, as of the Effective Time, be assumed by Parent and converted into a restricted unit award representing a contractual right to receive Parent Common Units or, in the case of Seconded Employees, the right to receive cash determined based on the value of Parent Common Units (each an “Assumed Restricted Unit Award”). Each such Assumed Restricted Unit Award shall be converted into a restricted unit award to receive a number of Parent Common Units (or the cash equivalent thereof, as applicable) equal to the product obtained by multiplying (x) the number of Partnership Common Units subject to such Partnership Phantom Unit immediately prior to the Effective Time by (y) the Exchange Ratio, rounded up or down to the nearest whole Parent Common Unit. Each Assumed Restricted Unit Award shall otherwise be subject to the same terms and conditions (including as to vesting, distribution equivalent rights and issuance) as were applicable to the Partnership Phantom Unit immediately prior to the Effective Time.

(b) Each award of performance units that corresponds to Partnership Common Units, including Seconded Employee Performance Awards (each, a “Partnership Performance Award,” and together with the Partnership Phantom Units, the “Partnership Equity Awards”), that is outstanding and unvested as of the Effective Time, shall, as of the Effective Time, be measured as to performance as of the Effective Time (or a date reasonably proximate thereto) as determined in good faith by the GP Board and each such Partnership Performance Award shall, with respect to the number of Partnership Common Units that are considered earned with respect thereto based on the higher of actual performance or target shall, as of the Effective Time (the “Earned Performance Units”), be assumed by Parent and converted into an Assumed Restricted Unit Award, which shall have distribution equivalent rights and be eligible to vest solely based

 

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on continued service at the end of the performance period that was originally applicable thereto; provided, however, that the Earned Performance Units will vest upon a “qualifying termination” and, to the extent applicable, will incorporate the provisions related to termination due to “retirement,” as provided in the Partnership Phantom Unit Awards. Notwithstanding the foregoing, with respect to Partnership Performance Awards granted in 2021, the number of Earned Performance Units shall be equal to the target number of units granted, regardless of performance. The number of Parent Common Units that are subject to such Assumed Restricted Unit Awards shall be equal to the number of Earned Performance Units with respect to the corresponding Partnership Performance Award, multiplied by the Exchange Ratio, rounded up or down to the nearest whole Parent Common Unit. Any performance units that correspond to Partnership Common Units that are not Earned Performance Units shall, upon the Effective Time, automatically be cancelled for no consideration.

(c) The General Partner shall take any and all actions reasonably necessary to effectuate the transactions contemplated by this Section 5.6 and such transactions shall be subject to compliance with Section 409A of the Code.

Section 5.7 Employee Matters.

(a) Following the Effective Time and until the first anniversary of the Closing Date (the “Continuation Period”), Parent shall, or shall cause one of its Subsidiaries to, provide the individuals who are employed by the Partnership, the General Partner or any of their Subsidiaries immediately before the Effective Time (the “Current Employees”) and who continue employment during such time period with (i) annual base salary or wages (as applicable) that are no less favorable than the annual base salary or wages (as applicable) provided to such Current Employees immediately prior to the Effective Time,(provided, that the foregoing shall not preclude Parent from implementing broad-based salary or other pay reduction programs following the date of this Agreement that are proportionate with reductions in salary or other pay for Parent’s other similarly situated employees), (ii) severance benefits that are no less favorable than the severance benefits set forth on Section 5.7(a) of the Partnership Disclosure Schedule, provided, however, that severance benefits for those certain employees subject to the Partnership’s February 2021 voluntary early retirement program (the “VERP”) and the other employees set forth on Section 5.7(a) of the Partnership Disclosure Schedule shall be as set forth in the VERP, and (iii) other compensation and employee benefits that are no less favorable than either, at Parent’s election, (A) the other compensation and employee benefits provided to similarly situated employees of Parent and its Subsidiaries, or (B) the other compensation and employee benefits provided to such Current Employees immediately prior to the Effective Time (excluding equity and equity-based compensation, defined benefit and supplemental pensions and retiree medical benefits).

(b) For purposes of vesting, eligibility to participate and, solely for vacation and paid time off policies, severance plans and policies, and disability plans and policies, determining levels of benefits (but not, for the avoidance of doubt, for purposes of benefit accrual under any defined benefit pension plan) under the employee benefit plans of Parent and its Subsidiaries providing benefits to any Current Employees after the Effective Time (the “New Plans”), each Current Employee shall be credited with his or her years of service with the Partnership, the General Partner and their Subsidiaries and their respective predecessors and

 

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prior employers before the Effective Time, to the same extent as such Current Employee was entitled, before the Effective Time, to credit for such service under any similar Partnership Benefit Plan in which such Current Employee participated or was eligible to participate immediately prior to the Effective Time, provided that the foregoing shall not apply to the extent that its application would result in a duplication of benefits with respect to the same period of service. In addition, and without limiting the generality of the foregoing, (i) each Current Employee shall be immediately eligible to participate, without any waiting time, in any and all New Plans to the extent coverage under such New Plan is comparable to a Partnership Benefit Plan in which such Current Employee participated immediately before the Effective Time (such plans, collectively, the “Old Plans”), (ii) for purposes of each New Plan providing medical, dental, pharmaceutical and/or vision benefits to any Current Employee, Parent shall use commercially reasonable efforts to cause all pre-existing condition exclusions and actively-at-work requirements of such New Plan to be waived for such employee and his or her covered dependents, unless and to the extent the individual, immediately prior to entry in the New Plans, was subject to the same such conditions under the comparable Old Plans, (iii) credit amounts paid under any Old Plan providing medical, dental, pharmaceutical and/or vision benefits under any corresponding New Plan for purposes of applying deductibles, co-payments and out-of-pocket maximums as though such amounts had been paid in accordance with the terms and conditions of the New Plan with respect to the plan year in which the Effective Time occurs, and (iv) assume and honor all vacation and paid time off days accrued by Current Employees prior to the Effective Time, including payment for such days upon termination of employment to the extent provided for under Law or the terms of the vacation and paid time off policies of the Partnership, the General Partner and their Subsidiaries, provided however, that the foregoing shall not restrict Parent from amending, modifying or terminating any applicable vacation or paid time off policy to the extent permitted by Law and (v) solely for vacation and paid time off policies, provide credit for years in the energy industry in addition to prior service credit with the Partnership, the General Partner and their Subsidiaries and their respective predecessors before the Effective Time. For purposes of this Agreement, “Benefit Plans” means any (i) “employee benefit plan” (within the meaning of Section 3(3) of ERISA), (ii) bonus, incentive or deferred compensation or equity or equity-based compensation plan, program, policy or arrangement, including employer stock and incentive plans, (iii) severance, change in control, employment, consulting, retirement, retention or termination plan, program, agreement, policy or arrangement or (iv) other compensation or benefit plan, program, agreement, policy, practice, contract, arrangement or other obligation, whether or not in writing and whether or not subject to ERISA, including all bonus, cash or equity-based incentive, deferred compensation, stock purchase, health, medical, dental, disability, accident, life insurance, or vacation, paid time off, perquisite, fringe benefit, severance, change of control, retention, employment, separation, retirement, pension, or savings, plans, programs, policies, agreements or arrangements.

(c) If the Effective Time occurs after July 1, 2021, then as soon as practicable following the Closing Date, Parent shall pay annual incentive bonuses for the 2021 calendar year in an amount equal to the higher of actual performance or target, prorated for the portion of the 2021 calendar year that occurs prior to the Closing Date, under the Partnership Short Term Incentive Plan. If the Effective Time occurs before July 1, 2021, then no pro-rated annual incentive bonuses will be paid in connection with the consummation of the transactions contemplated by this Agreement and the Current Employees will be eligible for annual bonuses for 2021 under the terms of Parent’s applicable short-term incentive plans as if they had been employed with Parent and its Subsidiaries from January 1, 2021.

 

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(d) Parent shall establish and maintain or make provision for, the establishment or continuation of a health care and dependent care flexible spending account plans applicable to Current Employees and the election by any Current Employee under the Partnership Benefit Plan that includes flexible spending accounts will be continued as an election as if made under the applicable Benefit Plan containing flexible spending accounts from the beginning of the plan year of Partnership.

(e) If the Effective Time occurs prior to the end of a school semester, Parent acknowledges that the Partnership, the General Partner or their applicable Subsidiary or applicable successor thereof shall retain their obligations with respect to the Partnership’s tuition reimbursement program for the remainder of that semester and shall provide benefits thereunder in accordance with terms of such program to eligible Current Employees immediately prior to the Effective Time.

(f) If requested by Parent, subject to the terms of any such Partnership Benefit Plan and applicable Law, the Partnership or General Partner, as applicable, shall both (i) execute resolutions to terminate any Partnership Benefit Plan qualified under Section 401(a) of the Code and containing a Code Section 401(k) cash or deferred arrangement (a “Partnership 401(k) Plan”) and (ii) fully vest each Current Employee in his or her account balance in such Partnership 401(k) Plan, in each case, effective at least one day prior to the Closing Date (the “ERISA Effective Date”). Prior to the ERISA Effective Date, the Partnership shall provide Parent with executed resolutions of its or, as applicable, its Subsidiary’s Board of Directors authorizing such termination and amending any such Partnership 401(k) Plan commensurate with its termination to the extent necessary to comply with all applicable Laws. The Partnership and the General Partner shall also take and/or cause their Subsidiaries to take such other actions in furtherance of the termination of each Partnership 401(k) Plan as Parent may reasonably require, including such actions as Parent may require prior to the Effective Time to support Parent obtaining a determination letter with respect to the termination of each Partnership 401(k) Plan following the ERISA Effective Date. Parent shall cause its Parent Benefit Plan qualified under Section 401(a) of the Code and containing a Code Section 401(k) cash or deferred arrangement to accept a direct rollover of any Current Employee’s benefits under the Partnership 401(k) Plan in cash and, if applicable, promissory notes.

(g) Parent acknowledges that the Partnership, the General Partner or their applicable Subsidiary or applicable successor thereof shall retain their obligations under the Partnership Deferred Compensation Plan and all duties and obligations thereunder. Parent will not cause the Partnership Deferred Compensation Plan to be terminated without payment of vested benefits accrued thereunder becoming payable to the participants therein.

(h) Parent hereby acknowledges that a “change of control” (or similar phrase) within the meaning of the Partnership Benefit Plans will occur at or prior to the Effective Time, as applicable. For the avoidance of doubt, Parent shall assume the Partnership Change of Control Plan and all duties and obligations of the Partnership thereunder. Parent will not terminate the Partnership Change of Control Plan prior to the end of the “Protected Period” as defined therein.

 

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(i) Nothing in this Section 5.7 shall be construed as an amendment of, or undertaking to amend, any Benefit Plan or to prevent the amendment or termination of any Benefit Plan in accordance with its terms. Nothing in this Section 5.7 shall limit the right of Parent, the Surviving Entities or any of their Subsidiaries to terminate the employment of any Current Employee at any time, subject to any rights to severance or other separation benefits accrued as of the applicable termination date under a Partnership Benefit Plan. Without limiting the generality of Section 8.13, the provisions of this Section 5.7 (including, for the avoidance of doubt, Section 5.7(j)) are solely for the benefit of the parties to this Agreement, and no current or former director, officer, employee, other service provider or independent contractor or any other person shall be a third-party beneficiary of this Agreement, and nothing herein shall be construed as an amendment to any Partnership Benefit Plan or other compensation or benefit plan or arrangement (including any Benefit Plan of Parent or its Subsidiaries) for any purpose.

(j) Subject to Section 5.7(k) below, Parent, the Partnership and the General Partner shall reasonably cooperate to take such actions as are necessary or desirable to provide for the termination of all Secondment Arrangements, and shall use commercially reasonable efforts to enter into an agreement or agreements with Ox or its applicable affiliate pursuant to which (i) the Secondment Arrangements shall be terminated upon or as soon as reasonably practicable after the Effective Time such that, as of such time of termination, the Seconded Employees shall be eligible to participate in the Benefit Plans of Parent or its applicable Subsidiary(ies) (the actual time of such termination, the “Secondment Termination Time”), excluding those obligations which by the terms of the Secondment Arrangements are intended to survive any such termination; (ii) one of Parent, the Partnership, the General Partner, or an applicable Subsidiary or successor of the foregoing shall have made an offer of employment, effective upon the Secondment Termination Time, to each Seconded Employee with such offers of employment on terms consistent with the provisions of Sections 5.7(a)-(d) and (h) but applying Section 5.7(a)-(d) and (h) with respect to the Seconded Employees by taking into account the compensation and benefits provided to the Seconded Employees by Ox or its applicable affiliate, and the Seconded Employees’ service with Ox or its applicable affiliate as of, immediately prior to the Effective Time (excluding, for the avoidance of doubt, equity and equity-based compensation, defined benefit and supplemental pensions and retiree medical benefits); and (iii) the Termination Costs and Severance Costs (as defined in the applicable Secondment Arrangement) of each Seconded Employee who does not become a Current Employee, or for which a Sponsor is otherwise responsible in respect of any Seconded Employee under the terms of the applicable Secondment Arrangement, will remain the obligation of the Partnership, the General Partner or their applicable Subsidiary or successor to the extent such Termination Costs and Severance Costs are the obligation of the Partnership, the General Partner or their applicable Subsidiary or successor pursuant to the terms of the applicable Secondment Arrangement. For the avoidance of doubt, subject to Section 5.7(k) below, it is expected that all such Seconded Employees who accept such offers and commence employment with Parent, the Partnership, the General Partner, or an applicable Subsidiary or successor of the foregoing shall be considered Current Employees for purposes of this Section 5.7. From and after the date of this Agreement, the General Partner and the Partnership shall, and shall use commercially reasonable efforts to cause any person employing a Seconded Employee to, reasonably cooperate with

 

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Parent and provide Parent with such information regarding the Seconded Employees as is reasonably requested by Parent, including compensation information. Section 5.7(j) of the Partnership Disclosure Schedule sets forth, to the knowledge of the Partnership, a true and correct list of each Benefit Plan or other agreement maintained, sponsored, or entered into by a Sponsor (or an Affiliate thereof) pursuant to which any Termination Costs and Severance Costs would be incurred with respect to any Seconded Employee.

(k) Inactive Seconded Employees. With respect to any Seconded Employee who, as of the Closing, is not actively in service and on a disability or other approved leave of absence (excluding bona fide vacation) (an “Inactive Seconded Employee”), Ox or its applicable affiliate shall employ or shall continue to employ such Inactive Seconded Employee following the Closing and the applicable Secondment Arrangement will remain in effect with respect to and will continue to cover such Inactive Seconded Employee until he or she returns to active service or terminates employment with Ox or its applicable affiliate, and Parent’s, the Partnership’s, the General Partnership’s, or their applicable Subsidiary’s offer of employment to such Inactive Seconded Employee shall be for employment on the earliest reasonably practicable date following the date on which such Inactive Seconded Employee is able to return to work, and otherwise on the terms and conditions consistent with this Section 5.7(k); provided that such Inactive Seconded Employee is able to return to work within 180 days following the Closing Date, or such later time as required by applicable Law. For all purposes of this Agreement, in the case of any Inactive Seconded Employee who becomes a Current Employee, the date that such Inactive Seconded Employee commences (or is deemed to commence) employment with Parent or its Subsidiaries or the time of such commencement (or deemed commencement) of employment shall be substituted for the “Secondment Termination Time,” wherever such term appears, except where the context requires otherwise.

Section 5.8 Regulatory Approvals; Efforts.

(a) Subject to the terms and conditions set forth in this Agreement, each of the parties hereto shall use (and shall cause its Subsidiaries and affiliates (other than Caribou and Ox and their respective affiliates (other than the Partnership and its Subsidiaries) to use) its reasonable best efforts to take, or cause to be taken, promptly all actions, and to do, or cause to be done, promptly and to assist and cooperate with the other parties in doing, all things necessary, proper or advisable under applicable Laws to consummate and make effective the LP Merger and the other transactions contemplated by this Agreement, including using reasonable best efforts to: (i) obtain all necessary actions or nonactions, waivers, clearances, consents and approvals, including the Partnership Approvals and the Parent Approvals, from Governmental Entities and make all necessary registrations, notifications and filings and take other steps as may be necessary to obtain an action or nonaction, waiver, clearance, consent or approval from any Governmental Entity, in each case as promptly as commercially practicable, (ii) obtain all necessary consents, approvals or waivers from third parties other than any Governmental Entity, in each case as promptly as commercially practicable, and (iii) execute and deliver any additional instruments necessary to consummate the transactions contemplated by this Agreement.

 

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(b) Subject to the terms and conditions herein provided and without limiting the foregoing, the Partnership and Parent shall use their reasonable best efforts to (i) as promptly as practicable (and in any event not more than fifteen business days) after the date hereof, make all required or advisable filings under the HSR Act, (ii) make available to the other party such information as the other party may reasonably request in order to make any HSR Act filings or respond to information or document requests by any relevant Governmental Entity, (iii) use reasonable best efforts to take, or cause to be taken, other actions and do, or cause to be done, other things advisable to consummate and make effective the transactions contemplated hereby, and (iv) keep each other apprised of the status of matters relating to the completion of the transactions contemplated hereby, including promptly furnishing the other with copies of substantive notices or other substantive communications or correspondence between the Partnership or Parent, or any of their respective Subsidiaries or affiliates, and any third party and/or any Governmental Entity (or members of their respective staffs) with respect to such transactions. Prior to transmitting any substantive communications, advocacy, white papers, information responses or other submissions to any Governmental Entity (or members of their respective staffs) in connection with the LP Merger or the other transactions contemplated by this Agreement, the Partnership and Parent shall permit counsel for the other parties a reasonable opportunity to review and provide comments thereon, and consider in good faith the views of the other parties in connection therewith. Each of the Partnership and Parent agrees not to participate in any substantive meeting or discussion, either in person or by telephone, with any Governmental Entity in connection with the LP Merger or the other transactions contemplated by this Agreement unless it consults with the other party in advance and, to the extent not prohibited by such Governmental Entity, gives the other parties the opportunity to attend and participate where appropriate and advisable under the circumstances.

(c) In furtherance and not in limitation of the foregoing, each of parties hereto shall use their reasonable best efforts to satisfy the conditions to closing identified in Section 6.1 of this Agreement, including (i) responding to and complying with, as promptly as reasonably practicable, any request for information or documentary material regarding the LP Merger or the other transactions contemplated by this Agreement from any relevant Governmental Entity and (ii) using reasonable best efforts to assist and cooperate with the other party in doing all things necessary, proper or advisable to consummate and make effective the transactions.

(d) Notwithstanding anything herein to the contrary, Parent agrees, and shall cause its Subsidiaries and affiliates, to take any and all steps necessary to (and the Partnership agrees, and shall cause its Subsidiaries and affiliates (other than Caribou and Ox and their respective affiliates (other than the Partnership and its Subsidiaries)), as necessary, to cooperate with Parent to) eliminate each and every impediment under any antitrust or competition law that is asserted by any Governmental Entity or any other party so as to enable the parties hereto to close the transactions contemplated hereby no later than the End Date, including but not limited to (i) negotiating, committing to and effecting by consent decree, hold separate orders, or otherwise, the sale, divestiture or disposition of such of Parent’s and its Subsidiaries’ assets, properties or businesses or of the Partnership’s properties or businesses to be acquired by it pursuant hereto, and the entering into such other arrangements as are necessary in order to effect the dissolution of any injunction, temporary restraining order or other order in any suit or proceeding, that would otherwise have the effect of preventing the consummation of the transactions contemplated by this Agreement no later than the End Date and (ii) defending through litigation on the merits any claim asserted in court by any party in order to avoid entry of, or to have vacated or terminated, any decree, order or judgment (whether temporary,

 

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preliminary or permanent) that would prevent the Closing from occurring no later than the End Date; provided, however, that such litigation in no way limits the other obligations of the parties; provided, further, that notwithstanding anything to the contrary contained in this Section 5.8 or otherwise in this Agreement, Parent and its Subsidiaries and affiliates shall not be required to offer, negotiate, commit to, effect, enter into or take any action, agreement, condition, commitment or remedy of any kind, including but not limited to any sale, divestiture or disposition of any assets, properties or businesses of Parent, the Partnership or their respective Subsidiaries or affiliates that would require Parent or its Subsidiaries or affiliates to sell, divest, lease, license, transfer, dispose of, or otherwise encumber, impair, limit or restrict Parent’s or its Subsidiaries’ or affiliates’ ownership, control, management or operation of assets or businesses (including for the avoidance of doubt, any equity or other interests) of Parent, the Partnership or any of their respective Subsidiaries or affiliates (other than Caribou and Ox and their respective affiliates (other than the Partnership and its Subsidiaries)) meeting or exceeding the Remedy Threshold. The Partnership and its Subsidiaries and affiliates (other than Caribou and Ox and their respective affiliates (other than the Partnership and its Subsidiaries)) (a) shall not, without the prior written consent of Parent, and (b) shall, if requested in writing by Parent, offer, negotiate, commit to, effect, enter into or take any action, agreement, condition, commitment or remedy as described in this Section 5.8(d).

Section 5.9 Takeover Statutes. If any takeover law may become, or may purport to be, applicable to the LP Merger or any other transactions contemplated hereby, each of the Partnership and Parent shall grant such approvals and take such actions as are reasonably necessary so that the transactions contemplated hereby may be consummated as promptly as practicable on the terms contemplated hereby and otherwise act to eliminate or minimize the effects of such statute or regulation on the transactions contemplated hereby.

Section 5.10 Public Announcements. So long as this Agreement is in effect, Parent and the Partnership shall use reasonable best efforts to develop a joint communications plan and each party shall use reasonable best efforts to ensure that all press releases and other public statements with respect to the transactions contemplated hereby, to the extent they have not been previously issued or disclosed, shall be consistent with such joint communications plan. Unless otherwise required by applicable Law or by obligations pursuant to any listing agreement with or rules of any securities exchange, each party shall consult with each other before issuing any press release or public statement with respect to the LP Merger and, subject to the requirements of applicable Law or the rules of any securities exchange, shall not issue any such press release or public statement prior to such consultation. Each of Parent and the Partnership may issue a press release, reasonably acceptable to the other party, announcing this Agreement.

Section 5.11 Indemnification and Insurance.

(a) Parent, Merger Sub and GP Merger Sub agree that all rights to exculpation, indemnification and advancement of expenses for acts or omissions occurring at or prior to the Effective Time, whether asserted or claimed prior to, at or after the Effective Time, now existing in favor of any of the current or former Indemnified Parties as provided in their respective certificate of limited partnership, partnership agreement, certificate of formation, limited liability company agreement (including the Partnership Organizational Documents and the GP Organizational Documents) or other organizational documents or in any agreement shall

 

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survive the Mergers and shall continue in full force and effect. For a period of six years from the Effective Time, Parent, the Surviving Entities shall maintain in effect any and all exculpation, indemnification and advancement of expenses provisions of the Partnership’s, the General Partner’s and any of their respective Subsidiaries’ certificates of limited partnership, partnership agreement, certificates of formation, limited liability company agreements, certificate of incorporation and bylaws or similar organizational documents in effect immediately prior to the Effective Time (including the Partnership Organizational Documents and the GP Organizational Documents) or in any indemnification agreements of the General Partner, the Partnership or their respective Subsidiaries with any of their respective current or former Indemnified Parties in effect immediately prior to the Effective Time, and shall not amend, repeal or otherwise modify any such provisions or the exculpation, indemnification or advancement of expenses provisions (and Parent, Merger Sub and GP Merger Sub shall not authorize or consent to any such amendment, repeal or other modification) of the Surviving Entities’ certificate of limited partnership, certificate of formation, partnership agreement and limited liability company agreement, as applicable, in any manner that would adversely affect the rights thereunder of any individuals who immediately before the Effective Time were current or former Indemnified Parties; provided, however, that all rights to indemnification in respect of any Action pending or asserted or any claim made within such period shall continue until the final disposition of such Action or resolution of such claim. From and after the Effective Time, Parent shall assume, be jointly and severally liable for, and honor, guaranty and stand surety for, and shall cause the GP Surviving Entity, Surviving Entity and its Subsidiaries to honor and perform, in accordance with their respective terms, each of the covenants contained in this Section 5.11 without limit as to time.

(b) Parent and the Surviving Entities shall jointly and severally, to the fullest extent permitted under applicable Law, indemnify and hold harmless (and advance funds in respect of each of the foregoing) each current and former director, officer or employee of the Partnership, General Partner or any of their respective Subsidiaries and each person who served as a director, officer, member, trustee, agent or fiduciary of another corporation, partnership, joint venture, trust, pension or other employee benefit plan or enterprise if such service was at the request or for the benefit of the Partnership, General Partner or any of their respective Subsidiaries (each, together with such person’s heirs, executors or administrators, an “Indemnified Party”), in each case against any costs or expenses (including advancing attorneys’ fees and expenses and other costs and expenses in advance of the final disposition of any claim, suit, proceeding or investigation to each Indemnified Party to the fullest extent permitted by applicable Law; provided, however, that the Indemnified Party to whom expenses are advanced provides an undertaking consistent with the Partnership Organizational Documents to repay such amounts if it is ultimately determined that such person is not entitled to indemnification), judgments, fines, losses, claims, damages, liabilities and amounts paid in settlement in connection with any actual or threatened claim, action, suit, proceeding or investigation, whether civil, criminal, administrative or investigative and including any matters addressed by alternative dispute resolution mechanism(s) (an “Action”), arising out of, relating to or in connection with their status, services or duties as an Indemnified Party or any action or omission by them in their capacities as such occurring or alleged to have occurred whether before or after the Effective Time (including acts or omissions in connection with such Indemnified Party serving as an officer, director, employee, agent or other fiduciary of any entity if such service was at the request or for the benefit of the Partnership and in all cases including any matters pertaining or relating to this Agreement, the transactions contemplated hereby and any approvals, determinations or processes relating to the foregoing). In the event of any such Action, the Surviving Entities shall cooperate with the Indemnified Party in the defense of any such Action.

 

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(c) For a period of six years from the Effective Time, Parent shall cause to be maintained in effect the coverage provided by the policies of directors’ and officers’ liability insurance and fiduciary liability insurance in effect as of the date hereof by the General Partner, Partnership and their respective Subsidiaries with respect to matters existing or arising on or before the Effective Time; provided, however, that Parent shall not be required to pay annual premiums in excess of 300% of the last annual premium paid by the Partnership prior to the date hereof in respect of the coverages (the “Maximum Amount”) required to be obtained pursuant hereto, but in such case shall purchase as much coverage as reasonably available for such amount. If the Partnership in its sole discretion elects, then the Partnership may, prior to the Effective Time, purchase (and prepay in full the aggregate premium for) a “tail policy,” that by its terms survives the Effective Time and the transactions contemplated hereby, with respect to acts or omissions occurring or alleged to have occurred prior to the Effective Time that were committed or alleged to have been committed by such Indemnified Parties in their capacity as such or relating to their status, service or duties as Indemnified Parties (with such policy having at least the same coverage and amounts and containing terms and conditions that are no less favorable to the covered individuals as existing policies); provided that in no event shall the Partnership be required to pay as the cost of such policy in excess of six times the Maximum Amount and, if such a “tail policy” is purchased, Parent shall have no further obligations under this Section 5.11(c). If a “tail policy” is purchased, the Surviving Entity shall, and Parent shall cause the Surviving Entity to, maintain such policies in full force and effect, and continue to honor the obligations thereunder.

(d) Parent shall pay all reasonable expenses, including reasonable attorneys’ fees, that may be incurred by any Indemnified Party in enforcing the indemnity and other obligations provided in this Section 5.11.

(e) The rights of each Indemnified Party shall be in addition to, and not in limitation of, any other rights such Indemnified Party may have under the certificates of limited partnership or partnership agreement or other organization documents of the Partnership or any of its Subsidiaries or the Surviving Entities, any other indemnification arrangement, the Delaware LP Act or otherwise.

(f) In the event Parent, the Surviving Entities or any of their respective successors or assigns (i) consolidates with or merges into any other person and shall not be the continuing or surviving corporation or entity in such consolidation or merger or (ii) transfers all or substantially all of its properties and assets to any person, then, and in either such case, proper provision shall be made so that the successors and assigns of Parent or the Surviving Entities, as the case may be, shall assume the obligations of such party set forth in this Section 5.11. Nothing in this Agreement is intended to, shall be construed to or shall release, waive or impair any rights to directors’ and officers’ insurance claims under any policy that is or has been in existence with respect to the General Partner, Partnership or any of their respective Subsidiaries or their respective officers, directors and employees, it being understood and agreed that the indemnification provided for in this Section 5.11 is not prior to, or in substitution for, any such claims under any such policies.

 

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(g) The obligations of Parent and the Surviving Entities under this Section 5.11 shall not be terminated, amended or modified in any manner so as to adversely affect any Indemnified Party (including their successors, heirs and legal representatives) to whom this Section 5.11 applies without the consent of such Indemnified Party. It is expressly agreed that, notwithstanding any other provision of this Agreement that may be to the contrary, (i) the Indemnified Parties to whom this Section 5.11 applies shall be third-party beneficiaries of this Section 5.11, and (ii) this Section 5.11 shall survive consummation of the LP Merger and shall be enforceable by such Indemnified Parties and their respective successors, heirs and legal representatives against Parent and the Surviving Entity and their respective successors and assigns.

Section 5.12 Control of Operations. Without in any way limiting any party’s rights or obligations under this Agreement, the parties understand and agree that (a) nothing contained in this Agreement shall give Parent or the Partnership, directly or indirectly, the right to control or direct the other party’s operations prior to the Effective Time and (b) prior to the Effective Time, each of the Partnership and Parent shall exercise, consistent with the terms and conditions of this Agreement, complete control and supervision over its operations.

Section 5.13 Section 16 Matters. Prior to the Effective Time, Parent and the Partnership shall take all such steps as may be required to cause any dispositions of Partnership Common Units (including derivative securities with respect to Partnership Common Units) or acquisitions of Parent Common Units (including derivative securities with respect to Parent Common Units) resulting from the transactions contemplated by this Agreement by each individual who is subject to the reporting requirements of Section 16(a) of the Exchange Act with respect to the Partnership or will become subject to such reporting requirements with respect to Parent, to be exempt under Rule 16b-3 promulgated under the Exchange Act.

Section 5.14 Tax Matters.

(a) Parent, the Partnership and the General Partner each acknowledges and agrees that, for U.S. federal income and applicable state and local tax purposes, (a) the Preferred Contributions and the Mergers are intended to be treated as (i) a contribution pursuant to Section 721(a) of the Code by Caribou of all such Series A Preferred Units to Parent in exchange for Series G Preferred Units, (ii) a contribution pursuant to Section 351 of the Code by Parent of the Requisite Corporate Preferred Portion of such Series A Preferred Units to a Subsidiary of Parent that is treated as a corporation for U.S. federal income tax purposes, (iii) a contribution pursuant to Section 721(a) of the Code by each holder of Partnership Common Units of all such Common Units to Parent in exchange for Parent Common Units and (iv) in accordance with IRS Revenue Ruling 99-6, (A) to the Sponsors, the sale by the Sponsors of their interests in the General Partner to Parent in exchange for cash, and (B) to Parent, liquidation of the General Partner followed by a purchase of the assets of the General Partner from the Sponsors in exchange for cash, and (b) none of Parent, the Partnership, the General Partner, nor any partner or member, as the case may be, of Parent, the Partnership or the General Partner is intended to recognize taxable gain (other than any gain resulting from (A) any decrease in partnership liabilities

 

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pursuant to Section 752 of the Code, (B) a disguised sale attributable to contributions of cash or other property to the Partnership or the General Partner after the date of this Agreement and prior to the Effective Time, (C) the receipt of the GP Merger Consideration and (D) the application of Section 897 of the Code and the Treasury Regulations thereunder to any non-U.S. holder of Partnership Common Units or Series A Preferred Units that has beneficially owned more than five percent of the total Partnership Common Units or Series A Preferred Units, respectively, at any time in the five year period ending on the Closing Date) (the “Intended Tax Treatment”). Unless required to do so as a result of a “determination” as defined in Section 1313 of the Code, each of Parent, the Partnership and the General Partner agrees not to make any tax filings or otherwise take any position inconsistent with the Intended Tax Treatment and to cooperate with the other parties to make any filings, statements, or reports required to effect, disclose or report the Intended Tax Treatment.

(b) Each of Parent and the Partnership will (and will cause its respective Subsidiaries to) use its reasonable best efforts to cause the Preferred Contributions and the Mergers, taken together, to properly be treated, and will not take or knowingly fail to take (and will cause its Subsidiaries not to take or knowingly fail to take) any actions that would reasonably be expected to prevent or impede the Preferred Contributions and the Mergers, taken together, from properly being treated, in accordance with the Intended Tax Treatment.

(c) Each of Parent, the General Partner and the Partnership will use its reasonable best efforts and will reasonably cooperate with one another to obtain the opinions of counsel referred to in Section 6.1(e), Section 6.1(f), Section 6.2(e) and Section 6.3(d) (the “Required Tax Opinions”). In connection therewith, (i) Parent shall deliver to requisite counsels one or more duly executed certificates containing such representations as shall be reasonably necessary or appropriate to enable such counsels to render the Required Tax Opinions, as applicable (the “Parent Tax Certificate”) and (ii) the Partnership shall deliver to requisite counsels one or more duly executed certificates containing such representations as shall be reasonably necessary or appropriate to enable such counsels to render the Required Tax Opinions, as applicable (the “Partnership Tax Certificate”), in each case dated as of the Closing Date (and, if requested, Parent and the Partnership shall deliver such certificates to requisite counsels in connection with any opinions to be filed in connection with the Form S-4 dated as of the date of such opinions), and Parent, the General Partner and the Partnership shall provide such other information as reasonably requested by counsels for purposes of rendering the Required Tax Opinions (or any opinions to be filed in connection with the Form S-4).

(d) Parent shall (i) prepare and file any U.S. federal (and applicable state and local) income Tax Returns for the Partnership for the tax year including the Closing Date (and any prior years for which such returns are not yet filed as of Closing) in accordance with the past practices of the Partnership (other than reflecting an interim closing of the books under Section 706 of the Code on the Closing Date), and (ii) provide Caribou and Ox with access to such Partnership files, work papers and other materials as Caribou or Ox may reasonably request to confirm that such Tax Returns have been prepared in accordance with the past practices of the Partnership.

 

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(e) Parent shall cause the Requisite Corporate Preferred Portion of the Series A Preferred Units (or any interest in the Partnership into which such Series A Preferred Units are converted) to be held by a Subsidiary of Parent that is treated as a corporation for U.S. federal income tax purposes or another Subsidiary of Parent (the “Preferred Holding Subsidiary”) that is regarded as separate from Parent or any Parent affiliate that owns interests in the Partnership other than the Requisite Corporate Preferred Portion for U.S. federal income tax purposes for the longer of (A) a period of six months following the Closing or (B) through the end of the calendar year that includes the Closing.

Section 5.15 NYSE Listing. Parent shall cause the Parent Common Units to be issued in the LP Merger and such other Parent Common Units to be reserved for issuance in connection with the LP Merger to be approved for listing on the NYSE, subject to official notice of issuance, prior to the Closing Date.

Section 5.16 Financing Assistance.

(a) Prior to the Effective Time, the Partnership shall, and shall cause its Subsidiaries and their respective Representatives to, use commercially reasonable efforts to provide customary cooperation in connection with any financing by Parent or any of its Subsidiaries in connection with the LP Merger, in each case, as may be reasonably requested by Parent, Merger Sub or their Representatives. Notwithstanding anything to the contrary herein, Parent and Merger Sub acknowledge and agree that consummation of any such financing by Parent or any of its Subsidiaries is not a condition to Closing or any of their respective obligations under this Agreement. Without limiting the generality of the foregoing, the Partnership shall, and shall cause its Subsidiaries and their respective Representatives to, upon reasonable request of Parent, (i) furnish the report of the Partnership’s auditor on the three most recently available audited consolidated financial statements of the Partnership and its Subsidiaries and use its commercially reasonable efforts to obtain the consent of such auditor to the use of such reports, including in documents filed with the SEC under the Securities Act, in accordance with normal custom and practice and use commercially reasonable efforts to cause such auditor to provide customary comfort letters to the arrangers, underwriters, initial purchasers or placement agents, as applicable, in connection with any such financing; (ii) furnish any customary additional financial statements, schedules, business or other financial data relating to the Partnership and its Subsidiaries as may be reasonably necessary to consummate any such financing, including providing customary assistance for the preparation of any pro forma financial information or pro forma financial statements required pursuant to the Securities Act or as may be customary and reasonably necessary in connection with any such financing (it being understood, in any event, that Parent shall be solely responsible for the preparation of any such pro forma financial information and/or pro forma financial statements); (iii) provide customary direct contact between (x) senior management and advisors, including auditors, of the Partnership and (y) the proposed arrangers, lenders, underwriters, initial purchasers or placement agents, as applicable, and/or Parent’s auditors, as applicable, in connection with any such financing, at reasonable times during regular business hours, and upon reasonable advance notice; (iv) make available, at reasonable times during regular business hours, and upon reasonable advance notice, the employees and advisors of the Partnership and its Subsidiaries to provide customary assistance with Parent’s or its Subsidiaries’ preparation of business projections; (v) obtain the reasonable cooperation and assistance of counsel to the Partnership and its Subsidiaries in connection with the customary legal opinions that counsel to Parent and its Subsidiaries may require to deliver with respect to any such financing; (vi) reasonably assist

 

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in the preparation of (but not, in each case of the following, entering into or executing) documents, opinions, certificates, and other agreements (including indentures or supplemental indentures) and take other actions that are or may be customary in connection with any such financing or necessary or desirable to permit Parent or its Subsidiaries to fulfill conditions or obligations under the financing documents, provided that such agreements shall be conditioned upon, and shall not take effect until, the Effective Time; (vii) reasonably assist in the preparation of one or more customary confidential information memoranda, prospectuses, offering memoranda and other marketing and syndication materials reasonably requested by Parent and reasonably necessary for such financing; (viii) permit Parent or its Subsidiaries’ customary use of the Partnership’s and its Subsidiaries’ logos for syndication and underwriting, as applicable, in connection with any such financing (subject to (A) advance review of and consultation with respect to such use; provided that, Parent agrees not to use any such logos to the extent that after such consultation the Partnership informs Parent that, despite the Partnership’s use of commercially reasonable efforts to remove or obtain a waiver of such prohibition, such use is prohibited by existing contractual obligations of the Partnership and its Subsidiaries, and (B) such use is not intended to, nor reasonably likely to, harm or disparage the Partnership or any of its Subsidiaries), (ix) participate in a reasonable number of meetings and presentations, during regular business hours and upon reasonable advance notice, with arrangers and prospective lenders and investors, as applicable (including the participation in such meetings of the Partnership’s senior management) and, in each case, at times and locations to be mutually agreed, (x) as further set forth in Section 5.16(c) below, take customary actions as may be reasonably requested by Parent in connection with the repayment of certain existing indebtedness for borrowed money of the Partnership and its Subsidiaries, including delivery of customary payoff and release documentation with respect thereto and (xi) use commercially reasonable efforts to assist in procuring any necessary rating agency ratings or approvals for such financing.

(b) Notwithstanding anything in this Section 5.16 to the contrary, in fulfilling its obligations pursuant to this Section 5.16, (i) none of the General Partner, the Partnership, its Subsidiaries or their respective Representatives shall be required to (A) pay any commitment or other fee, provide any security or incur any other liability in connection with any financing prior to the Effective Time (B) enter into any definitive agreement the effectiveness of which is not conditioned upon Closing, or (C) give any indemnities that are effective prior to the Effective Time, (ii) any requested cooperation shall not unreasonably interfere with the ongoing operations or business of the Partnership and its Subsidiaries and (iii) Parent shall, promptly upon request by the Partnership, reimburse the General Partner and the Partnership for all reasonable and documented out-of-pocket costs and expenses (including, without limitation, reasonable and documented out-of-pocket auditor’s, accountant’s, and attorneys’ fees) incurred by the General Partner, the Partnership or any of its Subsidiaries or their respective Representatives in connection with such cooperation. Parent shall indemnify and hold harmless the General Partner, the Partnership and its Subsidiaries from and against any and all claims, losses, or damages suffered or incurred by them directly or indirectly in connection with the arrangement of any such financing or any information provided in connection therewith (other than to the extent related to information provided by the General Partner, the Partnership, its Subsidiaries or their respective Representatives that contains any untrue statement of a material fact or omits to state any material fact required to be stated therein or necessary in order to make the statements therein, in light of the circumstances under which they are made, not misleading). In addition, no action, liability, or obligation of the General Partner, the Partnership, any of its Subsidiaries, or

 

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any of their respective Representatives pursuant to any agreement, arrangement, contract, certificate, instrument, or other document relating to any such financing will be effective until the Effective Time, and none of the General Partner, the Partnership, nor any of its Subsidiaries will be required to take any action pursuant to any of the foregoing that is not contingent on the occurrence of the Closing or that must be effective before the Effective Time. Further, nothing in this Section 5.16 will require (1) the General Partner, the Partnership, its Subsidiaries, or their respective Representatives to execute, deliver or enter into, or perform any agreement, document or instrument, including any definitive financing document, with respect to any financing or adopt resolutions approving the agreements, documents and/or instruments pursuant to which any financing is obtained or pledge any collateral with respect to any financing prior to Closing or (2) any officer or Representative of the General Partner, the Partnership or any of its Subsidiaries to deliver any certificate or take any other action under this Section 5.16 that could reasonably be expected to result in personal liability to such officer or Representative, or (3) the Representatives of the General Partner, the Partnership or its Subsidiaries to deliver any legal opinions with respect to such financing.

(c) At the request of Parent, the Partnership shall deliver to Parent on or prior to the Closing Date customary payoff letters or other satisfactory documentation from any third-party lenders (or agents therefor), trustees, or other holders of indebtedness of the Partnership or its Subsidiaries (or representatives therefor), as applicable, in the customary forms of such lenders, trustees or other holder of indebtedness or otherwise in form reasonably satisfactory to Parent, in each case, solely with respect to the indebtedness or obligations of the Partnership and its Subsidiaries set forth in Section 5.16(c) of the Partnership Disclosure Schedule (provided, that the Partnership shall use its commercially reasonable efforts to deliver such payoff letters or other documentation, as applicable, referred to in this clause (c) to Parent at least one calendar day prior to the Closing Date); provided, however, that the Partnership and its Subsidiaries shall not be obligated to make or cause to become effective any such action (nor shall the Partnership or any of its Subsidiaries be required to incur any cost or liability in respect thereof), and no such borrowings or indebtedness shall be repaid, prior to the Effective Time. The Partnership shall reasonably cooperate with Parent in replacing any letters of credit issued pursuant to the facilities evidencing the above referenced indebtedness or obligations.

(d) The Partnership shall, at the written request of Parent, (i) call for prepayment or redemption, or prepay or redeem, (ii) use commercially reasonable efforts to attempt to renegotiate the terms of, (iii) commence an offer to purchase and/or consent solicitation or (iv) satisfy and discharge or defease any then-existing indebtedness for borrowed money of the Partnership or any of its Subsidiaries; provided, however, that the Partnership and its Subsidiaries shall not be obligated to make or cause to become effective any such action (nor shall the Partnership or any of its Subsidiaries be required to incur any cost or liability in respect thereof) prior to the Effective Time. For the avoidance of doubt, any such redemption, prepayment or other payment made to satisfy and discharge or defease such portion of indebtedness for borrowed money of the Partnership or any of its Subsidiaries prior to or at Closing shall be the sole obligation of Parent, and all reasonable and documented out-of-pocket costs and expenses incurred by the Partnership or any of its Subsidiaries or their respective Representatives under this clause (d) shall be promptly reimbursed by Parent upon request. Parent shall prepare all necessary and appropriate documentation in connection with any action described above, and provide the Partnership, its Subsidiaries, and their respective Representatives with a reasonable opportunity and prior notice to comment on such documents. Parent and the Partnership shall, and shall cause their respective Subsidiaries and Representatives to, reasonably cooperate with each other in the preparation of such documents.

 

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Section 5.17 Obligations of Merger Subs and the Surviving Entities. Parent shall take all action necessary to cause each of the Merger Subs and the Surviving Entities to perform their respective obligations under this Agreement.

Section 5.18 Termination of Certain Agreements. Prior to the Effective Time, the agreements and arrangements (a) between the Sponsors relating to the Partnership, the General Partner and/or the Subsidiaries of the Partnership and (b) between a Sponsor and the Partnership, the General Partner and/or the Subsidiaries of the Partnership, in each case, as set forth Section 5.18 of the Partnership Disclosure Schedule, shall be terminated.

Section 5.19 Resignations. At or prior to the Closing Date, the General Partner shall (i) deliver duly executed letters of resignation or (ii) cause the removal, in each case, effective as of the Closing Date, of any member of the GP Board, manager, and/or officer of the General Partner, the Partnership or any of their respective Subsidiaries thereof that have been designated in writing by Parent at least three business days prior to the Closing Date (it being understood that such resignation shall not constitute a voluntary termination of employment with respect to any officer or director of the Partnership or its Subsidiaries).

Section 5.20 Distributions. After the date of this Agreement until the Effective Time, each of Parent and the Partnership shall coordinate with the other regarding the declaration of any distributions:

(a) in respect of Parent Common Units, Partnership Common Units and the record dates and payment dates relating thereto, it being the intention of the parties that holders of Partnership Common Units shall not receive, for any quarter, distributions both in respect of Partnership Common Units and also distributions in respect of Parent Common Units, as the case may be, that they receive in exchange therefor as LP Merger Consideration, but that they shall receive for any such quarter either: (a) only distributions in respect of Partnership Common Units or (b) only distributions in respect of Parent Common Units that they receive as LP Merger Consideration; and

(b) in respect of Series A Preferred Units and the Series G Preferred Units and the record dates and payment dates relating thereto, it being the intention of the parties that holders of Series A Preferred Units shall not receive, for any quarter, distributions both in respect of Series G Preferred Units and also distributions in respect of Series A Preferred Units, as the case may be, that they receive in connection with the Preferred Contribution and Issuance, but that they shall receive for any such quarter either: (a) only distributions in respect of Series A Preferred Units or (b) only distributions in respect of Series G Preferred Units that they receive in connection with the Preferred Contribution and Issuance.

 

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Section 5.21 Conflicts Committees. Prior to the Effective Time, the General Partner shall not, without the consent of the Conflicts Committee, eliminate the Conflicts Committee, or revoke or diminish the authority of the Conflicts Committee or remove or cause the removal of any director of the General Partner that is a member of the Conflicts Committee either as a member of the GP Board or the Conflicts Committee. For the avoidance of doubt, this Section 5.21 shall not apply to the filling of any vacancies caused by the death, incapacity or resignation of any director in accordance with the provisions of the organizational documents of the General Partner.

Section 5.22 Treatment of SESH. Notwithstanding anything to the contrary, with respect to SESH, the Partnership’s or the General Partner’s obligations under any section in this Agreement to cause SESH to take an action or not to take an action shall be deemed satisfied so long as the Partnership or the General Partner, as applicable, takes all lawful actions available to it and within its power under the organizational documents of SESH in order to cause SESH to take or not take such action; provided, however, that in connection with the foregoing, the Partnership or the General Partner, as applicable, shall not be obligated to take any action that would violate the applicable organizational documents or other binding governance arrangements of SESH or in contravention of the rights of the other parties to SESH.

ARTICLE VI.

CONDITIONS TO THE MERGERS

Section 6.1 Conditions to Each Partys Obligation to Effect the Mergers. The respective obligations of each party to effect the Mergers shall be subject to the fulfillment (or waiver by all parties, to the extent permissible under applicable Law) at or prior to the Effective Time of the following conditions:

(a) The Requisite Unitholder Approval shall have been obtained in accordance with applicable Law and the Partnership Organizational Documents;

(b) No injunction, order or decree by any court or other Governmental Entity of competent jurisdiction shall have been entered and shall continue to be in effect, no Law shall have been adopted or be effective, and no agreement with any Governmental Entity shall be in effect, in each case that prohibits, prevents or makes unlawful the consummation of the Mergers or the other transactions contemplated by this Agreement;

(c) All waiting periods (and any extensions thereof) applicable to the Mergers or the other transactions contemplated by this Agreement under the HSR Act shall have expired or been terminated;

(d) The Form S-4 shall have been declared effective by the SEC under the Securities Act and no stop order suspending the effectiveness of the Form S-4 shall have been issued by the SEC and no proceedings for that purpose shall have been initiated or threatened by the SEC;

(e) Parent shall have received an opinion of Latham & Watkins dated as of the Closing Date to the effect that (A) at least 90% of the gross income of Parent for all of the calendar year that immediately precedes the calendar year that includes the Closing Date and each calendar quarter of the calendar year that includes the Closing Date for which the necessary financial information is available is from sources treated as “qualifying income” within the

 

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meaning of Section 7704(d) of the Code and (B) at least 90% of the combined gross income of each of Parent and the Partnership for all of the calendar year that immediately precedes the calendar year that includes the Closing Date and each calendar quarter of the calendar year that includes the Closing Date for which the necessary financial information is available is from sources treated as “qualifying income” within the meaning of Section 7704(d) of the Code. In rendering such opinion, Latham & Watkins shall be entitled to receive and rely upon the Parent Tax Certificate, the Partnership Tax Certificate and any other representations, warranties and covenants of officers of Parent and the Partnership and any of their respective affiliates, which for the avoidance of doubt, for purposes of this Section 6.1(e), shall include the Sponsors, as to such matters as such counsel may reasonably request; and

(f) The Partnership shall have received an opinion of Vinson & Elkins L.L.P. (“Vinson & Elkins”) dated as of the Closing Date to the effect that at least 90% of the gross income of the Partnership for all of the calendar year that immediately precedes the calendar year that includes the Closing Date and each calendar quarter of the calendar year that includes the Closing Date for which the necessary financial information is available is from sources treated as “qualifying income” within the meaning of Section 7704(d) of the Code. In rendering such opinion, Vinson & Elkins shall be entitled to receive and rely upon the Partnership Tax Certificate, the Parent Tax Certificate and any other representations, warranties and covenants of officers of the Partnership and any of its respective affiliates, which, for the avoidance of doubt, for purposes of this Section 6.1(f), shall include the Sponsors, as to such matters as such counsel may reasonably request.

Section 6.2 Conditions to Obligation of the Partnership to Effect the Mergers. The obligation of the Partnership and the General Partner to effect the Mergers is further subject to the fulfillment (or waiver by both the Partnership and the General Partner) at or prior to the Effective Time of the following conditions:

(a) The representations and warranties of Parent, Merger Sub and GP Merger Sub set forth in (i) this Agreement (other than in Section 4.2(a), Section 4.10(b) and Section 4.10(c)) shall be true and correct both at and as of the date of this Agreement and at and as of the Closing Date as though made at and as of the Closing Date, except where such failures to be so true and correct (without regard to “materiality,” Parent Material Adverse Effect and similar qualifiers contained in such representations and warranties) would not, in the aggregate, reasonably be expected to have a Parent Material Adverse Effect, (ii) Section 4.2(a) shall be true and correct both at and as of the date of this Agreement and at and as of the Closing Date as though made at and as of the Closing Date, except for any immaterial inaccuracies, and (iii) Section 4.10(b) and Section 4.10(c) shall be true and correct both at and as of the date of this Agreement and at and as of the Closing Date as though made at and as of the Closing Date; provided, however, that representations and warranties that are made as of a particular date or period shall be true and correct (in the manner set forth in clause (i), (ii) or (iii), as applicable) only as of such date or period;

(b) Parent shall have in all material respects performed all obligations and complied with all covenants required by this Agreement to be performed or complied with by it prior to the Effective Time;

 

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(c) Parent shall have delivered to the Partnership a certificate, dated the Closing Date and signed by the Chief Executive Officer or another senior officer of Parent GP, certifying to the effect that the conditions set forth in Section 6.2(a) and Section 6.2(b) have been satisfied;

(d) The Parent Common Units to be issued in the LP Merger shall have been approved for listing on the NYSE, subject to official notice of issuance;

(e) The Partnership and the General Partner shall have received an opinion of Vinson & Elkins (upon which each Sponsor is entitled to rely) dated as of the Closing Date to the effect that for U.S. federal income tax purposes (i) the Partnership should not recognize any income or gain as a result of the Mergers and (ii) no gain or loss should be recognized by holders of Partnership Common Units (in their capacity as holders of Partnership Common Units) as a result of the Mergers (other than any gain resulting from (A) any decrease in partnership liabilities pursuant to Section 752 of the Code, (B) from the deemed sale of Parent Common Units pursuant to Section 2.3, (C) a disguised sale attributable to contributions of cash or other property to the Partnership after the date of this Agreement and prior to the Effective Time and (D) the application of Section 897 of the Code and the Treasury Regulations thereunder to any non-U.S. holder of Partnership Common Units that has beneficially owned more than five percent of the total Partnership Common Units at any time in the five year period ending on the Closing Date). In rendering such opinion, Vinson & Elkins shall be entitled to receive and rely upon the Partnership Tax Certificate, the Parent Tax Certificate and any other representations, warranties and covenants of officers of the Partnership, the General Partner and Parent and any of their respective affiliates, which, for the avoidance of doubt, for purposes of this Section 6.2(e), shall include the Sponsors, as to such matters as such counsel may reasonably request;

(f) The Pre-Closing Transactions shall have been completed;

(g) The Preferred Contributions shall have been completed; and

(h) Parent shall have delivered a duly executed counterpart to the Registration Rights Agreement.

Section 6.3 Conditions to Obligation of Parent to Effect the Mergers. The obligation of Parent to effect the Mergers is further subject to the fulfillment (or the waiver by Parent) at or prior to the Effective Time of the following conditions:

(a) The representations and warranties of the Partnership and the General Partner set forth in (i) this Agreement (other than in Section 3.2(a), Section 3.10(b) and Section 3.10(c)) shall be true and correct both at and as of the date of this Agreement and at and as of the Closing Date as though made at and as of the Closing Date, except where such failures to be so true and correct (without regard to “materiality,” Partnership Material Adverse Effect and similar qualifiers contained in such representations and warranties) would not, in the aggregate, reasonably be expected to have a Partnership Material Adverse Effect, (ii) Section 3.2(a) shall be true and correct at and as of the date

 

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of this Agreement and at and as of the Closing Date as though made at and as of the Closing Date, except for any immaterial inaccuracies, and (iii) Section 3.10(b) and Section 3.10(c) shall be true and correct both at and as of the date of this Agreement and at and as of the Closing Date as though made at and as of the Closing Date; provided, however, that representations and warranties that are made as of a particular date or period shall be true and correct (in the manner set forth in clauses (i), (ii) and (iii), as applicable) only as of such date or period;

(b) The Partnership shall have in all material respects performed all obligations and complied with all covenants required by this Agreement to be performed or complied with by it prior to the Effective Time;

(c) The Partnership shall have delivered to Parent a certificate, dated the Closing Date and signed by the Chief Executive Officer or another senior officer of the General Partner, certifying to the effect that the conditions set forth in Section 6.3(a) and Section 6.3(b) have been satisfied; and

(d) Parent shall have received an opinion of Latham & Watkins dated as of the Closing Date to the effect that for U.S. federal income tax purposes (i) Parent should not recognize any income or gain as a result of the Mergers (other than any gain resulting from any decrease in partnership liabilities pursuant to Section 752 of the Code), and (ii) no gain or loss should be recognized by holders of Parent Common Units immediately prior to the Mergers as a result of the Mergers (other than any gain resulting from any decrease in partnership liabilities pursuant to Section 752 of the Code). In rendering such opinion, Latham & Watkins shall be entitled to receive and rely upon the Parent Tax Certificate, the Partnership Tax Certificate and any other representations, warranties and covenants of officers of Parent, the Partnership and the General Partner and any of their respective affiliates, which, for the avoidance of doubt, for purposes of this Section 6.3(d),shall include the Sponsors, as to such matters as such counsel may reasonably request.

Section 6.4 Frustration of Closing Conditions. Neither the Partnership nor Parent may rely, either as a basis for not consummating the LP Merger or terminating this Agreement and abandoning the LP Merger, on the failure of any condition set forth in Section 6.1, Section 6.2 or Section 6.3, as the case may be, to be satisfied if such failure was caused by such party’s willful and intentional breach of any material provision of this Agreement.

ARTICLE VII.

TERMINATION

Section 7.1 Termination or Abandonment. Notwithstanding anything in this Agreement to the contrary, this Agreement may be terminated and abandoned at any time prior to the Effective Time:

(a) by the mutual written consent of the Partnership and Parent;

 

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(b) by either the Partnership or Parent, if the LP Merger shall not have been consummated on or prior to November 30, 2021 (the “End Date”); provided, however, that if all of the conditions to Closing, other than any of the conditions set forth in Section 6.1(b) or Section 6.1(c), shall have been satisfied or shall be capable of being satisfied at such time, the End Date shall automatically be extended to February 28, 2022, which date shall thereafter be deemed to be the End Date; provided, further, that the right to terminate this Agreement pursuant to this Section 7.1(b) shall not be available to a party if the failure of the Closing to occur by such date shall be due to the material breach by such party of any representation, warranty, covenant or other agreement of such party set forth in this Agreement;

(c) by either the Partnership or Parent, if an injunction or other Law shall have been entered, enacted or become effective permanently restraining, enjoining or otherwise prohibiting the consummation of the Mergers and such injunction or other Law has become final and nonappealable; provided, however, that the right to terminate this Agreement under this Section 7.1(c) shall not be available to a party if such injunction was due to the material breach by such party of any covenant or other agreement of such party set forth in this Agreement;

(d) by the Partnership, if Parent, Merger Sub or GP Merger Sub shall have breached or failed to perform any of its representations, warranties, covenants or other agreements contained in this Agreement, which breach or failure to perform (i) if it occurred or was continuing to occur on the Closing Date, would result in a failure of a condition set forth in Section 6.2(a) or Section 6.2(b) and (ii) by its nature, cannot be cured prior to the End Date or, if such breach or failure is capable of being cured by the End Date, Parent does not diligently attempt or ceases to diligently attempt to cure such breach or failure after receiving written notice from the Partnership describing such breach or failure in reasonable detail (provided that the Partnership is not then in material breach of any representation, warranty, covenant or other agreement contained herein);

(e) by Parent, if the Partnership or the General Partner shall have breached or failed to perform any of its representations, warranties, covenants or other agreements contained in this Agreement, which breach or failure to perform (i) if it occurred or was continuing to occur on the Closing Date, would result in a failure of a condition set forth in Section 6.3(a) or Section 6.3(b) and (ii) by its nature, cannot be cured prior to the End Date or, if such breach or failure is capable of being cured by the End Date, the Partnership or the General Partner, as applicable, does not diligently attempt, or ceases to diligently attempt, to cure such breach or failure in such a manner that would make it reasonably likely that such breach or failure will be cured prior to the End Date, in each case after receiving written notice from Parent describing such breach or failure in reasonable detail (provided that Parent is not then in material breach of any representation, warranty, covenant or other agreement contained herein); and

(f) by Parent, if the Partnership or the General Partner shall have Willfully Breached any of its obligations under Section 5.4, which materially impedes, interferes with or hinders the consummation of the transactions contemplated hereby on or before the End Date.

 

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Section 7.2 Effect of Termination. In the event of termination of this Agreement pursuant to Section 7.1, this Agreement shall terminate (except for the provisions of this Section 7.2, Section 7.3 and Article VIII), and there shall be no other liability on the part of the Partnership or Parent to the other, except, subject to Section 7.3, for liability arising out of or the result of, fraud or any Willful Breach of any covenant or agreement or Willful Breach of any representation or warranty in this Agreement occurring prior to termination or as provided for in the Confidentiality Agreement, in which case the aggrieved party shall be entitled to all rights and remedies available at law or in equity.

Section 7.3 Breakup Fee.

(a) If (i) this Agreement is terminated by Parent pursuant to Section 7.1(f) [Willful Breach], then the Partnership shall pay the Break-Up Fee to Parent, within three business days of such termination, by wire transfer of same day federal funds to the account specified by Parent.

(b) If (i) this Agreement is terminated by Parent pursuant to Section 7.1(e) [Breach of Representation or Failure to Perform Covenant] and (ii) prior to such termination and after the date of this Agreement, any person (other than Parent, Merger Sub or any of their respective affiliates) shall have made an Acquisition Proposal, which shall have been publicly announced or disclosed or otherwise communicated to the GP Board or any affiliate of the General Partner (including Caribou and Ox but excluding their respective affiliates (other than the Partnership and its Subsidiaries)) and not have been withdrawn prior to such termination and (iii) within 12 months after the date of such termination, the Partnership enters into a definitive agreement with respect to an Acquisition Proposal (or publicly approves or recommends to the unitholders of the Partnership or otherwise does not oppose, in the case of a tender or exchange offer, an Acquisition Proposal) or consummates an Acquisition Proposal, then the Partnership shall pay to Parent, within three business days of the first to occur of the events described in clause (iii), the Breakup Fee , by wire transfer of same day federal funds to the account specified by Parent.

(c) Solely for purposes of this Section 7.3, “Acquisition Transaction” shall have the meaning ascribed thereto in Section 5.4(c)(i), except that all references to “25% or more” shall be changed to “more than 50%.”

(d) As used in this Agreement, “Breakup Fee” means $97,500,000.

Upon payment of the Breakup Fee to Parent pursuant to Section 7.3(a) or Section 7.3(b), no parties shall have any further liability with respect to this Agreement or the transactions contemplated hereby to the Partnership or its unitholders or Parent or its unitholders, as applicable; provided that nothing herein shall release any party from liability arising out of or the result of fraud. The parties acknowledge and agree that in no event shall the Partnership be required to pay the Breakup Fee, as applicable, on more than one occasion. In addition, the parties acknowledge that the agreements contained in this Section 7.3 are an integral part of the transactions contemplated by this Agreement and are not a penalty, and that, without these agreements, neither party would enter into this Agreement. If the Partnership fails to pay promptly the amounts due pursuant to this Section 7.3, the Partnership will also pay to Parent interest on the unpaid amount under this Section 7.3, accruing from its due date, at an interest rate per annum equal to two percentage points in excess of the prime commercial lending rate quoted by The Wall Street Journal and the reasonable out-of-pocket expenses (including legal fees) in connection with any action taken to collect payment. Any change in the interest rate hereunder resulting from a change in such prime rate will be effective at the beginning of the date of such change in such prime rate.

 

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ARTICLE VIII.

MISCELLANEOUS

Section 8.1 No Survival. None of the representations, warranties, covenants and agreements in this Agreement or in any instrument delivered pursuant to this Agreement shall survive the Mergers, except for covenants and agreements which contemplate performance after the Effective Time or otherwise expressly by their terms survive the Effective Time.

Section 8.2 Expenses. Whether or not the Mergers are consummated, all costs and expenses incurred in connection with the Mergers, this Agreement and the transactions contemplated hereby shall be paid by the party incurring or required to incur such expenses, except that (a) fees and expenses incurred in connection with the printing, filing and mailing of the Combined Consent Statement/Prospectus and Form S-4 (including applicable SEC filing fees) and (b) filing fees payable under the HSR Act shall be borne equally by Parent and the Partnership.

Section 8.3 Counterparts; Effectiveness. This Agreement may be executed in two or more counterparts, each of which shall be an original, with the same effect as if the signatures thereto and hereto were upon the same instrument, and shall become effective when one or more counterparts have been signed by each of the parties and delivered (by telecopy, electronic delivery or otherwise) to the other parties. Signatures to this Agreement transmitted by facsimile transmission, by electronic mail in “portable document format” (“.pdf”) form, or by any other electronic means intended to preserve the original graphic and pictorial appearance of a document, will have the same effect as physical delivery of the paper document bearing the original signature.

Section 8.4 Governing Law. This Agreement, and all claims or causes of action (whether at Law, in contract or in tort or otherwise) that may be based upon, arise out of or relate to this Agreement or the negotiation, execution or performance hereof, shall be governed by and construed in accordance with the laws of the State of Delaware, without giving effect to any choice or conflict of law provision or rule (whether of the State of Delaware or any other jurisdiction) that would cause the application of the laws of any jurisdiction other than the State of Delaware.

Section 8.5 Jurisdiction; Specific Enforcement. The parties agree that irreparable damage, for which monetary damages would not be an adequate remedy, would occur in the event that any of the provisions of this Agreement were not performed, or were threatened to be not performed, in accordance with their specific terms or were otherwise breached. It is accordingly agreed that, in addition to any other remedy that may be available to it at law or in equity, each of the parties shall be entitled to an injunction or injunctions or equitable relief to prevent breaches of this Agreement and to enforce specifically the terms and

 

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provisions of this Agreement exclusively in the Delaware Court of Chancery and any state appellate court therefrom within the State of Delaware (or, if the Delaware Court of Chancery declines to accept jurisdiction over a particular matter, any state or federal court within the State of Delaware), and all such rights and remedies at law or in equity shall be cumulative. The parties further agree that no party to this Agreement shall be required to obtain, furnish or post any bond or similar instrument in connection with or as a condition to obtaining any remedy referred to in this Section 8.5 and each party waives any objection to the imposition of such relief or any right it may have to require the obtaining, furnishing or posting of any such bond or similar instrument. In addition, each of the parties hereto irrevocably agrees that any legal action or proceeding relating to or arising out of this Agreement and the rights and obligations hereunder, or for recognition and enforcement of any judgment relating to or arising out of this Agreement and the rights and obligations hereunder brought by the other party hereto or its successors or assigns, shall be brought and determined exclusively in the Delaware Court of Chancery and any state appellate court therefrom within the State of Delaware (or, if the Delaware Court of Chancery declines to accept jurisdiction over a particular matter, any state or federal court within the State of Delaware). Each of the parties hereto hereby irrevocably submits with regard to any such action or proceeding for itself and in respect of its property, generally and unconditionally, to the personal jurisdiction of the aforesaid courts and agrees that it will not bring any action relating to or arising out of this Agreement or any of the transactions contemplated by this Agreement in any court other than the aforesaid courts. Each of the parties hereto hereby irrevocably waives, and agrees not to assert, by way of motion, as a defense, counterclaim or otherwise, in any action or proceeding with respect to this Agreement, (a) any claim that it is not personally subject to the jurisdiction of the above named courts, (b) any claim that it or its property is exempt or immune from jurisdiction of any such court or from any legal process commenced in such courts (whether through service of notice, attachment prior to judgment, attachment in aid of execution of judgment, execution of judgment or otherwise) and (c) to the fullest extent permitted by the applicable Law, any claim that (i) the suit, action or proceeding in such court is brought in an inconvenient forum, (ii) the venue of such suit, action or proceeding is improper or (iii) this Agreement, or the subject matter hereof, may not be enforced in or by such courts. To the fullest extent permitted by applicable Law, each of the parties hereto hereby consents to the service of process in accordance with Section 8.7; provided, however, that nothing herein shall affect the right of any party to serve legal process in any other manner permitted by Law.

Section 8.6 WAIVER OF JURY TRIAL. EACH OF THE PARTIES HERETO ACKNOWLEDGES AND AGREES THAT ANY CONTROVERSY WHICH MAY ARISE UNDER THIS AGREEMENT IS LIKELY TO INVOLVE COMPLICATED AND DIFFICULT ISSUES, AND THEREFORE EACH SUCH PARTY IRREVOCABLY AND UNCONDITIONALLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY AND ALL RIGHT TO TRIAL BY JURY IN ANY ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY.

Section 8.7 Notices. All notices and other communications hereunder shall be in writing and shall be deemed given (a) upon personal delivery to the party to be notified; (b) when received when sent by email or facsimile by the party to be notified, provided, however, that notice given by email or facsimile shall not be effective unless either (i) a duplicate

 

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copy of such email or fax notice is promptly given by one of the other methods described in this Section 8.7 or (ii) the receiving party delivers a written confirmation of receipt for such notice either by email or fax or any other method described in this Section 8.7; or (c) when delivered by a courier (with confirmation of delivery), in each case to the party to be notified at the following address:

To Parent, Merger Sub or GP Merger Sub:

Energy Transfer LP

8111 Westchester Drive

Suite 700, Dallas, Texas

Attention:   Thomas P. Mason

Email:         Tom.Mason@energytransfer.com

with copies to:

Latham & Watkins LLP

811 Main Street, Suite 3700

Houston, Texas 77002

Facsimile:   (713) 546-7401

Attention:   William N. Finnegan IV

                   Kevin M. Richardson

Email:         bill.finnegan@lw.com

                    kevin.richardson@lw.com

To the Partnership:

Enable Midstream Partners, LP

499 West Sheridan Avenue, Suite 1500

Oklahoma City, Oklahoma

Facsimile:   346-701-2918

Attention:   Mark C. Schroeder

Email:         mark.schroeder@enablemidstream.com

with copies to:

Vinson & Elkins L.L.P.

1001 Fannin Street, Suite 2500

Houston, Texas 77002

Facsimile:   713-615-5956

Attention:   David P. Oelman

                   Stephen M. Gill

                   Scott D. Rubinsky

Email:         doelman@velaw.com

                   sgill@velaw.com

                   srubinsky@velaw.com

 

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or to such other address as any party shall specify by written notice so given, and such notice shall be deemed to have been delivered as of the date so telecommunicated or personally delivered. Any party to this Agreement may notify any other party of any changes to the address or any of the other details specified in this paragraph; provided, however, that such notification shall only be effective on the date specified in such notice or five business days after the notice is given, whichever is later. Rejection or other refusal to accept or the inability to deliver because of changed address of which no notice was given shall be deemed to be receipt of the notice as of the date of such rejection, refusal or inability to deliver.

Section 8.8 Assignment; Binding Effect. Neither this Agreement nor any of the rights, interests or obligations hereunder shall be assigned or delegated by any of the parties hereto without the prior written consent of the other parties; provided, however, that Parent may assign its right to receive the Breakup Fee under Section 7.3 to one or more wholly owned direct or indirect subsidiaries of Parent without the prior written consent of the Partnership, so long as such assignment does not delay the Closing. Subject to the first sentence of this Section 8.8, this Agreement shall be binding upon and shall inure to the benefit of the parties hereto and their respective successors and assigns. Any purported assignment not permitted under this Section shall be null and void.

Section 8.9 Severability. Any term or provision of this Agreement which is held to be invalid or unenforceable in a court of competent jurisdiction shall be ineffective to the extent of such invalidity or unenforceability without rendering invalid or unenforceable the remaining terms and provisions of this Agreement. Upon such a determination, the parties hereto shall negotiate in good faith to modify this Agreement so as to effect the original intent of the parties hereto as closely as possible in an acceptable manner in order that the transaction contemplated hereby are consummated as originally contemplated to the fullest extent possible. If any provision of this Agreement is so broad as to be unenforceable, such provision shall be interpreted to be only so broad as is enforceable.

Section 8.10 Entire Agreement. This Agreement together with the exhibits hereto, schedules hereto, the Support Agreements and the Confidentiality Agreement constitute the entire agreement, and supersede all other prior agreements and understandings, both written and oral, between the parties, or any of them, with respect to the subject matter hereof and thereof, and this Agreement is not intended to grant standing to any person other than the parties hereto.

Section 8.11 Amendments; Waivers. At any time prior to the Effective Time, any provision of this Agreement may be amended or waived if, and only if, such amendment or waiver is in writing and signed, in the case of an amendment, by the Partnership, Parent, the General Partner, Merger Sub and GP Merger Sub or, in the case of a waiver, by the party against whom the waiver is to be effective; provided, however, after the Sponsor Written Consent has been obtained, if any such amendment or waiver shall (a) be materially adverse to the Sponsors, the effectiveness of such amendment or waiver shall be subject to the approval of the Sponsors and (b) by applicable Law or in accordance with the rules and regulations of the NYSE require further approval of the unitholders of the Partnership, the effectiveness of such amendment or waiver shall be subject to the approval of the unitholders of the Partnership; provided, further,

 

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that no provision of this Agreement may be amended or waived without the prior consent of the Conflicts Committee. Notwithstanding the foregoing, no failure or delay by any party hereto in exercising any right hereunder shall operate as a waiver thereof nor shall any single or partial exercise thereof preclude any other or further exercise of any other right hereunder.

Section 8.12 Headings. Headings of the Articles and Sections of this Agreement are for convenience of the parties only and shall be given no substantive or interpretive effect whatsoever. The table of contents to this Agreement is for reference purposes only and shall not affect in any way the meaning or interpretation of this Agreement.

Section 8.13 Third-Party Beneficiaries. Each of Parent, Merger Sub, GP Merger Sub, the Partnership and the General Partner agrees that (a) their respective representations, warranties, covenants and agreements set forth herein are solely for the benefit of the Partnership or Parent, Merger Sub and GP Merger Sub, as applicable, in accordance with and subject to the terms of this Agreement, and (b) except for (i) the provisions of Section 5.11, (ii) the right of the Partnership’s unitholders to receive the LP Merger Consideration on the terms and conditions of this Agreement, this Agreement is not intended to, and does not, confer upon any person other than the parties hereto any rights or remedies hereunder, including the right to rely upon the representations and warranties set forth herein. Notwithstanding the foregoing, each of Parent, Merger Sub, GP Merger Sub, the Partnership and the General Partner expressly agrees that each Sponsor is intended to, and shall, be a third party beneficiary of the representations, warranties and covenants and agreements of the parties set forth in this Agreement, which representations, warranties and covenants and agreements shall not be amended, modified or waived in any way that materially adversely affects a Sponsor without the prior written consent of such Sponsor. For the avoidance of doubt, the parties agree that without limiting the prior sentence, any amendment or modification of, or the waiver of rights under, Sections 2.1(a), 2.1(b), 5.1(b) (but only if such amendment or modification further restricts the conducts of the Partnership or its Subsidiaries businesses) 5.8, 5.11, 5.14, 5.18, 6.1, 6.2, 7.1, 7.2, 7.3, 8.13 or 8.14 of this Agreement shall be deemed to materially adversely affect the Sponsors.

Section 8.14 No Recourse to Sponsors. Notwithstanding anything to the contrary contained herein, each of Parent, Merger Sub, GP Merger Sub, the Partnership and the General Partner expressly agrees that the Sponsors shall have no liability to any person in connection with this Agreement or, except as expressly set forth in their respective Support Agreements and subject to the terms and conditions thereof, the transactions contemplated hereby, and none of the parties to this Agreement shall make any claims whatsoever against either Sponsor or its affiliates (other than the Partnership and the General Partner) or their respective representatives in connection with this Agreement or the transactions contemplated hereby other than, if applicable, enforcement by Parent of the Support Agreements in accordance with their terms.

Section 8.14 Interpretation. When a reference is made in this Agreement to an Article or Section, such reference shall be to an Article or Section of this Agreement unless otherwise indicated. Whenever the words “include,” “includes” or “including” are used in this Agreement, they shall be deemed to be followed by the words “without limitation.” The words “hereof,” “herein” and “hereunder” and words of similar import when used in this Agreement shall refer to this Agreement as a whole and not to any particular provision of this Agreement,

 

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unless the context otherwise requires. All terms defined in this Agreement shall have the defined meanings when used in any certificate or other document made or delivered pursuant thereto unless otherwise defined therein. The definitions contained in this Agreement are applicable to the singular as well as the plural forms of such terms and to the masculine as well as to the feminine and neuter genders of such term. References in this Agreement to specific laws or to specific provisions of laws shall include all rules and regulations promulgated thereunder, and any statute defined or referred to herein or in any agreement or instrument referred to herein shall mean such statute as from time to time amended, modified or supplemented, including by succession of comparable successor statutes. Each of the parties has participated in the drafting and negotiation of this Agreement. If an ambiguity or question of intent or interpretation arises, this Agreement must be construed as if it is drafted by all the parties, and no presumption or burden of proof shall arise favoring or disfavoring any party by virtue of authorship of any of the provisions of this Agreement.

Section 8.15 Definitions.

(a) As used in this Agreement:

(i) “affiliate” means, with respect to a specified person, any other person, whether now in existence or hereafter created, directly or indirectly controlling, controlled by or under direct or indirect common control with such specified person. For purposes of this definition and the definition of Subsidiary, “control” (including, with correlative meanings, “controlling,” “controlled by” and “under common control with”) means, with respect to a person, the power to direct or cause the direction of the management and policies of such person, directly or indirectly, whether through the ownership of equity interests, including but not limited to voting securities, by contract or agency or otherwise. Notwithstanding the foregoing, none of USA Compression Partners, LP, Sunoco LP or their respective Subsidiaries shall be deemed affiliates of Parent or any of Parent’s other Subsidiaries.

(ii) “business day” means any day other than a Saturday, a Sunday or a legal holiday for commercial banks in New York, New York.

(iii) “COVID-19” means the COVID-19 or SARS-CoV-2 virus (or any mutation or variation thereof).

(iv) “COVID-19 Actions” means any commercially reasonable actions, inactions, activities or conduct that a party reasonably determines in good faith are necessary or advisable to comply with COVID-19 Measures.

(v) “COVID-19 Measures” means, as applicable to a party or its Subsidiaries, any quarantine, “shelter in place,” “stay at home,” workforce reduction, social distancing, shut down, closure or sequester order, guideline, recommendation or Law, or any other applicable Laws, guidelines or recommendations by any Governmental Entity in connection with or in response to COVID-19.

 

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(vi) “Eagle Operating Preferred Units” means, collectively, the 6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units, 6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units, 7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units, 7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units, 7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units, 6.750% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units and 7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units of Energy Transfer Operating, L.P.

(vii) “GP Organizational Documents” means, collectively, (a) that certain Certificate of Formation of the General Partner, dated as of April 30, 2013, as amended, and (b) that certain Third Amended and Restated Limited Liability Company Agreement of the General Partner, dated as of June 22, 2016.

(viii) “knowledge” means (A) with respect to Parent and its Subsidiaries, the actual knowledge, after reasonable investigation of, the individuals listed in Section 8.15(a)(vii) of the Parent Disclosure Schedule and (B) with respect to the Partnership and its Subsidiaries, the actual knowledge, after reasonable investigation of, the individuals listed in Section 8.15(a)(vii) of the Partnership Disclosure Schedule.

(ix) “Parent Common Units” means common units representing limited partner interests in the Parent and having the rights and obligations specified in the Parent Partnership Agreement.

(x) “Partnership Change of Control Plan” means the Partnership’s Change of Control Plan, dated effective August 1, 2016.

(xi) “Partnership Credit Facilities” means those certain credit facilities entered into pursuant to (A) that certain Amended and Restated Revolving Credit Agreement, dated as of April 6, 2018, by and among the Partnership, Citibank, N.A., as administrative agent, and the lenders party thereto, and (B) that certain Term Loan Agreement, dated as of January 29, 2019, by and among the Partnership, Bank of America, N.A., as administrative agent, and the lenders party thereto, in each case, as amended, supplemented, or otherwise modified from time to time.

(xii) “Partnership Deferred Compensation Plan” means the Partnership’s Deferred Compensation Plan dated effective January 1, 2015.

(xiii) “Partnership Incentive Distribution Right” means “Incentive Distribution Right” as defined in the Partnership Agreement.

(xiv) “Partnership Short Term Incentive Plan” means the Partnership’s Short Term Incentive Plan dated effective January 1, 2014.

(xv) “person” means an individual, a corporation, a partnership, a limited liability company, an association, a trust or any other entity, group (as such term is used in Section 13 of the Exchange Act) or organization, including a Governmental Entity, and any permitted successors and assigns of such person.

 

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(xvi) “Registration Rights Agreement” means the registration rights agreement, to be entered into at the Closing, substantially in the form attached hereto as Exhibit A.

(xvii) “Remedy Threshold” has the meaning set forth in Section 5.8(d) of the Partnership Disclosure Schedule.

(xviii) “Seconded Employees” means the employees seconded to the Partnership, the General Partner or their respective Subsidiaries pursuant to the Secondment Arrangements.

(xix) “Secondment Arrangements” means all agreements and arrangements pursuant to which employees of Ox or any of its affiliates provide services to the Partnership, the General Partner or their respective Subsidiaries as seconded employees

(xx) “SESH” means Southeast Supply Header, LLC, a Delaware limited liability company.

(xxi) “Series G Preferred Units” means a new series of preferred units representing limited partner interests in Parent, to be established at or prior to Closing, designated as “7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units” and having the same preferences, rights, powers and duties as the 7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units of Energy Transfer Operating, L.P. outstanding as of the date hereof (other than any non-substantive differences to reflect the issuance of such securities by Parent, as opposed to Energy Transfer Operating, L.P.), which for the avoidance of doubt, shall be the same class (and having the same CUSIP) of preferred units issued to the holders of the 7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units of Energy Transfer Operating, L.P. in the Pre-Closing Transactions.

(xxii) “Subsidiary” means, with respect to any person, any corporation, limited liability company, partnership, association, or business entity, whether incorporated or unincorporated, of which (A) if a corporation, a majority of the total voting power of shares of stock entitled (without regard to the occurrence of any contingency) to vote in the election of directors, managers, or trustees thereof is at the time owned or controlled, directly or indirectly, by that person or one or more Subsidiaries of that person or a combination thereof, (B) if a partnership (whether general or limited), a general partner interest is at the time owned or controlled, directly or indirectly, by that person or one or more Subsidiaries of that person or a combination thereof or (C) if a limited liability company, partnership, association, or other business entity (other than a corporation), a majority of partnership or other similar ownership interest thereof is at the time owned or controlled, directly or indirectly, by that person or one or more Subsidiaries of that person or a combination thereof. For purposes hereof, a person or persons shall be deemed to have a majority ownership interest in a limited liability company, partnership, association, or other business entity (other than a corporation) if such person or persons shall be allocated a majority of limited liability

 

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company, partnership, association, or other business entity gains or losses. Notwithstanding the foregoing, (x) none of USA Compression Partners, LP, Sunoco LP or any of their respective Subsidiaries shall be deemed Subsidiaries of Parent or Energy Transfer Operating, L.P. and (y) SESH shall be deemed a Subsidiary of the Partnership; provided, that, for the avoidance of doubt, a Subsidiary of SESH shall not be deemed a Subsidiary of the Partnership for purposes of this Agreement.

(xxiii) “Tax” or “Taxes” means any and all U.S. federal, state or local or non-U.S. or provincial taxes, charges, imposts, levies or other assessments, including all net income, gross receipts, capital, sales, use, ad valorem, value added, transfer, franchise, profits, inventory, capital stock, license, withholding, payroll, employment, social security, unemployment, excise, severance, stamp, occupation, property and estimated taxes, customs duties, fees, assessments and similar charges, including any and all interest, penalties, fines, additions to tax or additional amounts imposed by any Governmental Entity in connection or with respect thereto.

(xxiv) “Tax Return” means any return, report or similar filing (including any attached schedules, supplements and additional or supporting material) filed or required to be filed with respect to Taxes, including any information return, claim for refund, amended return or declaration of estimated Taxes (and including any amendments with respect thereto).

(xxv) “Treasury Regulations” means the regulations (including temporary regulations) promulgated by the United States Department of the Treasury pursuant to and in respect of provisions of the Code. All references in this Agreement to sections of the Treasury Regulations shall include any corresponding provisions or provisions of succeeding, similar or substitute, temporary or final Treasury Regulations.

(xxvi) “Willful Breach” means a material breach, or failure to perform, that is the consequence of an act or omission of a Representative or a Subsidiary of the Partnership with the knowledge that the taking of, or failure to take, such act would, or would be reasonably expected to, cause a material breach of this Agreement.

(b) Each of the following terms is defined in the section of this Agreement set forth opposite such term:

 

Action

     Section 5.11(b)  

affiliates

     Section 8.15(a)(i)  

Agreement

     Preamble  

Acquisition Proposal

     Section 5.4(c)(i)  

Acquisition Transaction

     Section 5.4(c)(ii)  

Assumed Restricted Unit Award

     Section 5.6(a)  

Balance Sheet Date

     Section 3.6  

Benefit Plans

     Section 5.7(b)  

Breakup Fee

     Section 7.3(d)  

business day

     Section 8.15(a)(ii)  

Cancelled Units

     Section 2.1(e)  

 

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Caribou

     Recitals  

Certificates of Merger

     Section 1.3  

Certificates

     Section 2.2(b)  

Class A Units

     Section 4.2(a)  

Closing

     Section 1.2  

Closing Date

     Section 1.2  

Code

     Section 2.3  

Combined Consent Statement/Prospectus

     Section 3.3(b)  

Confidentiality Agreement

     Section 5.3(b)  

Conflicts Committee

     Recitals  

Continuation Period

     Section 5.7(a)  

Contract

     Section 3.20(a)  

control

     Section 8.15(a)(i)  

COVID-19

     Section 8.15(a)(iii)  

COVID-19 Action

     Section 8.15(a)(iv)  

COVID-19 Measures

     Section 8.15(a)(v)  

Current Employees

     Section 5.7(a)  

Delaware LLC Act

     Section 1.1(c)  

Delaware LP Act

     Section 1.1(d)  

Earned Performance Units

     Section 5.6(b)  

Effective Time

     Section 1.3  

End Date

     Section 7.1(b)  

Eagle Operating Preferred Units

     Section 8.15(a)(vi)  

Environmental Law

     Section 3.8(b)(i)  

ERISA

     Section 3.9(a)  

ERISA Affiliate

     Section 3.9(a)  

ERISA Effective Date

     Section 5.7(f)  

Exchange Act

     Section 3.3(b)  

Exchange Agent

     Section 2.2(a)  

Exchange Fund

     Section 2.2(a)  

Exchange Ratio

     Section 2.1(a)(i)  

Export Control and Economic Sanctions Laws

     Section 3.23(b)  

FCC

     Section 3.13(b)  

FCPA

     Section 3.7(c)  

FERC

     Section 3.13(b)  

Form S-4

     Section 3.12  

FPA

     Section 3.13(a)  

GAAP

     Section 3.1(b)  

General Partner

     Preamble  

Governmental Entity

     Section 2.2(e)  

GP Board

     Recitals  

GP Certificate of Merger

     Section 1.3  

GP Merger

     Recitals  

GP Merger Consideration

     Section 2.1(a)(ii)  

GP Merger Sub

     Preamble  

GP Surviving Entity

     Section 1.1(c)  

 

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Hazardous Materials

     Section 3.8(b)(ii)  

HSR Act

     Section 3.3(b)  

ICA

     Section 3.13(a)  

Inactive Seconded Employee

     Section 5.7(k)  

Indemnified Party

     Section 5.11(b)  

Intended Tax Treatment

     Section 5.14(a)  

IT Assets

     Section 3.16(c)  

knowledge

     Section 8.15(a)(viii)  

Latham & Watkins

     Section 1.2  

Law or Laws

     Section 3.7(a)  

Lien

     Section 3.3(c)  

LP Certificate of Merger

     Section 1.3  

LP Merger

     Recitals  

LP Merger Consideration

     Section 2.1(a)(i)  

Maximum Amount

     Section 5.11(c)  

Merger Sub

     Preamble  

Merger Subs

     Preamble  

Mergers

     Recitals  

New Plans

     Section 5.7(b)  

NGA

     Section 3.13(a)  

NGPA

     Section 3.13(a)  

NYSE

     Section 3.3(b)  

Old Plans

     Section 5.7(b)  

Ox

     Recitals  

Parent

     Preamble  

Parent Approvals

     Section 4.3(b)  

Parent Benefit Plans

     Section 4.9  

Parent Certificate of Limited Partnership

     Section 4.1(c)  

Parent Common Units

     Section 8.15(a)(ix)  

Parent Disclosure Schedule

     Preamble to Article IV  

Parent Employees

     Section 4.15(a)  

Parent Equity Plans

     Section 4.2(a)  

Parent GP

     Preamble  

Parent GP Board

     Section 4.3(a)  

Parent GP Interest

     Section 4.2(a)  

Parent Leased Real Property

     Section 4.16(a)  

Parent Material Adverse Effect

     Section 4.1(b)  

Parent Material Contracts

     Section 4.18(a)  

Parent Organizational Documents

     Section 4.1(c)  

Parent Owned Real Property

     Section 4.16(a)  

Parent Partnership Agreement

     Section 4.1(c)  

Parent Permits

     Section 4.7(b)  

Parent Permitted Lien

     Section 4.2(h)  

Parent Real Property

     Section 4.16(a)  

Parent Real Property Leases

     Section 4.16(a)  

Parent SEC Documents

     Section 4.4(a)  

 

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Parent Tax Certificate

     Section 5.14(c)  

Partnership

     Preamble  

Partnership 401(k) Plan

     Section 5.7(f)  

Partnership Agreement

     Recitals  

Partnership Approvals

     Section 3.3(b)  

Partnership Benefit Plans

     Section 3.9(a)  

Partnership Certificate of Limited Partnership

     Section 3.1(c)  

Partnership Common Units

     Recitals  

Partnership Credit Facilities

     Section 8.15(a)(xi)  

Partnership Change of Control Plan

     Section 8.15(a)(x)  

Partnership Deferred Compensation Plan

     Section 8.15(a)(xii)  

Partnership Employees

     Section 3.15(a)  

Partnership Equity Award

     Section 5.6(b)  

Partnership Disclosure Schedule

     Preamble to Article III  

Partnership GP Interest

     Section 3.2(a)  

Partnership Phantom Units

     Section 5.6(a)  

Partnership Incentive Distribution Right

     Section 8.15(a)(xiii)  

Partnership Intellectual Property

     Section 3.16(a)  

Partnership Leased Real Property

     Section 3.17(a)  

Partnership Material Adverse Effect

     Section 3.1(b)  

Partnership Material Contracts

     Section 3.20(a)  

Partnership Organizational Documents

     Section 3.1(c)  

Partnership Owned Real Property

     Section 3.17(a)  

Partnership Permits

     Section 3.7(b)  

Partnership Performance Award

     Section 5.6(b)  

Partnership Permitted Lien

     Section 3.2(g)  

Partnership Real Property

     Section 3.17(a)  

Partnership Real Property Leases

     Section 3.17(a)  

Partnership SEC Documents

     Section 3.4(a)  

Partnership Short Term Incentive Plan

     Section 8.15(a)(xiv)  

Partnership Tax Certificate

     Section 5.14(c)  

Permitted Encumbrances

     Section 3.17(a)  

person

     Section 8.15(a)(xv)  

Pre-Closing Transactions

     Section 1.1(a)  

Preferred Corporate Contribution

     Section 1.1(b)(ii)  

Preferred Contributions

     Section 1.1(b)(ii)  

Preferred Contribution and Issuance

     Section 1.1(b)(i)  

Preferred Holding Subsidiary

     Section 5.14(d)  

PUHCA

     Section 3.13(a)  

Registration Rights Agreement

     Section 8.15(a)(xvi)  

Remedies Exceptions

     Section 3.17(a)  

Representatives

     Section 5.3(a)  

Requisite Corporate Preferred Portion

     Section 1.1(b)(ii)  

Required Tax Opinions

     Section 5.14(c)  

Requisite Unitholder Approval

     Section 3.3(a)  

Rights-of-Way

     Section 3.2(h)  

 

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Sanctioned Jurisdiction

     Section 3.23(b)  

Sanctioned Party

     Section 3.23(b)  

Sarbanes-Oxley Act

     Section 3.5  

SDN List

     Section 3.23(b)  

SEC

     Section 3.3(b)  

Seconded Employee Performance Awards

     Section 3.2(b)  

Seconded Employee Phantom Awards

     Section 3.2(b)  

Seconded Employees

     Section 8.15(a)(xvii)  

Secondment Arrangements

     Section 8.15(a)(xix)  

Secretary of State

     Section 1.3  

Securities Act

     Section 3.3(b)  

Series A Preferred Units

     Section 1.1(b)(i)  

Sponsors

     Recitals  

SSI List

     Section 3.23(b)  

Subsidiary

     Section 8.15(a)(xiii)  

Support Agreement

     Recitals  

Surviving Entity

     Section 1.1(d)  

Systems

     Section 3.8(b)(iii)  

Tax Return

     Section 8.15(a)(xii)  

Taxes

     Section 8.15(a)(xxiii)  

Termination Date

     Section 5.1(a)  

Treasury Regulations

     Section 8.15(a)(xxv)  

under common control with

     Section 8.15(a)(i)  

Vinson & Elkins

     Section 6.1(f)  

Willful Breach

     Section 8.15(a)(xxvi)  

[Signature Pages Follow]

 

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IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed and delivered as of the date first above written.

 

ENERGY TRANSFER LP
By:   LE GP, LLC, its general partner
By:  

/s/ Thomas E. Long

  Name: Thomas E. Long
  Title: Co-Chief Executive Officer
ELK MERGER SUB LLC
By:  

/s/ Thomas E. Long

  Name: Thomas E. Long
  Title: Co-Chief Executive Officer
ELK GP MERGER SUB LLC
By:  

/s/ Thomas E. Long

  Name: Thomas E. Long
  Title: Co-Chief Executive Officer
SOLELY FOR PURPOSES OF SECTION 2.1(a)(i)
LE GP, LLC
By:  

/s/ Thomas E. Long

  Name: Thomas E. Long
  Title: Co-Chief Executive Officer

[Signature Page to Agreement and Plan of Merger]


ENABLE GP, LLC
By:  

/s/ Rodney J. Sailor

  Name: Rodney J. Sailor
  Title: President and Chief Executive Officer
ENABLE MIDSTREAM PARTNERS, LP
By:   ENABLE GP, LLC, its general partner
By:  

/s/ Rodney J. Sailor

  Name: Rodney J. Sailor
  Title: President and Chief Executive Officer
SOLELY FOR PURPOSES OF SECTION 1.1(b)(i)
CENTERPOINT ENERGY, INC.
By:  

/s/ Rodney J. Sailor

  Name: Rodney J. Sailor
  Title: President and Chief Executive Officer

[Signature Page to Agreement and Plan of Merger]


Exhibit A

EXECUTION VERSION

FORM OF

REGISTRATION RIGHTS AGREEMENT

This REGISTRATION RIGHTS AGREEMENT (this “Agreement”), dated as of [ ● ], 2021, is entered into by and among Energy Transfer LP, a Delaware limited partnership (the “Parent”), and certain unitholders of Enable Midstream Partners, LP, a Delaware limited partnership (the “Partnership”), as set forth on Schedule I hereto (collectively, the “Holders” and each, individually, a “Holder”). Each party to this Agreement is sometimes referred to individually in this Agreement as a “Party” and all of the parties to this Agreement are sometimes collectively referred to in this Agreement as the “Parties.”

WHEREAS, this Agreement is made in connection with the entry into that certain Agreement and Plan of Merger, dated as of February 16, 2021 (as it may be amended, supplemented, restated or otherwise modified from time to time, the “Merger Agreement”), by and among the Parent, the Partnership, Elk Merger Sub, LLC (“LP Merger Sub”), Elk GP Merger Sub LLC (“GP Merger Sub”) and Enable GP, LLC (the “General Partner”), pursuant to which (i) LP Merger Sub will merge with and into the Partnership, with the Partnership surviving as a wholly-owned subsidiary of the Parent (the “Partnership Merger”), (ii) GP Merger Sub will merge with and into the General Partner (the “GP Merger”), with the General Partner surviving the GP Merger as a direct wholly owned subsidiary of the Parent and (iii) by virtue of the Partnership Merger, the Holders will receive newly issued common units representing limited partner interests in the Parent (the “Parent Common Units”); and

WHEREAS, the execution and delivery of this Agreement is a condition to the closing of the transactions contemplated by the Merger Agreement (the “Closing”) and, in connection with the Closing, the Parent and the Holders wish to enter into this Agreement to provide the Holders certain registration rights with respect to the Parent Common Units to be owned by the Holder following the Closing of the Partnership Merger.

NOW, THEREFORE, in consideration of the premises and the mutual agreements and covenants hereinafter set forth, the Parent and the Holders hereby agree as follows:

ARTICLE I

DEFINITIONS

Section 1.01    Definitions. Capitalized terms used herein without definition shall have the meanings given to them in the Merger Agreement. The terms set forth below are used herein as so defined:

Affiliate” means, with respect to a specified Person, any other Person that directly or indirectly controls, is controlled by, or is under common control with such specified Person. For the purposes of this definition, “control” means the power to direct or cause the direction of the management and policies of a Person, directly or indirectly, whether through the ownership of voting securities, by contract or otherwise.

Agreement” shall have the meaning set forth in the preamble.


Block Trade” shall have the meaning set forth in Section 2.03.

Business Day” means any day other than a Saturday, a Sunday or a legal holiday for commercial banks in New York, New York.

Closing” shall have the meaning set forth in the recitals.

Courts” shall have the meaning set forth in Section 3.15.

Effectiveness Period” shall have the meaning set forth in Section 2.05(a)(ii).

Exchange Act” means the Securities Exchange Act of 1934, as amended, and the rules and regulations promulgated thereunder.

General Partner” shall have the meaning set forth in the recitals.

GP Merger” shall have the meaning set forth in the recitals.

GP Merger Sub” shall have the meaning set forth in the recitals.

Governmental Authority” means any federal, state, local, municipal, foreign or multinational government, or any subsidiary body thereof or governmental or quasi-governmental authority of any nature, including, any governmental agency, branch, commission, department, official, or entity, any court, judicial authority, or other tribunal, and any arbitration body or tribunal.

Holder” and “Holders” shall have the meaning set forth in the preamble.

Law” means any applicable domestic or foreign federal, state, local, municipal, or other administrative order, constitution, law, order, policy, ordinance, rule, code, principle of common law, case, decision, regulation, statute, tariff or treaty, or other requirements with similar effect of any Governmental Authority or any binding provisions or interpretations of the foregoing.

LP Merger Sub” shall have the meaning set forth in the recitals.

Merger Agreement” shall have the meaning set forth in the recitals.

National Securities Exchange” means an exchange registered with the SEC under Section 6(a) of the Exchange Act (or any successor to such Section) and any other securities exchange (whether or not registered with the SEC under Section 6(a) of the Exchange Act (or any successor to such Section) that Parent shall designate as a National Securities Exchange for purposes of this Agreement.

Other Holder” shall have the meaning set forth in Section 2.02(a).

Parent” shall have the meaning set forth in the preamble.

 

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Parent Common Units” shall have the meaning set forth in the recitals.

Parent Shelf Takedown Notice” shall have the meaning set forth in Section 2.01(b).

Partnership” shall have the meaning set forth in the preamble.

Partnership Agreement” means the Third Amended and Restated Agreement of Limited Partnership of the Parent dated as of February 8, 2006, as amended, and as may be amended, amended and restated or otherwise modified from time to time.

Partnership Merger” shall have the meaning set forth in the recitals.

Party” and “Parties” shall have the meaning set forth in the preamble.

Person” means any individual, corporation, company, voluntary association, partnership, joint venture, trust, limited liability company, unincorporated organization, government or any agency, instrumentality or political subdivision thereof or any other form of entity.

Piggyback Registration” shall have the meaning set forth in Section 2.02(a).

Proceedings” means any claim, action, arbitration, mediation, audit, hearing, investigation, proceeding, litigation, subpoena or suit (whether civil, criminal, administrative, investigative, or informal) commenced, brought, conducted, or heard by or before, or otherwise involving, any Governmental Authority, arbitrator, or mediator.

Prospectus” means the prospectus or prospectuses (whether preliminary or final) included in any Registration Statement and relating to Registrable Units, as amended or supplemented and including all material incorporated by reference in such prospectus or prospectuses.

Register,” “Registered,” and “Registration” shall refer to a registration effected by preparing and filing a registration statement or similar document in compliance with the Securities Act and the declaration or ordering of effectiveness of such registration statement or document.

Registrable Units” means (i) Parent Common Units beneficially owned by the Holders as of the date of this Agreement and (ii) any securities issued or issuable with respect thereto by way of conversion, exchange, replacement, unit dividend, unit split or other distribution or in connection with a combination of units, recapitalization, merger, consolidation or other reorganization or otherwise. For purposes of this Agreement, any Registrable Unit shall cease to be a Registrable Unit upon the earliest to occur of the following: (A) when a Registration Statement covering such Registrable Unit becomes or has been declared effective by the SEC and such Registrable Unit has been sold or disposed of pursuant to such effective Registration Statement, and (B) when such Registrable Unit has been disposed of pursuant to any section of Rule 144 (or any similar provision then in effect) under the Securities Act or in a private transaction exempt from registration under the Securities Act.

Registration Expenses” shall have the meaning set forth in Section 2.07.

 

3


Registration Statement” means any registration statement of the Parent under the Securities Act that covers any of the Registrable Units pursuant to the provisions of this Agreement, including the Prospectus, amendments and supplements to such Registration Statement, including post-effective amendments, all exhibits and all documents incorporated by reference in such Registration Statement.

SEC” means the United States Securities and Exchange Commission.

Securities Act” means the Securities Act of 1933, as amended from time to time, and the rules and regulations of the SEC promulgated thereunder.

Shelf Registration Statement” shall have the meaning set forth in Section 2.01(a).

Shelf Takedown Notice” shall have the meaning set forth in Section 2.01(b).

Shelf Underwritten Offering” shall have the meaning set forth in Section 2.01(b).

Suspension Period” shall have the meaning set forth in Section 2.04.

ARTICLE II

REGISTRATION RIGHTS

Section 2.01    Shelf Registration.

(a)    As promptly as practicable after the date hereof, and in any event within five days following the date hereof, the Parent shall use commercially reasonable efforts to prepare and file a Registration Statement to permit the public resale of the Registrable Units held by the Holders from time to time as permitted by Rule 415 of the Securities Act (a “Shelf Registration Statement”) in accordance with the provisions of this Agreement; provided, that the Parent shall only be obligated to prepare and file one such Shelf Registration Statement pursuant to this Section 2.01 on behalf of the Holders. The Parent shall effect such Shelf Registration Statement using a registration statement on Form S-3 whenever the Parent is eligible to do so, and shall use an Automatic Shelf Registration Statement (as defined in Rule 405 of the Securities Act) if it is a well-known seasoned issuer (as defined under Rule 405 of the Securities Act). The Parent shall use its commercially reasonable efforts to (i) cause such Shelf Registration Statement to be declared effective as soon as practicable after the filing thereof and (ii) keep such Shelf Registration Statement continuously effective during the Effectiveness Period.

(b)    At any time and from time to time following the effectiveness of the Shelf Registration Statement required by Section 2.01(a), any Holder may request to sell all or a portion of their Registrable Units in an underwritten offering that is registered pursuant to such Shelf Registration Statement, including a Block Trade (a “Shelf Underwritten Offering”), provided that such Holder(s) reasonably expect(s) to sell Registrable Units yielding aggregate gross proceeds of at least $200,000,000 from such Shelf Underwritten Offering. All requests for a Shelf Underwritten Offering shall be made by giving written notice to the Parent (the “Shelf Takedown

 

4


Notice”). Each Shelf Takedown Notice shall specify the approximate number of Registrable Units proposed to be sold in the Shelf Underwritten Offering and the expected price range (net of underwriting discounts and commissions) of such Shelf Underwritten Offering. Within three Business Days after receipt of any Shelf Takedown Notice, the Parent shall give written notice of such requested Shelf Underwritten Offering to all other Holders of Registrable Units (the “Parent Shelf Takedown Notice”) and, subject to the provisions of Section 2.01(d), shall include in such Shelf Underwritten Offering all Registrable Units with respect to which the Parent has received written requests for inclusion therein within five Business Days after sending the Parent Shelf Takedown Notice, or, in the case of a Block Trade, as provided in Section 2.03. The Parent shall enter into an underwriting agreement in a form as is customary in underwritten offerings of securities by the Parent with the managing underwriter selected by the Holder(s) requesting such Shelf Underwritten Offering (which managing underwriter shall be subject to approval of the Parent, which approval shall not be unreasonably withheld) and shall take all such other reasonable actions as are requested by the managing underwriter in order to expedite or facilitate the disposition of such Registrable Units in accordance with the terms of this Agreement. In connection with any Shelf Underwritten Offering contemplated by this Section 2.01(b), subject to Section 2.04, the underwriting agreement into which each Holder and the Parent shall enter shall contain such representations, covenants, indemnities and other rights and obligations as are customary in underwritten offerings of securities by the Parent. Notwithstanding any other provision of this Agreement to the contrary, CenterPoint Energy, Inc. (“CenterPoint”) may not demand more than five Shelf Underwritten Offerings and OGE Energy Corp. (“OGE”) may not demand more than three Shelf Underwritten Offerings, provided that there shall be no more than three Shelf Underwritten Offerings in any 12-month period, of which, no more than two such Shelf Underwritten Offerings in any 12-month period may be demanded by CenterPoint and no more than one such Shelf Underwritten Offering in any 12-month period may be demanded by OGE unless either CenterPoint or OGE shall assign to the other one or more such Shelf Underwritten Offerings in any 12-month period.

(c)    If the Parent or any of its Affiliates is conducting or actively pursuing a securities offering of Parent Common Units (other than in connection with any at-the-market offering or similar continuous offering program), then the Parent may suspend any Holder’s right to require the Parent to conduct a Shelf Underwritten Offering pursuant to Section 2.01(b); provided, however, that the Parent may only suspend such Holder’s right to require the Partnership to conduct a Shelf Underwritten Offering once in any six-month period and in no event for a period that exceeds an aggregate of 60 days in any 180-day period or 90 days in any 365-day period.

(d)    In connection with any Shelf Underwritten Offering, if the managing underwriter advises the Parent that in its opinion the number of Registrable Units proposed to be included in such offering exceeds the maximum number of Parent Common Units that can be sold in such offering without being likely to materially delay or jeopardize the success or timing of the offering (including the price per unit of the Parent Common Units proposed to be sold in such offering), the Parent shall include in such Shelf Underwritten Offering the Registrable Units of the Holders pro rata based on the total amount of Registrable Units requested to be included therein by each such Holder that can be sold without exceeding such maximum number of Parent Common Units.

 

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Section 2.02    Piggyback Registration.

(a)    If the Parent proposes to file with the SEC (i) a Registration Statement to register any Parent Common Units for an underwritten offering under the Securities Act or (ii) a prospectus supplement relating to the sale of Parent Common Units pursuant to an effective “automatic” registration statement, so long as the Parent is a WKSI at such time or, whether or not the Parent is a WKSI, so long as the Registrable Units were previously included in the underlying shelf Registration Statement or are included on an effective Registration Statement, in each case for its own account and/or for another Person (such other Person, an “Other Holder”), other than on a registration statement on Form S-8 or Form S-4, and the form of registration statement to be used may be used for a registration of Registrable Units (a “Piggyback Registration”), the Parent shall give five Business Days’ written notice to the Holders of its intention to file such registration statement and, subject to this Section 2.02, shall include in such Registration Statement and in any offering of Parent Common Units to be made pursuant to such Registration Statement all Registrable Units with respect to which the Parent has received a written request for inclusion therein from any Holder within three Business Days after such Holder’s receipt of the Parent’s notice. The Parent shall have no obligation to proceed with any Piggyback Registration and may abandon, terminate and/or withdraw such registration for any reason at any time prior to the pricing thereof. Any Holder shall have the right to withdraw such Holder’s request for inclusion of such Holder’s Registrable Units in such Piggyback Registration by giving written notice to the Parent of such withdrawal at least two Business Days prior to the time of the public announcement of the Parent’s intention to conduct such underwritten offering.

(b)    If a Piggyback Registration is initiated for an underwritten offering on behalf of the Parent or any Other Holder and the managing underwriter(s) advise the Parent that in their opinion the number of Parent Common Units proposed to be included in such offering exceeds the number of Parent Common Units that can be sold in such offering without being likely to materially delay or jeopardize the success or timing of the offering (including the price per unit of the Parent Common Units proposed to be sold in such offering), the Parent shall include in such registration and offering (i) first, the number of Parent Common Units that the Parent or, if such offering was initiated by any Other Holder, any Other Holder proposes to sell and (ii) second, the number of Parent Common Units requested to be included therein by the Holders that have elected to include Registrable Units in such Piggyback Registration, pro rata among all such Holders on the basis of the number of Parent Common Units requested to be included therein by all such Holders or as such Holders and the Parent may otherwise agree and (iii) third, the number of Parent Common Units requested to be included therein by other unitholders of Parent, pro rata among all such unitholders on the basis of the number of Parent Common Units requested to be included therein by all such unitholders or as such unitholders and the Parent may otherwise agree. If the number of Parent Common Units that can be so sold is less than the number of Parent Common Units proposed to be sold by the Parent or any Other Holder pursuant to the Piggyback Registration, the amount of Parent Common Units to be sold shall be fully allocated to the Parent or such Other Holder, as applicable.

(c)    In any Piggyback Registration under Section 2.02(b), the Parent shall have the right to select the underwriter or underwriters for any offering conducted pursuant thereto.

 

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(d)    None of the Holders shall sell any Registrable Units in any offering pursuant to a Piggyback Registration unless it (i) agrees to sell such Registrable Units on the basis provided in the underwriting arrangements approved by the Parent and (ii) completes and executes all questionnaires, powers of attorney, indemnities, underwriting agreements, lockups and other documents reasonably required of such Holder under the terms of such arrangements.

Section 2.03     Block Trades. Notwithstanding the foregoing, at any time and from time to time when a Shelf Registration Statement is on file with the SEC and is effective, if a Holder wishes to engage in an underwritten or other coordinated registered offering not involving a “roadshow,” an offer commonly known as a “block trade” (a “Block Trade”), with a total offering price reasonably expected to be at least, in the aggregate, either (x) $50 million or (y) all remaining Registrable Units held by the Holder, then notwithstanding the time periods provided for in Section 2.01(b), such Holder need only to notify the Parent of the Block Trade at least five Business Days prior to the day such offering is to commence and the Parent shall use commercially reasonable efforts to facilitate such Block Trade; provided that the Holders representing a majority of the Registrable Units wishing to engage in the Block Trade shall use commercially reasonable efforts to work with the Parent and any underwriters prior to making such request in order to facilitate preparation of the registration statement, prospectus and other offering documentation related to the Block Trade.

Section 2.04    Suspension Periods. The Parent may delay the filing or effectiveness of, or by written notice to the Holders suspend the use of, a Shelf Registration Statement in conjunction with a registration of Registrable Units pursuant to Section 2.01, but in each such case only if the Parent determines in good faith that (a) such delay would enable the Parent to avoid disclosure of material information, the disclosure of which at that time would be adverse to the Parent (including by interfering with, or jeopardizing the success of, any pending or proposed acquisition, disposition or reorganization), (b) such filing or use would render the Parent unable to comply with applicable securities Laws or (c) obtaining any financial statements (including required consents) required to be included in any such Shelf Registration Statement (or incorporated therein) would be impracticable. Any period during which the Parent has delayed the filing, effectiveness or use of a Registration Statement pursuant to this Section 2.04 is herein called a “Suspension Period.” During any such Suspension Period, the Holder will be entitled to withdraw any request for a Shelf Underwritten Offering and, if such request is withdrawn, such Shelf Underwritten Offering will not count as a Shelf Underwritten Offering. In no event shall the number of days covered by (i) any one Suspension Period exceed 60 days and (ii) all Suspension Periods in any 360 day period exceed 150 days. The Holders shall keep the existence of each Suspension Period confidential.

Section 2.05    Obligations of the Parent and the Holders. (a) Whenever required under Section 2.01 to use commercially reasonable efforts to effect the registration of any Registrable Units, the Parent shall:

(i)    as expeditiously as possible, subject to the other provisions of this Agreement, prepare and file with the SEC a Registration Statement with respect to such Registrable Units and cause such Registration Statement to be declared effective (or become automatically effective) under the Securities Act;

 

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(ii)    use commercially reasonable efforts to prepare and file with the SEC such amendments and supplements to such Registration Statement and the Prospectus used in connection therewith as may be necessary to comply with the applicable requirements of the Securities Act and to keep such Registration Statement effective until the earliest date on which any of the following occurs: (A) all Registrable Units covered by such Registration Statement have been distributed in the manner set forth and as contemplated in such Registration Statement, (B) there are no longer any Registrable Units outstanding and (C) three years from the date such Registration Statement becomes effective (the “Effectiveness Period”);

(iii)    furnish to each selling Holder (A) as far in advance as reasonably practicable before filing a Registration Statement or any other registration statement contemplated by this Agreement or any supplement or amendment thereto, upon request, copies of reasonably complete drafts of all such documents proposed to be filed, and provide each such Holder the opportunity to object to any information pertaining to such Holder and its plan of distribution that is contained therein and make the corrections reasonably requested by such Holder with respect to such information prior to filing such Registration Statement or such other registration statement and the prospectus included therein or any supplement or amendment thereto, and (B) an electronic copy of such Registration Statement or such other registration statement and the prospectus included therein and any supplements and amendments thereto in order to facilitate the public sale or other disposition of the Registrable Units covered by such Registration Statement or other registration statement;

(iv)    use commercially reasonable efforts to obtain the withdrawal of any order suspending the effectiveness of any Registration Statement, or the lifting of any suspension of the qualification or exemption from qualification of any Registrable Units for sale in any jurisdiction in the United States;

(v)    if applicable, use commercially reasonable efforts to register or qualify such Registrable Units under such other securities or blue sky laws of such U.S. jurisdictions as the Holders reasonably request and continue such registration or qualification in effect in such jurisdictions for as long as the applicable Registration Statement may be required to be kept effective under this Agreement (provided, that the Parent will not be required to (A) qualify generally to do business in any jurisdiction where it would not otherwise be required to qualify but for this subparagraph (v), (B) subject itself to taxation in any such jurisdiction or (C) consent to general service of process in any such jurisdiction);

(vi)    the Parent shall ensure that a Registration Statement when it becomes or is declared effective (including the documents incorporated therein by reference) will comply as to form in all material respects with all applicable requirements of the Securities Act and the Exchange Act and will not contain an untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary to make the statements therein not misleading (and, in the case of any prospectus contained in such Registration Statement, in the light of the circumstances under which a statement is made). As soon as practicable following the effective date of a Registration Statement, but in any event within one Business Day of such date, the Parent will notify the selling Holders of the effectiveness of such Registration Statement;

 

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(vii)    promptly notify the Holders, at any time when delivery of a Prospectus relating to its Registrable Units would be required under the Securities Act, of (A) the occurrence of any event as a result of which the Prospectus included in such Registration Statement contains an untrue statement of a material fact or omits to state a material fact necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading, and prepare, as soon as practical, a supplement or amendment to such Prospectus so that, as thereafter delivered to any prospective purchasers of such Registrable Units, such Prospectus shall not contain an untrue statement of a material fact or omit to state any material fact required to be stated therein necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading; (B) the Parent’s receipt of any written comments from the SEC with respect to any filing referred to in clause (A) and any written request by the SEC for amendments or supplements to such Registration Statement or any other registration statement or any Prospectus thereto, the issuance or threat of issuance by the SEC of any stop order suspending the effectiveness of such Registration Statement or any other registration statement contemplated by this Agreement, or the initiation of any proceedings for that purpose, and (C) the receipt by the Parent of any notification with respect to the suspension of the qualification of any Registrable Units for sale under the applicable securities or blue sky laws of any jurisdiction. The Parent agrees to as promptly as practicable amend or supplement the Prospectus or take other appropriate action so that the Prospectus does not include an untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading, and to take such other action as is necessary to remove a stop order, suspension, threat thereof or proceedings related thereto;

(viii)    upon request, furnish to each selling Holder, subject to appropriate confidentiality obligations, copies of any and all transmittal letters or other correspondence with the SEC or any other governmental agency or self-regulatory body or other body having jurisdiction (including any domestic or foreign securities exchange) relating to such offering of Registrable Units;

(ix)    otherwise use commercially reasonable efforts to comply with all applicable rules and regulations of the SEC, and make available to its security holders, as promptly as practicable, an earnings statement, which earnings statement shall satisfy the provisions of Section 11(a) of the Securities Act and Rule 158 promulgated thereunder;

(x)    use commercially reasonable efforts to cause the Registrable Units to be registered with or approved by such other governmental agencies or authorities as may be necessary by virtue of the business and operations of the Parent to enable the selling Holders to consummate the disposition of such Registrable Units; provided, however, that the Parent shall not be required to qualify or register as a foreign corporation or to take any action that would subject it to general service of process in any such jurisdiction where it is not presently qualified or registered or where it would be subject to taxation as a foreign corporation;

 

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(xi)    in the case of a Shelf Underwritten Offering requested pursuant to Section 2.01(b) or a Block Trade requested pursuant to Section 2.03, enter into an underwriting agreement containing such provisions (including provisions for indemnification, lockups, opinions of counsel and comfort letters) as are customary and reasonable for an offering of such kind;

(xii)    in the case of a Shelf Underwritten Offering requested pursuant to Section 2.01(b) or a Block Trade requested pursuant to Section 2.03, use commercially reasonable efforts to (A) cause the Parent’s independent accountants to provide customary “cold comfort” letters to the managing underwriter(s) of such offering in connection therewith and (B) cause the Parent’s counsel to furnish customary legal opinions to such underwriters in connection therewith; and

(xiii)    use commercially reasonable efforts to cause all such Registrable Units to be listed on each National Securities Exchange on which securities of the same class issued by the Parent are then listed.

(b)    It shall be a condition precedent to the obligations of the Parent to take any action pursuant to this Agreement that the Holders shall furnish to the Parent such information regarding itself, the Registrable Units held by it, and the intended method of disposition of such securities as the Parent shall reasonably request and as shall be required in connection with the action to be taken by the Parent.

(c)    The Holders agree by having their Parent Common Units treated as Registrable Units hereunder that, upon being advised in writing by the Parent of the occurrence of an event pursuant to Section 2.05(a)(vii) when the Parent is entitled to do so pursuant to Section 2.04, the Holders will immediately discontinue (and direct any other Persons making offers and sales of Registrable Units to immediately discontinue) offers and sales of Registrable Units pursuant to any Registration Statement until it is advised in writing by the Parent that the use of the Prospectus may be resumed and is furnished with a supplemented or amended Prospectus as contemplated by Section 2.05(a)(vii), and, if so directed by the Parent, the Holders will deliver to the Parent all copies, other than permanent file copies then in the Holders’ possession, of the Prospectus covering such Registrable Units current at the time of receipt of such notice.

(d)    The Parent may prepare and deliver an issuer free writing prospectus (as such term is defined in Rule 405 under the Securities Act) in lieu of any supplement to a Prospectus, and references herein to any “supplement” to a Prospectus shall include any such issuer free writing prospectus. No seller of Registrable Units may use a free writing prospectus to offer or sell any such Registrable Units without the Parent’s prior written consent.

(e)    It is understood and agreed that the Parent shall not have any obligations under this Article II at any time following the termination of this Agreement, unless an underwritten offering in which any Holder participates has been priced, but not completed, prior to the applicable date of such termination, in which event the Parent’s obligations under this Section 2.05 shall continue with respect to such offering until it is so completed.

 

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Section 2.06    Other Registration Rights Agreements. The Parent has not entered into and unless agreed in writing by each Holder on or after the date of this Agreement, will not enter into, any agreement that (i) is inconsistent with the rights granted to the Holders with respect to Registrable Units in this Agreement or otherwise conflicts with the provisions hereof in any material respect or (ii) other than as set forth in this Agreement, would allow any holder of Parent Common Units to include Parent Common Units in any Registration Statement filed by the Parent on a basis that is more favorable in any material respect to the rights granted to the Holders hereunder.

Section 2.07    Expenses of Registration. All expenses incurred in connection with any Registration pursuant to Section 2.01 and any Registration pursuant to Section 2.02 of this Agreement, and any offerings under the Registration Statements filed in such Registrations, excluding underwriters’ discounts and commissions, but including without limitation all registration, filing and qualification fees, word processing, duplicating, printers’ and accounting fees (including the expenses of any special audits or “cold comfort” letters required by or incident to such performance and compliance), fees of the Financial Industry Regulatory Authority, Inc. or listing fees, messenger and delivery expenses, all fees and expenses of complying with state securities or blue sky laws (including the reasonable fees and disbursements of counsel for the underwriters in connection with blue sky qualifications), and the fees and disbursements of counsel for the Parent (“Registration Expenses”), shall be paid by the Parent. The Holders shall bear and pay the underwriting discounts and commissions applicable to securities offered for their account in connection with any Registrations, Block Trades and underwritten offerings made pursuant to this Agreement.

Section 2.08    Indemnification. The Parent shall indemnify, to the fullest extent permitted by Law, the Holders and their respective directors, officers, affiliates, employees, agents and each Person who controls such Holder (within the meaning of the Securities Act or the Exchange Act), against all losses, claims, damages, liabilities, judgments, costs (including reasonable costs of investigation) and expenses (including reasonable attorneys’ fees) relating to the Registrable Units arising out of or based upon any untrue or alleged untrue statement of a material fact contained in any Registration Statement or Prospectus or any amendment thereof or supplement thereto or arising out of or based upon any omission or alleged omission of a material fact required to be stated therein or necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading, except insofar as the same are made in reliance and in conformity with information furnished in writing to the Parent by any Holder or to the Parent by any participating underwriter for use in connection with any such Registration Statement or Prospectus, or amendment or supplement thereto. In connection with an underwritten offering in which any Holder participates conducted pursuant to a registration effected hereunder, the Parent shall indemnify each participating underwriter to the same extent as provided above with respect to the indemnification of the Holders.

(a)    In connection with any Registration Statement in which any Holder is participating, such Holder shall furnish to the Parent in writing such information as the Parent reasonably

 

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requests for use in connection with any such Registration Statement or Prospectus, or amendment or supplement thereto, and such Holder shall indemnify to the fullest extent permitted by Law, the Parent and its respective directors, officers, affiliates, employees, agents and each Person who controls Parent (within the meaning of the Securities Act or the Exchange Act), against all losses, claims, damages, liabilities, judgments, costs (including reasonable costs of investigation) and expenses (including reasonable attorneys’ fees) arising out of or based upon any untrue or alleged untrue statement of material fact contained in the Registration Statement or Prospectus, or any amendment or supplement thereto, or arising out of or based upon any omission or alleged omission of a material fact required to be stated therein or necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading, but only to the extent that the same are made in reliance and in conformity with information furnished in writing to the Parent by or on behalf of such participating Holder expressly for use therein. In connection with an underwritten offering conducted pursuant to a registration effected hereunder, the participating Holders shall indemnify each participating underwriter to the same extent as provided above with respect to the indemnification of the Parent.

(b)    Any Person entitled to indemnification hereunder shall (1) give prompt written notice to the indemnifying Person of any claim with respect to which it seeks indemnification and (2) permit such indemnifying Person to assume the defense of such claim with counsel reasonably satisfactory to the indemnified Person. Failure to so notify the indemnifying Person shall not relieve it from any liability that it may have to an indemnified Person. The indemnifying Person shall not be subject to any liability for any settlement made by the indemnified Person without its consent (but such consent will not be unreasonably withheld). An indemnifying Person who is entitled to, and elects to, assume the defense of a claim shall not be obligated to pay the fees and expenses of more than one counsel (in addition to one local counsel) for all Persons indemnified (hereunder or otherwise) by such indemnifying Person with respect to such claim (and all other claims arising out of the same circumstances), unless in the reasonable judgment of any indemnified Person there may be one or more legal or equitable defenses available to such indemnified Person that are in addition to or may conflict with those available to another indemnified Person with respect to such claim, in which case each such indemnified Person shall be entitled to use separate counsel. The indemnifying Person shall not consent to the entry of any judgment or enter into or agree to any settlement relating to a claim or action for which any indemnified Person would be entitled to indemnification by any indemnified Person hereunder unless such judgment or settlement imposes no ongoing obligations on any such indemnified Person and includes as an unconditional term the giving, by all relevant claimants and plaintiffs to such indemnified Person, of a release, reasonably satisfactory in form and substance to such indemnified Person, from all liabilities in respect of such claim or action for which such indemnified Person would be entitled to such indemnification.

(c)    The indemnification provided for under this Agreement shall remain in full force and effect regardless of any investigation made by or on behalf of the indemnified Person or any officer or director of such indemnified Person and shall survive the transfer of securities and the termination of this Agreement, but only with respect to offers and sales of Registrable Units made before such termination.

 

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(d)    If the indemnification provided for in or pursuant to this Section 2.08 is due in accordance with the terms hereof, but is held by a court to be unavailable or unenforceable in respect of any losses, claims, damages, liabilities or expenses referred to herein, then each applicable indemnifying Person, in lieu of indemnifying such indemnified Person, shall contribute to the amount paid or payable by such indemnified Person as a result of such losses, claims, damages, liabilities or expenses in such proportion as is appropriate to reflect the relative fault of the indemnifying Person, on the one hand, and of the indemnified Person, on the other hand, in connection with the statements or omissions which result in such losses, claims, damages, liabilities or expenses as well as any other relevant equitable considerations. The relative fault of the indemnifying Person, on the one hand, and of the indemnified Person, on the other hand, shall be determined by reference to, among other things, whether the untrue or alleged untrue statement of a material fact or the omission or alleged omission to state a material fact relates to information supplied by the indemnifying Person or by the indemnified Person, and by such Person’s relative intent, knowledge, access to information and opportunity to correct or prevent such statement or omission.

Section 2.09    Lockup. The Holders shall, in connection with any underwritten offering of Parent Common Units, upon the request of the underwriters managing the underwritten offering of Parent Common Units, agree in writing not to effect any sale, disposition or distribution of any Registrable Units (other than that included in such Registration) without the prior written consent of the underwriters for such period of time as such underwriters may specify, but in no event to exceed 10 days prior to the date of the Prospectus and 60 days from the date of the Prospectus.

ARTICLE III

MISCELLANEOUS

Section 3.01    Termination. Except as provided in Section 2.08, this Agreement and all obligations of the Parent and each of the Holders hereunder shall automatically terminate and have no further force or effect as of the earlier of (i) the date on which the aggregate beneficial ownership of the Holders is less than 5% of the Registrable Units held by the Holders on the date hereof, and (ii) the date that is three years from the date here.

Section 3.02    Interpretations. In this Agreement, unless a clear contrary intention appears: (a) the singular includes the plural and vice versa; (b) reference to a Person includes such Person’s successors and assigns but, in the case of a Party, only if such successors and assigns are permitted by this Agreement, and reference to a Person in a particular capacity excludes such Person in any other capacity; (c) reference to any gender includes each other gender; (d) references to any Schedule, Section, Article and subsection refer to the corresponding Schedules, Sections, Articles and subsections of this Agreement unless expressly provided otherwise; (e) references in any Section or Article or definition to any clause means such clause of such Section, Article or definition; (f) “hereunder,” “hereof,” “hereto” and words of similar import are references to this Agreement as a whole and not to any particular provision of this Agreement; (g) the word “or” is not exclusive, and the word “including” (in its various forms) means “including without limitation”; (h) each accounting term not otherwise defined in this Agreement has the meaning commonly applied to it in accordance with GAAP; (i) references to “days” are to calendar days;

 

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and (j) all references to money refer to the lawful currency of the United States. The Article and Section titles and headings in this Agreement are inserted for convenience of reference only and are not intended to be a part of, or to affect the meaning or interpretation of, this Agreement.

Section 3.03    Amendment and Modifications. This Agreement may be amended, modified or supplemented only by written agreement of the Parent and Holders holding a majority of the then outstanding Registrable Units; provided, however, that notwithstanding the foregoing, any amendment, modification or supplement hereto that adversely affects one Holder, solely in its capacity as a holder of the Parent Common Units, in a manner that is materially different from the other Holders (in such capacity) shall require the consent of the Holder so affected.

Section 3.04    Waiver of Compliance. Except as otherwise provided in this Agreement, any failure of any of the Parties to comply with any obligation, covenant, agreement or condition herein may be waived by the Party entitled to the benefits thereof only by a written instrument signed by the Party granting such waiver, but such waiver or failure to insist upon strict compliance with such obligation, covenant, agreement or condition shall not operate as a waiver of, or estoppel with respect to, any subsequent or other failure.

Section 3.05    Notices. All notices and other communications hereunder shall be in writing and shall be deemed given if delivered personally or by email transmission, or mailed by a nationally recognized overnight courier, postage prepaid, to the Parties at the following addresses (or at such other address for a Party as shall be specified by like notice; provided, that notices of a change of address shall be effective only upon receipt thereof):

If to Parent to:

Energy Transfer LP

8111 Westchester Drive, Suite 600

Dallas, Texas 75225

Attention: General Counsel

E-Mail: tom.mason@energytransfer.com

with a copy to:

Latham & Watkins LLP

811 Main Street, Suite 3700

Houston, Texas 77002

  Attention:

William N. Finnegan IV

   

Kevin Richardson

  E-Mail:

bill.finnegan@lw.com

   

kevin.richardson@lw.com

and if to any Holder, at such Holder’s address or facsimile number as set forth in the Parent’s books and records.

 

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Section 3.06    Transfer or Assignment of Registration Rights. The rights to cause the Parent to register Registrable Units under Article II may be transferred or assigned by each Holder only to one or more transferees or assignees of Registrable Units that is an Affiliate of such Holder; provided, that (a) the Parent is given written notice prior to any said transfer or assignment, stating the name and address of each such Affiliate transferee or assignee and identifying the securities with respect to which such registration rights are being transferred or assigned and (b) each such Affiliate transferee or assignee assumes in writing responsibility for its portion of the obligations of such transferring Holder under this Agreement.

Section 3.07    Recapitalization, Exchanges, Etc. Affecting Units. The provisions of this Agreement shall apply to the full extent set forth herein with respect to any and all securities of the Parent or any successor or assign of the Parent (whether by merger, consolidation, sale of assets or otherwise) that may be issued in respect of, in exchange for or in substitution of, the Registrable Units, and shall be appropriately adjusted for combinations, unit splits, recapitalizations, pro rata distributions of units and the like occurring after the date of this Agreement.

Section 3.08    Third Party Beneficiaries. This Agreement shall be binding upon and, except as provided below, inure solely to the benefit of the Parties hereto and their respective successors and permitted assigns. None of the provisions of this Agreement shall be for the benefit of or enforceable by any Person other than the Parties, including any creditor of any Party or any of their Affiliates, except that Section 2.08 shall inure to the benefit of the Persons referred to therein. No Person other than the Parties shall obtain any right under any provision of this Agreement or shall by reason of any such provision make any claim in respect of any liability (or otherwise) against any other Parties hereto.

Section 3.09    Entire Agreement. This Agreement constitutes the entire agreement and understanding of the Parties with respect to the subject matter hereof and supersedes all prior agreements and understandings, both oral and written, among the Parties or between any of them with respect to such subject matter.

Section 3.10    Severability. Whenever possible, each provision of this Agreement shall be interpreted in such manner as to be effective and valid under applicable Law, but if any provision or portion of this Agreement is held to be invalid, illegal or unenforceable in any respect under any applicable Law in any jurisdiction by any applicable Governmental Authority, such invalidity, illegality or unenforceability shall not affect the validity, legality or enforceability of any other provision of this Agreement in such jurisdiction or affect the validity, legality or enforceability of any provision in any other jurisdiction, such provision shall be invalid, illegal or unenforceable only to the extent strictly required by such Governmental Authority, to the extent any such provision is deemed to be invalid, illegal or unenforceable, each Party agrees that it shall use its reasonable best efforts to cause such Governmental Authority to modify such provision so that such provision shall be valid, legal and enforceable as originally intended to the greatest extent possible and to the extent that the Governmental Authority does not modify such provision, each Party agrees that it shall endeavor in good faith to exercise or modify such provision so that such provision shall be valid, legal and enforceable as originally intended to the greatest extent possible.

 

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Section 3.11    Facsimiles; Electronic Transmission; Counterparts. This Agreement may be executed by facsimile or other electronic transmission (including scanned documents delivered by email) by any Party and such execution shall be deemed binding for all purposes hereof, without delivery of an original signature being thereafter required. This Agreement may be executed in one or more counterparts, each of which, when executed, shall be deemed to be an original and all of which together shall constitute one and the same document.

Section 3.12    Descriptive Headings. The descriptive headings of this Agreement are inserted for convenience only and do not constitute a part of this Agreement

Section 3.13    Governing Law. This Agreement and all questions relating to the interpretation or enforcement of this Agreement shall be governed by and construed in accordance with the Laws of the State of Delaware without regard to the Laws of the State of Delaware or any other jurisdiction that would call for the application of the substantive laws of any jurisdiction other than the State of Delaware.

Section 3.14    Consent to Jurisdiction. Each Party hereby agrees that service of summons, complaint or other process in connection with any Proceedings contemplated hereby may be made in accordance with Section 3.05 addressed to such Party at the address specified pursuant to Section 3.05. Each of the Parties irrevocably submits to the exclusive jurisdiction of the Court of Chancery of the State of Delaware, or in the event, but only in the event, that such court does not have jurisdiction over such action or proceeding, to the exclusive jurisdiction of the Superior Court of the State of Delaware (Complex Commercial Division) or, if the subject matter jurisdiction over the matter that is the subject of any such Proceedings is vested exclusively in the federal courts of the United States of America, the United States District Court for the District of Delaware, and any appellate courts of any thereof (collectively, the “Courts”), for the purposes of any Proceeding arising out of or relating to this Agreement or any transaction contemplated hereby (and agrees not to commence any Proceeding relating hereto except in such Courts as provided herein). Each of the Parties further agrees that service of any process, summons, notice or document hand delivered or sent in accordance with Section 3.05 to such Party’s address set forth in Section 3.05 will be effective service of process for any Proceeding in Delaware with respect to any matters to which it has submitted to jurisdiction as set forth in the immediately preceding sentence. Each of the Parties irrevocably and unconditionally waives any objection to the laying of venue of any Proceeding arising out of or relating to this Agreement or the transactions contemplated hereby or thereby in the Courts, and hereby further irrevocably and unconditionally waives and agrees not to plead or claim in any such court that any such Proceeding brought in any such court has been brought in an inconvenient forum. Notwithstanding the foregoing, each Party agrees that a final judgment in any Proceeding properly brought in accordance with the terms of this Agreement shall be conclusive and may be enforced by suit on the judgment in any jurisdiction or in any other manner provided at law or in equity.

Section 3.15    WAIVER OF JURY TRIAL. EACH PARTY WAIVES ALL RIGHT TO TRIAL BY JURY IN ANY PROCEEDING TO ENFORCE OR DEFEND ANY RIGHTS UNDER THIS AGREEMENT.

 

16


Section 3.16    Remedies. The Parties hereto agree that money damages would not be a sufficient remedy for any breach of this Agreement and that irreparable damage would occur in the event that any of the provisions of this Agreement were not performed in accordance with their specific terms or were otherwise breached. It is hereby agreed that, prior to the valid termination of this Agreement pursuant to Section 3.01, the Parties hereto shall be entitled to specific performance and injunctive or other equitable relief as a remedy for any such breach, to prevent breaches of this Agreement, and to specifically enforce compliance with this Agreement. In connection with any request for specific performance or equitable relief, each of the Parties hereto hereby waives any requirement for security or posting of any bond in connection with such remedy. Such remedy shall not be deemed to be the exclusive remedy for breach of this Agreement but shall be in addition to all other remedies available at law or equity to such party. The Parties further agree that, by seeking the remedies provided for in this Section 3.16, no Party hereto shall in any respect waive its right to seek any other form of relief that may be available to it (i) under this Agreement, including monetary damages in the event that this Agreement has been terminated or in the event that the remedies provided for in this Section 3.16 are not available or otherwise are not granted, or (ii) under the Merger Agreement.

[Signature Pages Follow]

 

17


IN WITNESS WHEREOF, the Parties have caused this Agreement to be duly executed as of the date first above written.

 

ENERGY TRANSFER LP
By:   LE GP, LLC.,
  its general partner
By:  

 

  Name:
  Title:
CENTERPOINT ENERGY, INC.
By:  

 

  Name:
  Title:
OGE ENERGY CORP.
By:  

 

  Name:
  Title:

SIGNATURE PAGE TO

REGISTRATION RIGHTS AGREEMENT


Schedule I

Holders

 

Name

   Number of Parent Common Units

CenterPoint Energy, Inc.

   [ ● ]

OGE Energy Corp.

   [ ● ]

Schedule I


Exhibit B

Sponsor Written Consent

WRITTEN CONSENT OF

[INSERT NAME OF UNITHOLDER]

[], 2021

Pursuant to Section 2.1 of that certain Support Agreement, dated as of February 16, 2021, by and between Energy Transfer LP, a Delaware limited partnership (“Parent”), Elk Merger Sub LLC, a Delaware limited liability company and a wholly owned subsidiary of Parent (“LP Merger Sub”), Elk GP Merger Sub LLC, a Delaware limited liability company and a wholly owned subsidiary of Parent (“GP Merger Sub”), Enable Midstream Partners, LP, a Delaware limited partnership (the “Partnership”), and Enable GP, LLC, a Delaware limited liability company and the general partner of the Partnership (the “General Partner”), the undersigned unitholder hereby provides its written consent to the matters set forth below. The undersigned unitholder’s common units of the Partnership (the “Partnership Common Units”) will be tabulated and voted on the proposal as indicated below. Any executed written consent returned without indicating a decision on the proposal will be voted to APPROVE the proposal.

The undersigned, being a record holder as of the close of business on [●], 2021 of [●] Partnership Common Units hereby acknowledges receipt of the consent statement/prospectus, which is part of the registration statement on Form S-4 (No. 333-[●]) of Parent, and which more fully describes the proposal below.

The undersigned record holder of [●] Partnership Common Units also hereby consents to, and does hereby approve, the Agreement and Plan of Merger, dated as of February 16, 2021, as such agreement may be amended from time to time, by and among Parent, LP Merger Sub, GP Merger Sub, the Partnership, the General Partner and solely for the purposes of Section 2.1(a)(i) therein, LE GP, LLC, a Delaware limited liability company and sole general partner of Parent, and, solely for purposes of Section 1.1(b)(i) therein, CenterPoint Energy, Inc., and the transactions contemplated thereby, including the merger of Merger Sub with and into the Partnership (the “Merger”), with the Partnership surviving as a wholly owned subsidiary of Parent.

By signing this written consent, a unitholder of the Partnership shall be deemed to have voted in favor of the proposal described above with respect to all Partnership Common Units which it is entitled to vote.

 

APPROVE ☐

  

DISAPPROVE ☐

  

ABSTAIN ☐

IMPORTANT: PLEASE DATE AND SIGN THE CONSENT BELOW. Please execute, date, sign and return this Written Consent promptly to (i) the Partnership by mailing it to 499 West Sheridan Avenue, Suite 1500 Oklahoma City, Oklahoma, Attention: Mark C. Schroeder, or by emailing a .pdf copy of your written consent to Mark.Schroeder@enablemidstream.com and (ii) to Energy Transfer, by emailing a .pdf copy of your written consent to Tom.Mason@energytransfer.com with a copy to Bill.Finnegan@lw.com.

IF AN ENTITY

 

 

(please print or type complete name of entity)

By:

(duly authorized signature)

Name:

(please print or type full name)

Title:

(please print or type full name)

Date:

EX-3.1

Exhibit 3.1

CERTIFICATE OF LIMITED PARTNERSHIP

OF

ENERGY TRANSFER EQUITY, L.P.

This Certificate of Limited Partnership, dated August     , 2005, has been duly executed and is filed pursuant to Section 17-201 of the Delaware Revised Uniform Limited Partnership Act (the “ Act ”) to form a limited partnership under the Act.

1. Name . The name of the limited partnership is “Energy Transfer Equity, L.P.”

2. Registered Office; Registered Agent . The address of the registered office required to be maintained by Section 17-104 of the Act is:

Corporation Trust Center

1209 Orange Street

Wilmington, Delaware 19801.

The name and the address of the registered agent for service of process required to be maintained by Section 17-104 of the Act are:

The Corporation Trust Company

Corporation Trust Center

1209 Orange Street

Wilmington, Delaware 19801.

3. General Partner. The name and the business, residence or mailing address of the general partner are:

LE GP, LLC

2828 Woodside Drive

Dallas, Texas 75204

EXECUTED as of the date written first above.

 

LE GP, LLC
its General Partner
By:  

/s/ John W. McReynolds

Name:   John W. McReynolds
Title:   President
EX-3.2

Exhibit 3.2

CERTIFICATE OF AMENDMENT

TO

CERTIFICATE OF LIMITED PARTNERSHIP

OF

ENERGY TRANSFER EQUITY, L.P.

The undersigned, desiring to amend the Certificate of Limited Partnership of Energy Transfer Equity, L.P., a Delaware limited partnership (the “Partnership”), as heretofore amended, pursuant to the provisions of Section 17-202 of the Delaware Revised Uniform Limited Partnership Act, does hereby certify as follows:

1.    The name of the limited partnership is Energy Transfer Equity, L.P.

2.    The certificate of limited partnership of the Partnership is hereby amended by deleting Paragraph 1 in its entirety and replacing it with the following new Paragraph:

“1.    Name. The name of the limited partnership is:

“Energy Transfer LP”

3.    This Certificate of Amendment shall become effective at 8:01 AM, Eastern Time, on October 19, 2018.

[ Signature Page Follows.]


IN WITNESS WHEREOF, the undersigned, being the sole general partner of the Partnership, has duly executed this Certificate of Amendment to Certificate of Limited Partnership of the Partnership.

 

GENERAL PARTNER:
LE GP, LLC
By:   /s/ John W. McReynolds
Name:   John W. McReynolds
Title:   President

SIGNATURE PAGE TO

CERTIFICATE OF AMENDMENT TO

CERTIFICATE OF LIMITED PARTNERSHIP OF

ENERGY TRANSFER EQUITY, L.P.

EX-3.3

Exhibit 3.3

THIRD AMENDED AND RESTATED

AGREEMENT OF LIMITED PARTNERSHIP

OF

ENERGY TRANSFER EQUITY, L.P.


TABLE OF CONTENTS

 

ARTICLE I
DEFINITIONS

 

Section 1.1

  Definitions      1  

Section 1.2

  Construction      15  

ARTICLE II

ORGANIZATION

 

Section 2.1

  Formation      15  

Section 2.2

  Name      15  

Section 2.3

  Registered Office; Registered Agent; Principal Office; Other Offices      16  

Section 2.4

  Purpose and Business      16  

Section 2.5

  Powers      16  

Section 2.6

  Power of Attorney      17  

Section 2.7

  Term      18  

Section 2.8

  Title to Partnership Assets      18  

ARTICLE III

RIGHTS OF LIMITED PARTNERS

 

Section 3.1

  Limitation of Liability      18  

Section 3.2

  Management of Business      19  

Section 3.3

  Outside Activities of the Limited Partners      19  

Section 3.4

  Rights of Limited Partners      19  

ARTICLE IV

CERTIFICATES; RECORD HOLDERS; TRANSFER OF PARTNERSHIP INTERESTS;

REDEMPTION OF PARTNERSHIP INTERESTS

 

Section 4.1

  Certificates      20  

Section 4.2

  Mutilated, Destroyed, Lost or Stolen Certificates      20  

Section 4.3

  Record Holders      21  

Section 4.4

  Transfer Generally      22  

Section 4.5

  Registration and Transfer of Limited Partner Interests      22  

Section 4.6

  Transfer of the General Partner Interest      23  

Section 4.7

  Restrictions on Transfers      24  

Section 4.8

  Taxation Certifications; Ineligible Assignees      25  

Section 4.9

  Redemption of Partnership Interests of Ineligible Assignees      26  

ARTICLE V

CAPITAL CONTRIBUTIONS AND ISSUANCE OF PARTNERSHIP INTERESTS

 

Section 5.1

  Prior Contributions      27  

Section 5.2

  Continuation of General Partner and Limited Partner Interests; Initial Offering; Contributions by the General Partner      28  

Section 5.3

  Issuance of Class B Units      28  


Section 5.4

  Contributions by the Underwriters      28  

Section 5.5

  Interest and Withdrawal      29  

Section 5.6

  Capital Accounts      29  

Section 5.7

  Conversion of Class B Units      31  

Section 5.8

  Issuances of Additional Partnership Securities      32  

Section 5.9

  Limited Preemptive Right      33  

Section 5.10

  Splits and Combinations      33  

Section 5.11

  Fully Paid and Non-Assessable Nature of Limited Partner Interests      34  

ARTICLE VI

ALLOCATIONS AND DISTRIBUTIONS

 

 

Section 6.1

  Allocations for Capital Account Purposes      34  

Section 6.2

  Allocations for Tax Purposes      38  

Section 6.3

  Requirement and Characterization of Distributions; Distributions to Record Holders      41  

Section 6.4

  Special Provisions Relating to the Holders of Class B Units      41  

ARTICLE VII

MANAGEMENT AND OPERATION OF BUSINESS

 

 

Section 7.1

  Management      42  

Section 7.2

  Certificate of Limited Partnership      44  

Section 7.3

  Restrictions on General Partner’s Authority      44  

Section 7.4

  Reimbursement of the General Partner      45  

Section 7.5

  Outside Activities      46  

Section 7.6

  Loans from the General Partner; Loans or Contributions from the Partnership; Contracts with Affiliates; Certain Restrictions on the General Partner      47  

Section 7.7

  Indemnification      49  

Section 7.8

  Liability of Indemnitees      50  

Section 7.9

  Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties      51  

Section 7.10

  Other Matters Concerning the General Partner      53  

Section 7.11

  Purchase or Sale of Partnership Securities      53  

Section 7.12

  Registration Rights of the General Partner and its Affiliates      54  

Section 7.13

  Reliance by Third Parties      57  

ARTICLE VIII

BOOKS, RECORDS, ACCOUNTING AND REPORTS

 

 

Section 8.1

  Records and Accounting      58  

Section 8.2

  Fiscal Year      58  

Section 8.3

  Reports      58  

ARTICLE IX

TAX MATTERS

 

 

Section 9.1

  Tax Returns and Information      59  

Section 9.2

  Tax Elections      59  

 

 

- ii -


Section 9.3

  Tax Controversies      59  

Section 9.4

  Withholding      59  

ARTICLE X

ADMISSION OF PARTNERS

 

Section 10.1

  Admission of Substituted Limited Partners      60  

Section 10.2

  Admission of Successor General Partner      61  

Section 10.3

  Admission of Additional Limited Partners      61  

Section 10.4

  Amendment of Agreement and Certificate of Limited Partnership      62  

ARTICLE XI

WITHDRAWAL OR REMOVAL OF PARTNERS

 

Section 11.1

  Withdrawal of the General Partner      62  

Section 11.2

  Removal of the General Partner      64  

Section 11.3

  Interest of Departing General Partner and Successor General Partner      64  

Section 11.4

  Withdrawal of Limited Partners      65  

ARTICLE XII

DISSOLUTION AND LIQUIDATION

 

Section 12.1

  Dissolution      65  

Section 12.2

  Continuation of the Business of the Partnership After Dissolution      66  

Section 12.3

  Liquidator      67  

Section 12.4

  Liquidation      67  

Section 12.5

  Cancellation of Certificate of Limited Partnership      68  

Section 12.6

  Return of Contributions      68  

Section 12.7

  Waiver of Partition      68  

Section 12.8

  Capital Account Restoration      68  

Section 12.9

  Certain Prohibited Acts      68  

ARTICLE XIII

AMENDMENT OF PARTNERSHIP AGREEMENT; MEETINGS; RECORD DATE

 

Section 13.1

  Amendments to be Adopted Solely by the General Partner      69  

Section 13.2

  Amendment Procedures      70  

Section 13.3

  Amendment Requirements      71  

Section 13.4

  Special Meetings      72  

Section 13.5

  Notice of a Meeting      72  

Section 13.6

  Record Date      72  

Section 13.7

  Adjournment      73  

Section 13.8

  Waiver of Notice; Approval of Meeting; Approval of Minutes      73  

Section 13.9

  Quorum      73  

Section 13.10

  Conduct of a Meeting      74  

Section 13.11

  Action Without a Meeting      74  

Section 13.12

  Voting and Other Rights      75  

 

- iii -


ARTICLE XIV

MERGER, CONSOLIDATION OR CONVERSION

 

Section 14.1

  Authority      75  

Section 14.2

  Procedure for Merger, Consolidation or Conversion      75  

Section 14.3

  Approval by Limited Partners      77  

Section 14.4

  Certificate of Merger      78  
Section 14.5   Amendment of Partnership Agreement      79  

ARTICLE XV

RIGHT TO ACQUIRE LIMITED PARTNER INTERESTS

 

Section 15.1

  Right to Acquire Limited Partner Interests      79  

ARTICLE XVI

COMMON UNIT REDEMPTION AGREEMENT

 

Section 16.1

  Redemption of Units      81  

Section 16.2

  Representations and Warranties of Initial Limited Partners      82  

Section 16.3

  Conditions to Closing of the IPO Upsize Redemption.      83  

Section 16.4

  Conditions to Closing of the Option Units Redemption.      84  

ARTICLE XVII

GENERAL PROVISIONS

 

Section 17.1

  Addresses and Notices      85  

Section 17.2

  Further Action      86  

Section 17.3

  Binding Effect      86  

Section 17.4

  Integration      86  

Section 17.5

  Creditors      86  

Section 17.6

  Waiver      86  

Section 17.7

  Counterparts      86  

Section 17.8

  Applicable Law      86  

Section 17.9

  Invalidity of Provisions      87  

Section 17.10

  Consent of Partners      87  

Section 17.11

  Facsimile Signatures      87  

Section 17.12

  Third Party Beneficiaries      87  

 

 

- iv -


THIRD AMENDED AND RESTATED

AGREEMENT OF LIMITED PARTNERSHIP

OF

ENERGY TRANSFER EQUITY, L.P.

THIS THIRD AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF ENERGY TRANSFER EQUITY, L.P. dated as of February 8, 2006, is entered into by and among LE GP, LLC, a Delaware limited liability company, as the General Partner, together with any other Persons who become Partners in the Partnership or parties hereto as provided herein. In consideration of the covenants, conditions and agreements contained herein, the parties hereto hereby agree as follows:

ARTICLE I

DEFINITIONS

Section 1.1 Definitions.

The following definitions shall be for all purposes, unless otherwise clearly indicated to the contrary, applied to the terms used in this Agreement.

Acquisition ” means any transaction in which any Group Member acquires (through an asset acquisition, merger, stock acquisition or other form of investment) control over all or a portion of the assets, properties or business of another Person for the purpose of increasing the operating capacity or revenues of the Partnership Group from the operating capacity or revenues of the Partnership Group existing immediately prior to such transaction.

Additional Book Basis ” means the portion of any remaining Carrying Value of an Adjusted Property that is attributable to positive adjustments made to such Carrying Value as a result of Book-Up Events. For purposes of determining the extent that Carrying Value constitutes Additional Book Basis:

(i) Any negative adjustment made to the Carrying Value of an Adjusted Property as a result of either a Book-Down Event or a Book-Up Event shall first be deemed to offset or decrease that portion of the Carrying Value of such Adjusted Property that is attributable to any prior positive adjustments made thereto pursuant to a Book-Up Event or Book-Down Event.

(ii) If Carrying Value that constitutes Additional Book Basis is reduced as a result of a Book-Down Event and the Carrying Value of other property is increased as a result of such Book-Down Event, an allocable portion of any such increase in Carrying Value shall be treated as Additional Book Basis; provided that the amount treated as Additional Book Basis pursuant hereto as a result of such Book-Down Event shall not exceed the amount by which the Aggregate Remaining Net Positive Adjustments after such Book-Down Event exceeds the remaining Additional Book Basis attributable to all of the Partnership’s Adjusted Property after such Book-Down Event (determined without regard to the application of this clause (ii) to such Book-Down Event).


Additional Book Basis Derivative Items ” means any Book Basis Derivative Items that are computed with reference to Additional Book Basis. To the extent that the Additional Book Basis attributable to all of the Partnership’s Adjusted Property as of the beginning of any taxable period exceeds the Aggregate Remaining Net Positive Adjustments as of the beginning of such period (the “ Excess Additional Book Basis ”), the Additional Book Basis Derivative Items for such period shall be reduced by the amount that bears the same ratio to the amount of Additional Book Basis Derivative Items determined without regard to this sentence as the Excess Additional Book Basis bears to the Additional Book Basis as of the beginning of such period.

Additional Limited Partner ” means a Person admitted to the Partnership as a Limited Partner pursuant to Section 4.5 and who is shown as such on the books and records of the Partnership.

Adjusted Capital Account ” means the Capital Account maintained for each Partner as of the end of each fiscal year of the Partnership, (a) increased by any amounts that such Partner is obligated to restore under the standards set by Treasury Regulation Section 1.704-1(b)(2)(ii)(c) (or is deemed obligated to restore under Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5)) and (b) decreased by (i) the amount of all losses and deductions that, as of the end of such fiscal year, are reasonably expected to be allocated to such Partner in subsequent years under Section 704(e)(2) and Section 706(d) of the Code and Treasury Regulation Section 1.751-1(b)(2)(ii), and (ii) the amount of all distributions that, as of the end of such fiscal year, are reasonably expected to be made to such Partner in subsequent years in accordance with the terms of this Agreement or otherwise to the extent they exceed offsetting increases to such Partner’s Capital Account that are reasonably expected to occur during (or prior to) the year in which such distributions are reasonably expected to be made (other than increases as a result of a minimum gain chargeback pursuant to Section 6.1(d)(i) or Section 6.1(d)(ii)). The foregoing definition of Adjusted Capital Account is intended to comply with the provisions of Treasury Regulation Section 1.704-1(b)(2)(ii)(d) and shall be interpreted consistently therewith. The “ Adjusted Capital Account ” of a Partner in respect of a General Partner Interest, a Common Unit, Class B Unit or any other Partnership Interest shall be the amount that such Adjusted Capital Account would be if such General Partner Interest, Common Unit, Class B Unit or other Partnership Interest were the only interest in the Partnership held by a Partner from and after the date on which such General Partner Interest, Common Unit, Class B Unit or other Partnership Interest was first issued.

Adjusted Property ” means any property the Carrying Value of which has been adjusted pursuant to Section 5.6(d)(i) or Section 5.6(d)(ii).

Affiliate ” means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with, the Person in question. As used herein, the term “ control ” means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.

Aggregate Remaining Net Positive Adjustments ” means, as of the end of any taxable period, the sum of the Remaining Net Positive Adjustments of all the Partners.

 

 

- 2 -


Agreed Allocation ” means any allocation, other than a Required Allocation, of an item of income, gain, loss or deduction pursuant to the provisions of Section 6.1, including, without limitation, a Curative Allocation (if appropriate to the context in which the term “ Agreed Allocation ” is used).

Agreed Value ” of any Contributed Property means the fair market value of such property or other consideration at the time of contribution as determined by the General Partner. The General Partner shall use such method as it determines to be appropriate to allocate the aggregate Agreed Value of Contributed Properties contributed to the Partnership in a single or integrated transaction among each separate property on a basis proportional to the fair market value of each Contributed Property.

Agreement ” means this Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., as it may be amended, supplemented or restated from time to time.

Assignee ” means a Person to whom one or more Limited Partner Interests have been transferred in a manner permitted under this Agreement and who has executed and delivered a Transfer Application, including a Taxation Certification, as required by this Agreement but who has not been admitted as a Substituted Limited Partner.

Associate ” means, when used to indicate a relationship with any Person, (a) any corporation or organization of which such Person is a director, officer or partner or is, directly or indirectly, the owner of 20% or more of any class of voting stock or other voting interest; (b) any trust or other estate in which such Person has at least a 20% beneficial interest or as to which such Person serves as trustee or in a similar fiduciary capacity; and (c) any relative or spouse of such Person, or any relative of such spouse, who has the same principal residence as such Person.

Available Cash ” means, with respect to any Quarter ending prior to the Liquidation Date,

(a) the sum of (i) all cash and cash equivalents of the Partnership Group (or the Partnership’s proportionate share of cash and cash equivalents in the case of Subsidiaries that are not wholly owned) on hand at the end of such Quarter, and (ii) all additional cash and cash equivalents of the Partnership Group (or the Partnership’s proportionate share of cash and cash equivalents in the case of Subsidiaries that are not wholly owned) on hand immediately prior to the date of the distribution of Available Cash with respect to such Quarter, less

(b) the amount of any cash reserves (or the Partnership’s proportionate share of cash reserves in the case of Subsidiaries that are not wholly owned) established by the General Partner to (i) provide for the proper conduct of the business of the Partnership (including reserves for future capital expenditures, for anticipated future credit needs of the Partnership Group and for refunds of collected rates reasonably likely to be refunded as a result of a settlement or hearing relating to FERC rate proceedings) subsequent to such Quarter, (ii) comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which any Group Member

 

- 3 -


is a party or by which it is bound or its assets are subject or (iii) provide funds for distributions under Section 6.3 in respect of any one or more of the next four Quarters; provided, however, that disbursements made by a Group Member or cash reserves established, increased or reduced after the end of such Quarter but on or before the date of determination of Available Cash with respect to such Quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining Available Cash, within such Quarter if the General Partner so determines.

Notwithstanding the foregoing, “ Available Cash ” with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero.

Board of Directors ” means, with respect to the Board of Directors of the general partner of the General Partner, its board of directors or managers, as applicable, if a corporation or limited liability company, or if a limited partnership, the board of directors or board of managers of the general partner of the General Partner.

Book Basis Derivative Items ” means any item of income, deduction, gain or loss included in the determination of Net Income or Net Loss that is computed with reference to the Carrying Value of an Adjusted Property ( e.g., depreciation, depletion, or gain or loss with respect to an Adjusted Property).

Book-Down Event ” means an event which triggers a negative adjustment to the Capital Accounts of the Partners pursuant to Section 5.6(d).

Book-Tax Disparity ” means with respect to any item of Contributed Property or Adjusted Property, as of the date of any determination, the difference between the Carrying Value of such Contributed Property or Adjusted Property and the adjusted basis thereof for federal income tax purposes as of such date. A Partner’s share of the Partnership’s Book-Tax Disparities in all of its Contributed Property and Adjusted Property will be reflected by the difference between such Partner’s Capital Account balance as maintained pursuant to Section 5.6 and the hypothetical balance of such Partner’s Capital Account computed as if it had been maintained strictly in accordance with federal income tax accounting principles.

Book-Up Event ” means an event which triggers a positive adjustment to the Capital Accounts of the Partners pursuant to Section 5.6(d).

Business Day ” means Monday through Friday of each week, except that a legal holiday recognized as such by the government of the United States of America or the states of New York or Texas shall not be regarded as a Business Day.

Capital Account ” means the capital account maintained for a Partner pursuant to Section 5.6. The “ Capital Account ” of a Partner in respect of a General Partner Interest, a Common Unit, a Class B Unit or any other Partnership Interest shall be the amount that such Capital Account would be if such General Partner Interest, Common Unit, Class B Unit or other Partnership Interest were the only interest in the Partnership held by a Partner from and after the date on which such General Partner Interest, Common Unit, Class B Unit or other Partnership Interest was first issued.

 

- 4 -


Capital Contribution ” means any cash, cash equivalents or the Net Agreed Value of Contributed Property that a Partner contributes to the Partnership pursuant to this Agreement.

Carrying Value ” means (a) with respect to a Contributed Property, the Agreed Value of such property reduced (but not below zero) by all depreciation, amortization and cost recovery deductions charged to the Partners’ Capital Accounts in respect of such Contributed Property, and (b) with respect to any other Partnership property, the adjusted basis of such property for federal income tax purposes, all as of the time of determination. The Carrying Value of any property shall be adjusted from time to time in accordance with Section 5.6(d)(i) and 5.6(d)(ii) and to reflect changes, additions or other adjustments to the Carrying Value for dispositions and acquisitions of Partnership properties, as deemed appropriate by the General Partner.

Cause ” means a court of competent jurisdiction has entered a final, non-appealable judgment finding the General Partner liable for actual fraud or willful misconduct in its capacity as a general partner of the Partnership.

Certificate ” means a certificate (i) substantially in the form of Exhibit A to this Agreement with respect to the Common Units, (ii) substantially in the form of Exhibit B to this Agreement with respect to the Class B Units, (iii) issued in global form in accordance with the rules and regulations of the Depositary or (iv) in such other form as may be adopted by the General Partner, issued by the Partnership evidencing ownership of one or more Units, or a certificate, in such form as may be adopted by the General Partner, issued by the Partnership evidencing ownership of one or more other Partnership Securities.

Certificate of Conversion ” means the Certificate of Conversion of the Partnership filed with Secretary of State of Delaware as referenced in Section 2.1 as such Certificate of Conversion may be amended, supplemented or restated from time to time.

Certificate of Limited Partnership ” means the Certificate of Limited Partnership of the Partnership filed with the Secretary of State of the State of Delaware as referenced in Section 2.1, as such Certificate of Limited Partnership may be amended, supplemented or restated from time to time.

Claim ” (as used in Section 7.12(d)) has the meaning assigned to such term in Section 7.12(d).

Class B Unit ” means a Partnership Security representing a fractional part of the Partnership Interests of all Limited Partners, and having the rights and obligations specified with respect to Class B Units in this Agreement.

Closing Date ” means the first date on which Common Units are sold by the Partnership to the Underwriters pursuant to the provisions of the Underwriting Agreement.

Closing Price ” has the meaning assigned to such term in Section 15.1(a).

Code ” means the Internal Revenue Code of 1986, as amended and in effect from time to time. Any reference herein to a specific section or sections of the Code shall be deemed to include a reference to any corresponding provision of successor law.

 

- 5 -


Combined Interest ” has the meaning assigned to such term in Section 11.3(a).

Commission ” means the United States Securities and Exchange Commission.

Common Unit ” means a Partnership Security representing a fractional part of the Partnership Interests of all Limited Partners, and having the rights and obligations specified with respect to Common Units in this Agreement.

Conflicts Committee ” means a committee of the Board of Directors of the General Partner composed entirely of one or more directors who are not (a) security holders, officers or employees of the General Partner, (b) officers, directors or employees of any Affiliate of the General Partner or (c) holders of any ownership interest in the Partnership other than Common Units, and who also meet the independence standards required to serve on an audit committee of a board of directors established by the Securities Exchange Act and the rules and regulations of the Commission thereunder by the National Securities Exchange on which the Common Units are listed or admitted for trading.

Contributed Property ” means each property or other asset, in such form as may be permitted by the Delaware Act, but excluding cash, contributed to the Partnership. Once the Carrying Value of a Contributed Property is adjusted pursuant to Section 5.6(d), such property shall no longer constitute a Contributed Property, but shall be deemed an Adjusted Property.

Conversion Notice ” has the meaning assigned to such term in Section 5.7(a).

Curative Allocation ” means any allocation of an item of income, gain, deduction, loss or credit pursuant to the provisions of Section 6.1(d)(xi).

Current Market Price ” has the meaning assigned to such term in Section 15.1(a).

Delaware Act ” means the Delaware Revised Uniform Limited Partnership Act, 6 Del C. § 17-101, et seq., as amended, supplemented or restated from time to time, and any successor to such statute.

Departing General Partner ” means a former General Partner from and after the effective date of any withdrawal or removal of such former General Partner pursuant to Section 11.1 or Section 11.2.

Depositary ” means, with respect to any Units issued in global form, The Depository Trust Company and its successors and permitted assigns.

Economic Risk of Loss ” has the meaning set forth in Treasury Regulation Section 1.752-2(a).

Effective Time ” means the time at which the Certificate of Conversion has been filed with the Secretary of State of the State of Delaware.

 

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Eligible Holder ” means a Person either (a) subject to United States federal income taxation on the income generated by the Partnership or (b) in the case of entities that are pass through entities for United States federal income taxation, all of whose beneficial owners are subject to United States federal income taxation on the income generated by the Partnership. Schedule I to the Transfer Application provides examples of Persons that are and Persons that are not Eligible Holders.

Event of Withdrawal ” has the meaning assigned to such term in Section 11.1(a).

FERC ” means the Federal Energy Regulatory Commission.

FERC Notice ” means the giving of notice by the Partnership to the Limited Partners in the manner specified in Section 17.1 hereof at any time after the Partnership becomes the owner, either directly or through any Subsidiary, of any pipeline subject to rate regulation by FERC.

General Partner ” means LE GP, LLC, a Delaware limited liability company and its successors and permitted assigns that are admitted to the Partnership as general partner of the Partnership (except as the context otherwise requires).

General Partner Interest ” means the ownership interest, if any, of the General Partner in the Partnership (in its capacity as a general partner without reference to any Limited Partner Interest held by it), which is evidenced by General Partner Units, and includes any and all benefits to which a General Partner is entitled as provided in this Agreement, together with all obligations of a General Partner to comply with the terms and provisions of this Agreement.

General Partner Unit ” means a fractional part of the General Partner Interest having the rights and obligations specified with respect to the General Partner Interest. A General Partner Unit is not a Unit.

Group ” means a Person that, with or through any of its Affiliates or Associates, has any agreement, arrangement or understanding for the purpose of acquiring, holding, voting (except voting pursuant to a revocable proxy or consent given to such Person in response to a proxy or consent solicitation made to 10 or more Persons), exercising investment power or disposing of any Partnership Securities with any other Person that beneficially owns, or whose Affiliates or Associates beneficially own, directly or indirectly, Partnership Interests.

Group Member ” means a member of the Partnership Group.

Indemnitee ” means (a) the General Partner, (b) any Departing General Partner, (c) any Person who is or was an Affiliate of the General Partner or any Departing General Partner, (d) any Person who is or was a member, partner, officer, director, fiduciary or trustee of any Group Member, the General Partner or any Departing General Partner or any Affiliate of any Group Member, the General Partner or any Departing General Partner, (e) any Person who is or was serving at the request of the General Partner or any Departing General Partner or any Affiliate of the General Partner or any Departing General Partner as an officer, director, employee, member, partner, agent, fiduciary or trustee of another Person; provided, that a Person shall not be an Indemnitee by reason of providing, on a fee-for-services basis, trustee, fiduciary or custodial services and (f) any Person the General Partner designates as an “ Indemnitee ” for purposes of this Agreement.

 

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Ineligible Assignee ” means a Person whom the General Partner has determined is not an Eligible Holder following a FERC Notice.

Initial Class B Holder ” means FEM, L.P., a Delaware limited partnership.

“Initial Common Unit” means the Common Units sold in the Initial Offering.

Initial Limited Partners ” means the Persons listed on Exhibit D hereto.

Initial Offering ” means the initial offering and sale of Common Units to the public, as described in the Registration Statement.

“ “ Issue Price ” means the price at which a Unit is purchased from the Partnership, after taking into account any sales commission or underwriting discount charged to the Partnership.

Limited Partner ” means, unless the context otherwise requires, (a) each Initial Limited Partner, each Limited Partner, each Substituted Limited Partner, each Additional Limited Partner and any Departing General Partner upon the change of its status from General Partner to Limited Partner pursuant to Section 11.3, in each case, in such Person’s capacity as a limited partner of the Partnership or (b) solely for purposes of Articles V, VI, VII, IX and XII, each Assignee.

Limited Partner Interest ” means the ownership interest of a Limited Partner or Assignee in the Partnership, which may be evidenced by Common Units, Class B Units or other Partnership Securities or a combination thereof or interest therein, and includes any and all benefits to which such Limited Partner or Assignee is entitled as provided in this Agreement, together with all obligations of such Limited Partner or Assignee to comply with the terms and provisions of this Agreement.

Liquidation Date ” means (a) in the case of an event giving rise to the dissolution of the Partnership of the type described in clauses (a) and (b) of the first sentence of Section 12.2, the date on which the applicable time period during which the holders of Outstanding Units have the right to elect to continue the business of the Partnership has expired without such an election being made, and (b) in the case of any other event giving rise to the dissolution of the Partnership, the date on which such event occurs.

Liquidator ” means one or more Persons selected by the General Partner to perform the functions described in Section 12.3 as liquidating trustee of the Partnership within the meaning of the Delaware Act.

Merger Agreement ” has the meaning assigned to such term in Section 14.1.

MLP ” means Energy Transfer Partners, L.P., a Delaware limited partnership, and any successors thereto.

“MLP Agreement ” means the Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., as it may be amended, supplemented or restated from time to time.

 

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National Securities Exchange ” means an exchange registered with the Commission under Section 6(a) of the Securities Exchange Act, and any successor to such statute, or the Nasdaq National Market or any successor thereto.

Net Agreed Value ” means, (a) in the case of any Contributed Property, the Agreed Value of such property reduced by any liabilities either assumed by the Partnership upon such contribution or to which such property is subject when contributed, and (b) in the case of any property distributed to a Partner or Assignee by the Partnership, the Partnership’s Carrying Value of such property (as adjusted pursuant to Section 5.6(d)(ii)) at the time such property is distributed, reduced by any indebtedness either assumed by such Partner upon such distribution or to which such property is subject at the time of distribution, in either case, as determined under Section 752 of the Code.

Net Income ” means, for any taxable year, the excess, if any, of the Partnership’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year over the Partnership’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year. The items included in the calculation of Net Income shall be determined in accordance with Section 5.6(b) and shall not include any items specially allocated under Section 6.1(d); provided that the determination of the items that have been specially allocated under Section 6.1(d) shall be made as if Section 6.1(d) were not in this Agreement.

Net Loss ” means, for any taxable year, the excess, if any, of the Partnership’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year over the Partnership’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year. The items included in the calculation of Net Loss shall be determined in accordance with Section 5.6(b) and shall not include any items specially allocated under Section 6.1(d); provided that the determination of the items that have been specially allocated under Section 6.1(d) shall be made as if Section 6.1(d) were not in this Agreement.

Net Positive Adjustments ” means, with respect to any Partner, the excess, if any, of the total positive adjustments over the total negative adjustments made to the Capital Account of such Partner pursuant to Book-Up Events and Book-Down Events.

Net Termination Gain ” means, for any taxable year, the sum, if positive, of all items of income, gain, loss or deduction recognized by the Partnership after the Liquidation Date. The items included in the determination of Net Termination Gain shall be determined in accordance with Section 5.6(b) and shall not include any items of income, gain, loss or deduction specially allocated under Section 6.1(d).

Net Termination Loss ” means, for any taxable year, the sum, if negative, of all items of income, gain, loss or deduction recognized by the Partnership after the Liquidation Date. The items included in the determination of Net Termination Loss shall be determined in accordance with Section 5.6(b) and shall not include any items of income, gain, loss or deduction specially allocated under Section 6.1(d).

 

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Nonrecourse Built-in Gain ” means with respect to any Contributed Properties or Adjusted Properties that are subject to a mortgage or pledge securing a Nonrecourse Liability, the amount of any taxable gain that would be allocated to the Partners pursuant to Sections 6.2(b)(i)(A), 6.2(b)(ii)(A) and 6.2(b)(iii) if such properties were disposed of in a taxable transaction in full satisfaction of such liabilities and for no other consideration.

Nonrecourse Deductions ” means any and all items of loss, deduction or expenditure (including, without limitation, any expenditure described in Section 705(a)(2)(B) of the Code) that, in accordance with the principles of Treasury Regulation Section 1.704-2(b), are attributable to a Nonrecourse Liability.

Nonrecourse Liability ” has the meaning set forth in Treasury Regulation Section 1.752-1(a)(2).

Notice of Election to Purchase ” has the meaning assigned to such term in Section 15.1(b).

Opinion of Counsel ” means a written opinion of counsel (who may be regular counsel to the Partnership or the General Partner or any of its Affiliates) in a form acceptable to the General Partner.

Option Closing Date ” means the date or dates on which any Common Units are sold by the Partnership to the Underwriters upon exercise of the Over-Allotment Option.

Outstanding ” means, with respect to Partnership Securities, all Partnership Securities that are issued by the Partnership and reflected as outstanding on the Partnership’s books and records as of the date of determination; provided, however, that if at any time any Person or Group (other than the General Partner or its Affiliates) beneficially owns 20% or more of any Outstanding Partnership Securities of any class then Outstanding, all Partnership Securities owned by such Person or Group shall not be voted on any matter and shall not be considered to be Outstanding when sending notices of a meeting of Limited Partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under this Agreement, except that Common Units so owned shall be considered to be Outstanding for purposes of Section 11.1(b)(iv) (such Common Units shall not, however, be treated as a separate class of Partnership Securities for purposes of this Agreement); provided, further, that the foregoing limitation shall not apply (i) to any Person or Group who acquired 20% or more of any Outstanding Partnership Securities of any class then Outstanding directly from the General Partner or its Affiliates, (ii) to any Person or Group who acquired 20% or more of any Outstanding Partnership Securities of any class then Outstanding directly or indirectly from a Person or Group described in clause (i) provided that the General Partner shall have notified such Person or Group in writing that such limitation shall not apply or (iii) to any Person or Group who acquired 20% or more of any Partnership Securities issued by the Partnership with the prior approval of the Board of Directors of the General Partner.

 

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Over-Allotment Option ” means the over-allotment option granted to the Underwriters by the Partnership pursuant to the Underwriting Agreement.

Partner Nonrecourse Debt ” has the meaning set forth in Treasury Regulation Section 1.704-2(b)(4).

Partner Nonrecourse Debt Minimum Gain ” has the meaning set forth in Treasury Regulation Section 1.704-2(i)(2).

Partner Nonrecourse Deductions ” means any and all items of loss, deduction or expenditure (including, without limitation, any expenditure described in Section 705(a)(2)(B) of the Code) that, in accordance with the principles of Treasury Regulation Section 1.704-2(i), are attributable to a Partner Nonrecourse Debt.

Partners ” means the General Partner and the Limited Partners.

Partnership ” means Energy Transfer Equity, L.P., a Delaware limited partnership.

Partnership Group ” means the Partnership and its Subsidiaries treated as a single consolidated entity.

Partnership Interest ” means an interest in the Partnership, which shall include the General Partner Interests and Limited Partner Interests.

Partnership Minimum Gain ” means that amount determined in accordance with the principles of Treasury Regulation Section 1.704-2(d).

Partnership Security ” means any class or series of equity interest in the Partnership (but excluding any options, rights, warrants and appreciation rights relating to an equity interest in the Partnership) and General Partner Units and any General Partner Interest represented thereby, including without limitation, Common Units and Class B Units.

Per Unit Capital Amount ” means, as of any date of determination, the Capital Account, stated on a per Unit basis, underlying any Unit held by a Person other than the General Partner or any Affiliate of the General Partner who holds Units.

Percentage Interest ” means, as of any date of determination, (a) as to the General Partner, the amount of its aggregate Capital Contributions to the Partnership divided by the aggregate Capital Contributions made to the Partnership by all Partners, (b) as to any Unitholder holding Units, the product obtained by multiplying (i) 100% less the percentage applicable to paragraphs (a) and (c) by (ii) the quotient obtained by dividing (A) the number of Units held by such Unitholder by (B) the total number of all Outstanding Units, and (c) as to the holders of additional Partnership Securities issued by the Partnership in accordance with Section 5.8, the percentage established as a part of such issuance.

Person ” means an individual or a corporation, limited liability company, partnership, joint venture, trust, unincorporated organization, association, government agency or political subdivision thereof or other entity.

 

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Pro Rata ” means (a) when modifying Units or any class thereof, apportioned equally among all designated Units in accordance with their relative Percentage Interests, and (b) when used with respect to Partners and Assignees, apportioned among all Partners and Assignees, as the case may be, in accordance with their relative Percentage Interests.

Purchase Date ” means the date determined by the General Partner as the date for purchase of all Outstanding Units of a certain class (other than Units owned by the General Partner and its Affiliates) pursuant to Article XV.

Quarter ” means, unless the context requires otherwise, a fiscal quarter of the Partnership, or with respect to the first fiscal quarter of the Partnership after the Closing Date the portion of such fiscal quarter after the Closing Date.

Recapture Income ” means any gain recognized by the Partnership (computed without regard to any adjustment required by Section 734 or Section 743 of the Code) upon the disposition of any property or asset of the Partnership, which gain is characterized as ordinary income because it represents the recapture of deductions previously taken with respect to such property or asset.

Record Date ” means the date established by the General Partner for determining (a) the identity of the Record Holders entitled to notice of, or to vote at, any meeting of Limited Partners or entitled to vote by ballot or give approval of Partnership action in writing without a meeting or entitled to exercise rights in respect of any lawful action of Limited Partners or (b) the identity of Record Holders entitled to receive any report or distribution or to participate in any offer.

Record Holder ” means the Person in whose name a Common Unit is registered on the books of the Transfer Agent as of the opening of business on a particular Business Day, or with respect to other Partnership Interests, the Person in whose name any such other Partnership Interest is registered on the books that the General Partner has caused to be kept as of the opening of business on such Business Day.

Redeemable Interests ” means any Partnership Interests for which a redemption notice has been given, and has not been withdrawn, pursuant to Section 4.9.

Registration Statement ” means the Registration Statement on Form S-1 (Registration No. 333-128097) as it has been or as it may be amended or supplemented from time to time, filed by the Partnership with the Commission under the Securities Act to register the offering and sale of the Common Units in the Initial Offering.

Remaining Net Positive Adjustments ” means as of the end of any taxable period, (i) with respect to the Unitholders holding Common Units or Class B Units, the excess of (a) the Net Positive Adjustments of the Unitholders holding Common Units or Class B Units, as of the end of such period over (b) the sum of those Partners’ Share of Additional Book Basis Derivative Items for each prior taxable period, and (ii) with respect to the General Partner (as holder of the General Partner Units), the excess of (a) the Net Positive Adjustments of the General Partner as of the end of such period over (b) the sum of the General Partner’s Share of Additional Book Basis Derivative Items with respect to the General Partner Units for each prior taxable period.

 

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Required Allocations ” means (a) any limitation imposed on any allocation of Net Losses or Net Termination Losses under Section 6.1(b) or Section 6.1(c)(ii) and (b) any allocation of an item of income, gain, loss or deduction pursuant to Section 6.1(d)(i), Section 6.1(d)(ii), Section 6.1(d)(iv), Section 6.1(d)(vii) or Section 6.1(d)(ix).

Residual Gain ” or “ Residual Loss ” means any item of gain or loss, as the case may be, of the Partnership recognized for federal income tax purposes resulting from a sale, exchange or other disposition of a Contributed Property or Adjusted Property, to the extent such item of gain or loss is not allocated pursuant to Section 6.2(b)(i)(A) or Section 6.2(b)(ii)(A), respectively, to eliminate Book-Tax Disparities.

Securities Act ” means the Securities Act of 1933, as amended, supplemented or restated from time to time and any successor to such statute.

Securities Exchange Act ” means the Securities Exchange Act of 1934, as amended, supplemented or restated from time to time and any successor to such statute.

Share of Additional Book Basis Derivative Items ” means in connection with any allocation of Additional Book Basis Derivative Items for any taxable period, (i) with respect to the Unitholders holding Common Units or Class B Units, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Unitholders’ Remaining Net Positive Adjustments as of the end of such period bears to the Aggregate Remaining Net Positive Adjustments as of that time and (ii) with respect to the General Partner (as holder of the General Partner Units), the amount that bears the same ratio to such Additional Book Basis Derivative Items as the General Partner’s Remaining Net Positive Adjustments as of the end of such period bears to the Aggregate Remaining Net Positive Adjustment as of that time.

Special Approval ” means approval by the sole member or by a majority of the members of the Conflicts Committee, as applicable.

Subsidiary ” means, with respect to any Person, (a) a corporation of which more than 50% of the voting power of shares entitled (without regard to the occurrence of any contingency) to vote in the election of directors or other governing body of such corporation is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person or a combination thereof, (b) a partnership (whether general or limited) in which such Person or a Subsidiary of such Person is, at the date of determination, a general or limited partner of such partnership, but only if more than 50% of the partnership interests of such partnership (considering all of the partnership interests of the partnership as a single class) is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person, or a combination thereof, or (c) any other Person (other than a corporation or a partnership) in which such Person, one or more Subsidiaries of such Person, or a combination thereof, directly or indirectly, at the date of determination, has (i) at least a majority ownership interest or (ii) the power to elect or direct the election of a majority of the directors or other governing body of such Person.

 

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Substituted Limited Partner ” means a Person who is admitted as a Limited Partner to the Partnership pursuant to Section 10.1 in place of and with all the rights of a Limited Partner and who is shown as a Limited Partner on the books and records of the Partnership.

Surviving Business Entity ” has the meaning assigned to such term in Section 14.2(b).

Taxation Certification ” means a properly completed certificate in such form or forms as may be specified by the General Partner by which a Limited Partner certifies that he (and if he is a nominee holding for the account of another Person, that to the best of his knowledge such other Person) is an Eligible Holder. A certification in the form specified in Annex A to the Transfer Application shall be considered a Taxation Certification unless the General Partner amends the form thereof pursuant to Section 13.1 hereof.

Trading Day ” has the meaning assigned to such term in Section 15.1(a).

transfer ” has the meaning assigned to such term in Section 4.4(a).

Transfer Agent ” means such bank, trust company or other Person (including the General Partner or one of its Affiliates) as shall be appointed from time to time by the Partnership to act as registrar and transfer agent for the Common Units; provided that if no Transfer Agent is specifically designated for any other Partnership Securities, the General Partner shall act in such capacity.

Transfer Application ” means the Transfer Application in the form attached hereto as Exhibit C.

Underwriter ” means each Person named as an underwriter in Schedule I to the Underwriting Agreement who purchases Common Units pursuant thereto.

Underwriting Agreement ” means the Underwriting Agreement dated February 2, 2006 among the Underwriters, the Partnership and certain other parties, providing for the purchase of Common Units by such Underwriters.

Unit ” means a Partnership Security that is designated as a “ Unit ” and shall include Common Units and Class B Units but shall not include General Partner Units (or the General Partner Interest represented thereby).

Unit Majority ” means at least a majority of the Outstanding Common Units and Outstanding Class B Units, if applicable, voting together as a single class.

Unitholders ” means the holders of Units.

Unrealized Gain ” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the fair market value of such property as of such date (as determined under Section 5.6(d)) over (b) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.6(d) as of such date).

 

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Unrealized Loss ” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.6(d) as of such date) over (b) the fair market value of such property as of such date (as determined under Section 5.6(d)).

U.S. GAAP ” means United States generally accepted accounting principles consistently applied.

Withdrawal Opinion of Counsel ” has the meaning assigned to such term in Section 11.1(b).

Section 1.2 Construction.

Unless the context requires otherwise: (a) any pronoun used in this Agreement shall include the corresponding masculine, feminine or neuter forms, and the singular form of nouns, pronouns and verbs shall include the plural and vice versa; (b) references to Articles and Sections refer to Articles and Sections of this Agreement; and (c) the term “ include ” or “ includes ” means includes “ including ” or words of like import shall be deemed to be followed by the words “ without limitation ;” and the terms “ hereof,” “ herein ” or “ hereunder ” refer to this Agreement as a whole and not to any particular provision of this Agreement. The table of contents and headings contained in this Agreement are for reference purposes only, and shall not affect in any way the meaning or interpretation of this Agreement.

ARTICLE II

ORGANIZATION

Section 2.1 Formation.

The Partnership was formed as of the Effective Time pursuant to the Certificate of Conversion and the Certificate of Limited Partnership converting Energy Transfer Company, L.P., a Texas limited partnership, into the Partnership, a Delaware limited partnership. Except as expressly provided to the contrary in this Agreement, the rights, duties (including fiduciary duties), liabilities and obligations of the Partners and the administration, dissolution and termination of the Partnership shall be governed by the Delaware Act. All Partnership Interests shall constitute personal property of the owner thereof for all purposes.

Section 2.2 Name.

The name of the Partnership shall be “ Energy Transfer Equity, L.P. ” The Partnership’s business may be conducted under any other name or names as determined by the General Partner, including the name of the General Partner. The words “ Limited Partnership,” “ LP,” “ Ltd. ” or similar words or letters shall be included in the Partnership’s name where necessary for the purpose of complying with the laws of any jurisdiction that so requires. The General Partner may change the name of the Partnership at any time and from time to time and shall notify the Limited Partners of such change in the next regular communication to the Limited Partners.

 

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Section 2.3 Registered Office; Registered Agent; Principal Office; Other Offices.

Unless and until changed by the General Partner, the registered office of the Partnership in the State of Delaware shall be located at 1209 Orange Street, Suite 400, Wilmington, Delaware 19801, and the registered agent for service of process on the Partnership in the State of Delaware at such registered office shall be The Corporation Trust Company. The principal office of the Partnership shall be located at 2828 Woodside Street, Dallas, Texas 75204 or such other place as the General Partner may from time to time designate by notice to the Limited Partners. The Partnership may maintain offices at such other place or places within or outside the State of Delaware as the General Partner deems necessary or appropriate. The address of the General Partner shall be 2828 Woodside Street, Dallas, Texas 75204 or such other place as the General Partner may from time to time designate by notice to the Limited Partners.

Section 2.4 Purpose and Business.

The purpose and nature of the business to be conducted by the Partnership shall be to (a) engage directly in, or enter into or form any corporation, partnership, joint venture, limited liability company or other arrangement to engage indirectly in, any business activity that is approved by the General Partner and that lawfully may be conducted by a limited partnership organized pursuant to the Delaware Act and, in connection therewith, to exercise all of the rights and powers conferred upon the Partnership pursuant to the agreements relating to such business activity; and (b) do anything necessary or appropriate to the foregoing, including the making of capital contributions or loans to a Group Member, provided, however, that the General Partner shall not cause the Partnership to engage, directly or indirectly, in any business activity that the General Partner determines would cause the Partnership to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes. To the maximum extent permitted by law, the General Partner shall have no duty or obligation to propose or approve, and may decline to propose or approve, the conduct by the Partnership of any business, free of any fiduciary duty or obligation whatsoever to the Partnership or any Limited Partner and, in declining to so propose or approve, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity.

Section 2.5 Powers.

The Partnership shall be empowered to do any and all acts and things necessary, appropriate, proper, advisable, incidental to or convenient for the furtherance and accomplishment of the purposes and business described in Section 2.4 and for the protection and benefit of the Partnership.

 

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Section 2.6 Power of Attorney.

(a) Each Limited Partner hereby constitutes and appoints the General Partner and, if a Liquidator (other than the General Partner) shall have been selected pursuant to Section 12.3, the Liquidator, severally (and any successor to either thereof by merger, transfer, assignment, election or otherwise) and each of their authorized officers and attorneys-in-fact, as the case may be, with full power of substitution, as his true and lawful agent and attorney-in-fact, with full power and authority in his name, place and stead, to:

(i) execute, swear to, acknowledge, deliver, file and record in the appropriate public offices (A) all certificates, documents and other instruments (including this Agreement and the Certificate of Limited Partnership and all amendments or restatements hereof or thereof) that the General Partner or the Liquidator determines to be necessary or appropriate to form, qualify or continue the existence or qualification of the Partnership as a limited partnership (or a partnership in which the limited partners have limited liability) in the State of Delaware and in all other jurisdictions in which the Partnership may conduct business or own property; (B) all certificates, documents and other instruments that the General Partner or the Liquidator determines to be necessary or appropriate to reflect, in accordance with its terms, any amendment, change, modification or restatement of this Agreement; (C) all certificates, documents and other instruments (including conveyances and a certificate of cancellation) that the General Partner or the Liquidator determines to be necessary or appropriate to reflect the dissolution and liquidation of the Partnership pursuant to the terms of this Agreement; (D) all certificates, documents and other instruments relating to the admission, withdrawal, removal or substitution of any Partner pursuant to, or other events described in, Article IV, X, XI or XII; (E) all certificates, documents and other instruments relating to the determination of the rights, preferences and privileges of any class or series of Partnership Securities issued pursuant to Section 5.8; and (F) all certificates, documents and other instruments (including agreements and a certificate of merger) relating to a merger, consolidation or conversion of the Partnership pursuant to Article XIV; and

(ii) execute, swear to, acknowledge, deliver, file and record all ballots, consents, approvals, waivers, certificates, documents and other instruments that the General Partner or the Liquidator determines to be necessary or appropriate to (A) make, evidence, give, confirm or ratify any vote, consent, approval, agreement or other action that is made or given by the Partners hereunder or is consistent with the terms of this Agreement or (B) effectuate the terms or intent of this Agreement; provided, that when required by Section 13.3 or any other provision of this Agreement that establishes a percentage of the Limited Partners or of the Limited Partners of any class or series required to take any action, the General Partner and the Liquidator may exercise the power of attorney made in this Section 2.6(a)(ii) only after the necessary vote, consent or approval of the Limited Partners or of the Limited Partners of such class or series, as applicable.

Nothing contained in this Section 2.6(a) shall be construed as authorizing the General Partner to amend this Agreement except in accordance with Article XIII or as may be otherwise expressly provided for in this Agreement.

(b) The foregoing power of attorney is hereby declared to be irrevocable and a power coupled with an interest, and it shall survive and, to the maximum extent permitted by law, not be affected by the subsequent death, incompetency, disability, incapacity, dissolution, bankruptcy or termination of any Limited Partner and the transfer of all or any portion of such Limited Partner’s Partnership Interest and shall extend to such Limited Partner’s heirs, successors, assigns and personal representatives. Each such Limited Partner hereby agrees to be bound by any representation made by the General Partner or the Liquidator acting in good faith pursuant to such power of attorney; and each such Limited Partner, to the maximum extent permitted by law, hereby waives any and all defenses that may be available to contest, negate or disaffirm the action of the General Partner or the Liquidator taken in good faith under such power of attorney. Each Limited Partner shall execute and deliver to the General Partner or the Liquidator, within 15 days after receipt of the request therefor, such further designation, powers of attorney and other instruments as the General Partner or the Liquidator may request in order to effectuate this Agreement and the purposes of the Partnership.

 

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Section 2.7 Term.

The term of the Partnership commenced upon the filing of the Certificate of Conversion and the Certificate of Limited Partnership in accordance with the Delaware Act and shall continue in existence until the dissolution of the Partnership in accordance with the provisions of Article XII. The existence of the Partnership as a separate legal entity shall continue until the cancellation of the Certificate of Conversion and the Certificate of Limited Partnership as provided in the Delaware Act.

Section 2.8 Title to Partnership Assets.

Title to Partnership assets, whether real, personal or mixed and whether tangible or intangible, shall be deemed to be owned by the Partnership as an entity, and no Partner, individually or collectively, shall have any ownership interest in such Partnership assets or any portion thereof. Title to any or all of the Partnership assets may be held in the name of the Partnership, the General Partner, one or more of its Affiliates or one or more nominees, as the General Partner may determine. The General Partner hereby declares and warrants that any Partnership assets for which record title is held in the name of the General Partner or one or more of its Affiliates or one or more nominees shall be held by the General Partner or such Affiliate or nominee for the use and benefit of the Partnership in accordance with the provisions of this Agreement; provided, however, that the General Partner shall use reasonable efforts to cause record title to such assets (other than those assets in respect of which the General Partner determines that the expense and difficulty of conveyancing makes transfer of record title to the Partnership impracticable) to be vested in the Partnership as soon as reasonably practicable; provided, further, that, prior to the withdrawal or removal of the General Partner or as soon thereafter as practicable, the General Partner shall use reasonable efforts to effect the transfer to the Partnership of record title to all Partnership assets held by the General Partner or its Affiliates and, prior to any such transfer, will provide for the use of such assets in a manner satisfactory to the General Partner. All Partnership assets shall be recorded as the property of the Partnership in its books and records, irrespective of the name in which record title to such Partnership assets is held.

ARTICLE III

RIGHTS OF LIMITED PARTNERS

Section 3.1 Limitation of Liability.

The Limited Partners shall have no liability under this Agreement except as expressly provided in this Agreement or the Delaware Act.

 

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Section 3.2 Management of Business.

No Limited Partner or Assignee, in its capacity as such, shall participate in the operation, management or control (within the meaning of the Delaware Act) of the Partnership’s business, transact any business in the Partnership’s name or have the power to sign documents for or otherwise bind the Partnership. Any action taken by any Affiliate of the General Partner or any officer, director, employee, manager, member, general partner, agent or trustee of the General Partner or any of its Affiliates, or any officer, director, employee, manager, member, general partner, agent or trustee of a Group Member, in its capacity as such, shall not be deemed to be participation in the control of the business of the Partnership by a limited partner of the Partnership (within the meaning of Section 17-303(a) of the Delaware Act) and shall not affect, impair or eliminate the limitations on the liability of the Limited Partners or Assignees under this Agreement.

Section 3.3 Outside Activities of the Limited Partners.

Subject to the provisions of Section 7.5, which shall continue to be applicable to the Persons referred to therein, regardless of whether such Persons shall also be Limited Partners, any Limited Partner or Assignee shall be entitled to and may have business interests and engage in business activities in addition to those relating to the Partnership, including business interests and activities in direct competition with the Partnership. Neither the Partnership nor any of the other Partners or Assignees shall have any rights by virtue of this Agreement in any business ventures of any Limited Partner or Assignee.

Section 3.4 Rights of Limited Partners.

(a) In addition to other rights provided by this Agreement or by applicable law, and except as limited by Section 3.4(b), each Limited Partner shall have the right, for a purpose reasonably related to such Limited Partner’s interest as a Limited Partner in the Partnership, upon reasonable written demand stating the purpose of such demand and at such Limited Partner’s own expense:

(i) to obtain true and full information regarding the status of the business and financial condition of the Partnership;

(ii) promptly after its becoming available, to obtain a copy of the Partnership’s federal, state and local income tax returns for each year;

(iii) to obtain a current list of the name and last known business, residence or mailing address of each Partner;

(iv) to obtain a copy of this Agreement and the Certificate of Limited Partnership and all amendments thereto, together with a copy of the executed copies of all powers of attorney pursuant to which this Agreement, the Certificate of Limited Partnership and all amendments thereto have been executed;

(v) to obtain true and full information regarding the amount of cash and a description and statement of the Net Agreed Value of any other Capital Contribution by each Partner and that each Partner has agreed to contribute in the future, and the date on which each became a Partner; and

 

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(vi) to obtain such other information regarding the affairs of the Partnership as is just and reasonable.

(b) Notwithstanding any other provision of this Agreement, the General Partner may keep confidential from the Limited Partners, for such period of time as the General Partner determines, (i) any information that the General Partner reasonably believes to be in the nature of trade secrets or (ii) other information the disclosure of which the General Partner believes (A) is not in the best interests of the Partnership, (B) could damage the Partnership or its business or (C) that any Group Member is required by law or by agreement with any third party to keep confidential (other than agreements with Affiliates of the Partnership the primary purpose of which is to circumvent the obligations set forth in this Section 3.4).

ARTICLE IV

CERTIFICATES; RECORD HOLDERS; TRANSFER OF PARTNERSHIP INTERESTS;

REDEMPTION OF PARTNERSHIP INTERESTS

Section 4.1 Certificates.

Upon the Partnership’s issuance of Common Units or Class B Units to any Person, the Partnership shall issue, upon the request of such Person, one or more Certificates in the name of such Person evidencing the number of such Units being so issued. In addition, (a) upon the General Partner’s request, the Partnership shall issue to it one or more Certificates in the name of the General Partner evidencing its interests in the Partnership and (b) upon the request of any Person owning other Partnership Securities, the Partnership shall issue to such Person one or more Certificates evidencing such other Partnership Securities. Certificates shall be executed on behalf of the Partnership by the Chairman of the Board, President or any Vice President and the Secretary or any Assistant Secretary of the General Partner. No Common Unit Certificate shall be valid for any purpose until it has been countersigned by the Transfer Agent; provided, however, that if the General Partner elects to issue Common Units in global form, the Common Unit Certificates shall be valid upon receipt of a certificate from the Transfer Agent certifying that the Common Units have been duly registered in accordance with the directions of the Partnership. Subject to the requirements of Section 6.4(b), the Partners holding Certificates evidencing Class B Units may exchange such Certificates evidencing Common Units on or after the date on which such Class B Units are converted into Common Units pursuant to the terms of Section 5.7.

Section 4.2 Mutilated, Destroyed, Lost or Stolen Certificates.

(a) If any mutilated Certificate is surrendered to the Transfer Agent (for Common Units) or the General Partner (for Partnership Securities other than Common Units), the appropriate officers of the General Partner on behalf of the Partnership shall execute, and the Transfer Agent (for Common Units) or the Partnership (for Partnership Securities other than Common Units) shall countersign and deliver in exchange therefor, a new Certificate evidencing the same number and type of Partnership Securities as the Certificate so surrendered.

 

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(b) The appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and the Transfer Agent (for Common Units) or the Partnership (for Partnership Securities other than Common Units) shall countersign, a new Certificate in place of any Certificate previously issued if the Record Holder of the Certificate:

(i) makes proof by affidavit, in form and substance satisfactory to the General Partner, that a previously issued Certificate has been lost, destroyed or stolen;

(ii) requests the issuance of a new Certificate before the General Partner has notice that the Certificate has been acquired by a purchaser for value in good faith and without notice of an adverse claim;

(iii) if requested by the General Partner, delivers to the General Partner a bond, in form and substance satisfactory to the General Partner, with surety or sureties and with fixed or open penalty as the General Partner may direct to indemnify the Partnership, the Partners, the General Partner and the Transfer Agent against any claim that may be made on account of the alleged loss, destruction or theft of the Certificate; and

(iv) satisfies any other reasonable requirements imposed by the General Partner.

(c) If a Limited Partner or Assignee fails to notify the General Partner within a reasonable period of time after he has notice of the loss, destruction or theft of a Certificate, and a transfer of the Limited Partner Interests represented by the Certificate is registered before the Partnership, the General Partner or the Transfer Agent receives such notification, the Limited Partner or Assignee shall be precluded from making any claim against the Partnership, the General Partner or the Transfer Agent for such transfer or for a new Certificate.

(d) As a condition to the issuance of any new Certificate under this Section 4.2, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in relation thereto and any other expenses (including the fees and expenses of the Transfer Agent) reasonably connected therewith.

Section 4.3 Record Holders.

The Partnership shall be entitled to recognize the Record Holder as the Partner or Assignee with respect to any Partnership Interest and, accordingly, shall not be bound to recognize any equitable or other claim to or interest in such Partnership Interest on the part of any other Person, regardless of whether the Partnership shall have actual or other notice thereof, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which such Partnership Interests are listed or admitted for trading. Without limiting the foregoing, when a Person (such as a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing) is acting as nominee, agent or in some other representative capacity for another Person in acquiring and/or holding Partnership Interests, as between the Partnership on the one hand, and such other Persons on the other, such representative Person (a) shall be the Partner or Assignee (as the case may be) of record and beneficially, and (b) shall be bound by this Agreement and shall have the rights and obligations of a Partner or Assignee (as the case may be) hereunder and as, and to the extent provided for herein.

 

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Section 4.4 Transfer Generally.

(a) The term “ transfer,” when used in this Agreement with respect to a Partnership Interest, shall be deemed to refer to a transaction (i) by which the General Partner assigns its General Partner Interest to another Person, and includes a sale, assignment, gift, pledge, encumbrance, hypothecation, mortgage, exchange, or any other disposition by law or otherwise or (ii) by which the holder of a Limited Partner Interest assigns such Limited Partner Interest to another Person who is or becomes a Limited Partner or an Assignee, and includes a sale, assignment, gift, exchange or any other disposition by law or otherwise, including any transfer upon foreclosure of any pledge, encumbrance, hypothecation or mortgage.

(b) No Partnership Interest shall be transferred, in whole or in part, except in accordance with the terms and conditions set forth in this Article IV. Any transfer or purported transfer of a Partnership Interest not made in accordance with this Article IV shall be null and void.

(c) Nothing contained in this Agreement shall be construed to prevent a disposition by any stockholder, member, partner or other owner of the General Partner of any or all of the issued and outstanding member interests, partner interests or other ownership interests in the General Partner, including through a merger or consolidation of the General Partner.

Section 4.5 Registration and Transfer of Limited Partner Interests.

(a) The General Partner shall keep or cause to be kept on behalf of the Partnership a register in which, subject to such reasonable regulations as it may prescribe and subject to the provisions of Section 4.5(b), the Partnership will provide for the registration and transfer of Limited Partner Interests. The Transfer Agent is hereby appointed registrar and transfer agent for the purpose of registering Common Units and transfers of such Common Units as herein provided. The Partnership shall not recognize transfers of Certificates evidencing Limited Partner Interests unless such transfers are effected in the manner described in this Section 4.5. Upon surrender of a Certificate for registration of transfer of any Limited Partner Interests evidenced by a Certificate, and subject to the provisions of Section 4.5(b), the appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and in the case of Common Units, the Transfer Agent shall countersign and deliver, in the name of the holder or the designated transferee or transferees, as required pursuant to the holder’s instructions, one or more new Certificates evidencing the same aggregate number and type of Limited Partner Interests as was evidenced by the Certificate so surrendered.

(b) Except as otherwise provided in Section 4.8, the Partnership shall not recognize any transfer of Limited Partner Interests until (i) the Certificates evidencing such Limited Partner Interests are surrendered for registration of transfer and (ii) following a FERC Notice, such Certificates are accompanied by a Transfer Application and accompanying Taxation Certification, properly completed and duly executed by the transferee (or the transferee’s attorney-in-fact duly authorized in writing). No charge shall be imposed by the General Partner for such transfer; provided, that as a condition to the issuance of any new Certificate under this Section 4.5, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed with respect thereto. Following a FERC Notice, no distributions or allocations will be made in respect of the Limited Partner Interests until a properly completed Transfer Application has been delivered.

 

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(c) Limited Partner Interests may be transferred only in the manner described in this Section 4.5. The transfer of any Limited Partner Interests and the admission of any new Limited Partner shall not constitute an amendment to this Agreement.

(d) Until admitted as a Substituted Limited Partner pursuant to Section 10.1, the Record Holder of a Limited Partner Interest shall be an Assignee in respect of such Limited Partner Interest. Limited Partners may include custodians, nominees or any other individual or entity in its own or any representative capacity.

(e) Following a FERC Notice, a transferee of a Limited Partner Interest who has completed and delivered a Transfer Application shall be deemed to have (i) requested admission as a Substituted Limited Partner, (ii) agreed to comply with and be bound by and to have executed this Agreement, (iii) represented and warranted that such transferee has the right, power and authority and, if an individual, the capacity to enter into this Agreement, (iv) granted the powers of attorney set forth in this Agreement, and (v) given the consents and approvals and made the waivers contained in this Agreement.

(f) Prior to the conversion of Class B Units into Common Units pursuant to the terms of Section 5.7, Partners owning Class B Units may only transfer such Class B Units to one or more Persons in connection with estate planning or as otherwise may be approved by the General Partner.

(g) Subject to (i) the foregoing provisions of this Section 4.5, (ii) Section 4.3, (iii) Section 4.7, (iv) with respect to any series of Limited Partner Interests, the provisions of any statement of designations or amendment to this Agreement establishing such series, (v) any contractual provisions binding on any Limited Partner and (vi) provisions of applicable law including the Securities Act, Limited Partnership Interests shall be freely transferable.

Section 4.6 Transfer of the General Partner Interest.

(a) Subject to Section 4.6(c) below, prior to December 31, 2015, the General Partner shall not transfer all or any part of its General Partner Interest (represented by General Partner Units) to a Person unless such transfer (i) has been approved by the prior written consent or vote of the holders of at least a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates) or (ii) is of all, but not less than all, of its General Partner Interest (represented by General Partner Units) to (A) an Affiliate of the General Partner (other than an individual) or (B) another Person (other than an individual) in connection with the merger or consolidation of the General Partner with or into another Person (other than an individual) or the transfer by the General Partner of all or substantially all of its assets to another Person (other than an individual).

(b) Subject to Section 4.6(c) below, on or after December 31, 2015, the General Partner may transfer all or any of its General Partner Interest (represented by General Partner Units) without Unitholder approval.

 

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(c) Notwithstanding anything herein to the contrary, no transfer by the General Partner of all or any part of its General Partner Interest (represented by General Partner Units) to another Person shall be permitted unless (i) the transferee agrees to assume the rights and duties of the General Partner under this Agreement and to be bound by the provisions of this Agreement and (ii) the Partnership receives an Opinion of Counsel that such transfer would not result in the loss of limited liability under Delaware law of any Limited Partner or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed), (iii) such transferee also agrees to purchase all (or the appropriate portion thereof, if applicable) of the partnership or membership interest of the General Partner as the general partner or managing member, if any, of each other Group Member. In the case of a transfer pursuant to and in compliance with this Section 4.6, the transferee or successor (as the case may be) shall, subject to compliance with the terms of Section 10.2, be admitted to the Partnership as the General Partner immediately prior to the transfer of the General Partner Interest, and the business of the Partnership shall continue without dissolution.

Section 4.7 Restrictions on Transfers.

(a) Except as provided in Section 4.7(d) below, but notwithstanding the other provisions of this Article IV, no transfer of any Partnership Interests shall be made if such transfer would (i) violate the then applicable federal or state securities laws or rules and regulations of the Commission, any state securities commission or any other governmental authority with jurisdiction over such transfer, (ii) terminate the existence or qualification of the Partnership under the laws of the jurisdiction of its formation, or (iii) cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed).

(b) The General Partner may impose restrictions on the transfer of Partnership Interests if it receives an Opinion of Counsel that such restrictions are necessary to avoid a significant risk of the Partnership becoming taxable as a corporation or otherwise becoming taxable as an entity for federal income tax purposes. The General Partner may impose such restrictions by amending this Agreement; provided, however, that any amendment that would result in the delisting or suspension of trading of any class of Limited Partner Interests on the principal National Securities Exchange on which such class of Limited Partner Interests is then listed or admitted for trading must be approved, prior to such amendment being effected, by the holders of at least a majority of the Outstanding Limited Partner Interests of such class.

(c) The transfer of a Class B Unit that has converted into a Common Unit shall be subject to the restrictions imposed by Section 6.4(b).

(d) Nothing contained in this Article IV, or elsewhere in this Agreement, shall preclude the settlement of any transactions involving Partnership Interests entered into through the facilities of any National Securities Exchange on which such Partnership Interests are listed or admitted for trading.

 

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(e) Each certificate evidencing Partnership Interests shall bear a conspicuous legend in substantially the following form:

THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF ENERGY TRANSFER EQUITY, L.P. THAT THIS SECURITY MAY NOT BE SOLD, OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED IF SUCH TRANSFER WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF ENERGY TRANSFER EQUITY, L.P. UNDER THE LAWS OF THE STATE OF DELAWARE, OR (C) CAUSE ENERGY TRANSFER EQUITY, L.P. TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED). LE GP, LLC, THE GENERAL PARTNER OF ENERGY TRANSFER EQUITY, L.P., MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF ENERGY TRANSFER EQUITY, L.P. BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES. THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.

Section 4.8 Taxation Certifications; Ineligible Assignees.

(a) Following a FERC Notice, if a transferee of a Limited Partner Interest fails to furnish a properly completed Taxation Certification in the manner specified in Section 4.5(b) or if, upon receipt of such Taxation Certification or otherwise, the General Partner determines that such transferee is not an Eligible Holder, the Limited Partner Interests owned by such transferee shall be subject to redemption in accordance with the provisions of Section 4.9.

(b) Following a FERC Notice, the General Partner may request any Limited Partner or Assignee to furnish to the General Partner, within 30 days after receipt of such request, an executed Taxation Certification or such other information concerning his federal income tax status with respect to the income and loss generated by the Partnership (or, if the Limited Partner or Assignee is a nominee holding for the account of another Person, the federal income tax status of such Person) as the General Partner may reasonably request. If a Limited Partner or Assignee fails to furnish to the General Partner within the aforementioned 30-day period such Taxation Certification or other requested information or if upon receipt of such Taxation Certification or other requested information the General Partner determines that a Limited Partner or Assignee is not an Eligible Holder, the Limited Partner Interests owned by such Limited Partner or Assignee shall be subject to redemption in accordance with the provisions of Section 4.9. In addition, the General Partner may require that the status of any such Limited Partner or Assignee be changed to that of an Ineligible Assignee and, thereupon, the General Partner shall be substituted for such Ineligible Assignee as the Limited Partner in respect of the Ineligible Assignee’s Limited Partner Interests.

 

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(c) Following a FERC Notice, the General Partner shall, in exercising voting rights in respect of Limited Partner Interests held by it on behalf of Ineligible Assignees, distribute the votes in the same ratios as the votes of Partners (including without limitation the General Partner) in respect of Limited Partner Interests other than those of Ineligible Assignees are cast, either for, against or abstaining as to the matter.

(d) Upon dissolution of the Partnership, an Ineligible Assignee shall have no right to receive a distribution in kind pursuant to Section 12.4 but shall be entitled to the cash equivalent thereof, and the Partnership shall provide cash in exchange for an assignment of the Ineligible Assignee’s share of any distribution in kind. Such payment and assignment shall be treated for Partnership purposes as a purchase by the Partnership from the Ineligible Assignee of his Limited Partner Interest (representing his right to receive his share of such distribution in kind).

(e) At any time after an Ineligible Assignee can and does certify that it has become an Eligible Holder, such Ineligible Assignee may, upon application to the General Partner, request admission as a Substituted Limited Partner with respect to any Limited Partner Interests of such Ineligible Assignee not redeemed pursuant to Section 4.9, such Ineligible Assignee be admitted as a Limited Partner, and upon admission of such Ineligible Assignee pursuant to Section 10.2 the General Partner shall cease to be deemed to be the Limited Partner in respect of such Ineligible Assignee’s Limited Partner Interests.

Section 4.9 Redemption of Partnership Interests of Ineligible Assignees.

(a) If at any time following a FERC Notice, the General Partner determines that Limited Partners, Assignees and transferees of Limited Partner Interests that are not Eligible Holders own, in the aggregate, 15% or more of the Outstanding Units, the Partnership may redeem the Limited Partner Interest of any Limited Partner, Assignee or transferee of any Limited Partner, Assignee or transferee that has failed to furnish to the General Partner a Transfer Application and accompanying Taxation Certification pursuant to Section 4.5(b) or that has failed to furnish to the General Partner a Taxation Certification or other information requested within the 30-day period specified in Section 4.8(a), or if upon receipt of such Taxation Certification or other information the General Partner determines, with the advice of counsel, that a Limited Partner, Assignee or transferee is not an Eligible Holder, in accordance with the following procedures:

(i) The General Partner shall, not later than the 30th day before the date fixed for redemption, give notice of redemption to the Limited Partner, Assignee or transferee, at his last address designated on the records of the Partnership or the Transfer Agent, by registered or certified mail, postage prepaid. The notice shall be deemed to have been given when so mailed. The notice shall specify the Redeemable Interests, the date fixed for redemption, the place of payment, and that payment of the redemption price will be made upon surrender of the Certificate evidencing the Redeemable Interests.

 

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(ii) The aggregate redemption price for Redeemable Interests of a Limited Partner, Assignee or transferee shall be an amount equal to the Current Market Price (the date of determination of which shall be the date fixed for redemption) of Limited Partner Interests of the class to be so redeemed multiplied by the number of Limited Partner Interests of each such class included among the Redeemable Interests owned by such Limited Partner, Assignee or transferee. The redemption price shall be paid as determined by the General Partner, in cash or by delivery of a promissory note of the Partnership in the principal amount of the redemption price, bearing interest at the rate of 5% annually and payable in three equal annual installments of principal together with accrued interest, commencing one year after the redemption date.

(iii) Upon surrender by or on behalf of the Limited Partner, Assignee or transferee, at the place specified in the notice of redemption, of the Certificate evidencing the Redeemable Interests, duly endorsed in blank or accompanied by an assignment duly executed in blank, the Limited Partner, Assignee or transferee, or his duly authorized representative shall be entitled to receive the payment therefor.

(iv) After the redemption date, Redeemable Interests shall no longer constitute issued and Outstanding Limited Partner Interests.

(b) The provisions of this Section 4.9 shall also be applicable to Limited Partner Interests held by a Limited Partner or Assignee as nominee of a Person determined to be other than an Eligible Holder.

(c) Nothing in this Section 4.9 shall prevent the recipient of a notice of redemption from transferring his Limited Partner Interest before the redemption date if such transfer is otherwise permitted under this Agreement. Upon receipt of notice of such a transfer, the General Partner shall withdraw the notice of redemption, provided the transferee of such Limited Partner Interest certifies to the satisfaction of the General Partner in a Taxation Certification that he is an Eligible Holder. If the transferee fails to make such certification, such redemption shall be effected from the transferee on the original redemption date.

ARTICLE V

CAPITAL CONTRIBUTIONS AND ISSUANCE OF PARTNERSHIP INTERESTS

Section 5.1 Prior Contributions.

Prior to the date hereof, the General Partner made certain Capital Contributions to the Partnership in exchange for an interest in the Partnership and has been admitted as the General Partner of the Partnership, and the Initial Limited Partners made certain Capital Contributions to the Partnership in exchange for an interest in the Partnership and have been admitted as Limited Partners of the Partnership.

 

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Section 5.2 Continuation of General Partner and Limited Partner Interests; Initial Offering; Contributions by the General Partner.

(a) Upon the Effective Time, the General Partner Interest (represented by General Partner Units) of the General Partner shall be continued, subject to all of the rights, privileges and duties of the General Partner under this Agreement.

(b) Upon the Effective Time, the Limited Partner Interests of the Initial Limited Partners shall be converted into the number of Common Units specified for each Initial Limited Partner in Exhibit D hereto, and such Limited Partner Interests shall be continued.

(c) Upon the issuance of any additional Limited Partner Interests by the Partnership, the General Partner may make, but is not obligated to make, additional Capital Contributions equal to its percentage interest (the quotient determined by dividing such General Partner’s Percentage Interest by the sum of 100 less such General Partner’s Percentage Interest) of any amount contributed to the Partnership by the Limited Partners in exchange for such additional Limited Partner Interests. Notwithstanding the preceding sentence and except as set forth in Article XII, the General Partner shall not be obligated to make any additional Capital Contributions to the Partnership.

Section 5.3 Issuance of Class B Units. On the Closing Date, the Partnership shall issue 2,521,570 Class B Units to the Initial Class B Holder. The Capital Account of such Class B Units shall be $0 as of the Closing Date and will constitute a profits interest in the Partnership for federal income tax purposes.

Section 5.4 Contributions by the Underwriters.

(a) On the Closing Date and pursuant to the Underwriting Agreement, each Underwriter shall contribute to the Partnership cash in an amount equal to the Issue Price per Initial Common Unit multiplied by the number of Common Units specified in the Underwriting Agreement to be purchased by such Underwriter at the Closing Date. In exchange for such Capital Contributions by the Underwriters, the Partnership shall issue Common Units to each Underwriter on whose behalf such Capital Contribution is made in an amount equal to the quotient obtained by dividing (i) the cash contribution to the Partnership by or on behalf of such Underwriter by (ii) the Issue Price per Initial Common Unit.

(b) Upon the exercise of the Over-Allotment Option, each Underwriter shall contribute to the Partnership cash in an amount equal to the Issue Price per Initial Common Unit, multiplied by the number of Common Units to be purchased by such Underwriter at the Option Closing Date. In exchange for such Capital Contributions by the Underwriters, the Partnership shall issue Common Units to each Underwriter on whose behalf such Capital Contribution is made in an amount equal to the quotient obtained by dividing (i) the cash contributions to the Partnership by or on behalf of such Underwriter by (ii) the Issue Price per Initial Common Unit.

(c) Except as provided in Section 5.1, no Limited Partner Interests will be issued or issuable as of or at the Closing Date other than (i) the Common Units issuable pursuant to subparagraph (a) hereof in aggregate number equal to 21,000,000 Units and (ii) the “ Option Units ” as such term is used in the Underwriting Agreement issuable upon exercise of the Over-

 

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Allotment Option pursuant to subparagraph (b) hereof in an aggregate number of up to 3,150,000 additional Units, (iii) the Common Units issued to the Initial Limited Partners in an aggregate number of up to 112,983,557 and (iv) the Class B Units issued to the Initial Class B Holder in an aggregate number equal to 2,521,570.

Section 5.5 Interest and Withdrawal.

No interest on Capital Contributions shall be paid by the Partnership. No Partner or Assignee shall be entitled to the withdrawal or return of its Capital Contribution, except to the extent, if any, that distributions made pursuant to this Agreement or upon termination of the Partnership may be considered as such by law and then only to the extent provided for in this Agreement. Except to the extent expressly provided in this Agreement, no Partner or Assignee shall have priority over any other Partner or Assignee either as to the return of Capital Contributions or as to profits, losses or distributions. Any such return shall be a compromise to which all Partners or Assignees agree within the meaning of Section 17-502(b) of the Delaware Act.

Section 5.6 Capital Accounts.

(a) The Partnership shall maintain for each Partner (or a beneficial owner of Partnership Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method acceptable to the General Partner) owning a Partnership Interest a separate Capital Account with respect to such Partnership Interest in accordance with the rules of Treasury Regulation Section 1.704-1(b)(2)(iv). Such Capital Account shall be increased by (i) the amount of all Capital Contributions made to the Partnership with respect to such Partnership Interest pursuant to this Agreement and (ii) all items of Partnership income and gain (including, without limitation, income and gain exempt from tax) computed in accordance with Section 5.6(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1, and decreased by (x) the amount of cash or Net Agreed Value of all actual and deemed distributions of cash or property made with respect to such Partnership Interest pursuant to this Agreement and (y) all items of Partnership deduction and loss computed in accordance with Section 5.6(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1.

(b) For purposes of computing the amount of any item of income, gain, loss or deduction which is to be allocated pursuant to Article VI and is to be reflected in the Partners’ Capital Accounts, the determination, recognition and classification of any such item shall be the same as its determination, recognition and classification for federal income tax purposes (including, without limitation, any method of depreciation, cost recovery or amortization used for that purpose), provided, that:

(i) Solely for purposes of this Section 5.6, the Partnership shall be treated as owning directly its proportionate share (as determined by the General Partner based upon the provisions of the MLP Agreement) of all property owned by the MLP or any other Subsidiary that is classified as a partnership for federal income tax purposes.

 

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(ii) All fees and other expenses incurred by the Partnership to promote the sale of (or to sell) a Partnership Interest that can neither be deducted nor amortized under Section 709 of the Code, if any, shall, for purposes of Capital Account maintenance, be treated as an item of deduction at the time such fees and other expenses are incurred and shall be allocated among the Partners pursuant to Section 6.1.

(iii) Except as otherwise provided in Treasury Regulation Section 1.704-1(b)(2)(iv)(m), the computation of all items of income, gain, loss and deduction shall be made without regard to any election under Section 754 of the Code which may be made by the Partnership and, as to those items described in Section 705(a)(1)(B) or 705(a)(2)(B) of the Code, without regard to the fact that such items are not includable in gross income or are neither currently deductible nor capitalized for federal income tax purposes. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment in the Capital Accounts shall be treated as an item of gain or loss.

(iv) Any income, gain, loss or deduction attributable to the taxable disposition of any Partnership property shall be determined as if the adjusted basis of such property as of such date of disposition were equal in amount to the Partnership’s Carrying Value with respect to such property as of such date.

(v) In accordance with the requirements of Section 704(b) of the Code, any deductions for depreciation, cost recovery or amortization attributable to any Contributed Property shall be determined as if the adjusted basis of such property on the date it was acquired by the Partnership were equal to the Agreed Value of such property. Upon an adjustment pursuant to Section 5.6(d) to the Carrying Value of any Partnership property subject to depreciation, cost recovery or amortization, any further deductions for such depreciation, cost recovery or amortization attributable to such property shall be determined as if the adjusted basis of such property were equal to the Carrying Value of such property immediately following such adjustment.

(vi) If the Partnership’s adjusted basis in a depreciable or cost recovery property is reduced for federal income tax purposes pursuant to Section 48(q)(1) or 48(q)(3) of the Code, the amount of such reduction shall, solely for purposes hereof, be deemed to be an additional depreciation or cost recovery deduction in the year such property is placed in service and shall be allocated among the Partners pursuant to Section 6.1. Any restoration of such basis pursuant to Section 48(q)(2) of the Code shall, to the extent possible, be allocated in the same manner to the Partners to whom such deemed deduction was allocated.

(c) A transferee of a Partnership Interest shall succeed to a pro rata portion of the Capital Account of the transferor relating to the Partnership Interest so transferred.

(d) (i) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), on an issuance of additional Partnership Interests for cash or Contributed Property, the issuance of Partnership Interests as consideration for the provision of services, or the conversion of the General Partner’s Combined Interest to Units pursuant to Section 11.3(b), the

 

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Capital Account of all Partners and the Carrying Value of each Partnership property immediately prior to such issuance shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, as if such Unrealized Gain or Unrealized Loss had been recognized on an actual sale of each such property immediately prior to such issuance and had been allocated to the Partners at such time pursuant to Section 6.1 in the same manner as any item of gain or loss actually recognized during such period would have been allocated. In determining such Unrealized Gain or Unrealized Loss, the aggregate cash amount and fair market value of all Partnership assets (including, without limitation, cash or cash equivalents) immediately prior to the issuance of additional Partnership Interests shall be determined by the General Partner using such method of valuation as it may adopt; provided, however, that the General Partner, in arriving at such valuation, must take fully into account the fair market value of the Partnership Interests of all Partners at such time. The General Partner shall allocate such aggregate value among the assets of the Partnership (in such manner as it determines) to arrive at a fair market value for individual properties.

(ii) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), immediately prior to any actual or deemed distribution to a Partner of any Partnership property (other than a distribution of cash that is not in redemption or retirement of a Partnership Interest), the Capital Accounts of all Partners and the Carrying Value of all Partnership property shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, as if such Unrealized Gain or Unrealized Loss had been recognized in a sale of such property immediately prior to such distribution for an amount equal to its fair market value, and had been allocated to the Partners, at such time, pursuant to Section 6.1 in the same manner as any item of gain or loss actually recognized during such period would have been allocated. In determining such Unrealized Gain or Unrealized Loss the aggregate cash amount and fair market value of all Partnership assets (including, without limitation, cash or cash equivalents) immediately prior to a distribution shall (A) in the case of an actual distribution that is not made pursuant to Section 12.4 or in the case of a deemed distribution, be determined and allocated in the same manner as that provided in Section 5.6(d)(i) or (B) in the case of a liquidating distribution pursuant to Section 12.4, be determined and allocated by the Liquidator using such method of valuation as it may adopt.

Section 5.7 Conversion of Class B Units.

(a) At any time after six months from the date on which any Class B Units are issued, upon written notice to the General Partner, any holder of Class B Units will have the right to require the Partnership to convert all or any portion of such holder’s Class B Units into Common Units on a one for one basis (a “ Conversion Notice ”).

(b) Upon the conversion of Class B Units in accordance with this Section 5.7, each converting holder shall be deemed to be the holder of record of the number of Common Units issuable upon conversion, notwithstanding that the Certificates representing such Common Units shall not then actually be delivered to such person. Upon notice from the Partnership, each holder of Class B Units so converted shall promptly surrender to the Partnership Certificates representing the Class B Units so converted in proper transfer form. Each Class B Unit shall be canceled by the General Partner upon its conversion.

 

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(c) A Class B Unit that has converted into a Common Unit pursuant to this Section 5.7 shall be subject to the provisions of Section 6.4(b).

(d) The issuance or delivery of Certificates for Common Units upon the conversion of Class B Units shall be made without charge to the converting holder of Class B Units for such Certificates or for any tax in respect of the issuance or delivery of such Certificates or the securities represented thereby, and such Certificates shall be issued or delivered in the respective names of, or in such names as may be directed by, the holders of the Class B Units converted; provided, however, that the Partnership shall not be required to pay any tax which may be payable in respect of any transfer involved in the issuance and delivery of any such Certificate in a name other than that of the holder of the Class B Units converted, and the Partnership shall not be required to issue or deliver such Certificate unless or until the Person or Persons requesting the issuance or delivery thereof shall have paid to the Partnership the amount of such tax or shall have established to the reasonable satisfaction of the Partnership that such tax has been paid.

Section 5.8 Issuances of Additional Partnership Securities.

(a) The Partnership may issue additional Partnership Securities and options, rights, warrants and appreciation rights relating to the Partnership Securities for any Partnership purpose at any time and from time to time to such Persons for such consideration and on such terms and conditions as the General Partner shall determine, all without the approval of any Limited Partners.

(b) Each additional Partnership Security authorized to be issued by the Partnership pursuant to Section 5.8(a) may be issued in one or more classes, or one or more series of any such classes, with such designations, preferences, rights, powers and duties (which may be senior to existing classes and series of Partnership Securities), as shall be fixed by the General Partner, including (i) the right to share in Partnership profits and losses or items thereof; (ii) the right to share in Partnership distributions; (iii) the rights upon dissolution and liquidation of the Partnership; (iv) whether, and the terms and conditions upon which the Partnership may or shall be required to redeem the Partnership Security (including sinking fund provisions); (v) whether such Partnership Security is issued with the privilege of conversion or exchange and, if so, the terms and conditions of such conversion or exchange; (vi) the terms and conditions upon which each Partnership Security will be issued, evidenced by certificates and assigned or transferred; (vii) the method for determining the Percentage Interest as to such Partnership Security; and (viii) the right, if any, of each such Partnership Security to vote on Partnership matters, including matters relating to the relative designations, preferences, rights, powers and duties of such Partnership Security.

(c) The General Partner is hereby authorized and directed to take all actions that it determines to be necessary or appropriate in connection with (i) each issuance of Partnership Securities and options, rights, warrants and appreciation rights relating to Partnership Securities pursuant to this Section 5.8, (ii) the conversion of the General Partner Interest (represented by General Partner Units) into Units pursuant to the terms of this Agreement, (iii) the admission of additional Limited Partners and (iv) all additional issuances of Partnership Securities. The General Partner shall determine the relative rights, powers and duties of the

 

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holders of the Units or other Partnership Securities being so issued. The General Partner shall do all things necessary to comply with the Delaware Act and is authorized and directed to do all things that it determines to be necessary or appropriate in connection with any future issuance of Partnership Securities or in connection with the conversion of the General Partner Interest into Units pursuant to the terms of this Agreement, including compliance with any statute, rule, regulation or guideline of any federal, state or other governmental agency or any National Securities Exchange on which the Units or other Partnership Securities are listed or admitted for trading.

(d) No fractional Partnership Securities shall be issued by the Partnership. If a distribution, subdivision or combination of Units pursuant to Section 5.8 would result in the issuance of fractional Units, each fractional Unit shall be rounded to the nearest whole Unit (and a 0.5 Unit shall be rounded to the next higher Unit).

Section 5.9 Limited Preemptive Right.

Except as provided in Section 5.6 and in this Section 5.9, no Person shall have any preemptive, preferential or other similar right with respect to the issuance of any Partnership Security, whether unissued, held in the treasury or hereafter created. The General Partner shall have the right, which it may from time to time assign in whole or in part to any of its Affiliates, to purchase Partnership Securities from the Partnership whenever, and on the same terms that, the Partnership issues Partnership Securities to Persons other than the General Partner and its Affiliates, to the extent necessary to maintain the Percentage Interests of the General Partner and its Affiliates equal to that which existed immediately prior to the issuance of such Partnership Securities. The General Partner shall be deemed to have waived this right with respect to any issuance of a particular Partnership Security in the event that the General Partner has not exercised this right prior to the issuance of such Partnership Security.

Section 5.10 Splits and Combinations.

(a) Subject to Section 5.8(d), the Partnership may make a Pro Rata distribution of Partnership Securities to all Record Holders or may effect a subdivision or combination of Partnership Securities so long as, after any such event, each Partner shall have the same Percentage Interest in the Partnership as before such event, and any amounts calculated on a per Unit basis or stated as a number of Units are proportionately adjusted.

(b) Whenever such a distribution, subdivision or combination of Partnership Securities is declared, the General Partner shall select a Record Date as of which the distribution, subdivision or combination shall be effective and shall send notice thereof at least 20 days prior to such Record Date to each Record Holder as of a date not less than 10 days prior to the date of such notice. The General Partner also may cause a firm of independent public accountants selected by it to calculate the number of Partnership Securities to be held by each Record Holder after giving effect to such distribution, subdivision or combination. The General Partner shall be entitled to rely on any certificate provided by such firm as conclusive evidence of the accuracy of such calculation.

 

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(c) Promptly following any such distribution, subdivision or combination, the Partnership may issue Certificates to the Record Holders of Partnership Securities as of the applicable Record Date representing the new number of Partnership Securities held by such Record Holders, or the General Partner may adopt such other procedures that it determines to be necessary or appropriate to reflect such changes. If any such combination results in a smaller total number of Partnership Securities Outstanding, the Partnership shall require, as a condition to the delivery to a Record Holder of such new Certificate, the surrender of any Certificate held by such Record Holder immediately prior to such Record Date.

Section 5.11 Fully Paid and Non-Assessable Nature of Limited Partner Interests.

All Limited Partner Interests issued pursuant to, and in accordance with the requirements of, this Article V shall be fully paid and non-assessable Limited Partner Interests in the Partnership, except as such non assessability may be affected by Section 17-607 of the Delaware Act.

ARTICLE VI

ALLOCATIONS AND DISTRIBUTIONS

Section 6.1 Allocations for Capital Account Purposes.

For purposes of maintaining the Capital Accounts and in determining the rights of the Partners among themselves, the Partnership’s items of income, gain, loss and deduction (computed in accordance with Section 5.6(b)) shall be allocated among the Partners in each taxable year (or portion thereof) as provided herein below.

(a) Net Income. After giving effect to the special allocations set forth in Section 6.1(d), Net Income for each taxable year and all items of income, gain, loss and deduction taken into account in computing Net Income for such taxable year shall be allocated to the Partners in accordance with their respective Percentage Interests.

(b) Net Losses. After giving effect to the special allocations set forth in Section 6.1(d), Net Losses for each taxable period and all items of income, gain, loss and deduction taken into account in computing Net Losses for such taxable period shall be allocated to the Partners in accordance with their respective Percentage Interests; provided that Net Losses shall not be allocated pursuant to this Section 6.1(b) to the extent that such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable year (or increase any existing deficit balance in its Adjusted Capital Account), instead any such Net Losses shall be allocated to Partners with positive Adjusted Capital Account balances in accordance with their Percentage Interests until such positive Adjusted Capital Accounts are reduced to zero, and thereafter to the General Partner.

(c) Net Termination Gains and Losses. After giving effect to the special allocations set forth in Section 6.1(d), all items of income, gain, loss and deduction taken into account in computing Net Termination Gain or Net Termination Loss for such taxable period shall be allocated in the same manner as such Net Termination Gain or Net Termination Loss is allocated hereunder. All allocations under this Section 6.1(c) shall be made after Capital Account balances have been adjusted by all other allocations provided under this Section 6.1 and after all distributions of Available Cash provided under Section 6.3 have been made; provided, however, that solely for purposes of this Section 6.1(c), Capital Accounts shall not be adjusted for distributions made pursuant to Section 12.4.

 

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(i) If a Net Termination Gain is recognized (or deemed recognized pursuant to Section 5.6(d)), such Net Termination Gain shall be allocated among the Partners in the following manner (and the Capital Accounts of the Partners shall be increased by the amount so allocated in each of the following subclauses, in the order listed, before an allocation is made pursuant to the next succeeding subclause):

 

  A.

First, to each Partner having a deficit balance in its Capital Account, in the proportion that such deficit balance bears to the total deficit balances in the Capital Accounts of all Partners, until each such Partner has been allocated Net Termination Gain equal to any such deficit balance in its Capital Account; and

 

  B.

Second, 100% to all Partners in accordance with their Percentage Interests;

(ii) If a Net Termination Loss is recognized (or deemed recognized pursuant to Section 5.6(d)), such Net Termination Loss shall be allocated among the Partners in the following manner:

 

  A.

First, 100% to all Partners, Pro Rata, until the Capital Account in respect of each Unit then Outstanding has been reduced to zero; and

 

  B.

Second, the balance, if any, to the General Partner.

(d) Special Allocations. Notwithstanding any other provision of this Section 6.1, the following special allocations shall be made for such taxable period:

(i) Partnership Minimum Gain Chargeback. Notwithstanding any other provision of this Section 6.1, if there is a net decrease in Partnership Minimum Gain during any Partnership taxable period, each Partner shall be allocated items of Partnership income and gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(f)(6), 1.704-2(g)(2) and 1.704-2(j)(2)(i), or any successor provision. For purposes of this Section 6.1(d), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income or gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d) with respect to such taxable period (other than an allocation pursuant to Sections 6.1(d)(v) and 6.1(d)(vi)). This Section 6.1(d)(i) is intended to comply with the Partnership Minimum Gain chargeback requirement in Treasury Regulation Section 1.704-2(f) and shall be interpreted consistently therewith.

 

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(ii) Chargeback of Partner Nonrecourse Debt Minimum Gain. Notwithstanding the other provisions of this Section 6.1 (other than Section 6.1(d)(i)), except as provided in Treasury Regulation Section 1.704-2(i)(4), if there is a net decrease in Partner Nonrecourse Debt Minimum Gain during any Partnership taxable period, any Partner with a share of Partner Nonrecourse Debt Minimum Gain at the beginning of such taxable period shall be allocated items of Partnership income and gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(i)(4) and 1.704-2(j)(2)(ii), or any successor provisions. For purposes of this Section 6.1(d), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income or gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d), other than Section 6.1(d)(i) and other than an allocation pursuant to Sections 6.1(d)(v) and 6.1(d)(vi), with respect to such taxable period. This Section 6.1(d)(ii) is intended to comply with the chargeback of items of income and gain requirement in Treasury Regulation Section 1.704-2(i)(4) and shall be interpreted consistently therewith.

(iii) Qualified Income Offset. In the event any Partner unexpectedly receives any adjustments, allocations or distributions described in Treasury Regulation Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5), or 1.704-1(b)(2)(ii)(d)(6), items of Partnership income and gain shall be specially allocated to such Partner in an amount and manner sufficient to eliminate, to the extent required by the Treasury Regulations promulgated under Section 704(b) of the Code, the deficit balance, if any, in its Adjusted Capital Account created by such adjustments, allocations or distributions as quickly as possible unless such deficit balance is otherwise eliminated pursuant to Section 6.1(d)(i) or (ii).

(iv) Gross Income Allocations. In the event any Partner has a deficit balance in its Capital Account at the end of any Partnership taxable period in excess of the sum of (A) the amount such Partner is required to restore pursuant to the provisions of this Agreement and (B) the amount such Partner is deemed obligated to restore pursuant to Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5), such Partner shall be specially allocated items of Partnership gross income and gain in the amount of such excess as quickly as possible; provided, that an allocation pursuant to this Section 6.1(d)(iii) shall be made only if and to the extent that such Partner would have a deficit balance in its Capital Account as adjusted after all other allocations provided for in this Section 6.1 have been tentatively made as if this Section 6.1(d)(iv) were not in this Agreement.

(v) Nonrecourse Deductions. Nonrecourse Deductions for any taxable period shall be allocated to the Partners in accordance with their respective Percentage Interests. If the General Partner determines that the Partnership’s Nonrecourse Deductions should be allocated in a different ratio to satisfy the safe harbor requirements of the Treasury Regulations promulgated under Section 704(b) of the Code, the General Partner is authorized, upon notice to the other Partners, to revise the prescribed ratio to the numerically closest ratio that does satisfy such requirements.

 

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(vi) Partner Nonrecourse Deductions. Partner Nonrecourse Deductions for any taxable period shall be allocated 100% to the Partner that bears the Economic Risk of Loss with respect to the Partner Nonrecourse Debt to which such Partner Nonrecourse Deductions are attributable in accordance with Treasury Regulation Section 1.704-2(i). If more than one Partner bears the Economic Risk of Loss with respect to a Partner Nonrecourse Debt, such Partner Nonrecourse Deductions attributable thereto shall be allocated between or among such Partners in accordance with the ratios in which they share such Economic Risk of Loss.

(vii) Nonrecourse Liabilities. For purposes of Treasury Regulation Section 1.752-3(a)(3), the Partners agree that Nonrecourse Liabilities of the Partnership in excess of the sum of (A) the amount of Partnership Minimum Gain and (B) the total amount of Nonrecourse Built-in Gain shall be allocated among the Partners in accordance with their respective Percentage Interests.

(viii) Code Section 754 Adjustments. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment to the Capital Accounts shall be treated as an item of gain (if the adjustment increases the basis of the asset) or loss (if the adjustment decreases such basis), and such item of gain or loss shall be specially allocated to the Partners in a manner consistent with the manner in which their Capital Accounts are required to be adjusted pursuant to such Section of the Treasury Regulations.

(ix) Economic Uniformity. With respect to any taxable period ending upon, or after, the date a Conversion Notice is given by a holder of Class B Units pursuant to Section 5.7, items of Partnership income and gain shall be allocated 100% to each Partner holding such Class B Units until each such Partner has been allocated an amount of Partnership income or gain that increases the Capital Account maintained with respect to each converted Class B Unit to an amount equal to the product of (1) the number of converted Class B Units and (2) the Per Unit Capital Amount for a Common Unit. The purpose for this allocation is to establish uniformity between the Capital Accounts underlying converted Class B Units and the Capital Accounts underlying Common Units held by Persons other than the General Partner and its Affiliates immediately prior to the conversion of Class B Units into Common Units.

(x) Curative Allocation.

 

  A.

Notwithstanding any other provision of this Section 6.1, other than the Required Allocations, the Required Allocations shall be taken into account in making the Agreed Allocations so that, to the extent possible, the net amount of items of income, gain, loss and deduction allocated to each Partner pursuant to the Required Allocations and the Agreed Allocations, together, shall be equal to the net amount of such items that would have been allocated to each such Partner under the Agreed Allocations had the Required Allocations and the related Curative Allocation not otherwise been provided in this Section 6.1. Notwithstanding the preceding

 

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  sentence, Required Allocations relating to (1) Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Partnership Minimum Gain and (2) Partner Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Partner Nonrecourse Debt Minimum Gain. Allocations pursuant to this Section 6.1(d)(ix)(A) shall only be made with respect to Required Allocations to the extent the General Partner determines that such allocations will otherwise be inconsistent with the economic agreement among the Partners. Further, allocations pursuant to this Section 6.1(d)(ix)(A) shall be deferred with respect to allocations pursuant to clauses (1) and (2) hereof to the extent the General Partner determines that such allocations are likely to be offset by subsequent Required Allocations.

 

  B.

The General Partner shall, with respect to each taxable period, (1) apply the provisions of Section 6.1(d)(ix)(A) in whatever order is most likely to minimize the economic distortions that might otherwise result from the Required Allocations, and (2) divide all allocations pursuant to Section 6.1(d)(ix)(A) among the Partners in a manner that is likely to minimize such economic distortions.

(xi) Corrective Allocations. In the event of any allocation of Additional Book Basis Derivative Items or any Book-Down Event or any recognition of a Net Termination Loss, the following rules shall apply:

 

  A.

In the case of any negative adjustments to the Capital Accounts of the Partners resulting from a Book-Down Event or from the recognition of a Net Termination Loss, such negative adjustment (1) shall first be allocated, to the extent of the Aggregate Remaining Net Positive Adjustments, in such a manner, as determined by the General Partner, that to the extent possible the aggregate Capital Accounts of the Partners will equal the amount that would have been the Capital Account balance of the Partners if no prior Book-Up Events had occurred, and (2) any negative adjustment in excess of the Aggregate Remaining Net Positive Adjustments shall be allocated pursuant to Section 6.1(c) hereof.

 

  B.

In making the allocations required under this Section 6.1(d)(x), the General Partner may apply whatever conventions or other methodology it determines will satisfy the purpose of this Section 6.1(d)(x).

Section 6.2 Allocations for Tax Purposes.

(a) Except as otherwise provided herein, for federal income tax purposes, each item of income, gain, loss and deduction shall be allocated among the Partners in the same manner as its correlative item of “ book ” income, gain, loss or deduction is allocated pursuant to Section 6.1.

 

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(b) In an attempt to eliminate Book-Tax Disparities attributable to a Contributed Property or Adjusted Property, items of income, gain, loss, depreciation, amortization and cost recovery deductions shall be allocated for federal income tax purposes among the Partners as follows:

(i) (A) In the case of a Contributed Property, such items attributable thereto shall be allocated among the Partners in the manner provided under Section 704(c) of the Code that takes into account the variation between the Agreed Value of such property and its adjusted basis at the time of contribution; and (B) any item of Residual Gain or Residual Loss attributable to a Contributed Property shall be allocated among the Partners in the same manner as its correlative item of “ book ” gain or loss is allocated pursuant to Section 6.1.

(ii) (A) In the case of an Adjusted Property, such items shall (1) first, be allocated among the Partners in a manner consistent with the principles of Section 704(c) of the Code to take into account the Unrealized Gain or Unrealized Loss attributable to such property and the allocations thereof pursuant to Section 5.6(d)(i) or Section 5.6(d)(ii), and (2) second, in the event such property was originally a Contributed Property, be allocated among the Partners in a manner consistent with Section 6.2(b)(i)(A); and (B) any item of Residual Gain or Residual Loss attributable to an Adjusted Property shall be allocated among the Partners in the same manner as its correlative item of “ book ” gain or loss is allocated pursuant to Section 6.1.

(iii) The General Partner shall apply the principles of Treasury Regulation Section 1.704-3(d) to eliminate Book-Tax Disparities, except as otherwise determined by the General Partner with respect to goodwill.

(c) For the proper administration of the Partnership and for the preservation of uniformity of the Limited Partner Interests (or any class or classes thereof), the General Partner shall (i) adopt such conventions as it deems appropriate in determining the amount of depreciation, amortization and cost recovery deductions; (ii) make special allocations for federal income tax purposes of income (including, without limitation, gross income) or deductions; and (iii) amend the provisions of this Agreement as appropriate (x) to reflect the proposal or promulgation of Treasury Regulations under Section 704(b) or Section 704(c) of the Code or (y) otherwise to preserve or achieve uniformity of the Limited Partner Interests (or any class or classes thereof). The General Partner may adopt such conventions, make such allocations and make such amendments to this Agreement as provided in this Section 6.1(c) only if such conventions, allocations or amendments would not have a material adverse effect on the Partners, the holders of any class or classes of Limited Partner Interests issued and Outstanding or the Partnership, and if such allocations are consistent with the principles of Section 704 of the Code.

 

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(d) The General Partner may determine to depreciate or amortize the portion of an adjustment under Section 743(b) of the Code attributable to unrealized appreciation in any Adjusted Property (to the extent of the unamortized Book-Tax Disparity) using a predetermined rate derived from the depreciation or amortization method and useful life applied to the Partnership’s common basis of such property, despite any inconsistency of such approach with Treasury Regulation Section 1.167(c)-1(a)(6) or any successor regulations thereto. If the General Partner determines that such reporting position cannot reasonably be taken, the General Partner may adopt depreciation and amortization conventions under which all purchasers acquiring Limited Partner Interests in the same month would receive depreciation and amortization deductions, based upon the same applicable rate as if they had purchased a direct interest in the Partnership’s property. If the General Partner chooses not to utilize such aggregate method, the General Partner may use any other depreciation and amortization conventions to preserve the uniformity of the intrinsic tax characteristics of any Limited Partner Interests, so long as such conventions would not have a material adverse effect on the Limited Partners or the Record Holders of any class or classes of Limited Partner Interests.

(e) Any gain allocated to the Partners upon the sale or other taxable disposition of any Partnership asset shall, to the extent possible, after taking into account other required allocations of gain pursuant to this Section 6.2, be characterized as Recapture Income in the same proportions and to the same extent as such Partners (or their predecessors in interest) have been allocated any deductions directly or indirectly giving rise to the treatment of such gains as Recapture Income.

(f) All items of income, gain, loss, deduction and credit recognized by the Partnership for federal income tax purposes and allocated to the Partners in accordance with the provisions hereof shall be determined without regard to any election under Section 754 of the Code which may be made by the Partnership; provided, however, that such allocations, once made, shall be adjusted (in the manner determined by the General Partner) to take into account those adjustments permitted or required by Sections 734 and 743 of the Code.

(g) Each item of Partnership income, gain, loss and deduction, shall for federal income tax purposes, be determined on an annual basis and prorated on a monthly basis and shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Units are then traded on the first Business Day of each month; provided, however, that (i) such items for the period beginning on the Closing Date and ending on the last day of the month in which the Option Closing Date or the expiration of the Over-Allotment Option occurs shall be allocated to the Partners as of the opening of the National Securities Exchange on the first Business Day of the next succeeding month; and provided, further, that gain or loss on a sale or other disposition of any assets of the Partnership or any other extraordinary item of income or loss realized and recognized other than in the ordinary course of business, as determined by the General Partner in its sole discretion, shall be allocated to the Partners as of the opening of the National Securities Exchange on the first Business Day of the month in which such gain or loss is recognized for federal income tax purposes. The General Partner may revise, alter or otherwise modify such methods of allocation to the extent permitted or required by Section 706 of the Code and the regulations or rulings promulgated thereunder.

(h) Allocations that would otherwise be made to a Limited Partner under the provisions of this Article VI shall instead be made to the beneficial owner of Limited Partner Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method determined by the General Partner.

 

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Section 6.3 Requirement and Characterization of Distributions; Distributions to Record Holders.

(a) Within 50 days following the end of each Quarter commencing with the Quarter ending on February 28, 2006, an amount equal to 100% of Available Cash with respect to such Quarter shall, subject to Section 17-607 of the Delaware Act, be distributed in accordance with this Article VI by the Partnership to the Partners in accordance with their respective Percentage Interests as of the Record Date selected by the General Partner. All distributions required to be made under this Agreement shall be made subject to Section 17-607 of the Delaware Act.

(b) Notwithstanding Section 6.3(a), in the event of the dissolution and liquidation of the Partnership, all receipts received during or after the Quarter in which the Liquidation Date occurs shall be applied and distributed solely in accordance with, and subject to the terms and conditions of, Section 12.4.

(c) The General Partner may treat taxes paid by the Partnership on behalf of, or amounts withheld with respect to, all or less than all of the Partners, as a distribution of Available Cash to such Partners.

(d) Each distribution in respect of a Partnership Interest shall be paid by the Partnership, directly or through the Transfer Agent or through any other Person or agent, only to the Record Holder of such Partnership Interest as of the Record Date set for such distribution. Such payment shall constitute full payment and satisfaction of the Partnership’s liability in respect of such payment, regardless of any claim of any Person who may have an interest in such payment by reason of an assignment or otherwise.

Section 6.4 Special Provisions Relating to the Holders of Class B Units.

(a) Except as otherwise provided in the Agreement and unless the context otherwise requires, (i) the Class B Units will have voting rights that are identical to the voting rights of Common Units at any time when the Class B Units are convertible into Common Units at the election of the holder thereof pursuant to Section 5.7 and, when such voting rights are in effect, the Class B Units will vote with the Common Units as a single class, so that each Class B Unit will be entitled to one vote on each matter with respect to which each Common Unit is entitled to vote and (ii) for all other purposes the holder of a Class B Unit shall have all of the rights and obligations of a Limited Partner holding Common Units hereunder. Immediately upon the conversion of a Class B Unit into a Common Unit pursuant to Section 5.7, the holder of a Class B Unit that has converted into a Common Unit shall possess all of the rights and obligations of a Unitholder holding a Common Unit hereunder; provided, however, that a converted Class B Unit shall remain subject to the provisions of Section 6.1(d)(ix) and Section 6.4(b).

 

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(b) The holder of a Class B Unit that has converted into a Common Unit pursuant to Section 5.11 shall not be issued a Common Unit Certificate pursuant to Section 4.1 and shall not be permitted to transfer its converted Class B Units to a Person that is not an Affiliate of the holder until such time as the General Partner determines, based on advice of counsel, that a converted Class B Unit should have, as a substantive matter, like intrinsic economic and United States federal income tax characteristics, in all material respects, to the intrinsic economic and United States federal income tax characteristics of a Common Unit then Outstanding. In connection with the condition imposed by this Section 6.4(b), the General Partner shall take whatever steps are required to provide economic uniformity to the converted Class B Units in preparation for a transfer of such converted Class B Units, including the application of Section 6.1(d)(ix); provided, however, that no such steps may be taken that would have a material adverse effect on the Unitholders holding Common Units represented by Common Unit Certificates.

ARTICLE VII

MANAGEMENT AND OPERATION OF BUSINESS

Section 7.1 Management.

(a) The General Partner shall conduct, direct and manage all activities of the Partnership. Except as otherwise expressly provided in this Agreement, all management powers over the business and affairs of the Partnership shall be exclusively vested in the General Partner, and no Limited Partner or Assignee shall have any management power over the business and affairs of the Partnership. In addition to the powers now or hereafter granted a general partner of a limited partnership under applicable law or that are granted to the General Partner under any other provision of this Agreement, the General Partner, subject to Section 7.3, shall have full power and authority to do all things and on such terms as it determines to be necessary or appropriate to conduct the business of the Partnership, to exercise all powers set forth in Section 2.5 and to effectuate the purposes set forth in Section 2.4, including the following:

(i) the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into Partnership Securities, and the incurring of any other obligations;

(ii) the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over the business or assets of the Partnership;

(iii) the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of the assets of the Partnership or the merger or other combination of the Partnership with or into another Person (the matters described in this clause (iii) being subject, however, to any prior approval that may be required by Section 7.3 and Article XIV);

(iv) the use of the assets of the Partnership (including cash on hand) for any purpose consistent with the terms of this Agreement, including the financing of the conduct of the operations of the Partnership, its Subsidiaries and the MLP; subject to Section 7.6(a), the lending of funds to other Persons; the repayment or guarantee of obligations of the Partnership,its Subsidiaries and the MLP and the making of capital contributions to any member of the Partnership, its Subsidiaries and the MLP;

 

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(v) the negotiation, execution and performance of any contracts, conveyances or other instruments (including instruments that limit the liability of the Partnership under contractual arrangements to all or particular assets of the Partnership, with the other party to the contract to have no recourse against the General Partner or its assets other than its interest in the Partnership, even if same results in the terms of the transaction being less favorable to the Partnership than would otherwise be the case);

(vi) the distribution of Partnership cash;

(vii) the selection and dismissal of employees (including employees having titles such as “ president,” “ vice president,” “ secretary ” and “ treasurer ”) and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

(viii) the maintenance of insurance for the benefit of the Partnership, the Partners and Indemnitees;

(ix) the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any further limited or general partnerships, joint ventures, limited liability companies, corporations or other relationships (including the acquisition of interests in, and the contributions of property to, the MLP and its Subsidiaries from time to time) subject to the restrictions set forth in Section 2.4;

(x) the control of any matters affecting the rights and obligations of the Partnership, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;

(xi) the indemnification of any Person against liabilities and contingencies to the extent permitted by law;

(xii) the entering into of listing agreements with any National Securities Exchange and the delisting of some or all of the Limited Partner Interests from, or requesting that trading be suspended on, any such exchange (subject to any prior approval that may be required under Section 4.7);

(xiii) the purchase, sale or other acquisition or disposition of Partnership Securities, or the issuance of options, rights, warrants and appreciation rights relating to Partnership Securities;

(xiv) the undertaking of any action in connection with the Partnership’s participation in the management of the MLP through its ownership of the general partner of the MLP; and

 

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(xv) the entering into of agreements with any of its Affiliates to render services to a Group Member or to itself in the discharge of its duties as General Partner of the Partnership.

(b) Notwithstanding any other provision of this Agreement, the Delaware Act or any applicable law, rule or regulation, each of the Partners and Assignees and each other Person who may acquire an interest in Partnership Securities hereby (i) approves, ratifies and confirms the execution, delivery and performance by the parties thereto of the Underwriting Agreement, the Omnibus Agreement and the other agreements described in or filed as exhibits to the Registration Statement that are related to the transactions contemplated by the Registration Statement; (ii) agrees that the General Partner (on its own or through any officer of the Partnership) is authorized to execute, deliver and perform the agreements referred to in clause (i) of this sentence and the other agreements, acts, transactions and matters described in or contemplated by the Registration Statement on behalf of the Partnership without any further act, approval or vote of the Partners or the Assignees or the other Persons who may acquire an interest in Partnership Securities; and (iii) agrees that the execution, delivery or performance by the General Partner, any Group Member or any Affiliate of any of them, of this Agreement or any agreement authorized or permitted under this Agreement (including the exercise by the General Partner or any Affiliate of the General Partner of the rights accorded pursuant to Article XV), shall not constitute a breach by the General Partner of any duty that the General Partner may owe the Partnership or the Limited Partners or any other Persons under this Agreement (or any other agreements) or of any duty stated or implied by law or equity.

Section 7.2 Certificate of Limited Partnership.

The General Partner has caused the Certificate of Limited Partnership to be filed with the Secretary of State of the State of Delaware as required by the Delaware Act and shall use all reasonable efforts to cause to be filed such other certificates or documents that the General Partner determines to be necessary or appropriate for the formation, continuation, qualification and operation of a limited partnership (or a partnership in which the limited partners have limited liability) in the State of Delaware or any other state in which the Partnership may elect to do business or own property. To the extent the General Partner determines such action to be necessary or appropriate, the General Partner shall file amendments to and restatements of the Certificate of Limited Partnership and do all things to maintain the Partnership as a limited partnership (or a partnership or other entity in which the limited partners have limited liability) under the laws of the State of Delaware or of any other state in which the Partnership may elect to do business or own property. Subject to the terms of Section 3.4(a), the General Partner shall not be required, before or after filing, to deliver or mail a copy of the Certificate of Limited Partnership, any qualification document or any amendment thereto to any Limited Partner.

Section 7.3 Restrictions on General Partner’s Authority.

Except as provided in Articles XII and XIV, the General Partner may not sell, exchange or otherwise dispose of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions (including by way of merger, consolidation or other combination) without the approval of holders of a Unit Majority; provided however that this provision shall not preclude or limit the General Partner’s ability to mortgage,

 

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pledge, hypothecate or grant a security interest in all or substantially all of the assets of the Partnership Group and shall not apply to any forced sale of any or all of the assets of the Partnership Group pursuant to the foreclosure of, or other realization upon, any such encumbrance. Without the approval of holders of a majority of Outstanding Units, the General Partner shall not, on behalf of the Partnership except as permitted under Sections 4.6, 11.1 and 11.2, elect or cause the Partnership to elect a successor general partner of the Partnership.

Section 7.4 Reimbursement of the General Partner.

(a) Except as provided in this Section 7.4 and elsewhere in this Agreement, the General Partner shall not be compensated for its services as general partner or managing member of any Group Member.

(b) The General Partner shall be reimbursed on a monthly basis, or such other reasonable basis as the General Partner may determine, for (i) all direct and indirect expenses it incurs or payments it makes on behalf of the Partnership (including salary, bonus, incentive compensation and other amounts paid to any Person) including Affiliates of the General Partner to perform services for the Partnership or for the General Partner in the discharge of its duties to the Partnership and, in the event the Partnership owns or operates, either directly or through any Subsidiary, any pipelines subject to rate regulation by FERC, including overhead allocated to the Partnership by Affiliates of the General Partner for its allocable share of actual overhead expenses consistent with then applicable accounting and allocation methodologies generally permitted by FERC for rate making purposes (or in the absence of then applicable methodologies permitted by FERC, consistent with the most recently applicable methodologies) and past business practices, and (ii) all other expenses allocable to the Partnership or otherwise incurred by the General Partner in connection with operating the Partnership’s business (including expenses allocated to the General Partner by its Affiliates). The General Partner shall determine the expenses that are allocable to the Partnership. Reimbursements pursuant to this Section 7.4 shall be in addition to any reimbursement to the General Partner as a result of indemnification pursuant to Section 7.7. The allocation of overhead to the Partnership by Affiliates of the General Partner for its allocable share of actual overhead expenses consistent with then applicable accounting and allocation methodologies generally permitted by FERC for rate making purposes (or in the absence of then applicable methodologies permitted by FERC, consistent with the most recently applicable methodologies) and past business practices shall be deemed to be fair and reasonable to the Partnership.

(c) The General Partner, without the approval of the Limited Partners (who shall have no right to vote in respect thereof), may propose and adopt on behalf of the Partnership employee benefit plans, employee programs and employee practices (including plans, programs and practices involving the issuance of Partnership Securities or options to purchase or rights, warrants or appreciation rights relating to Partnership Securities), or cause the Partnership to issue Partnership Securities in connection with, or pursuant to, any employee benefit plan, employee program or employee practice maintained or sponsored by the General Partner or any one of its Affiliates, in each case for the benefit of employees of the General Partner, any Group Member or any Affiliate, or any of them, in respect of services performed, directly or indirectly, for the benefit of the Partnership Group. The Partnership agrees to issue and sell to the General Partner or any of its Affiliates any Partnership Securities that the General

 

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Partner or such Affiliate is obligated to provide to any employees pursuant to any such employee benefit plans, employee programs or employee practices. Expenses incurred by the General Partner in connection with any such plans, programs and practices (including the net cost to the General Partner or such Affiliate of Partnership Securities purchased by the General Partner or such Affiliate from the Partnership to fulfill options or awards under such plans, programs and practices) shall be reimbursed in accordance with Section 7.4(b). Any and all obligations of the General Partner under any employee benefit plans, employee programs or employee practices adopted by the General Partner as permitted by this Section 7.4(c) shall constitute obligations of the General Partner hereunder and shall be assumed by any successor General Partner approved pursuant to Section 11.1 or 11.2 or the transferee of or successor to all of the General Partner’s General Partner Interest pursuant to Section 4.6.

Section 7.5 Outside Activities.

(a) After the Closing Date, the General Partner, for so long as it is the general partner of the Partnership (i) agrees that its sole business will be to act as the general partner or managing member, as the case may be, of the Partnership and any other partnership or limited liability company of which the Partnership is, directly or indirectly, a partner or managing member and to undertake activities that are ancillary or related thereto (including being a limited partner in the Partnership) and (ii) shall not engage in any business or activity or incur any debts or liabilities except in connection with or incidental to (A) its performance as general partner or managing member of one or more Group Members or as described in or contemplated by the Registration Statement, (B) the acquiring, owning or disposing of debt or equity securities in any Group Member; provided, however, that neither clause (i) or clause (ii) shall prohibit the General Partner from owning, directly or indirectly, limited partner interests or limited liability company interests in another Person.

(b) Except as specifically restricted by Section 7.5(a), each Group Member and Indemnitee shall have the right to engage in businesses of every type and description and other activities for profit and to engage in and possess an interest in other business ventures of any and every type or description, whether in businesses engaged in or anticipated to be engaged in by any Group Member, independently or with others, including business interests and activities in direct competition with the business and activities of any Group Member, and none of the same shall constitute a breach of this Agreement or any duty expressed or implied by law to any Group Member or any Partner. Neither any Group Member, any Limited Partner nor any other Person shall have any rights by virtue of this Agreement, the MLP Agreement or the partnership relationship established hereby or thereby in any business ventures of any Group Member or any Indemnitee.

(c) Subject to the terms of Sections 7.5(a) and 7.5(b), but otherwise notwithstanding anything to the contrary in this Agreement, (i) the engaging in competitive activities by any Group Member or any Indemnitee in accordance with the provisions of this Section 7.5 is hereby approved by the Partnership and all Partners, (ii) it shall be deemed not to be a breach of any fiduciary duties or any other obligation of any type whatsoever of the General Partner for any Group Member or any Indemnitee to engage in such business interests and activities in preference to or to the exclusion of the Partnership and (iii) none of the General Partner, any Group Member nor any Indemnitee shall have any obligation hereunder or as a result of any duty expressed or implied by law to present business opportunities to the Partnership, any other Group Member or any Indemnitee.

 

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(d) The General Partner and any of its Affiliates may acquire Units or other Partnership Securities in addition to those acquired on the Closing Date and, except as otherwise provided in this Agreement, shall be entitled to exercise all rights of a General Partner or Limited Partner, as applicable, relating to such Units or Partnership Securities.

(e) The term “ Affiliates ” when used in Section 7.5(d) with respect to the General Partner shall not include any Group Member or any Subsidiary of the Group Member.

(f) Anything in this Agreement to the contrary notwithstanding, to the extent that any provision of this Agreement purports or is interpreted to have the effect of limiting or restricting the fiduciary duties that might otherwise, as a result of Delaware or other applicable law, be owed by the General Partner, its Board of Directors or any committee thereof to the Partnership and its Limited Partners, each Limited Partner consents to such limitations and restrictions related to such fiduciary duties to the maximum extent that such consent is permitted under Delaware or other applicable law.

Section 7.6 Loans from the General Partner; Loans or Contributions from the Partnership; Contracts with Affiliates; Certain Restrictions on the General Partner.

(a) The General Partner or any of its Affiliates may, but shall be under no obligation to, lend to any Group Member, and any Group Member may borrow from the General Partner or any of its Affiliates, funds needed or desired by the Group Member for such periods of time and in such amounts as the General Partner may determine. Any loan made to a Group Member by the General Partner or any of its Affiliates shall be on terms that are fair and reasonable to the Partnership; provided, however, that the requirements of this Section 7.6(c) shall be deemed satisfied as to (i) any transaction approved by Special Approval, (ii) any transaction, the terms of which are no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or (iii) any transaction that, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership), is equitable to the Partnership. The borrowing party shall reimburse the lending party for any costs (other than any additional interest costs) incurred by the lending party in connection with the borrowing of such funds. For purposes of Sections 7.6(a) and 7.6(b), the term “ Group Member ” shall include any Affiliate of a Group Member that is controlled by the Group Member. No Group Member may lend funds to the General Partner or any of its Affiliates (other than another Group Member).

(b) The Partnership may lend or contribute to any Group Member, and any Group Member may borrow from the Partnership, funds on terms and conditions determined by the General Partner provided, however, that the Partnership may not charge the Group Member interest at a rate less than the rate that would be charged to the Group Member (without reference to the General Partner’s financial abilities or guarantees) by unrelated lenders on comparable loans. The foregoing authority shall be exercised by the General Partner in its sole discretion and shall not create any right or benefit in favor of any Group Member or any other Person.

 

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(c) No borrowing by any Group Member or the approval thereof by the General Partner shall be deemed to constitute a breach of any duty, expressed or implied, of the General Partner or its Affiliates to the Partnership or the Limited Partners by reason of the fact that the purpose or effect of such borrowing is directly or indirectly to (i) enable distributions to the General Partner or its Affiliates (including in their capacities as Limited Partners) to exceed the General Partner’s Percentage Interest of the total amount distributed to all partners.

(d) The General Partner may itself, or may enter into an agreement with any of its Affiliates to, render services to a Group Member or to the General Partner in the discharge of its duties as general partner of the Partnership. Any services rendered to a Group Member by the General Partner or any of its Affiliates shall be on terms that are fair and reasonable to the Partnership; provided, however, that the requirements of this Section 7.6(c) shall be deemed satisfied as to (i) any transaction approved by Special Approval, (ii) any transaction, the terms of which are no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or (iii) any transaction that, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership), is equitable to the Partnership. The provisions of Section 7.4 shall apply to the rendering of services described in this Section 7.6(c).

(e) The Partnership may transfer assets to joint ventures, other partnerships, corporations, limited liability companies or other business entities in which it is or thereby becomes a participant upon such terms and subject to such conditions as are consistent with this Agreement and applicable law.

(f) Neither the General Partner nor any of its Affiliates shall sell, transfer or convey any property to, or purchase any property from, the Partnership, directly or indirectly, except pursuant to transactions that are fair and reasonable to the Partnership; provided, however, that the requirements of this Section 7.7(f) shall be deemed to be satisfied as to (i) the transactions effected pursuant to Section 5.4 and any other transactions described in or contemplated by the Registration Statement, (ii) any transaction approved by Special Approval, (iii) any transaction, the terms of which are no less favorable to the Partnership than those generally being provided to or available from unrelated third parties, or (iv) any transaction that, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership), is equitable to the Partnership. With respect to any contribution of assets to the Partnership in exchange for Partnership Securities, the Conflicts Committee, in determining whether the appropriate number of Partnership Securities are being issued, may take into account, among other things, the fair market value of the assets, the liquidated and contingent liabilities assumed, the tax basis in the assets, the extent to which tax-only allocations to the transferor will protect the existing partners of the Partnership against a low tax basis, and such other factors as the Conflicts Committee deems relevant under the circumstances.

(g) The General Partner and its Affiliates will have no obligation to permit any Group Member to use any facilities or assets of the General Partner and its Affiliates, except as may be provided in contracts entered into from time to time specifically dealing with such use, nor shall there be any obligation on the part of the General Partner or its Affiliates to enter into such contracts.

 

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(h) Without limitation of Sections 7.6(a) through 7.6(g), and notwithstanding anything to the contrary in this Agreement, the existence of the conflicts of interest described in the Registration Statement are hereby approved by all Partners.

Section 7.7 Indemnification.

(a) To the maximum extent permitted by law but subject to the limitations expressly provided in this Agreement, all Indemnitees shall be indemnified and held harmless by the Partnership from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which any Indemnitee may be involved, or is threatened to be involved, as a party or otherwise, by reason of its status as an Indemnitee; provided, that the Indemnitee shall not be indemnified and held harmless if there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Section 7.7, the Indemnitee acted in bad faith or engaged in fraud, willful misconduct, or in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was unlawful; provided, further, no indemnification pursuant to this Section 7.7 shall be available to the General Partner or its Affiliates (other than a Group Member) with respect to its or their obligations incurred pursuant to the Underwriting Agreement (other than obligations incurred by the General Partner on behalf of the Partnership). Any indemnification pursuant to this Section 7.7 shall be made only out of the assets of the Partnership, it being agreed that the General Partner shall not be personally liable for such indemnification and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate such indemnification.

(b) To the maximum extent permitted by law, expenses (including legal fees and expenses) incurred by an Indemnitee who is indemnified pursuant to Section 7.7(a) in defending any claim, demand, action, suit or proceeding shall, from time to time, be advanced by the Partnership prior to a determination that the Indemnitee is not entitled to be indemnified upon receipt by the Partnership of any undertaking by or on behalf of the Indemnitee to repay such amount if it shall be determined that the Indemnitee is not entitled to be indemnified as authorized in this Section 7.7.

(c) The indemnification provided by this Section 7.7 shall be in addition to any other rights to which an Indemnitee may be entitled under any agreement, pursuant to any vote of the holders of Outstanding Limited Partner Interests entitled to vote on such matter, as a matter of law or otherwise, both as to actions in the Indemnitee’s capacity as an Indemnitee and as to actions in any other capacity (including any capacity under the Underwriting Agreement), and shall continue as to an Indemnitee who has ceased to serve in such capacity and shall inure to the benefit of the heirs, successors, assigns and administrators of the Indemnitee.

(d) The Partnership may purchase and maintain (or reimburse the General Partner or its Affiliates for the cost of) insurance, on behalf of the General Partner, its Affiliates and such other Persons as the General Partner shall determine, against any liability that may be asserted against, or expense that may be incurred by, such Person in connection with the Partnership’s activities or such Person’s activities on behalf of the Partnership, regardless of whether the Partnership would have the power to indemnify such Person against such liability under the provisions of this Agreement.

 

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(e) For purposes of this Section 7.7, the Partnership shall be deemed to have requested an Indemnitee to serve as fiduciary of an employee benefit plan whenever the performance by it of its duties to the Partnership also imposes duties on, or otherwise involves services by, it to the plan or participants or beneficiaries of the plan; excise taxes assessed on an Indemnitee with respect to an employee benefit plan pursuant to applicable law shall constitute “ fines” within the meaning of Section 7.7(a); and action taken or omitted by it with respect to any employee benefit plan in the performance of its duties for a purpose reasonably believed by it to be in the best interest of the participants and beneficiaries of the plan shall be deemed to be for a purpose that is in the best interests of the Partnership.

(f) In no event may an Indemnitee subject the Limited Partners to personal liability by reason of the indemnification provisions set forth in this Agreement.

(g) An Indemnitee shall not be denied indemnification in whole or in part under this Section 7.7 because the Indemnitee had an interest in the transaction with respect to which the indemnification applies if the transaction was otherwise permitted by the terms of this Agreement.

(h) The provisions of this Section 7.7 are for the benefit of the Indemnitees, their heirs, successors, assigns and administrators and shall not be deemed to create any rights for the benefit of any other Persons.

(i) No amendment, modification or repeal of this Section 7.7 or any provision hereof shall in any manner terminate, reduce or impair the right of any past, present or future Indemnitee to be indemnified by the Partnership, nor the obligations of the Partnership to indemnify any such Indemnitee under and in accordance with the provisions of this Section 7.7 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.8 Liability of Indemnitees.

(a) Notwithstanding anything to the contrary set forth in this Agreement, no Indemnitee shall be liable for monetary damages to the Partnership, the Limited Partners, the Assignees or any other Persons who have acquired interests in the Partnership Securities, for losses sustained or liabilities incurred as a result of any act or omission of an Indemnitee unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter in question, the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was criminal.

(b) Subject to its obligations and duties as General Partner set forth in Section 7.1(a), the General Partner may exercise any of the powers granted to it by this Agreement and perform any of the duties imposed upon it hereunder either directly or by or through its agents, and the General Partner shall not be responsible for any misconduct or negligence on the part of any such agent appointed by the General Partner in good faith.

 

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(c) To the extent that, at law or in equity, an Indemnitee has duties (including fiduciary duties) and liabilities relating thereto to the Partnership or to the Partners, the General Partner and any other Indemnitee acting in connection with the Partnership’s business or affairs shall not be liable to the Partnership or to any Partner for its good faith reliance on the provisions of this Agreement.

(d) Any amendment, modification or repeal of this Section 7.8 or any provision hereof shall be prospective only and shall not in any way affect the limitations on the liability of the Indemnitees under this Section 7.8 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted, and provided such Person became an Indemnitee hereunder prior to such amendment, modification or repeal.

Section 7.9 Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties.

(a) Unless otherwise expressly provided in this Agreement, whenever a potential conflict of interest exists or arises between the General Partner or any of its Affiliates, on the one hand, and the Partnership, any Group Member, any Partner or any Assignee, on the other, any resolution or course of action by the General Partner or its Affiliates in respect of such conflict of interest shall be permitted and deemed approved by all Partners, and shall not constitute a breach of this Agreement or of any agreement contemplated herein or therein, or of any duty stated or implied by law or equity, if the resolution or course of action in respect of such conflict of interest is (i) approved by Special Approval, (ii) approved by the vote of a majority of the Common Units (excluding Common Units owned by the General Partner and its Affiliates), (iii) on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or (iv) fair and reasonable to the Partnership, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership). The General Partner shall be authorized but not required in connection with its resolution of such conflict of interest to seek Special Approval of such resolution, and the General Partner may also adopt a resolution or course of action that has not received Special Approval. If Special Approval is not sought and the Board of Directors of the General Partner determines that the resolution or course of action taken with respect to a conflict of interest satisfies either of the standards set forth in clauses (iii) or (iv) above, then it shall be presumed that, in making its decision, the Board of Directors acted in good faith, and in any proceeding brought by any Limited Partner or Assignee or by or on behalf of such Limited Partner or Assignee or any other Limited Partner or Assignee or the Partnership challenging such approval, the Person bringing or prosecuting such proceeding shall have the burden of overcoming such presumption. Notwithstanding anything to the contrary in this Agreement or any duty otherwise existing at law or equity, the existence of the conflicts of interest described in the Registration Statement are hereby approved by all Partners and shall not constitute a breach of this Agreement.

 

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(b) Whenever the General Partner makes a determination or takes or declines to take any other action, or any of its Affiliates causes it to do so, in its capacity as the general partner of the Partnership as opposed to in its individual capacity, whether under this Agreement, or any other agreement contemplated hereby or otherwise, then unless another express standard is provided for in this Agreement, the General Partner, or such Affiliates causing it to do so, shall make such determination or take or decline to take such other action in good faith and shall not be subject to any other or different standards imposed by this Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. In order for a determination or other action to be in “ good faith ” for purposes of this Agreement, the Person or Persons (including the Board of Directors or any committee thereof acting on behalf of the General Partner) making such determination or taking or declining to take such other action must believe that the determination or other action is in the best interests of the Partnership.

(c) Whenever the General Partner (including the Board of Directors or any committee thereof acting on behalf of the General Partner) makes a determination or takes or declines to take any other action, or any of its Affiliates causes it to do so, in its individual capacity as opposed to in its capacity as a general partner of the Partnership, whether under this Agreement or any other agreement contemplated hereby or otherwise, then the General Partner (including the Board of Directors or any committee thereof acting on behalf of the General Partner), or such Affiliates causing it to do so, are entitled to make such determination or to take or decline to take such other action free of any fiduciary duty or obligation whatsoever to the Partnership, any Limited Partner or Assignee, and the General Partner (including the Board of Directors or any committee thereof acting on behalf of the General Partner), or such Affiliates causing it to do so, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. By way of illustration and not of limitation, whenever the phrase, “ at the option of the General Partner,” or some variation of that phrase, is used in this Agreement, it indicates that the General Partner is acting in its individual capacity. For the avoidance of doubt, whenever the General Partner votes or transfers its Units, or refrains from voting or transferring its Units, it shall be acting in its individual capacity. The General Partner’s organizational documents may provide that determinations to take or decline to take any action in its individual, rather than representative, capacity may or shall be determined by its members, if the General Partner is a limited liability company, stockholders, if the General Partner is a corporation, or the members or stockholders of the General Partner’s general partner, if the General Partner is a limited partnership.

(d) Notwithstanding anything to the contrary in this Agreement, none of the General Partner and its Affiliates, nor the Board of Directors or any committee thereof, shall have any duty or obligation, express or implied, to (i) sell or otherwise dispose of any asset of the Partnership Group other than in the ordinary course of business or (ii) permit any Group Member to use any facilities or assets of the General Partner and its Affiliates, except as may be provided in contracts entered into from time to time specifically dealing with such use. Any determination by the General Partner or any of its Affiliates to enter into such contracts shall be at its option.

 

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(e) Except as expressly set forth in this Agreement, none of the General Partner, the Board of Directors, any committee of the Board of Directors nor any other Indemnitee shall have any duties or liabilities, including fiduciary duties, to the Partnership or any Limited Partner or Assignee. The provisions of this Agreement, to the extent that they restrict, eliminate or otherwise modify the duties and liabilities, including fiduciary duties, of the General Partner or any other Indemnitee otherwise existing at law or in equity, are agreed by the Partners to replace such other duties and liabilities of the General Partner, the Board of Directors, any committee of the Board of Directors or such other Indemnitee.

(f) The Unitholders hereby authorize the General Partner, on behalf of the Partnership as a partner or member of a Group Member, to approve of actions by the general partner or managing member of such Group Member similar to those actions permitted to be taken by the General Partner pursuant to this Section 7.9.

Section 7.10 Other Matters Concerning the General Partner.

(a) The General Partner (including the Board of Directors or any committee thereof acting on behalf of the General Partner) may rely and shall be protected in acting or refraining from acting upon any resolution, certificate, statement, instrument, opinion, report, notice, request, consent, order, bond, debenture or other paper or document believed by it to be genuine and to have been signed or presented by the proper party or parties.

(b) The General Partner (including the Board of Directors or any committee thereof acting on behalf of the General Partner) may consult with legal counsel, accountants, appraisers, management consultants, investment bankers and other consultants and advisers selected by it, and any act taken or omitted to be taken in reliance upon the opinion (including an Opinion of Counsel) of such Persons as to matters that the General Partner (including the Board of Directors or any committee thereof acting on behalf of the General Partner) reasonably believes to be within such Person’s professional or expert competence shall be conclusively presumed to have been done or omitted in good faith and in accordance with such opinion.

(c) The General Partner (including the Board of Directors or any committee thereof acting on behalf of the General Partner) shall have the right, in respect of any of its powers or obligations hereunder, to act through any of its duly authorized officers, a duly appointed attorney or attorneys-in-fact or the duly authorized officers of the Partnership. Each such attorney shall, to the extent provided by the General Partner (including the Board of Directors or any committee thereof acting on behalf of the General Partner) in the power of attorney, have full power and authority to do and perform each and every act and duty that is permitted or required to be done by the General Partner (including the Board of Directors or any committee thereof acting on behalf of the General Partner) hereunder.

Section 7.11 Purchase or Sale of Partnership Securities.

The General Partner may cause the Partnership to purchase or otherwise acquire Partnership Securities, which shall be held by the Partnership as treasury securities unless they are expressly canceled by action of an appropriate officer of the General Partner. As long as Partnership Securities are held by any Group Member, such Partnership Securities shall not be considered Outstanding for any purpose, except as otherwise provided herein. The General Partner or any of its Affiliates may also purchase or otherwise acquire and sell or otherwise dispose of Partnership Securities for their own account, subject to the provisions of Articles IV and X.

 

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Section 7.12 Registration Rights of the General Partner and its Affiliates.

(a) If (i) the General Partner or any Affiliate of the General Partner (including for purposes of this Section 7.12, any Person that is an Affiliate of the General Partner at the date hereof notwithstanding that it may later cease to be an Affiliate of the General Partner) holds Partnership Securities that it desires to sell and (ii) Rule 144 of the Securities Act (or any successor rule or regulation to Rule 144) or another exemption from registration is not available to enable such holder of Partnership Securities (the “ Holder ”) to dispose of the number of Partnership Securities it desires to sell at the time it desires to do so without registration under the Securities Act, then at the option and upon the request of the Holder, the Partnership shall file with the Commission as promptly as practicable after receiving such request, and use all commercially reasonable efforts to cause to become effective and remain effective for a period of not less than six months following its effective date or such shorter period as shall terminate when all Partnership Securities covered by such registration statement have been sold, a registration statement under the Securities Act registering the offering and sale of the number of Partnership Securities specified by the Holder; provided, however, that the Partnership shall not be required to effect more than three registrations pursuant to this Section 7.12(a) and Section 7.12(b); and provided further, however, that if the Conflicts Committee determines in good faith that the requested registration would be materially detrimental to the Partnership and its Partners because such registration would (x) materially interfere with a significant acquisition, reorganization or other similar transaction involving the Partnership, (y) require premature disclosure of material information that the Partnership has a bona fide business purpose for preserving as confidential or (z) render the Partnership unable to comply with requirements under applicable securities laws, then the Partnership shall have the right to postpone such requested registration for a period of not more than six months after receipt of the Holder’s request, such right pursuant to this Section 7.12(a) or Section 7.12(b) not to be utilized more than once in any twelve-month period. Except as provided in the preceding sentence, the Partnership shall be deemed not to have used all reasonable efforts to keep the registration statement effective during the applicable period if it voluntarily takes any action that would result in Holders of Partnership Securities covered thereby not being able to offer and sell such Partnership Securities at any time during such period, unless such action is required by applicable law. In connection with any registration pursuant to the immediately preceding sentence, the Partnership shall (i) promptly prepare and file (A) such documents as may be necessary to register or qualify the securities subject to such registration under the securities laws of such states as the Holder shall reasonably request; provided, however, that no such qualification shall be required in any jurisdiction where, as a result thereof, the Partnership would become subject to general service of process or to taxation or qualification to do business as a foreign corporation or partnership doing business in such jurisdiction solely as a result of such registration, and (B) such documents as may be necessary to apply for listing or to list the Partnership Securities subject to such registration on such National Securities Exchange as the Holder shall reasonably request, and (ii) do any and all other acts and things that may be necessary or appropriate to enable the Holder to consummate a public sale of such Partnership Securities in such states. Except as set forth in Section 7.12(d), all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

 

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(b) If any Holder holds Partnership Securities that it desires to sell and Rule 144 of the Securities Act (or any successor rule or regulation to Rule 144) or another exemption from registration is not available to enable such Holder to dispose of the number of Partnership Securities it desires to sell at the time it desires to do so without registration under the Securities Act, then at the option and upon the request of the Holder, the Partnership shall file with the Commission as promptly as practicable after receiving such request, and use all commercially reasonable efforts to cause to become effective and remain effective for a period of not less than six months following its effective date or such shorter period as shall terminate when all Partnership Securities covered by such shelf registration statement have been sold, a “ shelf ” registration statement covering the Partnership Securities specified by the Holder on an appropriate form under Rule 415 under the Securities Act, or any similar rule that may be adopted by the Commission; provided, however, that the Partnership shall not be required to effect more than three registrations pursuant to Section 7.12(a) and this Section 7.12(b); and provided further, however, that if the Audit and Conflicts Committee determines in good faith that any offering under, or the use of any prospectus forming a part of, the shelf registration statement would be materially detrimental to the Partnership and its Partners because such offering or use would (x) materially interfere with a significant acquisition, reorganization or other similar transaction involving the Partnership, (y) require premature disclosure of material information that the Partnership has a bona fide business purpose for preserving as confidential or (z) render the Partnership unable to comply with requirements under applicable securities laws, then the Partnership shall have the right to suspend such offering or use for a period of not more than six months after receipt of the Holder’s request, such right pursuant to Section 7.12(a) or this Section 7.12(b) not to be utilized more than once in any twelve-month period. Except as provided in the preceding sentence, the Partnership shall be deemed not to have used all commercially reasonable efforts to keep the shelf registration statement effective during the applicable period if it voluntarily takes any action that would result in Holders of Partnership Securities covered thereby not being able to offer and sell such Partnership Securities at any time during such period, unless such action is required by applicable law. In connection with any shelf registration pursuant to this Section 7.12(b), the Partnership shall (i) promptly prepare and file (A) such documents as may be necessary to register or qualify the securities subject to such shelf registration under the securities laws of such states as the Holder shall reasonably request; provided, however, that no such qualification shall be required in any jurisdiction where, as a result thereof, the Partnership would become subject to general service of process or to taxation or qualification to do business as a foreign corporation or partnership doing business in such jurisdiction solely as a result of such shelf registration, and (B) such documents as may be necessary to apply for listing or to list the Partnership Securities subject to such shelf registration on such National Securities Exchange as the Holder shall reasonably request, and (ii) do any and all other acts and things that may be necessary or appropriate to enable the Holder to consummate a public sale of such Partnership Securities in such states. Except as set forth in Section 7.12(d), all costs and expenses of any such shelf registration and offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

 

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(c) If the Partnership shall at any time propose to file a registration statement under the Securities Act for an offering of equity securities of the Partnership for cash (other than an offering relating solely to an employee benefit plan), the Partnership shall use all commercially reasonable efforts to include such number or amount of securities held by any Holder in such registration statement as the Holder shall request; provided, that the Partnership is not required to make any effort or take an action to so include the securities of the Holder once the registration statement becomes or is declared effective by the Commission, including any registration statement providing for the offering from time to time of securities pursuant to Rule 415 of the Securities Act. If the proposed offering pursuant to this Section 7.12(c) shall be an underwritten offering, then, in the event that the managing underwriter or managing underwriters of such offering advise the Partnership and the Holder in writing that in their opinion the inclusion of all or some of the Holder’s Partnership Securities would adversely and materially affect the success of the offering, the Partnership shall include in such offering only that number or amount, if any, of securities held by the Holder that, in the opinion of the managing underwriter or managing underwriters, will not so adversely and materially affect the offering. Except as set forth in Section 7.12(d), all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

(d) If underwriters are engaged in connection with any registration referred to in this Section 7.12, the Partnership shall provide indemnification, representations, covenants, opinions and other assurance to the underwriters in form and substance reasonably satisfactory to such underwriters. Further, in addition to and not in limitation of the Partnership’s obligation under Section 7.7, the Partnership shall, to the maximum extent permitted by law, indemnify and hold harmless the Holder, its officers, directors and each Person who controls the Holder (within the meaning of the Securities Act) and any agent thereof (collectively, “ Indemnified Persons ”) from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which any Indemnified Person may be involved, or is threatened to be involved, as a party or otherwise, under the Securities Act or otherwise (hereinafter referred to in this Section 7.12(d) as a “ claim ” and in the plural as “ claims ”) based upon, arising out of or resulting from any untrue statement or alleged untrue statement of any material fact contained in any registration statement under which any Partnership Securities were registered under the Securities Act or any state securities or Blue Sky laws, in any preliminary prospectus (if used prior to the effective date of such registration statement), or in any summary or final prospectus or in any amendment or supplement thereto (if used during the period the Partnership is required to keep the registration statement current), or arising out of, based upon or resulting from the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements made therein not misleading; provided, however, that the Partnership shall not be liable to any Indemnified Person to the extent that any such claim arises out of, is based upon or results from an untrue statement or alleged untrue statement or omission or alleged omission made in such registration statement, such preliminary, summary or final prospectus or such amendment or supplement, in reliance upon and in conformity with written information furnished to the Partnership by or on behalf of such Indemnified Person specifically for use in the preparation thereof.

 

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(e) The provisions of Sections 7.12(a), 7.12(b) and 7.12(c) shall continue to be applicable with respect to the General Partner (and any of the General Partner’s Affiliates) after it ceases to be a general partner of the Partnership, during a period of two years subsequent to the effective date of such cessation and for so long thereafter as is required for the Holder to sell all of the Partnership Securities with respect to which it has requested during such two-year period inclusion in a registration statement otherwise filed or that a registration statement be filed; provided, however, that the Partnership shall not be required to file successive registration statements covering the same Partnership Securities for which registration was demanded during such two-year period. The provisions of Section 7.12(d) shall continue in effect thereafter.

(f) The rights to cause the Partnership to register Partnership Securities pursuant to this Section 7.12 may be assigned (but only with all related obligations) by a Holder to a transferee or assignee of such Partnership Securities, provided (i) the Partnership is, within a reasonable time after such transfer, furnished with written notice of the name and address of such transferee or assignee and the Partnership Securities with respect to which such registration rights are being assigned; and (ii) such transferee or assignee agrees in writing to be bound by and subject to the terms set forth in this Section 7.12.

(g) Any request to register Partnership Securities pursuant to this Section 7.12 shall (i) specify the Partnership Securities intended to be offered and sold by the Person making the request, (ii) express such Person’s present intent to offer such Partnership Securities for distribution, (iii) describe the nature or method of the proposed offer and sale of Partnership Securities, and (iv) contain the undertaking of such Person to provide all such information and materials and take all action as may be required in order to permit the Partnership to comply with all applicable requirements in connection with the registration of such Partnership Securities.

Section 7.13 Reliance by Third Parties.

Notwithstanding anything to the contrary in this Agreement, any Person dealing with the Partnership shall be entitled to assume that the General Partner and any officer of the General Partner authorized by the General Partner to act on behalf of and in the name of the Partnership has full power and authority to encumber, sell or otherwise use in any manner any and all assets of the Partnership and to enter into any authorized contracts on behalf of the Partnership, and such Person shall be entitled to deal with the General Partner or any such officer as if it were the Partnership’s sole party in interest, both legally and beneficially. Each Limited Partner hereby waives any and all defenses or other remedies that may be available against such Person to contest, negate or disaffirm any action of the General Partner or any such officer in connection with any such dealing. In no event shall any Person dealing with the General Partner or any such officer or its representatives be obligated to ascertain that the terms of the Agreement have been complied with or to inquire into the necessity or expedience of any act or action of the General Partner or any such officer or its representatives. Each and every certificate, document or other instrument executed on behalf of the Partnership by the General Partner or any such officer or its representatives shall be conclusive evidence in favor of any and every Person relying thereon or claiming thereunder that (a) at the time of the execution and delivery of such certificate, document or instrument, this Agreement was in full force and effect, (b) the Person executing and delivering such certificate, document or instrument was duly authorized and empowered to do so for and on behalf of the Partnership and (c) such certificate, document or instrument was duly executed and delivered in accordance with the terms and provisions of this Agreement and is binding upon the Partnership.

 

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ARTICLE VIII

BOOKS, RECORDS, ACCOUNTING AND REPORTS

Section 8.1 Records and Accounting.

The General Partner shall keep or cause to be kept at the principal office of the Partnership appropriate books and records with respect to the Partnership’s business, including all books and records necessary to provide to the Limited Partners any information required to be provided pursuant to Section 3.4(a). Any books and records maintained by or on behalf of the Partnership in the regular course of its business, including the record of the Record Holders of Units or other Partnership Securities, books of account and records of Partnership proceedings, may be kept on, or be in the form of, computer disks, hard drives, punch cards, magnetic tape, photographs, micrographics or any other information storage device; provided, that the books and records so maintained are convertible into clearly legible written form within a reasonable period of time. The books of the Partnership shall be maintained, for financial reporting purposes, on an accrual basis in accordance with U.S. GAAP.

Section 8.2 Fiscal Year.

The fiscal year of the Partnership shall be a fiscal year ending August 31.

Section 8.3 Reports.

(a) As soon as practicable, but in no event later than 120 days after the close of each fiscal year of the Partnership, the General Partner shall cause to be mailed or made available, by any reasonable means (including posting on the Partnership’s website), to each Record Holder of a Unit as of a date selected by the General Partner, an annual report containing financial statements of the Partnership for such fiscal year of the Partnership, presented in accordance with U.S. GAAP, including a balance sheet and statements of operations, Partnership equity and cash flows, such statements to be audited by a firm of independent public accountants selected by the General Partner.

(b) As soon as practicable, but in no event later than 90 days after the close of each Quarter except the last Quarter of each fiscal year, the General Partner shall cause to be mailed or made available, by any reasonable means (including posting on the Partnership’s website), to each Record Holder of a Unit, as of a date selected by the General Partner, a report containing unaudited financial statements of the Partnership and such other information as may be required by applicable law, regulation or rule of any National Securities Exchange on which the Units are listed or admitted for trading, or as the General Partner determines to be necessary or appropriate.

 

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ARTICLE IX

TAX MATTERS

Section 9.1 Tax Returns and Information.

The Partnership shall timely file all returns of the Partnership that are required for federal, state and local income tax purposes on the basis of the accrual method and a taxable year ending on December 31. The tax information reasonably required by Record Holders for federal and state income tax reporting purposes with respect to a taxable year shall be furnished to them within 90 days of the close of the calendar year in which the Partnership’s taxable year ends. The classification, realization and recognition of income, gain, losses and deductions and other items shall be on the accrual method of accounting for federal income tax purposes.

Section 9.2 Tax Elections.

(a) The Partnership shall make the election under Section 754 of the Code in accordance with applicable regulations thereunder, subject to the reservation of the right to seek to revoke any such election upon the General Partner’s determination that such revocation is in the best interests of the Limited Partners. Notwithstanding any other provision herein contained, for the purposes of computing the adjustments under Section 743(b) of the Code, the General Partner shall be authorized (but not required) to adopt a convention whereby the price paid by a transferee of a Limited Partner Interest will be deemed to be the lowest quoted closing price of the Limited Partner Interests on any National Securities Exchange on which such Limited Partner Interests are listed or admitted for trading during the calendar month in which such transfer is deemed to occur pursuant to Section 6.2(g) without regard to the actual price paid by such transferee.

(b) Except as otherwise provided herein, the General Partner shall determine whether the Partnership should make any other elections permitted by the Code.

Section 9.3 Tax Controversies.

Subject to the provisions hereof, the General Partner is designated as the Tax Matters Partner (as defined in the Code) and is authorized and required to represent the Partnership (at the Partnership’s expense) in connection with all examinations of the Partnership’s affairs by tax authorities, including resulting administrative and judicial proceedings, and to expend Partnership funds for professional services and costs associated therewith. Each Partner agrees to cooperate with the General Partner and to do or refrain from doing any or all things reasonably required by the General Partner to conduct such proceedings.

Section 9.4 Withholding.

Notwithstanding any other provision of this Agreement, the General Partner is authorized to take any action that may be required to cause the Partnership to comply with any withholding requirements established under the Code or any other federal, state or local law including, without limitation, pursuant to Sections 1441, 1442, 1445 and 1446 of the Code. To the extent that the Partnership is required or elects to withhold and pay over to any taxing authority any amount resulting from the allocation or distribution of income to any Partner (including, without limitation, by reason of Section 1446 of the Code), the General Partner may treat the amount withheld as a distribution of cash pursuant to Section 6.3 in the amount of such withholding from such Partner.

 

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ARTICLE X

ADMISSION OF PARTNERS

Section 10.1 Admission of Substituted Limited Partners.

(a) By acceptance of the transfer of any Limited Partner Interests in accordance with this Section 10.1(a) or the issuance of any Limited Partner Interests in a merger or consolidation pursuant to Article XIV, and except as provided in Section 10.1(b), each transferee of a Limited Partner Interest (including any nominee holder or an agent or representative acquiring such Limited Partner Interests for the account of another Person) (i) shall be admitted to the Partnership as a Limited Partner with respect to the Limited Partner Interests so transferred to such Person when any such transfer or admission is reflected in the books and records of the Partnership, with or without execution of this Agreement, (ii) shall become bound by the terms of, and shall be deemed to have executed, this Agreement, (iii) shall become the Record Holder of the Limited Partner Interests so transferred, (iv) represents that the transferee has the capacity, power and authority to enter into this Agreement, (v) grants the powers of attorney set forth in this Agreement and (vi) makes the consents and waivers contained in this Agreement. The transfer of any Limited Partner Interests and the admission of any new Limited Partner shall not constitute and amendment to this Agreement. Except as provided in Section 10.1(b), a Person may become a Record Holder of a Limited Partner Interest without the consent or approval of any of the Partners. A Person may not become a Limited Partner without acquiring a Limited Partner Interest and until such Person is reflected in the books and records of the Partnership as the Record Holder of such Limited Partner Interest. The rights and obligations of a Person who is an Ineligible Assignee shall be determined in accordance with Section 10.1(b).

(b) Following a FERC Notice, (i) clause (i) of Section 10.1(a) shall no longer be applicable, (ii) the transferor of a Limited Partner Interest made in accordance with Article IV shall be deemed to have given the transferee the right to seek admission as a Substituted Limited Partner subject to the conditions of, and in the manner permitted under, this Agreement and (iii) a transferor of a Certificate representing a Limited Partner Interest shall only have the authority to convey to a purchaser or other transferee who does not execute and deliver a Transfer Application (a) the right to negotiate such Certificate to a purchaser or other transferee and (b) the right to transfer the right to request admission as a Substituted Limited Partner to such purchaser or other transferee in respect of the transferred Limited Partner Interests. No transferor of a Limited Partnership Interest or other Person shall have any obligation or responsibility to provide a Transfer Application to a transferee or assist or participate in any way with respect to the completion or delivery thereof. Following a FERC Notice, each transferee of a Limited Partner Interest (including any nominee holder or an agent acquiring such Limited Partner Interest for the account of another Person) who executes and delivers a properly completed Transfer Application, containing a properly completed and executed Taxation Certification, shall, by virtue of such execution and delivery, be an Assignee. Such Assignee shall automatically be admitted to the Partnership as a Substituted Limited Partner with respect to the Limited Partner Interests so transferred to such Person at such time as such transfer is recorded in the books and records of the Partnership, and until so recorded, such transferee shall be an Assignee. The General Partner shall periodically, but no less frequently than on the first Business Day of each calendar quarter, cause any unrecorded transfers of Limited Partner

 

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Interests with respect to which a properly completed, duly executed Transfer Application, including the accompanying Taxation Certification, has been received to be recorded in the books and records of the Partnership. An Assignee shall have an interest in the Partnership equivalent to that of a Limited Partner with respect to allocations and distributions, including liquidating distributions, of the Partnership. With respect to voting rights attributable to Limited Partner Interests that are held by Assignees, the General Partner shall be deemed to be the Limited Partner with respect thereto and shall, in exercising the voting rights in respect of such Limited Partner Interests on any matter, vote such Limited Partner Interests at the written direction of the Assignee who is the Record Holder of such Limited Partner Interests. If no such written direction is received, such Limited Partner Interests will not be voted. An Assignee shall have no other rights of a Limited Partner.

Section 10.2 Admission of Successor General Partner.

A successor General Partner approved pursuant to Section 11.1 or 11.2 or the transferee of or successor to all of the General Partner Interest pursuant to Section 4.6 who is proposed to be admitted as a successor General Partner shall be admitted to the Partnership as the General Partner effective immediately prior to the withdrawal or removal of the predecessor or transferring General Partner pursuant to Section 11.1 or 11.2 or the transfer of such General Partner’s General Partner Interest pursuant to Section 4.6; provided, however, that no such successor shall be admitted to the Partnership until compliance with the terms of Section 4.6 has occurred and such successor has executed and delivered such other documents or instruments as may be required to effect such admission. Any such successor shall, subject to the terms hereof, carry on the business of the Partnership without dissolution.

Section 10.3 Admission of Additional Limited Partners.

(a) A Person (other than the General Partner, an Initial Limited Partner or a Substituted Limited Partner) who makes a Capital Contribution to the Partnership in accordance with this Agreement shall be admitted to the Partnership as an Additional Limited Partner only upon furnishing to the General Partner:

(i) evidence of acceptance in form satisfactory to the General Partner of all of the terms and conditions of this Agreement, including the power of attorney granted in Section 2.6,

(ii) following a FERC Notice, a properly completed Taxation Certification; and

(iii) such other documents or instruments as may be required by the General Partner to effect such Person’s admission as an Additional Limited Partner.

(b) Notwithstanding anything to the contrary in this Section 10.3, no Person shall be admitted as an Additional Limited Partner without the consent of the General Partner. The admission of any Person as an Additional Limited Partner shall become effective on the date upon which the name of such Person is recorded as such in the books and records of the Partnership, following the consent of the General Partner to such admission.

 

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Section 10.4 Amendment of Agreement and Certificate of Limited Partnership.

To effect the admission to the Partnership of any Partner, the General Partner shall take all steps necessary and appropriate under the Delaware Act to amend the records of the Partnership to reflect such admission and, if necessary, to prepare as soon as practicable an amendment to this Agreement and, if required by law, the General Partner shall prepare and file an amendment to the Certificate of Limited Partnership, and the General Partner may for this purpose, among others, exercise the power of attorney granted pursuant to Section 2.6.

ARTICLE XI

WITHDRAWAL OR REMOVAL OF PARTNERS

Section 11.1 Withdrawal of the General Partner.

(a) The General Partner shall be deemed to have withdrawn from the Partnership upon the occurrence of any one of the following events (each such event herein referred to as an “ Event of Withdrawal ”):

(i) the General Partner voluntarily withdraws from the Partnership by giving written notice to the other Partners;

(ii) the General Partner transfers all of its rights as General Partner pursuant to Section 4.6;

(iii) the General Partner is removed pursuant to Section 11.2;

(iv) the General Partner (A) makes a general assignment for the benefit of creditors; (B) files a voluntary bankruptcy petition for relief under Chapter 7 of the United States Bankruptcy Code; (C) files a petition or answer seeking for itself a liquidation, dissolution or similar relief (but not a reorganization) under any law; (D) files an answer or other pleading admitting or failing to contest the material allegations of a petition filed against the General Partner in a proceeding of the type described in clauses (A)-(C) of this Section 11.1(a)(iv); or (E) seeks, consents to or acquiesces in the appointment of a trustee (but not a debtor-in-possession), receiver or liquidator of the General Partner or of all or any substantial part of its properties;

(v) a final and non-appealable order of relief under Chapter 7 of the United States Bankruptcy Code is entered by a court with appropriate jurisdiction pursuant to a voluntary or involuntary petition by or against the General Partner; or

(vi) (A) in the event the General Partner is a corporation, a certificate of dissolution or its equivalent is filed for the General Partner, or 90 days expire after the date of notice to the General Partner of revocation of its charter without a reinstatement of its charter, under the laws of its state of incorporation; (B) in the event the General Partner is a partnership or a limited liability company, the dissolution and commencement of winding up of the General Partner; (C) in the event the General Partner is acting in such capacity by virtue of being a trustee of a trust, the termination of the trust; (D) in the event the General Partner is a natural person, his death or adjudication of incompetency; and (E) otherwise in the event of the termination of the General Partner.

 

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If an Event of Withdrawal specified in Section 11.1(a)(iv), (v) or (vi)(A), (B), (C) or (E) occurs, the withdrawing General Partner shall give notice to the Limited Partners within 30 days after such occurrence. The Partners hereby agree that only the Events of Withdrawal described in this Section 11.1 shall result in the withdrawal of the General Partner from the Partnership.

(b) Withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall not constitute a breach of this Agreement under the following circumstances: (i) at any time during the period beginning on the Closing Date and ending at 12:00 midnight, Central Standard Time, on December 31, 2015, the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to the Limited Partners; provided that prior to the effective date of such withdrawal, the withdrawal is approved by Unitholders holding at least a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates) and the General Partner delivers to the Partnership an Opinion of Counsel (“ Withdrawal Opinion of Counsel ”) that such withdrawal (following the selection of the successor General Partner) would not result in the loss of the limited liability of any Limited Partner or any Group Member or cause any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated or taxed as such); (ii) at any time after 12:00 midnight, Central Standard Time, on December 31, 2015, the General Partner voluntarily withdraws by giving at least 90 days’ advance notice to the Unitholders, such withdrawal to take effect on the date specified in such notice; (iii) at any time that the General Partner ceases to be the General Partner pursuant to Section 11.1(a)(ii) or is removed pursuant to Section 11.2; or (iv) notwithstanding clause (i) of this sentence, at any time that the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to the Limited Partners, such withdrawal to take effect on the date specified in the notice, if at the time such notice is given one Person and its Affiliates (other than the General Partner and its Affiliates) own beneficially or of record or control at least 50% of the Outstanding Units. The withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall also constitute the withdrawal of the General Partner as general partner or managing member, to the extent applicable, of the other Group Members. If the General Partner gives a notice of withdrawal pursuant to Section 11.1(a)(i), the holders of a Unit Majority, may, prior to the effective date of such withdrawal, elect a successor General Partner. The Person so elected as successor General Partner shall automatically become the successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If, prior to the effective date of the General Partner’s withdrawal pursuant to Section 11.1(a)(i), a successor is not selected by the Unitholders as provided herein or the Partnership does not receive a Withdrawal Opinion of Counsel, the Partnership shall be dissolved in accordance with Section 12.1. Any successor General Partner elected in accordance with the terms of this Section 11.1 shall be subject to the provisions of Section 10.2.

 

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Section 11.2 Removal of the General Partner.

The General Partner may be removed if such removal is approved by the Unitholders holding at least 66 2 / 3 % of the Outstanding Units (including Units held by the General Partner and its Affiliates). Any such action by such holders for removal of the General Partner must also provide for the election of a successor General Partner by the Unitholders holding a majority of Outstanding Units (including Units held by the General Partner and its Affiliates). Such removal shall be effective immediately following the admission of a successor General Partner pursuant to Section 10.2. The removal of the General Partner shall also automatically constitute the removal of the General Partner as general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If a Person is elected as a successor General Partner in accordance with the terms of this Section 11.2, such Person shall, upon admission pursuant to Section 10.2, automatically become a successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. The right of the holders of Outstanding Units to remove the General Partner shall not exist or be exercised unless the Partnership has received an opinion opining as to the matters covered by a Withdrawal Opinion of Counsel. Any successor General Partner elected in accordance with the terms of this Section 11.2 shall be subject to the provisions of Section 10.2.

Section 11.3 Interest of Departing General Partner and Successor General Partner.

(a) In the event of (i) withdrawal of the General Partner under circumstances where such withdrawal does not violate this Agreement or (ii) removal of the General Partner by the holders of Outstanding Units under circumstances where Cause does not exist, if a successor General Partner is elected in accordance with the terms of Section 11.1 or 11.2, the Departing General Partner shall have the option exercisable prior to the effective date of the departure of such Departing General Partner to require its successor to purchase (x) its General Partner Interest and (y) its general partner interest (or equivalent interest), if any, in the other Group Members ((x) and (y) collectively, the “ Combined Interest ”) in exchange for an amount in cash equal to the fair market value of such Combined Interest, such amount to be determined and payable as of the effective date of its departure or, if there is not agreement as to the fair market value of such Combined Interest, within ten (10) days after such agreement is reached. If the General Partner is removed by the Unitholders under circumstances where Cause exists or if the General Partner withdraws under circumstances where such withdrawal violates this Agreement, and if a successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner), such successor shall have the option, exercisable prior to the effective date of the departure of such Departing General Partner (or, in the event the business of the Partnership is continued, prior to the date the business of the Partnership is continued), to purchase the Combined Interest of the Departing General Partner for such fair market value of such Combined Interest of the Departing General Partner. In either event, the Departing General Partner shall be entitled to receive all reimbursements due such Departing General Partner pursuant to Section 7.4, including any employee-related liabilities (including severance liabilities), incurred in connection with the termination of any employees employed by the Departing General Partner for the benefit of the Partnership or the other Group Members.

 

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For purposes of this Section 11.3(a), the fair market value of a Departing General Partner’s Combined Interest shall be determined by agreement between the Departing General Partner and its successor or, failing agreement within 30 days after the effective date of such Departing General Partner’s departure, by an independent investment banking firm or other independent expert selected by the Departing General Partner and its successor, which, in turn, may rely on other experts, and the determination of which shall be conclusive as to such matter. If such parties cannot agree upon one independent investment banking firm or other independent expert within 45 days after the effective date of such departure, then the Departing General Partner shall designate an independent investment banking firm or other independent expert, the Departing General Partner’s successor shall designate an independent investment banking firm or other independent expert, and such firms or experts shall mutually select a third independent investment banking firm or independent expert, which third independent investment banking firm or other independent expert shall determine the fair market value of the Combined Interest of the Departing General Partner. In making its determination, such third independent investment banking firm or other independent expert may consider the then current trading price of Units on any National Securities Exchange on which Units are then listed or admitted for trading, the value of the Partnership’s assets, the rights and obligations of the Departing General Partner and other factors it may deem relevant.

(b) If the Combined Interest is not purchased in the manner set forth in Section 11.3(a), the Departing General Partner (or its transferee) shall become a Limited Partner and its Combined Interest shall be converted into Common Units pursuant to a valuation made by an investment banking firm or other independent expert selected pursuant to Section 11.3(a), without reduction in such Partnership Interest (but subject to proportionate dilution by reason of the admission of its successor). Any successor General Partner shall indemnify the Departing General Partner (or its transferee) as to all debts and liabilities of the Partnership arising on or after the date on which the Departing General Partner (or its transferee) becomes a Limited Partner. For purposes of this Agreement, conversion of the Combined Interest of the Departing General Partner to Common Units will be characterized as if such General Partner (or its transferee) contributed its Combined Interest to the Partnership in exchange for the newly issued Common Units.

Section 11.4 Withdrawal of Limited Partners.

No Limited Partner shall have any right to withdraw from the Partnership; provided, however, that when a transferee of a Limited Partner’s Limited Partner Interest becomes a Record Holder of the Limited Partner Interest so transferred, such transferring Limited Partner shall cease to be a Limited Partner with respect to the Limited Partner Interest so transferred.

ARTICLE XII

DISSOLUTION AND LIQUIDATION

Section 12.1 Dissolution.

The Partnership shall not be dissolved by the admission of Additional Limited Partners or by the admission of a successor General Partner in accordance with the terms of this Agreement. Upon the removal or withdrawal of the General Partner, if a successor General Partner is elected pursuant to Section 11.1 or Section 11.2, the Partnership shall not be dissolved and such successor General Partner shall continue the business of the Partnership. The Partnership shall dissolve, and (subject to Section 12.2) its affairs shall be wound up, upon:

 

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(a) an Event of Withdrawal of the General Partner as provided in Section 11.1(a) (other than Section 11.1(a)(ii)), unless a successor is elected and an Opinion of Counsel is received as provided in Section 11.1(b) or Section 11.2 and such successor is admitted to the Partnership pursuant to Section 10.2;

(b) an election to dissolve the Partnership by the General Partner that is approved by the holders of a Unit Majority;

(c) the entry of a decree of judicial dissolution of the Partnership pursuant to the provisions of the Delaware Act; or

(d) at any time there are no Limited Partners, unless the Partnership is continued without dissolution in accordance with the Delaware Act.

Section 12.2 Continuation of the Business of the Partnership After Dissolution.

Upon (a) dissolution of the Partnership following an Event of Withdrawal caused by the withdrawal or removal of the General Partner as provided in Section 11.1(a)(i) or (iii) and the failure of the Partners to select a successor to such Departing General Partner pursuant to Section 11.1 or Section 11.2, then within 90 days thereafter, or (b) dissolution of the Partnership upon an event constituting an Event of Withdrawal as defined in Section 11.1(a)(iv), (v) or (vi), then, to the maximum extent permitted by law, within 180 days thereafter, the holders of a Unit Majority may elect to continue the business of the Partnership on the same terms and conditions set forth in this Agreement by appointing as a successor General Partner a Person approved by the holders of a majority of Outstanding Units. Unless such an election is made within the applicable time period as set forth above, the Partnership shall conduct only activities necessary to wind up its affairs. If such an election is so made, then:

(i) the Partnership shall continue without dissolution unless earlier dissolved in accordance with this Article XII;

(ii) if the successor General Partner is not the former General Partner, then the interest of the former General Partner shall be treated in the manner provided in Section 11.3; and

(iii) the successor General Partner shall be admitted to the Partnership as General Partner, effective as of the Event of Withdrawal, by agreeing in writing to be bound by this Agreement; provided, that the right of the holders of a majority of Outstanding Units to approve a successor General Partner and to reconstitute and to continue the business of the Partnership shall not exist and may not be exercised unless the Partnership has received an Opinion of Counsel that (x) the exercise of the right would not result in the loss of limited liability of any Limited Partner and (y) neither the Partnership nor the MLP would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of such right to continue (to the extent not already so treated or taxed).

 

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Section 12.3 Liquidator.

Upon dissolution of the Partnership, unless the Partnership is continued pursuant to Section 12.2, the General Partner shall select one or more Persons to act as Liquidator. The Liquidator (if other than the General Partner) shall be entitled to receive such compensation for its services as may be approved by holders of at least a majority of the Outstanding Common Units voting as a single class. The Liquidator (if other than the General Partner) shall agree not to resign at any time without 15 days’ prior notice and may be removed at any time, with or without cause, by notice of removal approved by holders of at least a majority of the Outstanding Common Units voting as a single class. Upon dissolution, removal or resignation of the Liquidator, a successor and substitute Liquidator (who shall have and succeed to all rights, powers and duties of the original Liquidator) shall within 30 days thereafter be approved by holders of at least a majority of the Outstanding Common Units voting as a single class. The right to approve a successor or substitute Liquidator in the manner provided herein shall be deemed to refer also to any such successor or substitute Liquidator approved in the manner herein provided. Except as expressly provided in this Article XII, the Liquidator approved in the manner provided herein shall have and may exercise, without further authorization or consent of any of the parties hereto, all of the powers conferred upon the General Partner under the terms of this Agreement (but subject to all of the applicable limitations, contractual and otherwise, upon the exercise of such powers, other than the limitation on sale set forth in Section 7.3) necessary or appropriate to carry out the duties and functions of the Liquidator hereunder for and during the period of time required to complete the winding up and liquidation of the Partnership as provided for herein.

Section 12.4 Liquidation.

The Liquidator shall proceed to dispose of the assets of the Partnership, discharge its liabilities, and otherwise wind up its affairs in such manner and over such period as the Liquidator determines to be in the best interest of the Partners, subject to Section 17-804 of the Delaware Act and the following:

(a) Disposition of Assets. The assets may be disposed of by public or private sale or by distribution in kind to one or more Partners on such terms as the Liquidator and such Partner or Partners may agree. If any property is distributed in kind, the Partner receiving the property shall be deemed for purposes of Section 12.4(c) to have received cash equal to its fair market value; and contemporaneously therewith, appropriate cash distributions must be made to the other Partners. The Liquidator may defer liquidation or distribution of the Partnership’s assets for a reasonable time if it determines that an immediate sale or distribution of all or some of the Partnership’s assets would be impractical or would cause undue loss to the Partners. The Liquidator may distribute the Partnership’s assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the Partners.

 

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(b) Discharge of Liabilities. Liabilities of the Partnership include amounts owed to the Liquidator as compensation for serving in such capacity (subject to the terms of Section 12.3) and amounts to Partners otherwise than in respect of their distribution rights under Article VI. With respect to any liability that is contingent, conditional or unmatured or is otherwise not yet due and payable, the Liquidator shall either settle such claim for such amount as it thinks appropriate or establish a reserve of cash or other assets to provide for its payment. When paid, any unused portion of the reserve shall be distributed as additional liquidation proceeds.

(c) Liquidation Distributions. All property and all cash in excess of that required to discharge liabilities as provided in Section 12.4(b) shall be distributed to the Partners in accordance with, and to the extent of, the positive balances in their respective Capital Accounts, as determined after taking into account all Capital Account adjustments (other than those made by reason of distributions pursuant to this Section 12.4(c)) for the taxable year of the Partnership during which the liquidation of the Partnership occurs (with such date of occurrence being determined pursuant to Treasury Regulation Section 1.704-1(b)(2)(ii)(g)), and such distribution shall be made by the end of such taxable year (or, if later, within 90 days after said date of such occurrence).

Section 12.5 Cancellation of Certificate of Limited Partnership.

Upon the completion of the distribution of Partnership cash and property as provided in Section 12.4 in connection with the liquidation of the Partnership, the Certificate of Limited Partnership and all qualifications of the Partnership as a foreign limited partnership in jurisdictions other than the State of Delaware shall be canceled and such other actions as may be necessary to terminate the Partnership shall be taken.

Section 12.6 Return of Contributions.

The General Partner shall not be personally liable for, and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate, the return of the Capital Contributions of the Limited Partners or Unitholders, or any portion thereof, it being expressly understood that any such return shall be made solely from Partnership assets.

Section 12.7 Waiver of Partition.

To the maximum extent permitted by law, each Partner hereby waives any right to partition of the Partnership property.

Section 12.8 Capital Account Restoration.

No Partner shall have any obligation to restore any negative balance in its Capital Account upon liquidation of the Partnership.

Section 12.9 Certain Prohibited Acts.

Without obtaining Special Approval, the General Partner shall not take any action to cause the Partnership or the MLP to (i) make or consent to a general assignment for the benefit of the Partnership’s or the MLP’s creditors; (ii) file or consent to the filing of any bankruptcy, insolvency or reorganization petition for relief under the United States Bankruptcy Code naming

 

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the Partnership or the MLP or otherwise seek, with respect to the Partnership or the MLP, relief from debts or protection from creditors generally; (iii) file or consent to the filing of a petition or answer seeking for the Partnership or the MLP a liquidation, dissolution, arrangement, or similar relief under any law; (iv) file an answer or other pleading admitting or failing to contest the material allegations of a petition filed against the Partnership or the MLP in a proceeding of the type described in clauses (i) – (iii) of this Section 12.9; (v) seek, consent to or acquiesce in the appointment of a receiver, liquidator, conservator, assignee, trustee, sequestrator, custodian or any similar official for the Partnership or the MLP or for all or any substantial portion of its properties; (vi) sell all or substantially all of its assets, except in accordance with Section 7.3(b); (vii) dissolve or liquidate, except in accordance with Article XII; or (viii) merge or consolidate, except in accordance with Article XIV.

ARTICLE XIII

AMENDMENT OF PARTNERSHIP AGREEMENT; MEETINGS; RECORD DATE

Section 13.1 Amendments to be Adopted Solely by the General Partner.

Each Partner agrees that the General Partner, without the approval of any Partner, may amend any provision of this Agreement and execute, swear to, acknowledge, deliver, file and record whatever documents may be required in connection therewith, to reflect:

(a) a change in the name of the Partnership, the location of the principal place of business of the Partnership, the registered agent of the Partnership or the registered office of the Partnership;

(b) the admission, substitution, withdrawal or removal of Partners in accordance with this Agreement;

(c) a change that the General Partner determines to be necessary or appropriate to qualify or continue the qualification of the Partnership as a limited partnership or a partnership in which the Limited Partners have limited liability under the laws of any state or to ensure that the Group Members will not be treated as associations taxable as corporations or otherwise taxed as entities for federal income tax purposes;

(d) a change that the General Partner determines (i) does not adversely affect the Limited Partners (including any particular class of Partnership Interests as compared to other classes of Partnership Interests) in any material respect, (ii) to be necessary or appropriate to (A) satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute (including the Delaware Act) or (B) facilitate the trading of the Limited Partner Interests (including the division of any class or classes of Outstanding Limited Partner Interests into different classes to facilitate uniformity of tax consequences within such classes of Limited Partner Interests) or comply with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Limited Partner Interests are or will be listed, (iii) to be necessary or appropriate in connection with action taken by the General Partner pursuant to Section 5.10 or (iv) to be required to effect the intent expressed in the Registration Statement or the intent of the provisions of this Agreement or is otherwise contemplated by this Agreement;

 

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(e) a change in the fiscal year or taxable year of the Partnership and any other changes that the General Partner determines to be necessary or appropriate as a result of a change in the fiscal year or taxable year of the Partnership including, if the General Partner shall so determine, a change in the definition of “ Quarter ” and the dates on which distributions are to be made by the Partnership;

(f) an amendment that is necessary, in the Opinion of Counsel, to prevent the Partnership, or the General Partner or its directors, officers, trustees or agents from in any manner being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisers Act of 1940, as amended, or “ plan asset ” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended, regardless of whether such are substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;

(g) an amendment that the General Partner determines to be necessary or appropriate in connection with the authorization of issuance of any class or series of Partnership Securities pursuant to Section 5.8;

(h) any amendment expressly permitted in this Agreement to be made by the General Partner acting alone;

(i) an amendment effected, necessitated or contemplated by a Merger Agreement approved in accordance with Section 14.3;

(j) an amendment that the General Partner determines to be necessary or appropriate to reflect and account for the formation by the Partnership of, or investment by the Partnership in, any corporation, partnership, joint venture, limited liability company or other entity, in connection with the conduct by the Partnership of activities permitted by the terms of Section 2.4;

(k) a merger or conveyance pursuant to Section 14.3(d); or

(l) a change in the form of the Transfer Application or the Taxation Certification necessary or appropriate as determined by the General Partner to effectuate the purposes of Section 4.5 or Section 4.8 hereof; or

(m) any other amendments substantially similar to the foregoing.

Section 13.2 Amendment Procedures.

Except as provided in Sections 13.1 and 13.3, all amendments to this Agreement shall be made in accordance with the following requirements. Amendments to this Agreement may be proposed only by the General Partner; provided, however, that the General Partner shall have no duty or obligation to propose any amendment to this Agreement and may decline to do so free of any fiduciary duty or obligation whatsoever to the Partnership or any Limited Partner and, in declining to propose an amendment to the maximum extent permitted by law, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or

 

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regulation or at equity. A proposed amendment shall be effective upon its approval by the General Partner and the holders of a Unit Majority, unless a greater or different percentage is required under this Agreement or by Delaware law. Each proposed amendment that requires the approval of the holders of a specified percentage of Outstanding Units shall be set forth in a writing that contains the text of the proposed amendment. If such an amendment is proposed, the General Partner shall seek the written approval of the requisite percentage of Outstanding Units or call a meeting of the Unitholders to consider and vote on such proposed amendment. The General Partner shall notify all Record Holders upon final adoption of any such proposed amendments. Notwithstanding the provisions of Sections 13.1 and 13.2, no amendment of (i) the definitions of “ Conflicts Committee,” “ Special Approval ”, (ii) Section 2.9, (iii) Section 4.6, (iv) Section 7.3(b), (v) Section 7.9(a), (vi) Section 12.9; (vii) Section 14.2, or (viii) any other provision of this Agreement requiring that Special Approval be obtained as a condition to any action, shall be effective without first obtaining Special Approval.

Section 13.3 Amendment Requirements.

(a) Notwithstanding the provisions of Sections 13.1 and 13.2, no provision of this Agreement that establishes a percentage of Outstanding Units (including Units deemed owned by the General Partner) required to take any action shall be amended, altered, changed, repealed or rescinded in any respect that would have the effect of reducing such voting percentage unless such amendment is approved by the written consent or the affirmative vote of holders of Outstanding Units whose aggregate Outstanding Units constitute not less than the voting requirement sought to be reduced.

(b) Notwithstanding the provisions of Sections 13.1 and 13.2, no amendment to this Agreement may (i) enlarge the obligations of any Limited Partner without its consent, unless such shall be deemed to have occurred as a result of an amendment approved pursuant to Section 13.3(c) or (ii) enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable to the General Partner or any of its Affiliates without its consent, which consent may be given or withheld at its option.

(c) Except as provided in Section 14.3, and without limitation of the General Partner’s authority to adopt amendments to this Agreement without the approval of any Partners as contemplated in Section 13.1, any amendment that would have a material adverse effect on the rights or preferences of any class of Partnership Interests in relation to other classes of Partnership Interests must be approved by the holders of not less than a majority of the Outstanding Partnership Interests of the class affected.

(d) Notwithstanding any other provision of this Agreement, except for amendments pursuant to Section 13.1 and except as otherwise provided by Section 14.3(b), no amendments shall become effective without the approval of the holders of at least 90% of the Outstanding Units voting as a single class unless the Partnership obtains an Opinion of Counsel to the effect that such amendment will not affect the limited liability of any Limited Partner under applicable law.

 

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(e) Except as provided in Section 13.1, this Section 13.3 shall only be amended with the approval of the holders of at least 90% of the Outstanding Units.

Section 13.4 Special Meetings.

All acts of Limited Partners to be taken pursuant to this Agreement shall be taken in the manner provided in this Article XIII. Special meetings of the Limited Partners may be called by the General Partner or by Limited Partners owning 20% or more of the Outstanding Partnership Securities of the class or classes for which a meeting is proposed. Limited Partners shall call a special meeting by delivering to the General Partner one or more requests in writing stating that the signing Limited Partners wish to call a special meeting and indicating the general or specific purposes for which the special meeting is to be called. Within 60 days after receipt of such a call from Limited Partners or within such greater time as may be reasonably necessary for the Partnership to comply with any statutes, rules, regulations, listing agreements or similar requirements governing the holding of a meeting or the solicitation of proxies for use at such a meeting, the General Partner shall send a notice of the meeting to the Limited Partners either directly or indirectly through the Transfer Agent. A meeting shall be held at a time and place determined by the General Partner on a date not less than 10 days nor more than 60 days after the mailing of notice of the meeting. Limited Partners shall not vote on matters that would cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability under the Delaware Act or the law of any other state in which the Partnership is qualified to do business.

Section 13.5 Notice of a Meeting.

Notice of a meeting called pursuant to Section 13.4 shall be given to the Record Holders of the class or classes of Limited Partner Interests for which a meeting is proposed in writing by mail or other means of written communication in accordance with Section 16.1. The notice shall be deemed to have been given at the time when deposited in the mail or sent by other means of written communication.

Section 13.6 Record Date.

For purposes of determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners or to give approvals without a meeting as provided in Section 13.11 the General Partner may set a Record Date, which shall not be less than 10 nor more than 60 days before (a) the date of the meeting (unless such requirement conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Limited Partner Interests are listed or admitted for trading, in which case the rule, regulation, guideline or requirement of such National Securities Exchange shall govern) or (b) in the event that approvals are sought without a meeting, the date by which Limited Partners are requested in writing by the General Partner to give such approvals.

 

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Section 13.7 Adjournment.

When a meeting is adjourned to another time or place, notice need not be given of the adjourned meeting and a new Record Date need not be fixed, if the time and place thereof are announced at the meeting at which the adjournment is taken, unless such adjournment shall be for more than 45 days. At the adjourned meeting, the Partnership may transact any business which might have been transacted at the original meeting. If the adjournment is for more than 45 days or if a new Record Date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given in accordance with this Article XIII.

Section 13.8 Waiver of Notice; Approval of Meeting; Approval of Minutes.

The transactions of any meeting of Limited Partners, however called and noticed, and whenever held, shall be as valid as if it had occurred at a meeting duly held after regular call and notice, if a quorum is present, either in person or by proxy. Attendance of a Limited Partner at a meeting shall constitute a waiver of notice of the meeting, except when the Limited Partner attends the meeting for the express purpose of objecting, at the beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened; and except that attendance at a meeting is not a waiver of any right to disapprove the consideration of matters required to be included in the notice of the meeting, but not so included, if the disapproval is expressly made at the meeting

Section 13.9 Quorum.

The holders of a majority of the Outstanding Partnership Securities of the class or classes for which a meeting has been called (including Limited Partner Interests deemed owned by the General Partner) represented in person or by proxy shall constitute a quorum at a meeting of Limited Partners of such class or classes unless any such action by the Limited Partners requires approval by holders of a greater percentage of such Limited Partner Interests, in which case the quorum shall be such greater percentage. At any meeting of the Limited Partners duly called and held in accordance with this Agreement at which a quorum is present, the act of Limited Partners holding Outstanding Partnership Securities that in the aggregate represent a majority of the Outstanding Partnership Securities entitled to vote and be present in person or by proxy at such meeting shall be deemed to constitute the act of all Limited Partners, unless a greater or different percentage is required with respect to such action under the provisions of this Agreement, in which case the act of the Limited Partners holding Outstanding Partnership Securities that in the aggregate represent at least such greater or different percentage shall be required. The Limited Partners present at a duly called or held meeting at which a quorum is present may continue to transact business until adjournment, notwithstanding the withdrawal of enough Limited Partners to leave less than a quorum, if any action taken (other than adjournment) is approved by the required percentage of Outstanding Partnership Securities specified in this Agreement (including Outstanding Partnership Securities deemed owned by the General Partner). In the absence of a quorum any meeting of Limited Partners may be adjourned from time to time by the affirmative vote of holders of at least a majority of the Outstanding Partnership Securities entitled to vote at such meeting (including Outstanding Partnership Securities deemed owned by the General Partner) represented either in person or by proxy, but no other business may be transacted, except as provided in Section 13.7.

 

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Section 13.10 Conduct of a Meeting.

The General Partner shall have full power and authority concerning the manner of conducting any meeting of the Limited Partners or solicitation of approvals in writing, including the determination of Persons entitled to vote, the existence of a quorum, the satisfaction of the requirements of Section 13.4, the conduct of voting, the validity and effect of any proxies and the determination of any controversies, votes or challenges arising in connection with or during the meeting or voting. The General Partner shall designate a Person to serve as chairman of any meeting and shall further designate a Person to take the minutes of any meeting. All minutes shall be kept with the records of the Partnership maintained by the General Partner. The General Partner may make such other regulations consistent with applicable law and this Agreement as it may deem advisable concerning the conduct of any meeting of the Limited Partners or solicitation of approvals in writing, including regulations in regard to the appointment of proxies, the appointment and duties of inspectors of votes and approvals, the submission and examination of proxies and other evidence of the right to vote, and the revocation of approvals in writing.

Section 13.11 Action Without a Meeting.

If authorized by the General Partner, any action that may be taken at a meeting of the Limited Partners may be taken without a meeting if an approval in writing setting forth the action so taken is signed by Limited Partners owning not less than the minimum percentage of the Outstanding Limited Partner Interests (including Limited Partner Interests deemed owned by the General Partner) that would be necessary to authorize or take such action at a meeting at which all the Limited Partners were present and voted (unless such provision conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Limited Partner Interests are listed or admitted for trading, in which case the rule, regulation, guideline or requirement of such National Securities Exchange shall govern). Prompt notice of the taking of action without a meeting shall be given to the Limited Partners who have not approved in writing. The General Partner may specify that any written ballot submitted to Limited Partners for the purpose of taking any action without a meeting shall be returned to the Partnership within the time period, which shall be not less than 20 days, specified by the General Partner. If a ballot returned to the Partnership does not vote all of the Limited Partner Interests held by the Limited Partners, the Partnership shall be deemed to have failed to receive a ballot for the Limited Partner Interests that were not voted. If approval of the taking of any action by the Limited Partners is solicited by any Person other than by or on behalf of the General Partner, the written approvals shall have no force and effect unless and until (a) they are deposited with the Partnership in care of the General Partner, (b) approvals sufficient to take the action proposed are dated as of a date not more than 90 days prior to the date sufficient approvals are deposited with the Partnership and (c) an Opinion of Counsel is delivered to the General Partner to the effect that the exercise of such right and the action proposed to be taken with respect to any particular matter (i) will not cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability, and (ii) is otherwise permissible under the state statutes then governing the rights, duties and liabilities of the Partnership and the Partners.

 

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Section 13.12 Voting and Other Rights.

(a) Only those Record Holders of the Limited Partner Interests on the Record Date set pursuant to Section 13.6 (and also subject to the limitations contained in the definition of “ Outstanding ”) shall be entitled to notice of, and to vote at, a meeting of Limited Partners or to act with respect to matters as to which the holders of the Outstanding Limited Partner Interests have the right to vote or to act. All references in this Agreement to votes of, or other acts that may be taken by, the Outstanding Limited Partner Interests shall be deemed to be references to the votes or acts of the Record Holders of such Outstanding Limited Partner Interests.

(b) With respect to Limited Partner Interests that are held for a Person’s account by another Person (such as a broker, dealer, bank, trust company or clearing corporation, or an agent of any of the foregoing), in whose name such Limited Partner Interests are registered, such other Person shall, in exercising the voting rights in respect of such Limited Partner Interests on any matter, and unless the arrangement between such Persons provides otherwise, vote such Limited Partner Interests in favor of, and at the direction of, the Person who is the beneficial owner, and the Partnership shall be entitled to assume it is so acting without further inquiry. The provisions of this Section 13.12(b) (as well as all other provisions of this Agreement) are subject to the provisions of Section 4.3.

ARTICLE XIV

MERGER, CONSOLIDATION OR CONVERSION

Section 14.1 Authority.

The Partnership may merge or consolidate with one or more corporations, limited liability companies, statutory trusts or associations, real estate investment trusts, common law trusts or unincorporated businesses, including a partnership (whether general or limited (including a limited liability partnership)) or convert into any such entity, whether such entity is formed under the laws of the State of Delaware or any other state of the United States of America, pursuant to a written agreement of merger or consolidation (“ Merger Agreement ”) or a written plan of conversion (“ Plan of Conversion ”), as the case may be, in accordance with this Article XIV.

Section 14.2 Procedure for Merger, Consolidation or Conversion.

(a) Merger, consolidation or conversion of the Partnership pursuant to this Article XIV requires the prior consent of the General Partner, provided, however, that, to the maximum extent permitted by law, the General Partner shall have no duty or obligation to consent to any merger, consolidation or conversion of the Partnership and may decline to do so free of any fiduciary duty or obligation whatsoever to the Partnership, any Limited Partner and, in declining to consent to a merger, consolidation or conversion, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity.

 

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(b) If the General Partner shall determine to consent to the merger or consolidation, the General Partner shall approve the Merger Agreement, which shall set forth:

(i) the names and jurisdictions of formation or organization of each of the business entities proposing to merge or consolidate;

(ii) the name and jurisdiction of formation or organization of the business entity that is to survive the proposed merger or consolidation (the “ Surviving Business Entity ”);

(iii) the terms and conditions of the proposed merger or consolidation;

(iv) the manner and basis of exchanging or converting the equity securities of each constituent business entity for, or into, cash, property or interests, rights, securities or obligations of the Surviving Business Entity; and (i) if any general or limited partner interests, securities or rights of any constituent business entity are not to be exchanged or converted solely for, or into, cash, property or general or limited partner interests, rights, securities or obligations of the Surviving Business Entity, the cash, property or interests, rights, securities or obligations of any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity) which the holders of such general or limited partner interests, securities or rights are to receive in exchange for, or upon conversion of their interests, securities or rights, and (ii) in the case of securities represented by certificates, upon the surrender of such certificates, which cash, property or general or limited partner interests, rights, securities or obligations of the Surviving Business Entity or any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity), or evidences thereof, are to be delivered;

(v) a statement of any changes in the constituent documents or the adoption of new constituent documents (the articles or certificate of incorporation, articles of trust, declaration of trust, certificate or agreement of limited partnership, operating agreement or other similar charter or governing document) of the Surviving Business Entity to be effected by such merger or consolidation;

(vi) the effective time of the merger, which may be the date of the filing of the certificate of merger pursuant to Section 14.4 or a later date specified in or determinable in accordance with the Merger Agreement ( provided, that if the effective time of the merger is to be later than the date of the filing of such certificate of merger, the effective time shall be fixed at a date or time certain at or prior to the time of the filing of such certificate of merger and stated therein); and

(vii) such other provisions with respect to the proposed merger or consolidation that the General Partner determines to be necessary or appropriate.

(c) If the General Partner shall determine to consent to the conversion, the General Partner may approve and adopt a Plan of Conversion containing such terms and conditions that the General Partner determines to be necessary or appropriate.

 

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Section 14.3 Approval by Limited Partners.

(a) Except as provided in Section 14.3(d), the General Partner, upon its approval of the Merger Agreement or Plan of Conversion, as the case may be, shall direct that the Merger Agreement or the Plan of Conversion, as applicable, be submitted to a vote of Limited Partners, whether at a special meeting or by written consent, in either case in accordance with the requirements of Article XIII. A copy or a summary of the Merger Agreement or the Plan of Conversion, as applicable, shall be included in or enclosed with the notice of a special meeting or the written consent.

(b) Except as provided in Section 14.3(d), the Merger Agreement or the Plan of Conversion, as applicable, shall be approved upon receiving the affirmative vote or consent of the holders of a Unit Majority.

(c) Except as provided in Section 14.3(d), after such approval by vote or consent of the Limited Partners, and at any time prior to the filing of the certificate of merger or a certificate of conversion pursuant to Section 14.4, the merger, consolidation or conversion may be abandoned pursuant to provisions therefor, if any, set forth in the Merger Agreement or the Plan of Conversion, as the case may be.

(d) Notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted without Limited Partner approval, to convert the Partnership or any Group Member into a new limited liability entity, to merge the Partnership or any Group Member into, or convey all of the Partnership’s assets to, another limited liability entity which shall be newly formed and shall have no assets, liabilities or operations at the time of such conversion, merger or conveyance other than those it receives from the Partnership or other Group Member if (i) the General Partner has received an Opinion of Counsel that the merger or conveyance, as the case may be, would not result in the loss of the limited liability of any Limited Partner or cause the Partnership or the MLP to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such), (ii) the sole purpose of such conversion, merger or conveyance is to effect a mere change in the legal form of the Partnership into another limited liability entity and (iii) the governing instruments of the new entity provide the Limited Partners and the General Partner with the same rights and obligations as are herein contained.

(e) Additionally, notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to merge or consolidate the Partnership with or into another entity if (A) the General Partner has received an Opinion of Counsel that the merger or consolidation, as the case may be, would not result in the loss of the limited liability of any Limited Partner or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such), (B) the merger or consolidation would not result in an amendment to the Partnership Agreement, other than any amendments that could be adopted pursuant to Section 13.1, (C) the Partnership is the Surviving Business Entity in such merger or consolidation, (D) each Partnership Unit outstanding immediately prior to the effective date of the merger or consolidation is to be an identical Partnership Unit of the Partnership after the effective date of the merger or consolidation, and (E) the number of Partnership Securities to be issued by the Partnership in such merger or consolidation do not exceed 20% of the Partnership Securities Outstanding immediately prior to the effective date of such merger or consolidation.

 

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Section 14.4 Certificate of Merger.

(a) Upon the required approval, if any, by the General Partner and the Unitholders of a Merger Agreement or a Plan of Conversion, as the case may be, a certificate of merger or certificate of conversion, as applicable, shall be executed and filed with the Secretary of State of the State of Delaware in conformity with the requirements of the Delaware Act.

(b) At the effective time of the certificate of merger:

(i) all of the rights, privileges and powers of each of the business entities that has merged or consolidated, and all property, real, personal and mixed, and all debts due to any of those business entities and all other things and causes of action belonging to each of those business entities, shall be vested in the Surviving Business Entity and after the merger or consolidation shall be the property of the Surviving Business Entity to the extent they were of each constituent business entity;

(ii) the title to any real property vested by deed or otherwise in any of those constituent business entities shall not revert and is not in any way impaired because of the merger or consolidation;

(iii) all rights of creditors and all liens on or security interests in property of any of those constituent business entities shall be preserved unimpaired; and

(iv) all debts, liabilities and duties of those constituent business entities shall attach to the Surviving Business Entity and may be enforced against it to the same extent as if the debts, liabilities and duties had been incurred or contracted by it.

(c) At the effective time of the certificate of conversion:

(i) the Partnership shall continue to exist, without interruption, but in the organizational form of the converted entity rather than in its prior organizational form;

(ii) all rights, title, and interests to all real estate and other property owned by the Partnership shall continue to be owned by the converted entity in its new organizational form without reversion or impairment, without further act or deed, and without any transfer or assignment having occurred, but subject to any existing liens or other encumbrances thereon;

(iii) all liabilities and obligations of the Partnership shall continue to be liabilities and obligations of the converted entity in its new organizational form without impairment or diminution by reason of the conversion;

 

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(iv) all rights of creditors or other parties with respect to or against the prior interest holders or other owners of the Partnership in their capacities as such in existence as of the effective time of the conversion will continue in existence as to those liabilities and obligations and may be pursued by such creditors and obligees as if the conversion did not occur;

(v) a proceeding pending by or against the Partnership or by or against any of Partners in their capacities as such may be continued by or against the converted entity in its new organizational form and by or against the prior partners without any need for substitution of parties; and

(vi) the Partnership Securities that are to be converted into partnership interests, shares, evidences of ownership, or other securities in the converted entity as provided in the Plan of Conversion or certificate of conversion shall be so converted, and Partners shall be entitled only to the rights provided in the Plan of Conversion or certificate of conversion.

(d) A merger, consolidation or conversion effected pursuant to this Article shall not be deemed to result in a transfer or assignment of assets or liabilities from one entity to another.

Section 14.5 Amendment of Partnership Agreement.

Pursuant to Section 17-211(g) of the Delaware Act, an agreement of merger or consolidation approved in accordance with Section 17-211(b) of the Delaware Act may (a) effect any amendment to this Agreement or (b) effect the adoption of a new partnership agreement for a limited partnership if it is the Surviving Business Entity. Any such amendment or adoption made pursuant to this Section 14.5 shall be effective at the effective time or date of the merger or consolidation.

ARTICLE XV

RIGHT TO ACQUIRE LIMITED PARTNER INTERESTS

Section 15.1 Right to Acquire Limited Partner Interests.

(a) Notwithstanding any other provision of this Agreement, if at any time 90% or more of the total Limited Partner Interests of any class then Outstanding is held by the General Partner and its Affiliates, the General Partner shall then have the right, which right it may assign and transfer in whole or in part to the Partnership or any Affiliate of the General Partner, exercisable at its option, to purchase all, but not less than all, of such Limited Partner Interests of such class then Outstanding held by Persons other than the General Partner and its Affiliates, at the greater of (x) the Current Market Price as of the date three days prior to the date that the notice described in Section 15 is mailed and (y) the highest price paid by a General Partner or any of its Affiliates for any such Limited Partner Interest of such class purchased during the 90-day period preceding the date that the notice described in Section 15.1(b) is mailed. As used in this Agreement, (i) ” Current Market Price, ” as of any date of any class of Limited Partner Interests listed or admitted to trading on any National Securities Exchange, means the average of the daily Closing Prices (as hereinafter defined) per limited partner interest of such class for the 20 consecutive Trading Days (as hereinafter defined) immediately prior to such date; (ii) ” Closing Price ” for any day means the last sale price on such day, regular way, or in case no such sale takes place on such day, the average of the closing bid and asked prices on such day, regular way, in either case as reported in the principal consolidated transaction

 

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reporting system with respect to securities listed or admitted for trading on the principal National Securities Exchange on which such Limited Partner Interests of such class are listed or admitted to trading or, if such Limited Partner Interests of such class are not listed or admitted to trading on any National Securities Exchange, the last quoted price on such day or, if not so quoted, the average of the high bid and low asked prices on such day in the over-the-counter market, as reported by the Nasdaq or any other system then in use, or, if on any such day such Limited Partner Interests of such class are not quoted by any such organization, the average of the closing bid and asked prices on such day as furnished by a professional market maker making a market in such Limited Partner Interests of such class selected by the General Partner, or if on any such day no market maker is making a market in such Limited Partner Interests of such class, the fair value of such Limited Partner Interests on such day as determined by the General Partner; and (iii) ” Trading Day ” means a day on which the principal National Securities Exchange on which such Limited Partner Interests of any class are listed or admitted to trading is open for the transaction of business or, if Limited Partner Interests of a class are not listed or admitted to trading on any National Securities Exchange, a day on which banking institutions in New York City generally are open.

(b) If the General Partner, any Affiliate of the General Partner or the Partnership elects to exercise the right to purchase Limited Partner Interests granted pursuant to Section 15.1(a), the General Partner shall deliver to the Transfer Agent notice of such election to purchase (the “ Notice of Election to Purchase ”) and shall cause the Transfer Agent to mail a copy of such Notice of Election to Purchase to the Record Holders of Limited Partner Interests of such class or classes (as of a Record Date selected by the General Partner) at least 10, but not more than 60, days prior to the Purchase Date. Such Notice of Election to Purchase shall also be published for a period of at least three consecutive days in at least two daily newspapers of general circulation printed in the English language and published in the Borough of Manhattan, New York. The Notice of Election to Purchase shall specify the Purchase Date and the price (determined in accordance with Section 15.1(a)) at which Limited Partner Interests will be purchased and state that the General Partner, its Affiliate or the Partnership, as the case may be, elects to purchase such Limited Partner Interests, upon surrender of Certificates representing such Limited Partner Interests in exchange for payment, at such office or offices of the Transfer Agent as the Transfer Agent may specify, or as may be required by any National Securities Exchange on which such Limited Partner Interests are listed or admitted for trading. Any such Notice of Election to Purchase mailed to a Record Holder of Limited Partner Interests at his address as reflected in the records of the Transfer Agent shall be conclusively presumed to have been given regardless of whether the owner receives such notice. On or prior to the Purchase Date, the General Partner, its Affiliate or the Partnership, as the case may be, shall deposit with the Transfer Agent cash in an amount sufficient to pay the aggregate purchase price of all of such Limited Partner Interests to be purchased in accordance with this Section 15.1. If the Notice of Election to Purchase shall have been duly given as aforesaid at least 10 days prior to the Purchase Date, and if on or prior to the Purchase Date the deposit described in the preceding sentence has been made for the benefit of the holders of Limited Partner Interests subject to purchase as provided herein, then from and after the Purchase Date, notwithstanding that any Certificate shall not have been surrendered for purchase, all rights of the holders of such Limited Partner Interests (including any rights pursuant to Articles IV, V, VI, and XII) shall thereupon cease, except the right to receive the purchase price (determined in accordance with Section 15.1(a)) for Limited Partner Interests therefor, without interest, upon surrender to the Transfer

 

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Agent of the Certificates representing such Limited Partner Interests, and such Limited Partner Interests shall thereupon be deemed to be transferred to the General Partner, its Affiliate or the Partnership, as the case may be, on the record books of the Transfer Agent and the Partnership, and the General Partner or any Affiliate of the General Partner, or the Partnership, as the case may be, shall be deemed to be the owner of all such Limited Partner Interests from and after the Purchase Date and shall have all rights as the owner of such Limited Partner Interests (including all rights as owner of such Limited Partner Interests pursuant to Articles IV, V, VI and XII).

(c) At any time from and after the Purchase Date, a holder of an Outstanding Limited Partner Interest subject to purchase as provided in this Section 15.1 may surrender his Certificate evidencing such Limited Partner Interest to the Transfer Agent in exchange for payment of the amount described in Section 15.1(a), therefor, without interest thereon.

(d) Notwithstanding anything in Article XIII to the contrary, this Article cannot be amended without the affirmative vote of the holders of not less than 90% of the Outstanding Units.

ARTICLE XVI

COMMON UNIT REDEMPTION AGREEMENT

Section 16.1 Redemption of Units.

(a) In the event that the General Partner determines that the Partnership will offer and sell more than 17,500,000 Common Units in the Initial Offering, then on the Closing Date (as defined below), and subject to the terms and conditions and in reliance on the representations and warranties herein set forth, the Initial Limited Partners agree to transfer to the Partnership, and the Partnership agrees to redeem from the Initial Limited Partners, a number of Common Units, the number of Common Units purchased from the Partnership by the Underwriters on the Closing Date (excluding the Option Units) that exceed 17,500,000 Common Units (the “ Upsize IPO Units ”). The redemption price per Common Unit redeemed by the Partnership pursuant to this Section 16.1(a) shall be equal to the Issue Price. The closing of such transfer and purchase (the “ IPO Upsize Redemption ”) shall take place at such place and such time so as to coincide with the Underwriters’ initial purchase of Common Units from the Partnership on the Closing Date. The number of Upsize IPO Units to be transferred by an Initial Limited Partner, and purchased by the Partnership, shall be determined on a pro rata basis based on the aggregate number of Common Units owned by such Initial Limited Partner on the Closing Date (prior to giving effect to this Section 16.1(a)) in relation to the total number of Common Units outstanding on the Closing Date (prior to giving effect to the Initial Offering and this Section 16.1(a)).

(b) On the Option Closing Date, and subject to the terms and conditions and in reliance on the representations and warranties herein set forth, the Initial Limited Partners agree to transfer to the Partnership, and the Partnership agrees to redeem from the Initial Limited Partners a number of Common Units purchased from the Partnership by the Underwriters pursuant to the exercise of the Over-Allotment Option (the “ Option Units Redemption ”). The redemption price per Common Unit redeemed by the Partnership pursuant to this Section 16.1(b) shall be equal to the Issue Price. The closing of such Option Units Redemption shall take place

 

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at such place and such time so as to coincide with the Underwriters’ purchase of Option Units from the Partnership on the Option Closing Date. The number of Option Units to be transferred by an Initial Limited Partner, and purchased by the Partnership, shall be determined on a pro rata basis based on the aggregate number of Common Units owned by such Initial Limited Partner on the Option Closing Date (prior to giving effect to this Section 16.1(b)) in relation to the total number of Common Units outstanding on the Option Closing Date (prior to giving effect to this Section 16.1(b)).

(c) At each closing pursuant to this Section 16.1, each Initial Limited Partner shall assign and transfer to the Partnership all its right, title and interest in and to the IPO Upsize Units or the Option Units, as the case may be, free and clear of all liens or other limitations or restrictions and deliver to the Partnership the certificate or certificates representing the IPO Upsize Units or the Option Units, as the case may be, duly endorsed in blank or accompanied by separate stock powers so endorsed. Each Initial Limited Partner shall execute the certificate of transfer on the back of the certificate or certificates representing the IPO Upsize Units or the Option Units, as the case may be.

(d) The Partnership shall pay the Issue Price for the IPO Upsize Units or the Option Units, as the case may be, of each Initial Limited Partner on the Closing Date or Option Closing Date, as the case may be, without deduction, by wire transfer of immediately available funds to an account of such Initial Limited Partner (the number for which account shall have been furnished to the Partnership at least one business day prior to such closing date).

Section 16.2 Representations and Warranties of Initial Limited Partners. Each Initial Limited Partner hereby severally represents and warrants to, and agrees with the Partnership, as applicable, that:

(a) Existence and Power. Such Initial Limited Partner has the power and authority to execute and deliver this Agreement and perform each of its obligations contemplated by this ARTICLE XVI.

(b) Authority; Approvals. (i) If such Initial Limited Partner is a corporation, partnership, limited liability company or other entity, the execution and delivery of this Agreement by such Initial Limited Partner, the consummation by such Initial Limited Partner of each of the transactions and the performance by such Initial Limited Partner of its obligations contemplated hereby have been duly and properly authorized by all necessary corporate, partnership, limited liability company or other entity action on the part of such Initial Limited Partner. This Agreement has been duly executed and delivered by such Initial Limited Partner, and constitutes the valid and legally binding obligation of such Initial Limited Partner, enforceable against such Initial Limited Partner in accordance with its terms, subject, (A) as to enforceability, to bankruptcy, insolvency, reorganization, moratorium and other similar laws of general applicability relating to or affecting creditors’ rights and to general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law) and (B) to equitable principles of general applicability relating to the availability of specific performance, injunctive relief, or other equitable remedies.

 

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(ii) The execution and delivery of this Agreement by such Initial Limited Partner and the consummation of each of the transactions and the performance of each of the obligations contemplated by this ARTICLE XVI (A) do not conflict with, violate or breach (whether with or without notice or a lapse of time or both), require the consent of any Person to or otherwise result in a material detriment to such Initial Limited Partner under, (x) its organizational documents or (y) any agreement to which it is a party or by which its assets or property is bound or any law or order applicable to it.

(iii) No approval from any Governmental Entity is required with respect to such Initial Limited Partner in connection with the execution and delivery by such Initial Limited Partner of this Agreement, the performance by such Initial Limited Partner of its obligations under this ARTICLE XVI or the consummation by such Initial Limited Partner of the transactions contemplated by this ARTICLE XVI, except for any such approval the failure of which to be made or obtained (A) has not impaired and could not reasonably be expected to impair the ability of such Initial Limited Partner to perform its obligations under this ARTICLE XVI in any material respect, and (B) could not reasonably be expected to delay, in any material respect, or prevent the consummation of any of the transactions contemplated by this Agreement. As used in this ARTICLE XVI, the term “Governmental Entity” means any agency, bureau, commission, authority, department, official, political subdivision, tribunal or other instrumentality of any government, whether (x) regulatory, administrative or otherwise; (y) federal, state or local; or (z) domestic or foreign.

(c) Ownership of Redemption Units. Such Initial Limited Partner is the record and beneficial owner of the IPO Upsize Units and Option Units (collectively, the “ Redemption Units ”) to be sold by it pursuant to this ARTICLE XVI, free and clear of any lien and any other limitation or restriction with full right and authority to deliver the same hereunder, and will transfer and deliver to the Partnership on the Closing Date or the Option Closing Date, as the case may be, valid title to such Redemption Units, in each case free and clear of any lien and any such other limitation or restriction.

Section 16.3 Conditions to Closing of the IPO Upsize Redemption.

(a) Conditions to Obligations of the Partnership. The obligation of the Partnership to redeem the IPO Upsize Units on the Closing Date is subject to the satisfaction of the following conditions:

(i) The closing contemplated in Section 2 of the Underwriting Agreement shall have occurred with respect to the IPO Upsize Units;

(ii) No action, claim, suit, hearing, complaint, demand, injunction, litigation, judgment, arbitration, order, decree, ruling or governmental investigation or proceeding is then pending or threatened by any court or Governmental Entity, and no such court or Governmental Entity shall have issued any injunction, judgment or order, which shall remain in effect, that would prevent consummation of the IPO Upsize Redemption; provided, however, that the parties hereto shall use their reasonable best efforts to have any such injunction, judgment or order vacated or reversed;

 

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(iii) The representations and warranties of the Initial Limited Partners contained in Section 16.3 and in any certificate or other writing delivered by the Initial Limited Partners pursuant hereto shall be true in all material respects at and as of the Closing Date, as if made at and as of such date.

(b) Conditions of Obligations of the Initial Limited Partners. The obligation of the Initial Limited Partners to consummate the transactions contemplated by Section 16.1(a) on the Closing Date is subject to the satisfaction of the following conditions:

(i) The closing contemplated in Section 2 of the Underwriting Agreement shall have occurred with respect to the IPO Upsize Units; and

(ii) No action, claim, suit, hearing, complaint, demand, injunction, litigation, judgment, arbitration, order, decree, ruling or governmental investigation or proceeding is then pending or threatened by any court or Governmental Entity, and no such court or Governmental Entity shall have issued any injunction, judgment or order, which shall remain in effect, that would prevent consummation of the IPO Upsize Redemption; provided, however, that the parties hereto shall use their reasonable best efforts to have any such injunction, judgment or order vacated or reversed.

Section 16.4 Conditions to Closing of the Option Units Redemption.

(a) Conditions to Obligations of the Partnership. The obligation of the Partnership to redeem the Option Units on the Option Closing Date is subject to the satisfaction of the following conditions:

(i) The closing contemplated in Section 2 of the Underwriting Agreement shall have occurred with respect to the Option Units;

(ii) No action, claim, suit, hearing, complaint, demand, injunction, litigation, judgment, arbitration, order, decree, ruling or governmental investigation or proceeding is then pending or threatened by any court or Governmental Entity, and no such court or Governmental Entity shall have issued any injunction, judgment or order, which shall remain in effect, that would prevent consummation of the Option Redemption; provided, however, that the parties hereto shall use their reasonable best efforts to have any such injunction, judgment or order vacated or reversed;

(iii) The representations and warranties of the Initial Limited Partners contained in Section 16.3 and in any certificate or other writing delivered by the Initial Limited Partners pursuant hereto shall be true in all material respects at and as of the Option Closing Date, as if made at and as of such date.

(b) Conditions of Obligations of the Initial Limited Partners. The obligation of the Initial Limited Partners to consummate the transactions contemplated on the Option Closing Date is subject to the satisfaction of the following conditions:

(i) The closing contemplated in Section 2 of the Underwriting Agreement shall have occurred with respect to the Option Units; and

 

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(ii) No action, claim, suit, hearing, complaint, demand, injunction, litigation, judgment, arbitration, order, decree, ruling or governmental investigation or proceeding is then pending or threatened by any court or Governmental Entity, and no such court or Governmental Entity shall have issued any injunction, judgment or order, which shall remain in effect, that would prevent consummation of the Option Redemption; provided, however, that the parties hereto shall use their reasonable best efforts to have any such injunction, judgment or order vacated or reversed.

ARTICLE XVII

GENERAL PROVISIONS

Section 17.1 Addresses and Notices.

Any notice, demand, request, report or proxy materials required or permitted to be given or made to a Partner or Assignee under this Agreement shall be in writing and shall be deemed given or made when delivered in person or when sent by first class United States mail or by other means of written communication to the Partner or Assignee at the address described below. Any notice, payment or report to be given or made to a Partner or Assignee hereunder shall be deemed conclusively to have been given or made, and the obligation to give such notice or report or to make such payment shall be deemed conclusively to have been fully satisfied, upon sending of such notice, payment or report to the Record Holder of such Partnership Securities at his address as shown on the records of the Transfer Agent or as otherwise shown on the records of the Partnership, regardless of any claim of any Person who may have an interest in such Partnership Securities by reason of any assignment or otherwise. An affidavit or certificate of making of any notice, payment or report in accordance with the provisions of this Section 17.1 executed by the General Partner, the Transfer Agent or the mailing organization shall be prima facie evidence of the giving or making of such notice, payment or report. If any notice, payment or report addressed to a Record Holder at the address of such Record Holder appearing on the books and records of the Transfer Agent or the Partnership is returned by the United States Postal Service marked to indicate that the United States Postal Service is unable to deliver it, such notice, payment or report and any subsequent notices, payments and reports shall be deemed to have been duly given or made without further mailing (until such time as such Record Holder or another Person notifies the Transfer Agent or the Partnership of a change in his address) if they are available for the Partner or Assignee at the principal office of the Partnership for a period of one year from the date of the giving or making of such notice, payment or report to the other Partners and Assignees. Any notice to the Partnership shall be deemed given if received by the General Partner at the principal office of the Partnership designated pursuant to Section 2.3. The General Partner may rely and shall be protected in relying on any notice or other document from a Partner or Assignee or other Person if believed by it to be genuine.

 

- 85 -


Section 17.2 Further Action.

The parties shall execute and deliver all documents, provide all information and take or refrain from taking action as may be necessary or appropriate to achieve the purposes of this Agreement.

Section 17.3 Binding Effect.

This Agreement shall be binding upon and inure to the benefit of the parties hereto and their heirs, executors, administrators, successors, legal representatives and permitted assigns.

Section 17.4 Integration.

This Agreement constitutes the entire agreement among the parties hereto pertaining to the subject matter hereof and supersedes all prior agreements and understandings pertaining thereto.

Section 17.5 Creditors.

None of the provisions of this Agreement shall be for the benefit of, or shall be enforceable by, any creditor of the Partnership.

Section 17.6 Waiver.

No failure by any party to insist upon the strict performance of any covenant, duty, agreement or condition of this Agreement or to exercise any right or remedy consequent upon a breach thereof shall constitute waiver of any such breach of any other covenant, duty, agreement or condition.

Section 17.7 Counterparts.

This Agreement may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart. Each party shall become bound by this Agreement immediately upon affixing its signature hereto or, in the case of a Person acquiring a Limited Partner Interest upon accepting the certificate evidencing such Limited Partner Interest or executing and delivering a Transfer Application as herein described, independently of the signature of any other party.

Section 17.8 Applicable Law.

This Agreement shall be construed in accordance with and governed by the laws of the State of Delaware, without regard to the principles of conflicts of law.

 

- 86 -


Section 17.9 Invalidity of Provisions.

If any provision of this Agreement is or becomes invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions contained herein shall not be affected thereby.

Section 17.10 Consent of Partners.

Each Partner hereby expressly consents and agrees that, whenever in this Agreement it is specified that an action may be taken upon the affirmative vote or consent of less than all of the Partners, such action may be so taken upon the concurrence of less than all of the Partners and each Partner shall be bound by the results of such action.

Section 17.11 Facsimile Signatures.

The use of facsimile signatures affixed in the name and on behalf of the transfer agent and registrar of the Partnership on certificates representing Common Units is expressly permitted by this Agreement.

Section 17.12 Third Party Beneficiaries.

Each Partner agrees that any Indemnitee shall be entitled to assert rights and remedies hereunder as a third party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or privilege to such Indemnitee.

[Rest of Page Intentionally Left Blank]

 

- 87 -


IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first written above.

 

GENERAL PARTNER:
LE GP, LLC
By:  

/s/ John W. McReynolds

 

John W. McReynolds

President

LIMITED PARTNERS:
All Limited Partners now and hereafter admitted as Limited Partners of the Partnership, pursuant to powers of attorney now and hereafter executed in favor of, and granted and delivered to the General Partner or without execution hereof pursuant to Section 10.1(a).
By:   LE GP, LLC
General Partner, as attorney-in-fact for the Limited Partners pursuant to the Powers of Attorney granted pursuant to Section 2.6.
By:  

/s/ John W. McReynolds

 

John W. McReynolds

President

 

- 88 -


EXHIBIT A

to the Third Amended and Restated

Agreement of Limited Partnership of

Energy Transfer Equity, L.P.

Certificate Evidencing Common Units

Representing Limited Partner Interests in

Energy Transfer Equity, L.P.

 

No. _______________    _______________ Common Units

In accordance with Section 4.1 of the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., as amended, supplemented or restated from time to time (the “ Partnership Agreement ”), Energy Transfer Equity, L.P., a Delaware limited partnership (the “ Partnership ”), hereby certifies that ___________________ (the “ Holder ”) is the registered owner of Common Units representing limited partner interests in the Partnership (the “ Common Units ”) transferable on the books of the Partnership, in person or by duly authorized attorney, upon surrender of this Certificate properly endorsed and accompanied by a properly executed application for transfer of the Common Units represented by this Certificate. The rights, preferences and limitations of the Common Units are set forth in, and this Certificate and the Common Units represented hereby are issued and shall in all respects be subject to the terms and provisions of, the Partnership Agreement. Copies of the Partnership Agreement are on file at, and will be furnished without charge on delivery of written request to the Partnership at, the principal office of the Partnership located at 2828 Woodside Street, Dallas, Texas 75204. Capitalized terms used herein but not defined shall have the meanings given them in the Partnership Agreement.

The Holder, by accepting this Certificate, is deemed to have (i) requested admission as, and agreed to become, a Limited Partner and to have agreed to comply with and be bound by and to have executed the Partnership Agreement, (ii) represented and warranted that the Holder has all right, power and authority and, if an individual, the capacity necessary to enter into the Partnership Agreement, (iii) granted the powers of attorney provided for in the Partnership Agreement and (iv) made the waivers and given the consents and approvals contained in the Partnership Agreement.

THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF ENERGY TRANSFER EQUITY, L.P. THAT THIS SECURITY MAY NOT BE SOLD, OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED IF SUCH TRANSFER WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF ENERGY TRANSFER EQUITY, L.P. UNDER THE LAWS OF THE STATE OF DELAWARE, OR (C) CAUSE ENERGY TRANSFER EQUITY, L.P. TO BE TREATED AS AN ASSOCIATION TAXABLE AS A

 

A-1


CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED). LE GP, LLC, THE GENERAL PARTNER OF ENERGY TRANSFER EQUITY, L.P., MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF ENERGY TRANSFER EQUITY, L.P. BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES. THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.

This Certificate shall not be valid for any purpose unless it has been countersigned and registered by the Transfer Agent and Registrar.

 

Dated:_______________     Energy Transfer Equity, L.P.
Countersigned and Registered by:     By:   LE GP, LLC,
        its General Partner

     

    By:  

     

as Transfer Agent and Registrar     Name:  
By:  

     

    By:  

     

  Authorized Signature       Secretary

[ Reverse of Certificate ]

ABBREVIATIONS

The following abbreviations, when used in the inscription on the face of this Certificate, shall be construed as follows according to applicable laws or regulations:

 

TEN COM -    as tenants in common       UNIF GIFT/TRANSFERS MIN ACT
TEN ENT -    as tenants by the entireties       __________ Custodian _________
         (Cust)                                      (Minor)
JT TEN -    as joint tenants with right of survivorship and not as tenants in common       under Uniform Gifts/Transfers to CD
Minors Act (State)

Additional abbreviations, though not in the above list, may also be used.

FOR VALUE RECEIVED, __________ hereby assigns, conveys, sells and transfers unto

 

     

    

     

(Please print or typewrite name
and address of Assignee)
     (Please insert Social Security or other
identifying number of Assignee)

 

 

A-2


__________ Common Units representing limited partner interests evidenced by this Certificate, subject to the Partnership Agreement, and does hereby irrevocably constitute and appoint __________ as its attorney-in-fact with full power of substitution to transfer the same on the books of Energy Transfer Equity, L.P.

 

Date: _____________________      NOTE:    The signature to any endorsement hereon must correspond with the name as written upon the face of this Certificate in every particular, without alteration, enlargement or change.
THE SIGNATURE(S) MUST BE GUARANTEED BY AN ELIGIBLE GUARANTOR INSTITUTION (BANKS, STOCKBROKERS, SAVINGS AND LOAN ASSOCIATIONS AND CREDIT UNIONS WITH MEMBERSHIP IN AN APPROVED SIGNATURE GUARANTEE MEDALLION PROGRAM), PURSUANT TO S.E.C. RULE 17Ad-15        
       

     

        (Signature)
       

     

        (Signature)

     

       

No transfer of the Common Units evidenced hereby will be registered on the books of the Partnership, unless the Certificate evidencing the Common Units to be transferred is surrendered for registration or transfer and, following a FERC Notice, an Application for Transfer of Common Units has been properly completed and executed by a transferee either (a) on the form set forth below or (b) on a separate application that the Partnership will furnish on request without charge. A transferor of the Common Units shall have no duty to the transferee with respect to execution of the Application for Transfer of Common Units in order for such transferee to obtain registration of the transfer of the Common Units.

 

 

A-3


EXHIBIT B

to the Third Amended and Restated

Agreement of Limited Partnership of

Energy Transfer Equity, L.P.

Certificate Evidencing Class B Units

Representing Limited Partner Interests in

Energy Transfer Equity, L.P.

 

No. _______________    _______________ Class B Units

In accordance with Section 4.1 of the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., as amended, supplemented or restated from time to time (the “ Partnership Agreement ”), Energy Transfer Equity, L.P., a Delaware limited partnership (the “ Partnership ”), hereby certifies that ___________________ (the “ Holder ”) is the registered owner of Class B Units representing limited partner interests in the Partnership (the “ Class B Units ”) transferable on the books of the Partnership, in person or by duly authorized attorney, upon surrender of this Certificate properly endorsed and accompanied by a properly executed application for transfer of the Class B Units represented by this Certificate. The rights, preferences and limitations of the Class B Units are set forth in, and this Certificate and the Class B Units represented hereby are issued and shall in all respects be subject to the terms and provisions of, the Partnership Agreement. Copies of the Partnership Agreement are on file at, and will be furnished without charge on delivery of written request to the Partnership at, the principal office of the Partnership located at 2828 Woodside Street, Dallas, Texas 75204. Capitalized terms used herein but not defined shall have the meanings given them in the Partnership Agreement.

The Holder, by accepting this Certificate, is deemed to have (i) requested admission as, and agreed to become, a Limited Partner and to have agreed to comply with and be bound by and to have executed the Partnership Agreement, (ii) represented and warranted that the Holder has all right, power and authority and, if an individual, the capacity necessary to enter into the Partnership Agreement, (iii) granted the powers of attorney provided for in the Partnership Agreement and (iv) made the waivers and given the consents and approvals contained in the Partnership Agreement.

THIS SECURITY HAS NOT BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933, AS AMENDED. IT MAY NOT BE SOLD, OFFERED FOR SALE, PLEDGED OR HYPOTHECATED IN THE ABSENCE OF A REGISTRATION STATEMENT IN EFFECT WITH RESPECT TO THE SECURITIES UNDER SUCH ACT OR AN OPINION OF COUNSEL SATISFACTORY TO THE PARTNERSHIP THAT SUCH REGISTRATION IS NOT REQUIRED.

THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF ENERGY TRANSFER EQUITY, L.P. THAT THIS SECURITY MAY NOT BE SOLD, OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED IF SUCH TRANSFER WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES

 

 

B-1


LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF ENERGY TRANSFER EQUITY, L.P. UNDER THE LAWS OF THE STATE OF DELAWARE, OR (C) CAUSE ENERGY TRANSFER EQUITY, L.P. TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED). LE GP, LLC, THE GENERAL PARTNER OF ENERGY TRANSFER EQUITY, L.P., MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF ENERGY TRANSFER EQUITY, L.P. BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES. THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.

This Certificate shall not be valid for any purpose unless it has been countersigned and registered by the Transfer Agent and Registrar.

 

Dated:_______________     Energy Transfer Equity, L.P.
Countersigned and Registered by:     By:   LE GP, LLC,
        its General Partner

     

    By:  

     

as Transfer Agent and Registrar     Name:  

 

By:  

     

    By:  

     

  Authorized Signature       Secretary

[Reverse of Certificate ]

ABBREVIATIONS

The following abbreviations, when used in the inscription on the face of this Certificate, shall be construed as follows according to applicable laws or regulations:

 

TEN COM -    as tenants in common       UNIF GIFT/TRANSFERS MIN ACT
TEN ENT -    as tenants by the entireties       __________ Custodian _________
         (Cust)                                      (Minor)
JT TEN -    as joint tenants with right of survivorship and not as tenants in common       under Uniform Gifts/Transfers to CD
Minors Act (State)

 

 

B-2


Additional abbreviations, though not in the above list, may also be used.

FOR VALUE RECEIVED, __________ hereby assigns, conveys, sells and transfers unto

 

     

  

     

(Please print or typewrite name
and address of Assignee)
   (Please insert Social Security or other
identifying number of Assignee)

__________ Class B Units representing limited partner interests evidenced by this Certificate, subject to the Partnership Agreement, and does hereby irrevocably constitute and appoint __________ as its attorney-in-fact with full power of substitution to transfer the same on the books of Energy Transfer Equity, L.P.

 

Date: _____________________    NOTE:    The signature to any endorsement hereon must correspond with the name as written upon the face of this Certificate in every particular, without alteration, enlargement or change.
THE SIGNATURE(S) MUST BE GUARANTEED BY AN ELIGIBLE GUARANTOR INSTITUTION (BANKS, STOCKBROKERS, SAVINGS AND LOAN ASSOCIATIONS AND CREDIT UNIONS WITH MEMBERSHIP IN AN APPROVED SIGNATURE GUARANTEE MEDALLION PROGRAM), PURSUANT TO S.E.C. RULE 17Ad-15      

(Signature)

 

(Signature)

     

     

No transfer of the Class B Units evidenced hereby will be registered on the books of the Partnership, unless the Certificate evidencing the Class B Units to be transferred is surrendered for registration or transfer and, following a FERC Notice, an Application for Transfer of Class B Units has been properly completed and executed by a transferee either (a) on the form set forth below or (b) on a separate application that the Partnership will furnish on request without charge. A transferor of the Class B Units shall have no duty to the transferee with respect to execution of the Application for Transfer of Class B Units in order for such transferee to obtain registration of the transfer of the Class B Units.

 

 

B-3


EXHIBIT C

to the Third Amended and Restated

Agreement of Limited Partnership of

Energy Transfer Equity, L.P.

Application for Transfer of Common Units

Following a FERC Notice, transferees of Common Units must execute and deliver this application to Energy Transfer Equity, L.P., c/o LE GP, LLC, 2828 Woodside Street, Dallas, Texas 75204; Attn: CFO, to be admitted as limited partners of Energy Transfer Equity, L.P. (the “ Partnership ”).

The undersigned (“ Assignee ”) hereby (a) applies for transfer to the name of the Assignee the Common Units evidenced hereby, (b) requests admission as a Substituted Limited Partner and agrees to comply with and be bound by, and hereby executes, the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., as amended, supplemented or restated to the date hereof (the “ Partnership Agreement ”), (c) represents and warrants that the Assignee has all right, power and authority and, if an individual, the capacity necessary to enter into the Partnership Agreement, (d) appoints the General Partner of the Partnership and, if a Liquidator shall be appointed, the Liquidator of the Partnership as the Assignee’s attorney-in-fact to execute, swear to, acknowledge and file any document, including the Partnership Agreement and any amendment thereto and the Certificate of Limited Partnership of the Partnership and any amendment thereto, necessary or appropriate for the Assignee’s admission as a Substituted Limited Partner and as a party to the Partnership Agreement, (e) gives the powers of attorney provided for in the Partnership Agreement, and (f) makes the waivers and gives the consents and approvals contained in the Partnership Agreement. Capitalized terms not defined herein have the meanings assigned to such terms in the Partnership Agreement. This application constitutes a Taxation Certification, as defined in the Partnership Agreement.

 

Date:________________________     

     

     Signature of Assignee

     

    

     

Social Security or other identifying number      Name and Address of Assignee

 

 

C-1


Annex A

Taxation Certification

The undersigned hereby certifies to Energy Transfer Equity, L.P. (the “ Partnership ”) that the Assignee (including to the best of Assignee’s knowledge, any person for whom the Assignee will hold the Common Units) is an Eligible Holder. 1

Type of Assignee (check one):

 

☐ Individual      ☐ Partnership       ☐ Corporation (Subchapter C)
☐ (Corporation (Subchapter S)            ☐ Pension Fund, IRA or KEOGH             Plan
Tax-exempt entities such as municipalities           
☐ Trust      ☐ Mutual Fund       ☐ Other (specify)_________________

If not an Individual (check one):

 

the entity is subject to United States federal income taxation on the income generated by the Partnership;

 

the entity is not subject to United States federal income taxation, but it is a pass-through entity and all of its beneficial owners are subject to United States federal income tax on the income generated by the Partnership;

 

the entity is not subject to United States federal income taxation and it is (a) not a pass-through entity or (b) a pass-through entity, but not all of its beneficial owners are subject to United States federal income taxation on the income generated by the Partnership. [ IMPORTANT NOTE – by checking this box, the undersigned is acknowledging that it is not an Eligible Holder.]

Type of Tax Return Filed by Assignee (check one):

 

☐ Form 1040      ☐ Form 1120       ☐ Other (specify) ______________

Nationality (check one):

 

☐   U.S. Citizen, Resident or Domestic Entity

       

☐   Foreign Corporation

     Non-resident Alien   

 

1 

The term “Eligible Holder” means (a) an individual or entity subject to United States federal income taxation on the income generated by the Partnership; or (b) an entity not subject to United States federal income taxation on the income generated by the Partnership, so long as all of the entity’s owners are subject to United States federal income taxation on the income generated by the Partnership. Schedule I hereto contains a list of various types of investors that are categorized and identified as either “Eligible Holders” or “Non-Eligible Holders.”

 

C-2


If the U.S. Citizen, Resident or Domestic Entity box is checked, the following certification must be completed.

Under Section 1445(e) of the Internal Revenue Code of 1986, as amended (the “ Code ”), the Partnership must withhold tax with respect to certain transfers of property if a holder of an interest in the Partnership is a foreign person. To inform the Partnership that no withholding is required with respect to the undersigned’s interest in it, the undersigned hereby certifies the following (or, if applicable, certifies the following on behalf of the holder of the interest).

Complete Either A or B:

 

A.

Individual

 

  1.

I am not a non-resident alien for purposes of U.S. income taxation.

 

  2.

My U.S. taxpayer identification number (Social Security Number) is _____________.

 

  3.

My home address is _________________________________________________.

 

B.

Partnership, Corporation or Other

 

  1.

___________________________________________________ is not a foreign corporation, foreign partnership, foreign trust (name of undersigned) or foreign estate (as those terms are defined in the Code and Treasury Regulations).

 

  2.

The undersigned’s U.S. employer identification number is __________________.

 

  3.

The undersigned’s office address and place of incorporation (if applicable) is_________________________________________________________________.

The undersigned agrees to notify the Partnership within sixty (60) days of the date the undersigned becomes a foreign person.

The undersigned understands that this certificate may be disclosed to the Internal Revenue Service by the Partnership and that any false statement contained herein could be punishable by fine, imprisonment or both.

Under penalties of perjury, I declare that I have examined this certification and to the best of my knowledge and belief it is true, correct and complete and, if applicable, I further declare that I have authority to sign this document on behalf of:

 

     

Name of Holder of Interest

     

Signature and Date

     

Title (if applicable)

 

 

C-3


Note: If the undersigned is a broker, dealer, bank, trust company, clearing corporation, other nominee holder or an agent of any of the foregoing, and is holding for the account of any other person, this application should be completed by an officer thereof or, in the case of a broker or dealer, by a registered representative who is a member of a registered national securities exchange or a member of the National Association of Securities Dealers, Inc., or, in the case of any other nominee holder, a person performing a similar function. If the undersigned is a broker, dealer, bank, trust company, clearing corporation, other nominee owner or an agent of any of the foregoing, the above certification as to any person for whom the undersigned will hold the Common Units shall be made to the best of the undersigned’s knowledge.

 

 

C-4


Schedule I

Eligible Holders

The following are considered Eligible Holders:

 

   

Individuals (U.S. or non-U.S.)

 

   

C corporations (U.S. or non-U.S.)

 

   

Tax exempt organizations subject to tax on unrelated business taxable income or “UBTI,” including IRAs, 401(k) plans and Keough accounts

 

   

S corporations with shareholders that are individuals, trusts or tax exempt organizations subject to tax on UBTI

Potentially Eligible Holders

The following are considered Eligible Holders, unless the information in parenthesis applies:

 

   

S corporations (unless they have ESOP shareholders*)

 

   

Partnerships (unless its partners include mutual funds, real estate investment trusts or “REITs,” governmental entities and agencies, S corporations with ESOP shareholders* or other partnerships with such partners)

 

   

Trusts (unless beneficiaries are not subject to tax)

Non-Eligible Holders

The following are not considered Eligible Holders:

 

   

Mutual Funds

 

   

REITs

 

   

Governmental entities and agencies

 

   

S corporations with ESOP shareholders*

 

*

“S corporations with ESOP shareholders” are S corporations with shareholders that include employee stock ownership plans.

 

 

C-5


EXHIBIT D

to the Third Amended and Restated

Agreement of Limited Partnership of

Energy Transfer Equity, L.P.

 

Initial Limited Partners    Common Units Owned  
     Pre-Split      Post-Split 1  

ETC Holdings, L.P.

2838 Woodside Street

Dallas, TX 75204

     151,936,519        82,662,382  

ET Company, Ltd.

2838 Woodside Street

Dallas, TX 75204

     296,359        161,237  

Kellen Holdings, LLC

c/o Liberty Energy Holdings

175 Berkley Street

Boston, MA 02116

     22,000,000        11,969,291  

Oasis Gas Partners LLC

111 Center Street, Suite 2500

Little Rock, AR 72201

     18,000,000        9,793,056  

Sowood Commodity Partners Fund LP

500 Boylston Street, 17th floor

Boston, MA 02116

     13,000,000        7,072,763  

PH Investments, LLC

c/o The Pilot House

Lewis Wharf

Boston, MA 02110

     10,000,000        5,440,587  

Greenhill Capital Partners, L.P.

Greenhill Capital Partners (Cayman), L.P.

Greenhill Capital Partners (Executives), L.P.

Greenhill Capital, L.P.

    

6,188,688

884,298

976,791

1,950,223

 

 

 

 

    

3,367,009

481,110

531,432

1,061,036

 

 

 

 

c/o Greenhill & Co. LLC

300 Park Avenue, 23rd Floor

New York, NY 10022

     

 

1 

After reverse unit split using a factor of .544058682.

 

D-1


Initial Limited Partners    Common Units Owned  
     Pre-Split      Post-Split1  

WH Energy Investors, L.L.C.

c/o Midland Properties, Inc.

2001 Shawnee Mission Parkway

Shawnee Mission, KS 66205

     3,000,000        1,632,176  

UNC Investment Funds, LLC

c/o UNC Management Company, Inc.

308 West Rosemary Street, Suite 203

Chapel Hill, NC 27516

     1,200,000        652,870  

Phillips Oil & Gas, Inc.

330 Marshall Street, Suite 300

Shreveport, LA 71101

     500,000        272,029  

Rainbow Investments Company

710 Buffalo Street, Suite 800

Corpus Christi, TX 78401

     300,000        163,218  

Lon C. Kile

808 Huntington Ct.

Southlake, TX 76092

     500,000        272,029  

Steven R. Anderson

P.O. Box 8916

Horseshoe Bay, TX 78657

     1,214,575        660,800  

David W. Brantley, Jr.

2308 Worthington

Dallas, TX 75204

     303,645        165,200  

Jeffrey Woodley Burrow

6851 Westlake Ave.

Dallas, Texas 75214

     607,287        330,400  

John Walter Daigh

825 Johns Rd, # 628

Boerne, TX 78006

     607,287        330,400  

Timothy B. Dahlstrom

2314 Encino Cliff

San Antonio, TX 78259

     303,644        165,200  

Exhibit D-2


Initial Limited Partners    Common Units Owned  
     Pre-Split      Post-Split1  

Charles R Hays Jr.

13511 Norland

San Antonio TX, 78232

     303,644        165,200  

George Clayton Kutch

2838 Woodside St.

Dallas, TX 75204

     1,214,575        660,800  

Donald James LaBauve

7709 Broadway, No. 322B

San Antonio, TX 78209

     607,287        330,400  

Renee Y. Lorenz

1617 Heatherbrook Ct.

Southlake, TX 76092

     1,214,575        660,800  

Leonard Ray McMillian

718 Cedar Creek Drive

Tyler, Tx 75703

     607,287        330,400  

John M. Stallcup

8711 S. Winston Ave.

Tulsa, OK 74137

     303,644        165,200  

FHM Investments, LLC

7005 Quail Rock Lane

Reno, NV 89511

     12,610,488        6,860,846  

Total Number of Common Units

     250,630,816        136,357,871  

Exhibit D-3

EX-3.4

Exhibit 3.4

AMENDMENT NO. 1

TO

THIRD AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP

OF

ENERGY TRANSFER EQUITY, L.P.

This Amendment No. 1 (this “ Amendment ”) to the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., a Delaware limited partnership (the “ Partnership ”), dated as of February 8, 2006 (the “ Partnership Agreement ”), is entered into effective as of November 1, 2006, by LE GP, LLC, a Delaware limited liability company (the “ General Partner ”), as the general partner of the Partnership, on behalf of itself and the Limited Partners of the Partnership. Capitalized terms used but not defined herein are used as defined in the Partnership Agreement.

RECITALS

WHEREAS, Section 5.8 of the Partnership Agreement provides that the General Partner, without the approval of any Limited Partner except as otherwise provided in the Partnership Agreement, may, for any Partnership purpose, at any time or from time to time, issue additional Partnership Securities for such consideration and on such terms and conditions as shall be established by the General Partner in its sole discretion; and

WHEREAS, Section 13.1(d)(i) of the Partnership Agreement provides that the General Partner, without the approval of any Partner, may amend any provision of the Partnership Agreement (to reflect a change that, in the discretion of the General Partner, does not adversely affect the Unitholders in any material respect); and

WHEREAS, Section 13.1(g) of the Partnership Agreement provides that the General Partner, without the approval of any Partner (subject to Section 5.9 of the Partnership Agreement), may amend any provision of the Partnership Agreement to reflect an amendment that, in the discretion of the General Partner, is necessary or appropriate in connection with the authorization of issuance of any class or series of Partnership Securities pursuant to Section 5.8 of the Partnership Agreement; and

WHEREAS, the Partnership has entered into a Contribution and Conveyance Agreement, dated as of November 1, 2006 (the “ Contribution Agreement ”), between the Partnership and Energy Transfer Investments, L.P., a Delaware limited partnership (“ ETI ”), pursuant to which ETI will contribute to the Partnership the 50% Class B limited partner interest in Energy Transfer Partners GP, L.P. owned by ETI in exchange for a new class of Partnership Securities to be designated as “Class C Units” with such terms as are set forth in this Amendment; and

WHEREAS, the General Partner has determined that the creation of the Class C Units will be in the best interests of the Partnership and beneficial to the Limited Partners, including the holders of the Common Units; and

WHEREAS, the issuance of the Class C Units complies with the requirements of the Partnership Agreement; and

WHEREAS, the General Partner has determined, pursuant to Section 13.1(j) of the Partnership Agreement, that the amendments to the Partnership Agreement set forth herein are necessary or appropriate in connection with the authorization of the issuance of the Class C Units; and

NOW, THEREFORE, the Partnership Agreement is hereby amended as follows:

Section 1. Amendments.

(a) Section 1.1 is hereby amended to add or amend and restate the following definitions:

Class C Distribution Increase Date ” has the meaning assigned to such term in Section 5.12(g).

Class C Unit ” means a Partnership Security representing a fractional part of the Partnership Interests of all Limited Partners and Assignees, and having the rights and obligations specified with respect to the Class C Units in this Agreement. The term “Class C Unit” does not refer to a Common Unit prior to the conversion of a Class C Unit into a Common Unit pursuant to the terms hereof.

Conversion Approval ” has the meaning assigned to such term in Section 5.12(f).

Conversion Approval Date ” has the meaning assigned to such term in Section 5.12(f).

Conversion Effective Date ” has the meaning assigned to such term in Section 5.12(h).

Excess Payment ” has the meaning set forth in Section 5.12(g).

Initial Common Units ” means the Common Units sold in the Initial Offering.

Initial Offering ” means the initial public offering and sale of Common Units to the public in February 2006.

Initial Unit Price ” means with respect to the Common Units and the Class G Units, the initial public offering price per Common Unit at which the Common Units were sold to the public in the Initial Offering.

 

1


Issue Price ” means the price at which a Unit is purchased from the Partnership, after taking into account any sales commission or underwriting discount charged to the Partnership and after taking into account any other form of discount with respect to the price at which a Unit is purchased from the Partnership.

Remaining Net Positive Adjustments ” means, as of the end of any taxable period, (i) with respect to the Unitholders holding Common Units, Class B Units or Class C Units, the excess of (a) the Net Positive Adjustments of the Unitholders holding Common Units, Class B Units or Class C Units as of the end of such period over (b) the sum of those Partners’ Share of Additional Book Basis Derivative Items for each prior taxable period and (ii) with respect to the General Partner (as holder of the General Partner Interest), the excess of (a) the Net Positive Adjustments of the General Partner as of the end of such period over (b) the sum of the General Partner’s Share of Additional Book Basis Derivative Items with respect to the General Partner Interest for each prior taxable period.

Share of Additional Book Basis Derivative Items ” means, in connection with any allocation of Additional Book Basis Derivative Items for any taxable period, (i) with respect to the Unitholders holding Common Units, Class B Units or Class C Units, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Unitholders’ Remaining Net Positive Adjustments as of the end of such period bears to the Aggregate Remaining Net Positive Adjustments as of that time and (ii) with respect to the General Partner (as holder of the General Partner Interest), the amount that bears the same ratio to such Additional Book Basis Derivative Items as the General Partner’s Remaining Net Positive Adjustments as of the end of such period bears to the Aggregate Remaining Net Positive Adjustment as of that time.

Outstanding ” means, with respect to Partnership Securities, all Partnership Securities that are issued by the Partnership and reflected as outstanding on the Partnership’s books and records as of the date of determination; provided, however, that if at any time any Person or Group (other than the General Partner or its Affiliates) beneficially owns 20% or more of any Outstanding Partnership Securities of any class then Outstanding, all Partnership Securities owned by such Person or Group shall not be voted on any matter and shall not be considered to be Outstanding when sending notices of a meeting of Limited Partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under this Agreement, except that Common Units so owned shall be considered to be Outstanding for purposes of Section 11.1(b)(iv) (such Common Units shall not, however, be treated as a separate class of Partnership Securities for purposes of this Agreement); provided, further, that the limitation in the foregoing proviso shall not apply (i) to any Person or Group who acquired 20% or more of any Outstanding Partnership Securities of any class then Outstanding directly from the General Partner or its Affiliates, (ii) to any Person or Group who acquired 20% or more of any Outstanding Partnership Securities of any class then Outstanding directly or indirectly from a Person or Group described in clause (i) if the General Partner shall have notified such Person or Group in writing, prior to such acquisition, that such limitation shall not apply to such Person or Group or (iii) to any Person or Group who acquired 20% or more of any Partnership Securities issued by the Partnership with the prior approval of the Board of Directors of the General Partner; and provided, further, that none of the Class C Units shall be deemed to be Outstanding for purposes of determining if any Class C Units are entitled to distributions of Available Cash unless such Class C Units shall have been reflected on the books of the Partnership as outstanding during such Quarter and on the Record Date for the determination of any distribution of Available Cash.

Unrecovered Capital ” means at any time, with respect to a Unit, the Initial Unit Price less the sum of all distributions made in respect of an Initial Common Unit and any distributions of cash (or the Net Agreed Value of any distributions in kind) in connection with the dissolution and liquidation of the Partnership theretofore made in respect of an Initial Common Unit, adjusted as the General Partner determines to be appropriate to give effect to any distribution, subdivision or combination of such Units.

(b) Section 1.1 of the Partnership Agreement is hereby further amended to amend and restate the final sentence of the definition of “Common Unit” as follows:

“The term “Common Unit” does not refer to a Class C Unit prior to its conversion into a Common Unit pursuant to the terms hereof.”

(c) Section 4.7(c) of the Partnership Agreement is hereby amended and restated to read in its entirety:

“(c) The transfer of a Class B Unit that has converted into a Common Unit shall be subject to the restrictions imposed by Section 6.4(b). The transfer of a Class C Unit shall be subject to the restrictions imposed by Section 6.5.”

(d) Article V is hereby amended to add a new Section 5.12 creating a new series of Units as follows:

“Section 5.12 Establishment of Class C Units.

(a) General. The General Partner hereby designates and creates a class of Units to be designated as “Class C Units” and consisting of a total of 83,148,900 Class C Units, and fixes the designations, preferences and relative, participating, optional or other special rights, powers and duties of holders of the Class C Units as set forth in this Section 5.12.

(b) Rights of Class C Units. During the period commencing upon issuance of the Class C Units and ending on the Conversion Effective Date (or that later time specified in this Section 5.12(b)), unless amended pursuant to Section 5.12(i) hereof:

(i) Allocations. Except as otherwise provided in this Agreement, all items of Partnership income, gain, loss, deduction and credit shall be allocated to the Class C Units to the same extent as such items would be so allocated if such Class C Units were Common Units that were then Outstanding.

 

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(ii) Distributions. Except as otherwise provided in this Agreement, the Class C Units shall have the right to share in partnership distributions on a pro rata basis with the Common Units, so that the amount of any Partnership distribution to each Common Unit will equal the amount of such distribution to each Class C Unit; provided, however, in the event that the Partnership would not have available cash with respect to any Quarter sufficient to distribute $0.175 (the “ Initial Quarterly Distribution Amount ”) in respect of each Common Unit, Class B Unit and Class C Unit or there shall exist in respect of any Quarter, a Cumulative Common Unit Arrearage, then Available Cash with respect to such Quarter shall, subject to Section 17–607 of the Delaware Act, be distributed as follows:

(A) First, to the Unitholders holding Common Units and Class B Units and to the General Partner, in proportion to their respective Percentage Interests, until there has been distributed in respect of each Common Unit and Class B Unit then outstanding an amount equal to the Initial Quarterly Distribution Amount for such Quarter;

(B) Second, to the Unitholders holding Common Units and Class B Units and to the General Partner, in proportion to their respective Percentage Interests, until there has been distributed in respect of each Common Unit and Class B Unit then outstanding an amount equal to the Cumulative Common Unit Arrearage;

(C) Third, to the Unitholders holding Class C Units and to the General Partner, in proportion to their respective Percentage Interests.

The following definitions shall be applied to the terms used in this Section 5.12(b):

Common Unit Arrearage ” means, with respect to any Common Unit, whenever issued, as to any Quarter ending on or prior to the Conversion Effective Date as to which distributions are made pursuant to the proviso to Section 5.12(b)(ii), the excess, if any, of (a) the Initial Quarterly Distribution Amount with respect to such Common Unit in respect of such Quarter over (b) the sum of all Available Cash distributed with respect to such Common Unit in respect of such quarter pursuant to clause (A) of the proviso to Section 5.12(b)(ii).

Cumulative Common Unit Arrearage ” means, with respect to any Common Unit, whenever issued, and as of the end of any Quarter, the excess, if any, of (a) the sum resulting from adding together the Common Unit Arrearage for each of the Quarters ending on or prior to theConversion Effective Date over (b) the sum of any distributions theretofore made pursuant to clause (B) of the proviso to Section 5.12(b)(ii).

(c) Voting Rights. The Class C Units will have such voting rights pursuant to the Partnership Agreement as such Class C Units would have if they were Common Units that were then Outstanding, except that (i) with respect to Conversion Approval, none of the Class C Units shall be deemed Outstanding as of the record date for such vote or be entitled to vote thereon and (ii) other than with respect to Conversion Approval, the Class C Units shall be entitled to vote as a separate class on any matter that adversely affects the rights or preferences of the Class C Units in relation to other classes of Partnership Interests or as required by law. The approval of a majority of the Class C Units shall be required to approve any matter for which the holders of the Class C Units are entitled to vote as a separate class. Each Class C Unit will be entitled to the number of votes equal to the number of Common Units into which a Class C Unit is convertible at the time of the record date for the vote or written consent on the matter.

(d) Certificates. The Class C Units will be evidenced by certificates in substantially the form of Exhibit A to this Amendment, subject to the satisfaction of any applicable legal and regulatory requirements, may be assigned or transferred in a manner identical to the assignment and transfer of other Units. The certificates will initially include a restrictive legend to the effect that the Class C Units have not been registered under the Securities Act or any state securities laws.

(e) Registrar and Transfer Agent. The General Partner will act as registrar and transfer agent of the Class C Units.

(f) Conversion. Except as provided in Section 5.12(i) and in this Section 5.12(f), the Class C Units are not convertible into Common Units. The Partnership shall, pursuant to the Contribution Agreement, take such actions as may be necessary or appropriate to submit to a vote or consent of the Unitholders (other than holders of Class C Units) the approval of a change in the terms of the Class C Units to provide that each Class C Unit shall automatically convert into one Common Unit (subject to appropriate adjustment in the event of any split-up, combination or similar event affecting the Common Units that occurs prior to the conversion of the Class C Units) effective immediately upon receipt of such approval from such Unitholders (the “ Conversion Approval ”) without any further action by the holders thereof. The vote or consent required for the Conversion Approval will be the requisite vote required under the rules or staff interpretations of the National Securities Exchange on which the Common Units are listed or admitted for trading. The date that Conversion Approval is obtained is herein referred to as the “ Conversion Approval Date. ” Upon receipt of the Conversion Approval and compliance with Section 5.12(h), the terms of the Class C Units will be changed, automatically and without further action, on the Conversion Effective Date (as defined in Section 5.12(h) below), so that each Class C Unit is converted into one Common Unit and, immediately thereafter, none of the Class C Units shall be Outstanding.

(g) Automatic Provisions. If the Conversion Effective Date has not occurred within 180 days following the date of issuance of the Class C Units, then, effective as of the next succeeding day (the “ Class C Distribution Increase Date ”) until the Conversion Effective Date, Section 5.12(b) will be deemed to be amended in its entirety, automatically and without further action, as follows:

(b) Rights of Class C Units. Prior to the Conversion Effective Date (or the later date specified in this Section 5.12(b)):

(i) Allocations. All allocations of items of Partnership income, gain, loss, deduction and credit shall be allocated to the Class C Units based on 115% of that which would be allocated to the Common Units so that the amount thereof allocated to each Class C Unit will be 115% of the amount thereof allocated to each Common Unit, and the allocations to Class C Units shall have the same order of priority relative to allocations on the Common Units.

 

3


(ii) Distributions. The Class C Units shall have the right to share in Partnership distributions based on 115% of the amount of any Partnership distribution that would be made to each Common Unit so that the amount of any Partnership distribution to each Class C Unit will equal 115% of the amount of such distribution to each Common Unit, and the right of holders of Class C Units to receive distributions shall have the same order of priority relative to distributions on the Common Units.

(iii) Liquidating Distributions. The Class C Units shall have rights upon dissolution and liquidation of the Partnership, including the right to share in any liquidating distributions, that are based on 115% of the liquidating distributions that would be made to the Common Units so that the amount of any liquidating distribution to each Class C Unit will equal 115% of the amount of such distribution to each Common Unit, and the rights of the Class C Units upon dissolution and liquidation of the Partnership shall have the same order of priority relative to the rights of the Common Units.

(iv) Excess Payments. If the Conversion Effective Date occurs after the Class C Distribution Increase Date, on the Conversion Effective Date (or the later date specified as follows), then for the Quarter in which such conversion occurs, concurrently with the distribution of Available Cash in respect of such Quarter in accordance with Section 6.3 hereof (subject to this Section 5.12), a distribution shall be paid to each holder of record of Class C Units as of the Conversion Effective Date, with the amount of such distribution for each such Class C Unit to be equal to the product of (a) 15% of the amount to be distributed in respect of such Quarter to each Common Unit times (b) a fraction, of which (I) the numerator is the number of days in such Quarter up to but excluding the Conversion Effective Date and (II) the denominator is the total number of days in such Quarter (such amount, the “Excess Payment”). For the taxable year in which an Excess Payment is made, if not previously allocated, each holder of a Class C Unit shall be allocated items of gross income in an amount equal to the Excess Payment distributed to it as provided in Section 6.1(d)(xiii). For the avoidance of doubt, each Common Unit issued upon conversion of a Class C Unit shall be entitled to receive the full distribution payable to the holder of a Common Unit concurrently with the distribution of such Excess Payment.”

(h) Surrender of Certificates. Upon receipt of the Conversion Approval in accordance with Section 5.12(f) or a change in rules of the National Securities Exchange as described in Section 5.12(i), the General Partner shall give the holders of the Class C Units prompt notice of such Conversion Approval or change in rules and, subject to the requirements of Section 6.5, each holder of Class C Units shall promptly surrender the Class C Unit Certificates therefor, duly endorsed, at the office of the General Partner or of any transfer agent for the Class C Units. In the case of any such conversion, the Partnership shall, as soon as practicable thereafter, issue and deliver at such office to such holder of Class C Units one or more Common Unit Certificates, registered in the name of such holder, for the number of Common Units to which such holder shall be entitled. Such conversion shall be deemed to have been made as of the third calendar day following the Conversion Approval Date or, in the case of Section 5.12(i), the date of the effectiveness of such rule change (the “ Conversion Effective Date ”), and the Person entitled to receive the Common Units issuable upon such conversion shall be treated for all purposes as the record holder of such Common Units as of such date.

(i) Change in Rules of National Securities Exchange. If at any time (i) the rules of the National Securities Exchange on which the Common Units are listed or admitted to trading or the staff interpretations of such rules are changed or (ii) facts or circumstances arise so that no vote or consent of Unitholders is required as a condition to the listing or admission to trading of the Common Units that would be issued upon any conversion of any Class C Units into Common Units as provided in Section 5.12(f), the terms of such Class C Units will be changed so that each Class C Unit is converted (without further action or any vote of any Unitholders other than compliance with Section 5.12(h)) into one Common Unit and, immediately thereafter, none of the Class C Units shall be Outstanding.”

(e) Section 6.1(c)(i) is amended and restated as follows:

(i) If a Net Termination Gain is recognized (or deemed recognized pursuant to Section 5.6(d)), such Net Termination Gain shall be allocated among the Partners in the following manner (and the Capital Accounts of the Partners shall be increased by the amount so allocated in each of the following subclauses, in the order listed, before an allocation is made pursuant to the next succeeding subclause):

 

  A.

First, to each Partner having a deficit balance in its Capital Account, in the proportion that such deficit balance bears to the total deficit balances in the Capital Accounts of all Partners, until each such Partner has been allocated Net Termination Gain equal to any such deficit balance in its Capital Account;

 

  B.

Second, to all Unitholders holding Common Units and Class B Units and to the General Partner, in proportion to their respective Percentage Interests, until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) its Unrecovered Capital plus (2) the Initial Quarterly Distribution Amount for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to clause (A) of the proviso to Section 5.12(b)(ii) with respect to such Common Unit for such Quarter (the amount determined pursuant to this clause (2) is hereinafter defined as the “Unpaid IQD”); plus (3) any then existing Cumulative Common Unit Arrearage;

 

  C.

Third, if such net Termination Gain is recognized (or is deemed to be recognized) prior to the Conversion Effective Date, to all Unitholders holding Class C Units and to the General Partner, in proportion to their respective Percentage Interests, until the Capital Account in respect of each Class C Unit then Outstanding equals the sum of (1) its Unrecovered Capital, determined for the taxable year (or portion thereof) to which this allocation of gain relates, plus (2) the Initial Quarterly Distribution Amount for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to clause (C) of the proviso to Section 5.12(b)(ii) with respect to such Class C Unit for such Quarter;

 

4


D. Fourth, to all Unitholders and to the General Partner, in accordance with their relative Percentage Interests.

(f) Section 6.1(d)(ix) is amended and restated as follows:

“(xi) Economic Uniformity. (A) With respect to any taxable period ending upon, or after, the date a Conversion Notice is given by a holder of Class B Units pursuant to Section 5.7, items of Partnership income and gain shall be allocated 100% to each Partner holding such Class B Units until each such Partner has been allocated an amount of Partnership income or gain that increases the Capital Account maintained with respect to each converted Class B Unit to an amount equal to the product of (1) the number of converted Class B Units and (2) the Per Unit Capital Amount for a Common Unit. The purpose for this allocation is to establish uniformity between the Capital Accounts underlying converted Class B Units and the Capital Accounts underlying Common Units held by Persons other than the General Partner and its Affiliates immediately prior to the conversion of Class B Units into Common Units.

(B) At the election of the General Partner with respect to any taxable period ending upon the Conversion Effective Date, all or a portion of the remaining items of Partnership income or gain for such taxable period, after taking into account allocations pursuant to Section 6.1(d)(ix)(A), shall be allocated 100% to each Partner holding such Common Units resulting from the conversion pursuant to Section 5.12 in the proportion of the number of converted Class C Units held by such Partner to the total number of converted Class C Units then Outstanding, until each such Partner has been allocated an amount of Partnership income or gain that increases the Capital Account maintained with respect to each converted Class C Units to an amount equal to the product of (A) the number of converted Class C Units held by such Partner and (B) the Per Unit Capital Amount for a Common Unit. The purpose of this allocation is to establish uniformity between the Capital Accounts underlying converted Class C Units and the Capital Accounts underlying Common Units held by Persons other than the General Partner and its Affiliates immediately prior to the conversion of such converted Class C Units into Common Units.”

(g) Article VI is hereby amended to add a new Section 6.1(d)(xiii) as follows:

“(xiii) Priority Allocations. If the amount of cash or the Net Agreed Value of any property distributed (except cash or property distributed or deemed distributed pursuant to Section 5.6(a), with respect to Class C Units, or Section 12.4) to any Unitholder with respect to its Units for a taxable year is greater (on a per Unit basis) than the amount of cash or the Net Agreed Value of property distributed to the other Unitholders with respect to their Units (on a per Unit basis), then (1) each Unitholder receiving such greater cash or property distribution shall be allocated gross income and gain in an amount equal to the product of (aa) the amount by which the distribution (on a per Unit basis) to such Unitholder exceeds the distribution (on a per Unit basis) to the Unitholders receiving the smallest distribution and (bb) the number of Units owned by the Unitholder receiving the greater distribution; and (2) the General Partner shall be allocated gross income and gain in an aggregate amount equal to the product obtained by multiplying (aa) the quotient determined by dividing (x) the General Partner’s Percentage Interest at the time in which the greater cash or property distribution occurs, times (bb) the sum of the amounts allocated in clause (1) above by (y) the sum of 100 less the General Partner’s Percentage Interest at the time in which the greater cash or property distribution occurs.”

(h) Article VI is hereby amended to add a new Section 6.5 as follows:

“Section 6.5 Special Provisions Relating to the Holders of Class C Units. A Unitholder holding a Class C Unit that has converted into a Common Unit pursuant to Section 5.12 shall not be issued a Common Unit Certificate pursuant to Section 4.1, and shall not be permitted to transfer such Common Units until such time as the General Partner determines, based on advice of counsel, that the converted Class C Unit should have, as a substantive matter, like intrinsic economic and federal income tax characteristics of an Initial Common Unit. In connection with the condition imposed by this Section 6.5, the General Partner shall take whatever steps are required to provide economic uniformity to the converted Class C Units in preparation for a transfer of such Units, including the application of Section 6.1(d)(ix)(B); provided, however, that no such steps may be taken that would have a material adverse effect on the Unitholders holding Common Units represented by Common Unit Certificates.”

Section 2. Ratification of Partnership Agreement. Except as expressly modified and amended herein, all of the terms and conditions of the Partnership Agreement shall remain in full force and effect.

Section 3. Governing Law. This Amendment will be governed by and construed in accordance with the laws of the State of Delaware.

Section 4. Counterparts. This Amendment may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart.

 

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IN WITNESS WHEREOF, this Amendment has been executed as of the date first written above.

 

GENERAL PARTNER:
LE GP, LLC
By:  

/s/ John W. McReynolds

  John W. McReynolds, President
LIMITED PARTNERS:
All Limited Partners now and hereafter admitted as limited partners of the Partnership, pursuant to Powers of Attorney now and hereafter executed in favor of, and granted and delivered to, the General Partner.
By: LE GP, LLC, General Partner of
Energy Transfer Equity, L.P., as attorney-in-fact for all Limited Partners pursuant to the powers of Attorney granted pursuant to Section 2.6 of the Partnership Agreement.
By:  

/s/ John W. McReynolds

  John W. McReynolds, President

SIGNATURE PAGE TO

AMENDMENT NO. 1

TO

THIRD AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP

OF

ENERGY TRANSFER EQUITY, L.P.

 

6


EXHIBIT A

Certificate Evidencing Class C Units

Representing Limited Partner Interests in

Energy Transfer Equity, L.P.

 

No.                 

                    Class C Units

In accordance with Section 4.1 of the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., as amended, supplemented or restated from time to time (the “ Partnership Agreement ”), Energy Transfer Equity, L.P., a Delaware limited partnership (the “ Partnership ”), hereby certifies that                          (the “ Holder ”) is the registered owner of Class C Units representing limited partner interests in the Partnership (the “ Class C Units ”) transferable on the books of the Partnership, in person or by duly authorized attorney, upon surrender of this Certificate properly endorsed and accompanied by a properly executed application for transfer of the Class C Units represented by this Certificate. The rights, preferences and limitations of the Class C Units are set forth in, and this Certificate and the Class C Units represented hereby are issued and shall in all respects be subject to the terms and provisions of, the Partnership Agreement. Copies of the Partnership Agreement are on file at, and will be furnished without charge on delivery of written request to the Partnership at, the principal office of the Partnership located at 2828 Woodside Street, Dallas, Texas 75204. Capitalized terms used herein but not defined shall have the meanings given them in the Partnership Agreement.

The Holder, by accepting this Certificate, is deemed to have (i) requested admission as, and agreed to become, a Limited Partner and to have agreed to comply with and be bound by and to have executed the Partnership Agreement, (ii) represented and warranted that the Holder has all right, power and authority and, if an individual, the capacity necessary to enter into the Partnership Agreement, (iii) granted the powers of attorney provided for in the Partnership Agreement and (iv) made the waivers and given the consents and approvals contained in the Partnership Agreement.

THIS SECURITY HAS NOT BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933, AS AMENDED. IT MAY NOT BE SOLD, OFFERED FOR SALE, PLEDGED OR HYPOTHECATED IN THE ABSENCE OF A REGISTRATION STATEMENT IN EFFECT WITH RESPECT TO THE SECURITIES UNDER SUCH ACT OR AN OPINION OF COUNSEL SATISFACTORY TO THE PARTNERSHIP THAT SUCH REGISTRATION IS NOT REQUIRED.

THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF ENERGY TRANSFER EQUITY, L.P. THAT THIS SECURITY MAY NOT BE SOLD, OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED IF SUCH TRANSFER WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF ENERGY TRANSFER EQUITY, L.P. UNDER THE LAWS OF THE STATE OF DELAWARE, OR (C) CAUSE ENERGY TRANSFER EQUITY, L.P. TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED). LE GP, LLC, THE GENERAL PARTNER OF ENERGY TRANSFER EQUITY, L.P., MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF ENERGY TRANSFER EQUITY, L.P. BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES. THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.

 

A-1


This Certificate shall not be valid for any purpose unless it has been countersigned and registered by the Transfer Agent and Registrar.

 

Dated:                      Energy Transfer Equity, L.P.
Countersigned and Registered by:     By:   LE GP, LLC,
      its General Partner

 

    By:  

             

as Transfer Agent and Registrar     Name:  

 

By:  

         

    By:  

         

          Authorized Signature               Secretary

[Reverse of Certificate ]

ABBREVIATIONS

The following abbreviations, when used in the inscription on the face of this Certificate, shall be construed as follows according to applicable laws or regulations:

 

TEN COM -    as tenants in common       UNIF GIFT/TRANSFERS MIN ACT
TEN ENT -    as tenants by the entireties                        Custodian                 
         (Cust)                             (Minor)
JT TEN -    as joint tenants with right of survivorship and not as tenants in common       under Uniform Gifts/Transfers to CD Minors Act (State)

Additional abbreviations, though not in the above list, may also be used.

FOR VALUE RECEIVED,                  hereby assigns, conveys, sells and transfers unto                 

 

         

   

         

(Please print or typewrite name

and address of Assignee)

   

        (Please insert Social Security or other

        identifying number of Assignee)

             Class C Units representing limited partner interests evidenced by this Certificate, subject to the Partnership Agreement, and does hereby irrevocably constitute and appoint                 as its attorney-in-fact with full power of substitution to transfer the same on the books of Energy Transfer Equity, L.P.

 

Date:                    NOTE:   The signature to any endorsement hereon must correspond with the name as written upon the face of this Certificate in every particular, without alteration, enlargement or change.
THE SIGNATURE(S) MUST BE GUARANTEED BY AN ELIGIBLE GUARANTOR INSTITUTION (BANKS, STOCKBROKERS, SAVINGS AND LOAN ASSOCIATIONS AND CREDIT UNIONS WITH MEMBERSHIP IN AN APPROVED SIGNATURE GUARANTEE MEDALLION PROGRAM), PURSUANT TO S.E.C. RULE 17Ad-15    

 

(Signature)

 

(Signature)

No transfer of the Class C Units evidenced hereby will be registered on the books of the Partnership, unless the Certificate evidencing the Class C Units to be transferred is surrendered for registration or transfer and, following a FERC Notice, an Application for Transfer of Class C Units has been properly completed and executed by a transferee either (a) on the form set forth below or (b) on a separate application that the Partnership will furnish on request without charge. A transferor of the Class C Units shall have no duty to the transferee with respect to execution of the Application for Transfer of Class C Units in order for such transferee to obtain registration of the transfer of the Class C Units.

 

A-2

EX-3.5

Exhibit 3.5

AMENDMENT NO. 2

TO

THIRD AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP

OF

ENERGY TRANSFER EQUITY, L.P.

This Amendment No. 2 (this “ Amendment ”) to the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., a Delaware limited partnership (the “ Partnership ”), dated as of February 8, 2006 and amended as of November 1, 2006 (“ the Partnership Agreement ”), is entered into effective as of November 9, 2007, by LE GP, LLC, a Delaware limited liability company (the “ General Partner ”), as the general partner of the Partnership, on behalf of itself and the Limited Partners of the Partnership. Capitalized terms used but not defined herein are used as defined in the Partnership Agreement.

RECITALS

WHEREAS, Section 13.1(e) of the Partnership Agreement provides that the General Partner, without the approval of any Partner, may change the fiscal year of the Partnership and may amend any provision of the Partnership Agreement to reflect an amendment that, in the discretion of the General Partner, is necessary or appropriate as a result of the change in fiscal year;

NOW, THEREFORE, the Partnership Agreement is hereby amended as follows:

Section 1. Change of Fiscal Year. The text of Section 8.2 is hereby amended in its entirety to read as follows:

The fiscal year of the Partnership shall be from January 1 to December 31.

Section 2. Transition Period. In connection with the change from a fiscal year ending on August 31 of each year to a fiscal year ending on December 31 of each year as contemplated by Section 1 of this Amendment, the definition of “Quarter” is hereby amended in its entirety to read as follows:

“Quarter” means, unless the content otherwise requires, a fiscal quarter of the Partnership; provided, that, notwithstanding the foregoing, the period from September 1, 2007 through and including December 31, 2007 shall be deemed to be a “Quarter” and no partial period during the period from September 1, 2007 to December 31, 2007 shall be considered to be a “Quarter.”

Section 3. Ratification of Partnership Agreement. Except as expressly modified and amended herein, all of the terms and conditions of the Partnership Agreement shall remain in full force and effect.

Section 4. Governing Law. This Amendment will be governed by and construed in accordance with the laws of the State of Delaware.

Section 5. Counterparts. This Amendment may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart.


IN WITNESS WHEREOF, this Amendment has been executed as of the date first written above.

 

GENERAL PARTNER:
LE GP, LLC
By:  

/s/ John W. McReynolds

  John W. McReynolds, President
LIMITED PARTNERS:
All Limited Partners now and hereafter admitted as limited partners of the Partnership, pursuant to Powers of Attorney now and hereafter executed in favor of, and granted and delivered to, the General Partner.
By: LE GP, LLC, the General Partner of
Energy Transfer Equity, L.P., as attorney-in-fact for all Limited Partners pursuant to the powers of Attorney granted pursuant to Section 2.6 of the Partnership Agreement.
By:  

/s/ John W. McReynolds

  John W. McReynolds, President
EX-3.6

Exhibit 3.6

Execution Version

AMENDMENT NO. 3

TO

THIRD AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP

OF

ENERGY TRANSFER EQUITY, L.P.

This Amendment No. 3 (this “ Amendment ”) to the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., a Delaware limited partnership (the “ Partnership ”), dated as of February 8, 2006 (the “ Partnership Agreement ”), is entered into effective as of May 26, 2010, by LE GP, LLC, a Delaware limited liability company (the “ General Partner ”), as the general partner of the Partnership, on behalf of itself and the Limited Partners of the Partnership. Capitalized terms used but not defined herein are used as defined in the Partnership Agreement.

RECITALS

WHEREAS, Section 5.8 of the Partnership Agreement provides that the General Partner, without the approval of any Limited Partner except as otherwise provided in the Partnership Agreement, may, for any Partnership purpose, at any time or from time to time, issue additional Partnership Securities to such Persons for such consideration and on such terms and conditions as shall be established by the General Partner in its sole discretion;

WHEREAS, Section 13.1(d)(i) of the Partnership Agreement provides that the General Partner, without the approval of any Partner, may amend any provision of the Partnership Agreement (to reflect a change that, the General Partner determines, does not adversely affect the Limited Partners in any material respect);

WHEREAS, Section 13.1(g) of the Partnership Agreement provides that the General Partner, without the approval of any Partner, may amend any provision of the Partnership Agreement to reflect an amendment that, the General Partner determines, is necessary or appropriate in connection with the authorization of issuance of any class or series of Partnership Securities pursuant to Section 5.8 of the Partnership Agreement;

WHEREAS, all of the Class C Units were converted into Common Units on February 22, 2007, with the result that all Class C Units have been canceled and there are no Class C Units Outstanding as of the date hereof;

WHEREAS, all of the Class B Units were converted into Common Units on March 27, 2007, with the result that all Class B Units have been canceled and there are no Class B Units Outstanding as of the date hereof;

WHEREAS, the Partnership has entered into a General Partner Purchase Agreement, dated as of May 10, 2010 (the “ GP Purchase Agreement ”), between the Partnership, ETE GP Acquirer LLC, a Delaware limited liability company (“ ETE GP Acquirer ”) and Regency GP Acquirer, L.P., a Delaware limited partnership (“ Regency GP Seller ”), pursuant to which Regency GP Seller will transfer (i) 100% of the membership interests in Regency GP LLC, a Delaware limited liability company (“ RGPLLC ”) and (ii) the 99.999% limited partner interest inRegency GP LP, a Delaware limited partnership (“ RGPLP ” and, together with RGPLLC, the “ Regency GP Entities ”) and the general partner of Regency Energy Partners, L.P., a Delaware limited partnership (“ Regency ”) (such interests, together the “ Acquired Regency GP Interests ”) to ETE GP Acquirer in exchange for the issuance by the Partnership to Regency GP Seller of 3,000,000 units of a new class of Partnership Securities to be designated as “Series A Convertible Preferred Units” with the rights, preferences and privileges and such other terms as are set forth in this Amendment;

WHEREAS, the General Partner has determined that the creation of the Series A Preferred Units (as defined below) will be in the best interests of the Partnership and beneficial to the Limited Partners, including the holders of the Common Units;

WHEREAS, the issuance of the Series A Preferred Units complies with the requirements of the Partnership Agreement; and

WHEREAS, the General Partner has determined, pursuant to Section 13.1(g) of the Partnership Agreement, that the amendments to the Partnership Agreement set forth herein are necessary or appropriate in connection with the authorization of the issuance of the Series A Preferred Units;

 

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NOW, THEREFORE, the Partnership Agreement is hereby amended as follows:

Section 1. Amendments.

(a) Section 1.1 of the Partnership Agreement is hereby amended to add or amend and restate the following definitions:

Combined Accretion Multiple ” has the meaning ascribed to such term in Section 5.13(b)(xi)(B).

Election Notice Period ” has the meaning ascribed to such term in Section 5.13(b)(ix)(A).

Fair Market Value ” means, as of a particular date, (i) for any Marketable Security, the VWAP Price of such Marketable Security and (ii) for all property other than a Marketable Security, the value of the property on the date it was distributed by the Partnership in a Special Distribution, as determined in good faith by the General Partner.

Fractional Unit Cash Consideration ” has the meaning ascribed to such term in Section 5.13(b)(vii)(G).

Fundamental Change means (i) any merger or consolidation of the Partnership with another entity, (ii) a sale of all or substantially all of the assets of the Partnership, (iii) any dissolution or liquidation of the Partnership, (iv) any other transaction pursuant to which the General Partner or any Affiliate of the General Partner exercises its rights to purchase all of the Outstanding Common Units pursuant to Section 15.1 of this Agreement, (v) the sale or transfer, directlyor indirectly, of the general partner interest of the MLP by the Partnership (excluding any such sale or transfer to a, direct or indirect, wholly-owned Subsidiary of the Partnership), (vi) the failure of the Partnership to continue to maintain, directly or through direct or indirect wholly-owned Subsidiaries, ownership of at least 25,000,000 common units of the MLP (as appropriately adjusted for unit splits, unit distributions and the like) or (vii) the declaration of a distribution by the MLP to its unitholders that constitutes a distribution from Capital Surplus as opposed to Operating Surplus (as each such term is defined in the MLP Agreement as in effect on the Series A Issuance Date).

Fundamental Change Conversion Consideration ” means (x) if Common Units will remain Outstanding and continue to constitute Marketable Securities upon consummation of a Fundamental Change, a number of Common Units equal to (A) the sum of (1) the Series A Liquidation Value as of the date of consummation of the Fundamental Change plus (2) the lesser of (a) the Series A Accretion Amount as of the date of the consummation of a Fundamental Change or (b) $10.00, divided by (B) the VWAP Price as of the date of the consummation of the Fundamental Change and (y) in any circumstance not described in clause (x), the consideration received in connection with such Fundamental Change by a hypothetical holder of the number of Common Units that would be received by the holder of one Series A Preferred Unit pursuant to clause (x) had Common Units remained Outstanding and continued to constitute Marketable Securities upon consummation of such Fundamental Change.

Fundamental Change Documentation ” means any documentation (in addition to any certificates representing a holder’s Series A Preferred Units) that the General Partner reasonably requests to be delivered by each holder of Series A Preferred Units in connection with the conversion or redemption of the Series A Preferred Units due to a Fundamental Change, including, if applicable, wire transfer instructions in respect of any cash consideration to be received in connection with such Fundamental Change.

Fundamental Change Elected Common Unit Consideration ” has the meaning ascribed to such term in Section 5.13(b)(ix)(C)(a)(i).

Fundamental Change Elected Cash Consideration ” has the meaning ascribed to such term in Section 5.13(b)(ix)(C)(a)(i).

Fundamental Change Forced Redemption Election ” has the meaning ascribed to such term in Section 5.13(b)(ix)(A)(a).

Fundamental Change Redemption Consideration ” means (i) an amount in cash equal to the Series A Liquidation Value as of the date of the consummation of a Fundamental Change plus (ii) the Fundamental Change Redemption Consideration Premium.

 

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Fundamental Change Redemption Consideration Premium ” means, in respect of a Fundamental Change, (x) if Common Units will remain Outstanding and continue to constitute Marketable Securities upon the consummation of the Fundamental Change, a number of Common Units equal to (A) the greater of (1) the Series A Accretion Amount as of the date of the consummation of a Fundamental Change and (2) $10.00 divided by (B) the VWAP Price of a Common Unit as of the date of consummation of the Fundamental Change and (y) in any circumstance not described in clause (x), the consideration received in connection with such Fundamental Change by a hypothetical holder of the number of Common Units that would be received by the holder of one Series A Preferred Unit pursuant to clause (x) had Common Units remained Outstanding and continued to constitute Marketable Securities upon consummation of such Fundamental Change.

Fundamental Change Trigger Date ” has the meaning ascribed to such term in Section 5.13(b)(ix)(A).

Investor ” means, collectively, Regency GP Seller and each of its Affiliates from time to time that is the registered holder of any Series A Preferred Units.

Issue Price ” means the price at which a Unit is purchased from the Partnership, after taking into account any sales commission or underwriting discount charged to the Partnership and after taking into account any other form of discount with respect to the price at which a Unit is purchased from the Partnership; provided, however, that in the case of the Series A Preferred Units, the Issue Price shall be $100.00 per Unit.

Junior Securities ” means any class or series of Partnership Securities that, with respect to distributions on such Partnership Securities and distributions upon liquidation of the Partnership, ranks junior to the Series A Preferred Units, including but not limited to Common Units.

Marketable Security ” means any security listed on the New York Stock Exchange or the NASDAQ Stock Market.

Parity Securities ” means any class or series of Partnership Securities that, with respect to distributions on such Partnership Securities or distributions upon liquidation of the Partnership, ranks pari passu with the Series A Preferred Units.

Partnership Event ” has the meaning ascribed to such term in Section 5.13(b)(xi)(A).

Partnership Event Consummation Date ” has the meaning ascribed to such term in Section 5.13(b)(xi)(A).

Post-Partnership Event Accretion Multiple ” has the meaning ascribed to such term in Section 5.13(b)(xi)(B)(b).

Pre-Partnership Event Accretion Multiple ” has the meaning ascribed to such term in Section 5.13(b)(xi)(B)(a).

Public Equity Partnership Event ” has the meaning ascribed to such term in Section 5.13(b)(xi)(B).

Record Date ” means the date established by the General Partner for determining (a) the identity of the Record Holders entitled to notice of, or to vote at, any meeting of Limited Partners or entitled to vote by ballot or give approval of Partnership action in writing without a meeting or entitled to exercise rights in respect of any lawful action of Limited Partners, (b) the identity of Record Holders entitled to receive any report or distribution or to participate in any offer or (c) the identity of the Record Holders of Series A Preferred Units entitled to convert such Units or whose Units are to be redeemed.

Regency GP Purchase Agreement ” means the General Partner Purchase Agreement, dated May 10, 2010, by and between the Partnership, ETE GP Acquirer LLC, a Delaware limited liability company and Regency GP Seller.

Regency GP Seller ” means Regency GP Acquirer, L.P., a Delaware limited partnership.

Regulation FD ” means Regulation FD as promulgated by the Commission, as the same may be amended from time to time.

Securities Law Prohibition ” has the meaning ascribed to such term in Section 5.13(b)(vii)(H).

Senior Securities ” means any class or series of Partnership Securities that, with respect to distributions on such Partnership Securities or distributions upon liquidation of the Partnership, ranks senior to the Series A Preferred Units.

 

3


Series A Adjustment Event ” has the meaning ascribed to such term in Section 5.13(b)(xii)(A).

Series A Accretion Amount ” means, as of a particular date (i) $100.00 multiplied by (ii) the Trading Price Accretion Percentage as of such date multiplied by (iii) twenty-five percent (25%), expressed as a decimal.

Series A Conversion Cash Consideration ” has the meaning ascribed to such term in Section 5.13(b)(vii)(A)(b)(ii).

Series A Conversion Consideration ” has the meaning ascribed to such term in Section 5.13(b)(vii)(A).

Series A Conversion Documentation ” has the meaning ascribed to such term in Section 5.13(b)(vii)(C)(c).

Series A Conversion Notice ” has the meaning ascribed to such term in Section 5.13(b)(vii)(C).

Series A Conversion Notice Date ” has the meaning ascribed to such term in Section 5.13(b)(vii)(C).

Series A Distribution Payment Date ” has the meaning ascribed to such term in Section 5.13(b)(ii)(A).

Series A Distribution Rate ” means a fixed rate of $2.00 per Series A Preferred Unit per Quarter; provided, however, that with respect to the period commencing on the Series A Issuance Date and ending on the last day of the Quarter in which the Series A Issuance Date occurs, “ Series A Distribution Rate ” shall mean a fixed rate of the product of $2.00 per Series A Preferred Unit multiplied by a fraction of which the numerator is the number of days in such period and the denominator is 90.

Series A Exchange Cap ” means that number of units of Common Units which the Partnership may issue upon conversion or redemption, as the case may be, of the Series A Preferred Units without breaching the Partnership’s obligations under the rules or regulations of any National Securities Exchange on which the Common Units are listed or admitted to trading.

Series A Issuance Date ” means May 26, 2010.

Series A Liquidation Value ” means as of a particular date, with respect to a Series A Preferred Unit, the sum of (i) the Issue Price, plus (ii) all accumulated and unpaid and all accrued and unpaid distributions on such Series A Preferred Unit pursuant to Section 5.13(b)(ii)(A) as of such date.

Series A Maturity Date ” means May 26, 2014.

Series A Optional Redemption Trigger Date ” means May 26, 2013.

Series A Preferred Unit ” means a Partnership Security representing a fractional part of the Partnership Interests of all Limited Partners and Assignees, and having the rights, preferences and privileges and duties and obligations specified with respect to the Series A Preferred Units in this Agreement. The term “Series A Preferred Unit” does not refer to a Common Unit prior to the conversion of a Series A Preferred Unit into a Common Unit pursuant to the terms of this Agreement.

Series A Pro Rata Distribution ” means, in respect of any Parity Security, the distribution permitted to be made on such Parity Security in the event that the Partnership fails to pay in full in cash any distribution (or portion thereof) which any holder of Series A Preferred Units accrues and is entitled to receive, which is equal to the distribution payable in respect of such Parity Security as of such date, multiplied by a fraction (i) the numerator of which is the distribution paid inrespect of each Series A Preferred Unit on the most recent Series A Distribution Payment Date and (ii) the denominator of which is the distribution accumulated and payable on each Series A Preferred Unit immediately prior to the payment of such distribution on the most recent Series A Distribution Payment Date.

Series A Redemption Confirmation ” has the meaning ascribed to such term in Section 5.13(b)(viii)(C)(b).

Series A Redemption Consideration ” has the meaning ascribed to such term in Section 5.13(b)(viii)(A).

Series A Redemption Documentation ” has the meaning ascribed to such term in Section 5.13(b)(viii)(C)(b).

Series A Redemption Date ” has the meaning ascribed to such term in Section 5.13(b)(viii)(C)(a).

Series A Redemption Notice ” has the meaning ascribed to such term in Section 5.13(b)(viii)(C)(a).

 

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Special Distribution ” has the meaning ascribed to such term in Section 5.13(b)(xii)(A).

Successor Securities ” has the meaning ascribed to such term in Section 5.13(b)(xi)(B).

Trading Price Accretion Percentage ” as of a particular date means, subject to adjustment pursuant to Sections 5.13(b)(xi)(B) and 5.13(b)(xii)(A), a fraction, (i) the numerator of which equals (A) the VWAP Price of a Common Unit as of such date minus (B) the VWAP Price of a Common Unit as of the Series A Issuance Date and (ii) the denominator of which equals the VWAP Price of a Common Unit as of the Series A Issuance Date, provided that, if the numerator of the foregoing fraction is a negative amount, then the trading Price Accretion Percentage shall equal zero.

VWAP Price ” as of a particular date means the volume-weighted average trading price of a Common Unit on the National Securities Exchange on which the Common Units are listed or admitted to trading, calculated over the consecutive 10-Trading Day period ending on the close of trading on the Trading Day immediately prior to such date; provided, however, that the “ VWAP Price ” as of a particular date following consummation of a Public Equity Partnership Event shall mean the volume-weighted average trading price of the Successor Securities on the National Securities Exchange on which the Successor Securities are listed or admitted to trading, calculated over the consecutive 10-Trading Day period ending on the close of trading on the Trading Day immediately prior to such date.

(b) Section 1.1 of the Partnership Agreement is hereby further amended to add the following sentence to the end of the definition of “Common Unit”: 

“The term “Common Unit” does not refer to a Series A Preferred Unit prior to the conversion of such Unit into a Common Unit pursuant to the terms hereof.”

(c) Section 4.7(c) of the Partnership Agreement is hereby amended and restated to read in its entirety as follows:

“(c) The transfer of a Series A Preferred Unit shall be subject to the restrictions imposed by Section 5.13(b)(x) and Section 6.6.”

(d) Section 5.6(a) of the Partnership Agreement is hereby amended and restated to read in its entirety as follows:

“The Partnership shall maintain for each Partner (or a beneficial owner of Partnership Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method acceptable to the General Partner) owning a Partnership Interest a separate Capital Account with respect to such Partnership Interest in accordance with the rules of Treasury Regulation Section 1.704-1(b)(2)(iv) and the methodology set forth in Proposed Treasury Regulation Section 1.704-1(b)(2)(iv)(s). Such Capital Account shall be increased by (i) the amount of all Capital Contributions made to the Partnership with respect to such Partnership Interest pursuant to this Agreement and (ii) all items of Partnership income and gain (including, without limitation, income and gain exempt from tax) computed in accordance with Section 5.6(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1, and decreased by (x) the amount of cash or Net Agreed Value of all actual and deemed distributions of cash or property made with respect to such Partnership Interest pursuant to this Agreement and (y) all items of Partnership deduction and loss computed in accordance with Section 5.6(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1. The Partnership shall follow the methodology set forth in the proposed noncompensatory option regulations under Proposed Treasury Regulation Sections 1.704-1, 1.721-2 and 1.761-3 at all times, including when the assets of the Partnership are revalued or any Series A Preferred Units are converted pursuant to Section 5.13. For the avoidance of doubt, the Series A Preferred Units will be treated as a partnership interest in the Partnership for federal income tax purposes, and, therefore, each holder of a Series A Preferred Unit will be treated as a partner in the Partnership.”

 

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(e) Section 5.6(d)(i) of the Partnership Agreement is hereby amended and restated to read in its entirety as follows:

“(i) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f) and Proposed Treasury Regulation Section 1.704-1(b)(2)(iv)(s), on an issuance of additional Partnership Interests for cash or Contributed Property, the issuance of Partnership Interests as consideration for the provision of services, the conversion of the General Partner’s Combined Interest to Units pursuant toSection 11.3(b) or the conversion of a Series A Preferred Unit, the Capital Account of all Partners and the Carrying Value of each Partnership property immediately prior to such issuance, or immediately after such conversion (with respect to the conversion of a Series A Preferred Unit), shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, as if such Unrealized Gain or Unrealized Loss had been recognized on an actual sale of each such property immediately prior to such issuance or on the date of such conversion. Any such Unrealized Gain or Unrealized Loss (or items thereof) shall be allocated (A) if the operation of this sentence is triggered by the conversion of a Series A Preferred Unit, first to the Partners holding converted Series A Preferred Units until the Capital Account of each converted Series A Preferred Unit is equal to the Per Unit Capital Amount for a then Outstanding Common Unit (other than a converted Series A Preferred Unit), and (B) any remaining Unrealized Gain or Unrealized Loss shall be allocated among the Partners pursuant to Section 6.1(c) in the same manner as any item of gain or loss actually recognized would have been allocated. If the Unrealized Gain or Unrealized Loss allocated as a result of the conversion of a Series A Preferred Unit is not sufficient to cause the Capital Account of each converted Series A Preferred Unit to equal the Per Unit Capital Amount for a then Outstanding Common Unit (other than a converted Series A Preferred Unit), then Capital Account balances shall be reallocated between the Partners holding converted Series A Preferred Units and the Partners holding Common Units (other than converted Series A Preferred Units) so as to cause the Capital Account of each converted Series A Preferred Unit to equal the Per Unit Capital Amount for a then Outstanding Common Unit (other than a converted Series A Preferred Unit), in accordance with Proposed Treasury Regulation Section 1.704-1(b)(2)(iv)(s)(3). In determining such Unrealized Gain or Unrealized Loss, the aggregate cash amount and fair market value of all Partnership assets (including, without limitation, cash or cash equivalents) immediately prior to the issuance of additional Partnership Interests shall be determined by the General Partner using such method of valuation as it may adopt; provided, however, that the General Partner, in arriving at such valuation, must take fully into account the fair market value of the Partnership Interests of all Partners at such time and must reduce the fair market value of all Partnership assets by the excess, if any, of the fair market value of any Outstanding Series A Preferred Units that have not yet been converted over the aggregate Issue Price of such Series A Preferred Units to the extent of any Unrealized Gain that has not been reflected in the Partners’ Capital Accounts previously, pursuant to Proposed Treasury Regulation Section 1.704-1(b)(2)(iv)(h)(2). The General Partner shall allocate such aggregate value among the assets of the Partnership (in such manner as it determines) to arrive at a fair market value for individual properties.”

(f) Article V of the Partnership Agreement is hereby amended to add a new Section 5.13 creating a new series of Units as follows:

“Section 5.13 Establishment of Series A Preferred Units.

(a) General. The General Partner hereby designates and creates a series of Units to be designated as “Series A Convertible Preferred Units” and consisting of a total of 3,000,000 Series A Preferred Units, having the same rights, preferences and privileges, and subject to the same duties and obligations, as the Common Units, except as set forth in this Section 5.13 and in Sections 5.6(d)(i), 6.6 and 12.10. The class of Series A Preferred Units shall be closed immediately following the Series A Issuance Date and thereafter no additional Series A Preferred Units shall be designated, created or issued without the prior written approval of the General Partner and the holders of a majority of the Outstanding Series A Preferred Units. The initial Capital Account balance in respect of each Series A Preferred Unit issued on the Series A Issuance Date shall be the Issue Price for such Series A Preferred Unit.

(b) Rights of Series A Preferred Units. The Series A Preferred Units shall have the following rights, preferences and privileges and shall be subject to the following duties and obligations:

(i) Allocations.

(A) Notwithstanding anything to the contrary in Section 6.1(a), prior to any allocation made pursuant to Section 6.1(a), but after giving effect to any special allocations set forth in Section 6.1(d), any Net Income shall be allocated to all Unitholders holding Series A Preferred Units, Pro Rata, until the Capital Account in respect of each Outstanding Series A Preferred Unit is equal to the Series A Liquidation Value.

 

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(B) Notwithstanding anything to the contrary in Section 6.1(b), Unitholders holding Series A Preferred Units shall not receive any allocation pursuant to Section 6.1(b) unless and until the Adjusted Capital Accounts of all other Partners have been reduced to zero, in which case prior to allocating any remaining Net Losses to the General Partner, Net Losses shall be allocated to all Unitholders holding Series A Preferred Units, Pro Rata, until the Adjusted Capital Accounts of such Unitholders in respect of such Units have been reduced to zero.

(C) Notwithstanding anything to the contrary in Section 6.1(c)(i), (x) Unitholders holding Series A Preferred Units shall be allocated Net Termination Gain in accordance with Section 6.1(c)(i)(A) but shall not receive any allocation pursuant to Sections 6.1(c)(i)(B) – (D) with respect to their Series A Preferred Units, and (y) following any allocation made pursuant to Section 6.1(c)(i)(A) and prior to any allocation made pursuant to Section 6.1(c)(i)(B), any remaining Net Termination Gain shall be allocated to all Unitholders holding Series A Preferred Units, ProRata, until the Capital Account in respect of each Outstanding Series A Preferred Unit is equal to the Series A Liquidation Value.

(D) Notwithstanding anything to the contrary in Section 6.1(c)(ii), (x) Unitholders holding Series A Preferred Units shall not receive any allocation pursuant to Sections 6.1(c)(ii)(A) with respect to their Series A Preferred Units, and (y) following the allocations made pursuant to Section 6.1(c)(ii)(A), and prior to any allocation made pursuant to Section 6.1(c)(ii)(B), any remaining Net Termination Loss shall be allocated to all Unitholders holding Series A Preferred Units, Pro Rata, until the Capital Account in respect of each Outstanding Series A Preferred Unit has been reduced to zero.

(ii) Distributions.

(A) Commencing on the Series A Issuance Date, the holders of the Series A Preferred Units as of an applicable Record Date shall accrue and be entitled to receive cumulative distributions, prior to any other distributions pursuant to Section 6.3, in cash in an amount equal to the Series A Distribution Rate on each Outstanding Series A Preferred Unit. All such distributions shall be paid Quarterly, in arrears, within fifty (50) days after the end of each Quarter (a “ Series A Distribution Payment Date ”). If the Partnership fails to pay in full in cash any distribution (or portion thereof) which any holder of Series A Preferred Units accrues and is entitled to receive pursuant to this Section 5.13(b)(ii)(A), then (x) the amount of such accrued and unpaid distributions will accumulate until paid in full in cash and (y) the Partnership shall not be permitted to, and shall not, declare or make (i) any distributions in respect of any Junior Securities and (ii) any distributions in respect of any Parity Securities, other than Series A Pro Rata Distributions, unless and until all accrued and accumulated distributions on the Series A Preferred Units has been paid in full in cash.

(B) Notwithstanding anything in this Section 5.13(b)(ii) to the contrary, with respect to Series A Preferred Units that are converted into Common Units, the holder thereof shall not be entitled to a Series A Preferred Unit distribution and a Common Unit distribution with respect to the same period, but shall be entitled only to the distribution to be paid based upon the class of Units held as of the close of business on the Record Date for the distribution in respect of such period.

(C) Accrued and unpaid distributions in respect of the Series A Preferred Units will not accrue interest.

(iii) Issuance of Series A Preferred Units. The Series A Preferred Units shall be issued by the Partnership pursuant to the terms and conditions of the Regency GP Purchase Agreement.

(iv) Liquidation Value. In the event of any liquidation, dissolution or winding up of the Partnership, either voluntary or involuntary, the holders of the Series A Preferred Units shall be entitled to receive, out of the assets of the Partnership available for distribution to Unitholders, prior and in preference to any distribution of any assets of the Partnership to the holders of any other class or series of Partnership Securities, the positive value in each such holder’s Capital Account in respect of such Series A Preferred Units. If in the year of such liquidation, dissolution or winding up any such holder’s Capital Account in respect of such Series A Preferred Units is less than the aggregate Series A Liquidation Value of such Series A Preferred Units, then notwithstanding anything to the contrary contained in this Agreement, and prior to any other allocation pursuant to this Agreement for such year and prior to any distribution pursuant to the preceding sentence, items of gross income and gain shall be allocated to all Unitholders holding Series A Preferred Units, Pro Rata, until the Capital Account in respect of each Outstanding Series A Preferred Unit is equal to the Series A

 

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Liquidation Value (and no other allocation pursuant to this Agreement shall reverse the effect of such allocation). If in the year of such liquidation, dissolution or winding up any such holder’s Capital Account in respect of such Series A Preferred Units is less than the aggregate Series A Liquidation Value of such Series A Preferred Units after the application of the preceding sentence, then to the extent permitted by law and notwithstanding anything to the contrary contained in this Agreement, items of gross income and gain for any preceding taxable period(s) with respect to which Schedule K-1s have not been filed by the Partnership shall be reallocated to all Unitholders holding Series A Preferred Units, Pro Rata, until the Capital Account in respect of each Outstanding Series A Preferred Unit is equal to the Series A Liquidation Value (and no other allocation pursuant to this Agreement shall reverse the effect of such allocation).

(v) Voting Rights.

(A) The Series A Preferred Units shall not be entitled to vote on any matters related to the Partnership other than as expressly provided in this Section 5.13(b)(v).

(B) Notwithstanding any other provision of this Agreement, in addition to all other requirements imposed by Delaware law, and all othervoting rights granted under this Agreement, the affirmative vote of holders of a majority of the Outstanding Series A Preferred Units, voting separately as a class with one vote per Series A Preferred Unit, shall be necessary to amend this Agreement in any manner that (i) alters or changes the rights, preferences or privileges or duties and obligations of the Series A Preferred Units, (ii) increases or decreases the authorized number of Series A Preferred Units (including without limitation any issuance of additional Series A Preferred Units), or (iii) otherwise adversely affects the Series A Preferred Units in any material respect, including without limitation the creation (by reclassification or otherwise) of any class of Senior Securities (or amending the provisions of any existing class of Partnership Securities to make such class of Partnership Securities a class of Senior Securities); provided, however, that the Partnership may, without the consent or approval of the holders of the Series A Preferred Units (a) create (by reclassification or otherwise) and issue Junior Securities and Parity Securities (including by amending the provisions of any existing class of Partnership Securities to make such class of Partnership Securities a class of Junior Securities or Parity Securities) in an unlimited amount and (b) consummate any Fundamental Change.

(vi) Certificates.

(A) The Series A Preferred Units shall be evidenced by certificates in such form as the General Partner may approve and, subject to the satisfaction of any applicable legal, regulatory and contractual requirements, may be assigned or transferred in a manner identical to the assignment and transfer of other Units; unless and until the General Partner determines to assign the responsibility to another Person, the General Partner will act as the registrar and transfer agent for the Series A Preferred Units. The certificates evidencing Series A Preferred Units shall be separately identified and shall not bear the same CUSIP number as the certificates evidencing Common Units.

(B) The certificate(s) representing the Series A Preferred Units may be imprinted with a legend in substantially the following form (in addition to the legend required pursuant to Section 4.7(e)):

“THESE SECURITIES HAVE NOT BEEN REGISTERED WITH THE SECURITIES AND EXCHANGE COMMISSION OR THE SECURITIES COMMISSION OF ANY STATE IN RELIANCE UPON AN EXEMPTION FROM REGISTRATION UNDER THE SECURITIES ACT OF 1933, AS AMENDED (THE “SECURITIES ACT”) AND ARE SUBJECT TO THE TERMS OF THE THIRD AMENDED AND RESTATED LIMITED PARTNERSHIP AGREEMENT OF ENERGY TRANSFER EQUITY, L.P., AS AMENDED. THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF ENERGYTRANSFER EQUITY, L.P. THAT THIS SECURITY MAY NOT BE SOLD, OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED IF SUCH TRANSFER WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF ENERGY TRANSFER EQUITY, L.P. UNDER THE LAWS OF THE STATE OF DELAWARE, OR (C) CAUSE ENERGY TRANSFER EQUITY, L.P. TO BE TREATED AS AN

 

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ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED). LE GP, LLC, THE GENERAL PARTNER OF ENERGY TRANSFER EQUITY, L.P., MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF ENERGY TRANSFER EQUITY, L.P. BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES. THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.”

(vii) Conversion.

(A) Subject to adjustment as provided in Sections 5.13(b)(xi) and (xii), immediately prior to the close of business on the Series A Maturity Date, each Series A Preferred Unit shall convert into the right to receive, upon the satisfaction of the terms and conditions of this Section 5.13(b)(vii), at the election of the Partnership, either:

a. a number of Common Units equal to:

i. the sum of (A) the Series A Liquidation Value as of the Series A Maturity Date plus (B) the lesser of (1) the Series A Accretion Amount as of the Series A Maturity Date and (2) $10.00, divided by

ii. the VWAP Price as of the Series A Maturity Date; or

b. a number of Common Units and an amount of cash equal to:

i. a number of Common Units equal to (x) the sum of (A) fifty percent (50%) of the Series A Liquidation Value as of the Series A Maturity Date plus (B) the lesser of (1) the Series A Accretion Amount as of the Series A Maturity Date and (2) $10.00, divided by (y) the VWAP Price as of the Series A Maturity Date, and

ii. an amount of cash equal to fifty percent (50%) of the Series A Liquidation Value as of the Series A Maturity Date (the cash consideration to be received pursuant to this clause (ii), the “ Series A Conversion Cash Consideration ”).

The consideration to be received by the holder of a Series A Preferred Unit upon the conversion of such Series A Preferred Unit as provided in this Section 5.13(b)(vii)(A) is referred to as the “ Series A Conversion Consideration.

(B) Any Common Units received by a holder of Series A Preferred Units as the Series A Conversion Consideration shall be fully paid, validly issued and non-assessable (except as such nonassessability may be affected by matters described in Sections 17-303, 17-607 and 17-804 of the Delaware Act). Immediately prior to the close of business on the Series A Maturity Date, all Series A Preferred Units shall be converted automatically into and shall thereafter represent solely the right to receive the Series A Conversion Consideration. All Series A Preferred Units that have converted into the right to receive the Series A Conversion Consideration shall be automatically canceled and shall cease to exist, and the holders of converted Series A Preferred Units shall cease to have any rights with respect to such Series A Preferred Units other than the right to receive the Series A Conversion Consideration. Upon such conversion, any certificates representing Series A Preferred Units shall thereafter represent solely the right to receive the Series A Conversion Consideration.

(C) Within two Business Days following the Series A Maturity Date, the Partnership shall send written notice (a “ Series A Conversion Notice ) to each holder of record of Outstanding Series A Preferred Units as of the Series A Maturity Date, stating:

a. the election of the Partnership as to whether the Series A Preferred Units have converted into (i) Common Units pursuant to Section 5.13(b)(vii)(A)(a) or (ii) both Common Units and the Series A Conversion Cash Consideration pursuant to Section 5.13(b)(vii)(A)(b);

 

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b. the Partnership’s computation of the number of Common Units to be issued and the amount of Series A Conversion Cash Consideration, if any, to be paid in respect of each Series A Preferred Unit pursuant to Section 5.13(b)(vii)(A) (including, in each case, any adjustments pursuant to Sections 5.13(b)(xi) and (xii)), including the Partnership’s computation of the Series A Liquidation Value, the Series A Accretion Amount and the VWAP Price, in each case as of the Series A Maturity Date; and

c. that the holder must surrender the certificate or certificates representing any Series A Preferred Units held by such holder to the Partnership, and provide such other documentation as reasonably requested by the General Partner including wire transfer instructions in respect of any Series A Cash Conversion Cash Consideration or any Fractional Unit Cash Consideration (the “ Series A Conversion Documentation ”), in order to receive the Series A Conversion Consideration.

In addition to delivery in accordance with the general notice provisions contained in Section 17.1, the Series A Conversion Notice shall be deemed properly delivered on the date the Partnership issues a press release distributed through a widely circulated news or wire service as would satisfy the requirements of Regulation FD, containing the information required to be included in the Series A Conversion Notice pursuant to this Section 5.13(b)(vii)(C). The date any Series A Conversion Notice is deemed delivered shall be referred to as the “ Series A Conversion Notice Date. ”

(D) As promptly as practicable following the Series A Conversion Notice Date and subject to the book-entry provisions set forth below, the holders of Series A Preferred Units shall surrender the certificate or certificates representing the Series A Preferred Units being converted, duly endorsed, at the office of the Partnership or, if identified in the Series A Conversion Notice to such holder by the Partnership, at the offices of any transfer agent for such Units, together with the Series A Conversion Documentation. As promptly as practicable following the receipt of such certificate or certificates (or a lost unit affidavit reasonably acceptable to the Partnership in the event of a lost certificate) representing the Series A Preferred Units and the Series A Conversion Documentation by the Partnership or the Transfer Agent as provided in the immediately preceding sentence (but in any event no later than five (5) Business Days thereafter), the Partnership shall issue to such holder a certificate or certificates for the number of Common Units to which such holder shall be entitled under Section 5.13(b)(vii)(A) (with the number of and denomination of such certificates designated by such holder). In lieu of delivering physical certificates representing the Common Units issuableupon conversion of Series A Preferred Units, provided the Transfer Agent is participating in the Depository’s Fast Automated Securities Transfer program, upon request of the holder, the Partnership shall use its commercially reasonable efforts to cause the Transfer Agent to electronically transmit the Common Units issuable upon conversion to the holder, by crediting the account of the holder’s prime broker with the Depository through its Deposit Withdrawal Agent Commission (DWAC) system. The holders of Series A Preferred Units and the Partnership agree to coordinate with the Depository to accomplish this objective. The conversion pursuant to this Section 5.13(b)(vii) shall be deemed to have occurred immediately prior to the close of business on the Series A Maturity Date (whether or not the conversion includes the right to receive Series A Cash Consideration under Section 5.13(b)(vii)(A)(b) or Fractional Unit Cash Consideration under Section 5.13(b)(vii)(G)). The Person or Persons entitled to receive the Common Units issuable upon such conversion shall be treated for all purposes as the Record Holder or Holders of such Common Units at the close of business on the Series A Maturity Date.

(E) If the Partnership (i) elects to have the Series A Preferred Units convert into both Common Units and the right to receive the Series A Conversion Cash Consideration under Section 5.13(b)(vii)(A)(b) or (ii) is required to pay Fractional Unit Cash Consideration pursuant to Section 5.13(b)(vii)(G), then, as promptly as practicable following the receipt of such certificate or certificates (or a lost unit certificate affidavit reasonably acceptable to the Partnership in the event of a lost certificate) representing the Series A Preferred Units and the Series A Conversion Documentation by the Partnership or the Transfer Agent as provided in the first sentence of Section 5.13(b)(vii)(D) (but in any event within five (5) Business Days thereafter), the Partnership shall remit the Series A Cash Conversion Consideration and the Fractional Unit Cash Consideration, as applicable, to the holder surrendering such certificate or certificates (or a lost unit affidavit reasonably acceptable to the Partnership in the event of a lost certificate) representing Series A Preferred Units by wire transfer of immediately available funds to an account specified by such holder in writing.

 

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(F) The Partnership shall pay any and all issue, documentary, stamp and other taxes, excluding any income, franchise or similar taxes, that may be payable in respect of any issue or delivery of Common Units on conversion of, or payment of distributions on, Series A Preferred Units pursuant hereto. However, the holder of any Series A Preferred Units shall pay any tax that is due because the Common Units issuable upon conversion thereof or distribution payment thereon are issued in a name other than such holder’s name.

(G) No fractional Common Units shall be issued upon the conversion of any Series A Preferred Units. All Common Units (including fractions thereof) issuable upon conversion of more than one Series A Preferred Unit by a holder thereof shall be aggregated for purposes of determining whether the conversion would result in the issuance of any fractional unit. If, after the aforementioned aggregation, the conversion would result in the issuance of a fraction of a Common Unit, the Partnership shall, in lieu of issuing any fractional unit, either round up the number of units to the next highest whole number or, at the Partnership’s option, pay the holder otherwise entitled to such fraction a sum in cash equal to such fraction multiplied by the VWAP Price as of the Series A Maturity Date. The consideration payable in lieu of fractional Common Units pursuant to this Section 5.13(b)(vii)(G) as well as any consideration payable in lieu of fractional Common Units pursuant to Section 5.13(b)(viii)(F), are referred to as “ Fractional Unit Cash Consideration. ”

(H) The Partnership shall not be obligated to issue any Common Units upon conversion of the Series A Preferred Units, whether pursuant to this Section 5.13(b)(vii), or otherwise, if the issuance of such Common Units would exceed the Series A Exchange Cap or if such issuance could reasonably be expected to violate any applicable federal or state securities laws or rules and regulations of the Securities and Exchange Commission, any state securities commission or any other governmental authority with jurisdiction over such issuance (a “ Securities Law Prohibition ”). To the extent that a holder’s Series A Preferred Units would otherwise be converted into a number of Common Units that would exceed the Series A Exchange Cap, the Partnership shall pay in cash to such holder an amount equal to the VWAP Price as of the Series A Maturity Date multiplied by the number of Common Units that are not so issued but would otherwise be issuable as part of the Series A Conversion Consideration absent such Series A Exchange Cap or Securities Law Prohibition.

(I) Any Common Units issued upon conversion of the Series A Preferred Units pursuant to this Section 5.13(b)(vii) shall not be subject to the first proviso contained in the definition of “Outstanding” contained in this Agreement for so long as held by the Investor.

(viii) Optional Redemption.

(A) Subject to adjustment as provided in Sections 5.13(b)(xi) and (xii), beginning on the Series A Optional Redemption Trigger Date and ending on the last Business Day immediately prior to the Series A Maturity Date, the Partnership may, at its option, cause all, but not less than all, of the Series A Preferred Units to be redeemed by the Partnership for (a) cash in an amount per Outstanding Series A Preferred Unit equal to the Series A Liquidation Value on the Series A Redemption Date plus (b) anumber of Common Units per Outstanding Series A Preferred Units equal to (i) the greater of (x) the Series A Accretion Amount on the Series A Redemption Date and (y) $10.00 (such cash amount, the “ Series A Redemption Consideration ”) divided by (ii) the VWAP Price as of the Series A Redemption Date.

(B) Any Common Units received by a holder of Series A Preferred Units as the Series A Redemption Consideration shall be fully paid, validly issued and non-assessable (except as such nonassessability may be affected by matters described in Sections 17-303, 17-607 and 17-804 of the Delaware Act). At the time of the redemption pursuant to this Section 5.13(b)(viii), all Series A Preferred Units shall be converted automatically into and shall thereafter represent solely the right to receive the Series A Redemption Consideration. All such Series A Preferred Units that have converted into the right to receive the Series A Redemption Consideration shall be automatically canceled and shall cease to exist, and the holders of redeemed Series A Preferred Units shall cease to have any rights with respect to such Series A Preferred Units other than the right to receive the Series A Redemption Consideration. Upon such conversion, any certificates representing Series A Preferred Units shall thereafter represent solely the right to receive the Series A Redemption Consideration.

 

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(C) To redeem Series A Preferred Units pursuant to this Section 5.13(b)(viii), the Partnership shall:

a. no earlier than 30 days nor later than two days prior to the Series A Redemption Date, send a written notice (the “ Series A Redemption Notice ”) to each holder of record of Outstanding Series A Preferred Units as of the date of such notice stating that the Series A Preferred Units will be redeemed pursuant to this Section 5.13(b)(viii) effective as of the date set forth in the Series A Redemption Notice (the “ Series A Redemption Date ”); and

b. as promptly as practicable following the Series A Redemption Date, send a written notice (a “ Series A Redemption Confirmation ”) to each holder of record of Outstanding Series A Preferred Units as of the Series A Redemption Date stating: (i) that the Series A Preferred Units have been redeemed pursuant to this Section 5.13(b)(viii) effective as of the Series A Redemption Date; (ii) the Partnership’s computation of the amount of Series A Redemption Consideration to be paid in respect of each Series A Preferred Unit pursuant to Section 5.13(b)(viii)(A) (including any adjustments pursuant to Sections 5.13(b)(xi) and (xii)), including the Partnership’s computation of the Series A Liquidation Value, the Series A Accretion Amount and the VWAP Price, in each case as of the Series A Redemption Date; and (iii) that such

holder must surrender the certificate or certificates representing any Series A Preferred Units held by such holder to the Partnership and provide such other documentation as reasonably requested by the General Partner including wire transfer instructions in respect of the Series A Redemption Consideration (the “ Series A Redemption Documentation ”), in order to receive the Series A Redemption Consideration.

In addition to delivery in accordance with the general notice provisions contained in Section 17.1, the Series A Redemption Notice and/or a Series A Redemption Confirmation shall be deemed properly delivered on the date the Partnership issues a press release distributed through a widely circulated news or wire service as would satisfy the requirements of Regulation FD, containing the information required to be included in the Series A Redemption Notice pursuant to this Section 5.13(b)(viii)(C).

(D) As promptly as practicable following the Series A Redemption Date, the holders of Series A Preferred Units shall surrender the certificate or certificates representing the Series A Preferred Units being redeemed, duly endorsed, at the office of the Partnership or, if identified in the Series A Redemption Notice to such holder by the Partnership, at the offices of any transfer agent for such Units, together with the Series A Redemption Documentation. As promptly as practicable following the receipt of such certificate or certificates (or a lost unit affidavit reasonably acceptable to the Partnership in the event of a lost certificate) representing the Series A Preferred Units and the Series A Conversion Documentation by the Partnership or the Transfer Agent as provided in the immediately preceding sentence (but in any event no later than five (5) Business Days thereafter), the Partnership shall:

a. issue to such holder a certificate or certificates for the number of Common Units to which such holder shall be entitled under Section 5.13(b)(viii)(A) (with the number of and denomination of such certificates designated by such holder). In lieu of delivering physical certificates representing the Common Units issuable upon redemption of Series A Preferred Units, provided the Transfer Agent is participating in the Depository’s Fast Automated Securities Transfer program, upon request of the holder, the Partnership shall use its commercially reasonable efforts to cause the Transfer Agent to electronically transmit the Common Units issuable upon redemption to the holder, by crediting the account of the holder’s prime broker with the Depository through its Deposit Withdrawal Agent Commission (DWAC) system. The holders of Series A Preferred Units and the Partnership agree to coordinate with the Depository to accomplish this objective; and

b. remit the applicable cash portion of the Series A Redemption Consideration to the holder surrendering such certificate orcertificates representing Series A Preferred Units by wire transfer of immediately available funds to an account specified by such holder in writing.

 

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The redemption pursuant to this Section 5.13(b)(viii) shall be deemed to have occurred immediately prior to the close of business on the Series A Redemption Date. The Person or Persons entitled to receive the Common Units issuable upon such redemption shall be treated for all purposes as the Record Holder or Holders of such Common Units at the close of business on the Series A Maturity Date.

(E) The Partnership shall pay any and all issue, documentary, stamp and other taxes, excluding any income, franchise or similar taxes, that may be payable in respect of any issue or delivery of Common Units on redemption of, or payment of distributions on, Series A Preferred Units pursuant hereto. However, the holder of any Series A Preferred Units shall pay any tax that is due because the Common Units issuable upon redemption thereof or distribution payment thereon are issued in a name other than such holder’s name.

(F) No fractional Common Units shall be issued upon the redemption of any Series A Preferred Units. All Common Units (including fractions thereof) issuable upon redemption of more than one Series A Preferred Unit by a holder thereof shall be aggregated for purposes of determining whether the redemption would result in the issuance of any fractional unit. If, after the aforementioned aggregation, the redemption would result in the issuance of a fraction of a Common Unit, the Partnership shall, in lieu of issuing any fractional unit, either round up the number of units to the next highest whole number or, at the Partnership’s option, pay the holder otherwise entitled to such fraction a sum in cash equal to such fraction multiplied by the VWAP Price as of the Series A Redemption Date.

(G) The Partnership shall not be obligated to issue any Common Units upon redemption of the Series A Preferred Units, whether pursuant to this Section 5.13(b)(viii), or otherwise, if the issuance of such Common Units would exceed the Series A Exchange Cap or if such issuance could reasonably be expected to conflict with a Securities Laws Prohibition. To the extent that a holder’s Series A Preferred Units would otherwise be redeemed for a number of Common Units that would exceed the Series A Exchange Cap, the Partnership shall pay in cash to such holder an amount equal to the VWAP Price as of the Series A Redemption Date multiplied by the number of Common Units that are not so issued but would otherwise be issuable as part of the Series A Redemption Consideration absent such Series A Exchange Cap or Securities Law Prohibition. 

(H) Any Common Units issued upon redemption of the Series A Preferred Units pursuant to this Section 5.13(b)(viii) shall not be subject to the first proviso contained in the definition of “Outstanding” contained in this Agreement for so long as held by the Investor.

(ix) Fundamental Change.

(A) If on the earlier of the date (x) the Partnership enters into a definitive agreement to consummate a Fundamental Change, (y) of the consummation of a Fundamental Change or (z) of the declaration of a distribution by the MLP described in subsection (vii) of the definition of Fundamental Change (the “ Fundamental Change Trigger Date ”), Investor holds, in the aggregate, at least fifty percent (50%) of the Series A Preferred Units issued pursuant to the Regency GP Purchase Agreement, then the Partnership will within 10 Business Days of such date send a written notice to the Investor stating the nature of the Fundamental Change, including a description of the material terms of the transaction constituting a Fundamental Change and, if the Fundamental Change has not yet occurred, the date or expected date of consummation. No later than 10 Business Days following delivery of the notice provided for in the previous sentence (the “ Election Notice Period ”), the Investor may, in its sole discretion, deliver written notice to the Partnership of its election, in its sole discretion, to:

a. upon the occurrence of any of the events specified in subsections (i), (ii), (iii) or (iv) of the definition of Fundamental Change, require the Partnership to redeem all of the Outstanding Series A Preferred Units pursuant to Section 5.13(b)(ix)(B)(a) (a “ Fundamental Change Forced Redemption Election ”); or

b. upon the occurrence of any of the events specified in subsections (v), (vi) or (vii) of the definition of Fundamental Change, require the Partnership to elect to convert or redeem the Series A Preferred Units pursuant to Section 5.13(b)(ix)(C).

 

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If at any time the Investor does not hold, in the aggregate, at least fifty percent (50%) of the Series A Preferred Units issued pursuant to the Regency GP Purchase Agreement, then the provisions of this Section 5.13(b)(ix) shall immediately cease to have any force or effect and the Investor and the holders of Series A Preferred Units shall have no rights hereunder, regardless of whether or not the Investor subsequently acquires additional Series A Preferred Units.

(B) Upon the occurrence of any of the events specified in subsections (i), (ii), (iii) or (iv) of the definition of Fundamental Change:

a. If the Investor timely makes a Fundamental Change Forced Redemption Election, then the Partnership will redeem all of the Outstanding Series A Preferred Units for cash and Common Units in an amount per Outstanding Series A Preferred Unit equal to the Fundamental Change Redemption Consideration.

i. Subject to Section 5.13(b)(ix)(B)(a)(ii), in connection with a redemption pursuant to this Section 5.13(b)(ix)(B)(a), the Partnership will deliver notice of the redemption, the Series A Preferred Units will be canceled, the certificates representing Series A Preferred Units will be surrendered in exchange for the issuance of Common Units and the cash portion of the Fundamental Change Redemption Consideration and any Fractional Unit Cash Consideration will be paid, each in a manner consistent with the provisions of Section 5.13(b)(viii)(B)-(H), except that, for purposes of applying such provisions to a redemption pursuant to this Section 5.13(b)(ix)(B)(a), (A) all references to the “Series A Redemption Consideration” will mean the “Fundamental Change Redemption Consideration,” (B) all references to “Series A Redemption Date” will mean the time immediately prior to the consummation of the Fundamental Change, (C) all references to “Series A Redemption Documentation” will mean “Fundamental Change Documentation,” (D) the Partnership must deliver the Series A Redemption Notice no later than two Business Days following the later of the date of consummation of the Fundamental Change and the expiration of the Election Notice Period and (E) references to Section 5.13(b)(viii)(A) shall mean a redemption pursuant to this Section 5.13(b)(ix)(B)(a).

ii. In the event the Fundamental Change Redemption Consideration Premium does not consist of Common Units, the Partnership shall (i) make appropriate provision, in the definitive transaction document governing the Fundamental Change or otherwise, to ensure that the holders of Series A Preferred Units receive the Fundamental Change Redemption Consideration (including the Fundamental Change Redemption Consideration Premium) reasonably promptly following such Fundamental Change upon the surrender of their certificates representing Series A Preferred Units and (ii) deliver reasonable notice of such provisions to the holders of Series A Preferred Units (which notice may be delivered in a manner consistent with that contemplated for delivery of a Series A Redemption Notice pursuant to Section 5.13(b)(viii)(C)). 

b. If the Investor does not timely make a Fundamental Change Forced Redemption Election, then each Series A Preferred Unit Outstanding immediately prior to the consummation of the Fundamental Change will automatically be converted into the right to receive the Fundamental Change Conversion Consideration pursuant to this Section 5.13(b)(ix)(B)(b).

i. In the event the Fundamental Change Conversion Consideration consists of Common Units, the Partnership will deliver notice of the conversion, the Series A Preferred Units will be canceled, the certificates representing Series A Preferred Units will be surrendered in exchange for the issuance of Common Units and Fractional Unit Cash Consideration will be paid, each in a manner consistent with the provisions of Section 5.13(b)(vii)(B)-(I), except that, for purposes of applying such provisions to a conversion pursuant to this Section 5.13(b)(ix)(B)(b), (A) all references to the “Series A Conversion Consideration” will mean the “Fundamental Change Conversion Consideration,” (B) all references to the “Series A Maturity Date” will mean the time immediately prior to the consummation of the Fundamental Change, (C) all references to “Series A Conversion Documentation” will mean “Fundamental Change Documentation,” (D) the Partnership must deliver the Series A Conversion Notice no later than two Business Days following the later of the date of consummation of the Fundamental Change and the expiration of the Election Notice Period, (E) Section 5.13(b)(vii)(C)(a) shall be inapplicable, (F) references to Section 5.13(b)(vii)(A) shall mean a conversion pursuant to Section 5.13(b)(ix)(B)(b) and (G) Section 5.13(b)(vii)(H) shall apply to any Common Units that would otherwise be issuable as a result of the Fundamental Change.

 

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ii. In the event the Fundamental Change Conversion Consideration does not consist of Common Units, the Partnership shall (i) make appropriate provision, in the definitive transaction document governing the Fundamental Change or otherwise, to ensure that the holders of Series A Preferred Units receive the Fundamental Change Conversion Consideration reasonably promptly following such Fundamental Change upon the surrender of their certificates representing Series A Preferred Units and (ii) deliver reasonable notice of such provisions to the holders of Series A Preferred Units (which notice may be delivered in a manner consistent with that contemplated for delivery of a Series A Conversion Notice pursuant to Section 5.13(b)(vii)(C)). 

(C) a. Upon the occurrence of any of the events specified in subsections (v), (vi) or (vii) of the definition of Fundamental Change and the election of the Investor to require the Partnership to elect to convert or redeem the Series A Preferred Units pursuant to this Section 5.13(b)(ix)(C), the Partnership will, within two Business Days following the later of the date of consummation of the Fundamental Change and the expiration of the Election Notice Period, deliver written notice to the holders of all Outstanding Series A Preferred Units as of the date of consummation of such Fundamental Change, stating (i) the Partnership’s election to either (x) convert each of the Series A Preferred Units Outstanding immediately prior to the consummation of the Fundamental Change into, for each Series A Preferred Unit then Outstanding, the right to receive a number of Common Units equal to (A) the Series A Liquidation Value on the date of consummation of the Fundamental Change divided by (B) the VWAP Price as of the date of consummation of the Fundamental Change (the “ Fundamental Change Elected Common Unit Consideration ”) or (y) redeem each of the Series A Preferred Units Outstanding immediately prior to the consummation of the Fundamental Change for an amount in cash per Series A Preferred Unit then Outstanding equal to the Series A Liquidation Value on the date of the consummation of the Fundamental Change (the “ Fundamental Change Elected Cash Consideration ”), (ii) the Partnership’s calculation of the Fundamental Change Elected Common Unit Consideration or Fundamental Change Elected Cash Consideration, as applicable, and (iii) that the holder must surrender the certificate or certificates representing Series A Preferred Units to the Partnership, together with the Fundamental Change Documentation, in order to receive the Fundamental Change Elected Common Unit Consideration or the Fundamental Change Elected Cash Consideration, as applicable. In addition to delivery in accordance with the general notice provisions contained in Section 17.1, any notice required to be delivered by the Partnership pursuant to this section shall be deemed properly delivered on the date the Partnership issues a press release distributed through a widely circulated news or wire service as would satisfy the requirements of Regulation FD, containing the information required to be included in such notice.

b. In addition to the requirements of Section 5.13(b)(ix)(C)(a) and (c), upon the declaration of a distribution by the MLP described in subsection (vii) of the definition of Fundamental Change, the Partnership will promptly give written notice to the Investor of such declaration and, if (x) the Investor delivers written notice to the Partnership no later than two Business Days after receipt of such notice from the Partnership and the Partnership elects to issue the Fundamental Change Elected Common Unit Consideration pursuant to Section 5.13(ix)(C)(a), then the Partnership shall cause such conversion to occur prior to the Record Date for the distribution on the Common Units next succeedingsuch election by the Partnership so that the Investor will be a holder of Common Units as of such Record Date; or (y) if the Investor delivers written notice to the Partnership no later than two Business Days after receipt of such notice from the Partnership and the Partnership elects to redeem the Series A Preferred Units for the Fundamental Change Elected Cash Consideration pursuant to Section 5.13(ix)(C)(a), then the Partnership shall cause such redemption to occur prior to payment of the distribution in respect of the Partnership’s Common Units for the Record Date for the distribution on the Common Units next succeeding such election by the Partnership.

c. In the event the Partnership elects to convert the Series A Preferred Units into the right to receive the Fundamental Change Elected Common Unit Consideration, the Series A Preferred Units will be canceled, the certificates representing Series A Preferred Units will be surrendered in exchange for the issuance of Common Units and the Fractional Unit Cash Consideration, if any, will be paid, each in

 

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accordance with the provisions of Section 5.13(b)(vii)(B)-(I), except that, for purposes of applying such provisions to a conversion pursuant to Section 5.13(b)(ix)(C)(a)(i)(x), (A) all references to the “Series A Conversion Consideration” will mean the “Fundamental Change Elected Common Unit Consideration,” (B) all references to the “Series A Maturity Date” will mean the time immediately prior to the consummation of the Fundamental Change, (C) all references to “Series A Conversion Documentation” will mean “Fundamental Change Documentation,” (D) Section 5.13(b)(vii)(C)(a) shall be inapplicable, (E) references to Section 5.13(b)(vii)(A) shall mean a conversion pursuant to Section 5.13(b)(ix)(C)(a)(i)(x) and (F) Section 5.13(b)(vii)(H) shall apply to any Common Units that would otherwise be issuable as a result of the Fundamental Change.

d. In the event the Partnership elects to redeem the Series A Preferred Unit for the Fundamental Change Elected Cash Consideration, the Series A Preferred Units will be canceled, the certificates representing Series A Preferred Units will be surrendered and the Fundamental Change Elected Cash Consideration will be paid in accordance with the provisions of Section 5.13(b)(viii)(B)-(H), except that, for purposes of applying such sections to a redemption pursuant to Section 5.13(b)(ix)(C)(a)(i)(y) (A) all references to the “Series A Redemption Consideration” will mean the “Fundamental Change Elected Cash Consideration,” (B) all references to “Series A Redemption Date” will mean the time immediately prior to the consummation of the Fundamental Change and (C) all references to “Series A Redemption Documentation” will mean “Fundamental Change Documentation” and (D) references to Section 5.13(b)(viii)(A) shall mean a redemption pursuant to Section 5.13(b)(ix)(C)(a)(i)(y). 

(D) If any Fundamental Change that is contemplated by a definitive agreement is not consummated and therefore the conditions to the applicable redemption or exchange pursuant to this Section 5.13(b)(ix) have not been satisfied, the Partnership will send written notice to such effect to the Investor (which notice may be delivered in a manner consistent with that contemplated for delivery of a Series A Conversion Notice pursuant to Section 5.13(b)(vii)(C)). Notwithstanding anything to the contrary in this Agreement, if a Fundamental Change is not consummated, no Series A Preferred Units will be redeemed or converted pursuant to this Section 5.13(b)(ix).

(x) Limitations on Transfer. Series A Preferred Units may only be transferred to one or more transferees that, after giving effect to such transfer, each hold at least 1,000,000 Series A Preferred Units, provided that the foregoing limitation shall not apply to any transfer of Series A Preferred Units to (i) the holders of the class B units in Regency GP Seller of up to eight percent (8%) of the Series A Preferred Units or (ii) Regency GP Seller and its Affiliates. In addition, a Unitholder holding a Series A Preferred Unit that has converted into a Common Unit pursuant to Section 5.13 shall be subject to the restrictions on transfer imposed by Section 6.6(B). For the avoidance of doubt, nothing contained in this Section 5.13(b)(x) shall in any way affect the restrictions on transfers of Partnership Interests contained in Section 4.7, which shall apply to transfers of Series A Preferred Units.

(xi) Extraordinary Partnership Transactions.

(A) Except to the extent that any such event is a Fundamental Change as a result of which the Series A Preferred Units are redeemed or converted pursuant to Section 5.13(b)(ix), prior to the consummation of any recapitalization, reorganization, consolidation, merger, spin-off or other business combination in which the holders of Common Units are to receive securities, cash or other assets or any exchange or conversion of limited partnership interests pursuant to which all of the Common Units are converted into Parity Securities (other than, in each case, a Series A Adjustment Event or a Special Distribution) (any such event being a “ Partnership Event ”), the Partnership shall make appropriate provision to ensure that the holders of Series A Preferred Units receive in such Partnership Event a preferred security, issued by the Person surviving or resulting from such Partnership Event and containing provisions substantially equivalent to the provisions set forth in this Section 5.13 without abridgement, including, without limitation, the same powers, preferences, rights to distributions, rights to accumulation upon failure to pay distributions, and relative participating, optional or other special rights and the qualifications, limitations or restrictions thereon, that the Series A Preferred Units had immediately prior to such Partnership Event, subject to the adjustments described in Section 5.13(b)(xi)(B) and Section5.13(b)(xi)(C). The date on which a Partnership Event is consummated is referred to as the “ Partnership Event Consummation Date. ”

 

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(B) If in connection with a Partnership Event the Common Units are converted in whole or in part into other Marketable Securities (such securities the “ Successor Securities ” and such event, a “ Public Equity Partnership Event ”), then, following the Partnership Event Consummation Date, (i) upon the conversion of the Series A Preferred Units pursuant to Section 5.13(b)(vii), the redemption of the Series A Preferred Units pursuant to Section 5.13(b)(viii), or the redemption or conversion of the Series A Preferred Units pursuant to Section 5.13(b)(ix), any portion of the Series A Conversion Consideration, the Series A Redemption Consideration, the Fundamental Change Redemption Consideration, the Fundamental Change Conversion Consideration or the Fundamental Change Elected Common Unit Consideration, as applicable, that would otherwise consist of Common Units pursuant to the terms of Section 5.13(b)(vii), 5.13(b)(viii) or 5.13(b)(ix), as applicable, shall instead consist of Successor Securities, (ii) references in Sections 5.13(b)(ii)(B), 5.13(b)(vii), 5.13(b)(viii), 5.13(b)(ix), 6.6(a) and 6.6(b) to “Common Units” shall refer to the Successor Securities and (iii) the term “ Trading Price Accretion Percentage ” shall be modified to mean an amount equal to (a) the Combined Accretion Multiple less (b) 1.00. The “ Combined Accretion Multiple” shall mean an amount equal to the product of:

a. a fraction, (i) the numerator of which is the VWAP Price of the Common Units as of the Partnership Event Consummation Date and (ii) the denominator of which is the VWAP Price of the Common Units as of the Series A Issuance Date (the “ Pre-Partnership Event Accretion Multiple ”); multiplied by

b. a fraction, (i) the numerator of which is the VWAP Price of the Successor Securities as of the Series A Conversion Date, the Series A Redemption Date or the date of consummation of the Fundamental Change, as applicable and (ii) the denominator of which is the VWAP Price of the Successor Securities as of the eleventh Trading Day following the Partnership Event Consummation Date (the “ Post-Partnership Event Accretion Multiple ”),

provided that, if the foregoing product is less than 1.00, then the Combined Accretion Multiple shall equal 1.00.

(C) If in connection with a Partnership Event the Common Units do not remain Outstanding and are converted solely into cash or other assets or securities that do not constitute Marketable Securities (or any combination thereof), then following such Partnership EventConsummation Date, upon the conversion of the Series A Preferred Units pursuant to Section 5.13(b)(vii), the redemption of the Series A Preferred Units pursuant to Section 5.13(b)(viii), or the redemption or conversion of the Series A Preferred Units pursuant to Section 5.13(b)(ix):

a. any portion of the Series A Conversion Consideration, the Series A Redemption Consideration, the Fundamental Change Redemption Consideration, the Fundamental Change Conversion Consideration or the Fundamental Change Elected Common Unit Consideration, as applicable, that would otherwise consist of Common Units pursuant to the terms of Section 5.13(b)(vii), 5.13(b)(viii) or 5.23(b)(ix), as applicable, shall instead be payable solely in cash;

b. the Series A Conversion Consideration or the Series A Redemption Consideration, as applicable, shall be an amount equal to the Series A Liquidation Amount as of the Series A Maturity Date or the Series A Redemption Date, as applicable, plus:

i. in the event of a redemption, the greater of (i) the Series A Accretion Amount as of the Partnership Event Consummation Date and (ii) $10.00; or

ii. in the event of a conversion, the lesser of (i) the Series A Accretion Amount as of the Partnership Event Consummation Date and (ii) $10.00;

c. the term “ Fundamental Change Redemption Consideration Premium ” shall be modified to mean an amount in cash equal to the greater of (i) the Series A Accretion Amount as of the date of the Partnership Event Consummation Date and (ii) $10.00;

d. the term “ Fundamental Change Conversion Consideration ” shall be modified to mean an amount in cash equal to the Series A Liquidation Value as of the date of the consummation of the Fundamental Change plus the lesser of (i) the Series A Accretion Amount as of the Partnership Event Consummation Date and (ii) $10; and

 

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e. the Partnership will no longer have the option to convert the Series A Preferred Units into Common Units pursuant to Section 5.13(b)(ix)(C), but instead must convert them into the right to receive the Fundamental Change Elected Cash Consideration.

(xii) Distributions, Combinations and Subdivisions; Other Adjustments.

(A) If, after the Series A Issuance Date and prior to the earlier of the Series A Maturity Date and the Series A Redemption Date, the Partnership (a) makes a distribution on its Common Units in Common Units, (b) subdivides or splits its Common Units into a greater number of Common Units, (c) combines or reclassifies its Common Units into a smaller number of Common Units, (each of the events described in clauses (a) through (c), a “ Series A Adjustment Event ”) or (d) makes a distribution on its Common Units in any property other than cash or Common Units (a “ Special Distribution ”), then calculation of the Series A Conversion Consideration and the Series A Redemption Consideration shall be adjusted as provided in this Section 5.13(b)(xii)(A) and Sections 5.13(b)(xii)(C) and (D).

a. Solely for the purposes of determining the Trading Price Accretion Percentage for purposes of Section 5.13(b)(vii)(A) (in the event of a conversion) or Section 5.13(b)(viii)(A) (in the event of a redemption):

i. for each Series A Adjustment Event, the VWAP Price as of the Series A Maturity Date or the Series A Redemption Date, as applicable, shall be adjusted by multiplying such VWAP Price by a fraction, (i) the numerator of which shall be the number of Common Units Outstanding immediately following such Series A Adjustment Event and (ii) the denominator of which shall be the number of Common Units Outstanding immediately prior to such Series A Adjustment Event; and

ii. for each Special Distribution, the VWAP Price as of the Series A Maturity Date or the Series A Redemption Date, as applicable, shall be adjusted by adding to such VWAP Price the Fair Market Value of the property distributed on a Common Unit in such Special Distribution.

b. Solely for the purposes of determining the Trading Price Accretion Percentage for purposes of Section 5.13(b)(xi)(C) (in the event of conversion or redemption following a Partnership Event Consummation Date) and determining the Pre-Partnership Event Accretion Multiple pursuant to Section 5.13(b)(xi)(B)(a):

i. for each Series A Adjustment Event prior to the Partnership Event Consummation Date, the VWAP Price as of the Partnership Event Consummation Date shall be adjusted by multiplying such VWAP Price by a fraction, (i) the numerator ofwhich shall be the number of Common Units Outstanding immediately following such Series A Adjustment Event and (ii) the denominator of which shall be the number of Common Units Outstanding immediately prior to such Series A Adjustment Event; and

ii. for each Special Distribution prior to the Partnership Event Consummation Date, the VWAP Price as of the Partnership Event Consummation Date shall be adjusted by adding to such VWAP Price the Fair Market Value of the property distributed on a Common Unit in such Special Distribution.

c. Solely for the purposes of determining the Post-Partnership Event Accretion Multiple pursuant to Section 5.13(b)(xi)(B)(b):

i. for each Series A Adjustment Event following the Partnership Event Consummation Date, the VWAP Price as of the Series A Maturity Date or the Series A Redemption Date, as applicable, shall be adjusted by multiplying such VWAP Price by a fraction, (i) the numerator of which shall be the number of shares of Successor Securities outstanding immediately following such Series A Adjustment Event and (ii) the denominator of which shall be the number of shares of Successor Securities outstanding immediately prior to such Series A Adjustment Event; and

ii. for each Special Distribution following the Partnership Event Consummation Date, the VWAP Price as of the Series A Maturity Date or the Series A Redemption Date, as applicable, shall be adjusted by adding to such VWAP Price the Fair Market Value of the property distributed on a share of Successor Securities in such Special Distribution.

 

18


For purposes of this Section 5.13(b)(ix)(A)(c), references to “Common Units” in the definitions of “Series A Adjustment Event” and “Special Distribution” set forth in Section 5.13(b)(ix)(A) shall refer to Successor Securities.

(B) If, after the Series A Issuance Date and prior to the date of the consummation of a Fundamental Change, a Series A Adjustment Event or a Special Distribution occurs, then the calculation of the Fundamental Change Redemption Consideration or the Fundamental Change Conversion Consideration shall be adjusted as provided in this Section 5.13(b)(xii)(B) and Sections 5.13(b)(xii)(C) and (D). Solely for the purposes of determining the Trading Price Accretion Percentage for purposes of calculating the “Fundamental Change ConversionConsideration” (in the event of a conversion) or the “Fundamental Change Redemption Consideration” (in the event of a redemption):

a. for each Series A Adjustment Event, the VWAP Price as of the date of the consummation of a Fundamental Change shall be adjusted by multiplying such VWAP Price by a fraction, (i) the numerator of which shall be the number of Common Units Outstanding immediately following such Series A Adjustment Event and (ii) the denominator of which shall be the number of Common Units Outstanding immediately prior to such Series A Adjustment Event; and

b. for each Special Distribution, the VWAP Price as of the date of the consummation of a Fundamental Change shall be adjusted by adding to such VWAP Price the Fair Market Value of the property distributed on a Common Unit in such Special Distribution.

(C) Subsequent adjustments to the applicable VWAP Price shall be made successively in the order of occurrence of any Series A Adjustment Event or Special Distribution whenever more than one Series A Adjustment Event or Special Distribution occurs during an applicable period.

(D) If a Partnership Event, a Series A Adjustment Event or a Special Distribution occurs during a ten Trading Day period used for purposes of calculating a VWAP Price as of any particular date under any provision of this Agreement, the Partnership shall make appropriate adjustments to the VWAP Price to insure that the VWAP Price properly reflects the value of the Common Units or Successor Securities, as applicable, as of any particular date.

(g) The first sentence of Section 6.1 of the Partnership Agreement is amended and restated in its entirety to read as follows:

“For purposes of maintaining Capital Accounts and in determining the rights of the Partners among themselves, the Partnership’s items of income, gain, loss and deduction (computed in accordance with 5.6(b)) shall be allocated (subject to Section 5.13(b)) among the Partners in each taxable year (or portion thereof) as provided herein below.”

(h) Section 6.1(d)(ix) is hereby amended and restated in its entirety to read as follows:

“(ix) Redemption of Series A Preferred Units. Notwithstanding any other provision of this 6.1 (other than the Regulatory Allocations), with respect to any taxable period during which Series A Preferred Units are redeemed pursuant to the terms of Section 5.13(b), each Partner holding redeemed Series A Preferred Units shall be allocated items of income, gain, loss and deduction in a manner that results in the Capital Account balance of each such Partner attributable to itsredeemed Series A Preferred Units immediately prior to such redemption (and after taking into account any applicable Regulatory Allocations) to equal (i) the amount of cash paid to such Partner in redemption of such Series A Preferred Units, and (ii) the product of the number of Common Units received in the redemption and the Per Unit Capital Amount for a then Outstanding Common Unit (but only to the extent not otherwise achieved by operation of section 5.6(d)(ii)).”

(i) Section 6.2 of the Partnership Agreement is hereby amended to add the following as Section 6.2(i) immediately following Section 6.2(h):

 

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“Section 6.2(i). If Capital Account balances are reallocated between the Partners in accordance with Section 5.6(d)(i) hereof and Proposed Treasury Regulation Section 1.704-1(b)(2)(iv)(s)(4), beginning with the year of reallocation and continuing until the allocations required are fully taken into account, the Partnership shall make corrective allocations (allocations of items of gross income or gain or loss or deduction for federal income tax purposes that do not have a corresponding book allocation) to take into account the Capital Account reallocation, as provided in Proposed Treasury Regulation Section 1.704-1(b)(4)(x).”

(j) Article VI of the Partnership Agreement is hereby amended to add a new Section 6.6 as follows:

“Section 6.6 Special Provisions Relating to the Holders of Series A Preferred Units.

(A) A Unitholder holding a Series A Preferred Unit that has converted into a Common Unit pursuant to Section 5.13 shall be required to provide notice to the General Partner of the transfer of the converted Series A Preferred Unit within the earlier of (i) thirty (30) days following such transfer and (ii) the last Business Day of the calendar year during which such transfer occurred, unless (x) the transfer is to an Affiliate of the holder or (y) by virtue of the application of Section 5.6(d)(i), the General Partner has previously determined, based on advice of counsel, that the converted Series A Preferred Unit should have, as a substantive matter, like intrinsic economic and federal income tax characteristics of an Initial Common Unit. In connection with the condition imposed by this Section 6.6, the General Partner shall take whatever steps are required to provide economic uniformity to the converted Series A Preferred Unit in preparation for a transfer of such Units; provided, however, that no such steps may be taken that would have a material adverse effect on the Unitholders holding Common Units represented by Common Unit Certificates (for this purpose the allocations of income, gain, loss and deductions with respect to Series A Preferred Units or Common Units will be deemed not to have a material adverse effect on the Unitholders holding Common Units). 

(B) A Unitholder holding a Series A Preferred Unit that has converted into a Common Unit pursuant to Section 5.13 shall not be permitted to transfer, by assignment or otherwise, any such Common Unit until after 32 calendar days have elapsed from the date that the Series A Preferred Unit was converted into such Common Unit.

(C) Notwithstanding anything to the contrary set forth in this Agreement, the holders of the Series A Preferred Units (a) shall (i) possess the rights, preferences and privileges and the duties and obligations provided in this Agreement with respect to a Limited Partner pursuant to Article III and Article VII and (ii) have a Capital Account as a Partner pursuant to Section 5.6 and all other provisions related thereto and (b) shall not (i) be entitled to vote on any matters requiring the approval or vote of the holders of Outstanding Units, except as provided in Section 5.13, (ii) be entitled to any distributions other than as provided in Section 5.13, Article VI or Article XII or (iii) be allocated items of income, gain, loss or deduction other than as specified in Section 5.13 or Article VI.”

(k) Article XII of the Partnership Agreement is hereby amended to add a new Section 12.10 as follows:

“Section 12.10. Series A Liquidation Value. Notwithstanding anything to the contrary set forth in this Agreement, the holders of the Series A Preferred Units shall have the rights, preferences and privileges set forth in Section 5.13(b)(iv) upon liquidation of the Partnership pursuant to this Article XII.”

(l) The Partnership Agreement is hereby amended to eliminate any references therein to “Class B Units” or “Class C Units.”

Section 2. Ratification of Partnership Agreement. Except as expressly modified and amended herein, all of the terms and conditions of the Partnership Agreement shall remain in full force and effect.

Section 3. Governing Law. This Amendment will be governed by and construed in accordance with the laws of the State of Delaware.

Section 4. Counterparts. This Amendment may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart.

 

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IN WITNESS WHEREOF, this Amendment has been executed as of the date first written above.

 

GENERAL PARTNER:
LE GP, LLC
By:  

/s/ John W. McReynolds

  John W. McReynolds,
  President and Chief Financial Officer

LIMITED PARTNERS:

 

All Limited Partners now and hereafter admitted as limited partners of the Partnership, pursuant to Powers of Attorney now and hereafter executed in favor of, and granted and delivered to, the General Partner.
By: LE GP, LLC, General Partner of
Energy Transfer Equity, L.P., as
attorney-in-fact for all Limited Partners pursuant to the powers of Attorney granted pursuant to Section 2.6 of the Partnership Agreement.
By:  

/s/ John W. McReynolds

  John W. McReynolds,
  President and Chief Financial Officer

Signature Page to

Amendment No. 3 to ETE Partnership Agreement

EX-3.7

Exhibit 3.7

AMENDMENT NO. 4

TO

THIRD AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP

OF

ENERGY TRANSFER EQUITY, L.P.

This Amendment No. 4 (this “ Amendment ”) to the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., a Delaware limited partnership (the “ Partnership ”), dated as of February 8, 2006 (the “ Partnership Agreement”), is entered into effective as of December 23, 2013, by LE GP, LLC, a Delaware limited liability company (the “ General Partner”), as the general partner of the Partnership, on behalf of itself and the Limited Partners of the Partnership. Capitalized terms used but not defined herein are used as defined in the Partnership Agreement.

RECITALS

WHEREAS, Section 5.8 of the Partnership Agreement provides that the General Partner, without the approval of any Limited Partner except as otherwise provided in the Partnership Agreement, may, for any Partnership purpose, at any time or from time to time, issue additional Partnership Securities to such Persons for such consideration and on such terms and conditions as shall be established by the General Partner in its sole discretion;

WHEREAS, Section 13.1(d)(i) of the Partnership Agreement provides that the General Partner, without the approval of any Partner, may amend any provision of the Partnership Agreement (to reflect a change that the General Partner determines does not adversely affect the Limited Partners in any material respect);

WHEREAS, Section 13.1(g) of the Partnership Agreement provides that the General Partner, without the approval of any Partner, may amend any provision of the Partnership Agreement to reflect an amendment that the General Partner determines is necessary or appropriate in connection with the authorization of issuance of any class or series of Partnership Securities pursuant to Section 5.8 of the Partnership Agreement;

WHEREAS, the Partnership desires to issue newly created Class D Units (as defined below);

WHEREAS, the General Partner has determined that the creation of the Class D Units will be in the best interest of the Partnership and beneficial to the Limited Partners, including the holders of the Common Units;

WHEREAS, the issuance of the Class D Units complies with the requirements of the Partnership Agreement; and

WHEREAS, the General Partner has determined, pursuant to Section 13.1(g) of the Partnership Agreement, that the amendments to the Partnership Agreement set forth herein are necessary or appropriate in connection with the authorization of the issuance of the Class D Units;

NOW, THEREFORE, the Partnership Agreement is hereby amended as follows:

Section 1. Amendments.

(a) Section 1.1 of the Partnership Agreement is hereby amended to add or amend and restate the following definitions:

Accelerated Class D Unit Conversion Date” means the date on which a certain event has occurred as set forth in an agreement between the Partnership and a holder of a Class D Unit that has resulted in the Class D Unit Conversion Date of such holder being accelerated to the date of such event.

 

1


Additional Book Basis” means, with respect to any Adjusted Property, the portion of the Carrying Value of such Adjusted Property that is attributable to positive adjustments made to such Carrying Value, as determined in accordance with the provisions set forth below in this definition of Additional Book Basis. For purposes of determining the extent to which Carrying Value constitutes Additional Book Basis:

(i) Any negative adjustment made to the Carrying Value of an Adjusted Property as a result of either a Book-Down Event or a Book-Up Event shall first be deemed to offset or decrease that portion of the Carrying Value of such Adjusted Property that is attributable to any prior positive adjustments made thereto pursuant to a Book-Up Event or Book-Down Event.

(ii) If Carrying Value that constitutes Additional Book Basis is reduced as a result of a Book-Down Event (an “Additional Book Basis Reduction”) and the Carrying Value of other property is increased as a result of such Book-Down Event (a “Carrying Value Increase”), then any such Carrying Value Increase shall be treated as Additional Book Basis in an amount equal to the lesser of (a) the amount of such Carrying Value Increase and (b) the amount determined by proportionately allocating to the Carrying Value Increases resulting from such Book-Down Event the lesser of (I) the aggregate Additional Book Basis Reductions resulting from such Book-Down Event and (II) the amount by which the Aggregate Remaining Net Positive Adjustments after such Book-Down Event exceeds the remaining Additional Book Basis attributable to all of the Partnership’s Adjusted Property after such Book-Down Event (determined without regard to the application of this clause (ii) to such Book-Down Event).

Additional Book Basis Derivative Items means any Book Basis Derivative Items that are computed with reference to Additional Book Basis. To the extent that the Additional Book Basis attributable to all of the Partnership’s Adjusted Property as of the beginning of any taxable period exceeds the Aggregate Remaining Net Positive Adjustments as of the beginning of such period (the “Excess Additional Book Basis”), the Additional Book Basis Derivative Items for such period shall be reduced by the amount that bears the same ratio to the amount of Additional Book Basis Derivative Items determined without regard to this sentence as the Excess Additional Book Basis bears to the Additional Book Basis as of the beginning of such period. With respect to a Disposed of Adjusted Property, the Additional Book Basis Derivative Items shall be the amount of Additional Book Basis taken into account in computing gain or loss from the disposition of such Disposed of Adjusted Property; provided that the provisions of the immediately preceding sentence shall apply to the determination of the Additional Book Basis Derivative Items attributable to Disposed of Adjusted Property.

“Adjusted Capital Account” means, with respect to any Partner, the balance in such Partner’s Capital Account at the end of each taxable period of the Partnership after giving effect to the following adjustments:

(i) credit to such Capital Account any amounts which such Partner is (x) obligated to restore under the standards set by Treasury Regulation Section 1.704-1(b)(2)(ii)(c) or (y) deemed obligated to restore pursuant to the penultimate sentences of Treasury Regulation Sections 1.704-2(g)(1) and 1.704-2(i)(5); and

(ii) debit to such Capital Account the items described in Treasury Regulation Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5) and 1.704-1(b)(2)(ii)(d)(6).

The foregoing definition of Adjusted Capital Account is intended to comply with the provisions of Treasury Regulation Section 1.701-1(b)(2)(ii)(d) and shall be interpreted consistently therewith. The “Adjusted Capital Account” of a Partner in respect of any Partnership Interest shall be the amount that such Adjusted Capital Account would be if such Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such Partnership Interest were first issued.

“Agreed Value” of (a) a Contributed Property means the fair market value of such property at the time of contribution and (b) an Adjusted Property means the fair market value of such Adjusted Property on the date of the Revaluation Event, in each case as determined by the General Partner.

Book-Down Event” means a Revaluation Event that gives rise to a Net Termination Loss.

“Book-Up Event” means a Revaluation Event that gives rise to a Net Termination Gain.

 

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Carrying Value means (a) with respect to a Contributed Property or an Adjusted Property, the Agreed Value of such property reduced (but not below zero) by all depreciation, amortization and other cost recovery deductions charged to the Partners’ Capital Accounts in respect of such property, and (b) with respect to any other Partnership property, the adjusted basis of such property for U.S. federal income tax purposes, all as of the time of determination. The Carrying Value of any property shall be adjusted from time to time in accordance with Section 5.6(d) and to reflect changes, additions or other adjustments to the Carrying Value for dispositions and acquisitions of Partnership properties, as deemed appropriate by the General Partner.

Class D Unit” means a Partnership Security representing a fractional part of the Partnership Interests of all Limited Partners and Assignees, and having the rights and obligations specified with respect to the Class D Units in this Agreement. The term “Class D Unit” does not refer to a Common Unit, and after the conversion of a Class D Unit into a Common Unit pursuant to the terms herein, such Unit will be a Common Unit.

“Class D Unit Conversion Date” means one or more dates set forth in an agreement between the Partnership and a holder of a Class D Unit on which all or a percentage of such holder’s Class D Units are convertible into Common Units subject to the terms herein.

“Class D Unit Conversion Effective Date” means, with respect to each Class D Unit eligible to be converted into a Common Unit pursuant to the terms of Section 5.14, the date on which such Class D Unit has a Capital Account equal to the Per Unit Capital Account as a result of allocations of Unrealized Gain pursuant to Section 5.14(b)(i)(C)(2).

“Disposed of Adjusted Property” has the meaning assigned to such term in Section 6.1(d)(xi)(B).

“Event Issue Value” means, with respect to any Common Unit as of any date of determination, (i) in the case of a Revaluation Event that includes the issuance of Common Units pursuant to a public offering and solely for cash, the price paid for such Common Units, or (ii) in the case of any other Revaluation Event, the Closing Price of the Common Units on the date of such Revaluation Event or, if the General Partner determines that a value for the Common Unit other than such Closing Price more accurately reflects the Event Issue Value, the value determined by the General Partner.

“Good Standing” means the satisfaction of certain conditions or requirements set forth in an agreement between the Partnership and a holder of a Class D Unit affecting the right of the holder to receive distributions with respect to a Class D Unit or have a Class D Unit converted into a Common Unit.

Gross Liability Value means, with respect to any Liability of the Partnership described in Treasury Regulation Section 1.752-7(b)(3)(i), the amount of cash that a willing assignor would pay to a willing assignee to assume such Liability in an arm’s-length transaction. The Gross Liability Value of each Liability of the Partnership described in Treasury Regulation Section 1.752-7(b)(3)(i) shall be adjusted at such times as provided in this Agreement for an adjustment to Carrying Values.

“Liability” means any liability or obligation of any nature, whether accrued, contingent or otherwise.

“Net Income” means, for any taxable year, the excess, if any, of the Partnership’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year over the Partnership’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year. The items included in the calculation of Net Income shall be determined in accordance with Section 5.6(b) and shall not include any items specially allocated under Section 6.1(d); provided that the determination of the items that have been specially allocated under Section 6.1(d) shall be made without regard to any reversal of such items under Section 6.1(d)(xi).

“Net Loss” means, for any taxable year, the excess, if any, of the Partnership’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year over the Partnership’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year. The items included in the calculation of Net Loss shall be determined in accordance with Section 5.6(b) and shall not include any items specially allocated under Section 6.1(d); provided that the determination of the items that have been specially allocated under Section 6.1(d) shall be made without regard to any reversal of such items under Section 6.1(d)(xi).

 

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“Net Termination Gain” means, for any taxable period, (a) the sum, if positive, of all items of income, gain, loss or deduction (determined in accordance with Section 5.6(b)) that are recognized (i) after the Liquidation Date or (ii) upon the sale, exchange or other disposition of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions (excluding any disposition to a member of the Partnership Group), or (b) the excess, if any, of the aggregate amount of Unrealized Gain over the aggregate amount of Unrealized Loss deemed recognized by the Partnership pursuant to Section 5.6(d) on the date of a Revaluation Event; provided, however, the items included in the determination of Net Termination Gain shall not include any items of income, gain or loss specially allocated under Sections 5.14(b)(i)(C) and 6.1(d)(i) through 6.1(d)(x).

Net Termination Loss means, for any taxable period, (a) the sum, if negative, of all items of income, gain, loss or deduction (determined in accordance with Section 5.6(b)) that are recognized by the Partnership (i) after the Liquidation Date or (ii) upon the sale, exchange or other disposition of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions (excluding any disposition to a member of the Partnership Group) or (b) the excess, if any, of the aggregate amount of Unrealized Loss over the aggregate amount of Unrealized Gain deemed recognized by the Partnership pursuant to Section 5.6(d) on the date of a Revaluation Event; provided, however, the items included in the determination of Net Termination Loss shall not include any items of income, gain or loss specially allocated under Sections 5.14(b)(i)(C) and 6.1(d)(i) through 6.1(d)(x).

“Remaining Net Positive Adjustments” means, as of the end of any taxable period, (i) with respect to the Unitholders holding Common Units, the excess of (a) the Net Positive Adjustments of the Unitholders holding Common Units as of the end of such period over (b) the sum of those Partners’ Share of Additional Book Basis Derivative Items for each prior taxable period, (ii) with respect to the Unitholders holding Class D Units, the excess of (a) the Net Positive Adjustments of the Unitholders holding Class D Units as of the end of such period over (b) the sum of those Partners’ Share of Additional Book Basis Derivative Items for each prior taxable period, and (iii) with respect to the General Partner (as holder of the General Partner Interest), the excess of (a) the Net Positive Adjustments of the General Partner as of the end of such period over (b) the sum of the General Partner’s Share of Additional Book Basis Derivative Items with respect to the General Partner Interest for each prior taxable period.

“Revaluation Event” means an event that results in an adjustment of the Carrying Value of each Partnership property pursuant to Section 5.6(d).

“Share of Additional Book Basis Derivative Items” means, in connection with any allocation of Additional Book Basis Derivative Items for any taxable period, (i) with respect to the Unitholders holding Common Units, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Unitholders’ Remaining Net Positive Adjustments as of the end of such period bears to the Aggregate Remaining Net Positive Adjustments as of that time, (ii) with respect to the Unitholders holding Class D Units, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Unitholders’ Remaining Net Positive Adjustments as of the end of such period bears to the Aggregate Remaining Net Positive Adjustments as of that time, and (iii) with respect to the General Partner (as the holder of the General Partner Interest), the amount that bears the same ratio to such Additional Book Basis Derivative Items as the General Partner’s Remaining Net Positive Adjustments as of the end of such period bears to the Aggregate Remaining Net Positive Adjustment as of that time.

(b) Section 1.1 of the Partnership Agreement is hereby further amended to add the following sentence to the end of the definition of “Common Unit”;

“The term “Common Unit” does not refer to a Class D Unit prior to the conversion of such Unit into a Common Unit pursuant to the terms hereof.”

 

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(c) Section 4.7(c) of the Partnership Agreement is hereby amended and restated to read in its entirety as follows:

“(c) The transfer of a Class D Unit shall be subject to the restrictions imposed by Section 5.14(b)(vi) and Section 6.7.”

(d) Section 5.6(b) of the Partnership Agreement is hereby amended and restated to read in its entirety as follows:

“(b) For purposes of computing the amount of any item of income, gain, loss or deduction which is to be allocated pursuant to Article VI and is to be reflected in the Partners’ Capital Accounts, the determination, recognition and classification of any such item shall be the same as its determination, recognition and classification for federal income tax purposes (including, without limitation, any method of depreciation, cost recovery or amortization used for that purpose), provided, that:

(i) Solely for purposes of this Section 5.6, the Partnership shall be treated as owning directly its proportionate share (as determined by the General Partner based upon the provisions of the respective Group Members’ governing, organizational or similar documents) of all property owned by (x) any Group Member that is classified as a partnership for federal income tax purposes and (y) any other partnership, limited liability company, unincorporated business or other entity classified as a partnership for federal income tax purposes of which a Group Member is, directly or indirectly, a partner.

(ii) All fees and other expenses incurred by the Partnership to promote the sale of (or to sell) a Partnership Interest that can neither be deducted nor amortized under Section 709 of the Code, if any, shall, for purposes of Capital Account maintenance, be treated as an item of deduction at the time such fees and other expenses are incurred and shall be allocated among the Partners pursuant to Section 6.1.

(iii) The computation of all items of income, gain, loss and deduction shall be made (x) except as otherwise provided in Treasury Regulation Section 1.704-1(b)(2)(iv)(m), without regard to any election under Section 754 of the Code that may be made by the Partnership, and (y) as to those items described in Section 705(a)(1)(B) or 705(a)(2)(B) of the Code, without regard to the fact that such items are not includable in gross income or are neither currently deductible nor capitalized for U.S. federal income tax purposes.

(iv) To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) of the Code (including pursuant to Treasury Regulation Section 1.734-2(b)(1)) is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m)), to be taken into account in determining Capital Accounts, the amount of such adjustment in the Capital Accounts shall be treated as an item of gain or loss.

(v) In the event the Carrying Value of Partnership property is adjusted pursuant to Section 5.6(d), any Unrealized Gain resulting from such adjustment shall be treated as an item of gain and any Unrealized Loss resulting from such adjustment shall be treated as an item of loss.

(vi) Any income, gain or loss attributable to the taxable disposition of any Partnership property shall be determined as if the adjusted basis of such property as of such date were equal in amount to the Partnership’s Carrying Value with respect to such property as of such date.

(vii) Any deductions for depreciation, cost recovery or amortization attributable to any Contributed Property or Adjusted Property shall be determined under the rules prescribed by Treasury Regulation Section 1.704-3(d)(2) as if the adjusted basis of such property were equal to the Carrying Value of such property immediately following such adjustment.

(viii) The Gross Liability Value of each Liability of the Partnership described in Treasury Regulation Section 1.752-7(b)(3)(i) shall be adjusted at such times as provided in this Agreement for an adjustment to Carrying Values. The amount of any such adjustment shall be treated for purposes hereof as an item of loss (if the adjustment increases the Carrying Value of such Liability of the Partnership) or an item of gain (if the adjustment decreases the Carrying Value of such Liability of the Partnership).”

 

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(e) Section 5.6(d) of the Partnership Agreement is hereby amended and restated to read in its entirety as follows:

(d)

(i) Consistent with Treasury Regulation Sections 1.704-1(b)(2)(iv)(f) and 1.704-1(b)(2)(h)(2), on an issuance of additional Partnership Interests for cash or Contributed Property, the issuance of Partnership Interests as consideration for the provision of services or the conversion of the Combined Interest to Common Units pursuant to Section 11.3(b), the Carrying Value of each Partnership property immediately prior to such issuance shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership Property; provided, however, that in the event of an issuance of Partnership Interests for a de minimis amount of cash or Contributed Property, or in the event of an issuance of a de minimis amount of Partnership Interests as consideration for the provision of services, the General Partner may determine that such adjustments are unnecessary for the proper administration of the Partnership. In determining such Unrealized Gain or Unrealized Loss, the aggregate fair market value of all Partnership property (including cash or cash equivalents) immediately prior to the issuance of additional Partnership Interests shall be determined by the General Partner using such method of valuation as it may adopt. In making its determination of the fair market values of individual properties, the General Partner may first determine an aggregate value for the assets of the Partnership that takes into account the current trading price of the Common Units, the fair market value of all other Partnership Interests at such time, and the amount of Partnership Liabilities. The General Partner may allocate such aggregate value among the individual properties of the Partnership (in such manner as it determines appropriate). Absent a contrary determination by the General Partner, the aggregate fair market value of all Partnership assets (including cash or cash equivalents) immediately prior to a Revaluation Event shall be the value that would result in the Capital Account for each Common Unit that is Outstanding prior to such Revaluation Event being equal to the Event Issue Value.

(ii) In accordance with Treasury Regulation Sections 1.704-1(b)(2)(iv)(f) and 1.704-1(b)(2)(h)(2), immediately prior to any distribution to a Partner of any Partnership property (other than a distribution of cash that is not in redemption or retirement of a Partnership Interest), the Carrying Value of all Partnership property shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property. In determining such Unrealized Gain or Unrealized Loss the aggregate fair market value of all Partnership property (including cash or cash equivalents) immediately prior to a distribution shall (A) in the case of a distribution other than one made pursuant to Section 12.4, be determined in the same manner as that provided in Section 5.6(d)(i) or (B) in the case of a liquidating distribution pursuant to Section 12.4, be determined by the Liquidator using such method of valuation as it may adopt.

(f) Article V of the Partnership Agreement is hereby amended to add a new Section 5.14 creating a new class of Units as follows:

“Section 5.14 Establishment of Class D Units.

(a) General. The General Partner hereby designates and creates a class of Units to be designated as “Class D Units” and initially consisting of a total of 770,000 Class D Units, and fixes the designations, preferences and relative, participating, optional or other special rights, powers and duties of holders of the Class D Units as set forth in this Section 5.14. The initial Capital Account balance in respect of each Class D Unit shall be zero.

(b) Rights of Class D Units. With respect to each Class D Unit, during the period commencing upon issuance of such Class D Unit and ending on its Class D Unit Conversion Effective Date:

(i) Allocations.

(A) Allocations of Net Income. Net Income allocated pursuant to Section 6.1(a) shall be allocated to a Class D Unit to the same extent as such Net Income would be so allocated if such Class D Unit were a Common Unit that was then Outstanding.

 

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(B) Allocations of Net Losses. Notwithstanding anything to the contrary in Section 6.1(b), a Class D Unit shall not receive any allocation of Net Loss pursuant to Section 6.1(b).

(C) Allocations of Unrealized Gain. Notwithstanding anything to the contrary in Section 6.1(c), Unrealized Gain shall be allocated to a Class D Unit prior to its Class D Unit Conversion Effective Date as follows:

(1) Prior to any allocations of Net Termination Gain or Net Termination Loss to the Partners pursuant to Section 6.1(c), Unrealized Gain shall first be allocated to the Class D Units until the deficit balance in each Class D Unit, if any, has been eliminated.

(2) Upon or following the occurrence of each Class D Unit Conversion Date or an Accelerated Class D Unit Conversion Date, and provided that, with respect to a Class D Unit Conversion Date, the holder of the Class D Unit was in Good Standing, the Partnership shall allocate Unrealized Gain to such holder of Class D Units, prior to any allocations of Net Termination Gain or Net Termination Loss to the other Partners pursuant to Section 6.1(c), until the Capital Account of each Class D Unit eligible to be converted on such Class D Unit Conversion Date or Accelerated Class D Unit Conversion Date is equal to the Per Unit Capital Amount for a then Outstanding Common Unit. If the Unrealized Gain allocated as a result of this Section 5.14(b)(i)(C)(2) is not sufficient to cause the Capital Account of each Class D Unit eligible to be converted into a Common Unit to equal the Per Unit Capital Account of a then Outstanding Common Unit, such Unrealized Gain shall be allocated to such Class D Units in a manner so as to allow for the greatest number of Class D Units to be converted into Common Units without issuing fractional units and the conversion of any remaining Class D Units having a Capital Account less than the Per Unit Capital Account of a then Outstanding Common Unit shall be deferred until the date on which sufficient Unrealized Gain is available and can be allocated to such remaining Class D Units pursuant to this Section 5.14(b)(i)(C)(2).

(D) Allocations of Net Termination Gain. Notwithstanding anything to the contrary in Section 6.1(c)(i), a Class D Unit shall not receive any allocation pursuant to Section 6.1(c)(i).

(E) Allocations of Net Termination Loss. Notwithstanding anything to the contrary in Section 6.1(c)(ii), a Class D Unit shall not receive any allocation pursuant to Section 6.1(c)(ii).

(E) Corrective Allocations. In the case of any allocation of Additional Book Basis Derivative Items consisting of depreciation, amortization or any other form of cost recovery, the Partnership shall apply a “keep your own” methodology with respect to the Class D Units prior to its Class D Unit Conversion Effective Date and allocate such items as provided in Section 6.1(d)(xi).

(F) Protective Allocation. In the event it is subsequently determined by a taxing authority that the Partnership was entitled to a deduction or expense upon the issuance of a Class D Unit, such deduction or expense, or, if unavailable, other items of Partnership deduction or expense of equal amount, shall be allocated to the Class D Unit that gave rise to such Partnership deduction or expense, such allocation having been made in the period in which such Class D Units were issued, in order to accurately reflect the economic entitlement of the Partners holding Common Units as reflected in their Capital Accounts.

(ii) Distributions.

(A) General. Except as otherwise provided in this Agreement, the Class D Units shall have the right to share in Partnership distributions on a pro rata basis with the Common Units so that the amount of any Partnership distribution to each Class D Unit will equal the amount of such distribution to each Common Unit.

 

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(B) Catch-Up Distribution. Each Class D Unit may be entitled to a catch-up distribution equal to the aggregate distributions that were previously made to a Common Unit for one or more quarters of the calendar year in which the Class D Units were issued. The right of a holder of Class D Units to a distribution pursuant to this Section 5.14(b)(ii)(B) shall be set forth in an agreement between the Partnership and such holder of a Class D Unit. Such distribution, if applicable, shall be made within one (1) Business Day of the issuance of Class D Units to such holder.

(C) Requirement of Good Standing. The General Partner may enter into a separate agreement with a holder of a Class D Unit setting forth certain conditions affecting the rights of such holder of a Class D Unit. Such agreement shall specifically reference this section and establish the conditions upon which a holder of a Class D Unit is determined to be in Good Standing. In the event the holder of a Class D Unit fails to satisfies the conditions of Good Standing as set forth in such an agreement (unless cured pursuant to the terms of such separate agreement), such holder of a Class D Unit shall cease to have any right to distributions with respect to such holder’s Class D Units. For the avoidance of doubt, a requirement of Good Standing shall only affect the right to distributions with respect to the holder’s Class D Units and will not affect the holder’s right to distributions with respect to Common Units the holder may hold, including Common Units received as a result of the prior conversion of Class D Units, or any other Partnership Securities held by the holder.

(D) Notwithstanding anything in this Section 5.14(b)(ii) to the contrary, with respect to Class D Units that are converted into Common Units, the holder thereof shall not be entitled to a Class D Unit distribution and a Common Unit distribution with respect to such Units for the same period, but shall be entitled only to the distribution to be paid based upon the class of Units held as of the close of business on the Record Date for the distribution in respect of such period.

(iii) Conversion. Subject to a requirement of Good Standing as may be set forth in an agreement between the Partnership and a holder of Class D Units, the Class D Units shall convert into Common Units upon a Class D Unit Conversion Date (or, if applicable, an Accelerated Class D Unit Conversion Date) as defined in an agreement between the Partnership and the holder of Class D Units. Notwithstanding the foregoing, the conversion of a Class D Unit into a Common Unit shall not occur until the Class D Unit Conversion Effective Date of such Class D Unit.

(iv) Voting Rights. The Class D Units will have such voting rights pursuant to the Partnership Agreement as such Class D Units would have if they were Common Units that were then Outstanding, except that the Class D Units shall be entitled to vote as a separate class on any matter that adversely affects the rights or preferences of the Class D Units in relation to other classes of Partnership Interests or as required by law. The approval of a majority of the Class D Units shall be required to approve any matter for which the holders of the Class D units are entitled to vote as a separate class. Each Class D Unit will be entitled to the number of votes equal to the number of Common Units into which a Class D Unit is convertible at the time of the record date for the vote or written consent on the matter.

(v) Certificates.

(A) The Class D Units will be evidenced by certificates in such form as the General Partner may approve. Unless and until the General Partner determines to assign the responsibility to another Person, the General Partner will act as the register and transfer agent for the Class D Units. The certificates evidencing Class D Units shall be separately identified and shall not bear the same CUSIP number as the certificates evidencing Common Units.

(B) The certificate(s) representing the Class D Units may be imprinted with a legend in substantially the following form (in addition to the legend required pursuant to Section 4.7(e)):

“THESE SECURITIES HAVE NOT BEEN REGISTERED WITH THE SECURITIES AND EXCHANGE COMMISSION OR THE SECURITIES COMMISSION OF ANY STATE IN RELIANCE UPON AN EXEMPTION FROM REGISTRATION UNDER THE SECURITIES ACT OF 1933, AS AMENDED (THE “SECURITIES ACT”) AND ARE SUBJECT TO THE TERMS OF THE THIRD AMENDED AND RESTATED LIMITED PARTNERSHIP

 

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AGREEMENT OF ENERGY TRANSFER EQUITY, L.P., AS AMENDED. THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF ENERGY TRANSFER EQUITY, L.P. THAT THIS SECURITY MAY NOT BE TRANSFERRED, SOLD, ASSIGNED, PLEDGED OR OTHERWISE ALIENATED WITHOUT THE WRITTEN CONSENT OF LE GP, LLC, THE GENERAL PARTNER OF ENERGY TRANSFER EQUITY, L.P.”

(vi) Limitations on Transfer. Except as otherwise may be set forth in a separate agreement with a holder of a Class D Unit, no Class D Unit may be transferred, sold, assigned, pledged or otherwise alienated without the written consent of the General Partner.

(vii) Splits and Combinations. In the event the Partnership, while any Class D Units are Outstanding, (a) makes a distribution on its Common Units in Common Units, (b) subdivides or splits its Common Units into a greater number of Common Units, or (c) combines or reclassifies its Common Units into a smaller number of Common Units, a corresponding distribution, subdivision, split, combination, or reclassification of the Class D Units shall automatically occur with respect to the Class D Units, or such other appropriate adjustment to the Class D Units shall be made as determined by the General Partner, so that the number of Class D Units Outstanding immediately after such split or combination of the Common Units equals the number determined by multiplying the number of Class D Units Outstanding immediately prior to such split or combination of the Common Units by a fraction, (i) the numerator of which shall be the number of Common Units Outstanding immediately following such split or combination and (ii) the denominator of which shall be the number of Common Units Outstanding immediately prior to such split or combination.

(g) The first sentence of Section 6.1 of the Partnership Agreement is hereby amended and restated to read in its entirety as follows:

“For purposes of maintaining Capital Accounts and in determining the rights of the Partners among themselves, the Partnership’s items of income, gain, loss and deduction (computed in accordance with Section 5.6(b)) shall be allocated (subject to Section 5.14(b)) among the Partners in each taxable year (or portion thereof) as provided herein below.”

(h) Section 6.1(d)(xi) of the Partnership Agreement is hereby amended and restated to read in its entirety as follows:

“(xi) Corrective and Other Allocations. In the event of any allocation of Additional Book Basis Derivative Items or a Net Termination Loss, the following rules shall apply:

(A) The General Partner shall allocate Additional Book Basis Derivative Items consisting of depreciation, amortization or any other form of cost recovery (other than Additional Book Basis Derivative Items included in Net Termination Gain or Net Termination Loss) with respect to any Adjusted Property to the Class D Units, Pro Rata, in the same proportion as Unrealized Gain resulting from the Revaluation Event that gave rise to such Additional Book Basis Derivative Items was allocated to the Class D Units pursuant to Section 5.14(b)(i)(C).

(B) If a sale or other taxable disposition of an Adjusted Property, including, for this purpose, inventory (“Disposed of Adjusted Property”) occurs other than in connection with an event giving rise to Net Termination Gain or Net Termination Loss, the General Partner shall allocate (1) items of gross income and gain (x) away from the Class D Units and (y) to the Partners (other than holders of Class D Units to the extent of their Class D Units), or (2) items of deduction and loss (x) away from the Partners (other than holders of Class D Units to the extent of their Class D Units) and (y) to the Class D Units, to the extent that the Additional Book Basis Derivative Items with respect to the Disposed of Adjusted Property (determined in accordance with the last sentence of the definition of Additional Book Basis Derivative Items) treated as having been allocated to the Partners (other than holders of Class D Units to the extent of their Class D Units) pursuant to this Section 6.1(d)(xi)(B) exceed their Share of Additional Book Basis Derivative Items with respect to such Disposed of Adjusted Property. For purposes of this Section 6.1(d)(xi)(B), the Partners (other than holders of Class D Units to the extent of their Class D Units) shall be treated as having been allocated Additional Book Basis Derivative Items to the extent that such Additional Book Basis Derivative Items have reduced the amount of income that would otherwise

 

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have been allocated to such Partners under the Partnership Agreement (e.g., Additional Book Basis Derivative Items taken into account in computing cost of goods sold would reduce the amount of book income otherwise available for allocation among such Partners). Any allocation made pursuant to this Section 6.1(d)(xi)(B) shall be made after all of the other Agreed Allocations have been made as if this Section 6.1(d)(xi) were not in this Agreement and, to the extent necessary, shall require the reallocation of items that have been allocated pursuant to such other Agreed Allocations.

(C) Net Termination Loss in an amount equal to the lesser of (1) such Net Termination Loss and (2) the Aggregate Remaining Net Positive Adjustments shall be allocated in such manner as is determined by the General Partner that, to the extent possible, the Capital Account balances of the Partners will equal the amount they would have been had no prior Book-Up Events occurred, and any remaining Net Termination Loss (and the case of the Class D Units, Unrealized Gain) shall be allocated pursuant to Sections 5.14(b)(i)(C) and 6.1(c). In allocating Net Termination Loss pursuant to this Section 6.1(d)(xi)(C), the General Partner shall attempt, to the extent possible, to cause the Capital Accounts of the Partners (other than holders of Class D Units to the extent of their Class D Units), on the one hand, and the Class D Units, on the other hand, to equal the amount they would equal if (i) the Carrying Values of the Partnership’s property had not been previously adjusted in connection with any prior Book-Up Events, (ii) Unrealized Gain and Unrealized Loss (or, in the case of a liquidation, actual gain or loss) with respect to such Partnership property were determined with respect to such unadjusted Carrying Values, and (iii) any resulting Net Termination Gain (and the case of the Class D Units, Unrealized Gain) had been allocated pursuant to Sections 5.14(b)(i)(C) and 6.1(c).

(D) In making the allocations required under this Section 6.1(d)(xi), the General Partner may apply whatever conventions or other methodology it determines will satisfy the purpose of this Section 6.1(d)(xi). Without limiting the foregoing, if an Adjusted Property is contributed by the Partnership to another entity classified as a partnership for U.S. federal income tax purposes (the “lower tier partnership”), the General Partner may make allocations similar to those described in Sections 6.1(d)(xi)(A), (B), and (C) to the extent the General Partner determines such allocations are necessary to account for the Partnership’s allocable share of income, gain, loss and deduction of the lower tier partnership that relate to the contributed Adjusted Property in a manner that is consistent with the purpose of this Section 6.1(d)(xi).”

(i) Article VI is hereby amended to add a new Section 6.7 as follows:

“Section 6.7 Special Provisions Relating to the Holders of Class D Units.

(a) A Unitholder holding a Common Unit that derived from a Class D Unit pursuant to Section 5.14 shall not be issued a Common Unit Certificate, and shall not be permitted to transfer such Common Units until such time as the General Partner determines, based on advice of counsel, that the converted Class D Unit should have, as a substantive matter, like intrinsic economic and federal income tax characteristics of an Initial Common Unit. In connection with the condition imposed by this Section 6.7, the General Partner shall take whatever steps are required to provide economic uniformity to the converted Class D Units in preparation for a transfer of such Units; provided, however, that no steps may be taken that would have a material adverse effect on the Unitholders holding Common Units represented by Common Unit Certificates (for this purpose the allocations of Unrealized Gain with respect to Class D Units pursuant to Section 5.14(b)(i)(C)(2) will be deemed not to have a material adverse effect on the Unitholders holding Common Units).

(b) Notwithstanding anything to the contrary set forth in this Agreement, the holders of the Class D Units (a) shall (i) possess the rights, preferences and privileges and the duties and obligations provided in this Agreement with respect to a Limited Partner pursuant to Article III and Article VII, (ii) have a Capital Account as a Partner pursuant to Section 5.6 and all other provisions related thereto and be entitled to vote on any matters requiring the approval of the holders of Outstanding Units, and (b) shall not (i) be entitled to any distributions other than as provided in Section 5.14, Article VI or Article XII or (ii) be allocated items of income, gain, loss or deduction other than as specified in Section 5.14 or Article VI.

(j) Section 12.8 of the Partnership Agreement is hereby amended and restated to read in its entirety as follows:

 

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“Section 12.8 Capital Account Restoration. “No Partner shall have any obligation to restore any negative balance in its Capital Account upon liquidation of the Partnership except to the extent the holder has a negative Capital Account balance with respect to a Class D Unit. Any Partner with a negative Capital Account balance with respect to a Class D Unit shall have an obligation to restore such negative Class D Unit Capital Account balance upon liquidation of the Partnership.”

Section 2. Ratification of Partnership Agreement. Except as expressly modified and amended herein, all of the terms and conditions of the Partnership Agreement shall remain in full force and effect.

Section 3. Governing Law. This Amendment will be governed by and construed in accordance with the laws of the State of Delaware.

Section 4. Counterparts. This Amendment may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart.

 

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IN WITNESS WHEREOF, this Amendment has been executed as of the date first written above.

 

GENERAL PARTNER:
LE GP, LLC
By:  

/s/ John W. McReynolds

  John W. McReynolds
  President
LIMITED PARTNERS :
All Limited Partners now and hereafter admitted as limited partners of the Partnership, pursuant to the Powers of Attorney now and hereafter executed in favor of, and granted and delivered to, the General Partner.
By:   LE GP, LLC, General Partner of Energy Transfer Equity, L.P., as attorney-in-fact for all Limited Partners pursuant to the powers of Attorney granted pursuant to Section 2.6 of the Partnership Agreement.
By:  

/s/ John W. McReynolds

  John W. McReynolds
  President

 

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EX-3.8

Exhibit 3.8

AMENDMENT NO. 5

TO

THIRD AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP

OF

ENERGY TRANSFER EQUITY, L.P.

This Amendment No. 5 (this “ Amendment ”) to the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., a Delaware limited partnership (the “ Partnership ”), dated as of February 8, 2006 (as amended, the “ Partnership Agreement ”), is entered into effective as of March 8, 2016 by LE GP, LLC, a Delaware limited liability company (the “ General Partner ”), as the general partner of the Partnership, on behalf of itself and the Limited Partners of the Partnership. Capitalized terms used but not defined herein are used as defined in the Partnership Agreement.

RECITALS

WHEREAS, Section 5.8 of the Partnership Agreement provides that the General Partner, without the approval of any Limited Partner except as otherwise provided in the Partnership Agreement, may, for any Partnership purpose, at any time or from time to time, issue additional Partnership Securities to such Persons for such consideration and on such terms and conditions as the General Partner shall determine in its sole discretion;

WHEREAS, Section 13.1(g) of the Partnership Agreement provides that the General Partner, without the approval of any Partner, may amend any provision of the Partnership Agreement to reflect an amendment that the General Partner determines is necessary or appropriate in connection with the authorization of issuance of any class or series of Partnership Securities pursuant to Section 5.8 of the Partnership Agreement;

WHEREAS, Section 13.1(d)(i) of the Partnership Agreement provides that the General Partner, without the approval of any Partner, may amend any provision of the Partnership Agreement to reflect a change that the General Partner determines does not adversely affect the Limited Partners (including any particular class of Partnership Interests as compared to other classes of Partnership Interests) in any material respect;

WHEREAS, in accordance with Section 4(a)(2) of the Securities Act of 1933, as amended (the “ Securities Act ”), and Rule 506 of Regulation D, the Partnership is offering to certain holders of Common Units who are “accredited investors” (as defined in Regulation D promulgated under the Securities Act) the right to participate in a plan (the “ Plan ”) that will allow such holders to make a one-time election to forgo certain distributions on some or all of their Common Units for a period of up to nine Quarters commencing with distributions for the Quarter ending March 31, 2016, and reinvest those distributions in Series A Convertible Preferred Units (the “ Series A Convertible Units ”), a new class of Units representing limited partner interests in the Partnership that are convertible into Common Units on the Convertible Unit Conversion Date (as defined below), all as more fully described in this Amendment and in the Partnership’s Confidential Private Placement Memorandum dated February 29, 2016 relating to the Plan and the Series A Convertible Units and the Common Units to be issued upon conversion thereof;

WHEREAS, the Conflicts Committee of the Board of Directors of the General Partner (the “ Board ”), by unanimous vote, in good faith, (a) approved the Plan and the issuance of the Series A Convertible Units pursuant to the Plan and (b) resolved to recommend to the Board the approval of the Plan and the issuance of the Series A Convertible Units pursuant to the Plan;

WHEREAS, the foregoing approval of the Plan and the issuance of the Series A Convertible Units pursuant to the Plan by the Conflicts Committee constitutes Special Approval for all purposes under the Partnership Agreement, including but not limited to Section 7.9 thereof;

 

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WHEREAS, the Audit and Conflicts Committee (as defined in the Amended and Restated Limited Liability Company Agreement of LE GP, LLC, dated as of May 7, 2007 (as amended to date, the “ Company Agreement ”)), in good faith, (a) approved the Plan and the issuance of the Series A Convertible Units pursuant to the Plan and (b) resolved to recommend to the Board the approval of the Plan and the issuance of the Series A Convertible Units pursuant to the Plan;

WHEREAS, the foregoing approval of the Plan and the issuance of the Series A Convertible Units pursuant to the Plan by the Audit and Conflicts Committee constitutes Special Approval (as defined in the Company Agreement) for purposes under the Company Agreement;

WHEREAS, the Board, for and on behalf of the General Partner, acting in its individual capacity and in its capacity as general partner of the Partnership, has determined that the Plan, including the creation and issuance of the Series A Convertible Units, is in the best interests of the Partnership and beneficial to the Limited Partners, including the holders of Common Units, and has approved the Plan and the issuance of the Series A Convertible Units pursuant to the Plan;

WHEREAS, the issuance of the Series A Convertible Units complies with the requirements of the Partnership Agreement;

WHEREAS, the General Partner has determined, pursuant to Section 13.1(g) of the Partnership Agreement, that the amendments to the Partnership Agreement set forth herein are necessary or appropriate in connection with the authorization of issuance of the Series A Convertible Units; and

WHEREAS, the General Partner has determined, pursuant to Section 13.1(d)(i) of the Partnership Agreement, that, if and to the extent any amendments set forth herein are not necessary or appropriate in connection with the authorization of the issuance of the Series A Convertible Units, such amendments to the Partnership Agreement set forth herein do not adversely affect the Limited Partners (including any particular class of Partnership Interests as compared to other classes of Partnership Interests) in any material respect.

NOW, THEREFORE, the Partnership Agreement is hereby amended as follows:

Section 1. Amendments.

(a) Section 1.1 of the Partnership Agreement is hereby amended to add or amend and restate the following definitions:

As-Converted Basis ” means, with respect to each Series A Convertible Unit on any date of determination, as if the Convertible Unit Conversion Date had occurred on such date and such Series A Convertible Unit had converted into Common Units based on the Conversion Value and Conversion Price as of such date in accordance with Section 5.15(b)(iii).

Change of Contro l ” means (i) any “person” or “group” of related persons (as such terms are used in Sections 13(d) and 14(d) of the Securities Exchange Act), other than one or more Permitted Holders, is or becomes the beneficial owner (as defined in Rules 13d-3 and 13d-5 under the Securities Exchange Act, except that such person or group shall be deemed to have “beneficial ownership” of all shares that any such person or group has the right to acquire, whether such right is exercisable immediately or only after the passage of time), directly or indirectly, of more than 50% of the Voting Stock of the Partnership or the General Partner (or their respective successors by merger, consolidation or purchase of all or substantially all of their respective assets) or (ii) the sale, lease, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the assets of the Partnership and its Subsidiaries taken as a whole to any Person other than a Permitted Holder.

Common Unit Threshold ” means a number of Common Units equal to the quotient of $1,000,000,000 and the closing price of the Common Units on the New York Stock Exchange on the Series A Convertible Unit Issue Date.

 

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Conversion Price ” has the meaning set forth in Section 5.15(b)(iii).

Conversion Value ” means, with respect to each Series A Convertible Unit, as of any date of determination, the dollar value of the sum of (a) the aggregate amount of the Initial Period Accretion Amounts and (b) the aggregate amount of the Subsequent Period Accretion Amounts, in each case during the period commencing on the Series A Convertible Unit Issue Date and ending on the date of determination.

Conversion Value Cap ” means $0.285.

Converted Common Units ” means Common Units issued upon the conversion of the Series A Convertible Units on the Convertible Unit Conversion Date.

Convertible Unit Conversion Date ” has the meaning set forth in Section 5.15(b)(iii).

ETC ” means Energy Transfer Corp LP, a Delaware limited partnership, and any successors thereto.

Extraordinary Distributions ” means (a) any non-cash distribution or (b) any cash distribution that is materially and substantially greater, on a per unit basis, than the Partnership’s most recent regular quarterly distribution, as determined by the General Partner.

Initial Quarter ” has the meaning set forth in Section 6.3(e).

Initial Period Accretion Amount ” has the meaning set forth in Section 5.15(b)(ii).

Limited Partner Interest ” means the ownership interest of a Limited Partner or Assignee in the Partnership, which may be evidenced by Common Units, Series A Convertible Units or other Partnership Securities or a combination thereof or interest therein, and includes any and all benefits to which such Limited Partner or Assignee is entitled as provided in this Agreement, together with all obligations of such Limited Partner or Assignee to comply with the terms and provisions of this Agreement.

Memorandum ” means the Partnership’s Confidential Private Placement Memorandum dated February 29, 2016 relating to the Plan and the Series A Convertible Units and the Converted Common Units, including the Election Form and Letter of Transmittal, the form of which is attached as Annex A to the Memorandum.

Merger Closing Date ” means the closing date of the Williams Merger.

Merger Termination Date ” means the date of termination of the Williams Merger Agreement.

Participating Common Units ” means each Common Unit for which a Plan Offeree makes a valid election (and does not validly revoke such election) to participate in the Plan in accordance with, and subject to the terms of, the Memorandum.

Partnership Security ” means any class or series of equity interest in the Partnership (but excluding any options, rights, warrants and appreciation rights relating to an equity interest in the Partnership) and General Partner Units and any General Partner Interest represented thereby, including without limitation, Common Units and Series A Convertible Units.

Permitted Holders ” means (i) any of Kelcy L. Warren, his heirs at law, entities or trusts owned by or established for the benefit of such individual or his heirs at law (such as entities or trusts established for estate planning purposes), (ii) the MLP or any other Person under the management or control of the MLP, (iii) ETC or any other Person under the management or control of ETC and (iv) the General Partner and entities owned solely by existing and former management employees of the General Partner.

 

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Plan ” means the plan of the Partnership pursuant to which a Plan Offeree may make a one-time election to forgo certain distributions on some or all of their Common Units for a period of up to nine Quarters commencing with distributions for the Quarter ending March 31, 2016, and reinvest those distributions in Series A Convertible Units, all as more fully described in the Memorandum.

Plan Offeree ” means any Unitholder who has been provided the opportunity to participate in the Plan in accordance with, and subject to, the terms of the Memorandum.

Record Holder ” means the Person in whose name a Common Unit is registered on the books of the Transfer Agent as of the opening of business on a particular Business Day, or with respect to other Partnership Interests, including without limitation any Series A Convertible Units, the Person in whose name any such other Partnership Interest is registered on the books of the Transfer Agent or the books that the General Partner has caused to be kept, as the case may be, as of the opening of business on such Business Day.

Series A Convertible Units ” means the series of Units designated as Series A Convertible Preferred Units pursuant to Section 5.15.

Series A Convertible Unit Distribution Amount ” means $0.11 per Unit.

Series A Convertible Unit Issue Date ” means the date the Series A Convertible Units are issued.

Subsequent Quarter ” has the meaning set forth in Section 6.3(f).

Subsequent Period Accretion Amount ” has the meaning set forth in Section 5.15(b)(ii).

Unit ” means a Partnership Security that is designated as a “Unit” and shall include Common Units and Series A Convertible Units but shall not include General Partner Units (or the General Partner Interest represented thereby).

Unit Majority ” means at least a majority of the Outstanding Common Units and Outstanding Series A Convertible Units, in each case if applicable, voting together as a single class and on an As-Converted Basis.

Voting Stock ” of any Person as of any date means, with respect to any Person (other than a general or limited partnership), the equity interests of such Person pursuant to which the holders thereof have the general voting power under ordinary circumstances to elect at least a majority of the board of directors or other governing body of such Person (regardless of whether, at the time, equity interests of any other class or classes shall have, or might have, voting power by reason of the occurrence of any contingency) or, with respect to a partnership (whether general or limited), any general partner interest in such partnership.

Williams ” means The Williams Companies, Inc., a Delaware corporation.

Williams Merger ” means the merger of Williams with and into ETC pursuant to the Williams Merger Agreement.

Williams Merger Agreement ” means that certain Agreement and Plan of Merger dated as of September 28, 2015 among ETC, ETC Corp GP, LLC, the Partnership, the General Partner, Energy Transfer Equity GP, LLC and Williams.

(b) Section 1.1 of the Partnership Agreement is hereby further amended to add the following sentence to the end of the definition of “Common Unit”:

“The term “Common Unit” does not refer to a Series A Convertible Unit prior to the conversion of such Unit into a Common Unit pursuant to the terms hereof.”

 

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(c) Article V of the Partnership Agreement is hereby amended to add a new Section 5.15 creating a new class of Units as follows:

“Section 5.15 Establishment of Series A Convertible Units.

(a) General. The General Partner hereby designates and creates a class of Units to be designated as “Series A Convertible Preferred Units,” and fixes the designations, preferences and relative, participating, optional or other special rights, powers and duties of holders of the Series A Convertible Units as set forth in this Section 5.15. Upon their issuance in accordance with the terms of the Plan, and in consideration of the agreement by the holders of Participating Common Units to forgo certain distributions with respect to such Participating Common Units in accordance with the Plan, the Series A Convertible Units will be fully paid.

(b) Rights of Series A Convertible Units. The Series A Convertible Units shall have the following rights, preferences and privileges and shall be subject to the following duties and obligations:

(i) Allocations. For each calendar year during the period commencing upon the Series A Convertible Unit Issue Date and ending on the Convertible Unit Conversion Date, for purposes of allocating items of Partnership income, gain, loss and deduction to each Series A Convertible Unit pursuant to this Agreement, each Series A Convertible Unit will be treated as a Common Unit, determined on an As-Converted Basis as of the last day of such calendar year.

(ii) Conversion Value. The Conversion Value of each Series A Convertible Unit as of the Series A Convertible Unit Issue Date shall be zero. For each Initial Quarter, the Conversion Value shall be increased by an amount equal to the Conversion Value Cap less the per unit cash distribution paid with respect to each Participating Common Unit (excluding any Extraordinary Distributions) (the amount of such increase in any Initial Quarter, an Initial Period Accretion Amount ). For each Subsequent Quarter, the Conversion Value shall be increased by an amount equal to the Conversion Value Cap less the per unit cash distribution paid with respect to each Series A Convertible Unit (excluding any Extraordinary Distributions) (the amount of such increase in any Subsequent Quarter, a Subsequent Period Accretion Amount ). For the avoidance of doubt, the payment of an Extraordinary Distribution with respect to an Initial Quarter or Subsequent Quarter will not increase or decrease the Conversion Value of the Series A Convertible Units.

(iii) Conversion. Each Series A Convertible Unit shall convert into Common Units as described below on the first Business Day following the earliest to occur of (A) May 18, 2018; (B) the first date upon which the Series A Convertible Units would beconvertible into a number of Common Units that equals the Common Unit Threshold; (C) the date of a Change of Control of the Partnership and (D) the date of dissolution of the Partnership (such earliest date, the “ Convertible Unit Conversion Date ”). On the Convertible Unit Conversion Date, each Series A Convertible Unit shall be converted into a number of Common Units determined by dividing the Conversion Value by a price (the “ Conversion Price ”) equal to $6.56. No fractional units shall be issued upon conversion of the Series A Convertible Units but cash will be paid in lieu of fractional units based on the five-day volume weighted average closing price of the Common Units on the National Securities Exchange on which the Common Units are listed immediately prior to the Convertible Unit Conversion Date.

(iv) Voting Rights. The Series A Convertible Units will have such voting rights under this Agreement as such Series A Convertible Units would have on an As-Converted Basis, except that the Series A Convertible Units shall be entitled to vote as a separate class on any matter that adversely affects the rights or preferences of the Series A Convertible Units in relation to other classes of Partnership Interests or as required by law. The approval of a majority of the Series A Convertible Units shall be required to approve any matter for which the holders of the Series A Convertible Units are entitled to vote as a separate class. The Series A Convertible Units will be entitled to vote together as a single class with the Common Units on an As-Converted Basis on any matter for which the holders of Common Units are entitled to vote, with each Series A Convertible Unit entitled to the number of votes equal to the number of Common Units into which a Series A Convertible Unit is convertible at the time of the record date for the vote or written consent on the matter. Each reference in this Agreement to a vote of holders of Common Units shall be deemed to include the Series A Convertible Units on an As-Converted Basis.

 

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(v) Certificates; Book-Entry.

(A) Unless the General Partner shall determine otherwise, the Series A Convertible Units shall not be evidenced by certificates. Any certificates relating to the Series A Convertible Units that may be issued shall be in such form as the General Partner may approve. Any certificates evidencing Series A Convertible Units shall be separately identified and shall not bear the same CUSIP number as the certificates evidencing Common Units.

(B) Any certificate(s) evidencing the Series A Convertible Units and Converted Common Units may be imprinted with a legend in substantially the following form (in addition to the legend required pursuant to Section 4.7(e)):

“THESE SECURITIES HAVE NOT BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933, AS AMENDED, OR ANY STATE SECURITIES LAWS. THESE SECURITIES MAY NOT BE TRANSFERRED, SOLD, ASSIGNED, PLEDGED OR OTHERWISE DISPOSED OF UNTIL THE HOLDER THEREOF PROVIDES EVIDENCE SATISFACTORY TO THE GENERAL PARTNER (WHICH, IN THE DISCRETION OF THE GENERAL PARTNER, MAY INCLUDE AN OPINION OF COUNSEL SATISFACTORYTO THE GENERAL PARTNER) THAT SUCH TRANSFER, SALE, ASSIGNMENT, PLEDGE OR OTHER DISPOSITION WILL NOT VIOLATE APPLICABLE FEDERAL OR STATE SECURITIES LAWS. IN ADDITION, THESE SECURITIES ARE SUBJECT TO THE TERMS OF THE THIRD AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF ENERGY TRANSFER EQUITY, L.P., AS AMENDED, INCLUDING THE LIMITATIONS ON TRANSFER SET FORTH IN SECTION 5.15(b)(vi) THEREOF.”

(vi) Limitations on Transfer. No Series A Convertible Unit may be transferred, sold, assigned, pledged or otherwise alienated without the prior written consent of the General Partner.

(vii) Registrar and Transfer Agent. American Stock Transfer & Trust Company will act as the registrar and transfer agent for the Series A Convertible Units.

(viii) Splits and Combinations. For so long as any Series A Convertible Units are Outstanding, to the extent that the Partnership (A) makes a distribution on its Common Units in Common Units, (B) subdivides or splits its Common Units into a greater number of Common Units, or (C) combines or reclassifies its Common Units into a smaller number of Common Units, then the Conversion Value Cap, Conversion Price and Series A Convertible Unit Distribution Amount in effect immediately prior to the effective time of such distribution, subdivision, split, combination or reclassification shall each be proportionally adjusted by a fraction, (x) the numerator of which shall be the number of Common Units Outstanding immediately prior to such distribution, subdivision, split, combination or reclassification and (y) the denominator of which shall be the number of Common Units Outstanding immediately following such distribution, subdivision, split, combination or reclassification.

(ix) Liquidation. In the event of any dissolution of the Partnership, either voluntary or involuntary, the Series A Convertible Units shall automatically be converted into Common Units in accordance with Section 5.15(b)(iii) and shall be entitled to receive, out of the assets of the Partnership available for distribution to Unitholders, the positive value in each such holder’s Capital Account in accordance with Section 12.4.”

(d) The first sentence of Section 6.1 of the Partnership Agreement is hereby amended and restated to read in its entirety as follows:

“For purposes of maintaining Capital Accounts and in determining the rights of the Partners among themselves, the Partnership’s items of income, gain, loss and deduction (computed in accordance with Section 5.6(b)) shall be allocated (subject to Section 5.14(b) and Section 5.15(b)) among the Partners in each taxable year (or portion thereof) as provided herein below.”

 

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(e) Article VI is hereby amended to add a new Section 6.1(d)(xii) as follows:

“(xii) Series A Convertible Units and Cost Recovery Allocations. Notwithstanding any other provision of this Agreement to the contrary, for each calendar year in which the Series A Convertible Units are outstanding, prior to any allocations being made to the Common Units pursuant to this Agreement and prior to any allocations being made to the Series A Convertible Units pursuant to Section 5.15(b)(i), a holder of a Series A Convertible Unit shall be allocated depreciation, amortization, depletion or other cost recovery equal to the aggregate Initial Period Accretion Amounts and Subsequent Period Accretion Amounts attributable to such holder’s Series A Convertible Units for such calendar year.”

(f) Section 6.3 is hereby amended and restated to read in its entirety as follows:

“Section 6.3 Requirement and Characterization of Distributions; Distributions to Record Holders.

(a) Within 50 days following the end of each Quarter commencing with the Quarter ending on February 28, 2006, an amount equal to 100% of Available Cash with respect to such Quarter shall, subject to Section 17-607 of the Delaware Act, be distributed in accordance with this Article VI by the Partnership to the Partners as of the Record Date selected by the General Partner. All distributions required to be made under this Agreement shall be made subject to Section 17-607 of the Delaware Act.

(b) Notwithstanding Section 6.3(a), in the event of the dissolution and liquidation of the Partnership, all receipts received during or after the Quarter in which the Liquidation Date occurs shall be applied and distributed solely in accordance with, and subject to the terms and conditions of, Section 12.4.

(c) The General Partner may treat taxes paid by the Partnership on behalf of, or amounts withheld with respect to, all or less than all of the Partners, as a distribution of Available Cash to such Partners.

(d) Each distribution in respect of a Partnership Interest shall be paid by the Partnership, directly or through the Transfer Agent or through any other Person or agent, only to the Record Holder of such Partnership Interest as of the Record Date set for such distribution. Such payment shall constitute full payment and satisfaction of the Partnership’s liability in respect of such payment, regardless of any claim of any Person who may have an interest in such payment by reason of an assignment or otherwise.

(e) Subject to Section 6.3(g), for each Quarter as to which the declaration date and the Record Date for a Quarterly distribution with respect to the Common Units occurs (1) during the period commencing on the Series A Convertible Unit Issue Date and ending on the earlier to occur of (i) the Merger Termination Date and (ii) the Merger Closing Date (each, an “ Initial Quarter ”), and (2) for each Quarter as to which the declaration date and the Record Date for a Quarterly distribution with respect to the Common Units occurs after the Convertible Unit Conversion Date, Available Cash with respect to such Quarter shall be distributed to the General Partner and to the holders of the Common Units, in accordance with their respective Percentage Interests, until there has been distributed an amount equal to 100% of Available Cash.

(f) Subject to Section 6.3(g), for each Quarter as to which the declaration date and the Record Date for a Quarterly distribution with respect to the Common Units occurs during the period commencing on the earlier to occur of (i) the Merger Termination Date and (ii) the Merger Closing Date and ending on the Convertible Unit Conversion Date (each, a “ Subsequent Quarter ”), Available Cash with respect to such Subsequent Quarter shall be distributed:

(1) first, prior to any distributions being made to the holders of the Common Units and the General Partner, to the holders of the Series A Convertible Units, Pro Rata, until there has been distributed with respect to each Series A Convertible Unit an amount equal to the Series A Convertible Unit Distribution Amount; and

 

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(2) thereafter, to the holders of the Common Units and the General Partner, in accordance with their respective Percentage Interests, until there has been distributed an amount equal to 100% of Available Cash.

(g) Notwithstanding anything in this Sections 6.3 to the contrary, with respect to any Initial Quarter or Subsequent Quarter, any distribution constituting an Extraordinary Distribution shall be distributed to the General Partner and the holders of the Common Units and Series A Convertible Units, in accordance with their respective Percentage Interests, and on an As-Converted Basis.”

(g) Article VI is hereby amended to add a new Section 6.8 as follows:

“Section 6.8 Special Provisions Relating to the Holders of Series A Convertible Units.

(a) Notwithstanding anything to the contrary set forth in this Agreement, the holders of the Series A Convertible Units (i) shall (A) possess the rights, preferences and privileges and be subject to the duties and obligations provided in this Agreement with respect to a Limited Partner pursuant to Article III and Article VII and (B) have a Capital Account as a Partner pursuant to Section 5.6 and all other provisions related thereto and be entitled to vote on any matters requiring the approval of the holders of Outstanding Units, and (ii) shall not (A) be entitled to any distributions other than as provided in Section 5.15, Article VI or Article XII or (B) be allocated items of income, gain, loss or deduction other than as specified in Section 5.15 or Article VI.

(b) At the Convertible Unit Conversion Date, a holder of (i) a Participating Common Unit or (ii) a Converted Common Unit shall be allocated all or any portion of Partnership Unrealized Gain or Unrealized Loss, and thereafter, to the extent necessary, items of income, gain, loss or deduction such that the Per Unit Capital Amount with respect to each Common Unit referred to in clause (i) or clause (ii) above is equal to the Per Unit Capital Amount with respect to the Common Units (other than Participating Common Units) then outstanding.”

Section 2. Ratification of Partnership Agreement. Except as expressly modified and amended herein, all of the terms and conditions of the Partnership Agreement shall remain in full force and effect.

Section 3. Governing Law. This Amendment will be governed by and construed in accordance with the laws of the State of Delaware.

Section 4. Counterparts. This Amendment may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart.

Section 5. Severability. If any provision of this Amendment is or becomes invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions hereof, or of such provision in other respects, shall not be affected thereby.

 

 

8


IN WITNESS WHEREOF, this Amendment has been executed as of the date first written above.

 

GENERAL PARTNER:
LE GP, LLC
By:  

/s/ John W. McReynolds

  John W. McReynolds
  President
LIMITED PARTNERS:

All Limited Partners now and hereafter admitted as limited partners of the Partnership, pursuant to the Powers of Attorney now and hereafter executed in favor of, and granted and delivered to, the General Partner.

 

By:     LE GP, LLC, General Partner of Energy Transfer Equity, L.P., as attorney-in-fact for all Limited Partners pursuant to the Powers of Attorney granted pursuant to Section 2.6 of the Partnership Agreement.

By:  

/s/ John W. McReynolds

  John W. McReynolds
  President

[Signature Page to Amendment No. 5 to ETE Partnership Agreement]

EX-3.9

Exhibit 3.9

Execution Version

AMENDMENT NO. 6

TO

THIRD AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP

OF

ENERGY TRANSFER EQUITY, L.P.

This Amendment No. 6 (this “ Amendment ”) to the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., a Delaware limited partnership (the “ Partnership ”), dated as of February 8, 2006 (as amended, the “ Partnership Agreement ”), is entered into effective as of October 19, 2018 by LE GP, LLC, a Delaware limited liability company (the “ General Partner ”), as the general partner of the Partnership, on behalf of itself and the Limited Partners of the Partnership. Capitalized terms used but not defined herein are used as defined in the Partnership Agreement.

RECITALS

WHEREAS, Section 5.8 of the Partnership Agreement provides that the General Partner, without the approval of any Limited Partner except as otherwise provided in the Partnership Agreement, may, for any Partnership purpose, at any time or from time to time, issue additional Partnership Securities to such Persons for such consideration and on such terms and conditions as the General Partner shall determine in its sole discretion;

WHEREAS, Section 13.1(g) of the Partnership Agreement provides that the General Partner, without the approval of any Partner, may amend any provision of the Partnership Agreement to reflect an amendment that the General Partner determines is necessary or appropriate in connection with the authorization of issuance of any class or series of Partnership Securities pursuant to Section 5.8 of the Partnership Agreement;

WHEREAS, Section 13.1(d)(i) of the Partnership Agreement provides that the General Partner, without the approval of any Partner, may amend any provision of the Partnership Agreement to reflect a change that the General Partner determines does not adversely affect the Limited Partners (including any particular class of Partnership Interests as compared to other classes of Partnership Interests) in any material respect;

WHEREAS, Section 13.2 of the Partnership Agreement provides that no amendment of the definition of “Conflicts Committee” shall be effective without first obtaining Special Approval;

WHEREAS, it is proposed that, in connection with that certain Agreement and Plan of Merger (the “ Merger Agreement ”), dated as of August 1, 2018, by and among the Partnership, the General Partner, Streamline Merger Sub, LLC, a Delaware limited liability company and a wholly owned subsidiary of the Partnership (“ Merger Sub ”), Energy Transfer Partners, L.P., a Delaware limited partnership (“ ETP ”), and Energy Transfer Partners, L.L.C., a Delaware limited liability company and the general partner of the general partner of ETP (“ ETP LLC ”), pursuant to which Merger Sub will merge with and into ETP, with ETP surviving (the “ Merger ”), and in partial consideration for the waiver of the General Partner’s preemptive right under Section 5.9 of the Partnership Agreement with respect to the Common Units to be issued in connection with the Merger, the Partnership will issue Class A Units to the General Partner;

WHEREAS, the Conflicts Committee of the Board of Directors of the General Partner (the “ Board ”), by unanimous vote, in good faith, (a) approved the Merger and the other transactions contemplated by the Merger Agreement, including the issuance of the Class A Units, and (b) resolved to recommend to the Board the approval of the Merger and the issuance of the Class A Units;

 

1


WHEREAS, the foregoing approval of the Merger and the issuance of the Class A Units by the Conflicts Committee constitutes Special Approval for all purposes under the Partnership Agreement, including but not limited to Section 7.9 thereof;

WHEREAS, the Audit and Conflicts Committee (as defined in the Amended and Restated Limited Liability Company Agreement of LE GP, LLC, dated as of May 7, 2007 (as amended to date, the “ Company Agreement ”)), in good faith, (a) approved the Merger and the other transactions contemplated by the Merger Agreement, including the issuance of the Class A Units, and (b) resolved to recommend to the Board the approval of the Merger and the issuance of the Class A Units;

WHEREAS, the foregoing approval of the Merger and the issuance of the Class A Units by the Audit and Conflicts Committee constitutes Special Approval (as defined in the Company Agreement) for all purposes under the Company Agreement;

WHEREAS, the Board, for and on behalf of the General Partner, acting in its individual capacity and in its capacity as general partner of the Partnership, has determined that the Merger and the other transactions contemplated by the Merger Agreement, including the issuance of the Class A Units, is in the best interests of the Partnership and the unaffiliated holders of Common Units, and has approved the Merger and the issuance of the Class A Units;

WHEREAS, the issuance of the Class A Units complies with the requirements of the Partnership Agreement;

WHEREAS, the General Partner has determined, pursuant to Section 13.1(g) of the Partnership Agreement, that the amendments to the Partnership Agreement set forth herein are necessary or appropriate in connection with the authorization of issuance of the Class A Units; and

WHEREAS, the General Partner has determined, pursuant to Section 13.1(d)(i) of the Partnership Agreement, that, if and to the extent any amendments set forth herein are not necessary or appropriate in connection with the authorization of the issuance of the Class A Units, such amendments to the Partnership Agreement set forth herein do not adversely affect the Limited Partners (including any particular class of Partnership Interests as compared to other classes of Partnership Interests) in any material respect; and

WHEREAS, the Conflicts Committee has evaluated the proposed amendments to the definition of “Conflicts Committee” set forth herein and determined that such amendments are advisable, fair and reasonable to the Partnership and in the best interests of the Partnership and its unitholders other than the General Partner and its Affiliates and (ii) approved such amendments, with such approval intended to constitute Special Approval.

NOW, THEREFORE, the Partnership Agreement is hereby amended as follows:

Section 1. Amendments.

(a) Section 1.1 of the Partnership Agreement is hereby amended to add or amend and restate the following definitions:

Adjusted Capital Account” means, with respect to any Partner, the balance in such Partner’s Capital Account at the end of each taxable period of the Partnership after giving effect to the following adjustments:

(i) credit to such Capital Account any amounts which such Partner is (x) obligated to restore under the standards set by Treasury Regulation Section 1.704-1(b)(2)(ii)(c) or (y) deemed obligated to restore pursuant to the penultimate sentences of Treasury Regulation Sections 1.704-2(g)(1) and 1.704-2(i)(5); and

(ii) debit to such Capital Account the items described in Treasury Regulation Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5) and 1.704-1(b)(2)(ii)(d)(6).

 

2


The foregoing definition of Adjusted Capital Account is intended to comply with the provisions of Treasury Regulation Section 1.701-1(b)(2)(ii)(d) and shall be interpreted consistently therewith. The “Adjusted Capital Account” of a Partner in respect of any Partnership Interest (other than a Class A Unit) shall be the amount that such Adjusted Capital Account would be if such Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such Partnership Interest were first issued.

Capital Account ” means the capital account maintained for a Partner (other than with respect to a Class A Unit) pursuant to Section 5.6. The “ Capital Account ” of a Partner in respect of a General Partner Interest, a Common Unit or any other Partnership Interest (other than a Class A Unit) shall be the amount that such Capital Account would be if such General Partner Interest, Common Unit or other Partnership Interest were the only interest in the Partnership held by a Partner from and after the date on which such General Partner Interest, Common Unit or other Partnership Interest was first issued.

Class A Unit ” means a Partnership Security representing a fractional part of the Partnership Interests, and having the rights and obligations specified with respect to Class A Units in this Agreement.

Class A Unitholders ” means the holder or holders of the Class A Units.

Common Voting Security ” means any Partnership Security with voting rights that are pari passu with the Common Units, including without limitation the Class A Units.

Conflicts Committee ” means a committee of the Board of Directors of the General Partner composed entirely of one or more directors who are not (a) security holders, officers or employees of the General Partner, (b) officers, directors or employees of any Affiliate of the General Partner (other than members of the MLP GP Board so long as the Partnership directly or indirectly owns all of the outstanding equity interests in the MLP other than non-participating, non-convertiblepreferred securities of the MLP) or (c) holders of any ownership interest in the Partnership other than Common Units, and who also meet the independence standards required to serve on an audit committee of a board of directors established by the Securities Exchange Act and the rules and regulations of the Commission thereunder by the National Securities Exchange on which the Common Units are listed or admitted for trading.

Limited Partner Interest ” means the ownership interest of a Limited Partner or Assignee in the Partnership, which may be evidenced by Common Units, Class A Units or other Partnership Securities or a combination thereof or interest therein, and includes any and all benefits to which such Limited Partner or Assignee is entitled as provided in this Agreement, together with all obligations of such Limited Partner or Assignee to comply with the terms and provisions of this Agreement.

MLP ” means Energy Transfer Operating, L.P., or any successor thereto.

MLP GP Board ” means the board of directors or board of managers of the general partner of the MLP, or, if the general partner of the MLP is a limited partnership, the board of directors or board of managers of the general partner of the general partner of the MLP.

Partnership ” means Energy Transfer LP, a Delaware limited partnership.

Partnership Security ” means any class or series of equity interest in the Partnership (but excluding any options, rights, warrants and appreciation rights relating to an equity interest in the Partnership) and General Partner Units and any General Partner Interest represented thereby, including without limitation, Common Units and Class A Units.

Percentage Interest ” means, as of any date of determination, (a) as to the General Partner, the amount of its aggregate Capital Contributions to the Partnership divided by the aggregate Capital Contributions made to the Partnership by all Partners, (b) as to any Unitholder holding Units, the product obtained by multiplying (i) 100% less the percentage applicable to paragraphs (a) and (c) by (ii) the quotient obtained by dividing (A) the number of Units

 

3


held by such Unitholder by (B) the total number of all Outstanding Units, and (c) as to the holders of additional Partnership Securities issued by the Partnership in accordance with Section 5.8, the percentage established as a part of such issuance. The Percentage Interest with respect to a Class A Unit shall at all times be zero.

Unit ” means a Partnership Security that is designated as a “Unit” and shall include Common Units but shall not include General Partner Units (or the General Partner Interest represented thereby) or Class A Units.

Unitholders ” means the holders of Units and shall not include the Class A Unitholders.

Section 1.1 of the Partnership Agreement is hereby further amended to add the following sentence to the end of the definition of “Common Unit”:

“The term “Common Unit” shall not include a Class A Unit.”

(b) Section 2.2 of the Partnership Agreement is hereby amended and restated as follows:

Section 2.2 Name.

The name of the Partnership shall be “Energy Transfer LP”. The Partnership’s business may be conducted under any other name or names as determined by the General Partner, including the name of the General Partner. The words “Limited Partnership,” “LP,” “Ltd.” or similar words or letters shall be included in the Partnership’s name where necessary for the purpose of complying with the laws of any jurisdiction that so requires. The General Partner may change the name of the Partnership at any time and from time to time and shall notify the Limited Partners of such change in the next regular communication to the Limited Partners.

(c) Article V of the Partnership Agreement is hereby amended to add a new Section 5.16 creating a new class of Partnership Securities as follows:

“Section 5.16 Establishment of Class A Units.

(a) General. The General Partner hereby designates and creates a class of Partnership Securities to be designated as “Class A Units,” and fixes the designations, preferences and relative, participating, optional or other special rights, powers, duties and obligations of holders of the Class A Units as set forth in this Section 5.16. Upon their issuance, the Class A Units will be fully paid.

(b) Rights of Class A Units. The Class A Units shall have the following rights, preferences and privileges and shall be subject to the following duties and obligations:

(i) Voting Rights. Except as may be required by law, the Class A Units will be entitled to vote together as a single class with the Common Units on any matter for which the holders of Common Units are entitled to vote. Each reference in this Agreement to a vote of holders of Common Units shall be deemed to include the Class A Units. Each Class A Unit shall be entitled to one vote.

(ii) Economic Interests. The Class A Units shall represent Limited Partner Interests in the Partnership, and shall not be entitled to any distributions from the Partnership, except that, upon any liquidation, dissolution or winding up of the Partnership, the Class A Units in the aggregate shall be entitled to an aggregate distribution of $100 prior and in preference to any distribution of any assets of the Partnership to the holders of any other class or series of Partnership Securities. For the avoidance of doubt, each Class A Unitholder shall receive its pro rata share of such $100 based on the number of Class A Units outstanding at the time of any such liquidation, winding up or dissolution.

 

4


(iii) Certificates; Book-Entry. Unless the General Partner shall determine otherwise, the Class A Units shall not be evidenced by certificates. Any certificates relating to the Class A Units that may be issued shall be in such form as the General Partner may approve. Any certificates evidencing Class A Units shall be separately identified and shall not bear the same CUSIP number as the certificates evidencing Common Units.

(iv) Limitations on Transfer. No Class A Unit may, directly or indirectly, be transferred, sold, assigned, pledged or otherwise alienated by the General Partner (or indirectly by any member of LE GP, LLC) or any subsequent transferee, without the prior approval of the Conflicts Committee, other than to Kelcy Warren, Ray Davis or to any trust, family partnership or family limited liability company, the sole beneficiaries, partners or members of which are Kelcy Warren, Ray Davis or their respective relatives. Any transfer or purported transfer of Class A Units not made in accordance with this Section 5.16(b)(iv) shall be null and void.

(v) Registrar and Transfer Agent. The General Partner will act as the registrar and transfer agent for the Class A Units.

(vi) Splits and Combinations. For so long as any Class A Units are Outstanding, to the extent that the Partnership (A) makes a distribution on its Common Units or other Common Voting Security in Common Units or other Common Voting Security, (B) subdivides or splits its Common Units or other Common Voting Securities into a greater number of Common Units or other Common Voting Securities, or (C) combines or reclassifies its Common Units or other Common Voting Securities into a smaller number of Common Units or other Common Voting Securities, then the number of Class A Units shall be proportionally adjusted, and if necessary, additional Class A Units shall be issued to the Class A Unitholders, such that the number of Class A Units issued immediately after such distribution, subdivision, split, combination or reclassification shall represent the same voting interest as such Class A Units represented immediately prior to such distribution, subdivision, split, combination or reclassification.

(vii) Class A Unit Issuances.

(A) Initial Issuance. Effective on the date of this Amendment, the Partnership has issued [647,079,608] Class A Units to LE GP, LLC.

(B) Future Issuances. For so long as Kelcy Warren is an officer or director of the General Partner, if the Partnership issues any additional Common Units or any other Common Voting Security, the Partnership shall automatically issue, for no additional consideration, an additional number of Class A Units to the Class A Unitholders (and if more than one Class A Unitholder exists at such time, pro rata in accordance with their respective Class A Unit ownership at such time), necessary for each Class A Unitholder to maintain a voting interest with respect to such Class A Units that the Class A Units represent in relation to the aggregate voting interest of the Common Units and other Common Voting Securities immediately prior to such Common Unit or other Common Voting Security issuance. The provisions of this Section 5.16(b)(iv)(B) shall terminate at such time as Kelcy L. Warren ceases to be an officer or director of the General Partner; provided, that for the avoidance of doubt, all Class A Units Outstanding at such time shall be unchanged and remain outstanding.

(C) Except as set forth in this Section 5.16(b)(vii), there shall be no other issuances by the Partnership of Class A Units.

(viii) Allocations. The Class A Units shall not be entitled to receive any (1) allocations of Net Income pursuant to Section 6.1(a), (2) allocations of Net Losses pursuant to Section 6.1(b), (3) allocations of Net Termination Gains or Losses pursuant to Section 6.1(c), (4) special allocations pursuant to Section 6.1(d) or (5) allocations for tax purposes pursuant to Section 6.2. Allocations pursuant to Sections 6.1(a), 6.1(b), 6.1(c), 6.1(d) and 6.2 shall be made consistent with the facts that the Class A Units are not Units, and that the Class A Unitholders are not Unitholders and, therefore have no Percentage Interests with respect to their Class A Units.

(d) Section 13.3 of the Partnership Agreement is hereby amended to add the following new clause (f):

 

5


“(f) Notwithstanding anything to the contrary herein, without the approval of the holders of 66 2/3% of the Class A Units, the Partnership may not take any action that disproportionately or materially adversely affects the rights, preferences or privileges of the Class A Units or amend the terms of the Class A Units.”

Section 2. Ratification of Partnership Agreement. Except as expressly modified and amended herein, all of the terms and conditions of the Partnership Agreement shall remain in full force and effect.

Section 3. Governing Law. This Amendment will be governed by and construed in accordance with the laws of the State of Delaware.

Section 4. Counterparts. This Amendment may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart.

Section 5. Severability. If any provision of this Amendment is or becomes invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions hereof, or of such provision in other respects, shall not be affected thereby.

[ Signature Page Follows. ]

 

 

6


IN WITNESS WHEREOF, this Amendment has been executed as of the date first written above.

 

GENERAL PARTNER:
LE GP, LLC
By:  

/s/ John W. McReynolds

  John W. McReynolds
  President

 

LIMITED PARTNERS:
All Limited Partners now and hereafter admitted as limited partners of the Partnership, pursuant to the Powers of Attorney now and hereafter executed in favor of, and granted and delivered to, the General Partner.
By:   LE GP, LLC, General Partner of Energy Transfer Equity, L.P., as attorney-in-fact for all Limited Partners pursuant to the Powers of Attorney granted pursuant to Section 2.6 of the Partnership Agreement.
By:  

/s/ John W. McReynolds

  John W. McReynolds
  President

SIGNATURE PAGE TO

AMENDMENT NO. 6 TO

THIRD AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF

ENERGY TRANSFER EQUITY, L.P.

EX-3.10

Exhibit 3.10

AMENDMENT NO. 7

TO

THIRD AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP

OF

ENERGY TRANSFER LP

This Amendment No. 7 (this “Amendment”) to the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer LP, a Delaware limited partnership (the “Partnership”), dated as of February 8, 2006 (as amended, the “Partnership Agreement”), is entered into effective as of August 6, 2019 by LE GP, LLC, a Delaware limited liability company (the “General Partner”), as the general partner of the Partnership, on behalf of itself and the Limited Partners of the Partnership. Capitalized terms used but not defined herein are used as defined in the Partnership Agreement.

RECITALS

WHEREAS, Section 13.1(d) of the Partnership Agreement provides that the General Partner, without the approval of any Partner, may amend any provision of the Partnership Agreement to reflect a change that the General Partner determines (i) does not adversely affect the Limited Partners (including any particular class of Partnership Interests as compared to other classes of Partnership Interests) in any material respect or (ii) is necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute (including the Delaware Act), and the General Partner has determined this Amendment satisfies both such conditions.

NOW, THEREFORE, the General Partner does hereby amend the Partnership Agreement as follows:

Section 1. Amendment.

(a) Section 1.1 of the Partnership Agreement is hereby amended by adding or amending and restating the following definitions, as stated herein below, in the appropriate alphabetical order:

Designated Individual” has the meaning assigned to such term in Section 9.3.

Indemnitee” means (a) the General Partner, (b) any Departing General Partner, (c) any Person who is or was an Affiliate of the General Partner or any Departing General Partner, (d) any Person who is or was a member, partner, officer, director, fiduciary or trustee of any Group Member, the General Partner or any Departing General Partner or any Affiliate of any Group Member, the General Partner or any Departing General Partner, (e) the Partnership Representative and the Designated Individual, (f) any Person who is or was serving at the request of the General Partner or any Departing General Partner or any Affiliate of the General Partner or any Departing General Partner as an officer, director, employee, member, partner, agent, fiduciary or trustee of another Person; provided, that a Person shall not be an Indemnitee by reason of providing, on a fee-for-services basis, trustee, fiduciary or custodial services and (g) any Person the General Partner designates as an “Indemnitee” for purposes of this Agreement.

Partnership Representative” has the meaning assigned to such term in Section 9.3.

(b) Section 9.3 of the Partnership Agreement is hereby deleted in its entirety and replaced with the following:

“Section 9.3 Tax Controversies.

Subject to the provisions hereof and for Partnership taxable years beginning before or on December 31, 2017, the General Partner is designated as the Tax Matters Partner (as defined in the Code) and is authorized and required to represent the Partnership (at the Partnership’s expense) in connection with all examinations of the Partnership’s affairs by tax authorities, including resulting administrative and judicial proceedings, and to expend Partnership funds for professional services and costs associated therewith. Each Partner agrees to cooperate with the General Partner and to do or refrain from doing any or all things reasonably required by the General Partner to conduct such proceedings.


With respect to Partnership taxable years beginning after December 31, 2017, the General Partner is designated as the “partnership representative” in accordance with the rules prescribed pursuant to Section 6223 of the Code (the “Partnership Representative”). The Partnership Representative shall have the authority to designate from time to time a “Designated Individual” to act on behalf of the Partnership Representative, and such Designated Individual shall be subject to replacement by the Partnership Representative in accordance with Treasury Regulations Section 301.6223-1. The Partnership Representative, or the Designated Individual, as applicable, shall have the sole authority to act on behalf of the Partnership in connection with all examinations of the Partnership’s affairs by tax authorities, including resulting administrative and judicial proceedings, and to expend Partnership funds for professional services and costs associated therewith. The Partnership Representative or the Designated Individual, as applicable, shall exercise in its sole discretion, any and all authority of the Partnership Representative under the Code, including, without limitation, (i) binding the Partnership and its Partners with respect to tax matters and (ii) determining whether to make any available election under Section 6226 of the Code. Any reasonable, documented cost or expense that the Partnership Representative or the Designated Individual, as applicable, incurs in connection with its duties, including the preparation for or pursuance of administrative or judicial proceedings, shall be paid by the Partnership. Neither the Partnership Representative nor the Designated Individual shall be liable to the Partnership or to its partners for acts or omissions taken or suffered by it in its capacity as either Partnership Representative or Designated Individual, as the case may be, in good faith; provided that such act or omission is not in willful violation of this Agreement and does not constitute fraud or a willful violation of law.

The General Partner shall amend the provisions of this Agreement as appropriate in accordance with Article XIII to reflect the proposal or promulgation of Treasury Regulations implementing the partnership audit, assessment and collection rules adopted by the Bipartisan Budget Act of 2015, including any amendments to those rules.

Section 2. Ratification of Partnership Agreement. Except as expressly modified and amended herein, all of the terms and conditions of the Partnership Agreement shall remain in full force and effect.

Section 3. Governing Law. This Amendment will be governed by and construed in accordance with the laws of the State of Delaware.

Section 4. Counterparts. This Amendment may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart.

Section 5. Severability. If any provision of this Amendment is or becomes invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions hereof, or of such provision in other respects, shall not be affected thereby.

[Signature Page Follows.]


IN WITNESS WHEREOF, this Amendment has been executed as of the date first written above.

 

GENERAL PARTNER:
LE GP, LLC
By:  

/s/ Thomas E. Long

Name:   Thomas E. Long
Title:   Chief Financial Officer
LIMITED PARTNERS:
All Limited Partners now and hereafter admitted as limited partners of the Partnership, pursuant to the Powers of Attorney now and hereafter executed in favor of, and granted and delivered to, the General Partner
By:   LE GP, LLC, General Partner of Energy Transfer LP, as attorney-in-fact for all Limited Partners pursuant to the Powers of Attorney granted pursuant to Section 2.6 of the Partnership Agreement.

 

By:  

/s/ Thomas E. Long

Name:   Thomas E. Long
Title:   Chief Financial Officer

SIGNATURE PAGE TO

AMENDMENT NO. 7 TO

THIRD AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF

ENERGY TRANSFER LP

EX-5.1

Exhibit 5.1

 

   811 Main Street, Suite 3700
   Houston, TX 77002
   Tel: +1.713.546.5400 Fax: +1.713.546.5401
  

www.lw.com

 

  
LOGO    FIRM / AFFILIATE OFFICES
   Beijing    Moscow
   Boston    Munich
   Brussels    New York
   Century City    Orange County
   Chicago    Paris
March 5, 2021    Dubai    Riyadh
   Düsseldorf    San Diego
   Frankfurt    San Francisco
   Hamburg    Seoul
   Hong Kong    Shanghai
Energy Transfer LP    Houston    Silicon Valley
8111 Westchester Drive, Suite 600    London    Singapore
Dallas, Texas 75225    Los Angeles    Tokyo
   Madrid    Washington, D.C.
   Milan   

 

  Re:

Registration Statement on Form S-4

Ladies and Gentlemen:

We have acted as special counsel to Energy Transfer LP, a Delaware limited partnership (the “Partnership”), in connection with the proposed issuance by the Partnership of 950,000 of its 6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in the Partnership (the ET Series A Preferred Units), 550,000 of its 6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in the Partnership (the ET Series B Preferred Units), 18,000,000 of its 7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in the Partnership (the ET Series C Preferred Units), 17,800,000 of its 7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in the Partnership (the ET Series D Preferred Units), 32,000,000 of its 7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in the Partnership (the ET Series E Preferred Units), 500,000 of its 6.750% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in the Partnership (the ET Series F Preferred Units), and 1,100,000 of its 7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in the Partnership (the ET Series G Preferred Units and, collectively with the ET Series A Preferred Units, the ET Series B Preferred Units, the ET Series C Preferred Units, the ET Series D Preferred Units, the ET Series E Preferred Units and the ET Series F Preferred units, the New ET Preferred Units), with each series of New ET Preferred Units being issued in exchange for an equivalent number and series of outstanding preferred units (the Existing ETO Preferred Units) of Energy Transfer Operating L.P. (ETO) pursuant to the terms and conditions of that certain Agreement and Plan of Merger, dated as of March 5, 2021, by and among ET, ETO Merger Sub LLC, a Delaware limited liability company, and ETO (the Merger Agreement).

The New ET Preferred Units are included in a registration statement on Form S-4 under the Securities Act of 1933, as amended (the “Act”), filed with the Securities and Exchange Commission (the “Commission”) on March 5, 2021 (as so filed and as so amended, the “Registration Statement”). This opinion is being furnished in connection with the requirements of Item 601(b)(5) of Regulation S-K under the Act, and no opinion is expressed herein as to any matter pertaining to the contents of the Registration Statement or related prospectus, other than as expressly stated herein with respect to the issuance of the New ET Preferred Units.

As such counsel, we have examined such matters of fact and questions of law as we have considered appropriate for purposes of this letter. With your consent, we have relied upon certificates and other assurances of officers of the general partner of the general partner of the Partnership and others as to factual matters without having independently verified such factual matters. We are opining herein as to the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”), and we express no opinion with respect to the applicability thereto, or the effect thereon, of the laws of any other jurisdiction or, in the case of Delaware, any other laws, or as to any matters of municipal law or the laws of any local agencies within any state.


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Subject to the foregoing and the other matters set forth herein, it is our opinion that, as of the date hereof, upon the issuance and delivery of the ET Preferred Units in the manner contemplated by the Registration Statement and the Merger Agreement, the issue of the New ET Preferred Units will have been duly authorized by all necessary limited partnership action of the Partnership, and the New ET Preferred Units will be validly issued and, under the Delaware Act, recipients of the New ET Preferred Units will have no obligation to make further payments or contributions to the Partnership solely by reason of their ownership of the New ET Preferred Units or their status as limited partners of the Partnership and no personal liability for the obligations of the Partnership, solely by reason of being limited partners of the Partnership.

This opinion is for your benefit in connection with the Registration Statement and may be relied upon by you and by persons entitled to rely upon it pursuant to the applicable provisions of the Act. We consent to your filing this opinion as an exhibit to the Registration Statement and to the reference to our firm in the prospectus contained in the Registration Statement under the heading “Legal Matters.” In giving such consent, we do not thereby admit that we are in the category of persons whose consent is required under Section 7 of the Act or the rules and regulations of the Commission thereunder.

Very truly yours,

/s/ Latham & Watkins LLP

EX-8.1

Exhibit 8.1

 

   811 Main Street, Suite 3700
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LOGO    FIRM / AFFILIATE OFFICES
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March 5, 2021    Düsseldorf    San Diego
   Frankfurt    San Francisco
   Hamburg    Seoul
Energy Transfer LP    Hong Kong    Shanghai
8111 Westchester Drive, Suite 600    Houston    Silicon Valley
Dallas, Texas 75225    London    Singapore
   Los Angeles    Tokyo
   Madrid    Washington, D.C.
   Milan   
     

 

  Re:

Agreement and Plan of Merger, dated as of March 5, 2021

Ladies and Gentlemen:

We have acted as special tax counsel to Energy Transfer LP, a Delaware limited partnership (“ET”), in connection with (i) the proposed merger (the “Merger”) of ETO Merger Sub LLC, a Delaware limited liability company and a direct wholly owned subsidiary of ET (“Merger Sub”), with and into Energy Transfer Operating, L.P., a Delaware limited partnership (“ETO”), with ETO surviving the Merger as a wholly owned subsidiary of ET, as contemplated by the Agreement and Plan of Merger, dated as of March 5, 2021, by and among ET, Merger Sub, and ETO (the “Merger Agreement”); and (ii) the preparation of a registration statement on Form S-4 under the Securities Act of 1933, as amended (the “Act”) filed with Securities and Exchange Commission by ET, including the prospectus forming a part thereof (as so filed and as amended, the “Registration Statement”). This opinion is being delivered in connection with the Registration Statement. Capitalized terms not defined herein have the meanings specified in the Merger Agreement unless otherwise indicated.

In rendering our opinion, we have examined and, with your consent, are expressly relying upon (without any independent investigation or review thereof) the truth and accuracy of the factual statements, representations, covenants and warranties contained in (i) the Merger Agreement (including any exhibits and schedules thereto), (ii) the Registration Statement, (iii) the tax Officer’s Certificate of ET, delivered to us for purposes of this opinion (the “Officer’s Certificate”), and (iv) such other documents and corporate records as we have deemed necessary or appropriate for purposes of our opinion.

In addition, we have assumed, with your consent, that:

 

  1.

Original documents (including signatures) are authentic, and documents submitted to us as copies conform to the original documents, and there has been (or will be by the effective time of the Merger) execution and delivery of all documents where execution and delivery are prerequisites to the effectiveness thereof;

 

  2.

The Merger will be consummated in the manner contemplated by, and in accordance with the provisions of, the Merger Agreement and the Registration Statement, and the Merger will be effective under the laws of the State of Delaware;

 

  3.

All factual statements, descriptions and representations contained in any of the documents referred to herein or otherwise made to us are true, complete and correct in all respects and will remain true, complete and correct in all respects up to and including the effective time of the Merger and throughout the subsequent periods specified in the Officer’s Certificate, and no actions have been taken or will be taken that are inconsistent with such factual statements, descriptions or representations or that make any such factual statements, descriptions or representations untrue, incomplete or incorrect at the effective time of the Merger or throughout the subsequent periods specified in the Officer’s Certificate;


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  4.

Any statements made in any of the documents referred to herein “to the knowledge of” or similarly qualified are true, complete and correct in all respects and will continue to be true, complete and correct in all respects at all times up to and including the effective time of the Merger, in each case without such qualification; and

 

  5.

The parties have complied with and, if applicable, will continue to comply with, the covenants contained in the Merger Agreement and the Registration Statement.

Based upon and subject to the foregoing, and subject to the qualifications, exceptions, assumptions and limitations stated in the Merger Agreement, the Registration Statement, and the Officer’s Certificate, the statements in the Registration Statement under the caption “Material U.S. Federal Income Tax Consequences of ET Preferred Unit Ownership,” insofar as such statements purport to constitute summaries of United States federal income tax law and regulations or legal conclusions with respect thereto, constitute the opinion of Latham & Watkins LLP as to the material U.S. federal income tax consequences of the matters described therein.

In addition to the matters set forth above, this opinion is subject to the exceptions, limitations and qualifications set forth below.

 

  1.

This opinion represents our best judgment regarding the application of U.S. federal income tax laws arising under the Internal Revenue Code of 1986, as amended, existing judicial decisions, administrative regulations and published rulings and procedures, but does not address all of the U.S. federal income tax consequences of New ET Preferred Unit ownership or all of the matters discussed in the Registration Statement under the caption “Material U.S. Federal Income Tax Consequences of ET Preferred Unit Ownership.” We express no opinion as to U.S. federal, state, local, foreign or other tax consequences, other than as set forth herein and in the Registration Statement. Our opinion is not binding upon the Internal Revenue Service or the courts, and there is no assurance that the Internal Revenue Service will not assert a contrary position. Furthermore, no assurance can be given that future legislative, judicial or administrative changes, on either a prospective or retroactive basis, would not adversely affect the validity of the conclusions stated herein and in the Registration Statement. Nevertheless, we undertake no responsibility to advise you of any new developments in the application or interpretation of the U.S. federal income tax laws.

 

  2.

No opinion is expressed as (i) to any matter not discussed in the Registration Statement under the caption “Material U.S. Federal Income Tax Consequences of ET Preferred Unit Ownership” or (ii) to any matter whatsoever if, to the extent relevant to our opinion, either all the transactions described in the Merger Agreement are not consummated in accordance with the terms of the Merger Agreement and without waiver or breach of any provisions thereof or all of the factual statements, representations, warranties and assumptions upon which we have relied, including in the Registration Statement and the Officer’s Certificate, are not true and accurate at all relevant times.

We are furnishing this opinion in connection with the filing of the Registration Statement and this opinion is not to be relied upon for any other purpose without our prior written consent. We consent to the filing of this opinion as an exhibit to the Registration Statement and to the reference to our firm name therein under the caption “Material U.S. Federal Income Tax Consequences of ET Preferred Unit Ownership.” In giving this consent, we do not admit that we are within the category of persons whose consent is required under Section 7 of the Act or the rules or regulations of the Securities and Exchange Commission promulgated thereunder.

Very truly yours,

/s/ Latham & Watkins LLP

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have issued our reports dated February 19, 2021 with respect to the consolidated financial statements and internal control over financial reporting of Energy Transfer LP included in the Annual Report on Form 10-K for the year ended December 31, 2020, which is incorporated by reference in this Registration Statement. We consent to the incorporation by reference of the aforementioned reports in this Registration Statement, and to the use of our name as it appears under the caption “Experts.”

/s/ GRANT THORNTON LLP

Dallas, Texas

March 5, 2021

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have issued our report dated February 19, 2021 with respect to the consolidated financial statements of Energy Transfer Operating, L.P. included in the Annual Report on Form 10-K for the year ended December 31, 2020, which is incorporated by reference in this Registration Statement. We consent to the incorporation by reference of the aforementioned report in this Registration Statement, and to the use of our name as it appears under the caption “Experts.”

 

/s/ GRANT THORNTON LLP

Dallas, Texas

March 5, 2021