Sunoco Logistics Partners LP--Form 10-K
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

FORM 10-K

 

 

(Mark One)

 

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2012

OR

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                     to                    

Commission file number 1-31219

 

 

SUNOCO LOGISTICS PARTNERS L.P.

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   23-3096839

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

1818 Market Street, Suite 1500, Philadelphia, PA   19103
(Address of principal executive offices)   (Zip Code)

Registrant’s telephone number, including area code: (866) 248-4344

 

 

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class

 

Name of each exchange

on which registered

Common Units representing limited
partnership interests
  New York Stock Exchange
Senior Notes 8.75%, due February 15, 2014   New York Stock Exchange
Senior Notes 6.125%, due May 15, 2016   New York Stock Exchange
Senior Notes 5.50%, due February 15, 2020   New York Stock Exchange

Senior Notes 4.65%, due February 15, 2022

Senior Notes 3.45%, due January 15, 2023

 

New York Stock Exchange

New York Stock Exchange

Senior Notes 6.85%, due February 15, 2040   New York Stock Exchange

Senior Notes 6.10%, due February 15, 2042

Senior Notes 4.95%, due January 15, 2043

 

New York Stock Exchange

New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

 

 

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Exchange Act.    Yes  x    No  ¨

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act.    Yes  ¨    No  x

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  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 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  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment of this Form 10-K.  ¨

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

 

Large accelerated filer   x    Accelerated filer   ¨
Non-accelerated filer   ¨  (Do not check if a smaller reporting company)    Smaller reporting company   ¨

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act).    Yes  ¨    No  x

The aggregate value of the Common Units held by non-affiliates of the registrant (treating all executive officers and directors of the registrant and holders of 10 percent or more of the Common Units outstanding (including the General Partner of the registrant, Sunoco Partners LLC, as if they may be affiliates of the registrant)) was $2.5 billion as of June 29, 2012, based on $36.27 per unit, the closing price of the Common Units as reported on the New York Stock Exchange on that date.

At February 28, 2013, the number of the registrant’s Common Units outstanding were 103,796,318.

DOCUMENTS INCORPORATED BY REFERENCE: NONE

 

 

 


Table of Contents

TABLE OF CONTENTS

 

PART I

       3   
   ITEM 1.    BUSINESS        3   
   ITEM 1A.    RISK FACTORS        20   
   ITEM 1B.    UNRESOLVED STAFF COMMENTS        33   
   ITEM 2.    PROPERTIES        33   
   ITEM 3.    LEGAL PROCEEDINGS        33   
   ITEM 4.    MINE SAFETY DISCLOSURES        34   

PART II

       34   
   ITEM 5.   

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SECURITYHOLDER MATTERS AND PURCHASES OF EQUITY SECURITIES

       34   
   ITEM 6.    SELECTED FINANCIAL DATA        37   
   ITEM 7.   

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

       41   
   ITEM 7A.   

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

       64   
   ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA        66   
   ITEM 9.   

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

       115   
   ITEM 9A.    CONTROLS AND PROCEDURES        115   
   ITEM 9B.    OTHER INFORMATION        115   

PART III

       116   
   ITEM 10.    DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE        116   
   ITEM 11.    EXECUTIVE COMPENSATION        120   
   ITEM 12.   

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SECURITYHOLDER MATTERS

       161   
   ITEM 13.   

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

       164   
   ITEM 14.    PRINCIPAL ACCOUNTING FEES AND SERVICES        165   

PART IV

       167   
   ITEM 15.    EXHIBITS AND FINANCIAL STATEMENT SCHEDULES        167   


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Forward-Looking Statements

This annual report on Form 10-K discusses our goals, intentions and expectations as to future trends, plans, events, results of operations or financial condition, or states other information relating to us, based on the current beliefs of our management as well as assumptions made by, and information currently available to, our management.

Words such as “may,” “anticipates,” “believes,” “expects,” “estimates,” “planned,” “scheduled” or similar phrases or expressions identify forward-looking statements. Although we believe these forward-looking statements are reasonable, they are based upon a number of assumptions, any or all of which may ultimately prove to be inaccurate. These statements are subject to numerous assumptions, uncertainties and risks that may cause future results to be materially different from the results projected, forecasted, estimated or budgeted, including, but not limited to the following:

 

   

Our ability to successfully consummate announced acquisitions or expansions and integrate them into our existing business operations;

 

   

Delays related to construction of, or work on, new or existing facilities and the issuance of applicable permits;

 

   

Changes in demand for, or supply of, crude oil and refined petroleum products that impact demand for our pipeline, terminalling and storage services;

 

   

Changes in the short-term and long-term demand for crude oil, refined petroleum products and natural gas liquids we buy and sell;

 

   

An increase in the competition encountered by our terminals, pipelines and crude oil and refined products acquisition and marketing operations;

 

   

Changes in the financial condition or operating results of joint ventures or other holdings in which we have an equity ownership interest;

 

   

Changes in the general economic conditions in the United States;

 

   

Changes in laws and regulations to which we are subject, including federal, state, and local tax, safety, environmental and employment laws;

 

   

Changes in regulations governing composition of the products that we transport, terminal and store;

 

   

Improvements in energy efficiency and technology resulting in reduced demand for refined petroleum products;

 

   

Our ability to manage growth and/or control costs;

 

   

The ability of Energy Transfer Partners, L.P. to successfully integrate our operations and employees, and realize anticipated synergies;

 

   

The effect of changes in accounting principles and tax laws and interpretations of both;

 

   

Global and domestic economic repercussions, including disruptions in the crude oil and refined petroleum products markets, from terrorist activities, international hostilities and other events, and the government’s response thereto;

 

   

Changes in the level of operating expenses and hazards related to operating facilities (including equipment malfunction, explosions, fires, spills and the effects of severe weather conditions);

 

   

The occurrence of operational hazards or unforeseen interruptions for which we may not be adequately insured;

 

   

The age of, and changes in the reliability and efficiency of our operating facilities;

 

   

Changes in the expected level of capital, operating, or remediation spending related to environmental matters;

 

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Changes in insurance markets resulting in increased costs and reductions in the level and types of coverage available;

 

   

Risks related to labor relations and workplace safety;

 

   

Non-performance by or disputes with major customers, suppliers or other business partners;

 

   

Changes in our tariff rates implemented by federal and/or state government regulators;

 

   

The amount of our debt, which could make us vulnerable to adverse general economic and industry conditions, limit our ability to borrow additional funds, place us at competitive disadvantages compared to competitors that have less debt, or have other adverse consequences;

 

   

Restrictive covenants in our credit agreements;

 

   

Changes in our or our general partner’s credit ratings, as assigned by ratings agencies;

 

   

The condition of the debt capital markets and equity capital markets in the United States, and our ability to raise capital in a cost-effective way;

 

   

Performance of financial institutions impacting our liquidity, including those supporting our credit facilities;

 

   

The effectiveness of our risk management activities, including the use of derivative financial instruments to hedge commodity risks;

 

   

Changes in interest rates on our outstanding debt, which could increase the costs of borrowing; and

 

   

The costs and effects of legal and administrative claims and proceedings against us or any entity in which we have an ownership interest, and changes in the status of, or the initiation of new litigation, claims or proceedings, to which we, or any entity in which we have an ownership interest, are a party.

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on future results. We undertake no obligation to update publicly any forward-looking statement whether as a result of new information or future events.

 

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PART I

As used in this document, unless the context otherwise indicates, the terms “we,” “us,” and “our” means Sunoco Logistics Partners L.P. (the “Partnership”), one or more of our operating subsidiaries, or all of them as a whole.

 

ITEM 1. BUSINESS

(a) General Development of Business

We are a publicly traded Delaware limited partnership that 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 and refined petroleum products. The principal executive offices of Sunoco Partners LLC, our general partner, are located at 1818 Market Street, Suite 1500, Philadelphia, Pennsylvania 19103 (telephone (866) 248-4344). Our website address is www.sunocologistics.com.

On October 5, 2012, Sunoco, Inc. (“Sunoco”) was acquired by Energy Transfer Partners, L.P. (“ETP”). Prior to this transaction, Sunoco (through its wholly-owned subsidiary Sunoco Partners LLC) served as the Partnership’s general partner and owned a two percent general partner interest, all of the Partnership’s incentive distribution rights and a 32.4 percent limited partner interest in the Partnership. In connection with the acquisition, Sunoco’s interests in the general partner and limited partnership were contributed to ETP, resulting in a change of control of the Partnership’s general partner. As a result, the Partnership became a consolidated subsidiary of ETP on the acquisition date.

(b) Financial Information about Segments

See Part II, Item 8. “Financial Statements and Supplementary Data.”

(c) Narrative Description of Business

We are a Delaware limited partnership which is principally engaged in the transport, terminalling and storage of crude oil and refined petroleum products. In addition to logistics services, we also own acquisition and marketing assets which are used to facilitate the purchase and sale of crude oil and refined products. Our portfolio of geographically diverse assets earns revenues in 30 states located throughout the United States. Our reporting segments are as follows:

 

   

The Crude Oil Pipelines transport crude oil principally in Oklahoma and Texas. The segment consists of approximately 4,900 miles of crude oil trunk pipelines and approximately 500 miles of crude oil gathering lines that supply the trunk pipelines.

 

   

The Crude Oil Acquisition and Marketing business gathers, purchases, markets and sells crude oil principally in the mid-continent United States. The segment utilizes our fleet of approximately 200 crude oil transport trucks, approximately 120 crude oil truck unloading facilities and third-party assets.

 

   

The Terminal Facilities consist of an aggregate crude oil and refined petroleum products storage capacity of approximately 40 million barrels, including the 22 million barrel Nederland, Texas crude oil terminal; the 5 million barrel Eagle Point, New Jersey refined petroleum products and crude oil terminal; approximately 40 active refined petroleum products marketing terminals located in the northeast, midwest and southwest United States; and several refinery terminals located in the northeast United States.

 

   

The Refined Products Pipelines consist of approximately 2,500 miles of refined products pipelines and joint venture interests in four refined products pipelines in selected areas of the United States.

 

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Our primary business strategies focus on generating stable cash flows, increasing pipeline and terminal throughput, utilizing our crude oil gathering assets to maximize value for producers, pursuing economically accretive organic growth opportunities and improving operating efficiencies. We believe that these strategies will result in continued increases in distributions to our unitholders.

Crude Oil Pipelines

Crude Oil Pipelines

The crude oil pipelines consist of approximately 4,900 miles of crude oil trunk pipelines and approximately 500 miles of crude oil gathering pipelines in the southwest and midwest United States. These lines primarily deliver crude oil and other feedstocks to refineries in those regions.

We completed the following acquisitions of crude oil pipelines since December 31, 2009:

 

   

West Texas Gulf Pipe Line Company—In August 2010, we acquired an additional ownership interest in West Texas Gulf Pipe Line Company (“West Texas Gulf”) from an affiliate of BP, increasing our ownership from 43.8 percent to 60.3 percent. We remain the operator of the pipeline and as we have a controlling financial interest, West Texas Gulf is reflected as a consolidated subsidiary within the Crude Oil Pipelines from the date of acquisition. West Texas Gulf owns approximately 600 miles of common carrier crude oil pipelines, which originate from the West Texas oil fields at Colorado City and extend to Longview, Texas where deliveries are made to several pipelines, including the Mid-Valley pipeline.

 

   

Mid-Valley Pipeline Company—In July 2010, we acquired an additional ownership interest in Mid-Valley Pipeline Company (“Mid-Valley”) from an affiliate of BP, increasing our ownership from 55.3 percent to 91.0 percent. We remain the operator of the pipeline and as we have a controlling financial interest, Mid-Valley is reflected as a consolidated subsidiary within the Crude Oil Pipelines from the date of acquisition. Mid-Valley owns approximately 1,000 miles of crude oil pipelines, which originate in Longview, Texas and terminate in Samaria, Michigan. Mid-Valley provides crude oil to a number of refineries, primarily in the midwest United States.

Our pipelines access several trading hubs, including the largest trading hub for crude oil in the United States located in Cushing, Oklahoma (“Cushing”), as well as other trading hubs located in Midland, Colorado City and Longview, Texas. Our crude oil pipelines also deliver to and connect with other pipelines that deliver crude oil to a number of third-party refineries.

The table below summarizes the average daily number of barrels of crude oil and other feedstocks transported on our crude oil pipelines in each of the years presented:

 

     Year Ended December 31,  
      2012      2011      2010  

Pipeline throughput (thousands of barrels per day (“bpd”))(1)(2)

     1,556         1,587         1,183   

 

(1) 

Excludes amounts attributable to equity ownership interests in corporate joint ventures which are not consolidated.

(2) 

In July and August 2010, we acquired controlling financial interests in Mid-Valley and West Texas Gulf, respectively, and we accounted for the entities as consolidated subsidiaries from the dates of their respective acquisitions. Average volumes for the year ended December 31, 2010 of 278 thousand bpd have been included in the consolidated total. From the dates of acquisition, these pipelines had actual throughput of 696 thousand bpd for the year ended December 31, 2010.

Southwest United States

Our pipelines in the southwest United States consist of approximately 2,950 miles of crude oil trunk pipelines and approximately 300 miles of crude oil gathering pipelines in Texas. The Texas system is connected

 

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to the Mid-Valley pipeline, other third-party pipelines and our Nederland Terminal. Revenues are generated from tariffs paid by shippers utilizing our transportation services. These tariffs are filed with the Railroad Commission of Texas (“Texas R.R.C.”) and the Federal Energy Regulatory Commission (“FERC”).

We also own and operate a crude oil pipeline and gathering system in Oklahoma. This system contains approximately 850 miles of crude oil trunk pipelines and approximately 200 miles of crude oil gathering pipelines. We have the ability to deliver substantially all of the crude oil gathered on our Oklahoma system to Cushing. Revenues are generated on our Oklahoma system from tariffs paid by shippers utilizing our transportation services. We file these tariffs with the Oklahoma Corporation Commission (“OCC”) and the FERC. We are one of the largest purchasers of crude oil from producers in the state, and are the primary shipper on our Oklahoma system.

Midwest United States

We are the majority owner of approximately 1,000 miles of a crude oil pipeline that originates in Longview, Texas and passes through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky and Ohio, and terminates in Samaria, Michigan. This pipeline provides crude oil to a number of refineries, primarily in the midwest United States.

In addition, we own approximately 100 miles of crude oil pipeline that runs from Marysville, Michigan to Toledo, Ohio, and a truck injection point for local production at Marysville. This pipeline receives crude oil from the Enbridge pipeline system for delivery to refineries located in Toledo, Ohio and to Marathon’s Samaria, Michigan tank farm, which supplies its refinery in Detroit, Michigan.

Revenues are generated from tariffs paid by shippers utilizing our transportation services. These tariffs are filed with the FERC.

Crude Oil Acquisition and Marketing

Our crude oil acquisition and marketing activities include the gathering, purchasing, marketing and selling of crude oil primarily in the mid-continent United States. The operations are conducted using approximately 200 crude oil transport trucks and third-party assets and approximately 120 crude oil truck unloading facilities. Specifically, the crude oil acquisition and marketing activities include:

 

   

purchasing crude oil at the wellhead from producers and in bulk from aggregators at major pipeline interconnections and trading locations;

   

storing inventory during contango market conditions (price of crude oil for future delivery is higher than current prices);

 

   

buying and selling crude oil at different locations and for different grades in order to maximize value for producers;

 

   

transporting crude oil on our pipelines and trucks or, when necessary or cost effective, pipelines or trucks owned and operated by third parties; and

 

   

marketing crude oil to major integrated oil companies, independent refiners and resellers in various types of sale and exchange transactions.

We completed the following acquisition in the crude oil acquisition and marketing business since December 31, 2009:

 

   

Crude Oil Acquisition and Marketing Business—In August 2011, we acquired a crude oil acquisition and marketing business from Texon L.P. (“Texon”) which consisted of a 75 thousand bpd crude oil purchasing business and gathering assets in 16 states, primarily in the mid-continent United States.

 

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The crude oil acquisition and marketing operations generate substantial revenue and cost of products sold as a result of the significant volume of crude oil bought and sold. However, the absolute price levels for crude oil normally do not bear a relationship to gross profit, although these price levels significantly impact revenue and cost of products sold. As a result, period-to-period variations in revenue and cost of products sold are not generally meaningful in analyzing the variation in gross profit for the crude oil acquisition and marketing operations. The operating results of the crude oil acquisition and marketing operations are dependent on our ability to sell crude oil at a price in excess of the aggregate cost. Our crude oil acquisition and marketing operations are affected by overall levels of supply and demand for crude oil and relative fluctuations in market-related indices. Generally, we expect a base level of earnings from our crude oil acquisition and marketing operations that may be optimized and enhanced when there is a high level of market volatility, favorable basis differentials and/or a steep contango or backwardated structure. Our management believes gross profit, which is equal to sales and other operating revenue less cost of products sold and operating expenses, is a key measure of financial performance for this segment. Although we implement risk management activities to provide general stability in our margins, these margins are not fixed and will vary from period to period.

We mitigate most of our pricing risk on purchase contracts by selling crude oil for an equal term on a similar pricing basis. We also mitigate most of our volume risk by entering into sales agreements, generally at the same time that purchase agreements are executed, at similar volumes. As a result, volumes sold are generally equal to volumes purchased. We do not acquire and hold futures contracts or other derivative products for the purpose of speculating on crude oil price changes, as these activities could expose us to significant losses.

Crude Oil Purchases and Exchanges

In a typical producer’s operation, crude oil flows from the wellhead to a separator where the petroleum gases are removed. After separation, the producer treats the crude oil to remove water, sediment, and other contaminants and then moves it to an on-site storage tank. When the tank is full, the producer contacts our field personnel to purchase and transport the crude oil to market. The crude oil in producers’ tanks is then either delivered directly or transported via truck to our pipeline or to a third party’s pipeline. The trucking services are performed either by our truck fleet or a third-party trucking operation.

Crude oil purchasers who buy from producers compete on the basis of price and highly responsive services. Our management believes that its ability to offer competitive pricing and high-quality field and administrative services to producers is a key factor in our ability to maintain our volume of lease purchased crude oil and to obtain new volume.

We also enter into exchange agreements to enhance margins throughout the acquisition and marketing process. When opportunities arise to increase our margin or to acquire a grade of crude oil that more nearly matches our delivery requirement or the preferences of our refinery customers, our physical crude oil is exchanged with third parties. Generally, we enter into exchanges to acquire crude oil of a desired quality in exchange for a common grade crude oil or to acquire crude oil at locations that are closer to our end-markets, thereby reducing transportation costs.

Generally, we enter into contracts with producers at market prices for a term of one year or less, with a majority of the transactions on a 30-day renewable basis. For the year ended December 31, 2012, we purchased 289 thousand bpd from approximately 4 thousand producers who comprise approximately 51 thousand active leases. We also undertook 384 thousand bpd of exchanges and bulk purchases during the same period.

 

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The following table shows our average daily volume for crude oil lease purchases and sales and other exchanges and bulk purchases for the years presented:

 

     Year Ended December 31,  
     2012      2011      2010  
     (in thousands of bpd)  

Lease purchases:

        

Available for sale

     283         215         181   

Exchanged

     6         9         8   

Other exchanges and bulk purchases

     384         439         449   
  

 

 

    

 

 

    

 

 

 

Total Purchases

     673         663         638   
  

 

 

    

 

 

    

 

 

 

Bulk Sales

     342         281         250   

Exchanges:

        

Purchased at the lease

     6         9         8   

Other

     321         370         382   
  

 

 

    

 

 

    

 

 

 

Total Sales

     669         660         640   
  

 

 

    

 

 

    

 

 

 

Crude Oil Price Volatility

Crude oil commodity prices have historically been volatile and cyclical. Profitability from our Crude Oil Acquisition and Marketing segment is dependent on our ability to sell crude oil at prices in excess of our aggregate cost. Our operations are not directly affected by the absolute level of crude oil prices, but are affected by overall levels of supply and demand for crude oil and relative fluctuations in market related indices. Generally, we expect a base level of earnings from our Crude Oil Acquisition and Marketing business, which may be optimized and enhanced when there is a high level of market volatility. Integration between our crude oil acquisition and marketing assets, crude oil pipelines and terminal facilities allows us to further improve upon earnings during periods when there are favorable basis differentials between various types of crude oils. Additionally, we are able to increase our base level of earnings when there is a steep contango or backwardated market structure.

During periods when supply exceeds the demand for crude oil in the near term, the market for crude oil is often in contango, meaning that the price of crude oil for future deliveries is higher than the price for current deliveries. A contango market generally has a negative impact on our lease gathering margins, but is favorable to commercial strategies associated with tankage. Access to our crude oil storage facilities during a contango market allows us to improve our lease gathering margins by simultaneously purchasing crude oil inventories at current prices for storage and selling forward at higher prices for future delivery.

When there is a higher demand than supply of crude oil in the near term, the market is backwardated, meaning that the price of crude oil for future deliveries is lower than the price for current deliveries. A backwardated market has a positive impact on our lease gathering margins because crude oil gatherers can capture a premium for prompt deliveries. In this environment, there is little incentive to store crude oil, as current prices are above delivery prices in the futures markets. In a backwardated market, increased lease gathering margins provide an offset to reduced use of storage capacity.

The periods between a backwardated market and a contango market are referred to as transition periods. Depending on the overall duration of these transition periods, how we have allocated our assets to particular strategies and the time length of our crude oil purchase and sale contracts and storage lease agreements, these transition periods may have either an adverse or beneficial effect on our aggregate segment profit. A prolonged transition from a backwardated market to a contango market, or vice versa (essentially a market that is neither in pronounced backwardation nor contango), represents the most difficult environment for our marketing activities.

 

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Crude Oil Trucking

We own approximately 120 crude oil truck unloading facilities in the mid-continent United States with the majority located on our pipeline system. Approximately 360 crude oil truck drivers are employed by an affiliate of our general partner and approximately 200 crude oil transport trucks and third-party assets are utilized. The crude oil truck drivers pick up crude oil at production lease sites and transport it to various truck unloading facilities on our pipelines and third-party pipelines. Third-party trucking firms are also retained to transport crude oil to certain facilities.

Terminal Facilities

The Terminal Facilities consist of an aggregate crude oil and refined petroleum products storage

capacity of approximately 40 million barrels, 41 active refined petroleum products marketing terminals located in the northeast, midwest and southwest United States and several refinery terminals located in the northeast United States.

We completed the following acquisitions in the terminalling business since December 31, 2009:

 

   

East Boston Terminal—In September 2011, we acquired a refined products terminal, located in East Boston, Massachusetts, from affiliates of ConocoPhillips. The terminal is the sole service provider to Logan International Airport under a long-term contract to provide jet fuel. The terminal includes a 10-bay truck rack and total active storage capacity for this facility is approximately 1 million barrels.

 

   

Eagle Point Tank Farm—In July 2011, we acquired the Eagle Point tank farm and related assets from Sunoco. The tank farm is located in Westville, New Jersey and consists of approximately 5 million barrels of active storage for clean products and dark oils.

 

   

Southwest Terminals—In October 2010, we acquired a crude oil and refined products terminal located in Bay City, Texas and a refined products terminal and pipeline segment located in Big Sandy, Texas. The terminals have a total capacity of less than half of a million barrels. In February 2012, we completed the sale of the Big Sandy terminal to Delek US Holdings, Inc.

 

   

Butane Blending—In July 2010, we acquired a butane blending business from Texon. The butane blending business generates profits by adding less expensive normal butane to higher priced gasoline, while complying with regional and seasonally variable specifications for maximum vapor pressure. The business provides terminal and pipeline operators with the use of proprietary automated blending systems and butane supply to optimize butane blending in pipelines and at refined products terminals. We hold U.S. patents for these systems.

Refined Products Terminals

Our 41 active refined products terminals receive refined products from pipelines, barges, railcars, and trucks and distribute them to Sunoco and to third parties, who in turn deliver them to end-users and retail outlets. Terminals are facilities where products are transferred to or from storage or transportation systems, such as a pipeline, to other transportation systems, such as trucks or other pipelines. The operation of these facilities is called “terminalling.” Terminals play a key role in moving product to the end-user markets by providing the following services: storage; distribution; blending to achieve specified grades of gasoline and middle distillates; and other ancillary services that include the injection of additives and the filtering of jet fuel. Typically, our refined products terminal facilities consist of multiple storage tanks and are equipped with automated truck loading equipment that is operational 24 hours a day. This automated system provides controls over allocations, credit, and carrier certification.

Our refined products terminals derive revenues from terminalling fees paid by customers. A fee is charged for receiving refined products into the terminal and delivering them to trucks, barges, or pipelines. In addition to terminalling fees, we generate revenues by charging customers fees for blending services, including ethanol and biodiesel blending, injecting additives, and filtering jet fuel. Our refined products pipelines supply the majority of our refined products terminals, with third-party pipelines and barges supplying the remainder.

 

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The table below summarizes the total average daily throughput for the refined products terminals in each of the years presented:

 

     Year Ended December 31,  
      2012      2011      2010  

Refined products throughput (thousands of bpd)

     487         492         488   

The following table outlines the number of active terminals and storage capacity by state:

 

State

   Number of
Terminals
     Storage
Capacity
 
            (thousands
of barrels)
 

Indiana

     1         206   

Maryland

     1         715   

Massachusetts

     1         1,160   

Michigan

     3         762   

New Jersey

     4         746   

New York(1)

     4         920   

Ohio

     7         904   

Pennsylvania

     13         1,734   

Virginia

     1         403   

Louisiana

     1         161   

Texas

     5         715   
  

 

 

    

 

 

 

Total

     41         8,426   
  

 

 

    

 

 

 

 

(1) 

We have a 45 percent ownership interest in a terminal at Inwood, New York and a 50 percent ownership interest in a terminal at Syracuse, New York. The storage capacities included in the table represent the proportionate share of capacity attributable to our ownership interests in these terminals.

Refined Products Acquisition and Marketing

With the acquisition of a butane blending business in 2010, we expanded our refined products acquisition and marketing activities. In 2011 and 2012, we continued to expand our butane blending service platform by installing our blending technology at both our refined products terminals and third-party facilities. Revenues from these activities are generated through sales of refined products which are purchased in bulk or generated through blending. The operating results of our refined products acquisition and marketing activities are dependent on our ability to execute sales in excess of the aggregate cost, and therefore we structure our acquisition and marketing operations to optimize the sources and timing of purchases and minimize the transportation and storage costs. In order to manage exposure to volatility in refined products prices, our policy is to (i) only purchase refined products for which sales contracts have been executed or for which ready markets exist, (ii) structure sales contracts so that price fluctuations do not materially impact the margins earned, and (iii) not acquire and hold physical inventory, futures contracts or other derivative instruments for the purpose of speculating on commodity price changes. However, we do utilize a seasonal hedge program involving swaps, futures and other derivative instruments to mitigate the risk associated with unfavorable market movements in the price of refined products. These derivative contracts act as a hedging mechanism against the volatility of prices.

Nederland Terminal

The Nederland Terminal, which is located on the Sabine-Neches waterway between Beaumont and Port Arthur, Texas, is a large marine terminal providing storage and distribution services for refiners and other large

 

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transporters of crude oil. The terminal receives, stores, and distributes crude oil, feedstocks, lubricants, petrochemicals, and bunker oils (used for fueling ships and other marine vessels), and also blends lubricants. The terminal currently has a total storage capacity of approximately 22 million barrels in approximately 130 aboveground storage tanks with individual capacities of up to 660 thousand barrels.

The Nederland Terminal can receive crude oil at each of its five ship docks and three barge berths. The five ship docks are capable of receiving over 2 million bpd of crude oil. In addition to our Crude Oil Pipelines, the terminal can also receive crude oil through a number of other pipelines, including:

 

   

the Cameron Highway pipeline, which is jointly owned by Enterprise Products and Genesis Energy;

 

   

the ExxonMobil Pegasus pipeline;

 

   

the Department of Energy (“DOE”) Big Hill pipeline; and

 

   

the DOE West Hackberry pipeline.

The DOE pipelines connect the terminal to the United States Strategic Petroleum Reserve’s West Hackberry caverns at Hackberry, Louisiana and Big Hill near Winnie, Texas, which have an aggregate storage capacity of approximately 400 million barrels.

The Nederland Terminal can deliver crude oil and other petroleum products via pipeline, barge, ship, rail, or truck. In total, the terminal is capable of delivering over 2 million bpd of crude oil to our Crude Oil Pipelines or a number of third-party pipelines including:

 

   

the ExxonMobil pipeline to its Beaumont, Texas refinery;

 

   

the DOE pipelines to the Big Hill and West Hackberry Strategic Petroleum Reserve caverns;

 

   

the Valero pipeline to its Port Arthur, Texas refinery; and

 

   

the Total pipelines to its Port Arthur, Texas refinery.

The table below summarizes the total average daily throughput for the Nederland Terminal in each of the years presented:

 

     Year Ended December 31,  
      2012      2011      2010  

Crude oil and refined products throughput (thousands of bpd)

     724         757         729   

Revenues are generated at the Nederland Terminal primarily by providing term or spot storage services and throughput capabilities to a number of customers.

Fort Mifflin Terminal Complex

The Fort Mifflin Terminal Complex is located on the Delaware River in Philadelphia and includes the Fort Mifflin Terminal, the Hog Island Wharf, the Darby Creek tank farm and connecting pipelines. Revenues are generated from the Fort Mifflin Terminal Complex by charging fees based on throughput. In connection with Sunoco’s decision to exit the refining business, we recognized a charge in the fourth quarter 2011 related to the Fort Mifflin Terminal Complex for asset write-downs and regulatory obligations which would have been incurred if certain terminal assets were permanently idled as substantially all of the revenues from the Fort Mifflin Terminal Complex are derived from the Philadelphia refinery. In September 2012, Sunoco completed the formation of Philadelphia Energy Solutions (“PES”), a joint venture with The Carlyle Group, which enabled the Philadelphia refinery to continue operating. In connection with this transaction, we entered into a new 10-year agreement to provide terminalling services to PES related to the Fort Mifflin Terminal Complex. In addition, we reversed certain regulatory obligations that were no longer expected to be incurred as a result of the formation of PES.

 

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The Fort Mifflin Terminal consists of two ship docks with 40-foot freshwater drafts with a total storage capacity of approximately 570 thousand barrels. Crude oil and some refined products enter the Fort Mifflin Terminal primarily from marine vessels on the Delaware River. One Fort Mifflin dock is designed to handle crude oil from very large crude carrier-class (“VLCC”) tankers and smaller crude oil vessels. The other dock can accommodate only smaller crude oil vessels.

The Hog Island Wharf is located next to the Fort Mifflin Terminal on the Delaware River and receives crude oil via two ship docks, one of which can accommodate crude oil tankers and smaller crude oil vessels and the other of which can accommodate some smaller crude oil vessels.

The Darby Creek tank farm is a primary crude oil storage terminal for the Philadelphia refinery. This facility has a total storage capacity of approximately 3 million barrels. Darby Creek receives crude oil from the Fort Mifflin Terminal and Hog Island Wharf via our pipelines. The tank farm then stores the crude oil and pumps it to the Philadelphia refinery via our pipelines.

The table below sets forth the average daily number of barrels of crude oil and refined products delivered to the Philadelphia refinery in each of the years presented:

 

     Year Ended December 31,  
      2012      2011      2010  

Crude oil throughput (thousands of bpd)

     293         267         267   

Refined products throughput (thousands of bpd)

     13         9         32   
  

 

 

    

 

 

    

 

 

 

Total (thousands of bpd)

     306         276         299   
  

 

 

    

 

 

    

 

 

 

Marcus Hook Tank Farm

The Marcus Hook tank farm has historically stored substantially all of the gasoline and middle distillates that Sunoco shipped from the Marcus Hook refinery. The tank farm has a total storage capacity of approximately 2 million barrels. After receipt of refined products from the Marcus Hook refinery, the tank farm either stored or delivered them to our Twin Oaks terminal, to the Twin Oaks pump station, an origin location for the Refined Products Pipelines, or to a third-party terminal via pipeline.

The main processing units at the Marcus Hook refinery were permanently idled in 2012 in connection with Sunoco’s exit from its refining business. We do not expect that this change will have a material impact on our results of operations, financial position or cash flows as we intend to continue utilizing the tank farm assets to provide terminalling services and to support movements on our refined products pipelines.

Eagle Point Terminal

The Eagle Point docks are located in Westville, New Jersey on the Delaware River and are connected to the Sunoco Eagle Point refinery, which was permanently shut down in the fourth quarter 2009. To compliment the services offered by our existing dock and truck loading equipment, we acquired the Eagle Point tank farm from Sunoco in July 2011. The tank farm is connected to our previously owned dock facility and allowed us to expand upon the services offered by our existing assets. The tank farm provides crude oil and refined products storage and distribution services and has a total active storage capacity of approximately 5 million barrels for clean products and dark oils. The docks can accommodate three ships or barges to receive and deliver crude oil, intermediate products and refined products to outbound ships and barges.

 

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The table below summarizes the total average daily throughput for the Eagle Point Terminal in each of the years presented:

 

     Year Ended December 31,  
      2012      2011      2010  

Crude oil throughput (thousands of bpd)

     14         4         13   

Refined products throughput (thousands of bpd)

     42         30         1   
  

 

 

    

 

 

    

 

 

 

Total (thousands of bpd)

     56         34         14   
  

 

 

    

 

 

    

 

 

 

Inkster Terminal

The Inkster Terminal, located near Detroit, Michigan, consists of eight salt caverns with a total storage capacity of approximately 975 thousand barrels. We use the Inkster Terminal’s storage in connection with our Toledo, Ohio to Sarnia, Canada pipeline system and for the storage of liquefied petroleum gases (“LPGs”) from Canada and a refinery in Toledo, which was sold by Sunoco to PBF Holding Company LLC in the first quarter of 2011. The terminal can receive and ship LPGs in both directions at the same time and has a propane truck loading rack.

Refined Products Pipelines

Refined Products Pipelines

We own and operate approximately 2,500 miles of refined products pipelines in selected areas of the United States. The refined products pipelines transport refined products from refineries in the northeast, midwest and southwest United States to markets in New York, New Jersey, Pennsylvania, Ohio, Michigan and Texas. The refined products transported in these pipelines include multiple grades of gasoline, middle distillates (such as heating oil, diesel and jet fuel) and LPGs (such as propane and butane). Rates for shipments on the Refined Products Pipelines are regulated by the FERC and the Pennsylvania Public Utility Commission (“PA PUC”), among other state regulatory agencies.

Since December 31, 2009, we completed the following acquisitions of refined products pipelines:

 

   

Inland Corporation—In May 2011, we acquired an 83.8 percent equity interest in Inland Corporation (“Inland”) from Sunoco and Shell Oil Company. Inland is the owner of 350 miles of active refined products pipelines in Ohio. The pipeline connects three refineries in Ohio to terminals and major markets in Ohio. As we have a controlling financial interest in Inland, the joint venture is reflected as a consolidated subsidiary in our consolidated financial statements. We assumed operatorship of the pipeline during 2012.

 

   

West Shore Pipe Line Company—In July 2010, we acquired from an affiliate of BP an additional 4.8 percent interest in West Shore Pipe Line Company (“West Shore”), a joint venture that owns approximately 650 miles of common carrier refined products pipelines, increasing our ownership interest from 12.3 percent to 17.1 percent. The system, which is operated by Buckeye Partners, L.P., originates from the Chicago, Illinois refining center and extends to Madison and Green Bay, Wisconsin with delivery points along the way.

 

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The following table shows the average shipments on the refined products pipelines in each of the years presented. Average shipments represent the average revenue-generating pipeline throughput:

 

     Year Ended
December 31,
 
      2012      2011      2010  

Pipeline throughput (thousands of bpd)(1)(2)

     582         522         468   

 

(1) 

Excludes amounts attributable to equity ownership interests in corporate joint ventures which are not consolidated.

(2) 

In May 2011, we acquired a controlling financial interest in Inland and we accounted for the entity as a consolidated subsidiary from the date of acquisition. Average volumes for the year ended December 31, 2011 of 88 thousand bpd have been included in the consolidated total. From the date of acquisition, this pipeline had actual throughput of 140 thousand bpd for the year ended December 31, 2011.

The mix of refined products delivered varies seasonally, with gasoline demand peaking during the summer months, and demand for heating oil and other distillate fuels peaking in the winter. In addition, weather conditions in the areas served by the Refined Products Pipelines affect both the demand for, and the mix of, the refined products delivered through the Refined Products Pipelines, although historically any overall impact on the total volume shipped has been short term.

Joint Ventures

We own equity interests in several common carrier refined products pipelines, summarized in the following table:

 

Pipeline

   Equity
Ownership
    Approximate
Pipeline
Mileage
 

Explorer Pipeline Company(1)

     9.4     1,850   

Yellowstone Pipe Line Company(2)

     14.0     700   

West Shore Pipe Line Company(3)

     17.1     650   

Wolverine Pipe Line Company(4)

     31.5     700   

 

(1) 

The system, which is operated by Explorer employees, originates from the refining centers of Lake Charles, Louisiana and Beaumont, Port Arthur and Houston, Texas, and extends to Chicago, Illinois, with delivery points in the Houston, Dallas/Fort Worth, Tulsa, St. Louis, and Chicago areas. Explorer charges market-based rates for all its tariffs.

(2) 

The system, which is operated by Phillips 66, originates from the Billings, Montana refining center and extends to Moses Lake, Washington with delivery points along the way. Tariff rates are regulated by the FERC for interstate shipments and the Montana Public Service Commission for intrastate shipments in Montana.

(3) 

The system, which is operated by Buckeye, originates from the Chicago, Illinois refining center and extends to Madison and Green Bay, Wisconsin with delivery points along the way. West Shore charges market-based tariff rates in the Chicago area.

(4) 

The system, which is operated by Wolverine employees, originates from Chicago, Illinois and extends to Detroit, Grand Haven, and Bay City, Michigan with delivery points along the way. Wolverine charges market-based rates for tariffs at the Detroit, Jackson, Niles, Hammond, and Lockport destinations.

Pipeline and Terminal Control Operations

Almost all of our refined products and crude oil pipelines are operated via satellite, microwave, and frame relay communication systems from central control rooms located in Montello, Pennsylvania and Sugar Land,

 

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Texas. The Montello control center primarily monitors and controls our Refined Products Pipelines, and the Sugar Land control center primarily monitors and controls our Crude Oil Pipelines. The Nederland Terminal has its own control center.

The control centers operate with Supervisory Control and Data Acquisition, or SCADA, systems that continuously monitor real time operational data, including refined product and crude oil throughput, flow rates, and pressures. In addition, the control centers monitor alarms and throughput balances. The control centers operate remote pumps, motors and valves associated with the delivery of refined products and crude oil. The computer systems are designed to enhance leak-detection capabilities, sound automatic alarms if operational conditions outside of pre-established parameters occur, and provide for remote-controlled shutdown of pump stations on the pipelines. Pump stations and meter-measurement points along our pipelines are linked by satellite or telephone communication systems for remote monitoring and control, which reduces the requirement for full-time on-site personnel at most of these locations.

Competition

Crude Oil Pipelines

Our Crude Oil Pipelines face competition from a number of major oil companies and other smaller entities. Competition among common carrier pipelines is based primarily on transportation charges, access to crude oil supply and market demand, which may be negatively impacted by changes in refiners’ supply sources. Additional investment in rail infrastructure to transport crude oil has also provided increased competition for crude oil pipelines.

Crude Oil Acquisition and Marketing

Our competitors include other crude oil pipeline companies, the major integrated oil companies, their marketing affiliates and independent gatherers, banks that have established trading platforms, brokers and marketers of widely varying sizes, financial resources and experience. Some of these competitors have capital resources many times greater than ours, and control greater supplies of crude oil. Crude oil acquisition and marketing competitive factors include price and contract flexibility, quantity and quality of services, and accessibility to end markets.

Terminal Facilities

The majority of the throughput at our crude oil terminal facilities in the northeast has historically been related to Sunoco’s refining operations. In connection with the formation of PES, we entered into a new 10-year agreement to provide terminalling services to PES related to the Fort Mifflin Terminal Complex. For further information on the impact, see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Agreements with Related Parties.”

Throughput at the Nederland Terminal is primarily related to third-party customers. The primary competitors of the Nederland Terminal are its refinery customers’ docks and other terminal facilities located in the Beaumont, Texas area.

Our 41 active refined products terminals located in the northeast, midwest and southwest compete with other independent terminals on price, versatility, and services provided. The competition primarily comes from integrated petroleum companies, refining and marketing companies, independent terminal companies, and distribution companies with marketing and trading activities. We are not aware of any direct competitors in the butane blending business in the United States and our patents provide us exclusive use and control over the distribution of our butane blending technology.

 

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Refined Products Pipelines

A substantial portion of the Refined Products Pipelines are located in the northeast United States and were constructed or acquired to distribute refined products to Sunoco’s retail network. While Sunoco completed the exit from its refining business in 2012, Sunoco continues to operate its retail marketing network and we expect that Sunoco will continue to utilize our Refined Products Pipelines as an efficient means to meet its retail marketing demand. For further information on the impact, see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Agreements with Related Parties.”

Generally, pipelines are the lowest cost method for long-haul, overland movement of refined products. Therefore, the most significant competitors for large volume shipments in these areas are other pipelines. Our management believes that high capital requirements, environmental considerations, and the difficulty in acquiring rights-of-way and related permits make it difficult for other companies to build competing pipelines in areas served by our pipelines. As a result, competing pipelines are likely to be built only in those cases in which strong market demand and attractive tariff rates support additional capacity in an area. Although it is unlikely that a pipeline system comparable in size and scope to the northeast and midwest portion of the Refined Products Pipelines will be built in the foreseeable future, new pipelines (including pipeline segments that connect with existing pipeline systems) could be built to effectively compete with it in particular locations.

In the southwest United States, our MagTex refined products pipeline system faces competition from existing third-party owned and joint venture pipelines that have excess capacity. Gulf Coast refinery expansions could justify the construction of a new pipeline that would compete with our refined products pipeline system in the southwest. However, at this time, we believe the existing pipelines have the capacity to satisfy expected future demand.

In addition to competition from other pipelines, we face competition from trucks that deliver refined products in a number of areas that we serve. While their costs may not be competitive for longer hauls or large volume shipments, trucks compete effectively for incremental and marginal volume in many areas where such means of transportation are prevalent. The availability of truck transportation places a significant competitive constraint on our ability to increase tariff rates.

Safety Regulation

A majority of our pipelines are subject to United States Department of Transportation (“DOT”) regulations and to regulations under comparable state statutes relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities.

DOT regulations require operators of hazardous liquid interstate pipelines to develop and follow a program to assess the integrity of all pipeline segments that could affect designated “high consequence areas,” including: high population areas, drinking water and ecological resource areas that are unusually sensitive to environmental damage from a pipeline release, and commercially navigable waterways. We have prepared our own written Risk Based Integrity Management Program, identified the line segments that could impact high consequence areas and completed a full assessment of these segments as prescribed by the regulations.

We believe that our pipeline operations are in substantial compliance with applicable DOT regulations and comparable state requirements. However, an increase in expenditures may be needed in the future to comply with higher industry and regulatory safety standards. Such expenditures cannot be estimated accurately at this time, but we do not believe they would likely have a material adverse effect relative to our results of operations, financial position or expected cash flows.

 

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Environmental Regulation

General

Our operations are subject to complex federal, state, and local laws and regulations relating to the protection of health and the environment, including laws and regulations which govern the handling and release of crude oil and other liquid hydrocarbon materials, some of which are discussed below. Violations of environmental laws or regulations can result in the imposition of significant administrative, civil and criminal fines and penalties and, in some instances, injunctions banning or delaying certain activities. Our management believes we are in substantial compliance with applicable environmental laws and regulations. However, these laws and regulations are subject to frequent change at the federal, state and local levels, and the trend is to place increasingly stringent limitations on activities that may affect the environment.

There are also risks of accidental releases into the environment associated with our operations, such as releases of crude oil or hazardous substances from our pipelines or storage facilities. To the extent an event is not covered by our insurance policies, such accidental releases could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for any related violations of environmental laws or regulations.

Sunoco indemnifies us for 100 percent of all losses from environmental liabilities related to the transferred assets arising prior to, and asserted within 21 years of, February 8, 2002, the date of our initial public offering (“IPO”). There is no monetary cap on this indemnification from Sunoco. Sunoco’s share of liability for claims asserted thereafter will decrease by 10 percent each year through the thirtieth year following the IPO date. In addition, this indemnification applies to the following, purchased from Sunoco subsequent to the IPO: interests in the Mesa Pipeline System, Mid-Valley, West Texas Gulf and Inland, as well as the Eagle Point tank farm. Any remediation liabilities not covered by this indemnity will be our responsibility.

We have agreed to indemnify Sunoco and its affiliates for events and conditions associated with the operation of the transferred assets occurring after the IPO date, and for environmental and toxic tort liabilities related to these assets to the extent Sunoco is not required to indemnify us. Total future costs for environmental remediation activities will depend upon, among other things, the extent of impact at each site, the timing and nature of required remedial actions, the technology available, and the determination of our liability at multi-party sites. As of December 31, 2012, all material environmental liabilities incurred by, and known to, us are either covered by the environmental indemnification or reserved for by us in our consolidated financial statements.

Air Emissions

Our operations are subject to the Clean Air Act, as amended, and comparable state and local statutes. We will be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing air emission related issues. In addition, the federal government has enacted regulations relating to restrictions on emissions of greenhouse gases (“GHGs”). At this time, our operations do not fall under any of the current GHG regulations. While the effect of these current regulations will not impact our operations, the federal, regional or state laws or regulations limiting emissions of GHGs in the United States could adversely affect the demand for crude oil or refined products transportation and storage services as well as contribute to increased compliance costs or additional operating restrictions.

Our customers are also subject to, and similarly affected by, environmental regulations. These include federal and state actions to develop programs for the reduction of GHG emissions as well as proposals that would create a cap and trade system that would require companies to purchase carbon emission allowances for emissions at manufacturing facilities and emissions caused by the use of the fuels sold. In addition, the Environmental Protection Agency (“EPA”) indicated that it intends to regulate carbon dioxide emissions. As a

 

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result of these regulations, our customers could be required to make significant capital expenditures, operate refineries at reduced levels, and pay significant penalties. It is uncertain what our customers’ responses to these emerging issues will be. Those responses could reduce throughput in our pipelines and terminals, cash flow, and our ability to make distributions or satisfy debt obligations.

Hazardous Substances and Waste

In the course of ordinary operations, we may generate waste that falls within the Comprehensive Environmental Response, Compensation, and Liability Act’s, referred to as CERCLA and also known as Superfund, definition of a “hazardous substance” and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. Costs for any such remedial actions, as well as any related claims, could have a material adverse effect on our maintenance capital expenditures and operating expenses to the extent not all are covered by the indemnity from Sunoco. For more information, please see “Environmental Remediation.”

We also generate solid wastes, including hazardous wastes that are subject to the requirements of the Federal Resource Conservation and Recovery Act, referred to as RCRA, and comparable state statutes. We are not currently required to comply with a substantial portion of the RCRA requirements because our operations generate minimal quantities of hazardous wastes. However, it is possible that additional wastes, which could include wastes currently generated during our operating activities, will in the future be designated as “hazardous wastes.” Hazardous wastes are subject to more rigorous and costly disposal requirements than non-hazardous wastes. Any changes in the regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses.

We currently own or lease properties where hydrocarbons are being or have been handled for many years. These properties and wastes disposed thereon may be subject to CERCLA, RCRA, and comparable state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater), or to perform remedial operations to prevent future contamination.

We have not been identified by any state or federal agency as a potentially responsible party in connection with the transport and/or disposal of any waste products to third-party disposal sites.

Water

Our operations can result in the discharge of regulated substances, including crude oil or refined products. The Federal Water Pollution Control Act of 1972, also known as the Clean Water Act, and comparable state laws impose restrictions and strict controls regarding the discharge of regulated substances into state waters or waters of the United States. Where applicable, our facilities have the required discharge permits.

The Oil Pollution Act subjects owners of covered facilities to strict joint and potentially unlimited liability for removal costs and other consequences of a release of oil, where the release is into navigable waters, along shorelines or in the exclusive economic zone of the United States. Spill prevention control and countermeasure requirements of the Clean Water Act and some state laws require that containment dikes and similar structures be installed to help prevent the impact on navigable waters in the event of a release. The Office of Pipeline Safety of the DOT, the EPA, or various state regulatory agencies, has approved our oil spill emergency response plans, and our management believes we are in substantial compliance with these laws.

In addition, some states maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Our management believes that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our results of operations, financial position or expected cash flows.

 

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Environmental Remediation

Contamination resulting from releases of refined products and crude oil is not unusual within the petroleum pipeline industry. Historic releases along our pipelines, gathering systems, and terminals as a result of past operations have resulted in impacts to the environment, including soils and groundwater. Site conditions, including soils and groundwater, are being evaluated at a number of properties where operations may have resulted in releases of hydrocarbons and other wastes. Sunoco has agreed to indemnify us from environmental and toxic tort liabilities related to the assets transferred to the extent such liabilities existed or arose from operation of these assets prior to the closing of the February 2002 IPO and are asserted within 30 years after the closing of the IPO. This indemnity will cover the costs associated with performance of the assessment, monitoring, and remediation programs, as well as any related claims and penalties. See “Environmental Regulation—General.”

We have experienced several petroleum and refined product releases for which we are not covered by an indemnity from Sunoco, and for which we are responsible for necessary assessment, remediation, and/or monitoring activities. Our management estimates that the total aggregate cost of performing the currently anticipated assessment, monitoring, and remediation activities at these sites is not material in relation to our operations, financial position or cash flows at December 31, 2012. We have implemented an extensive inspection program to prevent releases of refined products or crude oil into the environment from our pipelines, gathering systems, and terminals. Any damages and liabilities incurred due to future environmental releases from our assets have the potential to substantially affect our business and our ability to generate the cash flow necessary to make distributions or satisfy debt obligations.

Rate Regulation

General Interstate Regulation

Interstate common carrier pipeline operations are subject to rate regulation by the FERC under the Interstate Commerce Act, the Energy Policy Act of 1992, and related rules and orders. The Interstate Commerce Act requires that tariff rates for petroleum pipelines be “just and reasonable” and not unduly discriminatory. This statute also permits interested persons to challenge proposed new or changed rates and authorizes the FERC to suspend the effectiveness of such rates for up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund revenues in excess of the prior tariff during the term of the investigation. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.

The FERC generally has not investigated interstate rates on its own initiative when those rates, like those we charge, have not been the subject of a protest or a complaint by a shipper. However, the FERC could investigate our rates at the urging of a third party if the third party is either a current shipper or has a substantial economic interest in the tariff rate level. Although no assurance can be given that the tariffs charged by us ultimately will be upheld if challenged, management believes that the tariffs now in effect for our pipelines are within the maximum rates allowed under current FERC guidelines.

We have been approved by the FERC to charge market-based rates in most of the refined products locations served by our pipeline systems. In those locations where market-based rates have been approved, we are able to establish rates that are based upon competitive market conditions.

Intrastate Regulation

Some of our pipeline operations are subject to regulation by the Texas R.R.C., the PA PUC, and the OCC. The operations of our joint venture interests are also subject to regulation in the states in which they operate. The

 

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applicable state statutes require that pipeline rates be nondiscriminatory and provide no more than a fair return on the aggregate value of the pipeline property used to render services. State commissions generally have not initiated an investigation of rates or practices of petroleum pipelines in the absence of shipper complaints. Complaints to state agencies have been infrequent and are usually resolved informally. Although management cannot be certain that our intrastate rates ultimately would be upheld if challenged, we believe that, given this history, the tariffs now in effect are not likely to be challenged or, if challenged, are not likely to be ordered to be reduced.

Title to Properties

Substantially all of our pipelines were constructed on rights-of-way granted by the apparent record owners of the property and in limited instances these rights-of-way are revocable at the election of the grantor. Several rights-of-way for the pipelines and other real property assets are shared with other pipelines and other assets owned by affiliates of Sunoco and by third parties. In many instances, lands over which rights-of-way have been obtained are subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained permits from public authorities to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, and state highways and, in some instances, these permits are revocable at the election of the grantor. We have also obtained permits from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election. In some cases, property for pipeline purposes was purchased in fee. In some states and under some circumstances, we have the right of eminent domain to acquire rights-of-way and lands necessary for the common carrier pipelines. The previous owners of the applicable pipelines may not have commenced or concluded eminent domain proceedings for some rights-of-way.

Some of the leases, easements, rights-of-way, permits, and licenses acquired by us or transferred to us upon the closing of the IPO require the consent of the grantor to transfer these rights, which in some instances is a governmental entity. We have obtained or are in the process of obtaining third-party consents, permits, and authorizations sufficient for the transfer of the assets necessary to operate the business in all material respects. In our opinion, with respect to any consents, permits, or authorizations that have not been obtained, the failure to obtain them will not have a material adverse effect on the operation of our business.

We have satisfactory title to substantially all of the assets contributed in connection with the IPO. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with acquisition of real property, liens for environmental contamination, taxes and other burdens, easements, or other restrictions, management believes that none of these burdens materially detract from the value of the properties or will materially interfere with their use in the operation of our business.

Employees

We have no employees. To carry out the operations of Sunoco Logistics Partners L.P., our general partner and its affiliates employed approximately 1,700 people at December 31, 2012 who provide direct support to the operations. Labor unions or associations represent approximately 800 of these employees at December 31, 2012.

(d) Financial Information about Geographical Areas

We have no significant amount of revenue or segment profit or loss attributable to international activities.

(e) Available Information

We make available, free of charge on our website, www.sunocologistics.com, all materials that we file electronically with the Securities Exchange Commission, including our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after such materials are electronically filed with, or furnished to, the SEC.

 

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ITEM 1A.     RISK FACTORS

We believe that the following risk factors address the known material risks related to our business, partnership structure and debt obligations, as well as the material tax risks to our common unitholders. If any of the following risks were to actually occur, our business, results of operations, financial condition and cash flows as well as any related benefits of owning our securities, could be materially and adversely affected.

On October 5, 2012, Sunoco, Inc. (“Sunoco”) was acquired by Energy Transfer Partners, L.P. (“ETP”). Prior to this transaction, Sunoco (through its wholly-owned subsidiary Sunoco Partners LLC) served as the Partnership’s general partner and owned a two percent general partner interest, all of the incentive distribution rights and a 32.4 percent limited partner interest in the Partnership. In connection with the acquisition, Sunoco’s interests in the general partner, including the incentive distribution rights, and limited partnership were contributed to ETP. This resulted in a change in control of the general partner, and as a result, the Partnership became a consolidated subsidiary of ETP on the acquisition date.

The risk factor information presented below reflects the impacts of these transactions, including the change in the general partner ownership, and the ongoing business implications.

RISKS RELATED TO OUR BUSINESS

If we are unable to generate sufficient cash flow, our ability to pay quarterly distributions to our common unitholders at current levels or to increase our quarterly distributions in the future, could be materially impaired.

Our ability to pay quarterly distributions depends primarily on cash flow, including cash flow from financial reserves and credit facilities, and not solely on profitability, which is affected by non-cash items. As a result, we may pay cash distributions during periods when we record net losses and may be unable to pay cash distributions during periods when we record net income. Our ability to generate sufficient cash from operations is largely dependent on our ability to successfully manage our business which may also be affected by economic, financial, competitive, and regulatory factors that are beyond our control. To the extent we do not have adequate cash reserves, our ability to pay quarterly distributions to our common unitholders at current levels could be materially impaired.

An increase in interest rates may cause the market price of our units to decline.

Like all equity investments, an investment in our units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited partnership interests. Reduced demand for our units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our units to decline.

We depend upon Sunoco for a substantial portion of the volumes transported on our refined products pipelines and handled at our terminals. If Sunoco were to significantly reduce these volumes, it could materially and adversely affect our results of operations, financial condition or cash flows.

Our refined products pipelines and terminal assets provide an efficient outlet to supply Sunoco’s retail marketing network, and as such, we expect that Sunoco will continue to utilize our assets going forward. However, if Sunoco were to reduce its use of our facilities, it could adversely affect our results of operations, financial condition, or cash flows.

 

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A sustained decrease in demand for refined products in the markets served by our pipelines and terminals could materially and adversely affect our results of operations, financial position, or cash flows.

The following are material factors that could lead to a sustained decrease in market demand for refined products:

 

   

a sustained recession or other adverse economic condition that results in lower purchases of refined petroleum products;

 

   

higher refined products prices due to an increase in the market price of crude oil, changes in economic conditions, or other factors;

 

   

higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline or other refined products;

 

   

a shift by consumers to more fuel-efficient or alternative fuel vehicles or an increase in fuel economy, whether as a result of technological advances by manufacturers, pending legislation proposing to mandate higher fuel economy, or otherwise; and

 

   

a temporary or permanent material increase in the price of refined products as compared to alternative sources of refined products available to our customers.

A material decrease in demand or distribution of crude oil available for transport through our pipelines or terminal facilities could materially and adversely affect our results of operations, financial position, or cash flows.

The volume of crude oil transported through our crude oil pipelines and terminal facilities depends on the availability of attractively priced crude oil produced or received in the areas serviced by our assets. A period of sustained crude oil price declines could lead to a decline in drilling activity, production and import levels in these areas. Similarly, a period of sustained increases in the price of crude oil supplied from any of these areas, as compared to alternative sources of crude oil available to our customers, could materially reduce demand for crude oil in these areas. In either case, the volumes of crude oil transported in our crude oil pipelines and terminal facilities could decline, and it could likely be difficult to secure alternative sources of attractively priced crude oil supply in a timely fashion or at all. If we are unable to replace any significant volume declines with additional volumes from other sources, our results of operations, financial position, or cash flows could be materially and adversely affected.

Any reduction in the capability of our shippers to utilize either our pipelines or interconnecting third-party pipelines could cause a reduction of volumes transported in our pipelines and through our terminals.

Users of our pipelines and terminals are dependent upon our pipelines, as well as connections to third-party pipelines, to receive and deliver crude oil and refined products. Any interruptions or reduction in the capabilities of our pipelines or these interconnecting pipelines due to testing, line repair, reduced operating pressures, or other causes would result in reduced volumes transported in our pipelines or through our terminals. Similarly, if additional shippers begin transporting volume over interconnecting pipelines, the allocations to our existing shippers on these interconnecting pipelines could be reduced, which also could reduce volumes transported in our pipelines or through our terminals. Allocation reductions of this nature are not infrequent and are beyond our control. Any such interruptions or allocation reductions that, individually or in the aggregate, are material or continue for a sustained period of time could have a material adverse effect on our results of operations, financial position, or cash flows.

If we are unable to complete capital projects at their expected costs and/or in a timely manner, or if the market conditions assumed in our project economics deteriorate, our results of operations, financial condition, or cash flows could be affected materially and adversely.

Delays or cost increases related to capital spending programs involving construction of new facilities (or improvements and repairs to our existing facilities) could adversely affect our ability to achieve forecasted

 

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operating results. Although we evaluate and monitor each capital spending project and try to anticipate difficulties that may arise, such delays or cost increases may arise as a result of factors that are beyond our control, including:

 

   

denial or delay in issuing requisite regulatory approvals and/or permits;

 

   

unplanned increases in the cost of construction materials or labor;

 

   

disruptions in transportation of modular components and/or construction materials;

 

   

severe adverse weather conditions, natural disasters, or other events (such as equipment malfunctions explosions, fires, spills) affecting our facilities, or those of vendors and suppliers;

 

   

shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;

 

   

changes in market conditions impacting long lead-time projects;

 

   

market-related increases in a project’s debt or equity financing costs; and

 

   

nonperformance by, or disputes with, vendors, suppliers, contractors, or sub-contractors involved with a project.

Our forecasted operating results also are based upon our projections of future market fundamentals that are not within our control, including changes in general economic conditions, availability to our customers of attractively priced alternative supplies of crude oil and refined products and overall customer demand.

An impairment of goodwill and intangible assets could reduce our earnings.

At December 31, 2012, our consolidated balance sheet reflected $1.37 billion of goodwill and $843 million of intangible assets. Accounting principles generally accepted in the United States require us to test goodwill for impairment on an annual basis or when events or circumstances occur, indicating that goodwill might be impaired. Long-lived assets such as intangible assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If we determine that any of our goodwill or intangible assets were impaired, we would be required to take an immediate charge to earnings with a correlative effect on partners’ capital and balance sheet leverage as measured by debt to total capitalization.

Future acquisitions and expansions may increase substantially the level of our indebtedness and contingent liabilities, and we may be unable to integrate them effectively into our existing operations.

We evaluate and acquire assets and businesses that we believe complement or diversify our existing assets and businesses. Acquisitions may require substantial capital or the incurrence of substantial indebtedness. If we consummate any future material acquisitions, our capitalization and results of operations may change significantly.

Acquisitions and business expansions, including the integration with our new general partner, involve numerous risks, including difficulties in the assimilation of the assets and operations of the acquired businesses, inefficiencies and difficulties that arise because of unfamiliarity with new assets, new geographic areas and the businesses associated with them. Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined and we may experience unanticipated delays in realizing the benefits of an acquisition. In some cases, we have indemnified the previous owners and operators of acquired assets.

Following an acquisition, we may discover previously unknown liabilities associated with the acquired business for which we have no recourse under applicable indemnification provisions. In addition, the terms of an acquisition may require us to assume certain prior known or unknown liabilities for which we may not be indemnified or have adequate insurance.

 

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Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.

Our operations and those of our customers and suppliers may be subject to operational hazards or unforeseen interruptions such as natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, and other events beyond our control. If one or more of the facilities that we own, or any third-party facilities that we receive from or deliver to, are damaged by any disaster, accident, catastrophe or other event, our operations could be significantly interrupted. These interruptions might involve a loss of equipment or life, injury, extensive property damage, or maintenance and repair outages. The duration of the interruption will depend on the seriousness of the damages or required repairs. We may not be able to maintain or obtain insurance to cover these types of interruptions, or in coverage amounts desired, at reasonable rates. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Any event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could materially and adversely affect our results of operations, financial position, or cash flows.

We are exposed to the credit and other counterparty risk of our customers in the ordinary course of our business.

We have various credit terms with virtually all of our customers, and our customers have varying degrees of creditworthiness. Although we evaluate the creditworthiness of each of our customers, we may not always be able to fully anticipate or detect deterioration in their creditworthiness and overall financial condition, which could expose us to an increased risk of nonpayment or other default under our contracts and other arrangements with them. In the event that a material customer or customers default on their payment obligations to us, this could materially and adversely affect our results of operations, financial position, or cash flows.

Mergers among our customers and competitors could result in lower volumes being shipped on our pipelines or products stored in or distributed through our terminals, or reduced crude oil marketing margins or volumes.

Mergers between existing customers could provide strong economic incentives for the combined entities to utilize their existing systems instead of ours in those markets where the systems compete. As a result, we could lose some or all of the volumes and associated revenues from these customers and we could experience difficulty in replacing those lost volumes and revenues, which could materially and adversely affect our results of operations, financial position, or cash flows.

Rate regulation or market conditions may not allow us to recover the full amount of increases in our costs. Additionally, a successful challenge to our rates could materially and adversely affect our results of operations, financial position, or cash flows.

The primary rate-making methodology of the Federal Energy Regulatory Commission (“FERC”) is price indexing. We use this methodology in many of our interstate markets. In an order issued in December 2010, the FERC announced that, effective July 1, 2011, the index would equal the change in the producer price index for finished goods plus 2.65 percent (previously, the index was equal to the change in the producer price index for finished goods plus 1.3 percent). This index is to be in effect through July 2016. If the changes in the index are not large enough to fully reflect actual increases to our costs, our financial condition could be adversely affected. If the index results in a rate increase that is substantially in excess of the pipeline’s actual cost increases, or it results in a rate decrease that is substantially less than the pipeline’s actual cost decrease, the rates may be protested, and, if successful, result in the lowering of the pipeline’s rates. The FERC’s rate-making methodologies may limit our ability to set rates based on our true costs or may delay the use of rates that reflect increased costs.

 

 

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Under the Energy Policy Act adopted in 1992, certain interstate pipeline rates were deemed just and reasonable or “grandfathered.” On our FERC-regulated pipelines, most of our revenues are derived from such grandfathered rates. A person challenging a grandfathered rate must, as a threshold matter, establish a substantial change since the date of enactment of the Act, in either the economic circumstances or the nature of the service that formed the basis for the rate. If the FERC were to find a substantial change in circumstances, then the existing rates could be subject to detailed review. There is a risk that some rates could be found to be in excess of levels justified by our cost of service. In such event, the FERC would order us to reduce rates prospectively and could order us to pay reparations to shippers. Reparations could be required for a period of up to two years prior to the date of filing the complaint in the case of rates that are not grandfathered and for the period starting with the filing of the complaint in the case of grandfathered rates.

In addition, a state commission could also investigate our intrastate rates or terms and conditions of service on its own initiative or at the urging of a shipper or other interested party. If a state commission found that our rates exceeded levels justified by our cost of service, the state commission could order us to reduce our rates.

Potential changes to current rate-making methods and procedures may impact the federal and state regulations under which we will operate in the future. In addition, if the FERC’s petroleum pipeline rate-making methodology changes, the new methodology could materially and adversely affect our results of operations, financial position, or cash flows.

Our operations are subject to federal, state, and local laws and regulations relating to environmental protection and operational safety that could require substantial expenditures.

Our pipelines, gathering systems, and terminal operations are subject to increasingly strict environmental and safety laws and regulations. The transportation and storage of refined products and crude oil result in a risk that refined products, crude oil, and other hydrocarbons may be suddenly or gradually released into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies for natural resource damages, personal injury, or property damage to private parties and significant business interruption. We own or lease a number of properties that have been used to store or distribute refined products and crude oil for many years. Many of these properties also have been previously owned or operated by third parties whose handling, disposal, or release of hydrocarbons and other wastes were not under our control, and for which, in some cases, we have indemnified the previous owners and operators.

Failure to comply with these laws and regulations may result in assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens and, to a lesser extent, issuance of injunctions to limit or cease operations. We may be unable to recover these costs through increased revenues.

Our business is subject to federal, state and local laws and regulations that govern the product quality specifications of the petroleum products that we store and transport.

The petroleum products that we store and transport are sold by our customers for consumption into the public market. Various federal, state and local agencies have the authority to prescribe specific product quality specifications to commodities sold into the public market. Changes in product quality specifications could reduce our throughput volume, require us to incur additional handling costs or require the expenditure of significant capital. In addition, different product specifications for different markets impact the fungibility of products transported and stored in our pipeline systems and terminal facilities and could require the construction of additional storage to segregate products with different specifications. We may be unable to recover these costs through increased revenues.

In addition, the operations of our butane blending services are reliant upon gasoline vapor pressure specifications. Significant changes in such specifications could reduce butane blending opportunities, which would affect our ability to market our butane blending services licenses and which would ultimately affect our ability to recover the costs incurred to acquire and integrate the butane blending acquisition.

 

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Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for our services.

The U.S. Senate has considered legislation to restrict U.S. emissions of carbon dioxide and other greenhouse gases (“GHG”) that may contribute to global warming and climate change. Many states, either individually or through multi-state regional initiatives, have begun implementing legal measures to reduce GHG emissions. The U.S. House of Representatives has previously approved legislation to establish a “cap-and-trade” program, whereby the U.S. Environmental Protection Agency (“EPA”) would issue a capped and steadily declining number of tradable emissions allowances to certain major GHG emission sources so they could continue to emit GHGs into the atmosphere. The cost of such allowances would be expected to escalate significantly over time, making the combustion of carbon-based fuels (e.g., refined petroleum products, oil and natural gas) increasingly expensive. Beginning in 2011, EPA regulations required specified large domestic GHG sources to report emissions above a certain threshold occurring after January 1, 2010. Our facilities are not subject to this reporting requirement since our GHG emissions are below the applicable threshold. In addition, the EPA has proposed new regulations, under the federal Clean Air Act, that would require a reduction in GHG emissions from motor vehicles and could trigger permit review for GHG emissions from certain stationary sources. It is not possible at this time to predict how pending legislation or new regulations to address GHG emissions would impact our business. However, the adoption and implementation of federal, state, or local laws or regulations limiting GHG emissions in the U.S. could adversely affect the demand for our crude oil or refined products transportation and storage services, and result in increased compliance costs, reduced volumes or additional operating restrictions.

Terrorist attacks aimed at our facilities could adversely affect our business.

The U.S. government has issued warnings that energy assets, specifically the nation’s pipeline and terminal infrastructure, may be the future targets of terrorist organizations. Any terrorist attack at our facilities, those of our customers and, in some cases, those of other pipelines, refineries, or terminals could materially and adversely affect our results of operations, financial position, or cash flows.

Our risk management policies cannot eliminate all commodity risk, and our use of hedging arrangements could result in financial losses or reduce our income. In addition, any non-compliance with our risk management policies could result in significant financial losses.

We follow risk management practices designed to minimize commodity risk, and engage in hedging arrangements to reduce our exposure to fluctuations in the prices of refined products. These hedging arrangements expose us to risk of financial loss in some circumstances, including when the counterparty to the hedging contract defaults on its contract obligations, or when there is a change in the expected differential between the underlying price in the hedging agreement and the actual prices received. In addition, these hedging arrangements may limit the benefit we would otherwise receive from increases in prices for such refined products.

The accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions that are effective economically (whether to mitigate our exposure to fluctuations in commodity prices, or to balance our exposure to fixed and variable interest rates), these transactions may not be considered effective for accounting purposes. Accordingly, our consolidated financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at that point. In addition, it is not always possible for us to engage in a hedging transaction that completely mitigates our exposure to commodity prices. Our consolidated financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge.

We have adopted risk management policies designed to manage risks associated with our businesses. However, these policies cannot eliminate all price-related risks, and there is also the risk of non-compliance with such policies. We cannot make any assurances that we will detect and prevent all violations of our risk

 

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management practices and policies, particularly if deception or other intentional misconduct is involved. Any violations of our risk management practices or policies by our employees or agents could result in significant financial losses.

We do not own all of the land on which our pipelines and facilities are located, and we lease certain facilities and equipment, which subjects us to the possibility of increased costs to retain necessary land use which could disrupt our operations.

We do not own all of the land on which certain of our pipelines and facilities are located, and we are, therefore, subject to the risk of increased costs to maintain necessary land use. We obtain the rights to construct and operate certain of our pipelines and related facilities on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew rights-of-way contracts on acceptable terms, or increased costs to renew such rights could have a material adverse effect on our results of operations, financial condition and cash flows. In addition, we are subject to the possibility of increased costs under our rental agreements with landowners, primarily through rental increases and renewals of expired agreements.

Whether we have the power of eminent domain for our pipelines varies from state to state, depending upon the type of pipeline (e.g., crude oil, or refined products) and the laws of the particular state. In either case, we must compensate landowners for the use of their property and, in eminent domain actions, such compensation may be determined by a court. Our inability to exercise the power of eminent domain could negatively affect our business if we were to lose the right to use or occupy the property on which our pipelines are located.

Additionally, certain facilities and equipment (or parts thereof) used by us are leased from third parties for specific periods. Our inability to renew equipment leases or otherwise maintain the right to utilize such facilities and equipment on acceptable terms, or the increased costs to maintain such rights, could have a material adverse effect on our results of operations and cash flows.

A portion of our general and administrative services have been outsourced to third-party service providers. Fraudulent activity or misuse of proprietary data involving our outsourcing partners could expose us to additional liability.

We utilize both Sunoco and third parties in the processing of our information and data. Breaches of our security measures or the accidental loss, inadvertent disclosure or unapproved dissemination of proprietary information or sensitive or confidential data about us or our customers, including the potential loss or disclosure of such information or data as a result of fraud or other forms of deception, could expose us to a risk of loss or misuse of this information, result in litigation and potential liability for us, lead to reputational damage, increase our compliance costs, or otherwise harm our business. The Partnership continues to work with ETP in determining how the acquisition will impact these general and administrative functions going forward.

Security breaches and other disruptions could compromise our information and expose us to liability, which would cause our business and reputation to suffer.

In the ordinary course of our business, we collect and store sensitive data, including intellectual property, our proprietary business information and that of our customers, suppliers and business partners, and personally identifiable information of our employees, in our data centers and on our networks. The secure processing, maintenance and transmission of this information is critical to our operations and business strategy. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties, disruption of our operations, damage to our reputation, and cause a loss of confidence in our products and services, which could adversely affect our business.

 

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RISKS RELATED TO OUR PARTNERSHIP STRUCTURE

Our general partner’s discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to our unitholders.

Our partnership agreement provides that our general partner may reduce operating surplus by establishing cash reserves to provide funds for our future operating expenditures. In addition, the partnership agreement provides that our general partner may reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to our unitholders in any one or more of the next four quarters. These cash reserves will affect the amount of cash available for current distribution to our unitholders.

Even if unitholders are dissatisfied, they have limited rights under the partnership agreement to remove our general partner without its consent, which could lower the trading price of the common units.

The partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management. Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders did not elect our general partner or its board of directors and will have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is chosen by ETP, the sole member of our general partner. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a control premium in the trading price.

The control of our general partner may be transferred to a third party without unitholder consent.

Our general partner has the right to transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of the owner of our general partner from transferring its ownership interest in the general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of the general partner with its own appointees.

Conflicts of interest may arise between us and ETP, as the owner of our general partner which, due to limited fiduciary responsibilities, may permit ETP and its affiliates to favor their own interests to the detriment of our unitholders.

ETP owns and controls our two percent general partner interest and owns 32.3 percent of our limited partnership interests. Conflicts of interest may arise, from time to time, between ETP and its affiliates (including our general partner), on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates (including ETP) over the interests of our unitholders. These conflicts may include, among others, the following situations:

 

   

ETP and its affiliates may engage in competition with us. Neither our partnership agreement nor any other agreement requires ETP to pursue a business strategy that favors us or utilizes our assets, and our general partner may consider the interests of parties other than us, such as ETP, in resolving conflicts of interest;

 

   

under our partnership agreement, our general partner’s fiduciary duties are restricted, and our unitholders have only limited remedies available in the event of conduct constituting a potential breach of fiduciary duty by our general partner;

 

   

our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities, and reserves, each of which can

 

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affect the amount of cash available for distribution to our unitholders and the amount received by our general partner in respect of its incentive distribution rights (“IDRs”);

 

   

our general partner determines which costs incurred by ETP and its affiliates are reimbursable by us; and

 

   

our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for services rendered, or from entering into additional contractual arrangements with any of these entities on our behalf, so long as the terms of any additional contractual arrangements are fair and reasonable to us; and our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates.

We are a holding company. We conduct our operations through our subsidiaries and depend on cash flow from our subsidiaries to pay distributions to our unitholders and service our debt obligations.

We are a holding company. We conduct our operations through our subsidiaries. As a result, our cash flow and ability to pay distributions to our unitholders and to service our debt is dependent upon the earnings of our subsidiaries. In addition, we are dependent on the distribution of earnings, loans or other payments from our subsidiaries to us. Any payment of dividends, distributions, loans or other payments from our subsidiaries to us could be subject to statutory or contractual restrictions. Payments to us by our subsidiaries also will be contingent upon the profitability of our subsidiaries. If we are unable to obtain funds from our subsidiaries we may not be able to pay distributions to our unitholders or pay interest or principal on our debt securities when due.

Our general partner may cause us to borrow funds in order to make cash distributions, even where the purpose or effect of the borrowing benefits the general partner or its affiliates.

Our general partner is a wholly-owned subsidiary of ETP, and ETP also owns 32.3 percent of our limited partnership interests and all of our IDRs. Our general partner may cause us to borrow funds from affiliates of ETP or from third parties in order to pay cash distributions to our unitholders and to our general partner, including distributions with respect to our general partner’s IDRs.

Our general partner has a limited call right that may require our unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80 percent of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their common units at an undesirable time or price, may not receive a return on the investment, and may incur a tax liability upon the sale.

We may issue additional common units without unitholder approval, which would dilute our unitholders’ ownership interests.

We may issue an unlimited number of common units or other limited partner interests, including limited partner interests that rank senior to our common units, without the approval of our unitholders. The issuance of additional common units, or other equity securities of equal or senior rank, will decrease the proportionate ownership interest of existing unitholders and reduce the amount of cash available for distribution to our common unitholders and may adversely affect the market price of our common units.

 

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A unitholder may not have limited liability if a state or federal court finds that we are not in compliance with the applicable statutes or that unitholder action constitutes control of our business.

The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some states. A unitholder could be held liable in some circumstances for our obligations to the same extent as a general partner if a state or federal court determined that:

 

   

we had been conducting business in any state without complying with the applicable limited partnership statute; or

 

   

the right or the exercise of the right by the unitholders as a group to remove or replace our general partner, to approve some amendments to the partnership agreement, or to take other action under the partnership agreement constituted participation in the “control” of our business.

Under applicable state law, our general partner has unlimited liability for our obligations, including our debts and environmental liabilities, if any, except for our contractual obligations that are expressly made without recourse to our general partner.

In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that under some circumstances a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.

RISKS RELATED TO OUR DEBT

References under this heading to “we,” “us,” and “our” mean Sunoco Logistics Partners Operations L.P. or Sunoco Partners Marketing & Terminals L.P.

We may not be able to obtain funding, or obtain funding on acceptable terms, to meet our future capital needs.

Global market and economic conditions have been, and continue to be volatile. The debt and equity capital markets have been impacted by, among other things, significant write-offs in the financial services sector and the re-pricing of credit risk in the broadly syndicated market.

As a result, the cost of raising money in the debt and equity capital markets could be higher and the availability of funds from those markets could be diminished if we seek access to those markets. Accordingly, we cannot be certain that additional funding will be available if needed and to the extent required, on acceptable terms. If additional funding is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plan, enhance our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our revenues and results of operations.

Restrictions in our debt agreements may prevent us from engaging in some beneficial transactions or paying distributions to unitholders.

As of December 31, 2012, our total outstanding indebtedness was $1.59 billion excluding net unamortized fair value adjustments. Our payment of principal and interest on the debt will reduce the cash available for distribution on our units, as will our obligation to repurchase the senior notes upon the occurrence of specified events involving a change in control of our general partner. In addition, we are prohibited by our credit facilities and the senior notes from making cash distributions during an event of default, or if the payment of a distribution would cause an event of default, under any of our debt agreements. Our leverage and various limitations in our credit facilities and our senior notes may reduce our ability to incur additional debt, engage in some transactions, and capitalize on acquisition or other business opportunities. Any subsequent refinancing of our current debt or any new debt could have similar or greater restrictions.

 

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We could incur a substantial amount of debt in the future, which could prevent us from fulfilling our debt obligations.

We are permitted to incur additional debt, subject to certain limitations under our revolving credit facilities and, in the case of secured debt, under the indenture governing the notes. If we incur additional debt in the future, our increased leverage could, for example:

 

   

make it more difficult for us to satisfy our obligations under our debt securities or other indebtedness and, if we fail to comply with the requirements of the other indebtedness, could result in an event of default under our debt securities or such other indebtedness;

 

   

require us to dedicate a substantial portion of our cash flow from operations to required payments on indebtedness, thereby reducing the availability of cash flow from working capital, capital expenditures and other general corporate activities;

 

   

limit our ability to obtain additional financing in the future for working capital, capital expenditures and other general corporate activities;

 

   

limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

 

   

detract from our ability to successfully withstand a downturn in our business or the economy generally; and

 

   

place us at a competitive disadvantage against less leveraged competitors.

Our notes and related guarantees are effectively subordinated to any secured debt of ours or the guarantor as well as to any debt of our non-guarantor subsidiaries, and, in the event of our bankruptcy or liquidation, holders of our notes will be paid from any assets remaining after payments to any holders of our secured debt.

Our notes and related guarantees are general unsecured senior obligations of us and the guarantor, respectively, and effectively subordinated to any secured debt that we or the guarantor may have to the extent of the value of the assets securing that debt. The indentures permit the guarantor and us to incur secured debt provided certain conditions are met. Our notes are effectively subordinated to the liabilities of any of our subsidiaries unless such subsidiaries guarantee such notes in the future.

If we are declared bankrupt or insolvent, or are liquidated, the holders of our secured debt will be entitled to be paid from our assets securing their debt before any payment may be made with respect to our notes. If any of the preceding events occur, we may not have sufficient assets to pay amounts due on our secured debt and our notes.

We do not have the same flexibility as other types of organizations to accumulate cash, which may limit cash available to service our debt or to repay debt at maturity.

Our partnership agreement requires us to distribute, on a quarterly basis, 100 percent of our available cash to our general partner and Sunoco Logistics Partners L.P. within 45 days following the end of every quarter. The Sunoco Logistics Partners L.P. partnership agreement requires it to distribute, on a quarterly basis, 100 percent of its available cash to its unitholders of record within 45 days following the end of every quarter. Available cash with respect to any quarter is generally all of our or Sunoco Logistics Partners L.P.’s, as applicable, cash on hand at the end of such quarter, less cash reserves for certain purposes. The sole director of our general partner and the board of directors of Sunoco Logistics Partners L.P.’s general partner will determine the amount and timing of such distributions and have broad discretion to establish and make additions to our or Sunoco Logistics Partners L.P.’s, as applicable, reserves or the reserves of our or Sunoco Logistics Partners L.P.’s, as applicable, operating subsidiaries as they determine are necessary or appropriate. As a result, we and Sunoco Logistics Partners L.P. do not have the same flexibility as corporations or other entities that do not pay dividends or that have complete flexibility regarding the amounts they will distribute to their equity holders. Although our payment obligations to

 

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our partners are subordinate to our payment obligations on our debt, the timing and amount of our quarterly distributions to our partners could significantly reduce the cash available to pay the principal, premium (if any) and interest on our notes.

Rising short-term interest rates could increase our financing costs and reduce the amount of cash we generate.

As of December 31, 2012, we had $139 million of floating-rate debt outstanding. Rising short-term rates could materially and adversely affect our results of operations, financial condition or cash flows.

Any reduction in our credit ratings or in ETP’s credit ratings could materially and adversely affect our business, results of operations, financial condition and liquidity.

We currently maintain an investment grade rating by Moody’s, S&P and Fitch Ratings. However, our current ratings may not remain in effect for any given period of time and a rating may be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. If Moody’s, S&P or Fitch Ratings were to downgrade our long-term rating, particularly below investment grade, our borrowing costs could significantly increase, which would adversely affect our financial results, and our potential pool of investors and funding sources could decrease. Further, due to our relationship with ETP, any down-grading in ETP’s credit ratings could also result in a down-grading in our credit ratings. Ratings from credit agencies are not recommendations to buy, sell or hold our securities and each rating should be evaluated independently of any other rating.

TAX RISKS TO OUR COMMON UNITHOLDERS

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity level taxation by individual states. If the Internal Revenue Service (“IRS”) treats us as a corporation or we become subject to a material amount of entity level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to unitholders.

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this matter. The IRS may adopt positions that differ from the ones we take. A successful IRS contest of the federal income tax positions we take may impact adversely the market for our common units, and the costs of any IRS contest will reduce our cash available for distribution to unitholders.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax at the corporate tax rate, and likely would pay state income tax at varying rates. Distributions to unitholders generally would be taxed again as corporate distributions. Treatment of us as a corporation would result in a material reduction in anticipated cash flow and after-tax return to unitholders. Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or to otherwise subject us to a material level of entity-level taxation. States are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise and other forms of taxation. If any of these states were to impose a tax on us, the cash available for distribution to unitholders would be reduced. The partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to a material level of entity-level taxation for federal, state, or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.

The sale or exchange of 50 percent or more of our capital and profit interests during any twelve-month period will result in our termination as a partnership for federal income tax purposes.

We are considered to have been terminated for tax purposes since there were sales or exchanges which, in the aggregate, constituted 50 percent or more of the total interests in our capital and profits within a twelve-

 

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month period (a “technical termination”). For purposes of measuring whether the 50 percent threshold was reached, multiple sales of the same interest were counted only once. We believe that the 50 percent threshold was exceeded with ETP’s acquisition of Sunoco’s interests in the Partnership. The technical termination does not affect our classification as a partnership for federal income tax purposes, but instead, we will be treated as a new partnership for federal income tax purposes. The technical termination resulted in the closing of our taxable year for all unitholders.

In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in the unitholder’s taxable income for the year of termination. As a result of the technical termination, we are required to file two tax returns (and unitholders could receive two Schedules K-1 if the relief discussed below is not available) for the calendar year and the cost of the preparation of these returns will be borne by all unitholders. We are required to make new tax elections after the technical termination, including a new election under Section 754 of the Internal Revenue Code, and the termination has resulted in a deferral of our deductions for depreciation. A termination could also result in penalties if we had been unable to determine that the termination had occurred. Moreover, the technical termination could accelerate the application of, or subject us to, any tax legislation enacted before the technical termination. The IRS has recently announced a publicly traded partnership technical termination relief procedure whereby if a publicly traded partnership that has technically terminated requests publicly traded partnership technical termination relief and the IRS grants such relief, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the calendar year notwithstanding two partnership tax years. We are in the process of petitioning the IRS for this technical termination relief.

Our unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income which will be different in amount than the cash we distribute, our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that result from that income.

Tax gain or loss on disposition of our limited partner units could be more or less than expected.

If our unitholders sell their limited partner units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those limited partner units. Prior distributions to our unitholders in excess of the total net taxable income the unitholder was allocated for a unit, which decreased their tax basis in that unit, will, in effect, become taxable income to our unitholders if the limited partner unit is sold at a price greater than their tax basis in that limited partner unit, even if the price they receive is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if our unitholders sell their units, they may incur a tax liability in excess of the amount of cash received from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as individual retirement accounts (IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal tax returns and pay tax on their share of our taxable income.

 

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Our unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our limited partner units.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently conduct our business and own assets in approximately 30 states, most of which impose a personal income tax. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is our unitholders’ responsibility to file all United States federal, state and local tax returns.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units, may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Moreover, any such modification could make it more difficult or impossible for us to meet the exception which allows publicly traded partnerships that generate qualifying income to be treated as partnerships (rather than corporations) for U.S. federal income tax purposes, affect or cause us to change our business activities, or affect the tax consequences of an investment in our common units. For example, members of Congress have been considering substantive changes to the definition of qualifying income and the treatment of certain types of income earned from partnerships. While these specific proposals would not appear to affect our treatment as a partnership, we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

 

ITEM 1B.    UNRESOLVED STAFF COMMENTS

None.

 

ITEM 2. PROPERTIES

See Item 1. (c) for a description of the locations and general character of our material properties.

 

ITEM 3. LEGAL PROCEEDINGS

There are certain legal and administrative proceedings arising prior to the February 2002 initial public offering (“IPO”) pending against our Sunoco-affiliated predecessors and us (as successor to certain liabilities of those predecessors). Although the ultimate outcome of these proceedings cannot be ascertained at this time, it is reasonably possible that some of them may be resolved unfavorably. Sunoco has agreed to indemnify us for 100 percent of all losses from environmental liabilities related to the transferred assets arising prior to, and asserted within 21 years of February 8, 2002. There is no monetary cap on this indemnification from Sunoco. Sunoco’s share of liability for claims asserted thereafter will decrease by 10 percent each year through the thirtieth year following the February 8, 2002 date. Any remediation liabilities not covered by this indemnity will be our responsibility. In addition, Sunoco is obligated to indemnify us under certain other agreements executed after the IPO.

Additionally, we have received notices of violations and potential fines under various federal, state and local provisions relating to the discharge of materials into the environment or protection of the environment. While we believe that even if any one or more of the environmental proceedings listed below were decided against us, it would not be material to our financial position, we are required to report environmental proceedings if we reasonably believe that such proceedings will result in monetary sanctions in excess of $0.1 million.

 

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In August 2009, the Pipeline Hazardous Material Safety Administration (“PHMSA”) proposed penalties totaling $0.2 million based on alleged violations of various safety regulations relating to the November 2008 products release by Sunoco Pipeline L.P. in Murrysville, Pennsylvania. In December 2011, the assessed fine was paid. The Partnership completed the mandated corrective actions and received notice from PHMSA in June 2012 that no further action is required.

In 2009, the Environmental Protection Agency (“EPA”) proposed penalties based on alleged violations of the Clean Water Act associated with an October 2008 release from the Mid-Valley Pipeline. The EPA and the Partnership agreed upon a settlement of $0.3 million, which the Partnership paid in the first quarter 2012.

The Partnership’s Sunoco Pipeline L.P. subsidiary operates the West Texas Gulf Pipeline on behalf of West Texas Gulf Pipe Line Company and its shareholders pursuant to an Operating Agreement. Sunoco Pipeline L.P. also has a 60.3 percent ownership interest in the company. In March 2010, Sunoco Pipeline L.P. received a Notice of Probable Violation, Proposed Civil Penalty and proposed Compliance Order from PHMSA with proposed civil penalties in connection with a crude oil release that occurred at the Colorado City, Texas station on the West Texas Gulf Pipeline in June 2009. PHMSA issued a final order in August 2012 finding the Partnership in violation of all items identified in the original notice. The Partnership paid $0.4 million during the third quarter 2012 but has requested a petition for reconsideration on certain of the violations. The Partnership is awaiting a response from PHMSA.

In January 2012, the Partnership experienced a release on its refined products pipeline in Wellington, Ohio. In connection with this release, PHMSA issued a Corrective Action Order under which the Partnership is obligated to follow specific requirements in the investigation of the release and the repair and reactivation of the pipeline. The Partnership also entered into an Order on Consent with the EPA regarding the environmental remediation of the release site. The Partnership has not received any proposed penalties associated with this release and continues to cooperate with both PHMSA and the EPA to complete the investigation of the incident and repair of the pipeline.

In 2012, the EPA issued a proposed consent agreement related to releases that occurred at the Partnership’s pump station/tank farm in Barbers Hill, Texas and pump station/tank farm located in Cromwell, Oklahoma in 2010 and 2011, respectively. These matters were referred to the U.S. Department of Justice (“DOJ”) by the EPA. In November 2012, the Partnership received an initial assessment of $1.4 million associated with these releases. The Partnership is in discussions with the EPA and DOJ on this matter and hopes to resolve the issue during 2013.

 

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

 

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SECURITYHOLDER MATTERS AND PURCHASES OF EQUITY SECURITIES

Our common units are listed on the New York Stock Exchange under the symbol “SXL” beginning on February 5, 2002. At the close of business on February 28, 2013, there were 89 holders of record of our common units. These holders of record included the general partner with 33.5 million common units registered in its name, and Cede & Co., a clearing house for stock transactions, with the majority of the remaining 70.3 million common units registered to it.

On October 25, 2011, our Board of Directors declared a three-for-one split of our common and Class A units. The unit split resulted in the issuance of two additional common or Class A units for every one unit owned as of the close of business on November 18, 2011, which is the record date. The unit split was effective December 2, 2011. All unit and per unit information included in this report are presented on a post-split basis.

 

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Our registration statement to offer our limited partnership interests and debt securities to the public also allows our general partner to sell in one or more offerings, the common units it owns. For each offering of our general partner’s limited partnership units, we will provide a prospectus supplement that will contain specific information about the terms of that offering and the securities offered by our general partner in that offering.

The high and low sales price ranges (composite transactions) and distributions declared by quarter for 2012 and 2011 were as follows:

 

     2012      2011  
     Unit Price      Declared
Distributions
     Unit Price      Declared
Distributions
 

Quarter

   High      Low         High      Low     

1st

   $ 42.11       $ 35.01       $ 0.4275       $ 29.97       $ 27.10       $ 0.3983   

2nd

   $ 40.99       $ 31.65       $ 0.4700       $ 30.34       $ 26.00       $ 0.4050   

3rd

   $ 50.40       $ 36.29       $ 0.5175       $ 30.31       $ 24.40       $ 0.4133   

4th

   $ 52.04       $ 44.00       $ 0.5450       $ 39.98       $ 28.50       $ 0.4200   

Within 45 days after the end of each quarter, we distribute all cash on hand at the end of the quarter less reserves established by our general partner in its discretion. This is defined as “available cash” in the partnership agreement. Our general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct our business. We will make minimum quarterly distributions of $0.15 per common unit, to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner.

If cash distributions exceed $0.1667 per unit in a quarter, our general partner will receive increasing percentages, up to 50 percent, of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions.” The amounts shown in the table under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and our unitholders in any available cash from operating surplus that is distributed up to and including the corresponding amount in the column “Total Quarterly Distribution Target Amount,” until the available cash that is distributed reaches the next target distribution level, if any. The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

There is no guarantee that we will pay the minimum quarterly distribution on the common units in any quarter, and we are prohibited from making any distributions to our unitholders if it would cause an event of default, or an event of default exists under the credit facilities or the senior notes (see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources”).

In January 2010, we repurchased, and our general partner transferred and assigned to us for cancellation, the incentive distribution rights (“IDRs”) held by our general partner under our Second Amended and Restated Agreement of Limited Partnership, as amended, in consideration for (i) our issuance to our general partner of new IDRs issued under our Third Amended and Restated Agreement of Limited Partnership and (ii) our issuance to our general partner of a promissory note in the principal amount of $201 million. In February 2010, Sunoco Logistics Partners Operations L.P. issued a total of $500 million of Senior Notes, which mature in February 2020 and February 2040. A portion of the net proceeds from this offering was used to repay in the full this promissory note. For a further description of the senior notes issuance, see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

 

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The following table compares the target distribution levels and distribution “splits” between the general partner and the holders of our common units under the cancelled IDRs and under the new IDRs:

 

    

Cancelled IDRs

   

New IDRs

 
  

Total Quarterly
Distribution Target
Amount

   Marginal
Percentage Interest
in Distributions
   

Total Quarterly
Distribution
Target Amount

   Marginal
Percentage Interest in
Distributions
 
      General
Partner
    Unitholders        General
Partner
    Unitholders  

Minimum Quarterly Distribution

   $0.1500      2     98       

First Target Distribution

   up to $0.1667      2     98        No change     

Second Target Distribution

  

above $0.1667

up to $0.1917

     15 %*      85       

Third Target

   above $0.1917        above $0.1917     

Distribution

   up to $0.2333      25 %*      75   up to $0.5275      37 %*      63

Thereafter

   above $0.2333      50 %*      50   above $0.5275      50 %*      50

 

* Includes two percent general partner interest.

 

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ITEM 6. SELECTED FINANCIAL DATA

The following tables present selected current and historical audited financial data. The tables should be read together with the consolidated financial statements and the accompanying notes of Sunoco Logistics Partners L.P. included in Item 8. “Financial Statements and Supplementary Data.” The tables also should be read together with Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

    Successor     Predecessor  
    Period from Acquisition
(October 5, 2012) to
December 31, 2012
    Period from
January 1, 2012 to
October 4, 2012
    Year Ended December 31,  
      2011     2010     2009     2008  
    (in millions, except per
unit data)
    (in millions, except per unit data)  

Income Statement Data:

             

Revenues:

             

Sales and other operating revenue:

             

Unaffiliated customers

  $ 2,989      $ 9,460      $ 10,473      $ 6,691      $ 4,696      $ 7,540   

Affiliates

    200        461        432        1,117        706        2,572   

Other income(1)

    5        18        13        30        28        24   

Gain on divestment and related matters

    —          11        —          —          —          —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

  $ 3,194      $ 9,950      $ 10,918      $ 7,838      $ 5,430      $ 10,136   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

  $ 164      $ 478      $ 436      $ 301      $ 295      $ 245   

Gain on investments in affiliates

  $
 
 
—  
  
  
  $
 
 
—  
  
  
  $
 
 
—  
  
  
  $ 128      $
 
 
—  
  
  
  $
 
 
—  
  
  

Income before income tax expense

  $ 150      $ 413      $ 347      $ 356      $ 250      $ 214   

Net Income

  $ 142      $ 389      $ 322      $ 348      $ 250      $ 214   

Net Income attributable to noncontrolling interests

    3        8        9        2        —          —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net Income attributable to Sunoco Logistics Partners L.P.

  $ 139      $ 381      $ 313      $ 346      $ 250      $ 214   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net Income attributable to Sunoco Logistics Partners L.P. per Limited Partner unit:

             

Basic

  $ 1.11      $ 3.15      $ 2.56      $ 3.13      $ 2.17      $ 2.06   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Diluted

  $ 1.10      $ 3.14      $ 2.54      $ 3.11      $ 2.16      $ 2.05   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash distributions per unit to Limited Partners:(2)

             

Paid

  $ 0.52      $ 1.32      $ 1.61      $ 1.51      $ 1.37      $ 1.22   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Declared

  $ 0.55      $ 1.42      $ 1.64      $ 1.54      $ 1.40      $ 1.26   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Other Data:

             

Adjusted EBITDA(3)

  $ 219      $ 591      $ 573      $ 399      $ 372      $ 319   

Distributable Cash Flow(3)

  $ 165      $ 439      $ 390      $ 242      $ 264      $ 238   

 

(1) 

Includes equity income from the investments in the following joint ventures: Explorer Pipeline Company, Wolverine Pipe Line Company, West Shore Pipe Line Company (“West Shore”), Yellowstone Pipe Line Company, Mid-Valley Pipeline Company (“Mid-Valley”) and West Texas Gulf Pipe Line Company (“West Texas Gulf”). Equity income from the investments has been included based on our respective ownership percentages of each, and from the dates of acquisition forward. In the third quarter 2010, we acquired a controlling financial interest in Mid-Valley and West Texas Gulf. Therefore, these joint ventures are reflected as consolidated subsidiaries from the respective dates of acquisition.

(2) 

Cash distributions paid per unit to limited partners represent payments made per unit during the period stated. Cash distributions declared per unit to limited partners represent distributions declared per unit for the quarters within the period stated. Declared distributions were paid within 45 days following the close of each quarter.

 

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  (3) Adjusted EBITDA and distributable cash flow provide additional information for evaluating our ability to make distributions to our unitholders and our general partner. The following tables reconcile (a) the difference between net income, as determined under United States generally accepted accounting principles (“GAAP”), and Adjusted EBITDA and distributable cash flow and (b) net cash provided by operating activities and Adjusted EBITDA:

 

    Successor     Predecessor  
  Period from Acquisition
(October 5, 2012) to
December 31, 2012
    Period from
January 1, 2012 to
October 4, 2012
    Year Ended December 31,  
      2011     2010     2009     2008  
    (in millions)     (in millions)  

Net Income

  $ 142      $ 389      $ 322      $ 348      $ 250      $ 214   

Interest expense, net

    14        65        89        73        45        31   

Depreciation and amortization expense

    63        76        86        64        48        40   

Impairment charge

    —          9        31        3        —          6   

Provision for income taxes

    8        24        25        8        —          —     

Non-cash compensation expense

    2        6        6        5        5        4   

Unrealized losses/(gains) on commodity risk management activities

    (3     6        (2     2        —          —     

Proportionate share of unconsolidated affiliates’ interest, depreciation and provision for income taxes

    5        16        16        24        24        24   

Adjustments to commodity hedges resulting from “push-down” accounting

    (12     —          —           —           —           —      

Gain on investments in affiliates

    —          —          —           (128     —           —      
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

    219        591        573        399        372        319   

Interest expense, net

    (14     (65     (89     (73     (45     (31

Provision for income taxes

    (8     (24     (25     (8     —          —     

Amortization of fair value adjustments on long-term debt

    (6     —          —          —          —          —     

Distributions versus Adjusted EBITDA of unconsolidated affiliates

    (3     (25     (17     (36     (31     (24

Maintenance capital expenditures

    (21     (29     (42     (37     (32     (26

Distributable Cash Flow attributable to noncontrolling interests

    (2     (9     (10     (3     —          —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Distributable Cash Flow

  $ 165      $ 439      $ 390      $ 242      $ 264      $ 238   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

 
    Successor     Predecessor  
  Period from Acquisition
(October 5, 2012) to
December 31, 2012
    Period from
January 1, 2012 to
October 4, 2012
    Year Ended December 31,  
      2011     2010     2009     2008  
    (in millions)     (in millions)  

Net cash provided by operating activities

  $ 280      $ 411      $ 430      $ 341      $ 176      $ 229   

Interest expense, net

    14        65        89        73        45        31   

Amortization of bond premium, financing fees and bond discount

    6        (2     (2     (2     (2     (1

Deferred income tax expense

    2        —          2        —          —          —     

Regulatory matters excluded from Adjusted EBITDA

    —          10        (11     —          —          —     

Claim for (recovery of) environmental liability

    (13     14        —          —          —          —     

Net change in working capital pertaining to operating activities

    (94     35        35        (55     121        38   

Unrealized losses/(gains) on commodity risk management activities

    (3     6        (2     2        —          —     

Proportionate share of unconsolidated affiliates’ interest, depreciation and provision for income taxes

    5        16        16        24        24        24   

Adjustments to commodity hedges resulting from “push-down” accounting

    (12     —          —          —          —          —     

Provision for income taxes

    8        24        25        8        —          —     

Other

    26        12        (9     8        8        (2
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

  $ 219      $ 591      $ 573      $ 399      $ 372      $ 319   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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Our management believes Adjusted EBITDA and distributable cash flow information enhances an investor’s understanding of a business’s ability to generate cash for payment of distributions and other purposes. In addition, Adjusted EBITDA is also used as a measure in determining our compliance with certain revolving credit facility covenants. However, there may be contractual, legal, economic or other reasons which may prevent us from satisfying principal and interest obligations with respect to indebtedness and may require us to allocate funds for other purposes. Adjusted EBITDA and distributable cash flow do not represent and should not be considered alternatives to net income or cash flows from operating activities as determined under GAAP and may not be comparable to other similarly titled measures of other businesses.

 

    Successor     Predecessor  
  Period from Acquisition
(October 5, 2012) to
December 31, 2012 (1)
    Period from
January 1, 2012 to
October 4, 2012 (1)
    Year Ended December 31,  
      2011 (2)     2010 (3)     2009 (4)     2008 (5)  
    (in millions)     (in millions)  

Cash Flow Data:

             

Net cash provided by operating activities

  $ 280      $ 411      $ 430      $ 341      $ 176      $ 229   

Net cash used in investing activities

  $ (139   $ (224   $ (609   $ (426   $ (226   $ (332

Net cash provided by (used in) financing activities

  $ (140   $ (190   $ 182      $ 85      $ 50      $ 103   

Capital expenditures:

             

Maintenance(6)

  $ 21      $ 29      $ 42      $ 37      $ 32      $ 26   

Expansion(7)

    118        206        171        137        144        120   

Major acquisitions

    —          —          396        252        50        186   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total capital expenditures

  $ 139      $ 235      $ 609      $ 426      $ 226      $ 332   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) 

Cash flows related to expansion capital expenditures for the periods from October 5, 2012 to December 31, 2012 and from January 1, 2012 to October 4, 2012 included projects to expand upon the Partnership’s refined products acquisition and marketing services, upgrade the service capabilities at the Eagle Point and Nederland terminals, invest in the Partnership’s crude oil infrastructure by increasing its pipeline capabilities through previously announced growth projects in West Texas and expanding the trucking fleet, and invest in the Mariner West and Mariner East pipeline projects.

(2) 

Cash flows related to major acquisitions in 2011 include $73 million related to the acquisition of the East Boston terminal, $222 million related to the acquisition of the Texon crude oil purchasing and marketing business, $2 million related to the acquisition of the Eagle Point tank farm and $99 million related to the acquisition of a controlling financial interest in Inland Corporation. Expansion capital expenditures in 2011 include projects to expand upon our butane blending services, increase tankage at the Nederland facility, increase connectivity of the crude oil pipeline assets in Texas and increase our crude oil trucking fleet to meet the demand for transportation services in the southwest United States.

(3) 

Cash flows related to major acquisitions in 2010 include $152 million related to the acquisition of a butane blending business from Texon L.P., $91 million related to the acquisition of additional ownership interests in Mid-Valley, West Texas Gulf and West Shore and $9 million for the acquisition of two terminals in Texas. Expansion capital expenditures in 2010 include construction projects to expand services at our refined products terminals, increase tankage at the Nederland Terminal and to expand upon our refined products platform in the southwest United States.

(4) 

Cash flows related to major acquisitions in 2009 include $50 million related to the acquisition of Excel Pipeline LLC and a refined products terminal in Romulus, Michigan. Expansion capital expenditures in 2009 include the construction of tankage and pipeline assets in connection with our agreement to connect the Nederland Terminal to a Port Arthur, Texas refinery and construction of additional crude oil storage tanks at the Nederland Terminal.

(5) 

Cash flows related to major acquisitions in 2008 include $186 million related to the acquisition of the MagTex refined products pipeline system. Expansion capital expenditures in 2008 include construction of tankage and pipeline assets in connection with our agreement to connect the Nederland Terminal to a Port Arthur, Texas refinery and construction of additional crude oil storage tanks at the Nederland Terminal.

 

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(6) 

Maintenance capital expenditures are capital expenditures required to maintain equipment reliability, tankage and pipeline integrity and safety, and to address environmental regulations. We treat maintenance expenditures that do not extend the useful life of existing assets as operating expenses as incurred.

(7) 

Expansion capital expenditures are capital expenditures made to acquire and integrate complimentary assets, to improve operational efficiencies or reduce costs and to expand existing and construct new facilities, such as projects that increase storage or throughput volume.

 

    Successor     Predecessor  
  December  31,
2012
    December 31,  
    2011     2010     2009     2008  
  (in millions)     (in millions)  

Balance Sheet Data (at period end):

           

Net properties, plants and equipment

  $ 5,623      $ 2,522      $ 2,128      $ 1,534      $ 1,375   

Total assets

  $ 10,361      $ 5,477      $ 4,188      $ 3,099      $ 2,308   

Total debt

  $ 1,732      $ 1,698      $ 1,229      $ 868      $ 748   

Total Sunoco Logistics Partners L.P. Equity

  $ 6,072      $ 1,096      $ 965      $ 862      $ 670   

Noncontrolling interests

    123        98        77        —          —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total equity

  $ 6,195      $ 1,194      $ 1,042      $ 862      $ 670   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

    Successor     Predecessor  
  Period from Acquisition
(October 5, 2012) to
December 31, 2012
    Period from
January 1, 2012 to
October 4, 2012
    Year Ended December 31,  
      2011     2010     2009     2008  

Operating Data:

             

Crude Oil Pipelines (1)

             

Pipeline throughput (thousands of barrels per day (“bpd”))(2)

    1,584        1,546        1,587        1,183        658        683   

Pipeline revenue per barrel (cents)

    75.6        68.0        55.0        50.7        77.5        68.5   

Crude Oil Acquisition and Marketing (3)

             

Crude oil purchases (thousands of bpd)

    669        674        663        638        592        579   

Gross profit per barrel purchased (cents)(4)

    138.0        92.8        66.0        21.0        25.0        22.7   

Average crude oil price (per barrel)

  $ 88.20      $ 96.20      $ 95.14      $ 79.55      $ 61.93      $ 99.65   

Terminal Facilities(5)

             

Terminal throughput (thousands of bpd)

             

Refined products terminals

    451        499        492        488        462        436   

Nederland terminal

    787        703        757        729        597        526   

Refinery terminals

    411        369        443        465        591        654   

Refined Products Pipelines(1)

             

Pipeline throughput (thousands of bpd)(6)

    601        565        522        468        577        510   

Pipeline revenue per barrel (cents)

    63.0        62.2        68.3        70.0        60.7        55.4   

 

(1) 

Excludes amounts attributable to equity ownership interests in corporate joint ventures which are not consolidated.

(2) 

In July and August 2010, we acquired controlling financial interests in Mid-Valley and West Texas Gulf, respectively, and we accounted for the entities as consolidated subsidiaries from the dates of their respective acquisitions. Average volumes for the year ended December 31, 2010 of 278 thousand bpd have been included in the consolidated total. From the dates of acquisition, these pipelines had actual throughput of 696 thousand bpd for the year ended December 31, 2010.

(3) 

Includes results from the crude oil acquisition and marketing business acquired from Texon L.P. in August 2011 from the acquisition date.

(4) 

Represents total segment sales and other operating revenue minus cost of products sold and operating expenses divided by crude oil purchases.

(5) 

In July 2011 and August 2011, we acquired the Eagle Point tank farm and a refined products terminal located in East Boston, Massachusetts, respectively. Volumes and revenues for these acquisitions are included from their acquisition dates.

(6) 

In May 2011, we acquired a controlling financial interest in Inland and we accounted for the entity as a consolidated subsidiary from the date of acquisition. Average volumes for the year ended December 31, 2011 of 88 thousand bpd have been included in the consolidated total. From the date of acquisition, this pipeline had actual throughput of 140 thousand bpd for the year ended December 31, 2011.

 

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with the consolidated financial statements of Sunoco Logistics Partners L.P. Among other things, those consolidated financial statements include more detailed information regarding the basis of presentation for the following information.

Overview

We are a Delaware limited partnership which is principally engaged in the transport, terminalling and storage of crude oil and refined products. In addition to logistics services, we also own acquisition and marketing assets which are used to facilitate the purchase and sale of crude oil and refined products. Our portfolio of geographically diverse assets earns revenues in 30 states located throughout the United States. Revenues are generated by charging tariffs for transporting refined products, crude oil and other hydrocarbons through our pipelines as well as by charging fees for terminalling services at our facilities. Revenues are also generated by acquiring and marketing crude oil and refined products. Generally, crude oil and refined products purchases are entered into in contemplation of or simultaneously with corresponding sale transactions involving physical deliveries, which enables us to secure a profit on the transaction at the time of purchase.

On October 5, 2012, Sunoco, Inc. (“Sunoco”) was acquired by Energy Transfer Partners, L.P. (“ETP”). Prior to this transaction, Sunoco (through its wholly-owned subsidiary Sunoco Partners LLC) served as the Partnership’s general partner and owned a two percent general partner interest, all of the Partnership’s incentive distribution rights and a 32.4 percent limited partner interest in the Partnership. In connection with the acquisition, Sunoco’s interests in the general partner and limited partnership were contributed to ETP, resulting in a change of control of the Partnership’s general partner. As a result of the change in control, the Partnership’s assets and liabilities were adjusted to fair value on the closing date, October 5, 2012, by application of “push-down” accounting and the Partnership became a consolidated subsidiary of ETP. The effective date of the acquisition for accounting and reporting purposes was deemed to be October 1, 2012. Due to the application of “push-down” accounting, the Partnership’s consolidated financial statements and certain footnote disclosures are presented in two distinct periods to indicate the application of two different bases of accounting between the periods presented. The periods prior to the acquisition date, October 5, 2012, are identified as “Predecessor” and the period from October 5, 2012 forward is identified as “Successor.” The Partnership performed an analysis and determined that the activity from October 1, 2012 through October 4, 2012 was not material in relation to the Partnership’s financial position, results of operations or cash flows. Therefore, operating results between October 1, 2012 and October 4, 2012 have been included within the “Successor” period.

Strategic Actions

Our primary business strategies are to generate stable cash flows, increase pipeline and terminal throughput, utilize our crude oil gathering assets to maximize value for producers, pursue economically accretive organic growth opportunities and continue to improve operating efficiencies and reduce costs. We also utilize our pipeline systems to take advantage of market dislocations. We believe these strategies will result in continuing increases in distributions to our unitholders. As part of our strategy, we have undertaken several initiatives including the acquisitions and growth capital programs described below.

Acquisitions

During the three years ended December 31, 2012, we completed ten acquisitions for a total of $746 million.

2011 Acquisitions

 

   

East Boston Terminal—In August 2011, we acquired a refined products terminal, located in East Boston, Massachusetts, from affiliates of ConocoPhillips. The terminal is the sole service provider to Logan International Airport under a long-term contract to supply jet fuel. The terminal includes a

 

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10-bay truck rack and approximately 1 million barrels of capacity. The terminal was included in the Terminal Facilities segment from the date of acquisition;

 

   

Crude Oil Acquisition and Marketing Business—In August 2011, we acquired a crude oil acquisition and marketing business from Texon L.P. (“Texon”). The purchase consisted of a lease crude business and gathering assets in 16 states, primarily in the western United States. The crude oil volume of the business consisted of approximately 75,000 barrels per day at the wellhead. The business was included in the Crude Oil Acquisition and Marketing segment from the date of acquisition;

 

   

Eagle Point Tank Farm—In July 2011, we acquired the Eagle Point tank farm from Sunoco. The tank farm is located in Westville, New Jersey and consists of approximately 5 million barrels of active storage for refined products and dark oils. The tank farm was included in the Terminal Facilities segment from the date of acquisition; and,

 

   

Controlling Financial Interest in Inland Corporation—In May 2011, we acquired an 83.8 percent equity interest in Inland Corporation (“Inland”), which is the owner of 350 miles of active refined products pipelines in Ohio. The pipeline connects three refineries in Ohio to terminals and major markets in Ohio. We acquired its equity interest through a purchase of a 27.0 percent equity interest from Shell Oil Company (“Shell”) and a 56.8 percent equity interest from Sunoco. The pipeline was included in the Refined Products Pipeline segment from the date of acquisition.

2010 Acquisitions

 

   

Bay City Terminal—In October 2010, we acquired a terminal facility located in Bay City, Texas from Gulfstream Terminals & Marketing LLC. The terminal is capable of handling both crude oil and refined products volumes. Total active terminal storage capacity of this facility is less than half of a million barrels. The terminal was included within in the Terminal Facilities segment from the date of acquisition;

 

   

Big Sandy Terminal—In October 2010, we acquired a refined products terminal and pipeline segment located in Big Sandy, Texas from an affiliate of Chevron Corporation. The terminal and pipeline segment were not operational since being acquired. In February 2012, we completed a sale of the Big Sandy terminal to Delek US Holdings, Inc.

 

   

Butane Blending Business—In July 2010, we acquired a butane blending business from Texon. The acquisition included patented technology for blending of butane into refined products, contracts with customers currently utilizing the patented technology, butane inventories and other related assets. The acquisition was included within the Terminal Facilities segment as of the date of acquisition;

 

   

Controlling Financial Interests in Mid-Valley Pipeline Company and West Texas Gulf Pipe Line Company—In July and August 2010, we acquired additional ownership interests in Mid-Valley Pipeline Company (“Mid-Valley”) and West Texas Gulf Pipe Line Company (“West Texas Gulf”), increasing our ownership interest from 55.3 percent to 91.0 percent and from 43.8 percent to 60.3 percent, respectively. Mid-Valley owns an approximately 1,000-mile common carrier pipeline, which originates in Longview, Texas and terminates in Samaria, Michigan. The pipeline provides crude oil to a number of refineries, primarily in the midwest United States. West Texas Gulf owns and operates an approximately 600-mile common carrier crude oil pipeline system which originates from the West Texas oil fields at Colorado City and extends to Longview, Texas, where deliveries are made to several pipelines, including Mid-Valley. As we obtained a controlling financial interest in both entities, each was reflected as a consolidated subsidiary as of the respective acquisition dates, and are included in the Crude Oil Pipelines segment; and

 

   

Additional Equity Interest in West Shore Pipe Line Company—In July 2010, we acquired an additional ownership interest in West Shore Pipe Line Company (“West Shore”), increasing our ownership interest from 12.3 percent to 17.1 percent. West Shore owns and operates an approximately 650-mile common carrier refined products pipeline that originates in Chicago, Illinois and services delivery

 

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points from Chicago to Wisconsin. This investment is accounted for as an equity method investment, with the equity income recorded in the Refined Products Pipelines segment.

Growth Capital Program

In 2012, we completed $324 million of organic growth capital projects to improve operational efficiencies, reduce costs, expand existing facilities and construct new assets to increase storage, throughput volume or the scope of services we are able to provide. In 2012, these included projects to expand upon the Partnership’s refined products acquisition and marketing services, upgrade the service capabilities at the Eagle Point and Nederland Terminals, invest in the Partnership’s crude oil infrastructure by increasing its pipeline capabilities through previously announced organic growth projects in West Texas and expanding its trucking fleet, and invest in the Mariner West and Mariner East pipeline projects.

During 2013, we expect to spend approximately $700 million on expansion capital expenditures related to organic growth, excluding major acquisitions. This includes spending to capture more value from existing assets such as the Eagle Point terminal, the Nederland Terminal and our patented butane blending technology. Expansion capital expenditures in 2013 will also include progress on our previously announced growth projects, which are summarized as follows:

Mariner East

A joint pipeline and marine project to deliver natural gas liquids produced in the Marcellus Shale Basin to a storage facility on the east coast (“Project Mariner East”). This project would transport natural gas liquids, utilizing modified existing pipelines, from western Pennsylvania to the east coast where the natural gas liquids could be loaded on waterborne vessels for third-party transport to United States ports or export to international markets. The project will support the transportation of approximately 70,000 barrels per day with the ability to expand to support higher volumes. We anticipate the project to commence activity in the second half of 2014. As a result of substantial interest expressed during Open Seasons completed in 2012, we are actively developing a second phase related to this project.

Mariner West

In 2011, we announced a joint pipeline project with MarkWest Energy to deliver ethane produced in the Marcellus Shale Basin in western Pennsylvania to the Sarnia, Ontario petrochemical market (“Project Mariner West”). This project would transport ethane from western Pennsylvania to markets in Sarnia utilizing existing pipelines, which will be modified for ethane service. We completed a successful Open Season in 2011 which will enable Project Mariner West to proceed with an initial capacity to transport approximately 50,000 barrels per day and the ability to expand to support higher volumes. The project is expected to commence operations by July 2013.

Allegheny Access

In 2012, we announced a project to transport refined products from the midwest to eastern Ohio and western Pennsylvania markets utilizing existing and new assets. We completed a successful Open Season on this project during 2012 which will provide for initial capacity of 85,000 barrels per day which can be expanded to meet further demand. The project is expected to commence operations during the first half of 2014.

Permian Express Phase I

In 2012, we announced a project to transport West Texas crude oil to Gulf Coast markets utilizing existing pipelines. We completed a successful Open Season on this project during 2012 which will provide for initial capacity of 90,000 barrels per day which will be expanded to 150,000 barrels per day to support further demand. The Permian Express Phase I project is expected to commence operations in the second quarter of 2013 while we

 

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continue to prepare for additional capacity on this phase. In addition, we are actively developing a second phase for this project which would take additional West Texas crude oil to the Gulf Coast.

West Texas Crude

In 2011, we announced plans to expand takeaway capacity out of the Permian Basin in West Texas as there is a market need for incremental crude transportation to various refining centers in Texas, the mid-continent and the United States Gulf Coast (“West Texas Crude Expansion”). We completed three successful Open Seasons on this project during 2012 which will add approximately 110,000 barrels per day of capacity and will utilize existing pipelines. The project is expected to be fully completed by the second quarter of 2013.

Conservative Capital Structure

Our goal is to maintain substantial liquidity and a conservative capital structure. Sunoco Logistics Partners Operations L.P. (the “Operating Partnership”) and Sunoco Partners Marketing and Terminals L.P., our wholly-owned subsidiaries, have a five-year $350 million unsecured credit facility (the “$350 million Credit Facility”) and a $200 million 364 day unsecured credit facility (the “$200 million Credit Facility”), respectively. We will maintain our conservative capital structure by combining debt and equity issuances to finance our future growth.

Cash Distribution Increases

As a result of our continued growth, our general partner increased our cash distributions to limited partners in all quarters in the three years ended December 31, 2012. For the quarter ended December 31, 2012, the distribution increased to $0.5450 per common unit ($2.18 annualized). The distribution for the fourth quarter of 2012 was paid on February 14, 2013.

In January 2010, we repurchased, and our general partner transferred and assigned to us for cancellation, the incentive distribution rights (“IDRs”) held by the general partner under the Second Amended and Restated Agreement of Limited Partnership, as amended, as consideration for (i) our issuance to the general partner of new IDRs issued under the Third Amended and Restated Agreement of Limited Partnership and (ii) our issuance to the general partner of a promissory note in the amount of $201 million, which was repaid in full during the first quarter of 2010. The new IDRs provide for target distribution levels and distribution “splits” between the general partner and the holders of our limited partnership units equal to those applicable to the cancelled IDRs, except that (i) the general partner’s distribution split for distributions above the current second target distribution of $0.1917 per limited partnership unit per quarter (or $0.7668 per limited partnership unit on an annualized basis) and up to the third target distribution increased to 37% from 25% (these percentages include the general partner’s two percent interest); and (ii) the third target distribution increased from $0.2333 to $0.5275 per limited partnership unit per quarter (or from $0.9332 to $2.1100 per limited partnership unit on an annualized basis). See Note 13 to the consolidated financial statements included in Item 8. “Financial Statements and Supplementary Data” for more information on these changes.

 

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Results of Operations

The following table presents our consolidated operating results for the periods from October 5, 2012 to December 31, 2012, from January 1, 2012 to October 4, 2012, and for the years ended December 31, 2011 and 2010:

 

    Successor     Predecessor  
    Period from
Acquisition
(October 5,
2012) to
December 31,
2012(1)
    Period
from
January 1,
2012 to
October 4,
2012(1)
    Three
Months

Ended
December  31,
2011
    Nine Months
Ended
September 30,
2011
    Total
2011
    Year Ended
December 31,

2010
 
   

(in millions,

except per
unit data)

    (in millions, except per unit data)  

Statements of Income

             

Sales and other operating revenue:

             

Unaffiliated customers

  $ 2,989      $ 9,460      $ 3,325      $ 7,148      $ 10,473      $ 6,691   

Affiliates

    200        461        51        381        432        1,117   

Other income

    5        18        4        9        13        30   

Gain on divestment and related matters

    —          11        —          —          —          —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

    3,194        9,950        3,380        7,538        10,918        7,838   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cost of products sold and operating expenses

    2,933        9,311        3,178        7,086        10,264        7,398   

Depreciation and amortization expense

    63        76        25        61        86        64   

Impairment charge and related matters(2)

    —          (1     42        —          42        3   

Selling, general and administrative expenses

    34        86        23        67        90        72   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total costs and expenses

    3,030        9,472        3,268        7,214        10,482        7,537   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

    164        478        112        324        436        301   

Net interest expense

    14        65        26        63        89        73   

Gain on investments in affiliates

    —          —          —          —          —          128   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income before provision for income taxes

    150        413        86        261        347        356   

Provision for income taxes

    8        24        7        18        25        8   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net Income

    142        389        79        243        322        348   

Net Income attributable to noncontrolling interests

    3        8        3        6        9        2   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net Income attributable to Sunoco Logistics Partners L.P.

  $ 139      $ 381      $ 76      $ 237      $ 313      $ 346   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net Income attributable to Sunoco Logistics Partners L.P. per Limited Partner unit:

             

Basic

  $ 1.11      $ 3.15      $ 0.60      $ 1.96      $ 2.56      $ 3.13   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Diluted

  $ 1.10      $ 3.14      $ 0.60      $ 1.95      $ 2.54      $ 3.11   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) 

The effective date of the acquisition for accounting and reporting purposes was deemed to be October 1, 2012. The activity from October 1, 2012 through October 4, 2012 was not material in relation to the Partnership’s financial position, results of operations or cash flows.

(2) 

In September 2011, Sunoco announced its intention to exit its refining business in the northeast and initiated a process to sell its refineries located in Philadelphia and Marcus Hook, Pennsylvania. In December 2011, the main processing units at the Marcus Hook refinery were idled indefinitely. The Partnership recognized a $42 million charge in the fourth quarter 2011 for certain crude oil terminal assets which would have been negatively impacted if the Philadelphia refinery was permanently idled. The charge included a $31 million non-cash impairment for asset write-downs at the Fort Mifflin Terminal Complex and $11 million for regulatory obligations which would have been incurred if these assets were permanently idled. In September 2012, Sunoco contributed the refining assets of its Philadelphia refinery to Philadelphia Energy Solutions (“PES”), a joint venture between The Carlyle Group and Sunoco, which enabled the Philadelphia refinery to continue operating. As a result, the Partnership reversed $10 million of regulatory obligations during 2012 which were no longer expected to be incurred.

 

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Non-GAAP Financial Measures

To supplement our financial information presented in accordance with United States generally accepted accounting principles (“GAAP”), management uses additional measures that are known as “non-GAAP financial measures” in its evaluation of past performance and prospects for the future. The primary measures used by management are earnings before interest, taxes, depreciation and amortization expenses and other non-cash items (“Adjusted EBITDA”) and distributable cash flow (“DCF”).

Our management believes Adjusted EBITDA and distributable cash flow information enhances an investor’s understanding of a business’s ability to generate cash for payment of distributions and other purposes. In addition, Adjusted EBITDA calculations are also defined and used as a measure in determining our compliance with certain revolving credit facility covenants. However, there may be contractual, legal, economic or other reasons which may prevent us from satisfying principal and interest obligations with respect to indebtedness and may require us to allocate funds for other purposes. During the fourth quarter of 2012, the Partnership changed its definition of Adjusted EBITDA and Distributable Cash Flow to conform to the presentation utilized by its general partner. The Partnership also changed its measure of segment profit from operating income to the revised presentation of Adjusted EBITDA. This change did not impact the Partnership’s reportable segments. Prior period amounts have been recast to conform to current presentation. Adjusted EBITDA and distributable cash flow do not represent and should not be considered alternatives to net income or cash flows from operating activities as determined under GAAP and may not be comparable to other similarly titled measures of other businesses.

The following table reconciles the differences between net income, as determined under GAAP, and Adjusted EBITDA and distributable cash flow. The Partnership’s definition of Adjusted EBITDA has been revised beginning in the fourth quarter 2012. Prior period results have been recast to conform to current presentation.

 

    Successor     Predecessor  
    Period from Acquisition
(October 5, 2012) to
December 31, 2012(1)
    Period from
January 1, 2012 to
October 4, 2012(1)
    Three Months
Ended
December  31,
2011
    Nine Months
Ended
September  30,
2011
    Total
2011
    Year Ended
December 31,

2010
 
    (in millions)     (in millions)  

Net Income

  $ 142      $ 389      $ 79      $ 243      $ 322      $ 348   

Interest expense, net

    14        65        26        63        89        73   

Depreciation and amortization expense

    63        76        25        61        86        64   

Impairment charge

    —          9        31        —          31        3   

Provision for income taxes

    8        24        7        18        25        8   

Non-cash compensation expense

    2        6        1        5        6        5   

Unrealized losses/(gains) on commodity risk management activities

    (3     6        6        (8     (2     2   

Proportionate share of unconsolidated affiliates’ interest, depreciation and provision for income taxes

    5        16        4        12        16        24   

Adjustments to commodity hedges resulting from push-down accounting

    (12     —          —          —          —          —     

Gain on investments in affiliates

    —          —          —          —          —          (128
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

    219        591        179        394        573        399   

Interest expense, net

    (14     (65     (26     (63     (89     (73

Provision for income taxes

    (8     (24     (7     (18     (25     (8

Amortization of fair value adjustments on long-term debt

    (6     —          —          —          —          —     

Distributions versus Adjusted EBITDA of unconsolidated affiliates

    (3     (25     (4     (13     (17     (36

Maintenance capital expenditures

    (21     (29     (22     (20     (42     (37

Distributable Cash Flow attributable to noncontrolling interests

    (2     (9     (2     (8     (10     (3
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Distributable Cash Flow

  $ 165      $ 439      $ 118      $ 272      $ 390      $ 242   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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(1) 

The effective date of the acquisition for accounting and reporting purposes was deemed to be October 1, 2012. The activity from October 1, 2012 through October 4, 2012 was not material in relation to the Partnership’s financial position, results of operations or cash flows.

Analysis of Consolidated Operating Results

Net income attributable to the partnership interests was $139, $381, $313 and $346 million for the period from October 5, 2012 to December 31, 2012, the period from January 1, 2012 to October 4, 2012, and the years ended December 31, 2011 and 2010, respectively.

Net income attributable to partners was $139 million for the period from October 5, 2012 to December 31, 2012 compared to $76 million for the fourth quarter 2011. The $63 million increase was the result of improved operating performance which benefited from strong demand for crude oil transportation services and the absence of $42 million of impairment and related charges recognized in the fourth quarter 2011. Partially offsetting these positive factors were additional depreciation and amortization expense attributable to the Partnership’s assets being adjusted to fair value in connection with the acquisition of the general partner by ETP and higher selling, general and administrative expenses attributable to increased employee costs and contract services associated with growth in the business.

Net income attributable to partners was $381 million for the period from January 1, 2012 to October 4, 2012 compared to $237 million for the nine months ended September 30, 2011. The $144 million increase in 2012 was due primarily to improved operating performance which benefited from strong demand for crude oil transportation services, contributions from our 2011 acquisitions and organic projects. Included in current year results were gains of $25 million due to the reversal of regulatory obligations that were recorded in 2011, a contract settlement in connection with the sale of a refined products terminal and pipeline assets and an asset sale by one of the Partnership’s joint venture interests. These positive factors were partially offset by increased interest expense related primarily to the $600 million Senior Notes offering in July 2011 and higher selling, general and administrative expenses attributable to increased employee costs, incentive compensation and contract services associated with growth in the business.

Net income attributable to partners for 2011 decreased $33 million compared to the prior year period due primarily to the absence of a $128 million non-cash gain on our acquisition of additional interests in Mid-Valley and West Texas Gulf. The gain resulted from an adjustment to record our previous ownership interest at fair value in accordance with acquisition accounting rules. Also contributing to the decrease was a $42 million charge in 2011 for certain crude oil terminal assets which would have been negatively impacted if Sunoco’s Philadelphia refinery was permanently idled. Excluding these items, net income increased $137 million compared to 2010. Improved results from our operations were partially offset by higher interest expense related to debt offerings in 2011 and 2010. Proceeds from these offerings were used to fund growth initiatives and finance the IDR repurchase and exchange transaction.

Analysis of Operating Segments

We manage our operations through four operating segments: Crude Oil Pipelines, Crude Oil Acquisition and Marketing, Terminal Facilities and Refined Products Pipelines.

Crude Oil Pipelines

Our Crude Oil Pipelines segment consists of crude oil trunk and gathering pipelines in the southwest and midwest United States. Revenues are generated from tariffs and the associated fees paid by shippers utilizing our

 

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transportation services to deliver crude oil and other feedstocks to refineries within those regions. Rates for shipments on these pipelines are regulated by the Federal Energy Commission (“FERC”), Oklahoma Corporation Commission (“OCC”) and the Railroad Commission of Texas (“Texas R.R.C.”).

The following table presents the operating results and key operating measures for our Crude Oil Pipelines segment for the periods presented:

 

    Successor     Predecessor  
    Period from Acquisition
(October 5, 2012) to
December 31, 2012(1)
    Period from
January 1, 2012 to
October 4, 2012(1)
    Three Months
Ended
December  31,
2011
    Nine Months
Ended
September  30,
2011
    Total
2011
    Year Ended
December  31,
2010(2)
 
   

(in millions, except

for barrel amounts)

    (in millions, except for barrel amounts)  

Sales and other operating revenue

             

Unaffiliated customers

  $ 70      $ 187      $ 55      $ 141      $ 196      $ 117   

Affiliates

    —          —          —          6        6        25   

Intersegment revenue

    40        101        31        86        117        79   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total sales and other operating revenue

  $ 110      $ 288      $ 86      $ 233      $ 319      $ 221   

Depreciation and amortization expense

  $ 22      $ 19      $ 6      $ 19      $ 25      $ 21   

Adjusted EBITDA

  $ 72      $ 203      $ 58      $ 149      $ 207      $ 156   

Pipeline throughput (thousands of barrels per day (“bpd”))(3)(4)

    1,584        1,546        1,577        1,591        1,587        1,183   

Pipeline revenue per barrel (cents)(4)

    75.6        68.0        58.9        53.7        55.0        50.7   

 

(1) 

The effective date of the acquisition for accounting and reporting purposes was deemed to be October 1, 2012. The activity from October 1, 2012 through October 4, 2012 was not material in relation to the Partnership’s financial position, results of operations or cash flows.

(2) 

In the third quarter 2011, we realigned our reporting segments to separately report the results of the Crude Oil Pipelines and Crude Oil Acquisition and Marketing segments, which had previously been combined. For comparative purposes, all prior period amounts have been recast to reflect the new segment reporting.

(3) 

In July and August 2010, we acquired controlling financial interests in Mid-Valley and West Texas Gulf, respectively, and we accounted for the entities as consolidated subsidiaries from the dates of their respective acquisitions. Average volumes for the year ended December 31, 2010 of 278 thousand bpd have been included in the consolidated total. From the dates of acquisition, these pipelines had actual throughput of 696 thousand bpd for the year ended December 31, 2010.

(4) 

Excludes amounts attributable to equity ownership interests in corporate joint ventures which are not consolidated.

Adjusted EBITDA for the period from October 5, 2012 to December 31, 2012 increased $14 million compared to the prior year period due primarily to higher pipeline tariffs which were the result of organic projects placed into service during 2012 and an improved mix of higher tariff movements driven by strong demand for West Texas crude oil ($24 million). These improvements were partially offset by lower pipeline operating gains ($3 million), higher maintenance and integrity management costs ($3 million) and increased selling, general and administrative expenses ($3 million) compared to the prior year period.

Adjusted EBITDA for the Crude Oil Pipelines segment increased $54 million to $203 million for the period from January 1, 2012 to October 4, 2012, as compared to $149 million for the nine months ended September 30, 2011. The increase in Adjusted EBITDA was driven primarily by higher pipeline fees which benefited from tariff increases relative to the prior year period, organic growth projects and an improved mix of pipeline movements which benefited from the demand for West Texas crude oil ($61 million). Partially offsetting these improvements were increased selling, general and administrative expenses ($7 million) and overall volume reductions ($6 million).

Adjusted EBITDA for the Crude Oil Pipelines segment increased $51 million to $207 million for the year ended December 31, 2011 compared to the prior year. The increase in Adjusted EBITDA was driven primarily

 

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by full year results of the 2010 acquisitions of controlling financial interests in the Mid-Valley and West Texas Gulf pipelines and an increase in pipeline revenue per barrel ($32 million), which benefited from regulated tariff increases and increased demand for West Texas crude oil. The improvements were partially offset by increased operating expenses ($3 million) due primarily to increased property tax and utility expenses.

Crude Oil Acquisition and Marketing

Our Crude Oil Acquisition and Marketing segment reflects the sale of gathered and bulk purchased crude oil. The crude oil acquisition and marketing operations generate substantial revenue and cost of products sold as a result of the significant volume of crude oil bought and sold. However, the absolute price levels of crude oil normally do not bear a relationship to gross profit, although the price levels significantly impact revenue and costs of products sold. As a result, period-to-period variations in revenue and cost of products sold are not generally meaningful in analyzing the variation in gross profit for the Crude Oil Acquisition and Marketing segment. The operating results of the Crude Oil Acquisition and Marketing segment are affected by overall levels of supply and demand for crude oil and relative fluctuations in market related indices. Generally, we expect a base level of earnings from our Crude Oil Acquisition and Marketing segment that may be optimized and enhanced when there is a high level of market volatility, favorable basis differentials and/or a steep contango or backwardated structure. Our management believes gross profit, which is equal to sales and other operating revenue less cost of products sold and operating expenses, is a key measure of financial performance for the Crude Oil Acquisition and Marketing segment. Although we implement risk management activities to provide general stability in our margins, these margins are not fixed and will vary from period to period.

The following table presents the operating results and key operating measures for our Crude Oil Acquisition and Marketing segment for the periods presented:

 

    Successor     Predecessor  
    Period from Acquisition
(October 5, 2012) to
December 31, 2012(1)
    Period from
January 1, 2012 to
October 4, 2012(1)
    Three Months
Ended
December  31,
2011(2)
    Nine Months
Ended
September  30,

2011(2)
    Total
2011(2)
    Year Ended
December 31,

2010(3)
 
    (in millions, except for
barrel amounts)
    (in millions, except for barrel amounts)  
             

Sales and other operating revenue

             

Unaffiliated customers

  $ 2,747      $ 8,951      $ 3,135      $ 6,780      $ 9,915      $ 6,388   

Affiliates

    139        307        —          247        247        894   

Intersegment revenue

    2        —          —          1        1        —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total sales and other operating revenue

  $ 2,888      $ 9,258      $ 3,135      $ 7,028      $ 10,163      $ 7,282   

Depreciation and amortization expense

  $ 11      $ 16      $ 5      $ 5      $ 10      $ 2   

Impairment charge and related matters (4)

  $ —        $ 8      $ —        $ —        $ —        $ —     

Adjusted EBITDA

  $ 81      $ 158      $ 68      $ 80      $ 148      $ 39   

Crude oil purchases (thousands of bpd)

    669        674        690        654        663        638   

Gross profit per barrel purchased (cents) (5)

    138.0        92.8        111.8        49.8        66.0        21.0   

Average crude oil price (per barrel)

  $ 88.20      $ 96.20      $ 94.02      $ 95.52      $ 95.14      $ 79.55   

 

(1) 

The effective date of the acquisition for accounting and reporting purposes was deemed to be October 1, 2012. The activity from October 1, 2012 through October 4, 2012 was not material in relation to the Partnership’s financial position, results of operations or cash flows.

(2) 

Includes results from the crude oil acquisition and marketing business acquired from Texon in August 2011 from the acquisition date.

(3) 

In the third quarter 2011, we realigned our reporting segments to separately report the results of the Crude Oil Pipelines and Crude Oil Acquisition and Marketing segments, which had previously been combined. For comparative purposes, all prior period amounts have been recast to reflect the new segment reporting.

 

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(4) 

In the first quarter 2012, the Partnership recognized a non-cash impairment charge related to a cancelled software project.

(5) 

Represents total segment sales and other operating revenue minus cost of products sold and operating expenses, divided by crude oil purchases.

Adjusted EBITDA for the period from October 5, 2012 to December 31, 2012 increased $13 million compared to the prior year period due primarily to expanded crude oil margins which were the result of expansion in our crude oil trucking fleet, market related opportunities in West Texas and contributions from the assets acquired from Texon in the third quarter of 2011 ($23 million). These improvements were partially offset by overall volume reductions ($2 million) and higher selling, general and administrative expenses ($2 million).

Adjusted EBITDA for the Crude Oil Acquisition and Marketing segment increased $78 million to $158 million for the period from January 1, 2012 to October 4, 2012, as compared to $80 million for the nine months ended September 30, 2011. The increase in Adjusted EBITDA was driven primarily by expanded crude oil volumes and margins which were the result of expansion in our crude oil trucking fleet and market related opportunities in West Texas. Operating results were further improved by increased volumes and margins from the crude oil acquisition and marketing assets acquired from Texon in the third quarter 2011.

Adjusted EBITDA for the Crude Oil Acquisition and Marketing segment in 2011 increased $109 million to $148 million compared to the prior year period. The increase in Adjusted EBITDA was driven primarily by expanded crude oil margins ($102 million) and increased volumes ($2 million). Operating results for 2011 were improved by expansion of our crude oil trucking fleet during the year and increased production in the Eagle Ford Shale and West Texas regions, which had limited takeaway capacity and served to increase the pricing differential between the price of domestic and foreign crude oil. Further contributing to these improvements were increased volumes and margins from the crude oil acquisition and marketing assets acquired from Texon, which provided us with exposure into the Bakken shale and gulf coast of Texas and expanded our market share in areas in which we previously operated. These improvements were partially offset by reduced storage activity during 2011 resulting from a narrowing of the contango market structure compared to 2010.

Terminal Facilities

Our Terminal Facilities segment consists primarily of crude oil and refined products terminals and a refined products acquisition and marketing business. The Terminal Facilities segment earns revenue by providing storage, terminalling, blending and other ancillary services to our customers, as well as through the sale of refined products.

 

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The following table presents the operating results and key operating measures for our Terminal Facilities segment for the periods presented:

 

    Successor     Predecessor  
    Period from Acquisition
(October 5, 2012) to
December 31, 2012(1)
    Period from
January 1, 2012 to
October 4, 2012(1)
    Three Months
Ended
December  31,
2011
    Nine Months
Ended
September  30,
2011
    Total
2011
    Year Ended
December  31,
2010
 
    (in millions, except for
barrel amounts)
    (in millions, except for barrel amounts)  

Sales and other operating revenue

             

Unaffiliated customers

  $ 148      $ 264      $ 116      $ 181      $ 297      $ 142   

Affiliates

    50        118        34        81        115        122   

Intersegment revenue

    8        24        6        17        23        23   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total sales and other operating revenue

  $ 206      $ 406      $ 156      $ 279      $ 435      $ 287   

Depreciation and amortization expense

  $ 23      $ 28      $ 10      $ 24      $ 34      $ 26   

Impairment charge and related
matters(2)

  $ —        $ (10   $ 42      $ —        $ 42      $ 3   

Adjusted EBITDA

  $ 52      $ 173      $ 36      $ 113      $ 149      $ 127   

Terminal throughput (thousands of  bpd)(3)

             

Refined products terminals

    451        499        514        485        492        488   

Nederland terminal

    787        703        692        779        757        729   

Refinery terminals

    411        369        505        422        443        465   

 

(1) 

The effective date of the acquisition for accounting and reporting purposes was deemed to be October 1, 2012. The activity from October 1, 2012 through October 4, 2012 was not material in relation to the Partnership’s financial position, results of operations or cash flows.

(2) 

In the fourth quarter 2011, the Partnership recognized a $42 million charge for certain crude oil terminal assets in connection with Sunoco’s decision to exit the refining business. In the second quarter 2012, the Partnership recognized a $10 million gain on the reversal of certain regulatory obligations as such expenses were no longer expected to be incurred as the Philadelphia refinery will continue to operate in connection with Sunoco’s joint venture with The Carlyle Group.

(3) 

In July and August 2011, we acquired the Eagle Point tank farm and a refined products terminal located in East Boston, Massachusetts, respectively. Volumes and revenues for these acquisitions are included from their respective acquisition dates.

Adjusted EBITDA for the period from October 5, 2012 to December 31, 2012 increased $16 million compared to the prior year period. During the fourth quarter 2011, the Partnership recognized an $11 million charge for certain regulatory obligations which were expected to be incurred if Sunoco’s Philadelphia refinery were shut-down. Excluding this amount, Adjusted EBITDA for the Terminal Facilities segment increased $5 million compared to the prior year period due primarily to increased operating results from the Partnership’s refined products acquisition and marketing activities and contributions from organic projects to expand services at the Partnership’s Eagle Point and Nederland terminals ($3 million). Partially offsetting these improvements were decreased volumes at the Partnership’s refined products terminals, increased repair costs resulting from Hurricane Sandy ($3 million) and increased selling, general and administrative expenses.

Adjusted EBITDA for the Terminal Facilities segment increased $60 million to $173 million for the period from January 1, 2012 to October 4, 2012, as compared to $113 million for the nine months ended September 30, 2011. Results for 2012 included non-recurring gains related to the reversal of certain regulatory obligations that were recorded in 2011 ($10 million) and a contract settlement associated with the Partnership’s sale of the Big Sandy terminal and pipeline assets ($6 million). Excluding these items, Adjusted EBITDA increased $44 million due to contributions from the 2011 acquisitions of the Eagle Point tank farm and a refined products terminal in East Boston, Massachusetts ($17 million), operating results from the Partnership’s refined products acquisition

 

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and marketing activities ($12 million) and improved results from the Partnership’s Nederland Terminal ($5 million). Partially offsetting these increases were reduced volumes at the Partnership’s refinery terminals related to the idling of Sunoco’s Marcus Hook refinery in the fourth quarter 2011 ($4 million) and increased selling, general and administrative expenses ($5 million).

Adjusted EBITDA for the Terminal Facilities segment increased $22 million to $149 million for the year ended December 31, 2011. These improvements compared to 2010 were due primarily to expansion of our refined products acquisition and marketing activities ($24 million), which include butane blending services, contributions from the acquisitions of the Eagle Point tank farm and East Boston, Massachusetts refined products terminal ($4 million) and higher volumes and fees from our Nederland Terminal ($4 million). Partially offsetting these improvements was an $11 million charge for regulatory obligations which would have been incurred if Sunoco’s Philadelphia refinery were shut-down.

Refined Products Pipelines

Our Refined Products Pipelines segment consists of refined products pipelines, including a two-thirds undivided interest in the Harbor pipeline and joint venture interests in four refined products pipelines in selected areas of the United States. The Refined Products Pipeline System earns revenues by transporting refined products from refineries in the northeast, midwest and southwest United States to markets in six states. Rates for shipments on these pipelines are regulated by the FERC and the Pennsylvania Public Utility Commission (“PA PUC”).

The following table presents the operating results and key operating measures for our Refined Products Pipelines segment for the periods presented:

 

    Successor     Predecessor  
    Period from Acquisition
(October 5, 2012) to
December 31, 2012 (1)
    Period from
January 1, 2012
to October 4,
2012 (1)
    Three Months
Ended
December 31,
2011
    Nine Months
Ended
September 30,
2011
    Total
2011
    Year Ended
December 31,
2010
 
    (in millions, except
for barrel amounts)
    (in millions, except for barrel amounts)  

Sales and other operating revenue

           

Unaffiliated customers

  $ 24      $ 58      $ 20      $ 45      $ 65      $ 44   

Affiliates

    11        36        16        48        64        76   

Intersegment revenue

    —           2        1        —           1        —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total sales and other operating revenue

  $ 35      $ 96      $ 37      $ 93      $ 130      $ 120   

Depreciation and amortization expense

  $ 7      $ 13      $ 4      $ 13      $ 17      $ 15   

Impairment charge and related matters

  $ —        $ 1      $ —        $ —        $ —        $ —     

Adjusted EBITDA

  $ 14      $ 57      $ 17      $ 52      $ 69      $ 77   

Pipeline throughput (thousands of bpd)(2)(3)

    601        565        599        496        522        468   

Pipeline revenue per barrel (cents)(3)

    63.0        62.2        67.5        68.6        68.3        70.0   

 

(1) 

The effective date of the acquisition for accounting and reporting purposes was deemed to be October 1, 2012. The activity from October 1, 2012 through October 4, 2012 was not material in relation to the Partnership’s financial position, results of operations or cash flows.

(2) 

In May 2011, we acquired a controlling financial interest in Inland and we accounted for the entity as a consolidated subsidiary from the date of acquisition. Average volumes for the year ended December 31, 2011 of 88 thousand bpd have been included in the consolidated total. From the date of acquisition, this pipeline had actual throughput of 140 thousand bpd for the year ended December 31, 2011.

(3) 

Excludes amounts attributable to equity ownership interests in corporate joint ventures which are not consolidated.

Adjusted EBITDA for the period from October 5, 2012 to December 31, 2012 decreased $3 million compared to the prior year period due primarily to a shift to shorter pipeline movements at lower average tariffs

 

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($3 million). Further contributing to the decrease in results were higher selling, general and administrative expenses ($3 million). The decreases were partially offset by lower pipeline operating losses ($2 million).

Adjusted EBITDA for the Refined Products Pipelines increased $5 million to $57 million for the period from January 1, 2012 to October 4, 2012, as compared to the nine months ended September 30, 2011. Results for 2012 include non-recurring gains for a contract settlement associated with the Big Sandy refined products terminal and pipeline asset sale ($5 million) and an asset sale recognized by Explorer Pipeline Company ($6 million). Excluding these items, Adjusted EBITDA decreased $6 million compared to the prior period. Increased contributions from the acquisition of the Inland refined products pipeline ($5 million) were offset by lower pipeline volumes and fees driven primarily by the idling of the Marcus Hook refinery ($9 million) and increased environmental remediation expenses associated with a pipeline release in the first quarter 2012 ($4 million).

Adjusted EBITDA for the Refined Products Pipelines segment decreased $8 million to $69 million for the year ended December 31, 2011. Adjusted EBITDA decreased compared to 2010 due primarily to lower volumes on our refined products pipelines in the northeast and southwest United States ($9 million). Volumes were negatively impacted during 2011 by unplanned maintenance activity at Sunoco’s refineries during the first half of 2011.

Liquidity and Capital Resources

Liquidity

Cash generated from operations and borrowings under the $585 million of credit facilities are our primary sources of liquidity. At December 31, 2012, we had a net working capital surplus of $259 million and available borrowing capacity of $446 million under our revolving credit facilities which includes $15 million of available borrowing capacity from West Texas Gulf’s revolving credit facility. In January 2013, the balances outstanding under the Operating Partnership’s credit facilities were repaid in connection with the senior notes offering (see below). The primary driver of the working capital surplus was the decrease in current liabilities related to the repayment of the $250 million Senior Notes in February 2012 and the increase in current assets attributable to the value of crude oil inventory, which was adjusted to fair value in connection with the acquisition of the general partner by ETP. Our working capital position reflects crude oil and refined products inventories based on historical costs under the last-in, first-out (“LIFO”) method of accounting. We periodically supplement our cash flows from operations with proceeds from debt and equity financing activities.

Capital Resources

Credit Facilities

The Operating Partnership maintains two credit facilities totaling $550 million to fund the Operating Partnership’s working capital requirements, finance acquisitions and capital projects and for general partnership purposes. The credit facilities consist of a $350 million unsecured credit facility which expires in August 2016 (the “$350 million Credit Facility”) and a $200 million unsecured credit facility which expires in August 2013 (the “$200 million Credit Facility”). Outstanding borrowings under these credit facilities were $119 million at December 31, 2012.

The $350 million and $200 million credit facilities contain various covenants limiting our ability to a) incur further indebtedness, b) grant certain liens, c) make certain loans, acquisitions and investments, d) make any material change to the nature of our business, e) acquire another company, or f) enter into a merger or sale of assets, including the sale or transfer of interests in the Partnership’s subsidiaries. The $350 million and $200 million credit facilities also limit us, on a rolling four-quarter basis, to a maximum total debt to Adjusted EBITDA, as defined in the underlying credit agreement, ratio of 5.0 to 1, which could generally be increased to 5.50 to 1 during an acquisition period. Our ratio of total debt, excluding net unamortized fair value adjustments, to Adjusted EBITDA was 2.0 to 1 at December 31, 2012, as calculated in accordance with the credit agreements.

 

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In connection with the acquisition of Sunoco by ETP in October 2012, Sunoco’s interests in the general partner and limited partnership were contributed to ETP, resulting in a change of control of the Partnership’s general partner. This would have represented an event of default under the Partnership’s credit facilities as the general partner interest would no longer be owned by Sunoco. During the third quarter 2012, the Partnership amended this provision of its credit facilities to avoid an event of default upon the transfer of the general partner interest to ETP.

In May 2012, West Texas Gulf entered into a $35 million revolving credit facility (the “$35 million Credit Facility”) which expires in April 2015. The facility is available to fund West Texas Gulf’s general corporate purposes including working capital and capital expenditures. The credit facility also limits West Texas Gulf, on a rolling four-quarter basis, to a minimum fixed charge coverage ratio, as defined in the underlying credit agreement. The ratio for the fiscal quarter ending December 31, 2012 shall not be less than 1.00 to 1. The minimum ratio fluctuates between 0.80 to 1 and 1.00 to 1 throughout the term of the revolver as specified in the credit agreement. In addition, the credit facility limits West Texas Gulf to a maximum leverage ratio of 2.00 to 1. West Texas Gulf’s fixed charge coverage ratio and leverage ratio were 1.29 to 1 and 0.62 to 1, respectively, at December 31, 2012. Outstanding borrowings under this credit facility were $20 million at December 31, 2012.

Promissory Note, Affiliated Companies

In July 2010, the Operating Partnership entered into a subordinated $100 million variable rate promissory note due to Sunoco in May 2013 to fund a portion of the purchase price of our July 2010 acquisition of the butane blending business discussed earlier. The note was repaid in full during the fourth quarter 2011.

Senior Notes

The Operating Partnership had $250 million of 7.25 percent Senior Notes which matured and were repaid in February 2012.

In January 2013, the Operating Partnership issued $350 million of 3.45 percent Senior Notes and $350 million of 4.95 percent Senior Notes (the “2023 and 2043 Senior Notes”), due January 2023 and January 2043, respectively. The terms and conditions of the 2023 and 2043 Senior Notes are comparable to those under our existing senior notes. The net proceeds of $691 million from the 2023 and 2043 Senior Notes were used to pay outstanding borrowings under the $350 and $200 million credit facilities and for general partnership purposes.

In July 2011, the Operating Partnership issued $300 million of 4.65 percent Senior Notes and $300 million of 6.10 percent Senior Notes (the “2022 and 2042 Senior Notes”), due February 2022 and February 2042, respectively. The net proceeds of $595 million from the 2022 and 2042 Senior Notes were used to pay down outstanding borrowings under the prior credit facilities, which were used to fund the acquisitions of a controlling financial interest in Inland and the Texon crude oil acquisition and marketing business, and for general partnership purposes.

In February 2010, the Operating Partnership issued $250 million of 5.50 percent Senior Notes and $250 million of 6.85 percent Senior Notes, due February 2020 and February 2040, respectively. The net proceeds of $494 million from the 2020 and 2040 Senior Notes were used to repay the $201 million promissory note issued in connection with the Partnership’s repurchase and exchange of its IDR interest, repay outstanding borrowings under the prior credit facility and for general partnership purposes.

Equity Offerings

In July 2011, we issued 3.9 million Class A Units to Sunoco in connection with the acquisition of the Eagle Point tank farm and related assets. The deferred distribution units were a new class of units that converted to common units in July 2012. Prior to their conversion, the Class A units participated in the allocation of net

 

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income on a pro-rata basis with the common units. In connection with this transaction, the general partner contributed $2 million to the Partnership to maintain its two percent general partner interest.

In August 2010, we completed a public offering of 6.0 million limited partnership units. Net proceeds of $143 million were used to finance the purchase of our additional ownership interests in Mid-Valley, West Texas Gulf and West Shore and to reduce outstanding borrowings under the Operating Partnership’s prior credit facility. In connection with this offering, the general partner contributed $3 million to the Partnership to maintain its two percent general partner interest.

Cash Flows and Capital Expenditures

Net cash provided by operating activities for the periods from October 5, 2012 to December 31, 2012, from January 1, 2012 to October 4, 2012, and for the years ended December 31, 2011 and 2010 was $280, $411, $430, and $341 million, respectively. Net cash provided by operating activities in the 2012 periods was primarily the result of net income and non-cash charges for depreciation and amortization totaling $139 million. Net cash provided by operating activities for 2011 was primarily the result of net income of $322 million. Also contributing to net cash provided by operating activities for 2011 were non-cash charges for depreciation and amortization of $86 million and a $42 million charge, which was comprised of a $31 million asset impairment for crude oil terminal assets which were expected to be negatively impacted by the idling of Sunoco’s Philadelphia refinery and $11 million for regulatory obligations which would have been incurred if these assets were permanently idled. These sources were partially offset by a $35 million increase in working capital. The change in working capital was primarily the result of an increase in accounts receivable and an increase in refined products and crude oil inventories driven by growth within our acquisition and marketing activities. These changes were partially offset by increases in accounts payable. Net cash provided by operating activities for 2010 was primarily the result of net income of $220 million (excluding a $128 million non-cash gain in connection with the acquisitions of additional interests in Mid-Valley and West Texas Gulf). Also contributing to net cash provided by operating activities were non-cash charges for depreciation and amortization of $64 million and a $55 million decrease in working capital. The change in working capital was primarily the result of the liquidation of contango inventory positions.

Net cash used in investing activities for the periods from October 5, 2012 to December 31, 2012, from January 1, 2012 to October 4, 2012, and for the years ended December 31, 2011 and 2010 was $139, $224, $609 and $426 million, respectively. Net cash used in investing activities in the 2012 periods consisted of expansion capital projects and maintenance capital on our existing assets, partially offset by $11 million of proceeds received for the sale of the Big Sandy terminal and pipeline assets and the settlement of related throughput and deficiency contracts. Investing activities in 2011 and 2010 included $396 and $252 million of acquisitions, respectively, as well as expansion capital projects and maintenance capital on our existing assets. See “Capital Requirements” below for additional details on our investing activities.

Net cash provided by (used in) financing activities for the periods from October 5, 2012 to December 31, 2012, from January 1, 2012 to October 4, 2012, and for the years ended December 31, 2011 and 2010 was $(140), $(190), $182 and $85 million, respectively.

Net cash used in financing activities for the period from October 5, 2012 to December 31, 2012 was primarily attributable to $74 million in distributions paid to the limited partners and the general partner and net repayments of $40 million under our revolving credit facilities. Net cash used in financing activities for the period from January 1, 2012 to October 4, 2012 resulted primarily from the $250 million repayment of 7.25 percent Senior Notes in February 2012 and $178 million in distributions paid to limited partners and the general partner. These uses of cash were partially offset by $179 million of net credit facility borrowings and a $69 million decrease in advances to affiliates.

For the year ended December 31, 2011, the $182 million of cash provided by financing activities was primarily attributable to $595 million of net proceeds from the issuance of $600 million of Senior Notes. These

 

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proceeds were primarily used to pay down outstanding borrowings under the revolving credit facilities, which were used to finance the acquisitions of the controlling financial interest in Inland and the Texon crude oil acquisition and marketing business, and for general partnership purposes. This source of cash was partially offset by $210 million of quarterly distributions to the limited and general partners; the repayment of the $100 million promissory note to Sunoco; an increase in advances to affiliates of $63 million; and $31 million of net repayments under our revolving credit facilities.

For the year ended December 31, 2010, the $85 million of cash provided by financing activities was primarily attributable to net proceeds of $494 million from the issuance of $500 million of Senior Notes, net proceeds of $143 million related to our August 2010 equity offering and $100 million of proceeds from the July 2010 promissory note with Sunoco. These financing sources were used primarily to fund our 2010 acquisitions and growth projects and repay the $201 million promissory note issued in connection with the repurchase and exchange of the general partner’s IDRs. Cash provided by these sources were offset by $189 million of quarterly distributions to the limited and general partners and $238 million of net repayments under our prior credit facility.

Under a treasury services agreement with Sunoco, we participate in Sunoco’s centralized cash management program. Advances to affiliates in our consolidated balance sheets at December 31, 2012 and 2011 represent amounts due from Sunoco under this agreement.

Capital Requirements

Our operations are capital intensive, requiring significant investment to maintain, upgrade and enhance existing assets and to meet environmental and operational regulations. The capital requirements have consisted, and are expected to continue to consist, primarily of:

 

   

Maintenance capital expenditures that extend the usefulness of existing assets, such as those required to maintain equipment reliability, tankage and pipeline integrity and safety, and to address environmental regulations,

 

   

Expansion capital expenditures to acquire and integrate complementary assets to improve operational efficiencies or reduce costs and to expand existing and construct new facilities, such as projects that increase storage or throughput volume, and

 

   

Major acquisitions to acquire and integrate complementary assets to grow the business, to improve operational efficiencies or reduce costs.

The following table summarizes maintenance and expansion capital expenditures, including amounts paid for acquisitions, for the periods from October 5, 2012 to December 31, 2012, from January 1, 2012 to October 4, 2012, and for the years ended December 31, 2011 and 2010:

 

    Successor     Predecessor  
    Period from  Acquisition
(October 5, 2012) to
December 31, 2012
    Period  from
January 1, 2012 to
October 4, 2012
    Year Ended December 31,  
        2011     2010  
    (in millions)     (in millions)  

Maintenance

  $ 21      $ 29      $ 42      $ 37   

Expansion

    118        206        171        137   

Major Acquisitions

    —           —           396        252   
 

 

 

   

 

 

   

 

 

   

 

 

 

Total

  $ 139      $ 235      $ 609      $ 426   
 

 

 

   

 

 

   

 

 

   

 

 

 

Maintenance capital expenditures primarily consist of recurring expenditures at each of the business segments such as pipeline integrity costs, pipeline relocations, repair and upgrade of field instrumentation,

 

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including measurement devices, repair and replacement of tank floors and roofs, upgrades of cathodic protection systems and related equipment, and the upgrade of pump stations. Management expects maintenance capital expenditures to be approximately $65 million in 2013.

Expansion capital expenditures in the 2012 periods included projects to expand upon the Partnership’s refined products acquisition and marketing services, upgrade the service capabilities at the Eagle Point and Nederland terminals, invest in the Partnership’s crude oil infrastructure by increasing its pipeline capabilities through previously announced growth projects in West Texas and expanding the trucking fleet, and invest in the previously announced Mariner West and Mariner East Projects. Expansion capital for 2011 included projects to expand upon our butane blending services, increase tankage at the Nederland facility, increase connectivity of the crude oil pipeline assets in Texas and increase our crude oil trucking fleet to meet the demand for transportation services in the southwest United States. Expansion capital for the year ended December 31, 2010 included construction projects to expand services at our refined products terminals, increase tankage at the Nederland facility and expand upon our refined products platform in the southwest United States.

Major acquisitions during the year ended December 31, 2011 included the East Boston, Massachusetts terminal, the Texon crude oil purchasing and marketing business, the Eagle Point tank farm and an 83.8 percent equity interest in Inland which owns a refined products pipeline system in Ohio. Major acquisitions during the year ended December 31, 2010 included a butane blending business, a controlling financial interest in Mid-Valley and West Texas Gulf, an additional ownership interest in West Shore, and two terminals in Texas.

Management expects expansion capital projects to total approximately $700 million in 2013, excluding major acquisitions. Projected expansion capital includes spending on previously announced growth projects and spending to capture more value from existing assets such as the Eagle Point terminal, the Nederland Terminal and our patented butane blending technology.

We expect to fund our capital expenditures, including any additional acquisitions, from cash provided by operations, with proceeds from debt and equity offerings and, to the extent necessary, from the proceeds of borrowings under the credit facilities.

Contractual Obligations

The following table sets forth the aggregate amount of long-term debt maturities, annual rentals applicable to non-cancelable operating leases, and purchase commitments related to future periods at December 31, 2012:

 

     Year Ended December 31,      Thereafter      Total  
     2013     2014      2015      2016      2017        
     (in millions)  

Long-term debt:

                   

Principal

   $ 119 (1)    $ 175       $ 20       $ 175       $  —         $ 1,100       $ 1,589   

Interest

     89        76         74         67         63         907         1,276   

Operating leases

     11        11         10         8         5         2         47   

Purchase obligations

     2,404        —           —           —           —           —           2,404   
  

 

 

   

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
   $ 2,623      $ 262       $ 104       $ 250       $ 68       $ 2,009       $ 5,316   
  

 

 

   

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) 

Consists of amounts outstanding under the Partnership’s $350 and $200 million credit facilities at December 31, 2012 that were repaid in connection with the January 2013 senior notes offering.

Our operating leases reported above include leases of office space, third-party pipeline capacity, and other property and equipment, with initial or remaining non-cancelable terms in excess of one year.

 

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A purchase obligation is an enforceable and legally binding agreement to purchase goods and services that specifies significant terms, including: fixed or expected quantities to be purchased; market-related pricing provisions; and a specified term. Our purchase obligations consist primarily of non-cancelable contracts to purchase crude oil for terms of one year or less by our Crude Oil Acquisition and Marketing segment and non-cancelable contracts to purchase butane for terms of one year or less by our refined products acquisition and marketing business.

A significant portion of the above purchase obligations relate to actual crude oil purchases for the month of January 2013. The remaining crude oil purchase obligation amounts are based on the quantities committed to be purchased, assuming adequate well production for the remainder of the year, at December 31, 2012 crude oil prices. Actual amounts to be paid in regards to these obligations will be based upon market prices or formula-based market prices during the period of purchase. For further discussion of our Crude Oil Acquisition and Marketing activities, see Item 1. “Business—Crude Oil Acquisition and Marketing.”

Off-Balance Sheet Arrangements

We have not entered into any transactions, agreements or other contractual arrangements that would result in off-balance sheet liabilities.

Environmental Matters

Operation of the pipelines, terminals, and associated facilities are subject to stringent and complex federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment. As a result of compliance with these laws and regulations, liabilities have been accrued for estimated site restoration costs to be incurred in the future at the facilities and properties, including liabilities for environmental remediation obligations. Under our accounting policies, liabilities are recorded when site restoration and environmental remediation and cleanup obligations are either known or considered probable and can be reasonably estimated. For a discussion of the accrued liabilities and charges against income related to these activities, see Note 11 to the consolidated financial statements included in Item 8. “Financial Statements and Supplementary Data.”

Under the terms of the Omnibus Agreement and in connection with the contribution of assets to us by affiliates of Sunoco, Sunoco has agreed to indemnify us for 30 years from environmental and toxic tort liabilities related to the assets contributed that arise from the operation of such assets prior to closing of the February 2002 initial public offering (“IPO”). See “Agreements with Related Parties.”

For more information concerning environmental matters, see Item 1. “Business—Environmental Regulation.”

Impact of Inflation

Although the impact of inflation has slowed in recent years, it is still a factor in the United States economy and may increase the cost to acquire or replace property, plant, and equipment and may increase the costs of labor and supplies. To the extent permitted by competition, regulation, and existing agreements, we have and will continue to pass along increased costs to customers in the form of higher fees.

Critical Accounting Policies

A summary of our significant accounting policies is included in Note 2 to the consolidated financial statements included in Item 8. “Financial Statements and Supplementary Data.” Management believes that the application of these policies on a consistent basis enables us to provide the users of the consolidated financial statements with useful and reliable information about our operating results and financial condition. The

 

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preparation of our consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Significant items that are subject to such estimates and assumptions include long-lived assets (including intangible assets), goodwill, and environmental remediation activities. Although management bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, actual results may differ from the estimates on which our consolidated financial statements are prepared at any given point in time.

The critical accounting policies identified by our management are as follows:

Long-Lived Assets. The cost of long-lived assets (less estimated salvage value, in the case of properties, plants and equipment), is generally depreciated on a straight-line basis over the estimated useful lives of the assets. Useful lives are based on historical experience, contract expiration or other reasonable basis, and are adjusted when changes in planned use, technological advances or other factors indicate that a different life would be more appropriate. Changes in useful lives that do not result in the impairment of an asset are recognized prospectively.

The Partnership’s long-lived assets include identifiable intangible assets which are comprised of customer relationships, which consist of throughput contracts and historical shipping rights, and technology related assets, which consist of patented technology associated with the Partnership’s butane blending services. Customer relationship intangible assets represent the estimated economic value assigned to certain relationships acquired in connection with business combinations or asset purchases whereby (i) the Partnership acquired information about or access to customers, (ii) the customers now have the ability to transact business with the Partnership and (iii) the Partnership is positioned due to limited competition to provide products or services to the customers. Technology related intangible assets are the Partnership’s patents for the blending of butane into refined products. These patents are amortized over their remaining legal lives. The value assigned to these intangible assets is amortized on a straight-line basis over their respective economic lives through depreciation and amortization expense, over a weighted average amortization period of approximately 17 years.

Long-lived assets are reviewed for impairment whenever events or circumstances indicate that the carrying amount of the assets may not be recoverable. Such events and circumstances include, among other factors: operating losses; unused capacity; market value declines; technological developments resulting in obsolescence; changes in demand for products manufactured by others utilizing our services or for our products; changes in competition and competitive practices; uncertainties associated with the United States and world economies; changes in the expected level of environmental capital, operating or remediation expenditures; and changes in governmental regulations or actions. Additional factors impacting the economic viability of long-lived assets are discussed under “Forward-Looking Statements” in this document.

A long-lived asset is considered to be impaired when the undiscounted net cash flows expected to be generated by the asset are less than its carrying amount. Such estimated future cash flows are highly subjective and are based on numerous assumptions about future operations and market conditions. The impairment recognized is the amount by which the carrying amount exceeds the fair market value of the impaired asset. It is also difficult to precisely estimate fair market value because quoted market prices for our long-lived assets may not be readily available. Therefore, fair market value is generally based on the present values of estimated future cash flows using discount rates commensurate with the risks associated with the assets being reviewed for impairment.

In 2012, the Partnership recognized a non-cash impairment charge of $9 million related to a cancelled software project for the crude oil acquisition and marketing business and a refined products pipeline project in Texas. In 2011, the Partnership recognized a $42 million charge for certain crude oil terminal assets which would have been negatively impacted if Sunoco had permanently idled its Philadelphia refinery. The charge included a $31 million non-cash impairment for asset write-downs at the Fort Mifflin Terminal Complex and $11 million

 

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for regulatory obligations which would have been incurred if these assets were permanently idled. In September 2012, Sunoco completed the formation of PES, a joint venture with The Carlyle Group, which enabled the Philadelphia refinery to continue operating. As a result, we reversed $10 million of regulatory obligations in the second quarter of 2012 which were no longer expected to be incurred. For further discussion, see “Agreements with Related Parties” discussed below. In 2010, we recognized an impairment of $3 million related to the cancellation of a terminal construction project.

Goodwill. Goodwill represents the excess of consideration transferred plus the fair value of noncontrolling interests of an acquired business over the fair value of net assets acquired. Goodwill is not amortized; however it is tested for impairment annually or more often if warranted by events or changes in circumstances indicating that the carrying value may exceed the estimated fair value.

Management’s process of evaluating goodwill for impairment involves estimating the fair value of the Partnership’s reporting units that contain goodwill. Inherent in estimating the fair value for each reporting unit are certain judgments and estimates relating to market multiples for comparable businesses, including management’s interpretation of current economic indicators and market conditions, and assumptions about the Partnership’s strategic plans with regard to its operations. To the extent additional information arises, market conditions change or the Partnership’s strategies change, it is possible that the conclusion regarding whether the goodwill is impaired could change and result in future goodwill impairment charges.

Fair value is estimated using a market multiple methodology whereby multiples of business enterprise value to EBITDA of comparable companies are used to estimate the fair value of the reporting units. Management establishes fair value by comparing the reporting unit to other companies that are similar, from an operational or industry standpoint, and considers the risk characteristics in order to determine the risk profile relative to the comparable companies as a group. The most significant assumptions are the market multiplies.

Environmental Remediation. At December 31, 2012, our accrual for environmental remediation activities was $3 million. This accrual is for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. The accrual is undiscounted and is based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. It is often extremely difficult to develop reasonable estimates of future site remediation costs due to changing regulations, changing technologies and their associated costs, and changes in the economic envir