Document
Table of Contents

 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2018
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-31219
ENERGY TRANSFER PARTNERS, 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)
(214) 981-0700
(Registrant’s telephone number, including area code)


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  ý    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ý    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
 
ý
 
Accelerated filer
 
¨
Non-accelerated filer
 
¨  (Do not check if a smaller reporting company)
 
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 is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  ý
At May 4, 2018, the registrant had 1,165,133,105 Common Units outstanding.
 


Table of Contents

FORM 10-Q
ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
TABLE OF CONTENTS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


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Table of Contents

Forward-Looking Statements
Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer Partners, L.P. (the “Partnership” or “ETP”) 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 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 “Part I – Item 1A. Risk Factors” in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2017 filed with the Securities and Exchange Commission on February 23, 2018.
Definitions
The following is a list of certain acronyms and terms generally used in the energy industry and throughout this document:
 
/d
 
per day
 
 
 
 
 
AOCI
 
accumulated other comprehensive income (loss)
 
 
 
 
 
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
 
 
 
 
BBtu
 
billion British thermal units
 
 
 
 
 
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
 
 
 
 
 
CDM E&T
 
CDM Environmental & Technical Services LLC
 
 
 
 
 
Citrus
 
Citrus, LLC
 
 
 
 
 
CrossCountry
 
CrossCountry Energy, LLC
 
 
 
 
 
DOJ
 
United States Department of Justice
 
 
 
 
 
EPA
 
United States Environmental Protection Agency
 
 
 
 
 
ETC OLP
 
La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company
 
 
 
 
 
ETE
 
Energy Transfer Equity, L.P., a publicly traded partnership and the owner of ETP LLC for the periods presented herein
 
 
 
 
 
ETP GP
 
Energy Transfer Partners GP, L.P., the general partner of ETP
 
 
 
 
 
ETP Holdco
 
ETP Holdco Corporation
 
 
 
 
 
ETP LLC
 
Energy Transfer Partners, L.L.C., the general partner of ETP GP
 
 
 
 
Exchange Act
 
Securities Exchange Act of 1934
 
 
 
 
 
FEP
 
Fayetteville Express Pipeline LLC
 
 
 
 
 
FERC
 
Federal Energy Regulatory Commission
 
 
 
 
 
FGT
 
Florida Gas Transmission Company, LLC
 
 
 
 
 
GAAP
 
accounting principles generally accepted in the United States of America
 
 
 
 
 
HPC
 
RIGS Haynesville Partnership Co. and its wholly-owned subsidiary, Regency Intrastate Gas LP


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Table of Contents

 
 
 
 
 
IDRs
 
incentive distribution rights
 
 
 
 
 
Legacy ETP Preferred Units
 
legacy ETP Series A cumulative convertible preferred units
 
 
 
 
 
LIBOR
 
London Interbank Offered Rate
 
 
 
 
 
MBbls
 
thousand barrels
 
 
 
 
 
MEP
 
Midcontinent Express Pipeline LLC
 
 
 
 
 
MTBE
 
methyl tertiary butyl ether
 
 
 
 
 
NGL
 
natural gas liquid, such as propane, butane and natural gasoline
 
 
 
 
 
NYMEX
 
New York Mercantile Exchange
 
 
 
 
 
OSHA
 
federal Occupational Safety and Health Act
 
 
 
 
 
OTC
 
over-the-counter
 
 
 
 
 
Panhandle
 
Panhandle Eastern Pipe Line Company, LP and its subsidiaries
 
 
 
 
 
PCBs
 
polychlorinated biphenyls
 
 
 
 
 
PennTex
 
PennTex Midstream Partners, LP
 
 
 
 
 
PES
 
Philadelphia Energy Solutions
 
 
 
 
 
Regency
 
Regency Energy Partners LP
 
 
 
 
 
Retail Holdings
 
ETP Retail Holdings, LLC, a wholly-owned subsidiary of Sunoco, Inc.
 
 
 
 
 
Rover
 
Rover Pipeline LLC, a subsidiary of ETP
 
 
 
 
 
SEC
 
Securities and Exchange Commission
 
 
 
 
 
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
 
 
 
 
 
Sunoco Logistics
 
Sunoco Logistics Partners L.P.
 
 
 
 
 
Transwestern
 
Transwestern Pipeline Company, LLC
 
 
 
 
 
Trunkline
 
Trunkline Gas Company, LLC, a subsidiary of Panhandle
 
 
 
 
 
USAC
 
USA Compression Partners, LP
Adjusted EBITDA is a term used throughout this document, which we define as 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, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments. Adjusted EBITDA reflects amounts for less than wholly-owned subsidiaries based on 100% of the subsidiaries’ results of operations and for unconsolidated affiliates based on the Partnership’s proportionate ownership.


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PART I – FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
(unaudited)
 
March 31, 2018
 
December 31, 2017
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
446

 
$
306

Accounts receivable, net
3,123

 
3,946

Accounts receivable from related companies
340

 
318

Inventories
1,421

 
1,589

Income taxes receivable
166

 
135

Derivative assets
23

 
24

Other current assets
229

 
210

Total current assets
5,748

 
6,528

 
 
 
 
Property, plant and equipment
69,164

 
67,699

Accumulated depreciation and depletion
(9,791
)
 
(9,262
)
 
59,373

 
58,437

 
 
 
 
Advances to and investments in unconsolidated affiliates
3,258

 
3,816

Other non-current assets, net
758

 
758

Intangible assets, net
5,243

 
5,311

Goodwill
3,115

 
3,115

Total assets
$
77,495

 
$
77,965


The accompanying notes are an integral part of these consolidated financial statements.
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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
(unaudited)
 
March 31, 2018
 
December 31, 2017
LIABILITIES AND EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
3,288

 
$
4,126

Accounts payable to related companies
244

 
209

Derivative liabilities
147

 
109

Accrued and other current liabilities
2,140

 
2,143

Current maturities of long-term debt
404

 
407

Total current liabilities
6,223

 
6,994

 
 
 
 
Long-term debt, less current maturities
33,109

 
32,687

Non-current derivative liabilities
97

 
145

Deferred income taxes
2,860

 
2,883

Other non-current liabilities
1,100

 
1,084

 
 
 
 
Commitments and contingencies

 

Redeemable noncontrolling interests
21

 
21

 
 
 
 
Equity:
 
 
 
Series A Preferred Unitholders
943

 
944

Series B Preferred Unitholders
546

 
547

Common Unitholders
26,143

 
26,531

General Partner
365

 
244

Accumulated other comprehensive income
2

 
3

Total partners’ capital
27,999

 
28,269

Noncontrolling interest
6,086

 
5,882

Total equity
34,085

 
34,151

Total liabilities and equity
$
77,495

 
$
77,965


The accompanying notes are an integral part of these consolidated financial statements.
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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except per unit data)
(unaudited)
 
Three Months Ended
March 31,
 
2018
 
2017*
REVENUES:
 
 
 
Natural gas sales
$
1,062

 
$
1,012

NGL sales
2,030

 
1,547

Crude sales
3,254

 
2,542

Gathering, transportation and other fees
1,397

 
1,024

Refined product sales
439

 
471

Other
98

 
299

Total revenues
8,280

 
6,895

COSTS AND EXPENSES:
 
 
 
Cost of products sold
5,988

 
5,050

Operating expenses
604

 
492

Depreciation, depletion and amortization
603

 
560

Selling, general and administrative
112

 
110

Total costs and expenses
7,307

 
6,212

OPERATING INCOME
973

 
683

OTHER INCOME (EXPENSE):
 
 
 
Interest expense, net
(346
)
 
(332
)
Equity in earnings (losses) of unconsolidated affiliates
(72
)
 
73

Gain on Sunoco LP common unit repurchase
172

 

Gains on interest rate derivatives
52

 
5

Other, net
60

 
19

INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)
839

 
448

Income tax expense (benefit)
(40
)
 
55

NET INCOME
879

 
393

Less: Net income attributable to noncontrolling interest
164

 
62

NET INCOME ATTRIBUTABLE TO PARTNERS
715

 
331

General Partner’s interest in net income
402

 
206

Series A Preferred Unitholders’ interest in net income
15

 

Series B Preferred Unitholders’ interest in net income
9

 

Class H Unitholder’s interest in net income

 
93

Common Unitholders’ interest in net income
$
289

 
$
32

NET INCOME PER COMMON UNIT:
 
 
 
Basic
$
0.24

 
$
0.03

Diluted
$
0.24

 
$
0.03

* As adjusted. See Note 1.

The accompanying notes are an integral part of these consolidated financial statements.
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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
(unaudited)
 
Three Months Ended
March 31,
 
2018
 
2017*
Net income
$
879

 
$
393

Other comprehensive income (loss), net of tax:
 
 
 
Change in value of available-for-sale securities
(2
)
 
2

Actuarial loss relating to pension and other postretirement benefit plans
(2
)
 
(2
)
Change in other comprehensive income from unconsolidated affiliates
5

 

 
1

 

Comprehensive income
880

 
393

Less: Comprehensive income attributable to noncontrolling interest
164

 
62

Comprehensive income attributable to partners
$
716

 
$
331

* As adjusted. See Note 1.

The accompanying notes are an integral part of these consolidated financial statements.
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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF EQUITY
FOR THE THREE MONTHS ENDED MARCH 31, 2018
(Dollars in millions)
(unaudited)
 
Series A Preferred Units
 
Series B Preferred Units
 
Common Units
 
General Partner
 
Accumulated Other Comprehensive Income
 
Noncontrolling Interest
 
Total
Balance, December 31, 2017
$
944

 
$
547

 
$
26,531

 
$
244

 
$
3

 
$
5,882

 
$
34,151

Distributions to partners
(15
)
 
(9
)
 
(657
)
 
(264
)
 

 

 
(945
)
Distributions to noncontrolling interest

 

 

 

 

 
(183
)
 
(183
)
Units issued for cash

 

 
20

 

 

 

 
20

Capital contributions from noncontrolling interest

 

 

 

 

 
229

 
229

Repurchases of common units

 

 
(24
)
 

 

 

 
(24
)
Other comprehensive income, net of tax

 

 

 

 
1

 

 
1

Other, net
(1
)
 
(1
)
 
(16
)
 
(17
)
 
(2
)
 
(6
)
 
(43
)
Net income
15

 
9

 
289

 
402

 

 
164

 
879

Balance, March 31, 2018
$
943

 
$
546

 
$
26,143

 
$
365

 
$
2

 
$
6,086

 
$
34,085


The accompanying notes are an integral part of these consolidated financial statements.
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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
(unaudited)
 
Three Months Ended
March 31,
 
2018
 
2017*
OPERATING ACTIVITIES
 
 
 
Net income
$
879

 
$
393

Reconciliation of net income to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
603

 
560

Deferred income taxes
(40
)
 
54

Non-cash compensation expense
20

 
23

Gain on Sunoco LP common unit repurchase
(172
)
 

Distributions on unvested awards
(8
)
 
(8
)
Equity in (earnings) losses of unconsolidated affiliates
72

 
(73
)
Distributions from unconsolidated affiliates
106

 
82

Other non-cash
(78
)
 
(53
)
Net change in operating assets and liabilities, net of effects of acquisitions
392

 
(46
)
Net cash provided by operating activities
1,774

 
932

INVESTING ACTIVITIES
 
 
 
Cash proceeds from Bakken Pipeline Transaction

 
2,000

Cash proceeds from Sunoco LP common unit repurchase
540

 

Cash paid for acquisition of PennTex noncontrolling interest

 
(280
)
Cash paid for all other acquisitions
(4
)
 
(38
)
Capital expenditures, excluding allowance for equity funds used during construction
(1,718
)
 
(1,384
)
Contributions in aid of construction costs
20

 
6

Contributions to unconsolidated affiliates
(8
)
 
(111
)
Distributions from unconsolidated affiliates in excess of cumulative earnings
27

 
90

Other

 
(3
)
Net cash (used in) provided by investing activities
(1,143
)
 
280

FINANCING ACTIVITIES
 
 
 
Proceeds from borrowings
3,959

 
6,366

Repayments of long-term debt
(3,545
)
 
(7,216
)
Cash received from (paid to) affiliate notes
2

 
(250
)
Units issued for cash
20

 
826

Capital contributions from noncontrolling interest
229

 
106

Distributions to partners
(945
)
 
(896
)
Distributions to noncontrolling interest
(183
)
 
(148
)
Repurchases of common units
(24
)
 

Redemption of Legacy ETP Preferred Units

 
(53
)
Debt issuance costs

 
(19
)
Other
(4
)
 
3

Net cash used in financing activities
(491
)
 
(1,281
)
Increase (decrease) in cash and cash equivalents
140

 
(69
)
Cash and cash equivalents, beginning of period
306

 
360

Cash and cash equivalents, end of period
$
446

 
$
291

* As adjusted. See Note 1.

The accompanying notes are an integral part of these consolidated financial statements.
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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Tabular dollar and unit amounts, except per unit data, are in millions)
(unaudited)
1.
ORGANIZATION AND BASIS OF PRESENTATION
Organization
Energy Transfer Partners, L.P. (“ETP”) is a consolidated subsidiary of ETE.
In April 2017, Energy Transfer Partners, L.P. and Sunoco Logistics completed a merger transaction in which Sunoco Logistics acquired Energy Transfer Partners, L.P. in a unit-for-unit transaction (the “Sunoco Logistics Merger”), with the Energy Transfer Partners, L.P. unitholders receiving 1.5 common units of Sunoco Logistics for each Energy Transfer Partners, L.P. common unit they owned. In connection with the Sunoco Logistics Merger, Sunoco Logistics was renamed Energy Transfer Partners, L.P. and Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE.
The Sunoco Logistics Merger resulted in Energy Transfer Partners, L.P. being treated as the surviving consolidated entity from an accounting perspective, while Sunoco Logistics (prior to changing its name to “Energy Transfer Partners, L.P.”) was the surviving consolidated entity from a legal and reporting perspective. Therefore, for the pre-merger periods, the consolidated financial statements reflect the consolidated financial statements of the legal acquiree (i.e., the entity that was named “Energy Transfer Partners, L.P.” prior to the merger and name changes).
The consolidated financial statements of the Partnership presented herein include our operating subsidiaries (collectively, the “Operating Companies”), through which our activities are primarily conducted, as follows:
ETC OLP, Regency and PennTex, which are primarily engaged in midstream and intrastate transportation and storage natural gas operations. ETC OLP and Regency own and operate, through their wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and are engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico, West Virginia, Colorado and Ohio.
Energy Transfer Interstate Holdings, LLC, (“ETIH”) with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales, which is the parent company of:
Transwestern, engaged in interstate transportation of natural gas. Transwestern’s revenues consist primarily of fees earned from natural gas transportation services and operational gas sales.
ETC Fayetteville Express Pipeline, LLC, which directly owns a 50% interest in FEP, which owns 100% of the Fayetteville Express interstate natural gas pipeline.
ETC Tiger Pipeline, LLC, engaged in interstate transportation of natural gas.
CrossCountry, which indirectly owns a 50% interest in Citrus, which owns 100% of the FGT interstate natural gas pipeline.
ETC Midcontinent Express Pipeline, L.L.C., which directly owns a 50% interest in MEP.
ET Rover Pipeline, LLC, which ETIH directly owns a 50.1% interest in, which owns a 65% interest in the Rover pipeline.
ETC Compression, LLC, engaged in natural gas compression services and related equipment sales. As discussed further in Note 2 below, in April 2018, we contributed certain assets to USAC.
ETP Holdco, which indirectly owns Panhandle and Sunoco, Inc. Panhandle owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the transportation and storage of natural gas in the United States. Sunoco Inc.’s assets primarily consist of its ownership in Retail Holdings, which owns noncontrolling interests in Sunoco LP and PES. ETP Holdco also holds an equity method investment in ETP through its ownership of ETP Class E, Class G, and Class K units, which investment is eliminated in ETP’s consolidated financial statements.
Sunoco Logistics Partners Operations L.P., which 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.


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We currently have the following reportable business segments:
intrastate transportation and storage;
interstate transportation and storage;
midstream;
NGL and refined products transportation and services;
crude oil transportation and services; and
all other.
Prior periods have been retrospectively adjusted to reflect the impact of the Sunoco Logistics Merger on our reportable business segments.
Basis of Presentation
The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements of Energy Transfer Partners, L.P. for the year ended December 31, 2017, included in the Partnership’s Annual Report on Form 10-K filed with the SEC on February 23, 2018. In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC.
The historical common units and net income per limited partner unit amounts presented in these consolidated financial statements have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.
For prior periods reported herein, certain transactions related to the business of legacy Sunoco Logistics have been reclassified from cost of products sold to operating expenses; these transactions include sales between operating subsidiaries and their marketing affiliates. These reclassifications had no impact on net income or total equity.
Change in Accounting Policy
Inventory Accounting Change
During the fourth quarter of 2017, the Partnership elected to change its method of inventory costing to weighted-average cost for certain inventory that had previously been accounted for using the last-in, first-out (“LIFO”) method. The inventory impacted by this change included the crude oil, refined products and NGLs associated with the legacy Sunoco Logistics business. Management believes that the weighted-average cost method is preferable to the LIFO method as it more closely aligns the accounting policies across the consolidated entity, given that the legacy ETP inventory has been accounted for using the weighted-average cost method.


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As a result of this change in accounting policy, prior periods have been retrospectively adjusted, as follows:
 
Three Months Ended March 31, 2017
 
As Originally Reported*
 
Effect of Change
 
As Adjusted
Consolidated Statement of Operations and Comprehensive Income:
 
 
 
 
 
Cost of products sold
$
5,079

 
$
(29
)
 
$
5,050

Operating income
654

 
29

 
683

Income before income tax expense
419

 
29

 
448

Net income
364

 
29

 
393

Net income attributable to partners
324

 
7

 
331

Net income per common unit – basic
0.02

 
0.01

 
0.03

Net income per common unit – diluted
0.02

 
0.01

 
0.03

Comprehensive income
364

 
29

 
393

Comprehensive income attributable to partners
324

 
7

 
331

 
 
 
 
 
 
Consolidated Statements of Cash Flows:
 
 
 
 
 
Net income
364

 
29

 
393

Inventory valuation adjustments
(2
)
 
2

 

Net change in operating assets and liabilities (change in inventories)
(15
)
 
(31
)
 
(46
)
* Amounts reflect certain reclassifications made to conform to the current year presentation.
Revenue Recognition Standard
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Partnership adopted ASU 2014-09 on January 1, 2018.
Upon the adoption of ASU 2014-09, the amount of revenue that the Partnership recognizes on certain contracts has changed, primarily due to increases in revenue (with offsetting increases to cost of sales) resulting from recognition of non-cash consideration as revenue when received and as cost of sales when sold to third parties. In addition, income statement reclassifications were required for fuel usage and loss allowances related to multiple segments as well as contracts deemed to be in-substance supply agreements in our midstream segment. In addition to the evaluation performed, we have made appropriate design and implementation updates to our business processes, systems and internal controls to support recognition and disclosure under the new standard.
Utilizing the practical expedients allowed under the modified retrospective adoption method, Accounting Standards Codification (“ASC”) Topic 606 was only applied to existing contracts for which the Partnership has remaining performance obligations as of January 1, 2018, and new contracts entered into after January 1, 2018. ASC Topic 606 was not applied to contracts that were completed prior to January 1, 2018.
The Partnership has elected to apply the modified retrospective method to adopt the new standard. For contracts in scope of the new revenue standard as of January 1, 2018, the cumulative effect adjustment to partners’ capital was not material. The comparative information has not been restated under the modified retrospective method and continues to be reported under the accounting standards in effect for those periods.
The adoption of the new revenue standard resulted in reclassifications between revenue, cost of sales and operating expenses. There were no material changes in the timing of recognition of revenue and therefore no material impacts to the balance sheet upon adoption.


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Table of Contents

The disclosure below shows the impact of adopting the new standard during the period of adoption compared to amounts that would have been reported under the Partnership’s previous revenue recognition policies:
 
Three Months Ended March 31, 2018
 
As Reported
 
Balances Without Adoption of ASC 606
 
Effect of Change: Higher/(Lower)
Revenues:
 
 
 
 
 
Natural gas sales
$
1,062

 
$
1,062

 
$

NGL sales
2,030

 
2,019

 
11

Crude sales
3,254

 
3,254

 

Gathering, transportation and other fees
1,397

 
1,584

 
(187
)
Refined product sales
439

 
439

 

Other
98

 
98

 

 
 
 
 
 
 
Costs and expenses:
 
 
 
 
 
Cost of products sold
5,988

 
6,175

 
(187
)
Operating expenses
604

 
593

 
11

Additional disclosures related to revenue are included in Note 11.
Use of Estimates
The unaudited consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates.
Recent Accounting Pronouncements
ASU 2016-02
In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes the principles that lessees and lessors shall apply to report useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. In January 2018, the FASB issued Accounting Standards Update No. 2018-01 (“ASU 2018-01”), which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under Topic 840. The Partnership expects to adopt ASU 2016-02 and elect the practical expedient under ASU 2018-01 in the first quarter of 2019 and is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.
ASU 2017-12
In August 2017, the FASB issued Accounting Standards Update No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. The amendments in this update improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, the amendments in this update make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.
ASU 2018-02
In February 2018, the FASB issued Accounting Standards Update No. 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, which allows a reclassification from accumulated other comprehensive income to retained earnings at partners’ capital for stranded tax effects resulting from the Tax Cuts and Jobs Act of 2017. The Partnership elected to early adopt this ASU in the first quarter of 2018. The effect of the adoption was not material.


10

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2.
ACQUISITIONS AND OTHER INVESTING TRANSACTIONS
CDM Contribution
On April 2, 2018, ETP contributed to USAC all of the issued and outstanding membership interests of CDM and CDM E&T for aggregate consideration of approximately $1.7 billion, consisting of (i) 19,191,351 common units representing limited partner interests in USAC (“USAC Common Units”), (ii) 6,397,965 units of a newly authorized and established class of units representing limited partner interests in USAC (“Class B Units”) and (iii) $1.23 billion in cash, including customary closing adjustments (the “CDM Contribution”). The 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 Class B Units will not participate in distributions for the first four quarters following the closing date of April 2, 2018. Each 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.
Beginning April 2018, ETP’s consolidated financial statements will reflect an equity method investment in USAC. CDM and CDM E&T’s assets and liabilities have not been reflected as held for sale, nor have CDM and CDM E&T’s results been reflected as discontinued operations in these financial statements.
In connection with the CDM Contribution, ETE acquired (i) all of the outstanding limited liability company interests in USA Compression GP, LLC, the general partner of USAC, and (ii) 12,466,912 USAC Common Units for cash consideration equal to $250 million.
Sunoco LP Common Unit Repurchase
In February 2018, after the record date for Sunoco LP’s fourth quarter 2017 cash distributions, Sunoco LP repurchased 17,286,859 Sunoco LP common units owned by ETP for aggregate cash consideration of approximately $540 million. ETP used the proceeds from the sale of the Sunoco LP common units to repay amounts outstanding under its revolving credit facility. In connection with this transaction, the Partnership recognized a gain of $172 million.
3.
CASH AND CASH EQUIVALENTS
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:
 
Three Months Ended
March 31,
 
2018
 
2017*
Accounts receivable
$
817

 
$
(23
)
Accounts receivable from related companies
122

 
(44
)
Inventories
169

 
137

Other current assets
(48
)
 
43

Other non-current assets, net
(3
)
 
(18
)
Accounts payable
(667
)
 
(88
)
Accounts payable to related companies
(111
)
 
120

Accrued and other current liabilities
106

 
(139
)
Other non-current liabilities
16

 
(2
)
Derivative assets and liabilities, net
(9
)
 
(32
)
Net change in operating assets and liabilities, net of effects of acquisitions
$
392

 
$
(46
)
* As adjusted. See Note 1.


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Non-cash investing and financing activities are as follows:

Three Months Ended
March 31,

2018
 
2017
NON-CASH INVESTING ACTIVITIES:
 
 
 
Accrued capital expenditures
$
1,010

 
$
832

NON-CASH FINANCING ACTIVITIES:
 
 
 
Contribution of property, plant and equipment from noncontrolling interest
$

 
$
988

4.
INVENTORIES
Inventories consisted of the following:
 
March 31, 2018
 
December 31, 2017
Natural gas, NGLs, and refined products
$
419

 
$
733

Crude oil
701

 
551

Spare parts and other
301

 
305

Total inventories
$
1,421

 
$
1,589

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.
5.
FAIR VALUE MEASURES
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 consolidated debt obligations as of March 31, 2018 was $33.78 billion and $33.51 billion, respectively. As of December 31, 2017, the aggregate fair value and carrying amount of our consolidated debt obligations was $34.28 billion and $33.09 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 and interest rate derivatives 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 three months ended March 31, 2018, no transfers were made between any levels within the fair value hierarchy.


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The following tables summarize the gross fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of March 31, 2018 and December 31, 2017 based on inputs used to derive their fair values:
 
 
 
Fair Value Measurements at
March 31, 2018
 
Fair Value Total
 
Level 1
 
Level 2
Assets:
 
 
 
 
 
Commodity derivatives:
 
 
 
 
 
Natural Gas:
 
 
 
 
 
Basis Swaps IFERC/NYMEX
$
35

 
$
35

 
$

Swing Swaps IFERC
1

 

 
1

Fixed Swaps/Futures
14

 
14

 

Forward Physical Contracts
7

 

 
7

Power:
 
 
 
 
 
Forwards
78

 

 
78

Options – Puts
1

 
1

 

Options – Calls
1

 
1

 

Natural Gas Liquids – Forwards/Swaps
115

 
115

 

Total commodity derivatives
252

 
166

 
86

Other non-current assets
21

 
14

 
7

Total assets
$
273

 
$
180

 
$
93

Liabilities:
 
 
 
 
 
Interest rate derivatives
$
(167
)
 
$

 
$
(167
)
Commodity derivatives:
 
 
 
 
 
Natural Gas:
 
 
 
 
 
Basis Swaps IFERC/NYMEX
(81
)
 
(81
)
 

Swing Swaps IFERC
(1
)
 

 
(1
)
Fixed Swaps/Futures
(13
)
 
(13
)
 

Options – Calls
(1
)
 
(1
)
 

Forward Physical Contracts
(6
)
 

 
(6
)
Power – Forwards
(72
)
 

 
(72
)
Natural Gas Liquids – Forwards/Swaps
(169
)
 
(169
)
 

Refined Products – Futures
(3
)
 
(3
)
 

Total commodity derivatives
(346
)
 
(267
)
 
(79
)
Total liabilities
$
(513
)
 
$
(267
)
 
$
(246
)


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Fair Value Measurements at
December 31, 2017
 
Fair Value Total
 
Level 1
 
Level 2
Assets:
 
 
 
 
 
Commodity derivatives:
 
 
 
 
 
Natural Gas:
 
 
 
 
 
Basis Swaps IFERC/NYMEX
$
11

 
$
11

 
$

Swing Swaps IFERC
13

 

 
13

Fixed Swaps/Futures
70

 
70

 

Forward Physical Swaps
8

 

 
8

Power – Forwards
23

 

 
23

Natural Gas Liquids – Forwards/Swaps
193

 
193

 

Crude – Futures
2

 
2

 

Total commodity derivatives
320

 
276

 
44

Other non-current assets
21

 
14

 
7

Total assets
$
341

 
$
290

 
$
51

Liabilities:
 
 
 
 
 
Interest rate derivatives
$
(219
)
 
$

 
$
(219
)
Commodity derivatives:
 
 
 
 
 
Natural Gas:
 
 
 
 
 
Basis Swaps IFERC/NYMEX
(24
)
 
(24
)
 

Swing Swaps IFERC
(15
)
 
(1
)
 
(14
)
Fixed Swaps/Futures
(57
)
 
(57
)
 

Forward Physical Swaps
(2
)
 

 
(2
)
Power – Forwards
(22
)
 

 
(22
)
Natural Gas Liquids – Forwards/Swaps
(192
)
 
(192
)
 

Refined Products – Futures
(25
)
 
(25
)
 

Crude – Futures
(1
)
 
(1
)
 

Total commodity derivatives
(338
)
 
(300
)
 
(38
)
Total liabilities
$
(557
)
 
$
(300
)
 
$
(257
)
6.
NET INCOME PER LIMITED PARTNER UNIT
The historical common units and net income per limited partner unit amounts presented in these consolidated financial statements have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.
Net income for partners’ capital and statement of operations presentation purposes is allocated to the General Partner and Limited Partners in accordance with their respective partnership percentages, after giving effect to priority income allocations for incentive distributions, if any, to the General Partner, the holder of the IDRs pursuant to the Partnership Agreement, which are declared and paid following the close of each quarter. Earnings in excess of distributions are allocated to the General Partner and Limited Partners based on their respective ownership interests.


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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:
 
Three Months Ended
March 31,
 
2018
 
2017*
Net income
$
879

 
$
393

Less: Income attributable to noncontrolling interest
164

 
62

Net income, net of noncontrolling interest
715

 
331

General Partner’s interest in net income
402

 
206

Series A Preferred Unitholders’ interest in net income
15

 

Series B Preferred Unitholders’ interest in net income
9

 

Class H Unitholder’s interest in net income

 
93

Common Unitholders’ interest in net income
289

 
32

Additional earnings allocated to General Partner
(2
)
 
(3
)
Distributions on employee unit awards, net of allocation to General Partner
(8
)
 
(7
)
Net income available to Common Unitholders
$
279

 
$
22

Weighted average Common Units – basic
1,163.8

 
822.3

Basic net income per Common Unit
$
0.24

 
$
0.03

 
 
 
 
Dilutive effect of unvested employee unit awards
4.0

 
2.2

Weighted average Common Units – diluted
1,167.8

 
824.5

Diluted net income per Common Unit
$
0.24

 
$
0.03

* As adjusted. See Note 1.
7.
DEBT OBLIGATIONS
Credit Facilities and Commercial Paper
ETP Five-Year Credit Facility
ETP’s revolving credit facility (the “ETP Five-Year Credit Facility”) allows for unsecured borrowings up to $4.00 billion and matures in December 2022. The ETP 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 March 31, 2018, the ETP Five-Year Credit Facility had $2.76 billion outstanding, of which $1.93 billion was commercial paper. The amount available for future borrowings was $1.09 billion after taking into account letters of credit of $155 million. The weighted average interest rate on the total amount outstanding as of March 31, 2018 was 2.92%.
ETP 364-Day Facility
ETP’s 364-day term loan facility (the “ETP 364-Day Facility”) allows for unsecured borrowings up to $1.00 billion and matures on November 30, 2018. As of March 31, 2018, the ETP 364-Day Facility had no outstanding borrowings.
Bakken Credit Facility
In August 2016, Energy Transfer Partners, L.P., Sunoco Logistics and Phillips 66 completed project-level financing of the Bakken Pipeline. The $2.50 billion credit facility is anticipated to provide substantially all of the remaining capital necessary to complete the projects and matures in August 2019 (the “Bakken Credit Facility”). As of March 31, 2018, the Bakken Credit Facility had $2.50 billion of outstanding borrowings. The weighted average interest rate on the total amount outstanding as of March 31, 2018 was 3.31%.
Compliance with Our Covenants
We were in compliance with all requirements, tests, limitations, and covenants related to our credit agreements as of March 31, 2018.


15

Table of Contents

8.
EQUITY
The changes in outstanding common units during the three months ended March 31, 2018 were as follows:
 
 
Number of Units
Number of common units at December 31, 2017
 
1,164.1

Common units issued in connection with the distribution reinvestment plan
 
1.1

Repurchases of common units in open-market transactions
 
(1.2
)
Number of common units at March 31, 2018
 
1,164.0

Equity Distribution Program
During the three months ended March 31, 2018, there were no units issued under the Partnership’s equity distribution agreements. As of March 31, 2018, $752 million of the Partnership’s common units remained available to be issued under the Partnership’s existing $1.00 billion equity distribution agreement.
Distribution Reinvestment Program
During the three months ended March 31, 2018, distributions of $20 million were reinvested under the distribution reinvestment plan.
Preferred Units
As of each of March 31, 2018 and December 31, 2017, the Partnership had 950,000 Series A Preferred Units and 550,000 Series B Preferred Units outstanding.
In April 2018, ETP issued 18 million of its 7.375% Series C Preferred Units at a price of $25 per unit, resulting in total gross proceeds of $450 million. The proceeds were used to repay amounts outstanding under our revolving credit facility and for general partnership purposes.
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 ETP’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.
Quarterly Distributions of Available Cash
Under our limited partnership agreement, within 45 days after the end of each quarter, the Partnership distributes all cash on hand at the end of the quarter, less reserves established by the general partner in its discretion. This is defined as “available cash” in the partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct the Partnership’s business. The Partnership will make quarterly distributions to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner.
Distributions on common units declared and/or paid by the Partnership subsequent to December 31, 2017 were as follows:
Quarter Ended
 
Record Date
 
Payment Date
 
Rate
December 31, 2017
 
February 8, 2018
 
February 14, 2018
 
$
0.5650

March 31, 2018
 
May 7, 2018
 
May 15, 2018
 
0.5650



16

Table of Contents

ETE agreed to relinquish its right to the following amounts of incentive distributions in future periods:
 
 
Total Year
2018 (remainder)
 
$
111

2019
 
128

Each year beyond 2019
 
33

Distributions on preferred units declared and paid by the Partnership subsequent to December 31, 2017 were as follows:
 
 
 
 
 
 
Distribution per Preferred Unit
Quarter Ended
 
Record Date
 
Payment Date
 
Series A
 
Series B
December 31, 2017
 
February 1, 2018
 
February 15, 2018
 
$
15.451

 
$
16.378

Accumulated Other Comprehensive Income
The following table presents the components of AOCI, net of tax:
 
March 31, 2018
 
December 31, 2017
Available-for-sale securities (1)
$
4

 
$
8

Foreign currency translation adjustment
(5
)
 
(5
)
Actuarial loss related to pensions and other postretirement benefits
(7
)
 
(5
)
Investments in unconsolidated affiliates, net
10

 
5

Total AOCI, net of tax
$
2

 
$
3

(1) 
Effective January 1, 2018, the Partnership adopted Accounting Standards Update No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, which resulted in the reclassification of $2 million from accumulated other comprehensive income related to available-for-sale securities to common unitholders.
9.
INCOME TAXES
The Partnership’s effective tax rate differs 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. For the three months ended March 31, 2018 the Partnership’s income tax benefit also reflected a $67 million deferred benefit adjustment as the result of a state statutory rate reduction.
10.
REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES
Guarantee of Sunoco LP Notes
In connection with previous transactions whereby Retail Holdings contributed assets to Sunoco LP, Retail Holdings provided a limited contingent guarantee of collection, but not of payment, to Sunoco LP with respect to (i) $800 million principal amount of 6.375% senior notes due 2023 issued by Sunoco LP, (ii) $800 million principal amount of 6.25% senior notes due 2021 issued by Sunoco LP and (iii) $2.035 billion aggregate principal for Sunoco LP’s term loan due 2019. In December 2016, Retail Holdings contributed its interests in Sunoco LP, along with the assignment of the guarantee of Sunoco LP’s senior notes, to its subsidiary, ETC M-A Acquisition LLC (“ETC M-A”).
On January 23, 2018, Sunoco LP redeemed the previously guaranteed senior notes and issued the following notes for which ETC M-A has also guaranteed collection with respect to the payment of principal amounts:
$1.00 billion aggregate principal amount of 4.875% senior notes due 2023;
$800 million aggregate principal amount of 5.50% senior notes due 2026; and
$400 million aggregate principal amount of 5.875% senior notes due 2028.
Under the guarantee of collection, ETC M-A would have the obligation to pay the principal of each series of notes once all remedies, including in the context of bankruptcy proceedings, have first been fully exhausted against Sunoco LP with respect


17

Table of Contents

to such payment obligation, and holders of the notes are still owed amounts in respect of the principal of such notes. ETC M-A will not otherwise be subject to the covenants of the indenture governing the notes.
FERC Audit
In March 2016, the FERC commenced an audit of Trunkline for the period from January 1, 2013 to present to evaluate Trunkline’s compliance with the requirements of its FERC gas tariff, the accounting regulations of the Uniform System of Accounts as prescribed by the FERC, and the FERC’s annual reporting requirements. The audit is ongoing.
Commitments
In the normal course of business, ETP 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. ETP 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 our 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 leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2034. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:
 
Three Months Ended
March 31,
 
2018
 
2017
Rental expense
$
25

 
$
20

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.
Dakota Access Pipeline
On July 25, 2016, the United States Army Corps of Engineers (“USACE”) issued permits to Dakota Access to make two crossings of the Missouri River in North Dakota. The USACE also issued easements to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River. On July 27, 2016, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia against the USACE and challenged the legality of these permits and claimed violations of the National Historic Preservation Act (“NHPA”). The SRST also sought a preliminary injunction to rescind the USACE permits while the case was pending, which the court denied on September 9, 2016. Dakota Access intervened in the case. The Cheyenne River Sioux Tribe (“CRST”) also intervened. The SRST filed an amended complaint and added claims based on treaties between the Tribes and the United States and statutes governing the use of government property.
In February 2017, in response to a presidential memorandum, the Department of the Army delivered an easement to Dakota Access allowing the pipeline to cross Lake Oahe. The CRST moved for a preliminary injunction and temporary restraining order (“TRO”) to block operation of the pipeline, which was denied, and raised claims based on the religious rights of the Tribe.


18

Table of Contents

The SRST and the CRST amended their complaints to incorporate religious freedom and other claims. In addition, the Oglala and Yankton Sioux tribes (collectively, “Tribes”) have filed related lawsuits to prevent construction of the Dakota Access pipeline project. These lawsuits have been consolidated into the action initiated by the SRST. Several individual members of the Tribes have also intervened in the lawsuit asserting claims that overlap with those brought by the four Tribes.
On June 14, 2017, the Court ruled on SRST’s and CRST’s motions for partial summary judgment and the USACE’s cross-motions for partial summary judgment. The Court concluded that the USACE had not violated trust duties owed to the Tribes and had generally complied with its obligations under the Clean Water Act, the Rivers and Harbors Act, the Mineral Leasing Act, the National Environmental Policy Act (“NEPA”) and other related statutes; however, the Court remanded to the USACE three discrete issues for further analysis and explanation of its prior determinations under certain of these statutes. On May 3, 2018, the District Court ordered the USACE to file a status report by June 8, 2018 informing the Court when the USACE expects the remand process to be complete. Following the completion of the remand process by the USACE, the Court will make a determination regarding the three discrete issues covered by the remand order.
On December 4, 2017, the Court imposed three conditions on continued operation of the pipeline during the remand process. First, Dakota Access must retain an independent third-party to review its compliance with the conditions and regulations governing its easements and to assess integrity threats to the pipeline. The assessment report was filed with the Court. Second, the Court has directed Dakota Access to continue its work with the Tribes and the USACE to revise and finalize its emergency spill response planning for the section of the pipeline crossing Lake Oahe. Dakota Access filed the revised plan with the Court. And third, the Court has directed Dakota Access to submit bi-monthly reports during the remand period disclosing certain inspection and maintenance information related to the segment of the pipeline running between the valves on either side of the Lake Oahe crossing. The first and second reports were filed with the court on December 29, 2017 and February 28, 2018, respectfully.
In November 2017, the Yankton Sioux Tribe (“YST”), moved for partial summary judgment asserting claims similar to those already litigated and decided by the Court in its June 14, 2017 decision on similar motions by CRST and SRST. YST argues that the USACE and Fish and Wildlife Service violated NEPA, the Mineral Leasing Act, the Rivers and Harbors Act, and YST’s treaty and trust rights when the government granted the permits and easements necessary for the pipeline.
On March 19, 2018, the District Court denied YST’s motion for partial summary judgment and instead granted judgment in favor of Dakota Access pipeline and the USACE on the claims raised in YST’s motion. The Court concluded that YST’s NHPA claims are moot because construction of the pipeline is complete and that the government’s review process did not violate NEPA or the various treaties cited by the YST.
On February 8, 2018, the Court docketed a motion by CRST to “compel meaningful consultation on remand.” SRST then made a similar motion for “clarification re remand process and remand conditions.” The motions seek an order from the Court directing the USACE as to how it should conduct its additional review on remand. Dakota Access pipeline and the USACE opposed both motions. On April 16, 2018, the Court denied both motions.
While ETP believes that the pending lawsuits are unlikely to block operation of the pipeline, we cannot assure this outcome. ETP cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access project.
Mont Belvieu Incident
On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL Mont Belvieu’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. Lone Star is still quantifying the extent of its incurred and ongoing damages and has or will be seeking reimbursement for these losses.
MTBE Litigation
Sunoco, Inc. and/or Sunoco, Inc. (R&M) (now known as Sunoco (R&M), LLC) 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 April 18, 2018, Sunoco, Inc. is a defendant in six cases, including one case each initiated by the States of Maryland, Vermont and Rhode Island, one by the Commonwealth of Pennsylvania and two by the Commonwealth of Puerto Rico. The


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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 Energy Transfer Partners, L.P., ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals, L.P.
Sunoco, Inc. and Sunoco, Inc. (R&M) have reached a settlement with the State of New Jersey. The Court approved the Judicial Consent Order on December 5, 2017. On April 5, 2018, the Court entered an Order dismissing the matter with prejudice.
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
Purported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to the Regency-ETP merger (the “Regency Merger”). All but one Regency Merger-related lawsuits have been dismissed. On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action complaint 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; ETE, ETP, ETP GP, and the members of Regency’s board of directors (“Defendants”).
The Regency Merger Litigation alleges that the Regency Merger breached the Regency partnership agreement because Regency’s conflicts committee was not properly formed, and the Regency Merger was not approved in good faith. On March 29, 2016, the Delaware Court of Chancery granted Defendants’ motion to dismiss the lawsuit in its entirety. Dieckman appealed. On January 20, 2017, the Delaware Supreme Court reversed the judgment of the Court of Chancery. On May 5, 2017, Plaintiff filed an Amended Verified Class Action Complaint. Defendants then filed Motions to Dismiss the Amended Complaint and a Motion to Stay Discovery on May 19, 2017. On February 20, 2018, the Court of Chancery issued an Order granting in part and denying in part the motions to dismiss, dismissing the claims against all defendants other than Regency GP, LP and Regency GP LLC. On March 6, 2018, Defendants filed their Answer to Plaintiff’s Verified Amended Class Action Complaint.
Defendants cannot predict the outcome of the Regency Merger Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can Defendants predict the amount of time and expense that will be required to resolve the Regency Merger Litigation. Defendants believe the Regency Merger Litigation is without merit and intend to vigorously defend against it and any others that may be filed in connection with the Regency Merger.
Enterprise Products Partners, L.P. and Enterprise Products Operating LLC Litigation
On January 27, 2014, a trial commenced between ETP against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc.  Trial resulted in a verdict in favor of ETP against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETP.  The jury also found that ETP owed Enterprise $1 million under a reimbursement agreement.  On July 29, 2014, the trial court entered a final judgment in favor of ETP and awarded ETP $536 million, consisting of compensatory damages, disgorgement, and pre-judgment interest.  The trial court also ordered that ETP shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recovery on its counterclaims.  Enterprise filed a notice of appeal with the Court of Appeals. On July 18, 2017, the Court of Appeals issued its opinion and reversed the trial court’s judgment. ETP’s motion for rehearing to the Court of Appeals was denied. ETP filed a petition for review with the Texas Supreme Court.
Bayou Bridge
On January 11, 2018, environmental groups and a trade association filed suit against the United States Army Corps of Engineers (the “Corps”) in the United States District Court for the Middle District of Louisiana. Plaintiffs allege that the Corps’ issuance of permits authorizing the construction of the Bayou Bridge Pipeline through the Atchafalaya Basin (“Basin”) violated the National Environmental Policy Act, the Clean Water Act, and the Rivers and Harbors Act. They asked the district court to vacate these permits and to enjoin construction of the project through the Basin until the Corps corrects alleged deficiencies in its decision-making process. ETP, through its subsidiary Bayou Bridge Pipeline, LLC (“Bayou Bridge”), intervened on January 26. On March 27, Bayou Bridge filed an answer to the complaint.
On January 29, 2018, Plaintiffs filed motions for a preliminary injunction and TRO. United States District Court Judge Shelly Dick denied the TRO on January 30 but subsequently granted the preliminary injunction on February 23. On February 26, Bayou Bridge filed a notice of appeal and a motion to stay the February 23 preliminary injunction order. On February 27, Judge Dick issued an opinion that clarified her February 23 preliminary injunction order and denied Bayou Bridge’s February


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26 motion to stay as moot. On March 1, Bayou Bridge filed a new notice of appeal and motion to stay the February 27 preliminary injunction order in the district court. On March 5, the district court denied the March 1 motion to stay the February 27 order.
On March 2, 2018, Bayou Bridge filed a motion to stay the preliminary injunction in the Fifth Circuit. On March 15, the Fifth Circuit granted a stay of injunction pending appeal and found that Bayou Bridge “is likely to succeed on the merits of its claim that the district court abused its discretion in granting a preliminary injunction.” Oral arguments were heard on the merits of the appeal, that is, whether the district court erred in granting the preliminary injunction in the Fifth Circuit on April 30, 2018.
Rover
On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (“Ohio EPA”) filed suit against Rover Pipeline, LLC (“Rover”) and Pretec Directional Drilling, LLC (“Pretec”) seeking to recover approximately $2.6 million in civil penalties allegedly owed and certain injunctive relief related to permit compliance. Laney Directional Drilling Co., Atlas Trenchless, LLC, Mears Group, Inc., and D&G Directional Drilling, Inc. d/b/a D&G Directional Drilling, LLC (collectively, with Rover and Pretec, “Defendants”) were added as defendants on April 17, 2018.
Ohio EPA alleges that the defendants illegally discharged millions of gallons of drilling fluids into Ohio’s waters that caused pollution and degraded water quality, and that the defendants harmed pristine wetlands in Stark County. Ohio EPA further alleges that Rover caused the degradation of Ohio’s waters by discharging pollution in the form of sediment-laden storm water into Ohio’s waters and that Rover violated its hydrostatic permits by discharging effluent with greater levels of pollutants than those permits allowed and by not properly sampling or monitoring effluent for required parameters or reporting those alleged violations. Rover’s answer to Ohio EPA’s complaint is due on May 17, 2018.
In January 2018, Ohio EPA sent a letter to the FERC to express concern regarding drilling fluids lost down a hole during horizontal directional drilling (“HDD”) operations as part of the Rover Pipeline construction. Rover sent a January 24 response to FERC and stated, among other things, that as Ohio EPA conceded, Rover was conducting its drilling operations in accordance with specified procedures that had been approved by FERC and reviewed by the Ohio EPA. In addition, although the HDD operations were crossing the same resource as that which led to an inadvertent release of drilling fluids in April 2017, the drill in 2018 had been redesigned since the original crossing. Ohio EPA expressed concern that the drilling fluids could deprive organisms in the wetland of oxygen. Rover, however, has now fully remediated the site, a fact with which Ohio EPA concurs.
Other Litigation and Contingencies
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 of March 31, 2018 and December 31, 2017, accruals of approximately $30 million and $33 million, respectively, were reflected on our consolidated balance sheets related to these contingent obligations. 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.
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 prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued.
On April 25, 2018, and as amended on April 30, 2018, State Senator Andrew Dinniman filed a Formal Complaint and Petition for Interim Emergency Relief (“Complaint”) against Sunoco Pipeline L.P. (“Sunoco”) before the Pennsylvania Public Utilities Commission (“PUC”). Specifically, the Complaint alleges that (i) the services and facilities provided by the Mariner East Pipeline (“ME1”, “ME2” or “ME2x”) in West Whiteland Township are unreasonable, unsafe, inadequate, and insufficient for, among other reasons, selecting an improper and unsafe route through densely populated portions of the Township with homes, schools, and infrastructure and causing inadvertent returns and sinkholes during construction because of unstable geology in the Township; (ii) Sunoco failed to warn the public of the dangers of the pipeline; (iii) the construction of ME2 and ME2x increase the risk of damage to the existing co-located ME1 pipeline; and (iv) ME1, ME2 and ME2x are not public utility facilities. Based on these allegations, Senator Dinniman’s Complaint seeks emergency relief by way of an order (i) prohibiting construction of ME2 and ME2x in West Whiteland Township; (ii) prohibiting operation of ME1; (iii) in the alternative to (i) and (ii) prohibiting the construction of ME2 and ME2x and the operation of ME1 until Sunoco fully assesses and the PUC approves the condition, adequacy, efficiency, safety, and reasonableness of those pipelines and the geology in


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which they sit; (iv) requiring Sunoco to release to the public its written integrity management plan and risk analysis for these pipelines; and (v) finding that these pipelines are not public utility facilities. In short, the relief, if granted, would continue the suspension of operation of ME1 and suspend further construction of ME2 and ME2x in West Whiteland Township. A hearing before Administrative Law Judge Elizabeth H. Barnes on the emergency relief is scheduled for May 7 and 10, 2018.
On July 25, 2017, the Pennsylvania Environmental Hearing Board (“EHB”) issued an order to SPLP to cease HDD activities in Pennsylvania related to the Mariner East 2 project.  On August 1, 2017 the EHB lifted the order as to two drill locations.  On August 3, 2017, the EHB lifted the order as to 14 additional locations.  The EHB issued the order in response to a complaint filed by environmental groups against SPLP and the Pennsylvania Department of Environmental Protection (“PADEP”).  The EHB Judge encouraged the parties to pursue a settlement with respect to the remaining HDD locations and facilitated a settlement meeting.  On August 7, 2017 a final settlement was reached.  A stipulated order has been submitted to the EHB Judge with respect to the settlement.  The settlement agreement requires that SPLP reevaluate the design parameters of approximately 26 drills on the Mariner East 2 project and approximately 43 drills on the Mariner East 2X project.  The settlement agreement also provides a defined framework for approval by PADEP for these drills to proceed after reevaluation.  Additionally, the settlement agreement requires modifications to several of the HDD plans that are part of the PADEP permits.  Those modifications have been completed and agreed to by the parties and the reevaluation of the drills has been initiated by the company.
In addition, on June 27, 2017 and July 25, 2017, the PADEP entered into a Consent Order and Agreement with SPLP regarding inadvertent returns of drilling fluids at three HDD locations in Pennsylvania related to the Mariner East 2 project.  Those agreements require SPLP to cease HDD activities at those three locations until PADEP reauthorizes such activities and to submit a corrective action plan for agency review and approval.  SPLP is working to fulfill the requirements of those agreements and has been authorized by PADEP to resume drilling at one of the three locations.
No amounts have been recorded in our March 31, 2018 or December 31, 2017 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.
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, 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 and Louisiana Department of Environmental Quality notifying Sunoco Pipeline L.P. (“SPLP”) and Mid-Valley Pipeline Company (“Mid-Valley”) that enforcement actions were being pursued for three crude oil releases: (a) an estimated 550 barrels released from the Colmesneil-to-Chester pipeline in Tyler County, Texas (“Colmesneil”) operated and owned by SPLP in February of 2013; (b) an estimated 4,509 barrels released from the Longview-to-Mayersville pipeline in Caddo Parish, Louisiana (a/k/a Milepost 51.5) operated by SPLP and owned by Mid-Valley in October of 2014; and (c) an estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma operated and owned by SPLP in January of 2015. In May of 2017, we presented to the DOJ, EPA and Louisiana Department of Environmental Quality a summary of the emergency response and remedial efforts taken by SPLP after the releases occurred as well as operational changes instituted by SPLP to reduce the likelihood of future releases. In July 2017, we had a follow-up meeting with the DOJ, EPA and Louisiana Department of Environmental Quality during which the agencies presented their initial


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demand for civil penalties and injunctive relief. In short, the DOJ and EPA proposed federal penalties totaling $7 million for the three releases along with a demand for injunctive relief, and Louisiana Department of Environmental Quality proposed a state penalty of approximately $1 million to resolve the Caddo Parish release. We are currently working on a counteroffer to the Louisiana Department of Environmental Quality, and we are involved in settlement discussion with the agencies.
On January 3, 2018, PADEP issued an Administrative Order to Sunoco Pipeline L.P. directing that work on the Mariner East 2 and 2X pipelines be stopped.  The Administrative Order detailed alleged violations of the permits issued by PADEP in February of 2017, during the construction of the project.  Sunoco Pipeline L.P. began working with PADEP representatives immediately after the Administrative Order was issued to resolve the compliance issues.  Those compliance issues could not be fully resolved by the deadline to appeal the Administrative Order, so Sunoco Pipeline L.P. took an appeal of the Administrative Order to the Pennsylvania Environmental Hearing Board on February 2, 2018.  On February 8, 2018, Sunoco Pipeline L.P. entered into a Consent Order and Agreement with PADEP that (1) withdraws the Administrative Order; (2) establishes requirements for compliance with permits on a going forward basis; (3) resolves the non-compliance alleged in the Administrative Order; and (4) conditions restart of work on an agreement by Sunoco Pipeline L.P. to pay a $12.6 million civil penalty to the Commonwealth of Pennsylvania.  In the Consent Order and agreement, Sunoco Pipeline L.P. admits to the factual allegations, but does not admit to the conclusions of law that were made by PADEP.  PADEP also found in the Consent Order and Agreement that Sunoco Pipeline L.P. had adequately addressed the issues raised in the Administrative Order and demonstrated an ability to comply with the permits. Sunoco Pipeline L.P. concurrently filed a request to the Pennsylvania Environmental Hearing Board to discontinue the appeal of the Administrative Order.  That request was granted on February 8, 2018.
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 potentially be held 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, Inc. that are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that Sunoco, Inc. no longer operates, closed and/or sold refineries and other formerly owned sites.
Sunoco, Inc. 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 March 31, 2018, Sunoco, Inc. had been named as a PRP at approximately 50 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco, Inc. is usually one of a number of companies identified as a PRP at a site. Sunoco, Inc. has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’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.
 
March 31, 2018
 
December 31, 2017
Current
$
43

 
$
36

Non-current
302

 
314

Total environmental liabilities
$
345

 
$
350



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In 2013, we 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 three months ended March 31, 2018 and 2017, the Partnership recorded $5 million and $2 million, respectively, of expenditures related to environmental cleanup programs.
On December 2, 2010, Sunoco, Inc. entered an Asset Sale and Purchase Agreement to sell the Toledo Refinery to Toledo Refining Company LLC (“TRC”) wherein Sunoco, Inc. retained certain liabilities associated with the pre-closing time period. On January 2, 2013, EPA issued a Finding of Violation (“FOV”) to TRC and, on September 30, 2013, EPA issued a Notice of Violation (“NOV”)/ FOV to TRC alleging Clean Air Act violations. To date, EPA has not issued an FOV or NOV/FOV to Sunoco, Inc. directly but some of EPA’s claims relate to the time period that Sunoco, Inc. operated the refinery. Specifically, EPA has claimed that the refinery flares were not operated in a manner consistent with good air pollution control practice for minimizing emissions and/or in conformance with their design, and that Sunoco, Inc. submitted semi-annual compliance reports in 2010 and 2011 to the EPA that failed to include all of the information required by the regulations. EPA has proposed penalties in excess of $200,000 to resolve the allegations and discussions continue between the parties. The timing or outcome of this matter 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.
Our pipeline operations are subject to regulation by the United States Department of Transportation under the PHMSA, pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the 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 Health and Safety 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
The following disclosures discuss the Partnership’s revised revenue recognition policies upon the adoption of ASU 2014-09 on January 1, 2018, as discussed in Note 1. These policies were applied to the current period only, and the amounts reflected in the Partnership’s consolidated financial statements for the three months ended March 31, 2017 were recorded under the Partnership’s previous accounting policies.
Disaggregation of revenue
The Partnership’s consolidated financial statements reflect the following six reportable segments, which also represent the level at which the Partnership aggregates revenue for disclosure purposes:
intrastate transportation and storage;
interstate transportation and storage;
midstream;
NGL and refined products transportation and services;
crude oil transportation and services; and
all other.


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Note 14 depicts the disaggregation of revenue by segment, with revenue amounts reflected in accordance with ASC Topic 606 for 2018 and ASC Topic 605 for 2017.
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.
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 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.
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 for our customers. The various types of revenue contracts our midstream segment enters into include:


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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 (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.
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.


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Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of NGL’s 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 service segment are primarily derived from provide 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.
All other revenue
Our all other segment primarily includes our compression business which provides compression services to customers engaged in the transportation of natural gas. 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. As of March 31, 2018 and January 1, 2018, no contract assets have been recognized.
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 fee for a right to use our assets, 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. As of March 31, 2018, the Partnership had $317 million in deferred revenues representing the current value of our future performance obligations.


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The amount of revenue recognized in the current period that was included in the deferred revenue liability balance as of January 1, 2018 was $42 million.
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 contacts, only the fixed component of the contracts are included in the table below.
As of March 31, 2018, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations is $35.66 billion and the Partnership expects to recognize this amount as revenue within the time bands illustrated below:
 
 
2018 (remainder)
 
2019
 
2020
 
Thereafter
 
Total
Revenue expected to be recognized on contracts with customers existing as of March 31, 2018
 
$
3,430

 
$
4,596

 
$
4,116

 
$
23,520

 
$
35,662

Practical Expedients Utilized by the Partnership
For the period ended March 31, 2018, 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.
12.
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.


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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 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:
 
March 31, 2018
 
December 31, 2017
 
Notional Volume
 
Maturity
 
Notional Volume
 
Maturity
Mark-to-Market Derivatives
 
 
 
 
 
 
 
(Trading)
 
 
 
 
 
 
 
Natural Gas (BBtu):
 
 
 
 
 
 
 
Fixed Swaps/Futures
1,008

 
2018
 
1,078

 
2018
Basis Swaps IFERC/NYMEX (1)
82,493

 
2018-2020
 
48,510

 
2018-2020
Options – Puts
13,000

 
2018
 
13,000

 
2018
Options – Calls
460

 
2018
 

 
Power (Megawatt):
 
 
 
 
 
 
 
Forwards
236,680

 
2018-2019
 
435,960

 
2018-2019
Futures
126,200

 
2018
 
(25,760
)
 
2018
Options – Puts
238,400

 
2018
 
(153,600
)
 
2018
Options – Calls
349,600

 
2018
 
137,600

 
2018
(Non-Trading)
 
 
 
 
 
 
 
Natural Gas (BBtu):
 
 
 
 
 
 
 
Basis Swaps IFERC/NYMEX
9,750

 
2018-2020
 
4,650

 
2018-2020
Swing Swaps IFERC
(24,825
)
 
2018-2019
 
87,253

 
2018-2019
Fixed Swaps/Futures
(4,620
)
 
2018-2019
 
(4,700
)
 
2018-2019
Forward Physical Contracts
(224,178
)
 
2018-2020
 
(145,105
)
 
2018-2020
Natural Gas Liquid/Crude (MBbls) – Forwards/Swaps
38,875

 
2018-2019
 
6,679

 
2018-2019
Refined Products (MBbls) – Futures
(1,219
)
 
2018-2019
 
(3,783
)
 
2018-2019
Fair Value Hedging Derivatives
 
 
 
 
 
 
 
(Non-Trading)
 
 
 
 
 
 
 
Natural Gas (BBtu):
 
 
 
 
 
 
 
Basis Swaps IFERC/NYMEX
(18,685
)
 
2018
 
(39,770
)
 
2018
Fixed Swaps/Futures
(18,685
)
 
2018
 
(39,770
)
 
2018
Hedged Item – Inventory
18,685

 
2018
 
39,770

 
2018
(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:
Term
 
Type(1)
 
Notional Amount Outstanding
March 31, 2018
 
December 31, 2017
July 2018(2)
 
Forward-starting to pay a fixed rate of 3.76% and receive a floating rate
 
$
300

 
$
300

July 2019(2)
 
Forward-starting to pay a fixed rate of 3.64% and receive a floating rate
 
300

 
300

July 2020(2)
 
Forward-starting to pay a fixed rate of 3.52% and receive a floating rate
 
400

 
400

December 2018
 
Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%
 
1,200

 
1,200

March 2019
 
Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%
 
300

 
300

(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.  
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 industrials, 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 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
 
 
March 31, 2018
 
December 31, 2017
 
March 31, 2018
 
December 31, 2017
Derivatives designated as hedging instruments:
 
 
 
 
 
 
 
 
Commodity derivatives (margin deposits)
 
$

 
$
14

 
$

 
$
(2
)
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
 
Commodity derivatives (margin deposits)
 
166

 
262

 
(206
)
 
(281
)
Commodity derivatives
 
86

 
44

 
(140
)
 
(55
)
Interest rate derivatives
 

 

 
(167
)
 
(219
)
 
 
252

 
306

 
(513
)
 
(555
)
Total derivatives
 
$
252

 
$
320

 
$
(513
)
 
$
(557
)
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
 
March 31, 2018
 
December 31, 2017
 
March 31, 2018
 
December 31, 2017
Derivatives without offsetting agreements
 
Derivative liabilities
 
$

 
$

 
$
(167
)
 
$
(219
)
Derivatives in offsetting agreements:
 
 
 
 
 
 
 
 
OTC contracts
 
Derivative assets (liabilities)
 
86

 
44

 
(140
)
 
(55
)
Broker cleared derivative contracts
 
Other current assets (liabilities)
 
166

 
276

 
(206
)
 
(283
)
Total gross derivatives
 
252

 
320

 
(513
)
 
(557
)
Offsetting agreements:
 
 
 
 
 
 
 
 
Counterparty netting
 
Derivative assets (liabilities)
 
(63
)
 
(20
)
 
63

 
20

Counterparty netting
 
Other current assets (liabilities)
 
(165
)
 
(263
)
 
165