Edgar Filing: SUNOCO LOGISTICS PARTNERS L.P.

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

Sunoco Logistics Partners LP--Form 10-K

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

¨	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.

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


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

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;

•

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.

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.

(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.

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

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.

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.

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.

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.

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

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.

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.

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.

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,

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.

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.

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

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.

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

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.

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.

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.

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

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:

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

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unplanned increases in the cost of construction materials or labor;

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

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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;

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

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changes in market conditions impacting long lead-time projects;

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

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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.

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.

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.

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

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.

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:

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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;

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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;

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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

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”);

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

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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.

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:

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

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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.

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:

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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;

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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;

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

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

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

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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

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-

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.

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.

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.

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		Declared Distributions		High		Low		Declared Distributions
1^st	$	42.11	$	35.01	$	0.4275	$	29.97	$	27.10	$	0.3983
2^nd	$	40.99	$	31.65	$	0.4700	$	30.34	$	26.00	$	0.4050
3^rd	$	50.40	$	36.29	$	0.5175	$	30.31	$	24.40	$	0.4133
4^th	$	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.”

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
	Total Quarterly Distribution Target Amount	General Partner			Unitholders			Total Quarterly Distribution Target Amount	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.

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,
			Period from January 1, 2012 to October 4, 2012		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.

⁽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,
				Period from January 1, 2012 to October 4, 2012			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,
				Period from January 1, 2012 to October 4, 2012			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


	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,
				Period from January 1, 2012 to October 4, 2012 ⁽¹⁾			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.

⁽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,
	December 31, 2012		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,
			Period from January 1, 2012 to October 4, 2012		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⁾

⁽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⁾

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

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

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

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.

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.

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

⁽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

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⁾

⁽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

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⁾

⁽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.

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

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⁾

⁽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

($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.

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

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

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,
			Period from January 1, 2012 to October 4, 2012		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,

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		Thereafter		Total
	(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.

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

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

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 environment. In the above instances, if a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point or points in the range are more likely, in which case the most likely amount in the range is accrued. Engineering studies, historical experience and other factors are used to identify and evaluate remediation alternatives and their related costs in determining the estimated accruals for environmental remediation activities. Losses attributable to unasserted claims are also reflected in the accruals to the extent their occurrence is probable and reasonably estimable.

Management believes that none of the current remediation locations are material, individually or in the aggregate, to our financial position at December 31, 2012. As a result, our exposure to adverse developments with respect to any individual site is not expected to be material. However, if changes in environmental regulations occur, such changes could impact several of our facilities. As a result, from time to time, significant charges against income for environmental remediation may occur.

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, in whole or in part, 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 IPO. We have agreed to indemnify Sunoco and its affiliates for events and conditions associated with the operation of the assets that occur on or after the closing of the IPO and for environmental and toxic tort liabilities to the extent Sunoco is not required to indemnify us. See “Agreements with Related Parties” for additional information.

In summary, total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the technology available and needed to meet the various existing legal requirements, the nature and terms of cost sharing arrangements with other potentially responsible parties and the nature and extent of future environmental laws, inflation rates and the determination of our liability at the sites, if any, in light of the number, participation level and financial viability of other parties.

New Accounting Pronouncements

For a discussion of recently issued accounting pronouncements requiring adoption subsequent to December 31, 2012, see Note 2 to the consolidated financial statements included in Item 8. “Financial Statements and Supplementary Data.”

Agreements with Related Parties

Acquisition of Sunoco

The general and limited partner interests that were previously owned by Sunoco were contributed to ETP in connection with the acquisition of Sunoco by ETP. As a result of these transactions, both the Partnership and Sunoco became consolidated subsidiaries of ETP. The Partnership has various operating and administrative agreements with Sunoco, including the agreements described below. Sunoco continues to perform the administrative functions defined in such agreements on the Partnership’s behalf. The Partnership continues to work with ETP in determining how the acquisition will impact these agreements going forward.

In March 2011, Sunoco completed the sale of its Toledo, Ohio refinery to affiliates of PBF Holding Company LLC (“PBF”). Certain agreements with Sunoco to supply or purchase crude oil and provide pipeline and terminalling services to support the Toledo refinery were assigned to PBF or its agents in connection with the sale. 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. Management assessed the impact that Sunoco’s decision to exit its refining business in the northeast would have on the Partnership’s assets that historically served the refineries and determined that the Partnership’s refined products pipeline and terminal assets continued to have expected future cash flows that support their carrying values. However, the Partnership recognized a $42 million charge in the fourth quarter 2011 for 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 completed the formation of PES, a joint venture with The Carlyle Group, which enabled the Philadelphia refinery to continue operating. During the second quarter 2012, the Partnership reversed $10 million of regulatory obligations which were no longer expected to be incurred.

Sunoco utilizes the Partnership’s pipeline and terminal assets to supply refined products to Sunoco’s retail marketing network as described below under the caption “Pipeline and Terminalling Services.” Some of these services are provided to Sunoco and its affiliates (including PES) pursuant to agreements with terms that expire at various times as described below, and some of these services are provided to Sunoco and its affiliates (including PES) pursuant to agreements that are short term in nature or subject to termination by either party. Management expects that Sunoco will continue to utilize these services for the foreseeable future. However, if Sunoco reduces its use of the Partnership’s facilities, it could adversely affect the Partnership’s results of operations, financial condition or cash flows.

We are party to various agreements with Sunoco and its affiliated entities, as discussed below.

Pipeline and Terminalling Services

•

We have a five-year product terminal services agreement with Sunoco under which Sunoco may throughput refined products through our terminals. The agreement contains no minimum throughput obligations for Sunoco. The agreement runs through February 2017.

•

We have an agreement with PES relating to the Fort Mifflin Terminal Complex. Under this agreement, PES will deliver a minimum average of 300,000 bpd of crude oil and refined products per contract year at the Fort Mifflin facility. PES does not have exclusive use of the Fort Mifflin Terminal Complex; however, we are obligated to provide the necessary tanks, marine docks and pipelines for PES to meet its minimum requirements under the agreement. We executed a 10-year agreement with PES in September 2012. We had a previous agreement with Sunoco which included terms similar to those contained in the agreement with PES.

•

We have a three-year agreement with Sunoco to provide approximately 2.0 million barrels of storage capacity and terminalling services to Sunoco at the Eagle Point tank farm which we acquired from Sunoco in 2011. The agreement expires in June 2014. Sunoco does not have exclusive use of the Eagle Point tank farm.

•

In September 2012, Sunoco assigned its lease for the use of our inter-refinery pipelines between the Philadelphia and Marcus Hook refineries to PES. Under the 20-year lease agreement which expires in February 2022, PES leases the inter-refinery pipelines for an annual fee which escalates at 1.67 percent each January 1 for the term of the agreement. The lease agreement also requires PES to reimburse us for any non-routine maintenance expenditures, as defined, incurred during the term of the agreement. There were no material reimbursements under this agreement during 2010 through 2012.

•

Sunoco is a shipper on our refined products pipelines. All movements are on the same terms that would be available to an unrelated third party and are based on published tariff rates on the respective pipelines.

Commodity Sales Agreements

•

The Partnership has agreements with Sunoco whereby Sunoco purchases refined products, at market-based rates, at certain of the Partnership’s terminal facilities. These agreements are negotiated annually and currently do not extend beyond 2013.

•

The Partnership has agreements with PES whereby PES purchases crude oil, at market-based rates, for delivery to the Partnership’s Fort Mifflin and Eagle Point terminal facilities. These agreements contain minimum volume commitments and extend through 2014.

The renegotiated terms of the agreements with PES, provide PES with the option to purchase the Fort Mifflin and Belmont terminals if certain triggering events occur including a sale of substantially all of the assets or operations of the Philadelphia refinery, an initial public offering or a public debt filing of more than $200 million. If either option is exercised before December 31, 2013, the purchase price is established based on a defined EBITDA multiple for each terminal facility. After this date, the purchase price for each facility would be established based on a fair value amount determined by designated third parties.

Omnibus Agreement

In 2002, we entered into an Omnibus Agreement with Sunoco and our general partner that addresses the following matters:

•

our obligation to pay the general partner or Sunoco an annual administrative fee for the provision by Sunoco of certain general and administrative services;

•

an indemnity by Sunoco for certain environmental, toxic tort and other liabilities; and

•

our obligation to indemnify Sunoco and its affiliates for events and conditions associated with the operation of the assets that occur on or after the closing of the IPO and for environmental and toxic tort liabilities related to the assets to the extent Sunoco is not required to indemnify us.

Administrative Services

We have no employees, and reimburse the general partner and its affiliates for certain costs and other direct expenses incurred on our behalf. In addition, we have incurred additional general and administrative costs which we pay directly.

Under the Omnibus Agreement, we pay Sunoco an annual administrative fee that includes expenses incurred by Sunoco and its affiliates to perform centralized corporate functions, such as legal, accounting, treasury, engineering, information technology, insurance, and other corporate services, including the administration of employee benefit plans. This fee was $5, $13, $13 and $5 million 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, respectively. These fees do not include the costs of shared insurance programs (which are allocated to us based upon our share of the cash premiums incurred), the salaries of pipeline and terminal personnel or other employees of the general partner, or the cost of their employee benefits.

The initial term of Section 4.1 of the Omnibus Agreement (which concerns our obligation to pay the annual fee for provision of certain general and administrative services) was through the end of 2004. The parties have extended the term of Section 4.1 annually by one year in each year following 2004. The 2012 annual fee increased to $18 million to cover additional consolidation of services provided by Sunoco that were previously provided by third parties and included an allocation of senior management costs. The costs may be increased if the acquisition or construction of new assets or businesses requires an increase in the level of general and administrative services received by us. In the event that we are unable to obtain such services from Sunoco or other third parties at or below the current cost, our results of operations and financial condition may be adversely impacted.

In addition to the fees for the centralized corporate functions, selling, general and administrative expenses in the consolidated statements of comprehensive income include the allocation of shared insurance costs of $2, $5, $4 and $4 million 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, respectively. Our share of allocated Sunoco employee benefit plan expenses, including non-contributory defined benefit retirement plans, defined contribution 401(k) plans, employee and retiree medical, dental and life insurance plans, incentive compensation plans and other such benefits was $10, $28, $26 and $29 million 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, respectively. These expenses are reflected in cost of products sold and operating expenses and selling, general and administrative expenses in the consolidated statements of comprehensive income.

Indemnification

Under the terms of the Omnibus Agreement and in connection with the contribution of assets 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 IPO. Sunoco is obligated to indemnify us for 100 percent of all losses asserted within the first 21 years of closing of the IPO. Sunoco’s share of liability for claims asserted thereafter will decrease by 10 percent a year. For example, for a claim asserted during the twenty-third year after closing of the IPO, Sunoco would be required to indemnify us for 80 percent of the loss. There is no monetary cap on the amount of indemnity coverage provided by Sunoco. 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 environmental and toxic tort liabilities not covered by this indemnity will be our responsibility. Total future costs

for environmental remediation activities will depend upon, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the technology available and needed to meet the various existing legal requirements, the nature and extent of future environmental laws, inflation rates, and the determination of the liability at multiparty sites, if any, in light of the number, participation levels, and financial viability of other parties. We have agreed to indemnify Sunoco and its affiliates for events and conditions associated with the operation of the assets that occur on or after the closing of the IPO and for environmental and toxic tort liabilities to the extent Sunoco is not required to indemnify us.

Sunoco has also agreed to indemnify us for liabilities relating to:

•

the assets contributed to the Partnership, other than environmental and toxic tort liabilities, that arise out of the operation of the assets prior to the closing of the IPO and that are asserted within ten years after the closing of the IPO;

•

certain defects in title to the assets contributed to the Partnership and failure to obtain certain consents and permits necessary to conduct the business that arise within ten years after the closing of the IPO;

•

legal actions related to the period prior to the IPO currently pending against Sunoco or its affiliates; and

•

events and conditions associated with any assets retained by Sunoco or its affiliates.

Treasury Services Agreement

We have a treasury services agreement with Sunoco pursuant to which, among other things, we participate in Sunoco’s centralized cash management program. Under this program, all of the cash receipts and cash disbursements are processed, together with those of Sunoco and its other subsidiaries, through Sunoco’s cash accounts with a corresponding credit or charge to an affiliated account. The affiliated balances are settled periodically, but no less frequently than monthly. Amounts due from Sunoco and its subsidiaries earn interest at a rate equal to the average rate of our third-party money market investments, while amounts due to Sunoco and its subsidiaries bear interest at a rate equal to the interest rate provided in the $350 million Credit Facility.

ITEM 7A. QUANTITATIVE

AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to various market risks, including changing interest rates and volatility in crude oil and refined products commodity prices. To manage such exposure, interest rates, inventory levels and expectations of future commodity prices are monitored when making decisions with respect to risk management.

Interest Rate Risk

We have interest-rate risk exposure for changes in interest rates relating to our outstanding borrowings. We manage our exposure to changing interest rates through the use of a combination of fixed- and variable-rate debt. At December 31, 2012, we had $139 million of variable-rate borrowings under our revolving credit facilities. Outstanding borrowings bear interest cost of LIBOR plus an applicable margin. An increase in short-term interest rates will have a negative impact on funds borrowed under variable-rate debt arrangements.

At December 31, 2012, we had $1.45 billion of fixed-rate borrowings which was comprised of our outstanding senior notes. This amounts excludes the $143 million premium resulting from the adjustment of our assets and liabilities to fair value resulting from the application of push-down accounting in connection with the acquisition of the general partner by ETP. The estimated fair value of our senior notes was $1.64 billion at December 31, 2012. A hypothetical one-percent decrease in interest rates would increase the fair value of our fixed-rate borrowings at December 31, 2012 by approximately $150 million.

Commodity Market Risk

We are exposed to volatility in crude oil and refined products commodity prices. To manage such exposures, inventory levels and expectations of future commodity prices are monitored when making decisions with respect to risk management and inventory carried. Our policy is to purchase only commodity products for which we have a market and to structure our sales contracts so that price fluctuations for those products do not materially affect the margin we receive. We also seek to maintain a position that is substantially balanced within our various commodity purchase and sales activities. We may experience net unbalanced positions for short periods of time as a result of production, transportation and delivery variances, as well as logistical issues associated with inclement weather conditions. When unscheduled physical inventory builds or draws do occur, they are monitored and managed to a balanced position over a reasonable period of time.

We do not use futures or other derivative instruments to speculate on crude oil or refined products prices, as these activities could expose us to significant losses. We do use derivative contracts as economic hedges against price changes related to our forecasted refined products purchase and sale activities. These derivatives are intended to have equal and opposite effects of the purchase and sale activities. At December 31, 2012, the fair market value of our open derivative positions was a net liability of $3 million on 1.5 million barrels of refined products. These derivative positions vary in length but do not extend beyond one year. The potential decline in the market value of these derivatives from a hypothetical 10-percent adverse change in the year-end market prices of the underlying commodities that were being hedged by derivative contracts at December 31, 2012 was estimated to be $13 million. This hypothetical loss was estimated by multiplying the difference between the hypothetical and the actual year-end market prices of the underlying commodities by the contract volume amounts.

For additional information concerning our commodity market risk activities, see Note 15 to the consolidated financial statements included in Item 8. “Financial Statements and Supplementary Data.”

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

MANAGEMENT’S REPORT ON INTERNAL CONTROL

OVER FINANCIAL REPORTING

Management of Sunoco Logistics Partners L.P. (the “Partnership”) is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. The Partnership’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with U.S. generally accepted accounting principles.

The Partnership’s management assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2012. In making this assessment, the Partnership’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control—Integrated Framework.

Based on this assessment, management believes that, as of December 31, 2012, the Partnership’s internal control over financial reporting is effective based on those criteria. Ernst & Young LLP, an independent registered public accounting firm, has issued an attestation report on the effectiveness of the Partnership’s internal control over financial reporting, which appears in this section.

Michael J. Hennigan

President and Chief Executive Officer

Martin Salinas, Jr.

Chief Financial Officer

REPORT OF ERNST & YOUNG LLP, INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The Board of Directors of

Sunoco Partners LLC and Limited Partners of Sunoco Logistics Partners L.P.

We have audited Sunoco Logistics Partners L.P. (“the Partnership”) internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Sunoco Logistics Partners L.P.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A partnership’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A partnership’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the partnership; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the partnership are being made only in accordance with authorizations of management and directors of the partnership; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the partnership’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Sunoco Logistics Partners L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Sunoco Logistics Partners L.P. as of December 31, 2012 (successor) and 2011 (predecessor), and the related consolidated statements of comprehensive income, equity and cash flows for the period from October 5, 2012 to December 31, 2012 (successor), the period from January 1, 2012 to October 4, 2012 (predecessor) and the years ended December 31, 2011 and 2010 (predecessor) and our report dated March 1, 2013 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Philadelphia, Pennsylvania

March 1, 2013

REPORT OF ERNST & YOUNG LLP, INDEPENDENT REGISTERED

PUBLIC ACCOUNTING FIRM ON FINANCIAL STATEMENTS

To the Board of Directors of

Sunoco Partners LLC and Limited Partners of Sunoco Logistics Partners L.P.

We have audited the accompanying consolidated balance sheets of Sunoco Logistics Partners L.P. (the “Partnership”) as of December 31, 2012 (successor) and 2011 (predecessor), and the related consolidated statements of comprehensive income, equity, and cash flows for the period from October 5, 2012 to December 31, 2012 (successor), the period from January 1, 2012 to October 4, 2012 (predecessor) and the years ended December 31, 2011 and 2010 (predecessor). These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Sunoco Logistics Partners L.P. at December 31, 2012 (successor) and 2011 (predecessor) and the consolidated results of its operations and its cash flows for the period from October 5, 2012 to December 31, 2012 (successor), the period from January 1, 2012 to October 4, 2012 (predecessor) and the years ended December 31, 2011 and 2010 (predecessor), in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Sunoco Logistics Partners L.P.’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2013 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Philadelphia, Pennsylvania

March 1, 2013

SUNOCO LOGISTICS PARTNERS L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions, except units and per unit amounts)


	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,
				Period from January 1, 2012 to October 4, 2012			2011			2010
Revenues
Sales and other operating revenue:
Unaffiliated customers	$	2,989		$	9,460		$	10,473		$	6,691
Affiliates (Note 4)		200			461			432			1,117
Other income		5			18			13			30
Gain on divestment and related matters		—			11			—			—

Total Revenues		3,194			9,950			10,918			7,838

Costs and Expenses
Cost of products sold and operating expenses		2,933			9,311			10,264			7,398
Depreciation and amortization expense		63			76			86			64
Impairment charge and related matters (Note 2)		—			(1	)		42			3
Selling, general and administrative expenses		34			86			90			72

Total Costs and Expenses		3,030			9,472			10,482			7,537

Operating Income		164			478			436			301
Net interest cost to affiliates (Note 4)		—			—			3			2
Other interest cost and debt expense, net		18			73			93			76
Capitalized interest		(4	)		(8	)		(7	)		(5	)
Gain on investments in affiliates (Note 3)		—			—			—			128

Income Before Provision for Income Taxes		150			413			347			356
Provision for income taxes (Note 2)		8			24			25			8

Net Income		142			389			322			348
Net Income attributable to noncontrolling interests		3			8			9			2

Net Income attributable to Sunoco Logistics Partners L.P.	$	139		$	381		$	313		$	346

Calculation of Limited Partners’ interest:
Net Income attributable to Sunoco Logistics Partners L.P.	$	139		$	381		$	313		$	346
Less: General Partner’s interest		(24	)		(55	)		(54	)		(48	)

Limited Partners’ interest ⁽¹⁾	$	115		$	326		$	259		$	298

Net Income attributable to Sunoco Logistics Partners L.P. per Limited Partner unit (Note 5):
Basic	$	1.11		$	3.15		$	2.56		$	3.13

Diluted	$	1.10		$	3.14		$	2.54		$	3.11

Weighted average Limited Partners’ units outstanding (Note 5):
Basic		103.8			103.5			101.3			95.2

Diluted		104.1			103.9			101.8			95.7


Net Income	$	142		$	389		$	322		$	348
Recognition of funded status of affiliates’ postretirement plans		—			—			—			1
Gain (loss) on cash flow hedges		—			(21	)		4			(2	)

Other Comprehensive Income (Loss)		—			(21	)		4			(1	)

Comprehensive Income		142			368			326			347
Less: Comprehensive income attributable to noncontrolling interests		3			8			9			2

Comprehensive Income attributable to Sunoco Logistics Partners L.P.	$	139		$	360		$	317		$	345

⁽¹⁾	Includes interest in net income attributable to Class A units, which were converted to common units in July 2012.

(See Accompanying Notes)

SUNOCO LOGISTICS PARTNERS L.P.

CONSOLIDATED BALANCE SHEETS

(in millions)


	Successor			Predecessor
	December 31, 2012			December 31, 2011
Assets
Cash and cash equivalents	$	3		$	5
Advances to affiliated companies (Note 4)		56			107
Accounts receivable, affiliated companies (Note 4)		19			-
Accounts receivable, net		1,834			2,188
Inventories (Note 6)		478			206

Total Current Assets		2,390			2,506

Properties, plants and equipment		5,673			3,234
Less accumulated depreciation and amortization		(50	)		(712	)

Properties, plants and equipment, net (Note 7)		5,623			2,522

Investment in affiliates (Note 8)		118			73
Goodwill (Note 9)		1,368			77
Intangible assets, net (Note 9)		843			277
Other assets		19			22

Total Assets	$	10,361		$	5,477

Liabilities and Equity
Accounts payable	$	1,932		$	2,111
Accounts payable, affiliated companies (Note 4)		12			—
Current portion of long-term debt (Note 10)		—			250
Accrued liabilities		127			112
Accrued taxes payable (Note 2)		60			62

Total Current Liabilities		2,131			2,535

Long-term debt (Note 10)		1,732			1,448
Other deferred credits and liabilities		60			78
Deferred income taxes (Note 2)		243			222
Commitments and contingent liabilities (Note 11)

Total Liabilities		4,166			4,283

Equity
Sunoco Logistics Partners L.P. equity
Limited Partners’ interests (103,773,003 and 99,386,301 units outstanding, respectively)		5,175			1,039
General Partner’s interest		897			34
Class A interest (3,939,435 units outstanding at December 31, 2011)		—			22
Accumulated other comprehensive income		—			1

Total Sunoco Logistics Partners L.P. equity		6,072			1,096

Noncontrolling interests		123			98

Total Equity		6,195			1,194

Total Liabilities and Equity	$	10,361		$	5,477

(See Accompanying Notes)

SUNOCO LOGISTICS PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)


	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,
				Period from January 1, 2012 to October 4, 2012			2011			2010
Cash Flows from Operating Activities:
Net Income	$	142		$	389		$	322		$	348
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense		63			76			86			64
Impairment charge and related matters		—			(1	)		42			3
(Claim for) recovery of environmental liability		13			(14	)		—			—
Deferred income tax expense		(2	)		—			(2	)		—
Amortization of financing fees and bond discount		—			2			2			2
Amortization of bond premium		(6	)		—			—			—
Restricted unit incentive plan expense		2			6			6			5
Gain on investments in affiliates		—			—			—			(128	)
Changes in working capital pertaining to operating activities:
Accounts receivable, affiliated companies		(18	)		(1	)		154			(106	)
Accounts receivable, net		162			190			(647	)		(248	)
Inventories		(70	)		(44	)		(108	)		38
Accounts payable and accrued liabilities		4			(174	)		548			360
Accounts payable, affiliated companies		12			—			—			—
Accrued taxes payable		4			(6	)		18			11
Other		(26	)		(12	)		9			(8	)

Net cash provided by operating activities		280			411			430			341

Cash Flows from Investing Activities:
Capital expenditures		(139	)		(235	)		(213	)		(174	)
Acquisitions		—			—			(396	)		(252	)
Proceeds from divestments and related matters		—			11			—			—

Net cash used in investing activities		(139	)		(224	)		(609	)		(426	)

Cash Flows from Financing Activities:
Distributions paid to limited and general partners		(74	)		(178	)		(210	)		(189	)
Distributions paid to noncontrolling interests		(2	)		(5	)		(8	)		(4	)
Net proceeds from issuance of limited partner units		—			—			—			143
Contributions from general partner		—			—			2			3
Payments of statutory withholding on net issuance of limited partner units under restricted unit incentive plan		(7	)		(5	)		(3	)		(2	)
Repayments under credit facilities		(233	)		(322	)		(560	)		(888	)
Borrowings under credit facilities		193			501			529			650
Net proceeds from issuance of long-term debt		—			—			595			494
Repayments of senior notes		—			(250	)		—			—
Promissory note from affiliate		—			—			(100	)		100
Repayment of promissory note to general partner		—			—			—			(201	)
Advances to affiliated companies, net		(17	)		69			(63	)		(21	)

Net cash provided by (used in) financing activities		(140	)		(190	)		182			85

Net change in cash and cash equivalents		1			(3	)		3			—
Cash and cash equivalents at beginning of period		2			5			2			2

Cash and cash equivalents at end of period	$	3		$	2		$	5		$	2

(See Accompanying Notes)

SUNOCO LOGISTICS PARTNERS L.P.

CONSOLIDATED STATEMENTS OF EQUITY

(in millions)


	Limited Partners											General Partner			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
	Common					Class A
	Units		$			Units			$			$			$			$			$
Predecessor
Balance at December 31, 2009		93.0	$	837			—		$	—		$	27		$	(2	)	$	—		$	862

Net Income		—	$	298			—		$	—		$	48		$	—		$	2		$	348
Recognition of funded status of affiliates’ postretirement plans		—		—			—			—			—			1			—			1
Loss on cash flow hedges		—		—			—			—			—			(2	)		—			(2	)

Total comprehensive income (loss)		—		298			—			—			48			(1	)		2			347
Issuance of Limited Partner units to the public		6.0		143			—			—			3			—			—			146
Units issued under incentive plans		0.2		5			—			—			—			—			—			5
Distribution equivalent rights		—		(1	)		—			—			—			—			—			(1	)
Payment of statutory withholding on issuance of LTIP		—		(2	)		—			—			—			—			—			(2	)
Noncontrolling equity in joint venture acquisitions		—		—			—			—			—			—			80			80
Distribution related to IDR transaction		—		(197	)		—			—			(4	)		—			—			(201	)
Distributions		—		(143	)		—			—			(46	)		—			(4	)		(193	)
Other		—		—			—			—			—			—			(1	)		(1	)

Balance at December 31, 2010		99.2	$	940			—		$	—		$	28		$	(3	)	$	77		$	1,042

Net Income		—	$	257					$	2		$	54		$	—		$	9		$	322
Gain on cash flow hedges		—		—			—			—			—			4			—			4

Total comprehensive income		—		257			—			2			54			4			9			326
Issuance of Class A units to Sunoco, Inc.		—		—			3.9			20			2			—			—			22
Units issued under incentive plans		0.2		6			—			—			—			—			—			6
Distribution equivalent rights		—		(2	)		—			—			—			—			—			(2	)
Payment of statutory withholding on issuance of LTIP		—		(3	)		—			—			—			—			—			(3	)
Noncontrolling equity in joint venture acquisitions		—		—			—			—			—			—			20			20
Distributions		—		(160	)		—			—			(50	)		—			(8	)		(218	)
Other		—		1			—			—			—			—			—			1

Balance at December 31, 2011		99.4	$	1,039			3.9		$	22		$	34		$	1		$	98		$	1,194

Net Income		—	$	324			—		$	2		$	55		$	—		$	8		$	389
Loss on cash flow hedges		—		—			—			—			—			(21	)		—			(21	)

Total comprehensive income (loss)		—		324			—			2			55			(21	)		8			368
Units issued under incentive plans		0.3		6			—			—			—			—			—			6
Distribution equivalent rights		—		(1	)		—			—			—			—			—			(1	)
Payment of statutory withholding on issuance of LTIP		—		(5	)		—			—			—			—			—			(5	)
Conversion of Class A units to common units		3.9		24			(3.9	)		(24	)		—			—			—			—
Distributions		—		(133	)		—			—			(45	)		—			(5	)		(183	)

Balance at October 4, 2012		103.6	$	1,254			—		$	—		$	44		$	(20	)	$	101		$	1,379

Successor
Balance at October 5, 2012		103.6	$	5,118			—		$	—		$	893		$	—		$	123		$	6,134

Net Income		—	$	115			—		$	—		$	24			—		$	3		$	142
Gain on cash flow hedges		—		—			—			—			—			—			—			—

Total comprehensive income		—		115			—			—			24			—			3			142
Units issued under incentive plans		0.2		2			—			—			—			—			—			2
Distribution equivalent rights		—		—			—			—			—			—			—			—
Payment of statutory withholding on issuance of LTIP		—		(7	)		—			—			—			—			—			(7	)
Distributions		—		(54	)		—			—			(20	)		—			(2	)		(76	)
Other		—		1			—			—			—			—			(1	)		—

Balance at December 31, 2012		103.8	$	5,175			—		$	—		$	897		$	—		$	123		$	6,195

(See Accompanying Notes)

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Basis of Presentation

Sunoco Logistics Partners L.P. (the “Partnership” or “SXL”) is a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of refined products and crude oil pipelines, terminalling and storage assets, and refined products and crude oil acquisition and marketing assets. The Partnership is principally engaged in these activities in approximately 30 states located throughout the United States.

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 these transactions, the Partnership became a consolidated subsidiary of ETP and elected to apply “push-down” accounting which required its assets and liabilities to be adjusted to fair value on the closing date, October 5, 2012. 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.

The Partnership, along with the assistance of a third-party valuation firm, developed models to estimate the enterprise value of the Partnership on October 5, 2012. These models utilized a combination of observable market inputs and management assumptions, including application of a discounted cash flow approach to projected operating results, growth estimates and projected changes in market conditions. The estimated fair value of the partners’ capital balances as of October 5, 2012 was as follows:


	(in millions)
Fair value of Limited Partners’ interests	$	5,118
Fair value of General Partner’s interest		893
Fair value of Noncontrolling interests		123

	$	6,134

The Partnership then determined the estimated fair value of its assets and liabilities. The fair values of the Partnership’s current assets and current liabilities (with the exception of inventory) were assumed to approximate their carrying values. The estimated fair values of the Partnership’s long-lived tangible assets and inventory were determined utilizing observable market inputs where available or estimated replacement cost adjusted for a usage or obsolescence factor. The Partnership’s identifiable intangible assets consist of customer relationships and technology patents and were estimated by applying a discounted cash flow approach which was adjusted for customer attrition assumptions and projected market conditions. The estimated fair values of the Partnership’s long-term liabilities were determined utilizing observable market inputs where available or estimated based on their current carrying values. The Partnership has recorded goodwill as the excess of the estimated enterprise value over the sum of the fair value amounts allocated to the Partnership’s assets and liabilities. The following

table summarizes the preliminary allocation of the fair value of partners’ capital balances to the assets and liabilities of the Partnership on October 5, 2012. The preliminary allocation to certain assets and/or liabilities may be adjusted by material amounts as the Partnership continues to finalize its fair value estimates.


	(in millions)
Current assets	$	2,449
Properties, plants and equipment		5,533
Investment in affiliates		119
Goodwill ⁽¹⁾		1,368
Intangible assets		855
Other assets		25
Current liabilities		(2,132	)
Long-term debt		(1,778	)
Other deferred credits and liabilities		(61	)
Deferred income taxes		(244	)

	$	6,134

⁽¹⁾	Includes $200, $545 and $623 million allocated to the Crude Oil Pipelines, Crude Oil Acquisition and Marketing and Terminal Facilities, respectively.

2. Summary of Significant Accounting Policies

Principles of Consolidation

The consolidated financial statements reflect the results of the Partnership and its wholly-owned subsidiaries, including Sunoco Logistics Partners Operations L.P. (the “Operating Partnership”) and the proportionate shares of the Partnership’s undivided interests in assets, and the accounts of entities in which the Partnership has a controlling financial interest. A controlling financial interest is evidenced by either a voting interest greater than 50 percent or a risk and rewards model that identifies the Partnership or one of its subsidiaries as the primary beneficiary of a variable interest entity. The Partnership holds a controlling financial interest in Inland Corporation (“Inland”), Mid-Valley Pipeline Company (“Mid-Valley”) and West Texas Gulf Pipe Line Company (“West Texas Gulf”), and as such, these joint ventures are reflected as consolidated subsidiaries of the Partnership from the respective dates of acquisition. All significant intercompany accounts and transactions are eliminated in consolidation and noncontrolling interests in equity and net income are shown separately in the consolidated statements of comprehensive income and balance sheets. Equity ownership interests in corporate joint ventures in which the Partnership does not have a controlling financial interest are accounted for under the equity method of accounting.

Use of Estimates

The preparation of financial statements in conformity with United States generally accepted accounting principles (“GAAP”) requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual amounts could differ from these estimates.

Revenue Recognition

Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Acquisition and marketing revenues for crude oil and refined products are recognized when title to and risk of loss of the product is transferred to the customer. Terminalling and storage revenues are recognized at the time the services are provided. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer

to the Partnership’s end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the consolidated statements of comprehensive income.

Affiliated revenues consist of sales of crude oil and refined products, as well as the provision of crude oil and refined products, pipeline transportation, terminalling and storage services to ETP and Sunoco (including their affiliated entities). Sales of crude oil and refined products to affiliated entities are priced using market based rates. Sunoco and its affiliated entities pay fees for transportation or terminalling services based on the terms and conditions of an established agreement or utilizing published tariffs.

Cash Equivalents

The Partnership considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. At December 31, 2012 and 2011, these cash equivalents consisted of money market accounts.

Accounts Receivable, Net

Accounts receivable represent valid claims against non-affiliated customers (see Note 4 for affiliated receivables) for products sold or services rendered. The Partnership extends credit terms to certain customers after review of various credit indicators, including the customer’s credit rating. Outstanding customer receivable balances are regularly reviewed for possible non-payment indicators and reserves are recorded for doubtful accounts based upon management’s estimate of collectability at the time of review. Actual balances are charged against the reserve when all collection efforts have been exhausted.

Inventories

Inventories are valued at the lower of cost or market. Crude oil and refined products inventory costs have been determined using the last-in, first-out method (“LIFO”). Under this methodology, the cost of products sold consists of the actual acquisition costs of the Partnership, which include transportation and storage costs. Such costs are adjusted to reflect increases or decreases in inventory quantities, which are valued based on the changes in the LIFO inventory layers. The cost of materials, supplies and other inventories is principally determined using the average-cost method.

Properties, Plants and Equipment

Properties, plants and equipment are stated at cost. Additions to properties, plants and equipment, including replacements and improvements, are recorded at cost. Repair and maintenance expenditures are charged to expense as incurred. Depreciation is provided principally using the straight-line method based on the estimated useful lives of the related assets. For certain interstate pipelines, the depreciation rate is applied to the net asset value based on the Federal Energy Regulatory Commission’s (“FERC”) requirements, which approximates the useful lives prescribed under GAAP.

Capitalized Interest

The Partnership capitalizes interest on borrowed funds related to capital projects for periods that construction activities are in progress to bring these projects to their intended use.

Investment in Affiliates

Investment in affiliates, which consist of corporate joint ventures, are accounted for under the equity method of accounting. Under this method, an investment is carried at cost, increased for the equity in income or

decreased for the equity in loss from the date of acquisition, reduced for dividends received and increased or decreased for adjustments in other comprehensive income. Income recognized from the Partnership’s corporate joint venture interests is presented within other income in the consolidated statements of comprehensive income.

The Partnership allocates the excess of its investment cost over its equity in the net assets of affiliates to the underlying tangible and intangible assets of the corporate joint ventures. Other than land and indefinite-lived intangible assets, all amounts allocated, principally to pipeline and related assets, are amortized using the straight-line method over their estimated useful life of 40 years. The amortization of these amounts is included within depreciation and amortization in the consolidated statements of comprehensive income.

Acquisitions

The assets acquired and liabilities assumed as part of the Partnership’s business combinations are recorded at their estimated fair values as of the date of acquisition. Any excess of consideration transferred plus the fair value of noncontrolling interest over the estimated fair value of the net assets acquired is recorded as goodwill. To the extent the estimated fair value of the net assets acquired exceeds the purchase price plus the fair value of the noncontrolling interest, a gain is recorded in current operations. The results of operations of acquired businesses are included in the Partnership’s results from the dates of acquisition.

The Partnership’s asset acquisitions are recorded at the purchase price, which is allocated to the acquired assets and assumed liabilities based on their relative estimated fair values.

Assets acquired and liabilities assumed include tangible and intangible assets, and contingent assets and liabilities. The estimated fair values of these assets and liabilities are determined based on observable inputs such as quoted market prices, information from comparable transactions, offers made by other prospective acquirers in the cases where the Partnership has certain rights to acquire additional interests in existing investments, and the replacement cost of assets in the same condition or stage of usefulness, or on unobservable inputs such as expected future cash flows or internally developed estimates of value. The Partnership’s fair value measurements are classified within the fair value hierarchy established by GAAP based on the lowest level (least observable) input that is significant to the measurement in its entirety.

See Note 3 for additional information concerning the Partnership’s acquisitions during 2011 and 2010.

Impairment of Long-Lived Assets

Long-lived assets, other than those held for sale, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. An asset is considered to be impaired when the undiscounted estimated net cash flows expected to be generated by the asset are less than its carrying amount. The impairment recognized is the amount by which the carrying amount exceeds the estimated fair value of the impaired asset. Long-lived assets held for sale are recorded at the lower of their carrying amount or estimated fair value less cost to sell the assets.

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. Management assessed the impact that Sunoco’s decision to exit its refining business in the northeast would have on the Partnership’s assets that historically served the refineries and determined that the Partnership’s refined products pipeline and terminal assets continued to have expected future cash flows that support their carrying values. However, the Partnership recognized a $42 million charge in the fourth quarter 2011 for 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

completed the formation of Philadelphia Energy Solutions (“PES”), a joint venture with The Carlyle Group, which enabled the Philadelphia refinery to continue operating. Sunoco retained a non-operating minority interest of approximately 33 percent. During the second quarter 2012, the Partnership reversed $10 million of regulatory obligations which were no longer expected to be incurred.

The Partnership also recognized impairment charges of $9 and $3 million in 2012 and 2010, respectively. These charges related to software and construction project cancellations and reflect costs associated with assets that the Partnership could not deploy elsewhere within its operations.

The impairment recognized by the Partnership in 2011 was calculated using fair value assumptions, including comparable land sale transactions and current replacement costs of similar new equipment, adjusted to reflect the age, condition, maintenance history and estimated useful life of the assets. Since the fair value assessment reflected both observable and unobservable inputs, it was determined to be a level 3 fair value measurement within the fair value hierarchy under current accounting guidance.

Goodwill

Goodwill, which represents the excess of the purchase price in a business combination over the fair value of net assets acquired, 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. The Partnership determined during 2012, 2011 and 2010 that goodwill was not impaired.

Fair value is estimated using a market multiple methodology whereby multiples of business enterprise value to earnings before interest, taxes, depreciation and amortization (“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.

In September 2011, the Financial Accounting Standards Board (“FASB”) codified guidance related to the testing of goodwill for impairment. The guidance provides entities with the option to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, after assessing the totality of events or circumstances, an entity determines it is more likely than not that the fair value of a reporting unit is not less than its carrying amount, then performing the two-step impairment test is not required. However, if an entity concludes otherwise, then it is required to perform the first step of the two-step impairment test. Entities have the option of bypassing the qualitative analysis in any period and proceeding directly to the two-step impairment test. The provisions of this guidance, effective for the Partnership beginning January 1, 2012, did not have an impact on the Partnership’s consolidated financial statements and disclosures.

Intangible Assets

The Partnership has acquired intangible assets such as throughput and deficiency contracts, customer relationships, historical shipping rights and patents related to butane blending technology. The value assigned to these intangible assets is amortized on a straight-line basis over their respective economic lives through depreciation and amortization expense in the consolidated statements of comprehensive income.

Environmental Remediation

The Partnership accrues environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point or points in the range are more likely, in which case the most likely amount in this range is accrued.

Income Taxes

The Partnership is not a taxable entity for U.S. federal income tax purposes, or for the majority of states that impose income taxes. Rather, income taxes are generally assessed at the partner level. There are some states in which the Partnership operates where it is subject to state and local income taxes. Substantially all of the income tax reflected in the Partnership’s consolidated financial statements is derived from the operations of Inland, Mid-Valley and West Texas Gulf, all of which are entities subject to income taxes for federal and state purposes at the corporate level. The effective tax rates for these entities approximate the federal statutory rate of 35 percent.

The Partnership recognizes a tax benefit from uncertain positions only if it is more likely than not that the position is sustainable, based solely on its technical merits and consideration of the relevant taxing authorities’ widely understood administrative practices and precedents. The tax benefits recognized from such positions are measured based on the largest benefit that has a greater than 50 percent likelihood of being realized upon settlement.

The following table presents the components of income tax expense for the periods presented:


	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,
				Period from January 1, 2012 to October 4, 2012		2011			2010
	(in millions)			(in millions)
Federal
Current	$	8		$	22	$	25		$	6
Deferred		(2	)		—		(2	)		—
State
Current		2			2		2			2
Deferred		—			—		—			—

Total income tax expense	$	8		$	24	$	25		$	8

The income taxes paid by Inland, Mid-Valley and West Texas Gulf approximated current income tax expense for each year presented.

In taxable jurisdictions, the Partnership records deferred income taxes on all significant temporary differences between the book basis and the tax basis of assets and liabilities. At December 31, 2012 and 2011, the Partnership had $243 and $222 million, respectively, of net deferred tax liability derived principally from the difference in the book and tax bases of properties, plants and equipment associated with the Inland, Mid-Valley and West Texas Gulf acquisitions.

Long-Term Incentive Plan

The Partnership accounts for the compensation cost of all unit-based payment awards at fair value and reports the related expense within selling, general and administrative expenses in the consolidated statements of comprehensive income. Unit-based compensation cost for awards of restricted units is derived from the fair market value of common units on the grant date using a Monte Carlo Simulation if the payout is determined by market criteria related to unit proxies or grant date market price of the underlying unit. The Partnership recognizes unit-based compensation cost as expense ratably on a straight-line basis over the requisite service period. In accordance with the terms of certain awards issued prior to 2013, the recognition of compensation cost is accelerated in the period the participant becomes retirement-eligible.

Asset Retirement Obligations

Asset retirement obligations (“AROs”) represent the fair value of a liability related to the retirement of long-lived assets and are recorded at the time a legal obligation is incurred. A corresponding asset is also recorded at that time and is depreciated over the remaining useful life of the related asset. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be level 3 measurements as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.

The Partnership’s consolidated balance sheets included liabilities for asset retirement obligations, as a component of other deferred credits and liabilities, of $41 and $51 million at December 31, 2012 and 2011, respectively. The decrease in the balance from 2011 to 2012 was attributable to the $10 million reversal of certain regulatory obligations which were no longer expected to be incurred as a result of Sunoco’s joint venture with The Carlyle Group. The Partnership believes it may have additional asset retirement obligations related to its pipeline assets and storage tanks, for which it is not possible to estimate whether or when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time.

Fair Value Measurements

The Partnership determines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Partnership utilizes valuation techniques that maximize the use of observable inputs (levels 1 and 2) and minimize the use of unobservable inputs (level 3) within the fair value hierarchy established by the FASB. The Partnership generally applies a “market approach” to determine fair value. This method uses pricing and other information generated by market transactions for identical or comparable assets and liabilities. Assets and liabilities are classified within the fair value hierarchy based on the lowest level (least observable) input that is significant to the measurement in its entirety.

In May 2011, the FASB issued a new accounting standard update which amended the fair value measurement guidance and included enhanced disclosure requirements. The most significant change in disclosures was an expansion of the information required for level 3 measurements based on unobservable inputs. The Partnership adopted the amended guidance on January 1, 2012. The adoption of the amended guidance did not have a material impact on the Partnership’s consolidated financial statements and disclosures.

Comprehensive Income

In June 2011, the FASB codified guidance related to the presentation of comprehensive income. The guidance requires entities to present net income and other comprehensive income in a single continuous statement of comprehensive income or in two separate, but consecutive, statements. The components of net income and other comprehensive income are presented in the Partnership’s consolidated statements of

comprehensive income. The new guidance does not change the components that are recognized in net income and the components that are recognized in other comprehensive income. The revised presentation has been retroactively applied to all periods presented.

In February 2013, the FASB codified additional guidance related to the presentation and disclosure of components reclassified out of accumulated other comprehensive income (loss). The provisions of this guidance are effective for the Partnership beginning January 1, 2013. The Partnership does not expect the adoption of this standard to have a material impact on its consolidated financial statements and disclosures.

Lease Accounting

The Partnership accounts for arrangements that convey the right to use property, plant or equipment for a stated period of time as leases. Whether an arrangement contains a lease is determined at inception of the arrangement based on all of the facts and circumstances. The Partnership reassesses whether the arrangement contains a lease after the inception of the arrangement only if (a) there is a change in the contractual terms, (b) a renewal option is exercised or an extension is agreed to by the parties to the arrangement, (c) there is a change in the determination as to whether or not fulfillment is dependent on specified property, plant, or equipment, or (d) there is a substantial physical change to the specified property, plant, or equipment. The Partnership continually analyzes its new and existing arrangements to evaluate whether they contain leases. Revenue or expense from arrangements where the Partnership is the lessor or lessee, respectively, is recognized ratably over the term of the underlying arrangement.

Net Income Attributable to Sunoco Logistics Partners L.P. Per Limited Partner Unit

The Partnership uses the two-class method to determine basic and diluted earnings per unit. The two-class method is an earnings allocation formula that determines the earnings for each class of equity ownership and participating security according to distributions declared and participation rights in undistributed earnings. The Partnership calculates basic and diluted net income attributable to Sunoco Logistics Partners L.P. per limited partner unit (“net income attributable to SXL”) by dividing net income attributable to SXL, after deducting the amount allocated to the general partner’s interest and incentive distribution rights (“IDRs”), by the weighted average number of limited partner units and Class A units outstanding during the period. IDRs in a master limited partnership are treated as participating securities for the purpose of computing net income attributable to limited partner units. The general partner holds all of the IDRs. In addition, when earnings differ from cash distributions, undistributed or over distributed earnings are to be allocated to the general partner, limited partners and Class A unitholder based on the contractual terms of the partnership agreement.

3. Acquisitions

A key component of the Partnership’s primary business strategy is to pursue strategic and accretive acquisitions that complement its existing asset base. The Partnership completed the following acquisitions during the years ended December 31, 2011 and 2010:

2011 Acquisitions

•

In August 2011, the Partnership acquired a refined products terminal, located in East Boston, Massachusetts, from affiliates of ConocoPhillips for $56 million plus the fair value of inventory. The terminal includes a 10-bay truck rack and approximately 1 million barrels of capacity and is the sole service provider to Logan International Airport under a long-term contract to supply jet fuel. The acquisition was included within the Terminal Facilities segment.

•

In August 2011, the Partnership acquired a crude oil purchasing and marketing business from Texon L.P. (“Texon”) for $205 million plus the fair value of its crude oil inventory at the acquisition date. The purchase consisted of a crude oil acquisition and marketing business and gathering assets for

approximately 75,000 barrels per day at the wellhead in 16 states, primarily in the western United States. The acquisition was included within the Crude Oil Acquisition and Marketing segment.

•

In July 2011, the Partnership acquired the Eagle Point tank farm and related assets from Sunoco for $100 million. The tank farm is located in Westville, New Jersey and has approximately 5 million barrels of active storage for refined products and dark oils. The acquisition was funded by the issuance of 3.9 million of Class A units with an estimated market value of $98 million and payment of $2 million of cash to Sunoco. The Class A units were a new class of units on which no distributions were paid until the Class A units converted to common units in July 2012. As the acquisition was from a related party, the assets acquired were recorded by the Partnership at Sunoco’s net carrying value of $22 million. The $20 million difference between the carrying value of the assets and the cash consideration paid was recorded by the Partnership as an increase to equity. The acquisition was included within the Terminal Facilities segment.

•

In May 2011, the Partnership acquired an 83.8 percent equity interest in 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. The Partnership acquired its equity interest for $99 million, net of cash received, 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 56.8 percent equity interest acquired from Sunoco was considered a transaction between entities under common control and therefore the assets and liabilities transferred were recorded by the Partnership at Sunoco’s carrying value. As the Partnership acquired a controlling financial interest in Inland, the joint venture was reflected as a consolidated subsidiary of the Partnership from the date of the final acquisition and was included within the Refined Products Pipelines segment.

The following table summarizes the effects of the 2011 acquisitions on the Partnership’s consolidated balance sheet as of the respective acquisition dates:


	East Boston Terminal			Crude Oil Acquisition and Marketing			Eagle Point Tank Farm			Inland			Total
	(in millions)
Increase in:
Current assets	$	17		$	24		$	—		$	3		$	44
Properties, plants and equipment, net		63			7			22			178			270
Intangible assets, net		—			183			—			—			183
Goodwill		—			14			—			—			14
Current liabilities		—			(6	)		—			(1	)		(7	)
Other deferred credits and liabilities		(7	)		—			—			(1	)		(8	)
Deferred income taxes		—			—			—			(60	)		(60	)
Sunoco Logistics Partners L.P. equity		—			—			(20	)		—			(20	)
Noncontrolling interests		—			—			—			(20	)		(20	)

Cash paid for acquisitions	$	73		$	222		$	2		$	99		$	396

2010 Acquisitions

•

In October 2010, the Partnership acquired two terminals in Texas for $9 million. The Partnership also assumed a $1 million environmental liability in connection with these transactions. The acquisitions included a terminal in Bay City, Texas, acquired from Gulfstream Terminals & Marketing LLC, which is capable of handling both crude oil and refined product volumes. Total active terminal storage capacity of the facility is less than half of a million barrels. In addition, the Partnership acquired a refined products terminal and pipeline segment in Big Sandy, Texas, from affiliates of Chevron Corporation. The acquisitions were included in the Terminal Facilities from the respective dates of acquisition. In February 2012, the Partnership sold the refined products terminal and pipeline assets in

Big Sandy, Texas for $11 million. The buyer also assumed a $1 million environmental liability associated with the assets. The net book value of the assets sold and liability transferred approximated the sale price. In connection with the sale, the Partnership also agreed to cancel existing throughput and deficiency agreements in exchange for cash payments of $11 million. The Partnership recognized a total gain of $11 million related primarily to the contract settlement. The gain was recorded as $6 and $5 million within the Terminal Facilities and Refined Products Pipelines segments, respectively.

•

In July 2010, the Partnership acquired a butane blending business from Texon for $152 million including the fair value of its refined product inventory. 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. Goodwill was recognized related to expected synergies with the Partnership’s terminal facilities. The acquisition was included within the Terminal Facilities segment.

•

In July 2010, the Partnership exercised its rights to acquire an additional ownership interest in West Shore Pipeline Company (“West Shore”) from an affiliate of BP for $6 million, increasing its ownership interest from 12.3 percent to 17.1 percent. West Shore owns approximately 650 miles of common carrier refined products pipelines that originate in Chicago, Illinois and services delivery points from Chicago to Wisconsin. The investment is accounted for as an equity method investment within the Partnership’s Refined Products Pipelines segment, with the equity income recorded based on the Partnership’s ownership percentage from the date of acquisition.

•

In July 2010, the Partnership exercised its rights to acquire an additional ownership interest in Mid-Valley from an affiliate of BP for $58 million, increasing its ownership interest from 55.3 percent to 91.0 percent. Mid-Valley owns, and the Partnership is the operator of, 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.

In August 2010, the Partnership exercised similar rights to acquire an additional ownership interest in West Texas Gulf from an affiliate of BP for $27 million, increasing its ownership interest from 43.8 percent to 60.3 percent. West Texas Gulf owns, and the Partnership is the operator of, 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 the Partnership acquired a controlling financial interest in both Mid-Valley and West Texas Gulf, the joint ventures were reflected as consolidated subsidiaries of the Partnership from their respective acquisition dates. The acquisitions were included within the Crude Oil Pipelines segment from the respective acquisition dates. Gains attributable to the re-measurement of the previously held equity interests in Mid-Valley and West Texas Gulf totaling $128 million were recognized in “Gain on investments in affiliates” in the consolidated statement of comprehensive income for the year ended December 31, 2010. The fair value of the Partnership’s pre-acquisition equity interests in Mid-Valley and West Texas Gulf, $90 and $72 million, respectively, were determined based on the amounts paid by the Partnership, which were equal to the offers of other prospective acquirers (level 1 observable inputs). The Partnership used the same methodology to determine the fair value of the noncontrolling interests.

The following table summarizes the effects of the 2010 acquisitions on the Partnership’s consolidated balance sheet (including the consolidation of Mid-Valley and West Texas Gulf) as of the respective acquisition dates:


	Butane Blending		Joint Ventures			Terminals			Total
	(in millions)
Increase in:
Current assets	$	14	$	23		$	—		$	37
Investment in affiliates		—		6			—			6
Properties, plants and equipment, net		1		471			10			482
Intangible assets, net		90		—			—			90
Goodwill		47		—			—			47
Deferred charges and other assets		—		1			—			1
Current liabilities		—		(4	)		—			(4	)
Other deferred credits and liabilities		—		(1	)		(1	)		(2	)
Deferred income taxes		—		(164	)		—			(164	)
Sunoco Logistics Partners L.P. equity		—		(128	)		—			(128	)
Noncontrolling interests		—		(80	)		—			(80	)
Decrease in:
Investment in affiliates		—		(33	)		—			(33	)

Cash paid for acquisitions	$	152	$	91		$	9		$	252

No pro forma information has been presented since the impact of acquisitions during 2011 and 2010 were not material in relation to the Partnership’s consolidated results of operations.

4. Related Party Transactions

Acquisition of Sunoco

The general and limited partner interests that were previously owned by Sunoco were contributed to ETP in connection with the acquisition of Sunoco by ETP (Note 1). As a result of these transactions, both the Partnership and Sunoco became consolidated subsidiaries of ETP. The Partnership has various operating and administrative agreements with Sunoco, including the agreements described below. Sunoco continues to perform the administrative functions defined in such agreements on the Partnership’s behalf.

Pipeline and Terminalling Services

The Partnership is party to various agreements with Sunoco and its affiliates (including PES) to supply crude oil and refined products and to provide pipeline and terminalling services pursuant to agreements with terms that expire at various times as described below, and some of these services are provided pursuant to agreements or arrangements that are short term in nature or subject to termination by either party. Affiliated revenues in the consolidated statements of comprehensive income consist of sales of refined products and crude oil as well as the related provision, and services including pipeline transportation, terminalling, storage and blending.

The Partnership had the following material agreements with Sunoco and its affiliated entities at December 31, 2012:

•

The Partnership has a five-year product terminal services agreement with Sunoco under which Sunoco may throughput refined products through the Partnership’s terminals. The agreement contains no minimum throughput obligations for Sunoco. The agreement runs through February 2017.

•

The Partnership has an agreement with PES relating to the Fort Mifflin Terminal Complex. Under this agreement, PES will deliver an average of 300,000 barrels per day of crude oil and refined products per

contract year at the Fort Mifflin facility. PES does not have exclusive use of the Fort Mifflin Terminal Complex; however, the Partnership is obligated to provide the necessary tanks, marine docks and pipelines for PES to meet its minimum requirements under the agreement. The Partnership executed a 10-year agreement with PES in September 2012. The Partnership had a previous agreement with Sunoco which included terms similar to those contained in the agreement with PES.

•

The Partnership has a three-year agreement with Sunoco to provide approximately 2.0 million barrels of storage capacity and terminalling services to Sunoco at the Eagle Point tank farm. The agreement expires in June 2014. Sunoco does not have exclusive use of the Eagle Point tank farm.

•

In September 2012, Sunoco assigned its lease for the use of the Partnership’s inter-refinery pipelines between the Philadelphia and Marcus Hook refineries to PES. Under the 20-year lease agreement which expires in February 2022, PES leases the inter-refinery pipelines for an annual fee which escalates at 1.67 percent each January 1 for the term of the agreement. The lease agreement also requires PES to reimburse the Partnership for any non-routine maintenance expenditures, as defined, incurred during the term of the agreement. There were no material reimbursements under this agreement during 2010 through 2012.

•

Commodity Sales Agreements

•

Sunoco continues to utilize the Partnership’s pipeline and terminal assets to supply its retail marketing network in an efficient manner. Management expects that Sunoco will continue to utilize these services for the foreseeable future. However, if Sunoco reduces its use of the Partnership’s facilities, it could adversely affect the Partnership’s results of operations, financial condition or cash flows.

Advances to/from Affiliate

The Partnership has a treasury services agreement with Sunoco pursuant to which it, among other things, participates in Sunoco’s centralized cash management program. Under this program, all of the Partnership’s cash receipts and cash disbursements are processed, together with those of Sunoco and its other subsidiaries, through Sunoco’s cash accounts with a corresponding credit or charge to an affiliated account. The affiliated balances are settled periodically, but no less frequently than monthly. Amounts due from Sunoco earn interest at a rate equal to the average rate of the Partnership’s third-party money market investments, while amounts due to Sunoco bear interest at a rate equal to the interest rate provided in the Partnership’s $350 million Credit Facility (Note 10).

Incentive Distribution Rights Exchange

In January 2010, the Partnership entered into a repurchase agreement with its general partner, whereby the Partnership agreed to repurchase from the general partner the existing IDRs for $201 million and the issuance of new IDRs. The Partnership initially financed this arrangement with a promissory note to the general partner that was due December 31, 2010. Pursuant to this transaction, the Partnership executed the third amended and restated agreement of limited partnership of the Partnership (the “new partnership agreement”). The new partnership agreement reflects the cancellation of the original IDRs and the authorization and issuance of the new IDRs (Note 13). Proceeds from the February 2010 issuance of $500 million of Senior Notes were used to repay this promissory note in full (Note 10).

Promissory Note from Affiliate

In July 2010, the Partnership acquired a butane blending business from Texon. The acquisition was partially funded by a three-year, subordinated $100 million note from Sunoco, with an interest rate at three-month LIBOR plus 275 basis points per annum. The Partnership repaid the $100 million note during the fourth quarter of 2011.

Administrative Services

The Partnership has no employees, and reimburses the general partner and its affiliates for certain costs and other direct expenses incurred on the Partnership’s behalf. These costs may be increased if the acquisition or construction of new assets or businesses requires an increase in the level of general and administrative services received by the Partnership.

Under the Omnibus Agreement, the Partnership pays Sunoco an annual administrative fee that includes expenses incurred by Sunoco and its affiliates to perform certain centralized corporate functions, such as legal, accounting, treasury, engineering, information technology, insurance, and other corporate services, including the administration of employee benefit plans. This fee was $5, $13, $13, and $5 million 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, respectively. These fees do not include the costs of shared insurance programs (which are allocated to the Partnership based upon its share of the cash premiums incurred), the salaries of pipeline and terminal personnel or other employees of the general partner, or the cost of their employee benefits.

In addition to the fees for the centralized corporate functions, selling, general and administrative expenses in the consolidated statements of comprehensive income include the allocation of shared insurance costs of $2, $5, $4 and $4 million 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, respectively. The Partnership’s share of allocated Sunoco employee benefit plan expenses, including non-contributory defined benefit retirement plans, defined contribution 401(k) plans, employee and retiree medical, dental and life insurance plans, incentive compensation plans and other such benefits was $10, $28, $26 and $29 million 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, respectively. These expenses are reflected in cost of products sold and operating expenses and selling, general and administrative expenses in the consolidated statements of comprehensive income.

Affiliated Revenues and Accounts Receivable, Affiliated Companies

The Partnership is party to various agreements with Sunoco (including its affiliated entities) to supply crude oil and refined products, as well as to provide pipeline and terminalling services. Affiliated revenues in the consolidated statements of comprehensive income consist of sales of crude oil and refined products, as well as the related provision, and services including pipeline transportation, terminalling and storage and blending to ETP and Sunoco (including their affiliated entities).

Capital Contributions

In July 2011, the Partnership issued 3.9 million Class A Units to Sunoco in connection with the acquisition of the Eagle Point tank farm and related assets (Note 3). As this transaction was between related parties, accounting guidance required the issuance to be recorded at the net of Sunoco’s historical carrying value of the assets acquired ($22 million) and the $2 million cash consideration paid. The $20 million of deferred distribution units were a new class of units that were converted to common units in July 2012. Prior to their conversion, the Class A units participated in the allocation of net income on a pro-rata basis with the common units. In connection with this transaction, the general partner contributed $2 million to the Partnership. The Partnership recorded this amount as a capital contribution to Equity within its consolidated balance sheet.

In August 2010, the Partnership completed a public offering of 6.0 million limited partnership units. As a result of this offering, the general partner contributed $3 million to the Partnership to maintain its two percent general partner interest. The Partnership recorded this amount as a capital contribution to Equity within its consolidated balance sheet.

During 2012, 2011 and 2010, the Partnership issued 0.5, 0.2 and 0.2 million limited partnership units, respectively, to participants in the Sunoco Partners LLC Long-Term Incentive Plan upon completion of award vesting requirements. As a result of these issuances of limited partnership units, the general partner contributed less than $0.5 million in each period to the Partnership to maintain its two percent general partner interest. The Partnership recorded these amounts as capital contributions to Equity within its consolidated balance sheets.

5. Net Income Attributable to Sunoco Logistics Partners L.P. Per Limited Partner Unit Data

The general partner’s interest in net income attributable to SXL consists of its two percent general partner interest and “incentive distributions,” which are increasing percentages, up to 50 percent of quarterly distributions in excess of $0.1667 per limited partner unit (Note 13). The general partner was allocated net income attributable to SXL of $24 million (representing 17 percent of total net income attributable to SXL) for the period from October 5, 2012 to December 31, 2012, $55 million (representing 14 percent of total net income attributable to SXL) for the period from January 1, 2012 to October 4, 2012, $54 million (representing 17 percent of total net income attributable to SXL) for the year ended December 31, 2011, and $48 million (representing 14 percent of total net income attributable to SXL) for the year ended December 31, 2010. Diluted net income attributable to SXL per limited partner unit is calculated by dividing net income attributable to SXL by the sum of the weighted average number of common units and Class A units outstanding, prior to conversion to common units (Note 12), and the dilutive effect of incentive unit awards (Note 14).

The following table sets forth the reconciliation of the weighted average number of limited partner units used to compute basic net income attributable to SXL per limited partner unit to those used to compute diluted net income attributable to SXL per limited partner unit for the periods presented:


	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,
			Period from January 1, 2012 to October 4, 2012		2011		2010
	(in millions)		(in millions)
Weighted average number of limited partner units outstanding—basic		103.8		103.5		101.3		95.2
Add effect of dilutive incentive awards		0.3		0.4		0.5		0.5

Weighted average number of limited partner units—diluted		104.1		103.9		101.8		95.7

On December 2, 2011, the Partnership completed a three-for-one split of its 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. All unit and per unit information included in this report are presented on a post-split basis.

6. Inventories

The components of inventories are as follows:


	Successor		Predecessor
	December 31, 2012		December 31, 2011
	(in millions)		(in millions)
Crude oil	$	418	$	142
Refined products		48		55
Refined products additives		3		2
Materials, supplies and other		9		7

	$	478	$	206

The current replacement cost of crude oil and refined products inventory exceeded its carrying value by $7 and $196 million at December 31, 2012 and 2011, respectively. The increase in the crude oil inventory for 2012 compared to 2011 was due to the adjustment of the Partnership’s assets and liabilities to fair value resulting from the application of push-down accounting in connection with the acquisition of the general partner by ETP (Note 1).

7. Properties, Plants and Equipment

The components of net properties, plants and equipment are as follows:


			Successor			Predecessor
	Estimated Useful Lives		December 31, 2012			December 31, 2011
			(in millions)			(in millions)
Land and land improvements (including rights of way)		—	$	1,026		$	525
Pipeline and related assets		38 - 60		2,687			1,344
Terminals and storage facilities		5 - 44		934			768
Other		5 - 48		647			385
Construction-in-progress				379			212

Total properties, plants and equipment				5,673			3,234
Less: Accumulated depreciation and amortization				(50	)		(712	)

Total properties, plants and equipment, net			$	5,623		$	2,522

8. Investment in Affiliates

The corporate joint ventures own refined products pipeline systems. The Partnership’s ownership percentages in corporate joint ventures as of December 31, 2012 and 2011 were as follows:


		Ownership percentage
Explorer Pipeline Company		9.4%
Yellowstone Pipe Line Company		14.0%
West Shore Pipe Line Company		17.1%
Wolverine Pipe Line Company		31.5%

The Partnership’s investments in Yellowstone Pipe Line Company (“Yellowstone”), West Shore and Wolverine Pipe Line Company (“Wolverine”) at December 31, 2012 include a net excess investment amount of $91 million. The excess investment is the difference between the investment balance and the Partnership’s proportionate share of the net assets of the entities. The Partnership has not provided additional financial support to any of the joint ventures during the 2010 - 2012 period.

The Partnership had $31 million of undistributed earnings from its investments in corporate joint ventures within Equity at December 31, 2012. During 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, the Partnership received dividends of $6, $5, $11 and $15 million, respectively, from its investments in corporate joint ventures.

9. Goodwill and Other Intangible Assets

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 subject to at least an annual impairment testing. The Partnership’s goodwill balance at December 31, 2012 and 2011 was $1,368 and $77 million, respectively. The increase in the Partnership’s goodwill balance at December 31, 2012 related to the adjustment of its assets and liabilities to fair value resulting from the application of push-down accounting in connection with the acquisition of the general partner by ETP (Note 1). The Partnership’s goodwill balance increased to $77 million at December 31, 2011 from $63 million at December 31, 2010 related to the acquisition of a crude oil acquisition and marketing business in August 2011.

Identifiable Intangible Assets

The Partnership’s identifiable intangible assets 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. The values assigned to these intangible assets are amortized to earnings using a straight-line approach, over a weighted average amortization period of approximately 17 years. Amortization expense related to these intangibles was $12, $20, $15 and $4 million 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, respectively.

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 blending of butane into refined products. These patents are amortized over their remaining legal lives.


			Successor			Predecessor
	Weighted Average Amortization Period		December 31, 2012			December 31, 2011
			(in millions)			(in millions)
Gross
Customer relationships		19	$	808		$	239
Technology		10		47			58

Total gross				855			297

Accumulated amortization
Customer relationships				(11	)		(14	)
Technology				(1	)		(6	)

Total accumulated amortization				(12	)		(20	)

Total Net			$	843		$	277

As of December 31, 2012, the Partnership forecasts $49 million of annual amortization expense for each year through the year 2017 for these intangible assets.

Intangible assets attributable to rights of way are included in properties, plants and equipment in the Partnership’s consolidated balance sheets at December 31, 2012 and December 31, 2011.

10. Debt

The components of the Partnership’s long-term debt balances are as follows:


	Successor		Predecessor
	December 31, 2012		December 31, 2011
	(in millions)		(in millions)
Credit Facilities
$350 million Credit Facility, due August 2016	$	93	$	—
$200 million Credit Facility, due August 2013		26		—
$35 million Credit Facility, due April 2015		20		—
Senior Notes
Senior Notes - 7.25%, due February 2012		—		250
Senior Notes - 8.75%, due February 2014		175		175
Senior Notes - 6.125%, due May 2016		175		175
Senior Notes - 5.50%, due February 2020		250		250
Senior Notes - 4.65%, due February 2022		300		300
Senior Notes - 6.85%, due February 2040		250		250
Senior Notes - 6.10%, due February 2042		300		300
Unamortized fair value adjustments (Note 1)		143		—

Total debt		1,732		1,700
Less:
Unamortized bond discount		—		(2	)
Current portion of long-term debt ⁽¹⁾		—		(250	)

Long-term debt	$	1,732	$	1,448

⁽¹⁾	Amounts outstanding under the Partnership’s credit facilities at December 31, 2012 have been classified as long-term debt as the Partnership has the intent and ability to refinance such borrowings on a long-term basis.

The aggregate amount of long-term debt maturities is as follows:


Year Ended December 31,	(in millions)
2013 ⁽¹⁾	$	119
2014		175
2015		20
2016		175
2017		—
Thereafter		1,100

Total	$	1,589

⁽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 (see below).

Cash payments for interest related to long-term debt, net of capitalized interest (Note 2), were $2, $87, $73 and $59 million 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, respectively.

Promissory Note, Affiliated Companies

During the third quarter of 2010, the Operating Partnership entered into a subordinated $100 million variable rate promissory note due to Sunoco in May 2013. The note bore interest at three-month LIBOR plus

275 basis points per annum. The proceeds from this note were used to fund a portion of the purchase price of the Partnership’s acquisition of a butane blending business in July 2010. The Partnership repaid this note in full during the fourth quarter 2011.

Credit Facilities

The Partnership maintains two credit facilities totaling $550 million to fund the 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 and $200 million credit facilities contain various covenants limiting the Partnership’s ability to incur indebtedness; grant certain liens; make certain loans, acquisitions and investments; make any material change to the nature of its business; or enter into a merger or sale of assets, including the sale or transfer of interests in the Operating Partnership’s subsidiaries. The credit facilities also limit the Partnership, on a rolling four-quarter basis, to a maximum total consolidated debt to consolidated EBITDA ratio, as defined in the underlying credit agreements, of 5.0 to 1, which can generally be increased to 5.5 to 1 during an acquisition period. The Partnership’s ratio of total debt, excluding net unamortized fair value adjustments, to EBITDA was 2.0 to 1 at December 31, 2012, as calculated in accordance with the credit agreements.

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 the Operating Partnership’s 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.

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.

Debt Guarantee

The Partnership currently serves as guarantor of the senior notes and of any obligations under the $350 million and $200 million credit facilities. The Operating Partnership is also a guarantor of the $200 million Credit Facility. These guarantees are full and unconditional. See Note 20 for supplemental condensed consolidating financial information.

11. Commitments and Contingent Liabilities

Total rental expense 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 amounted to $3, $8, $10 and $8 million, respectively. The Partnership, as lessee, has non-cancelable operating leases for office space and equipment for which the aggregate amount of future minimum annual rentals as of December 31, 2012 was as follows:


Year Ended December 31,	(in millions)
2013	$	11
2014		11
2015		10
2016		8
2017		4
Thereafter		1

Total	$	45

The Partnership is subject to numerous federal, state and local laws which regulate the discharge of materials into the environment or that otherwise relate to the protection of the environment. These laws and regulations result in liabilities and loss contingencies for remediation at the Partnership’s facilities and at third-party or formerly owned sites. At December 31, 2012 and 2011, there were accrued liabilities for environmental remediation in the consolidated balance sheets of $3 and $4 million, respectively. The accrued liabilities for environmental remediation do not include any amounts attributable to unasserted claims, since no unasserted claims are probable of settlement or reasonably estimable, nor have any recoveries from insurance been assumed. Charges against income for environmental remediation totaled $1, $6, $5 and $3 million 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, respectively. The Partnership maintains insurance programs that cover certain of its existing or potential environmental liabilities. Claims for recovery of environmental liabilities and previous expenditures that are probable of realization totaled $1 million at December 31, 2012 and are included in other assets in the consolidated balance sheet.

Total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing

and nature of required remedial actions, the technology available and needed to meet the various existing legal requirements, the nature and extent of future environmental laws, inflation rates and the determination of the Partnership’s liability at multi-party sites, if any, in light of uncertainties with respect to joint and several liability, and the number, participation levels and financial viability of other parties. Management believes it is reasonably possible that additional environmental remediation losses will be incurred. At December 31, 2012, the aggregate of the estimated maximum additional reasonably possible losses, which relate to numerous individual sites, totaled $2 million.

The Partnership is a party to certain pending and threatened claims. Although the ultimate outcome of these claims cannot be ascertained at this time nor can a range of reasonably possible losses be determined, it is reasonably possible that some portion of them could be resolved unfavorably to the Partnership and its predecessor. Management does not believe that any liabilities which may arise from such claims and the environmental matters discussed above would be material in relation to the Partnership’s results of operations, financial position or cash flows at December 31, 2012. Furthermore, management does not believe that the overall costs for such matters will have a material impact, over an extended period of time, on the Partnership’s operations, cash flows or liquidity.

Sunoco has indemnified the Partnership for 30 years from environmental and toxic tort liabilities related to the assets contributed to the Partnership that arose from the operation of such assets prior to the closing of the February 2002 initial public offering (“IPO”). Sunoco has indemnified the Partnership for 100 percent of all losses asserted within the first 21 years of closing of the IPO. Sunoco’s share of liability for claims asserted thereafter will decrease by 10 percent a year. For example, for a claim asserted during the twenty-third year after closing of the IPO, Sunoco would be required to indemnify the Partnership for 80 percent of its loss. There is no monetary cap on the amount of indemnity coverage provided by Sunoco. The Partnership has agreed to indemnify Sunoco for events and conditions associated with the operation of the Partnership’s assets that occur on or after the closing of the IPO and for environmental and toxic tort liabilities to the extent Sunoco is not required to indemnify the Partnership.

Sunoco also has indemnified the Partnership for liabilities, other than environmental and toxic tort liabilities related to the assets contributed to the Partnership, that arose out of Sunoco’s ownership and operation of the assets prior to the closing of the IPO and that are asserted within 10 years after closing of the IPO. In addition, Sunoco has indemnified the Partnership from liabilities relating to certain defects in title to the assets contributed to the Partnership and associated with failure to obtain certain consents and permits necessary to conduct its business that arise within 10 years after closing of the IPO, as well as from liabilities relating to legal actions currently pending against Sunoco or its affiliates and events and conditions associated with any assets retained by Sunoco or its affiliates.

Management of the Partnership does not believe that any liabilities which may arise from claims indemnified by Sunoco would be material in relation to the operations, cash flows or financial position of the Partnership at December 31, 2012. There are certain other pending legal proceedings related to matters arising after the IPO that are not indemnified by Sunoco. Management believes that any liabilities that may arise from these legal proceedings will not be material in relation to the operations, cash flows or financial position of the Partnership at December 31, 2012.

12. Equity Offerings

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

allocation of net income on a pro-rata basis with the common units. Under accounting guidance, the Partnership recorded the Class A units at $20 million, the difference between Sunoco’s historical carrying value of the assets acquired and the cash paid by the Partnership. 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, the Partnership completed a public offering of 6.0 million common units. Net proceeds of $143 million were used to fund the acquisition of additional interests in three of the Partnership’s joint venture pipelines 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.

13. Cash Distributions

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

If cash distributions exceed $0.1667 per unit in a quarter, the general partner receives increasing percentages, up to 50 percent, of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions.” The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

In January 2010, the Partnership repurchased, and its general partner transferred and assigned to the Partnership for cancellation, the IDRs held by the general partner under the Second Amended and Restated Agreement of Limited Partnership, as amended, in consideration for (i) the issuance to the general partner of new IDRs issued under the Third Amended and Restated Agreement of Limited Partnership and (ii) the issuance to the general partner of a promissory note in the principal amount of $201 million. In February 2010, the Operating Partnership 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 full this promissory note.

The following table compares the target distribution levels and distribution “splits” between the general partner and the holders of the Partnership’s 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
	Total Quarterly Distribution Target Amount	General Partner			Unitholders			Total Quarterly Distribution Target Amount		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 Distribution	above $0.1917 up to $0.2333		25	%*		75	%		above $0.1917 up to $0.5275		37	%*		63	%
Thereafter	above $0.2333		50	%*		50	%		above $0.5275		50	%*		50	%

*	Includes two percent general partner interest.

Distributions paid by the Partnership for the periods presented were as follows:


Cash Distribution Payment Date	Cash Distribution per Limited Partner Unit		Annualized Cash Distribution per Limited Partner Unit		Total Cash Distribution to the Limited Partners		Total Cash Distribution to the General Partner
					(in millions)		(in millions)
Successor
November 14, 2012	$	0.5175	$	2.0700	$	54	$	20
Predecessor
August 14, 2012	$	0.4700	$	1.8800	$	49	$	17
May 15, 2012	$	0.4275	$	1.7100	$	43	$	14
February 14, 2012	$	0.4200	$	1.6800	$	41	$	14

November 14, 2011	$	0.4133	$	1.6532	$	41	$	13
August 12, 2011	$	0.4050	$	1.6200	$	40	$	13
May 13, 2011	$	0.3983	$	1.5932	$	40	$	12
February 14, 2011	$	0.3933	$	1.5732	$	39	$	12

November 12, 2010	$	0.3900	$	1.5600	$	39	$	12
August 13, 2010	$	0.3800	$	1.5200	$	35	$	11
May 14, 2010	$	0.3717	$	1.4867	$	35	$	10
February 12, 2010	$	0.3633	$	1.4533	$	34	$	14

On January 24, 2013, the Partnership declared a cash distribution of $0.5450 per unit ($2.18 per unit annualized) on its outstanding common units, representing the distribution for the quarter ended December 31, 2012. The $80 million distribution, including $23 million to the general partner, was paid on February 14, 2013 to unitholders of record at the close of business on February 8, 2013.

14. Management Incentive Plan

Sunoco Partners LLC, the general partner of the Partnership, has adopted the Sunoco Partners LLC Long-Term Incentive Plan (“LTIP”) for employees and directors of the general partner who perform services for the Partnership. The LTIP is administered by the independent directors of the Compensation Committee of the general partner’s board of directors with respect to employee awards, and by the general partner’s board of directors with respect to awards granted to the independent members. The LTIP currently permits the grant of restricted units and unit options covering an additional 0.9 million common units.

Restricted Units

A restricted unit entitles the grantee to receive a common unit or, at the discretion of the Compensation Committee, an amount of cash equivalent to the value of a common unit upon the vesting of the unit, which may include the attainment of predetermined performance targets. The Compensation Committee may make additional grants under the LTIP to employees and directors containing such terms as the Compensation Committee shall determine. Common units to be delivered to the grantee upon vesting may be common units acquired by the general partner in the open market, common units already owned by the general partner, common units acquired by the general partner directly from the Partnership or any other person, or any combination of the foregoing. The general partner will be entitled to reimbursement by the Partnership for the cost incurred in acquiring common units. If the Partnership issues new common units upon vesting of the restricted units, the total number of common units outstanding will increase.

The Compensation Committee, in its discretion, may grant tandem distribution equivalent rights (“DERs”) with respect to the restricted units. Subject to applicable vesting criteria, DERs entitle the grantee to receive an

amount of cash equal to the per unit cash distributions made by the Partnership during the period the restricted unit is outstanding. All units granted during the periods presented below included tandem DERs. A portion of these awards are subject to the Partnership achieving certain market-based and cash distribution performance targets as compared to a peer group average or certain cash distribution performance targets as defined by the Compensation Committee, which can cause the actual amount of units that ultimately vest to range between 0 to 200 percent of the original units granted. Restricted unit awards granted prior to October 4, 2012 generally vest over a three-year period, while the restricted unit awards granted during the period from October 5, 2012 to December 31, 2012 generally vest over a five-year period.

The following table summarizes information regarding restricted unit award activity for the periods presented:


	Number of Units			Weighted Average Grant Date Fair Value
Predecessor
Granted, non-vested and outstanding, December 31, 2009		467,985		$	19.13
Granted⁽¹⁾		272,427		$	24.87
Performance factor adjustment		131,760		$	17.65
Vested		(326,130	)	$	14.41
Cancelled/forfeited		(101,949	)	$	20.92

Granted, non-vested and outstanding, December 31, 2010		444,093		$	22.59

Granted⁽¹⁾		189,714		$	31.13
Performance factor adjustment		184,113		$	19.88
Vested		(413,934	)	$	20.05
Cancelled/forfeited		(23,010	)	$	27.66

Granted, non-vested and outstanding, December 31, 2011		380,976		$	27.86

Granted⁽¹⁾		192,459		$	35.92
Performance factor adjustment		137,941		$	25.24
Vested		(47,916	)	$	30.16
Cancelled/forfeited		(20,409	)	$	31.47

Granted, non-vested and outstanding, October 4, 2012		643,051		$	29.42

Successor
Granted, non-vested and outstanding, October 5, 2012		643,051		$	29.42
Granted		128,573		$	50.55
Performance factor adjustment		12,554		$	31.51
Vested⁽²⁾		(356,568	)	$	25.67
Cancelled/forfeited		—		$	—

Granted, non-vested and outstanding, December 31, 2012		427,610		$	38.96

⁽¹⁾

Of the total number of restricted units granted, the portion that represents units that are subject to performance factors may ultimately be issued at 0 to 200 percent of the original grant, based on the Partnership’s achievement of performance goals for total shareholder return and cash distributions relative to a selected peer group of competitors.

⁽²⁾

Relates primarily to awards that vested as a result of the acquisition of the general partner by ETP (Note 1). The unit-based compensation expense attributable to these awards that was recognized during the period from October 5, 2012 to December 31, 2012 was not material as the majority of such awards were scheduled to vest in December 2012.

The total fair value of restricted unit awards vested 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 $18, $2, $18, and $9 million, respectively. As of December 31, 2012, estimated compensation cost related to non-vested awards not yet recognized was $10 million, and the weighted average period over which this cost is expected to be recognized in expense is 2.5 years. The number of restricted stock units outstanding and the total compensation cost related to non-vested awards not yet recognized reflects the Partnership’s estimates of performance factors for certain restricted unit awards.

The estimated fair value of restricted units under the LTIP is determined based upon the nature of the award. For performance-based awards, the fair value is determined using the grant date market price of the Partnership’s common units. For market-based awards, the fair value is determined using a Monte Carlo simulation.

The Partnership recognizes compensation expense on a straight-line basis over the requisite service period, and estimates forfeitures over the requisite service period when recognizing compensation expense.

The following table summarizes the fair value assumptions associated with the performance based awards issued during the periods presented. The awards granted in the period from October 5, 2012 to December 31, 2012 were not performance based awards.


	Predecessor
	Period from January 1, 2012 to October 4, 2012			Year Ended December 31,
	Period from January 1, 2012 to October 4, 2012			2011			2010
Expected unit-price volatility		22.8	%		24.6	%		25.9	%
Distribution yield		4.6	%		5.4	%		6.4	%
Risk-free interest rate		0.3	%		1.0	%		1.6	%
Weighted average fair value of performance units granted during the year	$	34.94		$	31.51		$	25.16

Expected unit-price volatility is based on the daily historical volatility of the Partnership’s common units, generally for the three years prior to the grant date. The distribution yield represents the Partnership’s annualized distribution yield on the average closing price of the Partnership’s common units 30 days prior to the date of grant. The risk-free interest rate is based on the zero-coupon U.S. Treasury bond, with a term equal to the remaining contractual term of the restricted unit awards.

The Partnership recognized unit-based compensation expense within selling, general and administrative expenses in the consolidated statements of comprehensive income related to the LTIP of $2, $6, $6 and $5 million in 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, respectively, related to the unit grants and performance factor adjustments noted in the table above. Each of the restricted unit grants also have tandem DERs which are recognized as a reduction of equity when earned.

15. Derivatives and Risk Management

The Partnership is exposed to various market risks, including volatility in crude oil and refined product prices, counterparty credit risk and interest rates. In order to manage such exposure, the Partnership’s policy is (i) to only purchase crude oil and refined products for which sales contracts have been executed or for which ready markets exist, (ii) to structure sales contracts so that price fluctuations do not materially impact the margins earned, and (iii) not to acquire and hold physical inventory, futures contracts or other derivative instruments for the purpose of speculating on commodity price changes. Although the Partnership seeks to maintain a balanced inventory position within its commodity inventories, net unbalances may occur for short periods of time due to production, transportation and delivery variances. When physical inventory builds or draws do occur, the

Partnership continuously manages the variance to a balanced position over a period of time. Pursuant to the Partnership’s approved risk management policy, derivative contracts may be used to hedge or reduce exposure to price risk associated with acquired inventory or forecasted physical transactions.

Price Risk Management

The Partnership is exposed to risks associated with changes in the market price of crude oil and refined products as a result of the forecasted purchase or sale of these products. These risks are primarily associated with price volatility related to pre-existing or anticipated purchases, sales and storage. Price changes are often caused by shifts in the supply and demand for these commodities, as well as their locations. The physical contracts related to the Partnership’s crude oil and refined products businesses that qualify as derivatives have been designated as normal purchases and sales and are accounted for using traditional accrual accounting. The Partnership accounts for derivatives that do not qualify as normal purchases and sales at fair value. The Partnership does not utilize derivative instruments to manage its exposure to prices related to crude oil purchase and sale activities. The Partnership does utilize derivatives such as swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products. These derivative contracts act as a hedging mechanism against the volatility of prices by allowing the Partnership to transfer this price risk to counterparties who are able and willing to bear it.

While all derivative instruments utilized by the Partnership represent economic hedges, certain of these derivatives are not designated as hedges for accounting purposes. Such derivatives include certain contracts that were entered into and closed during the same accounting period and a limited number of contracts for where there is not sufficient correlation to the related items being economically hedged.

For refined products derivative contracts that are not designated as hedges for accounting purposes, all realized and unrealized gains and losses are recognized in the consolidated statement of comprehensive income during the current period. For refined products derivative contracts that are designated and qualify as cash flow hedges, the portion of the gain or loss on the derivative contract that is effective in offsetting the variable cash flows associated with the hedged forecasted transaction is reported as a component of other comprehensive income (loss) and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. The remaining gain or loss on the derivative contract in excess of the cumulative change in the present value of future cash flows of the hedged item, if any (i.e., the ineffective portion), is recognized in earnings during the current period. The amount of hedge ineffectiveness on derivative contracts was not material during the 2010 - 2012 period. All realized gains and losses associated with refined products derivative contracts are recorded in earnings in the same line item associated with the forecasted transaction, either sales and other operating revenue or cost of products sold and operating expenses.

The Partnership had open derivative positions on 1.5 million barrels of refined products at December 31, 2012 and 2011, respectively. The derivatives outstanding at December 31, 2012 vary in duration but do not extend beyond one year. The Partnership records its derivatives at fair value based on observable market prices (levels 1 and 2). As of December 31, 2012 and 2011, the fair values of the Partnership’s derivative assets and liabilities were:


	Successor			Predecessor
	December 31, 2012			December 31, 2011
	(in millions)			(in millions)
Derivative assets	$	4		$	6
Derivative liabilities		(7	)		(2	)

	$	(3	)	$	4

Derivative asset and liability balances are recorded in accounts receivable and accrued liabilities, respectively, in the consolidated balance sheets.

The Partnership’s derivative positions are comprised primarily of commodity contracts. The following table sets forth the impact of derivatives on the Partnership’s financial performance for the periods presented:


	Gains (Losses) Recognized in Other Comprehensive Income (Loss)			Gains (Losses) Recognized in Earnings			Location of Gains (Losses) Recognized in Earnings
(in millions)
Successor
Period from Acquisition (October 5, 2012) to December 31, 2012 ⁽¹⁾

Derivatives designated as cash flow hedging instruments:
Commodity contracts	$	—		$	(1	)	Sales and other operating revenue
Commodity contracts		—			—		Cost of products sold and operating expenses

	$	—		$	(1	)

Derivatives not designated as hedging instruments:
Commodity contracts				$	—		Sales and other operating revenue
Commodity contracts					12		Cost of products sold and operating expenses

				$	12

Predecessor
Period from January 1, 2012 to October 4, 2012
Derivatives designated as cash flow hedging instruments:
Commodity contracts	$	(21	)	$	(3	)	Sales and other operating revenue
Commodity contracts		—			1		Cost of products sold and operating expenses

	$	(21	)	$	(2	)

Derivatives not designated as hedging instruments:
Commodity contracts				$	(7	)	Sales and other operating revenue
Commodity contracts					(4	)	Cost of products sold and operating expenses

				$	(11	)

Year Ended December 31, 2011

Derivatives designated as cash flow hedging instruments:
Commodity contracts	$	4		$	(1	)	Sales and other operating revenue
Commodity contracts		—			2		Cost of products sold and operating expenses

	$	4		$	1

Derivatives not designated as hedging instruments:
Commodity contracts				$	6		Sales and other operating revenue
Commodity contracts					(1	)	Cost of products sold and operating expenses

				$	5

Year Ended December 31, 2010

Derivatives designated as cash flow hedging instruments:
Commodity contracts	$	—		$	—		Sales and other operating revenue
Commodity contracts		—			—		Cost of products sold and operating expenses

	$	—		$	—

Derivatives not designated as hedging instruments:
Commodity contracts				$	(1	)	Sales and other operating revenue
Commodity contracts					—		Cost of products sold and operating expenses

				$	(1	)

⁽¹⁾

The Partnership had deferred hedging losses of approximately $17 million in the accumulated other comprehensive loss component of equity prior to the acquisition of the general partner by ETP. These deferred losses were eliminated in connection with the adjustment of the Partnership’s assets and liabilities to fair value (Note 1). In addition, the Partnership did not re-designate its cash flow hedging derivatives which were open on the acquisition date. The Partnership’s earnings for the period from October 5, 2012 to December 31, 2012 included approximately $12 million of hedging gains resulting from the elimination of the deferred hedging losses of such positions and the non-hedge designation subsequent to the acquisition date.

Credit Risk Management

The Partnership maintains credit policies with regard to its counterparties that management believes minimize the overall credit risk through credit analysis, credit approvals, credit limits and monitoring procedures. The Partnership’s counterparties consist primarily of financial institutions and major integrated oil companies. This concentration of counterparties may impact the Partnership’s overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. At December 31, 2012 and 2011, the Partnership did not hold any over-the-counter derivatives.

Interest Rate Risk Management

The Partnership has interest rate risk exposure for changes in interest rates related to its outstanding borrowings. The Partnership manages its exposure to changes in interest rates through the use of a combination of fixed-rate and variable-rate debt. At December 31, 2012, the Partnership had $139 million of consolidated variable-rate borrowings under its revolving credit facilities.

16. Fair Value Measurements

The estimated fair value of financial instruments has been determined based on the Partnership’s assessment of available market information and appropriate valuation methodologies. The Partnership’s current assets (other than derivatives and inventories) and current liabilities are financial instruments and most of these items are recorded at cost in the consolidated balance sheets. The estimated fair value of these financial instruments approximates their carrying value due to their short-term nature. The Partnership’s derivatives are measured and recorded at fair value based on observable market prices (Note 15). The estimated fair value of the senior notes is determined using observable market prices, as these notes are actively traded. The estimated aggregate fair value of the senior notes at December 31, 2012 was $1.64 billion, compared to the carrying amount of $1.59 billion. The estimated aggregate fair value of the senior notes at December 31, 2011 was $1.91 billion, compared to the carrying amount of $1.70 billion.

17. Concentration of Credit Risk

The Partnership’s trade relationships are primarily with major integrated oil companies, independent oil companies and other pipelines and wholesalers. These concentrations of customers may affect the Partnership’s overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors. The Partnership maintains credit policies with regard to its counterparties that management believes minimizes the overall credit risk through credit analysis, credit approvals, credit limits and monitoring procedures. The credit positions of the Partnership’s customers are analyzed prior to the extension of credit and periodically after it has been extended. For certain transactions the Partnership may utilize letters of credit, prepayments and guarantees.

In 2012 and 2011, approximately 18 and 20 percent of the Partnership’s total revenues, respectively, were derived from crude oil sales to an individual customer. While this concentration has the ability to negatively impact revenues going forward, management does not anticipate a material adverse effect in the Partnership’s

financial position, results of operations or cash flows as the absolute price levels for crude oil normally do not bear a relationship to gross profit. In addition, the customer is subject to netting arrangements which allow the Partnership to offset payable activities and serve to mitigate credit exposure.

18. Business Segment Information

The Partnership operates in 30 states throughout the United States and four principal business segments: Crude Oil Pipelines, Crude Oil Acquisition and Marketing, Terminal Facilities and Refined Products Pipelines.

•

The Crude Oil Pipelines segment transports 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 pipelines receive fees for transporting crude oil to and from trading hubs, other pipelines and refineries in the southwest and midwest United States.

•

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

•

The Terminal Facilities segment consists of 41 active refined products terminals with an aggregate storage capacity of 8 million barrels, which provide storage, terminalling, blending and other ancillary services and are primarily sourced by the Refined Products Pipelines; the Nederland Terminal, a 22 million barrel marine crude oil terminal on the Texas Gulf Coast; a 2 million barrel refined product terminal that previously served Sunoco’s Marcus Hook refinery near Philadelphia, Pennsylvania; one inland and two marine crude oil terminals with a combined capacity of 3 million barrels, and related pipelines, which serve the Philadelphia refinery; the Eagle Point Terminal, a 5 million barrel refined products and crude oil terminal and dock facility; and a 1 million barrel liquefied petroleum gas terminal near Detroit, Michigan. The terminals receive fees for the terminalling, blending and other services provided.

•

The Refined Products Pipelines segment consists 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. The pipelines receive fees for transporting refined products from refineries to markets in the northeast, midwest and southwest United States.

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.

100

The following table sets forth consolidated statement of comprehensive income information concerning the Partnership’s business segments and reconciles total segment Adjusted EBITDA to net income attributable to SXL for the periods presented:


	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,
				Period from January 1, 2012 to October 4, 2012			2011			2010
	(in millions)			(in millions)
Sales and other operating revenue⁽¹⁾
Crude Oil Pipelines	$	110		$	288		$	319		$	221
Crude Oil Acquisition and Marketing		2,888			9,258			10,163			7,282
Terminal Facilities		206			406			435			287
Refined Products Pipelines		35			96			130			120
Intersegment eliminations		(50	)		(127	)		(142	)		(102	)

Total sales and other operating revenue	$	3,189		$	9,921		$	10,905		$	7,808

Depreciation and amortization
Crude Oil Pipelines	$	22		$	19		$	25		$	21
Crude Oil Acquisition and Marketing		11			16			10			2
Terminal Facilities		23			28			34			26
Refined Products Pipelines		7			13			17			15

Total depreciation and amortization	$	63		$	76		$	86		$	64

Impairment charge and related matters^(2) (3)
Crude Oil Acquisition and Marketing	$	—		$	8		$	—		$	—
Terminal Facilities		—			(10	)		42			3
Refined Products Pipelines		—			1			—			—

Total impairment charge and related matters	$	—		$	(1	)	$	42		$	3

Capital expenditures^{(4) (5)}
Crude Oil Pipelines	$	65		$	56		$	49		$	36
Crude Oil Acquisition and Marketing		1			15			15			2
Terminal Facilities		45			138			121			110
Refined Products Pipelines		26			24			23			17
Corporate		2			2			5			9

Total capital expenditures	$	139		$	235		$	213		$	174

Adjusted EBITDA
Crude Oil Pipelines	$	72		$	203		$	207		$	156
Crude Oil Acquisition and Marketing		81			158			148			39
Terminal Facilities		52			173			149			127
Refined Products Pipelines		14			57			69			77

Total Adjusted EBITDA		219			591			573			399
Interest expense, net		(14	)		(65	)		(89	)		(73	)
Depreciation and amortization expense		(63	)		(76	)		(86	)		(64	)
Impairment charge		—			(9	)		(31	)		(3	)
Provision for income taxes		(8	)		(24	)		(25	)		(8	)
Non-cash compensation expense		(2	)		(6	)		(6	)		(5	)
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	)
Adjustments to commodity hedges resulting from “push-down” accounting		12			—			—			—
Gain on investments in affiliates		—			—			—			128

Net Income⁽⁶⁾		142			389			322			348
Net Income attributable to noncontrolling interests		3			8			9			2

Net Income attributable to Sunoco Logistics Partners L.P.	$	139		$	381		$	313		$	346

101

⁽¹⁾	Sales and other operating revenue for the periods presented includes the following amounts from ETP and Sunoco (including their affiliated entities):


	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,
			Period from January 1, 2012 to October 4, 2012		2011		2010
	(in millions)		(in millions)
Crude Oil Pipelines	$	—	$	—	$	6	$	25
Crude Oil Acquisition and Marketing		139		307		247		894
Terminal Facilities		50		118		115		122
Refined Products Pipelines		11		36		64		76

Total sales and other operating revenue	$	200	$	461	$	432	$	1,117

⁽²⁾

In the first quarter 2012, the Partnership recognized a non-cash impairment charge related to a cancelled software project for the crude oil acquisition and marketing business and a refined products pipeline project in Texas. The impairment was recorded as $8 and $1 million within the Crude Oil Acquisition and Marketing and Refined Products Pipelines segments, respectively.

⁽³⁾

In 2011, the Partnership recognized a charge of $42 million for certain crude oil terminal assets which would have been negatively impacted if Sunoco’s Philadelphia refinery were 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 the second quarter 2012, the Partnership recognized a $10 million gain on the reversal of certain regulatory obligations. 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.

⁽⁴⁾	Total capital expenditures in 2011 exclude $396 million for the acquisition of a crude oil and marketing business, a refined products terminal, an interest in the Inland refined products pipeline system and the Eagle Point tank farm.

⁽⁵⁾	Total capital expenditures in 2010 exclude $252 million for the acquisition of the butane blending business, additional ownership interests in West Shore, Mid-Valley and West Texas Gulf, and two terminals.

⁽⁶⁾

Net income includes $5, $14, $12 and $14 million 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, respectively, of equity income attributable to the Refined Products Pipelines equity ownership interest in joint ventures. For the year ended December 31, 2010, net income also includes $12 million of equity income attributable to the Crude Oil Pipelines equity ownership interest in joint ventures.

The following table provides consolidated balance sheet information concerning the Partnership’s business segments as of December 31, 2012, 2011 and 2010, respectively:


	Crude Oil Pipelines		Crude Oil Acquisition and Marketing		Terminal Facilities		Refined Products Pipelines		Total
	(in millions)
Successor
As of December 31, 2012
Investment in affiliates	$	—	$	—	$	—	$	118	$	118
Goodwill	$	200	$	545	$	623	$	—	$	1,368
Identifiable assets⁽¹⁾	$	3,167	$	3,495	$	2,402	$	1,198	$	10,361
Predecessor
As of December 31, 2011
Investment in affiliates	$	—	$	—	$	—	$	73	$	73
Goodwill	$	2	$	14	$	53	$	8	$	77
Identifiable assets⁽²⁾	$	1,055	$	2,469	$	1,053	$	736	$	5,477
As of December 31, 2010
Investment in affiliates	$	—	$	—	$	—	$	73	$	73
Goodwill	$	2	$	—	$	53	$	8	$	63
Identifiable assets⁽³⁾	$	1,018	$	1,695	$	857	$	531	$	4,188

102

⁽¹⁾	Total identifiable assets include the Partnership’s unallocated $2 million cash and cash equivalents, $56 million advances to affiliates, $40 million to properties, plants and equipment, net and $1 million of other assets.

⁽²⁾	Total identifiable assets include the Partnership’s unallocated $2 million cash and cash equivalents, $107 million advances to affiliates, $15 million deferred financing costs, and $40 million to properties, plants and equipment, net.

⁽³⁾	Total identifiable assets include the Partnership’s unallocated $2 million cash and cash equivalents, $44 million advances to affiliates, $9 million deferred financing costs, and $32 million to properties, plants and equipment, net.

19. Quarterly Financial Data (Unaudited)

Summarized quarterly financial data is as follows:


	Predecessor									Successor
	First Quarter			Second Quarter			Third Quarter			Period from Acquisition (October 5, 2012) to December 31, 2012
	(in millions, except per unit amounts)									(in millions, except per unit amounts)
2012
Sales and other operating revenue:
Unaffiliated customers	$	3,275		$	3,119		$	3,066		$	2,989
Affiliates	$	126		$	194		$	141		$	200
Gross profit⁽¹⁾	$	176		$	224		$	210		$	256
Operating income	$	129		$	184		$	165		$	164
Net Income^{(2) (3)}	$	97		$	155		$	137		$	142
Net Income attributable to noncontrolling interests		2			3			3			3

Net Income attributable to Sunoco Logistics Partners L.P.	$	95		$	152		$	134		$	139
Less: General Partner’s interest		(15	)		(19	)		(21	)		(24	)

Limited Partners’ interest	$	80		$	133		$	113		$	115

Net Income attributable to Sunoco Logistics Partners L.P. per Limited Partner unit—basic	$	0.77		$	1.29		$	1.09		$	1.11
Net Income attributable to Sunoco Logistics Partners L.P. per Limited Partner unit—diluted	$	0.77		$	1.28		$	1.09		$	1.10

103


	Predecessor
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
	(in millions, except per unit amounts)
2011
Sales and other operating revenue:
Unaffiliated customers	$	1,955		$	2,385		$	2,808		$	3,325
Affiliates	$	303		$	39		$	39		$	51
Gross profit⁽¹⁾	$	113		$	158		$	172		$	198
Operating income	$	75		$	121		$	128		$	112
Net Income⁽⁴⁾	$	50		$	96		$	97		$	79
Net Income attributable to noncontrolling interests		2			2			2			3

Net Income attributable to Sunoco Logistics Partners L.P.	$	48		$	94		$	95		$	76
Less: General Partner’s interest		(12	)		(14	)		(14	)		(14	)

Limited Partners’ interest	$	36		$	80		$	81		$	62

Net Income attributable to Sunoco Logistics Partners L.P. per Limited Partner unit—basic	$	0.36		$	0.80		$	0.78		$	0.60
Net Income attributable to Sunoco Logistics Partners L.P. per Limited Partner unit—diluted	$	0.36		$	0.80		$	0.78		$	0.60

⁽¹⁾	Gross profit equals sales and other operating revenue less cost of products sold and operating expenses.

⁽²⁾

Net income for the first quarter 2012 includes an $11 million gain for cash payments received for the cancellation of existing throughput and deficiency agreements in connection with the Partnership’s sale of refined products terminal and pipeline assets in Big Sandy, Texas and a $9 million non-cash impairment charge related to a cancelled software project for the crude oil acquisition and marketing business and a refined products pipeline project in Texas.

⁽³⁾	Net income for the second quarter 2012 includes a $10 million gain on the reversal of certain regulatory obligations. 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.

⁽⁴⁾

Net income for the fourth quarter 2011 includes a charge of $42 million for certain crude oil terminal assets which would have been negatively impacted if Sunoco’s Philadelphia refinery was permanently idled. This 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 the assets were permanently idled.

20. Supplemental Condensed Consolidating Financial Information

The Partnership serves as guarantor of the senior notes. These guarantees are full and unconditional. For purposes of the following footnote, Sunoco Logistics Partners L.P. is referred to as “Parent Guarantor” and Sunoco Logistics Partners Operations L.P. is referred to as “Subsidiary Issuer.” All other consolidated subsidiaries of the Partnership are collectively referred to as “Non-Guarantor Subsidiaries.”

The following supplemental condensed consolidating financial information reflects the Parent Guarantor’s separate accounts, the Subsidiary Issuer’s separate accounts, the combined accounts of the Non-Guarantor Subsidiaries, the combined consolidating adjustments and eliminations and the Parent Guarantor’s consolidated accounts for the dates and periods indicated. For purposes of the following condensed consolidating information, the Parent Guarantor’s investments in its subsidiaries and the Subsidiary Issuer’s investments in its subsidiaries are accounted for under the equity method of accounting.

104

Consolidating Statement of Comprehensive Income (Loss)

Period from October 5, 2012 to December 31, 2012 (Successor)

(in millions)


	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries		Consolidating Adjustments			Total
Revenues
Sales and other operating revenue:
Unaffiliated customers	$	—	$	—		$	2,989	$	—		$	2,989
Affiliates		—		—			200		—			200
Other income		—		—			5		—			5
Equity in earnings of subsidiaries		139		152			—		(291	)		—

Total Revenues		139		152			3,194		(291	)		3,194

Costs and Expenses
Cost of products sold and operating expenses		—		—			2,933		—			2,933
Depreciation and amortization expense		—		—			63		—			63
Selling, general and administrative expenses		—		—			34		—			34

Total Costs and Expenses		—		—			3,030		—			3,030

Operating Income (Loss)		139		152			164		(291	)		164
Net interest (income) cost to affiliates		—		(1	)		1		—			—
Other interest cost and debt expense, net		—		18			—		—			18
Capitalized interest		—		(4	)		—		—			(4	)

Income (Loss) Before Provision for Income Taxes		139		139			163		(291	)		150
Provision for income taxes		—		—			8		—			8

Net Income (Loss)		139		139			155		(291	)		142
Net Income attributable to noncontrolling interests		—		—			3		—			3

Net Income (Loss) Attributable to Sunoco Logistics Partners L.P.	$	139	$	139		$	152	$	(291	)	$	139

Net Income (Loss)	$	139	$	139		$	155	$	(291	)	$	142
Recognition of funded status of affiliates’ postretirement plans		—		—			—		—			—
Gain (loss) on cash flow hedges		—		—			—		—			—

Other Comprehensive Income (Loss)		—		—			—		—			—

Comprehensive Income (Loss)		139		139			155		(291	)		142
Less: Comprehensive income (loss) attributable to noncontrolling interests		—		—			3		—			3

Comprehensive Income (Loss) Attributable to Sunoco Logistics Partners L.P.	$	139	$	139		$	152	$	(291	)	$	139

105

Consolidating Statement of Comprehensive Income (Loss)

Period from January 1, 2012 to October 4, 2012 (Predecessor)

(in millions)


	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Total
Revenues
Sales and other operating revenue:
Unaffiliated customers	$	—	$	—		$	9,460		$	—		$	9,460
Affiliates		—		—			461			—			461
Other income		—		—			18			—			18
Gain on divestment and related matters		—		—			11			—			11
Equity in earnings of subsidiaries		381		443			—			(824	)		—

Total Revenues		381		443			9,950			(824	)		9,950

Costs and Expenses
Cost of products sold and operating expenses		—		—			9,311			—			9,311
Depreciation and amortization expense		—		—			76			—			76
Impairment charge and related matters		—		—			(1	)		—			(1	)
Selling, general and administrative expenses		—		—			86			—			86

Total Costs and Expenses		—		—			9,472			—			9,472

Operating Income (Loss)		381		443			478			(824	)		478
Other interest cost and debt expense, net		—		70			3			—			73
Capitalized interest		—		(8	)		—			—			(8	)

Income (Loss) Before Provision for Income Taxes		381		381			475			(824	)		413
Provision for income taxes		—		—			24			—			24

Net Income (Loss)		381		381			451			(824	)		389
Less: Net Income attributable to noncontrolling interests		—		—			8			—			8

Net Income (Loss) Attributable to Sunoco Logistics Partners L.P.	$	381	$	381		$	443		$	(824	)	$	381

Net Income (Loss)	$	381	$	381		$	451		$	(824	)	$	389
Loss on cash flow hedges		—		—			(21	)		—			(21	)

Other Comprehensive Loss		—		—			(21	)		—			(21	)

Comprehensive Income (Loss)		381		381			430			(824	)		368
Less: Comprehensive income attributable to noncontrolling interests		—		—			8			—			8

Comprehensive Income (Loss) Attributable to Sunoco Logistics Partners L.P.	$	381	$	381		$	422		$	(824	)	$	360

106

Consolidating Statement of Comprehensive Income (Loss)

Year Ended December 31, 2011 (Predecessor)

(in millions)


	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries		Consolidating Adjustments			Total
Revenues
Sales and other operating revenue:
Unaffiliated customers	$	—	$	—		$	10,473	$	—		$	10,473
Affiliates		—		—			432		—			432
Other income		—		—			13		—			13
Equity in earnings of subsidiaries		313		399			—		(712	)		—

Total Revenues		313		399			10,918		(712	)		10,918

Costs and Expenses
Cost of products sold and operating expenses		—		—			10,264		—			10,264
Depreciation and amortization expense		—		—			86		—			86
Impairment charge and related matters		—		—			42		—			42
Selling, general and administrative expenses		—		—			90		—			90

Total Costs and Expenses		—		—			10,482		—			10,482

Operating Income (Loss)		313		399			436		(712	)		436
Net interest cost to affiliates		—		—			3		—			3
Other interest cost and debt expense, net		—		93			—		—			93
Capitalized interest		—		(7	)		—		—			(7	)

Income (Loss) Before Provision for Income Taxes		313		313			433		(712	)		347
Provision for income taxes		—		—			25		—			25

Net Income (Loss)		313		313			408		(712	)		322
Less: Net Income attributable to noncontrolling interests		—		—			9		—			9

Net Income (Loss) Attributable to Sunoco Logistics Partners L.P.	$	313	$	313		$	399	$	(712	)	$	313

Net Income (Loss)	$	313	$	313		$	408	$	(712	)	$	322
Gain on cash flow hedges		—		—			4		—			4

Other Comprehensive Income		—		—			4		—			4

Comprehensive Income (Loss)		313		313			412		(712	)		326
Less: Comprehensive income attributable to noncontrolling interests		—		—			9		—			9

Comprehensive Income (Loss) Attributable to Sunoco Logistics Partners L.P.	$	313	$	313		$	403	$	(712	)	$	317

107

Consolidating Statement of Comprehensive Income (Loss)

Year Ended December 31, 2010 (Predecessor)

(in millions)


	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Total
Revenues
Sales and other operating revenue:
Unaffiliated customers	$	—	$	—		$	6,691		$	—		$	6,691
Affiliates		—		—			1,117			—			1,117
Other income		—		—			30			—			30
Equity in earnings of subsidiaries		346		416			—			(762	)		—

Total Revenues		346		416			7,838			(762	)		7,838

Costs and Expenses
Cost of products sold and operating expenses		—		—			7,398			—			7,398
Depreciation and amortization expense		—		—			64			—			64
Impairment charge		—		—			3			—			3
Selling, general and administrative expenses		—		—			72			—			72

Total Costs and Expenses		—		—			7,537			—			7,537

Operating Income (Loss)		346		416			301			(762	)		301
Net interest (income) cost to affiliates		—		(1	)		3			—			2
Other interest cost and debt expense, net		—		76			—			—			76
Capitalized interest		—		(5	)		—			—			(5	)
Gain on investments in affiliates		—		—			128			—			128

Income (Loss) Before Provision for Income Taxes		346		346			426			(762	)		356
Provision for income taxes		—		—			8			—			8

Net Income (Loss)		346		346			418			(762	)		348
Net Income attributable to noncontrolling interests		—		—			2			—			2

Net Income (Loss) Attributable to Sunoco Logistics Partners L.P.	$	346	$	346		$	416		$	(762	)	$	346

Net Income (Loss)	$	346	$	346		$	418		$	(762	)	$	348
Recognition of funded status of affiliates’ postretirement plans		—		—			1			—			1
Loss on cash flow hedges		—		—			(2	)		—			(2	)

Other Comprehensive Loss		—		—			(1	)		—			(1	)

Comprehensive Income (Loss)		346		346			417			(762	)		347
Less: Comprehensive income attributable to noncontrolling interests		—		—			2			—			2

Comprehensive Income (Loss) Attributable to Sunoco Logistics Partners L.P.	$	346	$	346		$	415		$	(762	)	$	345

108

Consolidating Balance Sheet

December 31, 2012 (Successor)

(in millions)


	Parent Guarantor		Subsidiary Issuer		Non-Guarantor Subsidiaries			Consolidating Adjustments			Total
Assets
Cash and cash equivalents	$	—	$	2	$	1		$	—		$	3
Advances to affiliated companies		25		48		(17	)		—			56
Accounts receivable, affiliated companies		—		—		19			—			19
Accounts receivable, net		—		—		1,834			—			1,834
Inventories		—		—		478			—			478

Total Current Assets		25		50		2,315			—			2,390

Properties, plants and equipment, net		—		—		5,623			—			5,623
Investment in affiliates		6,048		7,714		118			(13,762	)		118
Goodwill		—		—		1,368			—			1,368
Intangible assets, net		—		—		843			—			843
Other assets		—		—		19			—			19

Total Assets	$	6,073	$	7,764	$	10,286		$	(13,762	)	$	10,361

Liabilities and Equity
Accounts payable	$	—	$	—	$	1,932		$	—		$	1,932
Accounts payable, affiliated companies		—		—		12			—			12
Accrued liabilities		1		30		96			—			127
Accrued taxes payable		—		—		60			—			60

Total Current Liabilities		1		30		2,100			—			2,131

Long-term debt		—		1,686		46			—			1,732
Other deferred credits and liabilities		—		—		60			—			60
Deferred income taxes		—		—		243			—			243

Total Liabilities		1		1,716		2,449			—			4,166

Equity
Sunoco Logistics Partners L.P. equity		6,072		6,048		7,714			(13,762	)		6,072
Noncontrolling interests		—		—		123			—			123

Total Equity		6,072		6,048		7,837			(13,762	)		6,195

Total Liabilities and Equity	$	6,073	$	7,764	$	10,286		$	(13,762	)	$	10,361

109

Consolidating Balance Sheet

December 31, 2011 (Predecessor)

(in millions)


	Parent Guarantor		Subsidiary Issuer		Non-Guarantor Subsidiaries			Consolidating Adjustments			Total
Assets
Cash and cash equivalents	$	—	$	2	$	3		$	—		$	5
Advances to affiliated companies		90		48		(31	)		—			107
Accounts receivable, net		—		—		2,188			—			2,188
Inventories		—		—		206			—			206

Total Current Assets		90		50		2,366			—			2,506

Properties, plants and equipment, net		—		—		2,522			—			2,522
Investment in affiliates		1,007		2,680		73			(3,687	)		73
Goodwill		—		—		77			—			77
Intangible assets, net		—		—		277			—			277
Other assets		—		13		9			—			22

Total Assets	$	1,097	$	2,743	$	5,324		$	(3,687	)	$	5,477

Liabilities and Equity
Accounts payable	$	—	$	1	$	2,110		$	—		$	2,111
Current portion of long-term debt		—		250		—			—			250
Accrued liabilities		1		37		74			—			112
Accrued taxes payable		—		—		62			—			62

Total Current Liabilities		1		288		2,246			—			2,535

Long-term debt		—		1,448		—			—			1,448
Other deferred credits and liabilities		—		—		78			—			78
Deferred income taxes		—		—		222			—			222

Total Liabilities		1		1,736		2,546			—			4,283

Equity
Sunoco Logistics Partners L.P. equity		1,096		1,007		2,680			(3,687	)		1,096
Noncontrolling interests		—		—		98			—			98

Total Equity		1,096		1,007		2,778			(3,687	)		1,194

Total Liabilities and Equity	$	1,097	$	2,743	$	5,324		$	(3,687	)	$	5,477

110

Consolidating Statement of Cash Flows

Period from October 5, 2012 to December 31, 2012 (Successor)

(in millions)


	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Total
Net Cash Flows from Operating Activities	$	140		$	162		$	270		$	(292	)	$	280

Cash Flows from Investing Activities:
Capital expenditures		—			—			(139	)		—			(139	)
Intercompany		(35	)		(37	)		(220	)		292			—

Net cash provided by (used in) investing activities		(35	)		(37	)		(359	)		292			(139	)

Cash Flows from Financing Activities:

Distributions paid to limited and general partners		(74	)		—			—			—			(74	)
Distributions paid to noncontrolling interests		(2	)		—			—			—			(2	)
Payments of statutory withholding on net issuance of limited partner units under restricted unit incentive plan		—			—			(7	)		—			(7	)
Repayments under credit facilities		—			(233	)		—			—			(233	)
Borrowings under credit facilities		—			182			11			—			193
Advances to affiliates, net		(28	)		(74	)		85			—			(17	)

Net cash provided by (used in) financing activities		(104	)		(125	)		89			—			(140	)

Net change in cash and cash equivalents		1			—			—			—			1

Cash and cash equivalents at beginning of period		—			2			—			—			2

Cash and cash equivalents at end of period	$	1		$	2		$	—		$	—		$	3

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Consolidating Statement of Cash Flows

Period from January 1, 2012 to October 4, 2012 (Predecessor)

(in millions)


	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Total
Net Cash Flows from Operating Activities	$	381		$	359		$	495		$	(824	)	$	411

Cash Flows from Investing Activities:
Capital expenditures		—			—			(235	)		—			(235	)
Proceeds from divestments and related matters		—			—			11			—			11
Intercompany		(290	)		(279	)		(255	)		824			—

Net cash provided by (used in) investing activities		(290	)		(279	)		(479	)		824			(224	)

Cash Flows from Financing Activities:

Distributions paid to limited and general partners		(178	)		—			—			—			(178	)
Distributions paid to noncontrolling interests		(5	)		—			—			—			(5	)
Payments of statutory withholding on net issuance of limited partner units under restricted unit incentive plan		—			—			(5	)		—			(5	)
Repayments under credit facilities		—			(322	)		—			—			(322	)
Borrowings under credit facilities		—			418			83			—			501
Repayment of senior notes		—			(250	)		—			—			(250	)
Advances to affiliates, net		92			74			(97	)		—			69

Net cash used in financing activities		(91	)		(80	)		(19	)		—			(190	)

Net change in cash and cash equivalents		—			—			(3	)		—			(3	)

Cash and cash equivalents at beginning of period		—			2			3			—			5

Cash and cash equivalents at end of period	$	—		$	2		$	—		$	—		$	2

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Consolidating Statement of Cash Flows

Year Ended December 31, 2011 (Predecessor)

(in millions)


	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Total
Net Cash Flows from Operating Activities	$	313		$	322		$	508		$	(713	)	$	430

Cash Flows from Investing Activities:
Capital expenditures		—			—			(213	)		—			(213	)
Acquisitions		—			—			(396	)		—			(396	)
Intercompany		(35	)		(786	)		108			713			—

Net cash provided by (used in) investing activities		(35	)		(786	)		(501	)		713			(609	)

Cash Flows from Financing Activities:

Distributions paid to limited and general partners		(210	)		—			—			—			(210	)
Distributions paid to noncontrolling interests		(8	)		—			—			—			(8	)
Contributions from general partner		2			—			—			—			2
Payments of statutory withholding on net issuance of limited partner units under restricted unit incentive plan		—			—			(3	)		—			(3	)
Repayments under credit facilities		—			(560	)		—			—			(560	)
Borrowings under credit facilities		—			529			—			—			529
Net proceeds from issuance of long-term debt		—			595			—			—			595
Promissory note from affiliate		—			(100	)		—			—			(100	)
Advances to affiliates, net		(62	)		—			(1	)		—			(63	)

Net cash provided by (used in) financing activities		(278	)		464			(4	)		—			182

Net change in cash and cash equivalents		—			—			3			—			3

Cash and cash equivalents at beginning of period		—			2			—			—			2

Cash and cash equivalents at end of period	$	—		$	2		$	3		$	—		$	5

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Consolidating Statement of Cash Flows

Year Ended December 31, 2010 (Predecessor)

(in millions)


	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Total
Net Cash Flows from Operating Activities	$	346		$	366		$	391		$	(762	)	$	341

Cash Flows from Investing Activities:
Capital expenditures		—			—			(174	)		—			(174	)
Acquisitions		—			—			(252	)		—			(252	)
Intercompany		(79	)		(723	)		40			762			—

Net cash provided by (used in) investing activities		(79	)		(723	)		(386	)		762			(426	)

Cash Flows from Financing Activities:

Distributions paid to limited and general partners		(189	)		—			—			—			(189	)
Distributions paid to noncontrolling interests		(4	)		—			—			—			(4	)
Net proceeds from issuance of limited partner units		143			—			—			—			143
Contributions from general partner		3			—			—			—			3
Payments of statutory withholding on net issuance of limited partner units under restricted unit incentive plan		—			—			(2	)		—			(2	)
Repayments under credit facilities		—			(888	)		—			—			(888	)
Borrowings under credit facilities		—			650			—			—			650
Net proceeds from issuance of long-term debt		—			494			—			—			494
Promissory note from affiliate		—			100			—			—			100
Repayment of promissory note to general partner		(201	)		—			—			—			(201	)
Advances to affiliates, net		(19	)		1			(3	)		—			(21	)

Net cash provided by (used in) financing activities		(267	)		357			(5	)		—			85

Net change in cash and cash equivalents		—			—			—			—			—

Cash and cash equivalents at beginning of period		—			2			—			—			2

Cash and cash equivalents at end of period	$	—		$	2		$	—		$	—		$	2

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ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None

ITEM 9A.

CONTROLS AND PROCEDURES

Disclosure controls and procedures are designed to ensure that information required to be disclosed in the Partnership’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified by the rules and forms of the Securities and Exchange Commission. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed in the Partnership’s reports under the Exchange Act is accumulated and communicated to management, including the President and Chief Executive Officer and the Chief Financial Officer of Sunoco Partners LLC (the Partnership’s general partner), as appropriate, to allow timely decisions regarding required disclosure.

As of December 31, 2012, the Partnership carried out an evaluation, under the supervision and with the participation of management of the general partner (including the President and Chief Executive Officer and the Chief Financial Officer), of the effectiveness of the design and operation of the Partnership’s disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, the general partner’s President and Chief Executive Officer and Chief Financial Officer concluded that the Partnership’s disclosure controls and procedures were effective.

Management of the general partner is responsible for establishing, maintaining, and annually assessing internal control over the Partnership’s financial reporting. A report by the general partner’s management, assessing the effectiveness of the Partnership’s internal control over financial reporting, appears under Item 8. “Financial Statements and Supplementary Data” of this report. Ernst & Young LLP, the Partnership’s independent registered public accounting firm, has issued an attestation report on the Partnership’s internal control over financial reporting, that also appears under Item 8. of this report.

No change in the Partnership’s internal control over financial reporting has occurred during the fiscal quarter ended December 31, 2012 that has materially affected, or that is reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

ITEM 9B.

OTHER INFORMATION

None.

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PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Prior to October 5, 2012, Sunoco Partners LLC, our general partner, was a wholly-owned, indirect subsidiary of Sunoco, Inc., a Pennsylvania corporation (“Sunoco”). Sunoco, through various subsidiaries, owned our general partner, all of the incentive distribution rights, and a 32.4 percent limited partner interest in us. However, on April 29, 2012, Sunoco entered into an Agreement and Plan of Merger, with Energy Transfer Partners, L.P. a Delaware limited partnership (“ETP”) and certain of its affiliates (the “Merger Agreement”). The Merger Agreement was amended on June 15, 2012. Upon consummation of the transactions contemplated by the amended Merger Agreement (the “Merger”), Sunoco survived as a wholly owned, indirect subsidiary of ETP and its affiliates. In connection with the Merger, Sunoco caused $2.0 billion in cash, together with the equity interests in our general partner, to be contributed to ETP, in exchange for 90,706,000 newly issued Class F units of ETP.

As a result of the Merger, our general partner is now a directly and wholly owned subsidiary of ETP. Our general partner manages our operations and activities. Our general partner’s Board of Directors (the “Board of Directors”) held five meetings during 2012. The Board of Directors has established standing committees to consider designated matters. The standing committees of the Board of Directors are: the Audit Committee, the Compensation Committee, and the Conflicts Committee. The listing standards of the New York Stock Exchange, or NYSE, do not require boards of directors of publicly-traded master limited partnerships to be composed of a majority of independent directors nor are they required to have a standing nominating or compensation committee. However, the Board of Directors has elected to have a standing compensation committee. The Board of Directors has adopted governance guidelines for the Board of Directors and charters for each of the Audit, Compensation, and Conflicts Committees.

•

The Audit Committee oversees external financial reporting, engages independent auditors, and reviews procedures for internal auditing and the adequacy of internal accounting controls. The Audit Committee met six times during 2012. The current members of the Audit Committee are: Basil Leon Bray (Chairman), Steven R. Anderson, and Scott A. Angelle.

•

The Compensation Committee oversees compensation decisions for executive officers of the general partner and the administration of the compensation plans described in the section entitled “Compensation Discussion and Analysis,” below. The Compensation Committee met five times during 2012. The current members of the Compensation Committee are: Scott A. Angelle (Chairman), Steven R. Anderson, Basil Leon Bray, Michael J. Hennigan, and Marshall S. (Mackie) McCrea, III. Since Mr. Hennigan is also an officer of our general partner, and since Mr. McCrea is President, Chief Operating Officer and Director of Energy Transfer Partners, L.L.C. (“ETP LLC”), the owner of ETP’s general partner, they each recuse themselves from Compensation Committee decisions relating to equity compensation awards (including awards under the Sunoco Partners LLC Long-Term Incentive Plan, or LTIP) to executive officers of the general partner. Mr. Hennigan also recuses himself from Compensation Committee discussion of his own compensation.

•

The Conflicts Committee reviews specific matters that the Board of Directors believes may involve conflicts of interest between Sunoco and us and determines whether the resolution of the conflict of interest is fair and reasonable to us. The Conflicts Committee met twice during 2012. The current members of the Conflicts Committee are: Steven R. Anderson (Chairman), Scott A. Angelle and Basil Leon Bray.

The members of each of the Audit Committee and the Conflicts Committee consist of those directors of our general partner who are not also executive officers of our general partner or its parent. In addition, all of the members of the Audit Committee must meet certain independence and experience standards established by the NYSE to serve on an audit committee of a board of directors. To be considered an independent director under the NYSE listing standards, the Board of Directors must affirmatively determine that a director has no material

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relationship with us, or our general partner. In making this determination, the Board of Directors adheres to the specific tests for independence included in the NYSE listing standards and our governance guidelines, and considers all of the facts and circumstances it deems necessary or advisable to make such a determination. The Board of Directors has determined affirmatively that Messrs. Anderson, Angelle, and Bray each qualify as “independent” under the NYSE listing standards and our governance guidelines (the “independent directors”). The Board of Directors also has determined that, based upon relevant experience, Mr. Bray is an “audit committee financial expert,” as defined in Item 407 of Regulation S-K of the Securities Exchange Act of 1934, as amended. A description of each member’s qualifications may be found elsewhere in this Item 10. Periodically, the Audit Committee meets separately with management, the independent auditors and personnel responsible for the internal audit function. In conjunction with regular meetings, the Audit Committee also meets in executive session without members of management present. Mr. Bray, as Chairman of the Audit Committee, leads these executive session meetings, the purpose of which is to promote open and candid discussion among the independent directors.

In order that interested parties may be able to make their concerns known to the independent directors, our unitholders and other interested parties may communicate directly with the Board of Directors, with the independent directors as a group, or with any director or committee chairperson by writing to such parties in care of Kathleen Shea-Ballay, Senior Vice President, General Counsel and Secretary, Sunoco Partners LLC, 1818 Market Street, Suite 1500, Philadelphia, PA 19103-3615. Communications may be submitted confidentially and anonymously. Under certain circumstances, the general partner or we may be required by law to disclose the information or identity of the person submitting the communication.

Communications addressed to the Board of Directors generally will be forwarded either to the appropriate committee chairperson or to all directors. Certain concerns communicated to the Board of Directors also may be referred to the general partner’s internal auditor or its General Counsel, in accordance with the general partner’s regular procedures for addressing such concerns. The chairman of the general partner’s Audit Committee, or the chairman of the Board of Directors, may direct that certain concerns be presented to the Audit Committee, or to the full Board of Directors, or that such concerns otherwise receive special treatment, including retention of external counsel or other advisors. No material actions were taken by the Board of Directors because of communications from unitholders or others received during 2012.

Our general partner has adopted a Code of Ethics for Senior Officers, which applies to the principal executive officer, the principal financial officer, the principal accounting officer, the treasurer and persons performing similar functions for the general partner and its subsidiaries. In addition, our general partner has adopted a Code of Business Conduct and Ethics, which applies to all directors, officers and employees. The Code of Business Conduct and Ethics addresses ethical handling of actual or apparent conflicts of interest, compliance with applicable laws, rules and regulations, full, fair, accurate, timely and understandable disclosure in public communications, and prompt internal reporting of violations. In accordance with the disclosure requirements of applicable law or regulation, we intend to disclose any amendment to, or waiver of, any provision of these Codes, on our website, via a press release, or under Item 5.05 of a current report on Form 8-K.

We make available, free of charge within the “Corporate Governance” section of our website at www.sunocologistics.com, and in print to any unitholder who so requests, the Code of Ethics for Senior Officers, the Code of Business Conduct and Ethics, the Audit Committee Charter, the Compensation Committee Charter, the Conflicts Committee Charter, the Corporate Governance Guidelines and our limited partnership agreement. The information contained on, or connected to, our internet website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with, or furnish to, the SEC.

Directors and Executive Officers of Sunoco Partners LLC (our General Partner)

Our common unit holders do not nominate candidates for, or vote for the election of, the directors of the Board of Directors. Our general partner is a limited liability company, and its directors are elected by ETP, as sole member of our general partner. The executive officers of the general partner are appointed by the Board of

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Directors. The diverse qualifications and experience of each of our general partner’s directors combine to help focus efforts on our core business of providing transportation, terminalling and storage of refined products and crude oil, as well as the purchase and sale of crude oil and refined products in the Northeast, Midwest, Southeast and Southwest regions of the United States. The specific qualifications of each these directors are discussed below with their biographical information.

The following table shows information for the current directors and executive officers of Sunoco Partners LLC, our general partner, as of the date of this filing. Executive officers and directors are each elected for one-year terms.


Name	Age	Position with the General Partner
Steven R. Anderson	63	Director
Scott A. Angelle	51	Director
Basil Leon Bray	68	Director
Michael J. Hennigan	53	Director, President and Chief Executive Officer
Thomas P. Mason	56	Director
Marshall S. (“Mackie”) McCrea, III	53	Director (Chairman)
Martin Salinas, Jr.	41	Director and Chief Financial Officer
Kurt A. Lauterbach	57	Senior Vice President, Lease Acquisitions
David R. Chalson	61	Senior Vice President, Operations
Michael W. Slough	56	Senior Vice President, Engineering, Construction & Procurement
Kathleen Shea-Ballay	47	Senior Vice President, General Counsel and Secretary
Peter J. Gvazdauskas	34	Vice President, Finance and Treasurer
Meghan Zaffarese	37	Vice President, Chief Human Resources Officer
Michael D. Galtman	38	Controller and Chief Accounting Officer

Mr. Anderson was elected to the Board of Directors in October 2012. Mr. Anderson began his career in the energy business more than 40 years ago with Conoco in the Permian Basin area. He then spent some 25 years with ANR Pipeline and its successor, The Coastal Corporation, as a natural gas supply and midstream executive. He later was Vice President of Commercial Operations with Aquila Midstream and, upon the sale of the midstream business to Energy Transfer in 2002, he became a part of the management team there. For the six years prior to his retirement from Energy Transfer, in October 2009, he served as Vice President of Mergers and Acquisitions. Since that time, he has been involved in private investments and currently serves as a member of the board of directors of the St. John Health System in Tulsa, Oklahoma, as well as various other community and civic organizations.

Mr. Angelle was elected to the Board of Directors in December 2012. He is an elected member of the Louisiana Public Service Commission, a five-person regulatory body. Beginning in May, 2010, Mr. Angelle served for six months as the interim Lieutenant Governor of Louisiana. During the period from 2004 to August 2012, with the exception of his service as Lieutenant Governor, he served as the Secretary of the Louisiana Department of Natural Resources. Since 2012, Mr. Angelle also has represented Louisiana’s Third Congressional District on the Board of Supervisors of Louisiana State University. Mr. Angelle also has a career in strategic planning and petroleum land management.

Mr. Bray was elected to the Board of Directors in October 2012. Currently, Mr. Bray is the Chief Executive Officer of Energy Strategies, Inc., an energy consulting firm headquartered in Tulsa, Oklahoma. He has held this position since 1994. Previously, he held various management positions with Phillips Petroleum Co., Endevco, Inc., and Anadarko Petroleum Corp. Mr. Bray also was Co-Founder and President of Resource Energy Services, LLC until its sale in 1996.

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Mr. Hennigan was elected to the Board of Directors in April 2010. He was elected President and Chief Executive Officer, effective March 1, 2012. Prior to that, he was President and Chief Operating Officer from July 2010 until March 2012. From May 2009 until July 2010, Mr. Hennigan served as Vice President, Business Development. Prior to joining our general partner, he was employed in the following positions at Sunoco: Senior Vice President, Business Improvement from October 2008 to May 2009; and Senior Vice President, Supply, Trading, Sales and Transportation from February 2006 to October 2008.

Mr. Mason was elected to the Board of Directors in October 2012. Mr. Mason has served as the Vice President, General Counsel and Secretary of ETP’s general partner since June 2008. Mr. Mason served as General Counsel and Secretary of ETP’s General Partner since February 2007. Prior to joining ETP, he was a partner in the Houston office of Vinson & Elkins. Mr. Mason has specialized in securities offerings and mergers and acquisitions for more than 25 years.

Mr. McCrea was elected as Chairman of the Board of Directors in October 2012. He has been a director of ETP’s general partner since December 23, 2009. He is the President and Chief Operating Officer of ETP’s general partner, and has served in that capacity since June 2008. Prior to that, he served as President, Midstream of ETP’s general partner from March 2007 to June 2008. Mr. McCrea also serves on the Board of Directors of the general partner of Energy Transfer Equity, L.P. Mr. McCrea has extensive project development and operational experience, and is able to assist the Board of Directors in creating and executing the Partnership’s strategic plan.

Mr. Salinas was elected to the Board of Directors in October 2012, and was elected contemporaneously as the Chief Financial Officer of our general partner. Mr. Salinas has served as Chief Financial Officer of ETP’s General Partner since June 2008. Prior to that, he served as Controller and Treasurer of ETP’s general partner from September 2004 to June 2008. Prior to joining ETP, Mr. Salinas was a Senior Audit Manager with KPMG in San Antonio, Texas from September 2002.

Mr. Chalson was elected Senior Vice President, Operations in January 2013. Prior to that, he was Vice President, Operations from July 2012 to January 2013. From 2007 to 2012, Mr. Chalson served as Manager, Oil Movements.

Mr. Galtman was elected Controller and Chief Accounting Officer in July 2008. From June 2007 to July 2008, he served as Manager of Financial Planning and Analysis for Sunoco Logistics Partners L.P.

Mr. Gvazdauskas was elected Vice President, Finance and Treasurer in January 2012. Prior to that, he had been Vice President, Finance since April 2010. From June 2008 to March 2010, he served as Manager of Corporate Finance of Sunoco; from December 2007 to May 2008, he was Manager of Special Projects at Sunoco; and from November 2005 to November 2007, he was Controller of SunCoke Energy, Inc.

Mr. Lauterbach was elected Senior Vice President, Lease Acquisitions in January 2013. Prior to that, he was Vice President, Lease Acquisitions, from October 2010 to January 2013. Mr. Lauterbach also served as Manager of Marketing and Trading—Lease Acquisition, from June 2008 through September 2010. From May 2000 to May 2008, he was Manager of Business and Performance Analysis—Lease Acquisition.

Ms. Shea-Ballay was elected Senior Vice President, General Counsel and Secretary in January 2013. Prior to that, she was Vice President, General Counsel and Secretary from June 2010 to January 2013. Ms. Shea-Ballay served as Assistant General Counsel and Chief Counsel for Commercial Transactions for Sunoco from April 2005 until June 2010. Prior to joining Sunoco, Ms. Shea-Ballay was a partner at the Pepper Hamilton LLP law firm in Philadelphia, Pennsylvania.

Mr. Slough was elected Senior Vice President, Engineering, Construction & Procurement in January 2013. Mr. Slough has been Vice President, Engineering, Construction & Procurement, of the Company since 2012. Prior to that, he was Director of Engineering & Construction, of the Company from 2010 to 2012. From 2006 to 2010, he was Venture Manager at Sunoco, Inc.

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Ms. Zaffarese was elected Vice President, Chief Human Resources Officer in January 2013. Prior to that, she was Director, Human Resources & Administration for the Company since March 2011. Prior to that, she was Director, Human Resources, PSG for Sunoco, Inc. from April 2010 to March 2011 and was Vice President, Executive Development and Corporate Human Resources, ARAMARK Corp. from May 2009 to April 2010.

SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

Section 16(a) of the Securities Exchange Act of 1934 requires the directors and executive officers of our general partner, as well as persons who own more than ten percent of the common units representing limited partnership interests in us, to file reports of ownership and changes of ownership on Forms 3, 4 and 5 with the Securities and Exchange Commission, or SEC. The Securities and Exchange Commission regulations also require that copies of these Section 16(a) reports be furnished to us by such reporting persons. Based upon a review of copies of these reports, we believe all applicable Section 16(a) reports were timely filed, with the exception of a Form 4 for Michael D. Galtman, reporting the vesting and settlement of certain restricted units granted in January 2011 under the Sunoco Partners LLC Long-Term Incentive Plan (“LTIP”), which was inadvertently filed late due to an administrative error.

ITEM 11.

EXECUTIVE COMPENSATION

We do not have any employees. We are managed by the officers of our general partner. We reimburse our general partner for certain indirect and direct expenses, including executive compensation expenses, incurred on our behalf. Employees of the general partner participate in employee benefit plans and arrangements sponsored by the general partner or its affiliates.

COMPENSATION DISCUSSION AND ANALYSIS

Overview:

ETP controls our general partner and owns a significant limited partner interest in us. Mr. Salinas is an employee of ETP’s general partner. In addition to rendering services to us, he devoted a majority of his professional time to ETP during 2012. Mr. Salinas participates in employee benefit plans and arrangements sponsored by ETP and its affiliates. The compensation committee of ETP’s general partner sets the components of his compensation, including salary and annual incentive, and we have no control over this compensation determination process. However, our general partner’s Compensation Committee may make equity awards to Mr. Salinas in recognition of the services provided to us. In January 2013, Mr. Salinas received such an equity award, in the form of 8,333 restricted units granted pursuant to our Long-Term Incentive Plan, or LTIP, vesting incrementally over a five-year period. Please refer to ETP’s 2012 Annual Report on Form 10-K for further information on Mr. Salinas’ compensation.

Effective March 1, 2012, Lynn L. Elsenhans stepped down as Chief Executive Officer of Sunoco Partners LLC, our general partner and, effective May 3, 2012, she also stepped down as a director and Chairman of our general partner’s Board of Directors. Ms. Elsenhans had been Chief Executive Officer since July 2010. She was elected as a director in August 2008, and had been Chairman since October 2008. Mr. Hennigan, who had been our general partner’s President and Chief Operating Officer since July 2010, succeeded Ms. Elsenhans as Chief Executive Officer. Effective March 1, 2012, Mr. Hennigan became President and Chief Executive Officer of Sunoco Partners LLC.

Effective May 3, 2012, Brian P. MacDonald succeeded Ms. Elsenhans as Chairman of our general partner’s Board of Directors. He had been a director since September 2009. Mr. MacDonald also served as Vice President and Chief Financial Officer of our general partner from March 2010, until March 1, 2012. Effective March 1, 2012, Michael J. Colavita became our general partner’s Interim Chief Financial Officer. As of the effective time of the Merger, on October 5, 2012, Mr. Colavita resigned as Interim Chief Financial Officer, and Mr. Salinas was appointed as our general partner’s Chief Financial Officer.

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During their tenure in 2012 as officers of our general partner, Ms. Elsenhans and Messrs. MacDonald, and Colavita were also employees of Sunoco (the “Sunoco Executives”). In addition to rendering services to us, they devoted a majority of their professional time to Sunoco during 2012. The Sunoco Executives participated in employee benefit plans and arrangements sponsored by Sunoco. The compensation committee of Sunoco’s Board of Directors determined the components of their compensation, including salary and annual incentive, and we had no control over that compensation determination process.

Under the terms of the Omnibus Agreement with Sunoco, we paid an administrative fee to reimburse Sunoco for the provision of general and administrative services for our benefit, including allocated expenses of Sunoco personnel who provided corporate services to us. The amount reimbursed to Sunoco was determined based upon the portion of professional time devoted to us by Sunoco personnel. In addition, each year our general partner determines the aggregate amount to be reimbursed to Sunoco by us, taking into account the totality of services performed for our benefit by the Sunoco Executives during the calendar year. See Item 13, “Certain Relationships, Related Transactions and Director Independence” for further discussion of our relationships and transactions with Sunoco, including reimbursement for the administrative services provided to us.

During 2012, Ms. Shea-Ballay and Mr. Hennigan were employees of our general partner and rendered their services solely to us. Except as specified below, all compensation paid to these individuals is fully disclosed in the tabular disclosure following this Compensation Discussion and Analysis (“CD&A”). Throughout the CD&A discussion, the following individuals are referred to as the Named Executive Officers, or NEOs, and are included in the Summary Compensation Table:

•

Michael J. Hennigan — President and Chief Executive Officer

•

Martin Salinas, Jr. — Chief Financial Officer

•

Kathleen Shea-Ballay — Vice President, General Counsel & Secretary

•

Lynn L. Elsenhans — Former Chairman and Chief Executive Officer

•

Brian P. MacDonald — Former Chairman and Vice President and Chief Financial Officer

•

Michael J. Colavita — Former Interim Chief Financial Officer

Compensation Philosophy and Objectives: Our general partner seeks to improve our financial and operating performance and provide a desirable return on investment to holders of our common units, while maintaining financial strength and flexibility. Our general partner provides a competitive compensation package in order to attract highly competent and skilled executives to meet these objectives. During 2012, where doing so was determined to be a cost-effective and administratively efficient means of providing benefits to its employees, our general partner was a participating employer in certain benefit plans sponsored by Sunoco, including its defined benefit pension plan. We reimbursed Sunoco for the benefits we received from our participation in these plans.

During 2012, the compensation for our executive officers, including our NEOs, but excluding Mr. Salinas and the Sunoco Executives, was determined by our general partner’s Compensation Committee. The compensation program utilizes objectives and measurement criteria based upon performance relative to other publicly traded master limited partnerships and general industry companies (adjusted for size), and this compensation program is designed to provide the competitive level of total compensation needed to attract, retain and motivate talented and experienced executives who can contribute to our success. The compensation program emphasizes performance-based compensation (pay-at-risk), to promote achievement of short-term and long-term business objectives consistent with our strategic plan and is structured so that the target compensation (base salary and performance-based annual and long-term opportunities) is typically at the median of the general industry market data. Executive compensation is aligned with the interests of our unitholders by providing annual incentive awards directly tied to cash flow generation and long term incentives in the form of restricted units. Our general partner also has adopted unit ownership guidelines requiring executives and certain other key employees to own a certain level of common units, as further described herein. The Compensation Committee

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reviews the compensation program and makes changes deemed appropriate and in the best interests of our unitholders and us. The Compensation Committee retains authority over all compensation decisions for our NEOs (other than the Shared Executives). The general partner’s eligible executives participate in the defined benefit programs and the qualified and non-qualified defined contribution plans of Sunoco.

Compensation Methodology: During 2012, our general partner utilized Compensation Advisory Partners LLC as a consultant to: (1) assess the effectiveness and competitiveness of the compensation program; (2) assist in evaluating and designing the compensation program; and (3) advise on executive compensation issues and external trends going forward. In support of the analytical work to be performed by Compensation Advisory Partners, our general partner engaged Towers Watson to provide comparative market information regarding:

•

compensation practices and programs, based on an analysis of other publicly traded master limited partnerships and general industry companies;

•

base salaries paid to executive officers with responsibilities similar in breadth and scope to the general partner at the publicly traded master limited partnership and general industry company level, for which such applicable data exists; and

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the mix of total compensation (including base salary, annual incentive award levels, long-term incentive award levels and short—and long-term incentive practices) paid to executive officers in similar positions at such companies.

The master limited partnership group consists of the entities in the LTIP Peer Group (as discussed on pages 127 and 128) as well as a broader group of publicly traded master limited partnerships composed of companies with varying levels of revenue, market capitalization and market maturity, including Markwest Partners LP, Amerigas Partners LP and Suburban Propane Partners LP, that may compete with the general partner for executive talent (together, the “MLP Group”). This MLP Group is reviewed annually with the assistance of the compensation consultants engaged by our general partner, and the composition of the MLP Group may be updated in order to reflect mergers, acquisitions, business bankruptcies and other similar events.

The Compensation Committee also reviews compensation data from the general industry on a position-by-position basis to ascertain competitive rates of compensation. This survey data consists of general industry data for executive positions reported in the Towers Watson Executive Compensation General Industry Database, a proprietary compensation database of approximately 800 U.S. industrial companies that is updated annually. The general industry data are collected at both the corporate (stand-alone parent company) and group (business unit of a larger organization) levels, and then size-adjusted using regression analysis to revenues comparable to those of our operating revenues plus either our crude oil acquisition and marketing margins (in the case of corporate data), or our crude oil acquisition and marketing revenues (in the case of group data). The general industry group together with the MLP Group form the “Compensation Comparative Group.”

The Compensation Committee reviewed the compensation data for each individual NEO (other than Mr. Salinas and the Sunoco Executives) compared to the compensation of executives in similar positions with similar responsibility levels in the Compensation Comparative Group. In its review for Ms. Shea-Ballay and Mr. Hennigan during 2012, the Compensation Committee looked primarily at general industry compensation data, but also reviewed the MLP Group data when such data was applicable to the specific executive position.

The three components of compensation for the NEOs (other than Mr. Salinas and the Sunoco Executives) consist of base salary, annual incentives and long-term incentives, as discussed below. Compensation levels for the NEOs were chosen to enhance our general partner’s ability to attract and retain a highly skilled and motivated executive leadership team. Based upon the individual performance of each NEO, as well as our performance as a whole, actual realized compensation may be higher or lower than the targets set under our Annual Incentive Plan, or our LTIP. In each case, an executive’s salary and incentive opportunities ultimately were determined by the unique responsibilities of his or her position. As a tool to assist in its review of executive compensation, the Compensation Committee uses tally sheets that reflect all components of the executive’s total compensation, including salary, annual incentives, and long-term incentives.

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Elements of Compensation: Unless specified to the contrary below, references in this section of the CD&A to “NEOs,” or “executive officers,” does not include Mr. Salinas or the Sunoco Executives.

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Base Salary: Base salary is designed to provide for a competitive fixed level of remuneration that attracts and retains executive officers, and compensates them for their level of responsibility and sustained individual performance (including experience, scope of responsibility, and results achieved). The salaries of the NEOs are reviewed on an annual basis. The compensation consultant provides data comparing the salaries of the NEOs to the salaries of executives in the Compensation Comparative Group. The general partner and the Compensation Committee attempt to establish and maintain base salaries for the NEOs at or near the median level of competitive market base salary data. Base salaries also are influenced by internal pay equity (fair and consistent application of compensation practices). The Compensation Committee, with input from the compensation consultant and the Chief Executive Officer (except with respect to the Chief Executive Officer’s own salary), approves all base salaries for the NEOs. The Summary Compensation Table on page 133 includes the NEO base salaries that were approved for 2012 or, for those NEOs that were employed for only a partial year, the salaries actually earned in 2012. At the NEO level, the balance of compensation is weighted toward pay-at-risk compensation (annual and long-term incentives).

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Annual Incentive Awards:

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Why the General Partner Has Adopted the Annual Incentive Plan. The general partner’s Annual Incentive Plan is designed to enhance the performance of key employees, including NEOs, by providing annual cash incentive opportunities for achievement of annual financial and operational performance goals. In particular, annual incentive awards are provided to NEOs and other key employees in order to provide competitive incentives to those who can significantly influence performance and promote achievement of our short-term business objectives. The Compensation Committee, in its sole discretion, determines the amount of the payments, if any, made to NEOs for each fiscal year. The Compensation Committee also may amend or change the Annual Incentive Plan at any time.

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Determination of the Amounts Awarded Under the Annual Incentive Plan. Under the plan, an individual’s annual incentive payout amount is determined by multiplying: (a) the product of his or her base salary and individual incentive guideline, by (b) a factor ranging from zero to 200 percent (the “Payout Percentage”), based upon the level of attainment of specific pre-established goals. For the 2012 annual incentive program, the Committee selected EBITDA less maintenance capital, and certain Partnership-related strategic milestones (described below) as the established performance goals. These goals were selected because they were deemed to be important for our short-term success and future sustainability. Multiple performance goals were selected because of the belief that no one goal was sufficient to capture the total performance that we sought to drive. Goals were established at levels that the Compensation Committee believes provide meaningful incentives for management to continue to be focused on operations excellence. If we do not achieve at least the minimum threshold performance goals, no award payment will be made. These performance goals and strategic milestones are not GAAP financial measures. For purposes of calculating the eventual payout of awards made for the 2012 plan year under the Annual

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Incentive Plan, the Compensation Committee approved performance goals and Payout Percentages based upon meeting weighted objectives for the following principal measurements:

(1)

Performance relative to the Partnership’s targeted EBITDA less maintenance capital (weighted 60%):


EBITDA less Maintenance Capital	Payout *
< $375 Million		0	%
$375 Million		25	%
$500 Million		100	%
> $625 Million		200	%

*	Payout Percentages for performance between specified goals will be interpolated on a straight-line basis, not to exceed the 200% cap.

(2)

Our performance related to five strategic milestones (weighted 40%):


Strategic Milestones	Weighting
Environmental (releases with off-site impacts)		10	%
Safety (employee and contractor lost time rate)		5	%
Organic Growth Funnel (projected EBITDA rom qualifying organic growth projects)		5	%
Northeast Logistics Transformation		5	%
Major Projects:
West Texas Expansion		5	%
Mariner West		5	%
Butane Installations		5	%

The use of health, environmental and safety performance goals reinforces that, along with financial success, management is focused on continuing to protect our employees and the communities in which we operate.

2012 Annual Incentive Payout Amount. The annual individual incentive guideline is based on general industry market data from the Compensation Comparative Group, as well as internal pay equity considerations. Following the end of each year, the Compensation Committee reviews performance data with management and the compensation consultant, and determines the extent to which the specified goals have been achieved, and the payment amount within the applicable range. Based upon our level of attainment of the specified goals during the 2012 plan year, the Payout Percentage was 170.4 percent. The annual incentive reinforces the links between strategy, goal setting and results. The individual incentive guidelines (as a percentage of base salary) for the NEOs for 2012 were as follows:


Name	Title	Annual Incentive Plan Individual Incentive 2012 Guideline
Michael J. Hennigan	President and Chief Executive Officer	110%
Martin Salinas, Jr.	Chief Financial Officer	Not Applicable
Kathleen Shea-Ballay	Vice President, General Counsel & Secretary	45%
Lynn L. Elsenhans	Former Chairman and Chief Executive Officer	Not Applicable
Brian P. MacDonald	Former Vice President and Chief Financial Officer	Not Applicable
Michael J. Colavita	Former Interim Chief Financial Officer	Not Applicable

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Under the general partner’s Annual Incentive Plan, the Compensation Committee has the discretion to reduce the amounts payable to participants, or to determine that no amount will be paid, even if all performance criteria for payout are met. The annual incentive awards are paid in cash. The annual incentives earned by executive officers who were NEOs for 2012 are included in the Summary Compensation Table on page 133 under “Non-Equity Incentive Plan Compensation.” Mr. Salinas and the Sunoco Executives did not participate in our Annual Incentive Plan during 2012.

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Long-Term Incentive Awards:

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Why the LTIP was Adopted. Long-term incentive awards for executive officers are granted under the LTIP in order to promote achievement of our long-term strategic business objectives. The LTIP was designed to align the economic interests of executive officers, key employees and directors with those of our common unitholders; to provide competitive compensation opportunities that can be realized through attainment of performance goals; and to provide an incentive to management for continuous employment with the general partner and its affiliates. Long-term incentive awards are based upon the common units representing limited partnership interests in us, although they may be payable in common units, or in cash. The Compensation Committee administers the LTIP and, in its discretion, may terminate or amend the LTIP at any time with respect to any units for which a grant has not yet been made. Changes to any outstanding grant that would materially impair the rights of a participant cannot be made without the consent of the participant. The Compensation Committee also has the right to alter or amend the LTIP or any part of the LTIP from time to time, including increasing the number of units that may be granted, subject to unitholder approval as required by the exchange upon which the common units are listed at that time.

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The elements of compensation under the LTIP. The LTIP provides for two types of awards: restricted units and unit options.

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Restricted Units. Each restricted unit is a phantom unit that entitles the grantee to receive a common unit upon vesting or, in the discretion of the Compensation Committee, an amount of cash equivalent to the value of a common unit. From time to time, the Compensation Committee may make grants under the plan to employees and/or directors containing such terms as the Compensation Committee shall determine under the plan. Special one-time grants of restricted units may be made at any time during the year, subject to the approval of the Compensation Committee. These grants are infrequent, and generally are used for new hires, retention, promotions and recognition of extraordinary accomplishments. The Compensation Committee will determine the conditions upon which the restricted units granted may become vested or forfeited, and whether or not any such restricted units will have distribution equivalent rights entitling the grantee to receive an amount in cash equal to cash distributions made by us with respect to a like number of our common units during the restricted period. Under our current LTIP, the Compensation Committee may grant either restricted units that vest over time with continued service, or restricted units with performance-based vesting. The payout of time-vesting restricted units is conditioned only upon continued employment through the end of each applicable vesting period. At the discretion of the Compensation Committee, the vesting periods for such grants typically ranges from three to five years, and these grants may be designed either to pay out in full only at the end of such period, or to pay out incrementally in equal annual installments during such period. Performance-based restricted units, on the other hand, are designed to pay out only if certain performance measures have been met over the applicable performance period, generally three years. As a result, the payout under an LTIP grant of performance-based restricted units is influenced not only by performance in the year in which the award is paid, but also by performance for the two prior years. The value received from all grants of restricted units will be affected by any changes in the trading price of our common units during the period between the grant date and the payment date.

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Unit Options. The LTIP currently permits the grant of options covering common units. No unit options have been granted since the inception of the LTIP in 2002. However, in the future, the Compensation Committee may grant unit options under the LTIP to employees and directors, containing such terms as the Compensation Committee shall determine.

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Accounting and Tax Considerations. We account for the equity compensation expense of our general partner’s employees, including the NEOs, in accordance with U.S. generally accepted accounting principles, or GAAP, which requires us to estimate and record an expense for each equity award over the vesting period of the award. For performance-based restricted units that are paid out in the form of common units, the value of our common units on the date of grant is used for determining the expense, with an adjustment for the actual performance factors achieved. Thus, the expense for performance-based restricted units payable in units generally is not adjusted for changes in the trading price of our common units after the date of grant. For market-based awards, the value is determined using a Monte Carlo simulation. The expense for unit options and stock-settled restricted units is recognized ratably over the vesting period. For cash compensation, the accounting rules require us to record it as an expense at the time the obligation is accrued. Because we are a partnership, and our general partner is a limited liability company, Code Section 162(m) does not apply to the compensation paid to our NEOs and, accordingly, our general partner’s Compensation Committee did not consider its impact in determining compensation levels for 2012. In deciding to grant long-term incentive awards of restricted units, rather than unit options, our general partner’s Compensation Committee did consider the tax implications to us.

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Equity Grant Practices. Equity awards to employees are approved at meetings of our general partner’s Compensation Committee. In exigent circumstances, however, such awards may be approved by unanimous written consent of the Compensation Committee. The grant date of an equity award is the date of the Compensation Committee meeting at which such equity award is approved. The Compensation Committee may, in its discretion, refrain from approving grants of equity awards to employees if the meeting at which such approval is to be considered occurs during a period in which management is in possession of material non-public information, in which case, approval of such equity awards may be deferred to the next Compensation Committee meeting. No grant approvals were deferred to a later Compensation Committee meeting in 2012.

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Determination of the Amounts Awarded under the LTIP. In conjunction with the review and approval of other elements of each NEO’s compensation, the annual LTIP awards of restricted units for 2012 were reviewed and approved at the Compensation Committee’s January 2012 meeting and the grant date was the date of the meeting. As appropriate, the Compensation Committee may also review and approve specific LTIP awards to executive officers at other times during the year in connection with their hiring, or promotion. In determining the appropriate long-term value for each executive, the Compensation Committee reviews the level of responsibility and total compensation of each executive, and the competitive market data presented by the compensation consultant. The Compensation Committee approved the specific awards granted to each NEO, and also approved the aggregate pool of awards to be granted to other key employees. In general, the target number of restricted units granted to each executive officer under the LTIP is calculated by taking the product of such officer’s base salary and the applicable guideline percentage for that officer, and then dividing by the average daily closing market price of our common units during the last ten (10) trading days prior to the meeting at which the LTIP grant will be approved. Under no circumstances may the aggregate number of units granted to a single executive exceed the maximum applicable limit(s) under the LTIP. When approving grants to executives, including the NEOs, the Compensation Committee may consider information provided by the Chief Executive Officer, except with respect to the Chief Executive Officer’s own grants. The Compensation Committee

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utilizes Towers Watson to assist in the evaluation of grant recommendations. For the LTIP grants made during 2012, the applicable guideline percentages for executive officers who were NEOs were as follows:


Name	Title	LTIP Guideline Percentage
Michael J. Hennigan	President and Chief Executive Officer	150%
Martin Salinas, Jr.	Chief Financial Officer	Not Applicable
Kathleen Shea-Ballay	Vice President, General Counsel & Secretary	75%
Lynn L. Elsenhans	Former Chairman and Chief Executive Officer	Not Applicable
Brian P. MacDonald	Former Vice President and Chief Financial Officer	Not Applicable
Michael J. Colavita	Former Interim Chief Financial Officer	Not Applicable

Awards granted under the LTIP are based upon the common units representing limited partnership interests in us. The expenses for LTIP equity awards are recognized ratably over the vesting period, and are accelerated for vesting at retirement eligibility dates.

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Determination of LTIP Award Payout. Performance-based restricted unit awards granted under the LTIP are generally designed to provide long-term incentive compensation that will pay out only if certain pre-established performance measures have been met over an applicable performance period. The performance period for the performance-based restricted units awarded in January 2010 ended December 31, 2012. However, in October 2012, the Merger of Sunoco into ETP, and the related transfer of equity ownership interests in our general partner from subsidiaries of Sunoco to ETP, resulted in a “Change of Control” for purposes of the LTIP. As of the effective date of the Merger, outstanding LTIP grants made prior to July 2010 automatically vested and became payable in accordance with their respective terms. Outstanding time-vesting grants were paid out in full. Performance-based grants outstanding for more than one year were paid out at the greater of the target amount, or an amount in line with our actual performance immediately prior to the Merger. Performance-based grants that were outstanding for one year or less were paid out at the target amount. In July 2010, our LTIP was amended to provide for “double-trigger” vesting and payout in the event of a Change of Control (as defined in the LTIP). Thus, in the event of a Change of Control, LTIP grants of restricted units or unit options, made after July 2010, will automatically vest and become payable or exercisable only if the grantee’s employment (or service as a director) is terminated as a result of a “Qualifying Termination” (as defined in the LTIP) following such Change of Control.

For the performance-based LTIP grants made prior to October 2012, the Compensation Committee has determined that eventual payout of such LTIP awards will depend upon our achievement of performance levels based on two equally weighted performance measures: total unitholder return (including cash distributions plus appreciation in unit price) relative to peer companies and distributable cash flow, as measured by the distribution coverage ratio (defined as the sum of distributable cash flow divided by the sum of the distributions paid to unitholders) relative to goals defined by the Compensation Committee, both measured over a three-year performance cycle. Our peer companies consist of other publicly traded master limited partnerships having a business mix comparable to ours (the “LTIP Peer Group”).

For the 2012 fiscal year, the LTIP Peer Group consisted of the following companies: Boardwalk Pipeline Partners, L.P.; Buckeye Partners LP; Crosstex Energy LP; El Paso Pipeline Partners, L.P.; Enbridge Energy Partners LP; Energy Transfer Partners L.P.; Enterprise Products Partners LP; Holly Energy Partners LP; Kinder Morgan Energy Partners LP; Magellan Midstream Partners LP; NuStar Energy LP; ONEOK Partners LP; Plains All American Pipeline LP; and Spectra Energy Partners LP. This LTIP Peer Group is reviewed annually with the assistance of Towers Watson. The performance period for the 2012 annual LTIP awards ends December 31, 2014. Actual payout may range from zero percent to 200 percent of the units granted to each recipient, based upon our performance with respect

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to each of these two measures. Payment with respect to earned performance-based restricted units is made in common units no later than March 15 following the end of the performance period. The following objective performance goals, assigned weights, and payout factors were approved by the Compensation Committee for the 2012 plan year:

Total Unitholder Return

(weighted 50%)


Ranking Against Peer Companies	Payout Factor
Below 40th Percentile		0	%
40th Percentile		50	%
50th Percentile		100	%
75th Percentile		150	%
90th Percentile		200	%

Distribution Coverage Ratio (weighted 50%)


Distribution Coverage Ratio Targets	Payout Factor
Below 1.00		0	%
1.00		25	%
1.20		75	%
1.30		100	%
1.55		150	%
1.80 and above		200	%

In selecting total unitholder return and distributable cash flow, as measured by the distribution coverage ratio, as the performance measures applicable to the payout of performance-based restricted units, consideration was given to a balanced incentive approach, utilizing those measures deemed most important to our common unitholders, while recognizing the difficulty of accurately predicting market conditions over time. For these grants, the Compensation Committee believes that performance relative to the peer companies is an important criterion for payout since market conditions are outside the control of management, and management will realize greater than median levels of compensation only when we outperform our LTIP Peer Group. Conversely, regardless of market conditions, management will realize less than median compensation levels when we underperform as compared to our LTIP Peer Group. Total unitholder return is a measure of investment performance expressed as total return to unitholders based upon the cumulative return over a three-year period reflecting price appreciation and reinvestment of cash distributions during the performance period and is a non-GAAP metric. Total unitholder return is measured using a one-month average stock price at the beginning and end of the three-year performance period. Similarly, distribution coverage ratio also is a non-GAAP financial measure that is measured over the same three-year performance period. As an additional incentive to promote the growth of cash distributions to our unitholders during the performance period, distribution equivalent rights were granted in tandem with the 2012 performance based restricted unit awards. At the end of the performance period, to the extent that the restricted units are paid out, these distribution equivalent rights entitle the grantee of the restricted units to receive an amount equal to the cumulative cash distributions that otherwise would have been paid over the performance period had the grantee been the holder of record of the number of our common units equal to the number of restricted units paid out. This amount may be taken in the form of cash or additional common units (fractional units are cashed out).

All of the new LTIP grants made subsequent to the October 2012 Merger are all time-vesting grants that provide for vesting over a specified time period, conditioned solely upon continued employment (or Board service) as of each applicable vesting date, rather than vesting based on the satisfaction of any performance objectives. This change resulted from the Compensation Committee’s determination that vesting based on continued employment, rather than the satisfaction of performance objectives, was more generally prevalent with companies in the energy industry. These restricted unit grants generally provide for vesting over a five-year period at 20 percent each year, subject to continued employment (or Board service) through each specified vesting date. Each of these restricted unit grants typically entitle the recipient to receive, with respect to each of our common units subject to such grant

that has not either vested or been forfeited, a cash payment equal to each cash distribution per common unit made by us on our common units promptly following each such distribution by us to our

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unitholders. In approving these restricted unit grants, the Compensation Committee considered the factors discussed above with regard to our Annual Incentive Plan, as well as the long-term objective of retaining the recipients of such grants, as key drivers of our future success, the existing level of equity ownership of such individuals and the previous equity unit awards to such individuals subject to vesting.

Unit Ownership Guidelines: Sunoco Partners LLC has established guidelines for the ownership of our common units, applicable to its executives and certain key employees. For executives (including NEOs) and other key employees, the applicable unit ownership guidelines are denominated as a multiple of base salary, and the amount of common units required to be owned increases with the level of responsibility. Under the current guidelines, the President and Chief Executive Officer is expected to own common units having a minimum value of five times his base salary, while each of the remaining NEOs are expected to own common units having a minimum value of two times their respective base salary. The general partner and the Compensation Committee believe that the ownership of our common units, as reflected in these guidelines, is an important means of tying the financial risks and rewards for our executives to our total unitholder return and better aligning the interests of such executives with those of our unitholders. Executive officers who have not yet met their respective guideline must accumulate our common units until such guideline is met. Except for sales of common units in settlement of tax obligations relating to the receipt and payment of LTIP awards, such persons are prohibited from disposing of any of our common units until the applicable ownership guideline has been attained. However, those individuals who have met or exceeded their applicable ownership guideline may dispose of our common units in a manner consistent with applicable law and our policy, but only to the extent that such individual’s remaining ownership of common units would continue to exceed the applicable ownership guideline.

Insider Trading (including Hedging) Policy: The employees of our general partner are subject to the Sunoco Partners LLC Insider Trading Policy which, among other things, prohibits such employees from entering into short sales, or purchasing, selling, or exercising any puts, calls, or similar derivative security instruments pertaining to our common units, all of which could incent an employee towards engaging in overly risky behavior for short-term gains. This prohibition does not extend to unit options that may be issued in accordance with the terms of our general partner’s LTIP.

Other Plans: During 2012, employees of the general partner and its affiliates, including the NEOs, participated in the following Sunoco benefit plans:

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The Sunoco, Inc. Retirement Plan is a qualified defined benefit plan, under which benefits are subject to Code limits for pay and amount. Under the Retirement Plan, executives hired before January 1, 1987 participate in a “final average pay” formula. Those executives hired on or after January 1, 1987 participate in a “cash balance” formula, which provides a benefit based on career pay rather than final average pay. Effective June 30, 2010, Sunoco froze pension benefits (including accrued and vested benefits) payable under this plan for all salaried employees, including the NEOs of our general partner who participate in this plan.

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The Sunoco, Inc. Pension Restoration Plan is a non-qualified, unfunded plan that provides retirement benefits that otherwise would be provided under the Retirement Plan, except for the Code limits. Effective June 30, 2010, Sunoco froze benefits (including accrued and vested benefits) payable under this plan for all salaried employees, including the NEOs of our general partner who participate in this plan.

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The Sunoco, Inc. Executive Retirement Plan is a non-qualified, unfunded plan that provides supplemental pension benefits to certain eligible NEOs over and above an NEO’s benefits under the Retirement Plan and the Pension Restoration Plan. In 2012, Ms. Elsenhans and Mr. MacDonald participated in the Executive Retirement Plan as Sunoco employees. Benefits under this plan are offset by those provided under the Retirement Plan and the Pension Restoration Plan. Effective June 30, 2010, Sunoco froze the benefits (including accrued and vested benefits) otherwise payable under this plan.

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The Sunoco, Inc. Capital Accumulation Plan (“SunCAP”) is a broad-based 401(k) qualified defined contribution plan for Sunoco and certain affiliates, including our general partner. SunCAP is designed for long-term investment, to assist employees in accumulating funds for retirement. Employees who elect to participate in SunCAP may elect to make salary deferrals immediately. For employees having at least one year of service, we match the first five percent of base pay contributed, on a dollar-for-dollar basis. Effective July 1, 2010, for all employees, whether or not they elect to make salary deferrals, including NEOs who are affected by the pension freeze, we may make:

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a discretionary profit sharing contribution of up to three percent of base pay for eligible employees, after one year of service; and

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an additional discretionary profit sharing contribution of up to four percent of base pay for such employees who, on June 30, 2010, had at least 10 years of service and completed years of age and service totaling at least 60.

This discretionary profit-sharing contribution was added to SunCAP to mitigate the impact of the pension benefits freeze described above. Participating employees choose how their contributions and our matching and profit sharing contributions are invested from among various funds provided for investment. An employee who terminates employment may elect to take a lump-sum distribution from the plan.

Until October 2012, one of the investment options in SunCAP included Sunoco common stock equivalent funds. However, in connection with the Merger of Sunoco with ETP, all Sunoco common stock held in the SunCAP was liquidated at the end of September. Beginning in October 2012, the Sunoco stock equivalent funds were removed as an investment option under the SunCAP. This change was necessitated because the conversion of Sunoco common stock into ETP common units resulting from the Merger, and the receipt and retention of merger consideration in the form of ETP common units within SunCAP accounts, would have resulted in prohibited transactions under the Employee Retirement Income Security Act of 1974 (“ERISA”), the federal law that applies to retirement plans. For this reason, the liquidation of the Sunoco stock equivalent funds was completed prior to the closing of the Merger.

In coordination with the elimination of the Sunoco stock equivalent funds in the SunCAP, the SunCoke Energy, Inc. Stock Fund (the “SunCoke Stock Fund”) also was liquidated and removed from SunCAP’s investment lineup. The SunCoke Stock Fund had been added to the SunCAP as an investment option in January 2012, when SunCoke Energy, Inc. was spun off as an independent company from Sunoco. For each active employee, including the NEOs, participating in SunCAP, the liquidation proceeds, from the Sunoco common stock equivalent funds and/or the SunCoke Stock Fund, were invested in accordance with the then-current contribution allocation percentages for such employee, on file with the SunCAP trustee (Vanguard Fiduciary Trust Company), or in certain Qualified Default Investment Alternatives, which were date-specific Vanguard Target Retirement Funds. For terminated employees, liquidation proceeds were invested in the Qualified Default Investment Alternatives.

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The Sunoco, Inc. Savings Restoration Plan was an excess 401(k) benefit plan available during 2012 to employees of Sunoco and its subsidiaries, and our general partner. It was a non-qualified deferred compensation plan available to those SunCAP participants subject to compensation and/or contribution limitations under the Internal Revenue Code (“Code”). Participants were able to contribute amounts in excess of the applicable Code limits, up to five percent of base salary. The amounts of the company match for NEOs in 2012 under the SunCAP and the Savings Restoration Plan are included in the Summary Compensation Table on page 133 under “All Other Compensation” and are further described in the notes accompanying the table. Effective as of December 31, 2012, the Savings Restoration Plan was terminated, amounts outstanding in participant accounts were liquidated, and the participating employees who were affected by the plan terrmination received the cash value of their outstanding account balances from Sunoco.

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The present value of each NEO’s accumulated pension benefit, as of year-end 2012 are included in the Pension Benefits Table on page 139. More detailed descriptions of the Retirement Plan, the Pension Restoration Plan and Executive Retirement Plan are included in the narrative accompanying the table. Consistent with actions taken by employers in other industries, effective June 30, 2010, Sunoco froze pension benefits for all salaried employees, including NEOs, and many non-union employees. This includes any pension benefits that NEOs may have accrued and that are vested under the Executive Retirement Plan. In addition to the freezing of retirement benefits, Sunoco phased out access to post-retirement medical benefits for employees who retire after July 1, 2010.

Other Benefits: Employees of our general partner and its affiliates, including NEOs, participate in a variety of other benefits arrangements, including medical, dental, life insurance, disability insurance, holidays and vacation. These benefits generally are provided on an enterprise-wide basis to employees of the general partner and its affiliates. Executive officers receive the same benefits and are responsible to pay the same premium as other non-represented employees.

Perquisites: In 2012, certain NEOs also received a limited number of personal benefits, or “perquisites.” The dollar amount of the perquisites received by our NEOs is included in the Summary Compensation Table on page 133, under “All Other Compensation.”

Severance and Change-in-Control Benefits: An employee, including an NEO, is an employee at will. This means that our general partner may terminate an employee’s employment at any time, with or without notice, and with or without cause or reason. Upon certain terminations of employment and in the event of a change in control, certain benefits may be paid or provided to our NEOs.

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Executive Involuntary Severance Plan provides certain severance benefits to certain of our general partner’s designated executive officers and other designated key management personnel who are involuntarily terminated other than for just cause, death or disability. In recognition of their past service, the plan is intended to alleviate the financial hardship that may be experienced by certain executives whose employment is terminated, due to circumstances beyond their control. The amount or kind of benefit to be provided is based on the executive’s position and compensation at the time of termination. Depending upon salary level, NEOs would receive severance payments ranging from one to one and one-half times base salary plus their annual individual incentive guideline in effect on the termination date. Eligible executives under the Involuntary Severance Plan are entitled to medical coverage during the applicable severance period, at the same rate that such benefits are provided to active employees. Following the Merger, the Executive Involuntary Severance Plan was amended to provide that the only eligible participants under the Plan are those employees who were eligible to participate on October 5, 2012, the date of the Merger, on which Sunoco merged into a wholly owned subsidiary of ETP.

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Special Executive Severance Plan provides severance benefits in case of termination (whether actual or constructive and other than for just cause, death or disability) occurring within two years after a change of control of the Partnership, as defined in the plan. The plan was adopted to retain key management personnel in the event of a major transaction or change in control, and to eliminate the uncertainty and questions that may arise among management with respect to such transaction, and that may result in the departure or distraction of key management personnel to our detriment and/or to the detriment of our general partner. Under such circumstances, the Board of Directors has determined that appropriate steps should be taken to reinforce and encourage the continued attention and dedication of key management personnel to their assigned duties without distraction and, hence, has adopted the plan. The Board of Directors believes that in the context of a change in control, potential acquirers otherwise may have an incentive to constructively terminate an executive’s employment to avoid paying severance, and it is therefore appropriate to provide severance benefits in this circumstance upon a constructive termination. Severance under this plan is payable in a lump sum, equal to three times annual compensation for the Chief Executive Officer, and two times annual compensation for the other NEOs.

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The Board of Directors believes that the potential severance payments provide an appropriate level of protection to executive officers for the critical period following a change in control at a reasonable cost to us. For these purposes, annual compensation consists of: (i) annual base salary in effect immediately prior to a change in control or immediately prior to the employment termination date, whichever is greater, plus (ii) the greater of the executive’s annual individual incentive guideline in effect immediately before the change in control or employment termination date, or the highest annual incentive awarded in any of the three years ending prior to the change in control, or any subsequent year ending before the employment termination date. Eligible executives under the Special Executive Severance Plan are entitled to medical, dental, vision and life insurance coverage during the applicable severance period, at the same rate that such benefits are provided to active employees. Following the Merger, the Special Executive Severance Plan was amended to provide that the only eligible participants under the Plan are those employees who were eligible to participate on October 5, 2012, the date of the Merger, on which Sunoco merged into a wholly owned subsidiary of ETP.

The Annual Incentive Plan provides that, upon a change in control, as defined in the plan, the participants will receive a pro rata portion of the annual incentive award based on the level of attainment of applicable performance targets at the time of the change in control. The Sunoco Partners LLC Long-Term Incentive Plan provides that, in the event of a qualifying termination following a change in control (as such terms are defined in the plan), all awards of restricted units or unit options automatically vest and become payable or exercisable, as the case may be. Performance-based restricted units that have been outstanding for more than one year will be paid out at the greater of the target amount, or an amount in line with our actual performance immediately prior to the change in control. Those performance-based restricted units that have been outstanding for one year or less will be paid out at the target amount. Additional information regarding these plans can be found under “Other Potential Post-Employment Payments” starting on page 144.

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SUMMARY COMPENSATION TABLE

The Summary Compensation Table reflects the total compensation earned by each NEO in each of 2012, 2011 and 2010 (or such shorter period of time during which such individual served as an executive officer of the general partner):


Name and Principal Position	Year		Salary ($)			Stock Awards⁽¹⁾ ($)			Non-Equity Incentive Plan Compensation⁽²⁾ ($)		Change in Pension Value and Nonqualified Deferred Compensation Earnings⁽³⁾ ($)		All Other Compensation⁽⁴⁾ ($)		Total ($)
M. J. Hennigan⁽⁵⁾		2012		539,716			6,533,065			956,174		0		292,351		8,321,306
President and Chief		2011		488,300			881,954			680,200		589,142		59,536		2,699,132
Executive Officer		2010		296,051	⁽⁷⁾		338,304	⁽⁸⁾		312,883		433,897		22,688		1,403,823

M. Salinas, Jr.		2012		n/a			n/a			n/a		n/a		n/a		—
Chief Financial Officer

K. Shea-Ballay		2012		290,500			212,582			222,775		19,610		22,606		768,073
Vice President, General Counsel & Secretary		2011		264,000			117,307			204,900		23,387		21,629		631,223

L. L. Elsenhans⁽⁶⁾		2012		n/a			n/a			n/a		n/a		n/a		—
Former Chairman and Chief		2011		n/a			364,566			n/a		n/a		n/a		364,566
Executive Officer		2010		n/a			n/a			n/a		n/a		n/a		—

B. P. MacDonald⁽⁶⁾		2012		n/a			n/a			n/a		n/a		n/a		—
Former Vice President and		2011		n/a			91,134			n/a		n/a		n/a		91,134
Chief Financial Officer		2010		n/a			n/a			n/a		n/a		n/a		—

M. J. Colavita⁽⁶⁾		2012		n/a			n/a			n/a		n/a		n/a		—
Former Interim Chief Financial Officer

NOTES TO TABLE:

⁽¹⁾

The amounts shown in this column reflect the aggregate grant date fair value of restricted unit awards under the LTIP, calculated in accordance with US GAAP. See Note 14 to our consolidated financial statements for fiscal 2012, for additional detail regarding assumptions underlying the value of these equity awards. In addition to the awards approved by the Compensation Committee at its regularly scheduled meetings in January 2012, February 2012, January 2011, July 2010, and January 2010, the amounts shown in this column also reflect the grant of time-vesting units to Mr. Hennigan, effective December 5, 2012, pursuant to his offer letter, following the Merger with ETP.

⁽²⁾

The amounts shown in this column reflect annual incentive amounts paid under the Annual Incentive Plan, for performance during 2012, 2011 and 2010, which were payable on or before March 15, 2013, March 15, 2012, and March 14, 2011, respectively. The 2012 annual incentive amounts were earned at 170.4 percent of target.

⁽³⁾

The amounts shown in this column reflect the change in present value for all defined benefit pension plans and supplemental executive retirement plans in which the NEOs participated between December 31, 2011 and December 31, 2012, December 31, 2010 and December 31, 2011, and December 31, 2009 and December 31, 2010, respectively. Pursuant to Mr. Hennigan’s Offer Letter agreement with ETP, in connection with the Merger, he waived any future rights or benefits to which he otherwise would have been entitled under both the Sunoco, Inc. Executive Retirement Plan (“SERP”) and the Sunoco, Inc. Pension Restoration Plan. As a consequence, the year-to-year change in actuarial present value of his pension benefits under the Sunoco, Inc. plans was negative. The applicable disclosure rules require the change in pension value be shown as “$0” if the actual calculation of the change in pension value is less than zero (i.e.,

a decrease). The decrease in pension value for Mr. Hennigan was $2,140,896. NEOs did not have any above-market or preferential payments on deferred compensation during 2012, 2011, or 2010. During 2012,

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certain NEOs had deferred amounts under the Savings Restoration Plan. The earnings received from participation in this plan were the same as quarterly dividends earned on Sunoco common stock (in the case of the Sunoco stock-related funds), and/or are based on the gains/losses of certain mutual funds, calculated in the same manner and at the same rate of earnings as for all other employees invested in those same funds in the SunCAP. Effective as of December 31, 2012, the Savings Restoration Plan was terminated, amounts outstanding in participant accounts were liquidated, and the participating employees who were affected received the cash value of their outstanding account balances, from Sunoco. Mr. Hennigan received payment of his outstanding cash balance at December 31, 2012. The amount shown for Ms. Shea-Ballay reflects her aggregate earnings in the Savings Restoration Plan for 2012. Her outstanding account balance of $5,991 at December 31, 2012 will be paid, including earnings or losses through the payable date, in February 2013.

⁽⁴⁾	The table below shows the components of this column for 2012:

Name

Year

Company
Contribution
Under
Defined
Contribution
Plan^(a)
($)

Cost of
BasicLife
Insurance^(b)
($)

Financial
Counseling^(c)
($)

Perquisites
>$10,000
($)

Amounts Paid
in
Connection
with
Change of
Control, or
Termination of
Employment^(d)
($)

Total
($)

M. J. Hennigan

2012

61,088

990

—

230,273

292,351

M. Salinas, Jr.

2012

n/a

—

n/a

K. Shea-Ballay

2012

22,084

522

n/a

—

22,606

L. L. Elsenhans

2012

n/a

—

n/a

B. P. MacDonald

2012

n/a

—

n/a

M. J. Colavita

2012

n/a

—

n/a

^(a)

During 2012, our general partner was a participating employer in the SunCAP the Savings Restoration Plan, which permitted participants to continue to receive matching contributions after exceeding applicable Code limits allowed under the SunCAP.

^(b)

Basic life insurance coverage is provided to employees of our general partner, including the NEOs. The coverage/premium amount is one times base salary, to a maximum coverage limit of one million dollars. The monthly rate was $0.15 for each $1,000 of base salary from January 1, 2012 through December 31, 2012.

^(c)

In 2006, the NEOs received perquisites including an allowance for financial counseling up to a maximum of $2,500 per year. We value the financial counseling benefit on the amount actually used. This annual financial counseling allowance was discontinued beginning on January 1, 2007, and any unused portion of the 2006 allowance could not be carried forward. However, the NEOs were permitted to continue to use amounts accrued prior to 2005, until such balances are depleted.

^(d)

This amount reflects the payout in cash of Mr. Hennigan’s outstanding account balance in the Savings Restoration Plan at December 31, 2012.

⁽⁵⁾

In connection with the consummation of the Merger, Mr.Hennigan accepted an offer letter from Energy Transfer Partners, L.P., effective as of October 5, 2012, to continue in his current positions as the President and Chief Executive Officer, and a director of our general partner (the “Offer Letter”). The terms of the Offer Letter include the following:

•

Base salary of $550,000, on an annualized basis;

•

Target bonus opportunity at 100% of base salary;

•

Retention of Mr. Hennigan’s right to certain benefits in the event of termination of employment or a change in control of our general partner under the Sunoco Partners LLC Special Executive Severance Plan (the “SESP”) for a period of two-years from the effective time of the Merger. The Offer Letter amended and limited the events giving rise to a “Qualifying Termination” under the SESP;

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•

One-time award, granted as of December 5, 2012, under the LTIP, consisting of 90,000 restricted units and cash distribution rights, vesting incrementally over a five-year period. The first percentage vesting will occur on October 6, 2014 (the “Initial Vesting Date”), and all distributions associated with the award prior to the Initial Vesting Date will be accrued, but not paid, until the Initial Vesting Date;

•

Eligibility, on a discretionary basis, for annual long-term equity incentive awards, consisting of SXL restricted units having a value equal to 200 percent to 300 percent of annual base salary (subject to a five-year graded vesting period);

•

Conversion of the present value ($2,789,413) of certain Sunoco deferred compensation benefits to the Energy Transfer Partners Deferred Compensation Plan for Former Sunoco Executives; and

•

Eligibility to participate in the employee benefit plans, including non-qualified deferred compensation, retirement, health and other welfare benefit plans, offered to similarly situated executives of ETP.

⁽⁶⁾

Ms. Elsenhans and Messrs. Colavita, MacDonald, and Salinas did not receive separate compensation for their services to us as either directors or officers of our general partner during the periods shown in the table. Ms. Elsenhans and Mr. MacDonald received performance-based restricted unit awards under the LTIP in January 2011, the payout of which was further conditioned upon continued service as officers of our general partner through the end of the applicable restriction period on December 31, 2013. During 2012, Ms. Elsenhans and Messrs. Colavita, and MacDonald were employees of Sunoco, and the compensation committee of Sunoco’s Board of Directors determined the components of their compensation, including salary and annual incentive. We had no control over Sunoco’s compensation determination process. Mr. Salinas is employed by the general partner of Energy Transfer Partners, L.P., which determines the components of his compensation, including salary and annual incentive. We have no control over this compensation determination process.

⁽⁷⁾

Mr. Hennigan began his employment with our general partner on May 15, 2009. Prior to that, he was a senior executive at Sunoco. Pursuant to an agreement between Sunoco and us, we paid a portion of Mr. Hennigan’s base salary during 2009 and 2010. The figure in this column for 2010 represents the portion of his salary earned and allocated to us in 2010. Sunoco reimbursed us $157,932 for that portion of Mr. Hennigan’s base salary in excess of this amount. Sunoco no longer pays any portion of Mr. Hennigan’s salary. Beginning in 2011, we paid Mr. Hennigan’s entire base salary.

⁽⁸⁾	During 2010, Sunoco reimbursed us $125,000 in connection with Mr. Hennigan’s 2010 performance based restricted units.

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GRANTS OF PLAN-BASED AWARDS

The following table sets forth the grant of plan-based awards to NEOs in 2012:

Name

Grant Date

Estimated Future Payouts
Under Non-Equity Incentive
Plan Awards⁽¹⁾

Estimated Future Payouts
Under Equity Incentive Plan
Awards⁽²⁾

All
Other
Stock
Awards:
Number
of
Shares
of Stock
or Units
(#)

Grant
date fair
value of
stock and
option
awards⁽³⁾
($)

Threshold
($)

Target
($)

Maximum
($)

Threshold
(#)

Target
(#)

Maximum
(#)

M. J. Hennigan

03-01-2012

—

550,000

1,100,000

President and Chief Executive Officer

03-01-2012

—

35,033

70,066

n/a

1,210,565

03-01-2012

19,535

773,000

12-05-2012

90,000

4,549,500

M. Salinas, Jr.

01-26-2012

—

n/a

Chief Financial Officer

01-26-2012

—

n/a

K. Shea-Ballay

01-26-2012

—

116,200

232,400

Vice President, General Counsel & Secretary

01-26-2012

—

6,152

12,304

n/a

212,582

L. L. Elsenhans

01-26-2012

n/a

Former Chairman and Chief Executive Officer

01-26-2012

—

n/a

B. P. MacDonald

01-26-2012

n/a

Former Vice President and Chief Financial Officer

01-26-2012

—

n/a

M. J. Colavita

01-26-2012

n/a

Former Interim Chief Financial Officer

01-26-2012

—

n/a

NOTES TO TABLE:

⁽¹⁾

This reflects a target and maximum annual incentive award amounts granted under our general partner’s Annual Incentive Plan for each NEO equal to the target percentages set forth above in the section entitled “Elements of Compensation—Annual Incentive Awards—2012 Annual Incentive Payout Amount.” The maximum reflects that the NEO may receive up to 200 percent of the target annual incentive award amount. The annual incentive is paid out in cash, and amounts earned for performance during the 2012 year will be paid out no later than March 15, 2013.

⁽²⁾

The 2012 annual grants of performance-based restricted units were awarded under the LTIP on January 26, 2012. These performance-based restricted units were granted with tandem distribution equivalent rights. Actual payout of these awards will depend upon our achievement of certain specified performance levels, based upon weighted annual objectives for total unitholder return relative to our LTIP peer group and distribution coverage ratio relative to defined goals. The portion of each award that may be earned during the performance period (which runs from January 1, 2012 to December 31, 2013) ranges from a threshold value of zero, to a target value equal to 100 percent of the award, and a maximum value of 200 percent of the award. Payment of amounts earned will occur following the end of the performance period, assuming continued employment with the general partner at such time. See “Other Post-Employment Payments” for a

136

discussion of the treatment of these awards under certain termination events or in the event of a change in control.

⁽³⁾

Reflects the grant date fair value of restricted unit awards granted under the LTIP during fiscal 2012, computed in accordance with US GAAP. During 2012, Mr. Hennigan received time-vesting awards (contingent upon continued employment with our general partner through the end of a specified restriction period) in February 2012, in connection with his appointment as Chief Executive Officer, and again in December 2012, following the Merger with ETP.

⁽⁴⁾	During 2012, Ms. Elsenhans, and Messrs. Colavita, MacDonald and Salinas did not participate in our general partner’s annual cash incentive plan, nor did they receive any LTIP awards.

OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END

The following table provides information concerning the unvested and outstanding equity awards to each current NEO as of December 31, 2012:

Name

Stock Awards

Number of Shares or
Units of Stock That Have
Not Vested
(#)

Market Value of Shares
or Units of Stock That
Have Not Vested⁽¹⁾
($)

Equity Incentive Plan
Awards: Number of
Unearned Shares, Units
or Other Rights That
Have Not Vested⁽²⁾
(#)

Equity Incentive Plan
Awards: Market or
Payout Value of
Unearned Shares,
Units or Other
Rights That Have
Not Vested
($)

M. J. Hennigan

26,967

⁽³⁾⁽⁵⁾

1,341,069

President and Chief Executive Officer

19,535

⁽⁴⁾⁽⁶⁾

971,476

35,033

⁽⁵⁾⁽⁴⁾

1,742,191

90,000

⁽⁶⁾⁽⁶⁾

4,475,700

M. Salinas, Jr.

n/a

⁽⁵⁾

n/a

⁽⁴⁾

n/a

Chief Financial Officer

K. Shea-Ballay

7,290

⁽³⁾⁽⁴⁾

362,532

Vice President, General Counsel & Secretary

6,152

⁽⁵⁾⁽⁴⁾

305,938

L. L. Elsenhans

n/a

⁽⁴⁾

n./a

Former Chairman and Chief Executive Officer

B. P. MacDonald

n/a

⁽⁴⁾

n/a

Former Vice President and

Chief Financial Officer

M. J. Colavita

n/a

⁽⁴⁾

n/a

Former Interim Chief Financial Officer

NOTES TO TABLE:

⁽¹⁾

The market value or payout value of the unearned restricted units assumes a payout at the target of 100 percent, and is equal to the closing price of our common units on December 31, 2012 of $49.73, multiplied by the number of restricted units outstanding. The amounts shown in this column do not include amounts for related distribution equivalents that could be included in the payout.

⁽²⁾

Actual payout of performance-based awards will depend upon our achievement of certain specified performance levels based on defined goals. The portion of each award that may be earned during the performance period ranges from a threshold value of zero, to a target value equal to 100 percent of the award, and a maximum value of 200 percent of the award. Payment of any amounts earned will occur

137

following such period, assuming continued employment with the general partner at such time. See “Other Post-Employment Payments” for a discussion of the treatment of these awards under certain termination events, or in the event of a change in control.

⁽³⁾	Reflects performance-based restricted units awarded January 27, 2011, with a performance period ending on December 31, 2013.

⁽⁴⁾	Reflects time-vesting restricted units awarded February 29, 2012, with a vesting period ending on December 31, 2014.

⁽⁵⁾	Reflects performance-based restricted units awarded January 26, 2012, with a performance period ending on December 31, 2014.

⁽⁶⁾	Reflects time-vesting restricted units awarded December 5, 2012, vesting incrementally over a five-year period ending on December 5, 2017.

OPTION EXERCISES AND STOCK VESTED

The following table provides information concerning the vesting in 2012 of certain restricted units, previously awarded under the LTIP to the NEOs:


Name	Stock Awards
Name	Number of Shares Acquired on Vesting⁽¹⁾ (#)		Value Realized on Vesting⁽²⁾ ($)
M. J. Hennigan		77,485		3,829,309
President and Chief Executive Officer

M. Salinas, Jr.		n/a		n/a
Chief FinancialOfficer

K. Shea-Ballay		n/a		n/a
Vice President, General Counsel & Secretary

L. L. Elsenhans		n/a		n/a
Former Chairman and Chief Executive Officer

B. P. MacDonald		10,527		520,244
Vice President and Chief Financial Officer

M. J. Colavita		n/a		n/a
Former Interim Chief Financial Officer

NOTES TO TABLE:

⁽¹⁾

The amounts shown in this column reflect the acceleration of vesting and payout, in the form of our common units, of LTIP grants as a result of the Merger with ETP on October 5, 2012. Of the amount shown for Mr. Hennigan, 53,947 common units were received as a result of the acceleration of performance-based restricted units, and 23,538 were received from the accelerated vesting of time-vesting units. For the performance-based restricted units, the number of common units to be paid out was determined by multiplying the target number of such restricted units by the applicable performance factor (191%).

⁽²⁾

Value realized on vesting was determined by multiplying the number of common units to be issued upon vesting by the closing market price of our common units on the Merger closing date ($49.42). These amounts do not reflect the value of units withheld by our General Partner to satisfy tax withholding obligations.

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PENSION BENEFITS

Our general partner is a participating employer in certain Sunoco pension and retirement plans, and our NEOs are eligible to participate in such plans. Benefits under these plans are calculated based on cash compensation including both base pay and annual incentives. The table below shows the estimated annual retirement benefits payable to a covered executive based upon the final average pay formulas of the Sunoco, Inc. Retirement Plan (the “SCIRP”), the Sunoco, Inc. Pension Restoration Plan, and the Sunoco, Inc. Executive Retirement Plan (the “SERP”). Executives who participate in these plans may elect to receive their accrued benefits in the form of either a lump sum or an annuity. The estimates shown in the table below assume that benefits are received in the form of a single lump sum at retirement. These estimates do not take into account potential future increases in base salary, or future annual incentives that may be paid. Effective June 30, 2010, Sunoco froze pension benefits for all salaried and many non-union employees. This freeze also applies to the NEOs. Ms. Elsenhans and Messrs. Colavita and MacDonald particpated in these plans as employees of Sunoco. Since we do not reimburse Sunoco for their pension benefits, which are instead paid for by Sunoco, we have not provided any disclosure with regard to the potential retirement benefits for Ms. Elsenhans and Messrs. Colavita and MacDonald.

Name

Plan

Number of
Years Credited
Service⁽¹⁾
(#)

Present
Value of
Accumulated
Benefit
Year-end
2012⁽²⁾
($)

Payments
During
Last
Fiscal
Year
($)

M. J. Hennigan ⁽³⁾

SCIRP (Qualified)

27.93

1,399,326

—

President and Chief Executive Officer

Pension Restoration

27.93

—

SERP

27.93

—

M. Salinas, Jr. ⁽⁴⁾

SCIRP (Qualified)

n/a

Chief Financial Officer

Pension Restoration

n/a

SERP

n/a

K. Shea-Ballay

SCIRP (Qualified)

5.19

161,045

—

Vice President, General Counsel &

Secretary

Pension Restoration

5.19

13,272

—

SERP

5.19

—

L. L. Elsenhans ⁽⁵⁾

SCIRP (Qualified)

n/a

Former Chairman and Chief Executive Officer

Pension Restoration

n/a

SERP

n/a

B. P. MacDonald ⁽⁵⁾

SCIRP (Qualified)

n/a

Former Vice President and Chief Financial Officer

Pension Restoration

n/a

SERP

n/a

M. J. Colavita ⁽⁵⁾

SCIRP (Qualified)

n/a

Former Interim Chief Financial Officer

Pension Restoration

n/a

SERP

n/a

NOTES TO TABLE:

⁽¹⁾	Credited years of service reflect actual service with the general partner, including years of service credited with Sunoco, Inc., prior to employment with our general partner.

⁽²⁾

An actuarial present value of the benefits is calculated by estimating expected future payments starting at an assumed retirement age, weighting the estimated payments by the estimated probability of surviving to each post-retirement age, and discounting weighted payments at an assumed discount rate to reflect the time value of money. The actuarial present value represents an estimate of the amount which, if invested as of December 31, 2012 at a discount rate of 3.50%, would be sufficient on an average basis to provide estimated future payments based on the current accumulated benefit. Estimated future payments are assumed to be in

139

the form of a single lump sum payment at retirement determined using interest rate and mortality table assumptions applicable under current IRS regulations for qualified pension plans. The conversion interest rate[s] assumed for lump sum payments are based on three segment rates under the Pension Protection Act of 2006 and the lump sum mortality table is derived from IRS regulations. In addition, the value of the lump sum payment includes the estimated value of the 50% postretirement death benefit payable, if married, to the spouse of a retired participant under the SERP and Final Average Pay formula benefits described below. It is assumed that 90% of all male members are married and 60% of females are married, with wives assumed to be 3 years younger than husbands. The assumed retirement age for each executive is the earliest age at which the executive could retire without any benefit reduction due to age. For NEOs, the assumed retirement age is 60 (i.e., the earliest age at which the executive could retire without any benefit reduction due to age), or actual age, if older than 60. Actual benefit present values will vary from these estimates depending on many factors, including an executive’s actual retirement age, final service, future compensation levels, interest rate movements and regulatory changes.

⁽³⁾

Pursuant to his Offer Letter agreement with ETP, in connection with the Merger, Mr. Hennigan waived any future rights or benefits to which he otherwise would have been entitled under both the SERP and the Pension Restoration Plan, in return for which, the present value ($2,789,413) of such deferred compensation benefits was credited to the Energy Transfer Partners Deferred Compensation Plan for Former Sunoco Executives.

⁽⁴⁾	Mr. Salinas is employed by ETP’s general partner, and does not participate in any of the Sunoco, Inc. pension benefit plans.

⁽⁵⁾	We do not reimburse Sunoco for the cost of pension benefits for Ms. Elsenhans, or Messrs. Colavita and MacDonald. Their retirement benefits are paid for entirely by Sunoco.

The Sunoco, Inc. Retirement Plan

The Sunoco, Inc. Retirement Plan, or SCIRP, is a qualified defined benefit retirement plan that covers most salaried and many hourly employees, including the NEOs. The SCIRP provides for normal retirement at age 65. The plan includes two benefit formulas:

(1)

Final Average Pay formula

•

The benefit equals 1-²/3 percent of Final Average Pay (the average earnings during the 36 consecutive months of highest earnings in the last ten years prior to retirement, or until June 30, 2010, whichever is sooner) multiplied by the credited service up to 30 years, plus ³/4 percent of Final Average Pay multiplied by the credited service over 30 years.

•

The benefit is then reduced by an amount equal to 1-²/3 percent of the estimated Social Security Primary Insurance amount multiplied by the credited years of service up to a maximum of 30 years.

•

The benefit is further reduced by ⁵/₁₂ percent for each month that retirement precedes age 60 (down to age 55), with the early retirement benefit at age 55 being 75 percent of the unreduced benefit.

(2)

Career Pay (cash balance) formula

•

The retirement benefit is expressed as an account balance, comprised of pay credits and indexing adjustments.

•

Pay credits equal seven percent of pay for the year up to the Social Security (FICA) Wage Base, ($106,800 in 2011,and $110,100 in 2012) plus 12 percent of pay that exceeds the Wage Base for the year.

•

The indexing adjustment equals the account balance at the end of each month multiplied by the monthly change in the All-Urban Consumer Price Index, plus 0.17 percent. However, if in any month the adjustment would be negative, the adjustment would be zero for such month.

140

For employees, including NEOs, hired before January 1, 1987 (Messrs. Hennigan and Colavita), the benefits under SCIRP are the greater of the Final Average Pay or Career Pay formula benefits. An employee may retire at the Normal Retirement Age of 65 regardless of years of service with Sunoco, or may retire as early as age 55 with 10 years of service. All employees hired before January 1, 1987 are 100 percent vested in their benefits. For employees, including NEOs, hired on or after January 1, 1987 (Ms. Elsenhans, Ms. Shea-Ballay and Mr. MacDonald), retirement benefits are calculated under the Career Pay formula only. An employee may retire at the Normal Retirement Age of 65, or may retire as early as age 55 with 10 years of service. An employee hired before January 1, 2008 is 40 percent vested in his or her benefit after completing two years of eligible service, and 100 percent vested after completing three years of eligible service. Employees hired on or after January 1, 2008 are 100 percent vested after three years of eligible service.

The normal form of benefit under the SCIRP is an annuity for the life of the employee, with 50 percent of that annuity paid for the life of the employee’s surviving spouse (50 percent Joint and Survivor Benefit). This 50 percent Joint and Survivor benefit is free for participants who benefit under the Final Average Pay formula, but is reduced actuarially for participants who benefit under the Career Pay formula. Other forms of payment are also offered such as a lump sum and other annuity options. Under the Career Pay formula, the lump sum is equal to the value of the employee’s account, and under the Final Average Pay formula, the lump sum is the actuarial equivalent of the annuity benefit, based on Internal Revenue Service prescribed interest rates and mortality tables.

The SCIRP is subject to qualified plan Code limits on the amount of annual benefit that may be paid, and on the amount of compensation that may be taken into account in calculating retirement benefits, under the plan. For 2010 and 2011, the limit on the compensation that may be used was $245,000. The limit on annual benefits payable for an employee retiring in 2012 was $250,000. Benefits in excess of those permitted under the statutory limits are paid from the Pension Restoration Plan, described below.

The amounts presented in the table above are actuarial present values based on accrued annual benefits, using pay and service through December 31, 2012.

If the benefit is paid in a lump sum, the actual amount distributed would vary depending on the actual interest rate and the mortality assumptions used to calculate the distribution at the time of retirement. The mortality table and interest rates to be used in determining a lump sum are set in accordance with the Pension Protection Act of 2006, or PPA. Under the PPA, the method for computing the lump sum interest rate was completely phased-in for 2012. The estimated amounts above do not take into account future credited service, potential future changes in base salary, the annual guideline incentive opportunity, or future annual incentives that may be paid as a result of Company performance.

Sunoco, Inc. Pension Restoration Plan

The Pension Restoration Plan is a non-qualified plan that provides retirement benefits that would be provided under the SCIRP, but are prohibited from being paid from the SCIRP by the Code limits. See the discussion regarding the SCIRP, above, for the limits. The benefit paid by the Pension Restoration Plan is the excess of the total benefit accrued under the SCIRP over the amount of benefit that the SCIRP is permitted to provide under the Code. All benefits under the Pension Restoration Plan that are paid in a lump sum are calculated using the same actuarial factors applicable under the SCIRP. Payment of benefits is made upon termination of employment, except that payment of amounts subject to Code Section 409A is delayed until six months after separation from service for any specified employee as defined under Code Section 409A. No additional benefits are being accrued under the Pension Restoration Plan with regard to participant accounts in SCIRP following June 30, 2010.

141

Sunoco, Inc. Executive Retirement Plan

The Sunoco, Inc. Executive Retirement Plan, or SERP, is a non-qualified defined benefit plan that may cover certain executive employees, including the NEOs. The SERP may provide pension benefits over and above an NEO’s benefits under SCIRP and the Pension Restoration Plan. All SERP benefits are offset by the SCIRP and the Pension Restoration Plan benefits. NEOs eligible for the SERP and hired before 1987 (Mr. Hennigan) generally will not receive a SERP benefit at retirement, since their SCIRP and Pension Restoration Plan benefits at retirement will equal or exceed their SERP benefits. An NEO must be at least 55 years old with five years of qualifying executive service, to be eligible for a SERP retirement benefit.

Ms. Elsenhans and Messrs. Hennigan and MacDonald were eligible to participate in this program. In connection with her stepping down as Chief Executive Officer and Chairman of Sunoco, Ms. Elsenhans entered into a termination agreement with Sunoco, pursuant to which she received a cash benefit reflecting her level of participation in the SERP. Pursuant to his Offer Letter agreement with ETP, in connection with the Merger, Mr. Hennigan waived any future rights or benefits to which he otherwise would have been entitled under the SERP and the Pension Restoration Plan, in return for which, the present value ($2,789,413) of such deferred compensation benefits was credited to the Energy Transfer Partners Deferred Compensation Plan for Former Sunoco Executives. Mr. MacDonald also entered into a similar arrangement with ETP at that time, except for the waiver of his right to a benefit under the Pension Restoration Plan.

142

NONQUALIFIED DEFERRED COMPENSATION

The following table includes deferred compensation provided to the NEOs in 2012, under the Sunoco, Inc. Savings Restoration Plan (“Savings Restoration Plan”), a nonqualified plan made available to employees who participate in the Sunoco, Inc. Capital Accumulation Plan, or SunCAP, (Sunoco’s 401(k) plan) and who may be subject to Code limits on compensation and/or contributions. Under the Savings Restoration Plan, the participants were able to contribute to an account in excess of the applicable limits. The executive’s contributions and our general partner’s matching contributions were credited to the extent they would be credited under the SunCAP. Ms. Elsenhans and Messrs. Colavita and MacDonald participated in the savings Restoration Plan and in the SunCAP as employees of Sunoco. Since we did not make any matching contributions to either plan on their behalf, nor did we reimburse Sunoco for any other expense relating to their participation in these plans, we have not provided any disclosure with regard to the participation of Ms. Elsenhans and Messrs. Colavita and MacDonald in the Savings Restoration Plan and/or SunCAP. The investment funds available under the Savings Restoration Plan were the same as those available to all employees participating in the SunCAP, and the executive received earnings on those investments, depending on the fund’s performance, calculated in the same manner and at the same rate as for all other employees invested in those funds in the SunCAP. Effective as of December 31, 2012, the Savings Restoration Plan was terminated, amounts outstanding in participant accounts were liquidated, and the affected participating employees received the cash value of their outstanding account balances from Sunoco.

The following table also includes any remaining balances that each NEO has accrued under the annual financial planning allowance that was discontinued beginning on January 1, 2007. NEOs are allowed to use remaining balances accrued prior to 2005, if any.

Name

Source

Executive
Contributions
in 2012
($)

Registrant
Contributions
in 2012⁽¹⁾
($)

Aggregate
Earnings
in 2012⁽²⁾
($)

Aggregate
Withdrawals/
Distributions
($)

Aggregate
Balance at
December 31,
2012
($)

M. J. Hennigan

Savings Restoration Plan

13,750

31,396

32,671

230,273

President and

Financial Counseling ⁽³⁾

2,350

Chief Executive Officer

M. Salinas, Jr.

Savings Restoration Plan

n/a

Chief Financial Officer

K. Shea-Ballay

Savings Restoration Plan

1,199

1,918

377

5,991

Vice President, General

Counsel & Secretary

L. L. Elsenhans

Savings Restoration Plan

n/a

Former Chairman and

Chief Executive Officer

B. P. MacDonald

Savings Restoration Plan

n/a

Vice President and

Chief Financial Officer

M. J. Colavita

Savings Restoration Plan

n/a

Former Interim

Chief Financial Officer

NOTES TO TABLE:

⁽¹⁾	These amounts represent our general partner’s match under the Sunoco, Inc. Savings Restoration Plan (described above), and which are also included in the Summary Compensation Table in the “All Other Compensation” column for this fiscal year.

⁽²⁾

These amounts reflect the net gains (losses) attributable to the investment funds in which the NEOs are deemed to have chosen to invest their contributions and our general partner’s matching contributions under the Savings Restoration Plan, which are based on how their contributions under SunCAP are invested.

143

⁽³⁾	Although the financial counseling allowances were discontinued effective January 1, 2007, the NEOs may use any remaining amounts that were accrued prior to 2005, until the balance has been depleted. This amount reflects the aggregate remaining balance.

OTHER POTENTIAL POST-EMPLOYMENT PAYMENTS

Certain plans, described below, provide for payments of benefits to the NEOs in connection with termination, or separation from employment, retirement, or a change in control of our general partner, or in some cases, Sunoco. The actual amounts paid can be determined only at the time of such NEO’s separation from employment with our general partner. The following describes the benefits that the NEOs would receive if such an event occurred. As current or former employees of Sunoco, Ms. Elsenhans and Messrs. Colavita and MacDonald participate in Sunoco’s corresponding severance and termination plans. To the extent that they participate in such Sunoco plans, they are not eligible to participate in, or to receive benefits from, our general partner’s Special Executive Severance Plan, or Executive Involuntary Termination Plan. Since we did not reimburse Sunoco for any expense relating to the participation of Ms. Elsenhans and Messrs. Colavita and MacDonald in these Sunoco plans, and since they are not currently eligible to participate in our corresponding plans, we have not provided any disclosure with regard to potential benefits payable to Ms. Elsenhans and Messrs. Colavita and MacDonald under the general partner’s Special Executive Severance Plan, or Executive Involuntary Termination Plan. Mr. Salinas is employed by the general partner of Energy Transfer Partners, L.P., and he does not participate in participate in the retirement, severance, or termination plans either of Sunoco, or of our general partner.

•

Retirement: The benefits paid to the NEOs upon retirement are described above, on pages 139 to 142.

•

Voluntary Termination: An NEO who resigns and leaves voluntarily, would receive the following benefits:

•

Sunoco, Inc. Retirement Plan (the “SCIRP”) and Pension Restoration Plan: Retirement eligible NEOs hired prior to January 1, 1987 (Messrs. Colavita and Hennigan) would receive benefits based upon the Final Average Pay formula of the SCIRP, which is a qualified defined benefit retirement plan. Effective January 1, 1987, for employees hired subsequent to that date, the SCIRP was converted from a final average pay plan to a cash balance pension plan. SCIRP benefits for NEOs hired after this conversion (Ms. Elsenhans, Ms. Shea-Ballay and Mr. MacDonald) are calculated using the Career Pay formula, based on a percentage of pay each year and an indexing adjustment. Normal retirement age under the SCIRP is 65 years. To the extent that the amount payable exceeds the maximum amount that may be paid under the SCIRP, the remaining amount would be paid under the Pension Restoration Plan. Effective June 30, 2010, Sunoco froze pension benefits for all salaried and many non-union employees. This freeze also applies to the NEOs.

•

Sunoco, Inc. Executive Retirement Plan (the “SERP”): The SERP provides pension benefits over and above benefits that may be paid under the SCIRP to participants who are at least 55 years of age, with a minimum of five years service as an executive. SERP benefits are offset by benefits payable under other qualified or non-qualified plans of Sunoco, Inc. The maximum benefit payable under any SERP formula cannot exceed 50 percent of final average earnings.

•

Sunoco Partners LLC Long-Term Incentive Plan (the “LTIP”): Under the LTIP, if an NEO is not retirement eligible, outstanding performance-based restricted units would be cancelled as of the termination date. If an NEO is eligible for retirement, unvested restricted units would continue to vest, and would pay out, along with the accompanying distribution equivalent rights, if the performance measures are met.

•

Sunoco Partners LLC Annual Incentive Plan: If an NEO voluntarily terminates employment prior to December 31 of the plan year, other than by retirement, he or she would not receive any incentive award for that year.

•

Vacation Benefits: Each NEO would be entitled to receive payment for his or her accrued vacation, which benefit is generally provided to active employees of the Partnership’s general partner.

144

•

Involuntary Termination—For Cause: An NEO who is terminated for cause would receive the following:

•

SCIRP/SERP: Benefits accrued under the SCRIP, SERP and Pension Restoration Plans would be paid according to the terms of those plans applicable to terminated or retirement eligible employees, as described in the Voluntary Termination section above.

•

LTIP: Under the LTIP, if an NEO is not retirement eligible, outstanding performance-based restricted units would be cancelled as of the termination date.

•

Sunoco Partners LLC Annual Incentive Plan: Any annual incentive award for that year would be forfeited.

•

Vacation Benefits: Each NEO would receive payment for his or her accrued vacation, which benefit is generally provided to active employees of the Partnership’s general partner.

•

Involuntary Termination—Not for Cause:

•

Sunoco Partners LLC Executive Involuntary Severance Plan (“Involuntary Severance Plan”): Executives whose employment is terminated by the Partnership’s general partner, other than for just cause, or as a result of death or disability, receive a severance allowance under the Involuntary Severance Plan. The plan is available to the general partner’s NEOs and certain other executive level employees. However, any NEO receiving benefits under the SERP would not also be eligible to receive benefits under this plan. Following the Merger of Sunoco with ETP, the Executive Involuntary Severance Plan was amended to provide that the only eligible participants under the Plan are those employees who were eligible to participate on October 5, 2012, the date of the Merger, on which Sunoco merged into a wholly owned subsidiary of ETP. The following is a summary of the benefits available under this plan:

•

In the case of the Chief Executive Officer, and the President and Chief Operating Officer, severance payments would be for a period of and equal to 78 weeks of base salary plus the annual individual guideline incentive amount, in effect on the termination date, as defined in the plan.

•

Other NEOs would receive severance payments for a period of and equal to 52 weeks of base salary plus the annual individual guideline incentive amount, in effect on the termination date, as defined in the plan.

•

Each NEO would be entitled to medical coverage for up to the period of severance received, at the same rate that such benefits are generally provided to active employees.

•

NEOs would receive a cash amount in lump sum equal to the NEO’s accrued but unused vacation through the end of his or her employment termination date as defined in the plan.

•

SCIRP: NEOs hired prior to January 1, 1987 (Messrs. Colavita and Hennigan) would receive benefits based upon the Final Average Pay formula of the SCIRP. SCIRP benefits for NEOs hired after the January 1, 1987 conversion of SCIRP from a final average pay plan to a cash balance pension plan (Ms. Elsenhans, Ms. Shea-Ballay and Mr. MacDonald), are calculated using the Career Pay formula. To the extent that the amount payable exceeds the amount available under the SCIRP, the remaining amount would be paid under the Pension Restoration Plan.

•

SERP: SERP benefits are offset by benefits payable under the SCIRP and Pension Restoration Plan. Under the terms of the SERP, Ms. Elsenhans and Messrs. Hennigan and MacDonald are eligible to receive benefits under this plan.

•

Involuntary Termination—Change of Control

•

Sunoco Partners LLC Special Executive Severance Plan: This plan was adopted to retain executives in the event of a change of control, and to eliminate the distraction and uncertainty such a transaction may create among management personnel, to the detriment of the organization. Following the Merger, the Special Executive Severance Plan was amended to provide that the only eligible participants under the Plan are those employees who were eligible to participate on October 5, 2012, the date of the Merger,

145

on which Sunoco merged into a wholly owned subsidiary of ETP. Payment of severance benefits under this plan provides severance allowances to executives whose employment is terminated in connection with, or following, a change of control. A “change of control” is defined as any one or more of the following events:

•

a transaction pursuant to which more than 50 percent of the combined voting power of the outstanding equity interests in the general partner cease to be owned by Sunoco, Inc. and its affiliates;

•

a “Change in Control” of Sunoco, Inc., as defined from time to time in the Sunoco, Inc. stock plans; or

•

the general partner of the Partnership ceases to be an affiliate of Sunoco.

There is a “double trigger” mechanism for the payment of severance benefits under this plan, requiring both a change of control and a qualifying termination of employment (as defined in the plan) following such change of control to trigger payment. Severance benefits under this plan are paid in a lump sum equal to three times annual compensation for the CEO, and two times annual compensation for the other NEOs. For these purposes, annual compensation consists of:

•

the executive’s annual base salary in effect immediately prior to a change of control or immediately prior to the employment termination date, whichever is greater, plus

•

the greater of 100 percent of the executive’s annual incentive guideline in effect immediately before the change of control or employment termination date.

Each eligible NEO would be entitled to medical, dental, vision and life insurance coverage for the period of severance received, at the same rate that such benefits are generally provided to active employees of the general partner. In the case of a change of control, the plan also provides for the protection of certain pension benefits and reimbursement for any additional tax liability incurred as a result of excise taxes imposed on payments deemed to be attributable to the change in control.

•

SCIRP: In the event of a change of control, the benefits of a participant whose employment began before September 5, 2001, and who is terminated (as defined in the plan) following a change in control, become 100 percent vested and are increased as follows:

•

Final Average Pay formula. A participant’s service is increased by three years, subject to reduction for service after the change in control. Final Average Pay will be the greater of : (A) the regularly determined Final Average Pay, (B) Final Average Pay based on earnings of the full month preceding the change in control, or (C) Final Average Pay based on earnings for the month preceding the termination of employment. For purposes of (B) and (C) monthly earnings will include base pay and ¹/₁₂ of the unadjusted annual guideline annual incentive under the Sunoco Partners LLC Annual Incentive Plan.

•

Career Pay (cash balance) formula. A participant’s service is increased by three years, subject to reduction for service after the change in control. In the month of termination, a participant’s Career Pay Earnings are increased by an amount equal to 36 months less the number of months worked after the Change in Control, times the greater of Career Pay Earnings for: (A) the month preceding termination or (B) the month preceding the change in control. For purposes of (A) and (B) monthly earnings will include base pay and ¹/₁₂ of the annual guideline annual incentive under the Sunoco Partners LLC Annual Incentive Plan.

•

SERP: Under the SERP, after a change of control and qualifying termination (as defined in the plan) (a “double trigger”), a participant becomes 100 percent vested in his SERP benefit. The following provisions also apply:

•

A participant’s service is increased by three years, subject to reduction for service following the change in control.

146

•

Final average pay at termination is no less than final average pay at the time of the change in control. In the case of a participant under age 55 at the time of termination, the change in control benefit will equal the benefit that would have been paid at age 55.

•

The benefit will be paid in a lump sum six months after separation from service with Sunoco pursuant to Code Section 409A.

•

Change of Control—Regardless of Termination

•

Sunoco Partners LLC Annual Incentive Plan: If a change of control occurs, (a “single trigger”) an NEO would receive a pro rata portion of the annual incentive based on level of attainment of applicable performance targets.

•

LTIP: If a change of control occurs, there is a “double trigger” mechanism, requiring both a change of control and a qualifying termination of employment (as defined in the plan) following such change of control, to trigger the payment of outstanding restricted units and accompanying distribution equivalent rights. Restricted units that have been outstanding for more than one year will be paid out at the greater of target or in amount in line with actual performance results. Restricted units that have been outstanding for less than one year will be paid out at target. Retention-based units will be paid out at as awarded. Restricted units may be paid out in cash, or in common units, as determined by our general partner’s Compensation Committee.

•

Death: In the case of death, an NEO’s beneficiary(ies) or estate would receive the following benefits:

•

Insurance:

•

Life insurance benefits equal to one times base compensation up to a maximum of $1 million plus any supplemental life insurance elected and paid for by the NEO.

•

Travel Accident insurance in the amount of three times base compensation (up to a maximum of $3 million) would be payable in the event of accidental death while traveling on company business.

•

An Occupational Death benefit in the amount of $250,000 would be payable in the event of accidental death on the company’s premises in the course of his job; however, the Occupational Death Plan does not pay benefits if there is a Travel Accident benefit of three times base compensation.

•

If the NEO is married, medical coverage would be available to his or her spouse on the same basis as other married employees, i.e., if retirement eligible at death, coverage would be available to his or her spouse on the same basis as other retirement eligible employees. If not retirement eligible, coverage would be available for a period equal to the time he or she was employed by the generalpartner or until the spouse reached age 65, if earlier.

•

SCIRP:

•

With respect to an NEO who is eligible for Final Average Pay formula benefits under SCIRP (Messrs. Colavita and Hennigan), his or her spouse would receive the greater of: (A) 50 percent of the benefit under the Final Average Pay formula, or (B) 100 percent of the benefit accrued under the Career Earnings Formula. A non-married NEO’s beneficiary(ies) or estate would receive 100 percent of the benefit accrued under the Career Earnings Formula. This benefit is the same for all similarly situated employees.

•

With respect to an NEO that is eligible for Career Pay Formula benefits only under SCIRP (Ms. Elsenhans, Ms. Shea-Ballay and Mr. MacDonald), a married or non-married NEO’s spouse, beneficiary(ies) or estate would receive 100 percent of the benefit accrued under the Career Earnings Formula. This benefit is the same for all similarly situated employees.

•

For all NEOs, to the extent that the amount payable under SCIRP exceeds the amount available due to IRS limits, the remaining amount would be paid under the Pension Restoration Plan at the employee’s death.

147

•

SERP: Under the SERP, a married NEO’s spouse would receive 50 percent of any benefit payable under the plan.

•

Sunoco Partners LLC Annual Incentive Plan: A prorated annual incentive based on date of death would be payable to the NEO’s beneficiary(ies) or estate.

•

LTIP: Under the LTIP all unvested restricted units would continue to vest, and, along with the accompanying distribution equivalent rights, would pay out at the end of the respective performance periods to the NEO’s beneficiary(ies) or estate if the applicable performance measures are met.

•

Disability: In the case of a termination of employment due to disability, an NEO would be eligible for the following benefits:

•

SCIRP/SERP: An NEO would continue to accrue benefits under SCIRP and SERP until normal retirement date or later, according to the terms of those plans.

•

Medical and Life Insurance: Medical and life insurance coverage would be available to the NEO on the same basis as to other disabled employees.

•

Long Term Disability: An NEO would receive benefits, including Social Security, up to 60 percent of total annual compensation or $25,000 per month, whichever is less, under Sunoco Inc.’s long-term disability plan.

•

Sunoco Partners LLC Annual Incentive Plan: An NEO would receive a pro rata portion of the annual incentive for the period from the start of the plan year to the date of permanent disability.

•

LTIP: Under the LTIP all unvested restricted units would continue to vest, and along with the accompanying distribution equivalent rights, will pay out at the end of the respective performance periods if the applicable performance measures are met.

Except for Ms. Elsenhans and Messrs. Colavita, MacDonald and Salinas (as explained above), the tables on the following pages reflect the estimated potential compensation and benefits for the NEOs under various scenarios involving a termination of employment. These amounts are estimates of the amounts that would be paid to the NEOs and the actual amounts paid can only be determined at the time of a named executive officer’s termination of employment. These estimates are based on the following assumptions:

•

the applicable provisions in the agreements and arrangements governing the NEOs’ benefits and payment which are summarized in the “Other Potential Post-Employment Payments” section on pages 144 to 155;

•

the triggering event occurred on December 31, 2012 (except for NEOs such as Ms. Elsenhans, who exited during 2012);

•

the transaction price per Partnership unit is $49.73, which was the price at the close on December 30, 2012;

•

pension lump-sum values are based on applicable segment interest rates under the Pension Protection Act of 2006;

•

health and welfare benefits are included, where applicable, at the estimated value of the continuation of these benefits; and

•

Executives become 100 percent vested in his or her SERP benefit and additional service is credited through the applicable Benefit Extension period.

•

each NEO has exhausted all available vacation benefits as of December 31, 2012.

148

Sunoco Logistics Partners L.P.

Other Potential Post-Employment Payments as of December 31, 2012

Michael J. Hennigan

President and Chief Operating Officer


Type of Benefit	Voluntary Termination ($)		Death ($)		Disability ($)		Termination for Cause ($)		Involuntary Termination Not for Cause ($)		Change in Control ($)
Cash Severance
Base Salary⁽¹⁾		0		0		0		0		825,000		1,650,000
Annual Incentive⁽²⁾		0		0		0		0		907,500		1,815,000

Total Cash Severance		0		0		0		0		1,732,500		3,465,000

Additional Pension Benefits⁽³⁾		0		0		0		0		0		123,033

Unit Ownership⁽⁴⁾⁽⁵⁾
Performance-Based RSU (2011-2013)⁽⁶⁾		0		1,433,983		1,433,983		0		1,433,983		2,867,967
Performance-Based RSU (2012-2014)⁽⁶⁾		0		1,791,780		1,791,780		0		1,791,780		1,791,780
Time-Vested RSUs⁽⁶⁾		0		5,474,827		5,474,827		0		5,474,827		5,474,827

Total Unit Ownership		0		8,700,590		8,700,590		0		8,700,590		10,134,574

Other Benefits
Outplacement⁽⁷⁾		0		0		0		0		25,000		25,000
Health & Welfare⁽⁸⁾		0		0		0		0		150,000		150,000

Total Other Benefits		0		0		0		0		175,000		175,000

TOTAL		0		8,700,590		8,700,590		0		10,608,090		13,897,607

NOTES TO TABLE

⁽¹⁾	Consists of 3.0 x multiple of the base salary prior to the Change in Control. Upon involuntary termination not for cause, consists of 78 weeks of base salary in effect on the termination date.

⁽²⁾	Consists of 3.0 x multiple of the target bonus prior to the Change in Control. Upon involuntary termination not for cause, consists of 78 weeks of target bonus in effect on the termination date.

⁽³⁾

Pursuant to his October 4, 2012 Offer Letter agreement with ETP, in connection with the Merger, Mr. Hennigan waived any future rights or benefits to which he otherwise would have been entitled under both the SERP and the Pension Restoration Plan (both non-qualified plans). Value shown in the table reflects additional qualified pension benefits.

⁽⁴⁾	Reflects intrinsic values of accelerated vesting of equity awards at an assumed closing price of $49.73 (closing price of Sunoco Logistics Partners L.P., on December 31, 2012). Values include unvested/unearned distribution equivalent rights of accelerated vesting of unit ownership.

⁽⁵⁾

Pursuant to the terms of a letter agreement with Mr. Hennigan, dated November 2, 2011, in the event of his involuntary termination not for cause, Mr. Hennigan’s time-vested RSUs will continue to vest and pay out, and his performance-based RSUs will be treated as described below for a Change in Control event.

⁽⁶⁾

Upon a Change in Control, performance-based RSUs outstanding more than twelve months from the grant date are paid out at the greater of target or actual performance immediately prior to the Change in Control. The estimated payout for the 2011 and 2012 performance cycles would have been 200% of target based on Total Return results (payout percentage does not reflect Cash Distribution Growth performance). Performance-based RSUs outstanding less than twelve months from the grant date prior to a Change in Control, are not adjusted for any performance factors. Under death, disability and retirement, outstanding

149

performance-based restricted units would continue to the end of the performance period, and payment, if any, would be based as though the participant had continued to be employed through the end of the performance period. Assumed to be paid at target under these scenarios.

⁽⁷⁾	Reimbursement for outplacement services ($25,000) as provided by our general partner.

⁽⁸⁾	Pursuant to the terms of a November 2, 2011 letter agreement, Mr. Hennigan will receive a lump sum payment of $150,000 in lieu of our general partner’s regular subsidy for post-employment benefits.

150

Sunoco Logistics Partners L.P.

Other Potential Post-Employment Payments as of December 31, 2012

Martin Salinas, Jr. ⁽¹⁾

Chief Financial Officer


Type of Benefit	Voluntary Termination ($)		Death ($)		Disability ($)		Termination for Cause ($)		Involuntary Termination Not for Cause ($)		Change in Control ($)
Cash Severance
Base Salary		0		0		0		0		0		0
Annual Incentive		0		0		0		0		0		0

Total Cash Severance		0		0		0		0		0		0

Additional Pension Benefits		0		0		0		0		0		0

Unit Ownership ⁽²⁾
Performance-Based RSU (2011-2013)		0		0		0		0		0		0
Performance-Based RSU (2012-2014)		0		0		0		0		0		0
Time-Vested RSUs		0		0		0		0		0		0

Total Unit Ownership		0		0		0		0		0		0

Other Benefits
Outplacement		0		0		0		0		0		0
Health & Welfare		0		0		0		0		0		0

Total Other Benefits		0		0		0		0		0		0

TOTAL		0		0		0		0		0		0

NOTES TO TABLE

⁽¹⁾	Mr. Salinas does not participate in the retirement, termination, or severance plans of Sunoco Partners LLC.

⁽²⁾	Mr. Salinas did not receive any Sunoco Logistics Partners L.P. equity during 2012.

151

Sunoco Logistics Partners L.P.

Other Potential Post-Employment Payments as of December 31, 2012

Kathleen Shea-Ballay

Vice President, General Counsel and Secretary


Type of Benefit	Voluntary Termination ($)		Death ($)		Disability ($)		Termination for Cause ($)		Involuntary Termination Not for Cause ($)		Change in Control ($)
Cash Severance
Base Salary⁽¹⁾		0		0		0		0		290,500		581,000
Annual Incentive⁽²⁾		0		0		0		0		130,725		261,450

Total Cash Severance		0		0		0		0		421,225		842,450

Additional Pension Benefits		0		0		0		0		0		95,589

Unit Ownership⁽³⁾
Performance-Based RSU (2011-2013)⁽⁴⁾		0		387,649		387,649		0		0		775,299
Performance-Based RSU (2012-2014)⁽⁴⁾		0		317,231		317,231		0		0		317,231
Time-Vested RSUs		0		0		0		0		0		0

Total Unit Ownership		0		704,880		704,880		0		0		1,092,530

Other Benefits
Outplacement⁽⁵⁾		0		0		0		0		25,000		25,000
Health & Welfare⁽⁶⁾		0		0		0		0		13,560		13,560

Total Other Benefits		0		0		0		0		38,560		38,560

TOTAL		0		704,880		704,880		0		459,785		2,069,129

NOTES TO TABLE

⁽¹⁾	Consists of 2.0 x multiple of the base salary prior to the Change in Control. Upon involuntary termination not for cause, consists of 52 weeks of base salary in effect on the termination date.

⁽²⁾	Consists of 2.0 x multiple of the target bonus prior to the Change in Control. Upon involuntary termination not for cause, consists of 52 weeks of target bonus in effect on the termination date.

⁽³⁾	Reflects intrinsic values of accelerated vesting of equity awards at an assumed closing price of $49.73 (closing price of Sunoco Logistics Partners L.P., on December 31, 2012). Values include unvested/unearned distribution equivalent rights of accelerated vesting of unit ownership.

⁽⁴⁾

Upon a Change in Control, performance-based restricted units outstanding more than twelve months from the grant date are paid out at the greater of target or actual performance immediately prior to the Change in Control. The estimated payout for the 2011 and 2012 performance cycles would have been 200% of target based on Total Return results (payout percentage does not reflect Cash Distribution Growth performance). Performance-based restricted units outstanding less than twelve months from the grant date prior to a Change in Control, are not adjusted for any performance factors. Under death, disability and retirement, outstanding performance-based restricted units would continue to the end of the performance period, and payment, if any, would be based as though the participant had continued to be employed through the end of the performance period. Assumed to be paid at target under these scenarios.

⁽⁵⁾	Reimbursement for outplacement services ($25,000) as provided by our general partner.

⁽⁶⁾	Health & Welfare and life insurance coverage during the severance period (52 weeks). Annual medical costs provided by our general partner. Dental coverage is not provided upon involuntary termination not for cause.

152

Sunoco Logistics Partners L.P.

Other Potential Post-Employment Payments as of December 31, 2012

Lynn L. Elsenhans⁽¹⁾

Former Chairman, President and Chief Executive Officer


Type of Benefit	Involuntary Termination Not for Cause ⁽¹⁾ ($)
Cash Severance
Base Salary		0
Annual Incentive		0

Total Cash Severance		0

Additional Pension Benefits		0

Unit Ownership
Performance-Based RSU (2011-2013) ⁽²⁾		1,261,664
Performance-Based RSU (2012-2014)		0
Time-Vested RSUs		0

Total Unit Ownership		1,261,664

Other Benefits
Outplacement		0
Health & Welfare		0

Total Other Benefits		0

TOTAL		1,261,664

NOTES TO TABLE

⁽¹⁾

On February 2, 2012, the Partnership announced that, effective March 1, 2012, Lynn L. Elsenhans was stepping down as Chief Executive Officer of Sunoco Partners LLC, the Partnership’s general partner. Effective May 3, 2012, Ms. Elsenhans also stepped down as a director and Chairman of the Board of Directors of the Partnership’s general partner. Ms. Elsenhans was not eligible for additional severance benefits under the Sunoco Partners LLC Special Executive Severance Plan, due to her participation in the Sunoco, Inc. Special Executive Severance Plan. In Ms. Elsenhans’ case, since the triggering event has actually occurred, and she was not serving as a named executive officer of at the end of the last completed fiscal year (December 31, 2012), the table reflects only the disclosure required for the actual triggering event.

⁽²⁾

In accordance with Ms. Elsenhans’ April 29, 2012 termination agreement, the 36,819 performance-based restricted units vested and were paid out 30 days following her resignation date. The amount shown in the table reflects the value of such vested units at a closing price of $32.63 on June 4, 2012. This value includes distribution equivalent rights related to the accelerated vesting of unit ownership.

153

Sunoco Logistics Partners L.P.

Other Potential Post-Employment Payments as of December 31, 2012

Brian P. MacDonald ⁽¹⁾

Former Vice President and Chief Financial Officer


Type of Benefit	Voluntary Termination ($)		Death ($)		Disability ($)		Termination for Cause ($)		Involuntary Termination Not for Cause ($)		Change in Control⁽²⁾ ($)
Cash Severance
Base Salary		0		0		0		0		0		0
Annual Incentive		0		0		0		0		0		0

Total Cash Severance		0		0		0		0		0		0

Additional Pension Benefits		0		0		0		0		0		0

Unit Ownership ⁽³⁾
Performance-Based RSU (2011-2013)		0		0		0		0		0		967,186
Performance-Based RSU (2012-2014)		0		0		0		0		0		0
Time-Vested RSUs		0		0		0		0		0		0

Total Unit Ownership		0		0		0		0		0		967,186

Other Benefits
Outplacement		0		0		0		0		0		0
Health & Welfare		0		0		0		0		0		0
Total Other Benefits		0		0		0		0		0		0

TOTAL		0		0		0		0		0		967,186

NOTES TO TABLE

⁽¹⁾

Mr. MacDonald is not eligible for additional severance benefits under the Sunoco Partners LLC Special Executive Severance Plan, due to his participation in the Sunoco, Inc. Special Executive Severance Plan. Mr. MacDonald served as Vice President and Chief Financial Officer of the Partnership’s general partner until March 1, 2012. Mr. MacDonald currently is an officer of ETP Holdco Corp., an ETP affiliate.

⁽²⁾	The Merger of Sunoco, Inc. with ETP was completed on October 5, 2012. The vesting of Mr. MacDonald’s performance-based restricted units was accelerated in connection with the Merger, and these units were paid out on October 4, 2012.

(3)	Reflects intrinsic value of vested performance-based restricted units at a closing price of $49.49 on October 4, 2012. This value includes distribution equivalent rights related to accelerated vesting of unit ownership.

154

Sunoco Logistics Partners L.P.

Other Potential Post-Employment Payments as of December 31, 2012

Michael J. Colavita ⁽¹⁾

Former Interim Chief Financial Officer


Type of Benefit	Voluntary Termination ($)		Death ($)		Disability ($)		Termination for Cause ($)		Involuntary Termination Not for Cause ($)		Change in Control ($)
Cash Severance
Base Salary		0		0		0		0		0		0
Annual Incentive		0		0		0		0		0		0

Total Cash Severance		0		0		0		0		0		0

Additional Pension Benefits		0		0		0		0		0		0

Unit Ownership ⁽²⁾
Performance-Based RSU (2011-2013)		0		0		0		0		0		0
Performance-Based RSU (2012-2014)		0		0		0		0		0		0
Time-Vested RSUs		0		0		0		0		0		0

Total Unit Ownership		0		0		0		0		0		0

Other Benefits
Outplacement		0		0		0		0		0		0
Health & Welfare		0		0		0		0		0		0

Total Other Benefits		0		0		0		0		0		0

TOTAL		0		0		0		0		0		0

NOTES TO TABLE

⁽¹⁾	Mr. Colavita was not eligible for additional severance benefits under the Sunoco Partners LLC Special Executive Severance Plan due to being a participant in the Sunoco, Inc. Special Executive Severance Plan.

⁽²⁾	Mr. Colavita has not received any Sunoco Logistics Partners L.P. equity.

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DIRECTOR COMPENSATION

Compensation Philosophy: The Board of Directors believes that the compensation program for independent directors should be designed to attract experienced and highly qualified individuals; provide appropriate compensation for their commitment and contributions to us and our unitholders; and align the interests of the independent directors and unitholders. The Board of Directors may engage a third-party compensation consultant to benchmark director compensation against other pipeline companies, and general industry, and to provide advice regarding “best practices” and trends in director compensation. Independent directors are compensated partly in cash and partly in restricted units, representing limited partnership interests in us. Currently, directors who are also employees of our general partner, or its affiliates, receive no additional compensation for service on the general partner’s Board of Directors or any committees of the Board. As such, they are not included in the narrative or tabular disclosures below.

Each independent director is reimbursed for out-of-pocket expenses in connection with attending meetings of the Board of Directors or committees, including room, meals and transportation to and from the meetings. When traveling on Partnership business, a director occasionally may be accompanied by a spouse. At times, a director may travel to and from Board of Directors and/or committee meetings on corporate aircraft. Directors also may be reimbursed for attendance at qualified third-party director education programs.

Each director will be indemnified fully by us for actions associated with being a member of our general partner’s Board of Directors, to the extent permitted under applicable state law.

Current Director Compensation Program: Following the consummation of the Merger of Sunoco with Energy Transfer Partners, L.P., our general partner approved a new program of compensation for non-employee directors, which consists of an annual cash retainer and equity award for all directors, chair retainers for the Audit Committee and Compensation Committee, annual cash retainers for members of the Audit, Compensation and Conflicts Committees, and per meeting fees for all directors. This new director compensation program will become effective during the 2013 calendar year. Messrs. Anderson, Angelle, and Bray received no compensation under this new program during 2012.

Director Compensation Program Prior to the Merger with ETP: Prior to the consummation, on October 5, 2012, of the Merger of Sunoco with Energy Transfer Partners, L.P., each non-employee director of our general partner received an annual retainer of $66,000 in cash, paid quarterly, and a number of restricted units, granted quarterly, under the Sunoco Partners LLC Long-Term Incentive Plan. These restricted units had an aggregate fair market value equal to $44,000 on an annual basis (the fair market value of each quarterly payment of restricted units was calculated as of the payment date). These restricted units were required to be deferred, and were credited to each independent director’s mandatory deferred compensation account under the Directors’ Deferred Compensation Plan. Amounts deferred in the form of restricted units were treated as if invested in common units of the Partnership, and included a credit for distribution equivalent rights (in the form of additional restricted units), credited on the applicable date(s) for Partnership cash distributions. In addition, the committee chairs of the Board of Directors also received the following supplemental annual retainers (payable in quarterly installments):

•

the chair of the Audit Committee received an annual committee chair retainer of $6,000 in cash;

•

the chair of the Conflicts Committee received an annual chair retainer of $2,000 in cash;

•

the chair of the Compensation Committee received an annual chair retainer of $3,500 in cash;

•

the “presiding director,” appointed to chair meetings of the independent directors of the Board, received an annual retainer of $5,000

In connection with the Merger, all of our general partner’s directors (except for Mr. Hennigan) resigned from the Board effective October 5, 2012, and were replaced with the current slate of directors. Since the Merger, the Directors’ Deferred Compensation Plan was terminated in January 2013, and the former directors’ deferred compensation accounts thereunder were liquidated and paid out in cash as a consequence of their termination of Board service in connection with the Merger.

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The following table reflects the compensation earned by each of the former non-employee directors of our general partner prior to October 2012:


Name	Fees Earned or Paid in Cash⁽¹⁾ ($)		Stock Awards⁽²⁾ ($)		All Other Compensation⁽³⁾ ($)		Total ($)
L.W. Berry, Jr. ⁽⁴⁾		49,500		n/a		1,327,991		1,377,491
Former Independent Director

S.L. Cropper		54,750		n/a		989,838		1,044,588
Former Independent Director

W. H. Easter, III		43,849		n/a		35,617		79,466
Former Independent Director

G. W. Edwards		43,849		n/a		35,617		79,466
Former Independent Director

P.L. Frederickson ⁽⁵⁾		52,125		n/a		572,513		624,638
Former Independent Director

W. R. Silver		n/a		n/a		372,219		372,219
Former Independent Director

NOTES TO TABLE:

⁽¹⁾	The amounts shown in this column reflect the gross cash payments of applicable retainers and fees received by directors during 2012

⁽²⁾	The annual retainer in the form of restricted units (automatically deferred, in accordance with terms of the Sunoco Partners LLC Directors’ Deferred Compensation Plan), was converted to cash and paid out following the Merger.

⁽³⁾	Amounts shown in this column reflect the liquidation and gross cash payout of each director’s outstanding deferred compensation account balance following the Merger with ETP, and related termination of Board service.

⁽⁴⁾

Mr. Berry made an election to defer, for six months following a change of control, the accelerated payout of certain of the restricted units in his deferred compensation account. At December 31, 2012, there were 4,499 restricted units subject to this deferral election in Mr. Berry’s account. These units will be paid out in cash in April 2013, at a value equal to the aggregate average trading price for a like number of the Partnership’s common units during the ten-day period immediately preceding the payout.

⁽⁵⁾

Mr. Frederickson made an election to defer, for six months following a change of control, the accelerated payout of certain of the restricted units in his deferred compensation account. At December 31, 2012, there were 3,035 restricted units subject to this deferral election in Mr. Frederickson’s account. These units will be paid out in cash in April 2013, at a value equal to the aggregate average trading price for a like number of the Partnership’s common units during the ten-day period immediately preceding the payout.

COMPENSATION PRACTICES AS THEY RELATE TO RISK MANAGEMENT

The Compensation Committee has oversight responsibility to ensure that our incentive compensation programs do not incentivize or encourage excessive or unnecessary risk-taking/wrong behavior. The following is a description of the compensation risk assessment process, as well as a description of our compensation risk mitigation techniques.

An executive’s compensation package includes a mix of base salary, cash-based short-term incentives, and equity-based long-term incentives. The mix is designed to balance the emphasis on short-term and long-term performance. Performance metrics applicable to short-term and long-term incentives have included a mix of financial and non-financial goals, some of which have been relative to our performance peers, such as the LTIP Peer Group. For example, for the 2012 annual incentive, the metrics included cash flow from operations,

157

achievement of certain strategic milestones, and health, environment and safety performance. The long-term metrics for the 2012 performance-based restricted units were total unitholder return and growth in cash distributions to unitholders relative to our peers. This approach creates a balance of absolute and relative performance to ensure that executives are rewarded when sustained results exceed our peer group.

The Compensation Committee reviews and approves the annual and long-term plan performance metrics and goals annually. As a part of this process, the Compensation Committee focuses on what executive behavior it is attempting to incent and the potential associated risks. The Compensation Committee periodically receives financial information from the CFO, and information on accounting matters that may have an impact on the performance goals, including any material changes in accounting methodology and information about extraordinary/special items excluded by us and from our peer companies’ results, so that the Compensation Committee members may understand how the exercise of management judgment in accounting and financial decisions affects plan payouts.

We maintain unit ownership guidelines for our top executives. The amount of our common units required to be owned increases with the level of responsibility. Requiring an executive to hold a substantial portion of accumulated wealth in our common units, which must be held until the executive retires or otherwise leaves the employ of our general partner or its affiliates, aligns his or her behavior towards long-term unitholder value creation. See “Compensation Discussion & Analysis—Elements of Compensation—Unit Ownership Guidelines” for additional information.

Employees of our general partner and its affiliates are subject to our Insider Trading Policy, which, among other things, prohibits an employee from entering into short sales, or purchasing, selling, or exercising any puts, calls or similar instruments pertaining to our securities, all of which could incent an employee towards engaging in overly risky behavior for short-term gains.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

There are no Compensation Committee interlocks.

158

COMPENSATION COMMITTEE REPORT

The Compensation Committee (the “Committee”) of the Board of Directors of Sunoco Partners LLC (the “Company”) reviews and approves the Company’s executive compensation philosophy; reviews and recommends to the Board for approval the Company’s short—and long-term compensation plans; reviews and approves the executive compensation programs and awards; and annually reviews, determines and approves the compensation for the Chief Executive Officer (“CEO”) and the other executive officers (collectively, the “Named Executive Officers” or “NEOs”) of the Company named in the Summary Compensation Table contained in the Annual Report on SEC Form 10-K of Sunoco Logistics Partners L.P. (the “Partnership”). The Company is the general partner of the Partnership. The Committee Chair reports Committee actions, decisions and recommendations at the meetings of the full Board. The Committee has authority to directly engage and consult outside advisors, experts and others to assist the Committee at the expense of the Partnership.

As required by applicable regulations of the Securities and Exchange Commission, the Committee has reviewed the executive compensation disclosures contained in the report captioned “Compensation Discussion and Analysis,” which report is required pursuant to Item 402(b) of SEC Regulation S-K, as amended. As part of this review, the Committee met with management and with such outside consultants and experts as it has deemed necessary or advisable (with and without management present), to discuss the scope and overall quality of the disclosure.

In reliance on the reviews and discussions referred to above, the Committee recommended to the Board of Directors, and the Board has approved, the inclusion of the “Compensation Discussion and Analysis” in the Partnership’s Annual Report on SEC Form 10-K for the fiscal year ended December 31, 2012, for filing with the Securities and Exchange Commission.

Respectfully submitted on February 21, 2013 by the members of the Compensation Committee of the Board of Directors of Sunoco Partners LLC:

Scott A. Angelle (Chairman)

Steven R. Anderson

Basil Leon Bray

Michael J. Hennigan

Marshall S. (Mackie) McCrea, III.

159

AUDIT COMMITTEE REPORT

The Audit Committee (the “Committee”) of the Board of Directors of Sunoco Partners LLC (the “Company”) reviews the Partnership’s financial reporting process on behalf of the Board of Directors of the Company. The Company is the general partner of the Partnership. Our management is responsible for the financial statements and the reporting process, including the internal control over financial reporting. The independent registered public accounting firm is responsible for expressing an opinion on the conformity of the audited financial statements with U.S. generally accepted accounting principles, and an opinion on the effectiveness of our internal control over financial reporting. The Committee monitors and oversees these processes.

The Committee discussed with our internal audit department and independent registered public accounting firm the overall scope and plans for their respective audits. In addition, the Committee has reviewed and discussed the audited financial statements and management’s and the independent registered public accounting firm’s evaluations of the Partnership’s system of internal control over financial reporting contained in the 2012 Annual Report on Form 10-K. As part of this review, the Committee met with the General Auditor and the independent registered public accounting firm, with and without management present, to discuss the results of their audits and the overall quality of the Partnership’s financial reporting.

As required by the standards of the Public Company Accounting Oversight Board, the Committee has discussed with the independent registered public accounting firm (1) the matters specified in Statement on Auditing Standards No. 61, “Communication with Audit Committees,” (Codification of Statements of Auditing Standards, August 2, 2007 AU 380), as amended, as adopted by the Public Company Accounting Oversight Board in Rule 3200T; and (2) the independence of the independent registered public accounting firm from the Partnership and management. The independent registered public accounting firm has provided the Committee the written disclosures and letter concerning independence, pursuant to applicable requirements of the Public Company Accounting Oversight Board. The Committee also considered the compatibility of non-audit services with the independent registered public accounting firm’s independence.

In reliance on the reviews and discussions referred to above, the Committee recommended to the Board of Directors, and the Board has approved, the inclusion of the audited financial statements and management’s report on internal control over financial reporting in the Partnership’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012, for filing with the Securities and Exchange Commission.

Respectfully submitted on February 21, 2013 by the members of the Audit Committee of the Board of Directors of Sunoco Partners LLC:

Basil Leon Bray (Chairman)

Steven R. Anderson

and Scott A. Angelle.

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ITEM 12.

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

Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides information, as of December 31, 2012, regarding our common units that may be issued upon conversion (assuming a one-for-one conversion) of outstanding restricted units granted under the general partner’s Long-Term Incentive Plan to executive officers, directors, and other key employees. For more information about this plan (which did not require approval by our limited partners at the time of its adoption in 2002), refer to “Item 11—Executive Compensation.”

EQUITY COMPENSATION PLAN INFORMATION(1)


Plan Category	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights		(b) Weighted-average exercise price of outstanding options, warrants and rights		(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders		—		—		—
Equity compensation plans not approved by security holders		713,058		—		871,176

Total		713,058		—		871,176

NOTES TO TABLE:

⁽¹⁾

The amounts in column (a) of this table reflect only restricted units that have been granted under the Sunoco Partners LLC Long-Term Incentive Plan, since the inception of the Plan. No unit options have been granted. Each restricted unit shown in the table represents a right to receive (upon vesting and payout) a specified number of our common units. Vesting and payout may be conditioned upon achievement of pre-determined financial or other performance objectives for, or attainment of certain length of service goals with us and our affiliates. No value is shown in column (b) of the table, since the restricted units do not have an exercise, or “strike,” price. For illustrative purposes, a maximum payment (i.e., a 200% ratio) has been assumed for vesting and payout of performance-related grants, and a target payout (i.e., a 100% ratio) has been assumed for vesting and payout of grants conditioned only upon service.

161

Beneficial Ownership Table

The following table sets forth the beneficial ownership of our common units by directors of Sunoco Partners LLC (our general partner), by each NEO and by directors and executive officers of Sunoco Partners LLC as a group, as of December 31, 2012. Unless otherwise noted, each individual exercises sole voting or investment power over the Partnership common units shown in the table. For purposes of this table, beneficial ownership includes Partnership common units as to which the person has sole or shared voting or investment power, as well as: (a) those Partnership common units that such person has the right to acquire through the December 31, 2012 vesting, and February 21, 2013 conversion, of performance-based restricted units awarded subsequent to July 2010 and (b) any additional Partnership common units that a person otherwise has the right to acquire within 60 days of December 31, 2012, through the conversion of restricted units. Prior to the October 5, 2012 Merger of Sunoco, Inc. with Energy Transfer Partners, L.P., Sunoco Partners LLC was owned by the following members: Sun Pipe Line Company (63.6 percent); Sunoco, Inc. (R&M) (17.4 percent); and Atlantic Refining & Marketing Corp. (19.0 percent), each of which was a direct or indirect wholly-owned subsidiary of Sunoco, Inc. Following the Merger, Sunoco Partners LLC is now wholly-owned by Energy Transfer Partners, L.P., as its sole member.


Name of Beneficial Owner⁽¹⁾	Number of Common Units Beneficially Owned⁽¹⁾		Percentage of Common Units Beneficially Owned
Sunoco Partners LLC		33,530,637
Steven R. Anderson		0		*
Scott A. Angelle		0		*
Basil Leon Bray		0		*
Michael J. Colavita		0		*
Lynn L. Elsenhans⁽²⁾		25,327		*
Michael J. Hennigan⁽³⁾		68,072		*
Brian P. MacDonald		10,527		*
Thomas P. Mason		0		*
Marshall S. (“Mackie”) McCrea, III		12,000		*
Martin Salinas, Jr.		0		*
Kathleen Shea-Ballay		8,614		*
All directors and executive officers as a group (11 persons)		124,540		*

*	Less than 0.5 percent.

NOTES TO TABLE:

⁽¹⁾	The address of each beneficial owner named above is: 1818 Market Street, Suite 1500, Philadelphia, PA 19103.

⁽²⁾	Ms. Elsenhans holds 3,696 of these units jointly with her spouse.

⁽³⁾	Mr. Hennigan’s spouse has voting and investment power with respect to 7,200 of these units.

In addition to the foregoing, Tortoise Capital Advisors LLC, a Delaware limited liability company, filed a Schedule 13G on February 12, 2012, to report that, as of December 31, 2012, it had shared voting power over 5,761,628 common units of the Partnership, and beneficial ownership of, and shared dispositive power over 6,086,398 common units of the Partnership, representing 5.9 percent of the total outstanding common units of the Partnership, as of that date.

162

The following table sets forth certain information regarding beneficial ownership of the common units representing limited partnership interests of Energy Transfer Partners, L.P., as of December 31, 2012, by directors of our general partner, by each NEO and by all directors and executive officers of our general partner, as a group. Unless otherwise noted, each individual exercises sole voting or investment power over the Energy Transfer Partners, L.P common units shown in the table. For purposes of this table, beneficial ownership includes Energy Transfer Partners, L.P common units as to which the person has sole or shared voting or investment power and also any Energy Transfer Partners, L.P common units that such person has the right to acquire within 60 days of December 31, 2012, through the exercise of any option, warrant, or right.


Name of Beneficial Owner	Common Units of Energy Transfer Partners, L.P. Beneficially Owned		Percentage of Energy Transfer Partners, L.P Common Units Beneficially Owned
Steven R. Anderson		10,025		*
Scott A. Angelle		0		*
Basil Leon Bray		2,809		*
Michael J. Colavita		2,466		*
Lynn L. Elsenhans⁽¹⁾		149,866		*
Michael J. Hennigan⁽²⁾		7,333		*
Brian P. MacDonald		32,000		*
Thomas P. Mason⁽³⁾		70,121		*
Marshall S. (“Mackie”) McCrea, III⁽³⁾		151,313		*
Martin Salinas, Jr.⁽³⁾		40,185		*
Kathleen Shea-Ballay		947		*
All directors and executive officers as a group (11 persons)		467,065		*

*	Less than 0.5 percent

NOTES TO TABLE:

⁽¹⁾	Ms. Elsenhans holds 70,685 of these ETP common units jointly with her spouse.

⁽²⁾	Mr. Hennigan’s spouse has voting and investment power with respect to 3,205 of these ETP common units.

⁽³⁾

Due to their positions as directors of the general partner of Energy Transfer Equity, L.P. (“ETE”), certain officers and directors of our general partner, who are also officers or directors of ETE’s general partner, may be deemed to own beneficially certain limited partnership interests in ETP, held by ETE, to the extent of their respective interests therein. Any such deemed ownership is not reflected in the table.

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ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

On February 5, 2010, our general partner, Sunoco Partners LLC, completed the sale of 6.6 million common units of the Partnership in a registered public secondary offering. As of February 28, 2013, our general partner owns a 33.7 percent partnership interest, which includes a two percent general partner interest and 33.5 million common units, representing a 32.3 percent limited partner interest in us. The general partner’s ability to manage and operate us effectively gives the general partner the ability to control us.

Distribution and Payments to the General Partner and Its Affiliates

The following table summarizes the distribution and payments made and to be made us to the general partner and its affiliates in connection with the ongoing operation and in the case of liquidation. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

Operational Stage

Payments to the general partner and its affiliates

We paid the general partner an administrative fee, $18 million for the year ended December 31, 2012, for the provision of various general and administrative services for our benefit. In addition, the general partner is entitled to reimbursement for all expenses it incurs on our behalf, including other general and administrative expenses. These reimbursable expenses include the salaries and the cost of employee benefits of employees of the general partner who provide services to us. The general partner has sole discretion in determining the amount of these expenses.

Removal or withdrawal of the general partner

If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests as provided in the Partnership Agreement.

Liquidation Stage

Liquidation

Upon liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.

Concurrently with and subsequent to the closing of the February 2002 IPO, we entered into several agreements with Sunoco, Inc. (R&M), and/or one or more of its affiliates. Some of these agreements have expired, been assigned and been extended or replaced. These agreements include the Omnibus Agreement, the Pipelines and Terminals Storage and Throughput Agreement, the Interrefinery Lease Agreement, an intellectual property license agreement, certain crude oil purchase and sale agreements, a treasury services agreement,

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various asset acquisition agreements and other agreements. The material agreements that are still outstanding are discussed in more detail under “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Agreements with Related Parties.”

Approval and Review of Related Party Transactions

Our Partnership Agreement and the Omnibus Agreement each contain provisions for our Conflicts Committee, comprised of our general partner’s independent directors, to review transactions with related parties. In some cases review is required and in others it is at the discretion of our general partner. Generally, transactions with related parties that are material to us are referred to the Conflicts Committee for review and approval. In determining materiality, our general partner evaluates several factors including the term of the transaction, the capital investment required, and the revenues expected from the transaction.

With respect to other related party transactions, we have in place a Code of Business Conduct and Ethics that is applicable to all directors, officers and employees of the Partnership and its subsidiaries and affiliates, a Code of Ethics for Senior Officers of the Partnership and its subsidiaries and affiliates, and a Conflict of Interest Policy applicable to all directors, officers and employees of the Partnership and its subsidiaries and affiliates. Each of these policies requires the approval by a supervisor, officer, or the Board of Directors, prior to entering into any related party transaction that could present a potential conflict of interest. Each of the Partnership Agreement, Code of Business Conduct and Ethics, and Code of Ethics for Senior Officers is publicly available on our website.

ITEM 14.

PRINCIPAL ACCOUNTING FEES AND SERVICES

The following table presents the aggregate fees for audit and other professional services by our independent registered public accounting firm, Ernst & Young LLP, for each of the last two fiscal years:


	For the Year Ended December 31,
Type of Fee	2012		2011
	(in millions)
Audit Fees⁽¹⁾	$	1.3	$	1.3
Audit Related Fees		—		—
Tax Fees		—		—
All Other Fees		—		—

	$	1.3	$	1.3

⁽¹⁾

Audit fees consist of fees for the audit of the Partnership’s annual consolidated financial statements, review of consolidated financial statements included in the Partnership’s quarterly reports on Form 10-Q and review of registration statements and issuance of comfort letters, consents and review of documents filed with the SEC. Audit fees also include the fees for the audit of the Partnership’s internal control as required by Section 404 of the Sarbanes-Oxley Act of 2002.

Each of the services listed above were approved by the Audit Committee of the general partner’s board of directors prior to their performance. All services rendered by Ernst & Young LLP, are performed pursuant to a written engagement letter with the general partner.

The Audit Committee of the general partner’s board of directors is responsible for pre-approving all audit services, and permitted non-audit services, to be performed by the independent registered public accounting firm for the Partnership, or its general partner. The Committee reviews the services to be performed to determine whether provision of such services potentially could impair the independence of the Partnership’s independent registered public accounting firm. The Committee’s approval procedures include reviewing a detailed budget for

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each particular service to be rendered, as well as a description of, and budgeted amounts for, specific categories of anticipated non-audit services. Pre-approval is generally granted for up to one year. Committee approval is required to exceed the budgeted amount for any particular category of services or to engage the independent registered public accounting firm for services not included in the budget. Additional services or specific engagements may be approved, on a case-by-case basis, prior to the independent registered public accounting firm undertaking such services.

Subject to the requirements of applicable law, the Audit Committee may delegate such pre-approval authority to the Audit Committee chairman. However, any pre-approvals granted by the chairman, acting pursuant to such delegated authority, are reviewed by the full membership of the Audit Committee at its next regular meeting. Management of the general partner provides periodic updates to the Audit Committee regarding the extent of any services provided in accordance with this pre-approval process, as well as the cumulative fees incurred to date for all non-audit services, to ensure that such services are within the parameters approved by the Audit Committee.

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PART IV

ITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)

The following documents are filed as part of this report:

(1)

The financial statements and notes thereto are included in Item 8. Financial Statements and Supplementary Data.

(2)

All financial statement schedules required are included in the financial statements or notes thereto.

(3)

Exhibits:


Exhibit No.		Description

2.1*		Asset and Membership Interest Purchase and Sale Agreement between Texon Distribution L.P. and Butane Acquisition I LLC, dated as of June 25, 2010 (incorporated by reference to Exhibit 2.1 of Form 8-K, file No. 1-31219, filed August 4, 2010)

2.1.1*		Schedules and Exhibits to Asset and Membership Interest Purchase and Sale Agreement omitted from this filing. Registrant hereby undertakes, pursuant to Regulation S-K Item 601(2) to furnish any such schedules and exhibits to the SEC supplementally, upon request (incorporated by reference to Exhibit 2.1.1 of Form 8-K, file No. 1-31219, filed August 4, 2010)

3.1*		Certificate of Limited Partnership of Sunoco Logistics Partners L.P. (incorporated by reference to Exhibit 3.1 to Form S-1 Registration Statement, file No. 333-71968, filed October 22, 2001)

3.2*		Certificate of Limited Partnership of Sunoco Logistics Operations L.P. (incorporated by reference to Exhibit 3.1 to Amendment No. 1 to Form S-1 filed December 18, 2001)

3.3*		First Amended and Restated Agreement of Limited Partnership of Sunoco Logistics Partners Operations L.P., dated as of February 8, 2002 (incorporated by reference to Exhibit 3.5 of Form 10-K, file No. 1-31219, filed April 1, 2002)

3.4*		Third Amended and Restated Agreement of Limited Partnership of Sunoco Logistics Partners L.P., dated as of January 26, 2010 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed January 28, 2010)

3.4.1*		Amendment No. 1 to Third Amended and Restated Partnership Agreement of Sunoco Logistics Partners L.P., dated as of July 1, 2011 (incorporated by reference to Exhibit 3.1 of Form 8-K, file No. 1-31219, filed July 5, 2011)

3.5*		Third Amended and Restated Limited Liability Company Agreement of Sunoco Partners LLC dated as of July 1, 2011 (incorporated by reference to Exhibit 3.2 of Form 8-K, file No. 1-31219, filed July 5, 2011)

4.1*		Indenture, dated as of December 16, 2005 (incorporated by reference to Exhibit 4.4 of Registration Statement on Form S-3, file No. 333-130564, filed December 21, 2005)

4.1.1*		Seventh Supplemental Indenture, dated as of January 10, 2013, by and among Sunoco Logistics Partners Operations L.P., as issuer, Sunoco Logistics Partners L.P., as guarantor, and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, file No.1-31219, filed January 10, 2013)

4.1.2*		Eighth Supplemental Indenture, dated as of January 10, 2013, by and among Sunoco Logistics Partners Operations L.P., as issuer, Sunoco Logistics Partners L.P., as guarantor, and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit 4.4 of Form 8-K, file No.1-31219, filed January 10, 2013)

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Exhibit No.		Description

10.1*		$350,000,000 Credit Agreement dated as of August 22, 2011, among Sunoco Logistics Partners Operations L.P., as the Borrower; Sunoco Logistics Partners L.P., as the Guarantor; Citibank, N.A., as Administrative Agent, Swing Line Lender and as a Lender and L/C Issuer; Barclays Bank PLC, as a Lender and L/C Issuer; and the other Lenders Party thereto (incorporated by reference to Exhibit 10.1 of Form 10-Q, file No. 1-31219, filed November 3, 2011)

10.1.1*		First Amendment to Credit Agreement, dated as of August 14, 2012, by and among Sunoco Logistics Partners Operations L.P., as the Borrower; Sunoco Logistics Partners L.P., as the Guarantor; the Undersigned Lenders and Citibank, N.A., as Administrative Agent, as a L/C Issuer and as Swing Line Lender (incorporated by reference to Exhibit 10.2 of Form 10-Q, file No. 1-31219, filed November 8, 2012)

10.2*		$200,000,000 364-Day Revolving Credit Agreement dated as of August 14, 2012, among Sunoco Partners Marketing & Terminals L.P., as Borrower; Sunoco Logistics Partners Operations L.P. and Sunoco Logistics Partners L.P., as the Guarantors; Citibank, N.A., as Administrative Agent and as a Lender; Barclays Bank PLC, as a Lender; and the other Lenders Party thereto (incorporated by reference to Exhibit 10.1 of Form 10-Q, file No. 1-31219, filed November 8, 2012)

10.3*		Contribution, Conveyance and Assumption Agreement, dated as of February 8, 2002, among Sunoco, Inc., Sun Pipe Line Company of Delaware, Sunoco, Inc. (R&M), Atlantic Petroleum Corporation; Sunoco Texas Pipe Line Company, Sun Oil Line of Michigan (Out) LLC, Mid-Continent Pipe Line (Out) LLC, Sun Pipe Line Services (Out) LLC, Atlantic Petroleum Delaware Corporation, Atlantic Pipeline (Out) L.P., Sunoco Partners LLC, Sunoco Partners Lease Acquisition & Marketing LLC, Sunoco Logistics Partners L.P., Sunoco Logistics Partners GP LLC, Sunoco Pipeline L.P., Sunoco Partners Marketing & Terminals L.P., Sunoco Mid-Con (In) LLC, Atlantic (In) L.P., Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners Operations GP LLC, Atlantic R&M (In) L.P., Sun Pipe Line Services (In) L.P., Sunoco Michigan (In) LLC, Atlantic (In) LLC, Sunoco Logistics Pipe Line GP LLC, Sunoco R&M (In) LLC, and Atlantic Refining & Marketing Corp. (incorporated by reference to Exhibit 10.4 of Form 10-K, file No. 1-31219, filed April 1, 2002)

10.4*		Omnibus Agreement, dated as of February 8, 2002, by and among Sunoco, Inc., Sunoco, Inc. (R&M), Sunoco Logistics Pipe Line Company of Delaware, Atlantic Petroleum Corporation, Sunoco Texas Pipe Line Company, Sun Pipe Line Services (Out) LLC, Sunoco Logistics Partners L.P., Sunoco Logistics Partners Operations L.P., and Sunoco Partners LLC (incorporated by reference to Exhibit 10.5 of Form 10-K, file No. 1-31219, filed April 1, 2002)

10.4.1*		Amendment No. 2011-1 to Omnibus Agreement, dated as of February 22, 2011, and effective January 1, 2011, by and among Sunoco, Inc., Sunoco, Inc. (R&M), Sun Pipe Line Company of Delaware LLC, Atlantic Petroleum Corporation, Sunoco Logistics Partners L.P., Sunoco Logistics Partners Operations L.P., Sunoco Pipeline L.P. and Sunoco Partners LLC (incorporated by reference to Exhibit 10.6.1 of Form-K, file No. 1-31219 filed February 23, 2011)

10.5*		Amended and Restated Treasury Services Agreement, dated as of November 26, 2003, by and among Sunoco, Inc., Sunoco Logistics Partners L.P., and Sunoco Logistics Partners Operations L.P. (incorporated by reference to Exhibit 10.7.1 of Form 10-K, file No. 1-31219, filed March 4, 2004)

10.6*		Intellectual Property and Trademark License Agreement, dated as of February 8, 2002 among Sunoco, Inc., Sunoco, Inc. (R&M), Sunmarks, Inc., Sunoco Logistics Partners L.P., Sunoco Logistics Partners Operations L.P., Sunoco Partners Marketing & Terminals L.P., Sunoco Pipeline L.P., and Sunoco Partners LLC (incorporated by reference to Exhibit 10.8 of Form 10-K, file No. 1-31219, filed April 1, 2002)

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Exhibit No.		Description

10.7*		Inter-refinery Lease, dated as of February 8, 2002, between Sunoco Pipeline L.P., and Sunoco, Inc. (R&M) (incorporated by reference to Exhibit 10.9 of Form 10-K, file No. 1-31219, filed April 1, 2002)

10.8*		Sunoco Partners LLC Executive Involuntary Severance Plan, as amended and restated as of July 27, 2010 (incorporated by reference to Exhibit 10.1 of Form 10-Q, file No. 1-31219, filed August 4, 2010)

10.8.1*		Amendment No. 2012-2 to the Sunoco Partners LLC Executive Involuntary Severance Plan (incorporated by reference to Exhibit 10.2 of Form 8-K, file No. 1-31219, filed January 7, 2013)

10.9*		Sunoco Partners LLC Long-Term Incentive Plan, as amended and restated as of October 24, 2012 (incorporated by reference to Exhibit 10.3 of Form 10-Q, file No. 1-31219, filed November 8, 2012)

10.9.1*		Form of Performance-Based Restricted Unit Agreement under the Sunoco Partners LLC Long-Term Incentive Plan (incorporated by reference to Exhibit 10.11.1 of Form 10-K, file No. 1-31219, filed February 23, 2011)

10.9.2		Form of Time-Vested Restricted Unit Agreement under the Sunoco Partners LLC Long-Term Incentive Plan

10.10*		Sunoco Partners LLC Annual Incentive Plan, as amended and restated as of April 25, 2011 (incorporated by reference to Exhibit 10.2 of Form 10-Q, file No. 1-31219, filed May 5, 2011)

10.11*		Sunoco Partners LLC Special Executive Severance Plan, as amended and restated as of July 27, 2010 (incorporated by reference to Exhibit 10.5 of Form 10-Q, file No. 1-31219, filed August 4, 2010)

10.11.1*		Amendment No. 2012-2 to the Sunoco Partners LLC Special Executive Severance Plan (incorporated by reference to Exhibit 10.1 of Form 8-K, file No. 1-31219, filed January 7, 2013)

10.12**		Crude Oil Pipeline Throughput and Deficiency Agreement between Motiva Enterprises LLC and Sunoco Pipeline L.P., dated as of December 19, 2006 (incorporated by reference to Exhibit 10.19 of Form 10-K, file no. 1-31219, filed February 23, 2007)

10.13**		Marine Dock and Terminalling Agreement between Motiva Enterprises LLC and Sunoco Partners Marketing & Terminals L.P., dated as of December 19, 2006 (incorporated by reference to Exhibit 10.20 of Form 10-K, file no. 1-31219, filed February 23, 2007)

10.14*		Membership Interest Purchase Agreement, effective as of July 27, 2006, between Sunoco, Inc. and Sunoco Pipeline Acquisition LLC (incorporated by reference to Exhibit 10.1 of Form 10-Q, file No. 1-31219, filed August 2, 2006)

10.15*		Product Terminal Services Agreement, dated as of May 1, 2007, among Sunoco, Inc. (R&M) and Sunoco Partners Marketing & Terminals L.P. (incorporated by reference to Exhibit 10.1 of Form 10-Q, file No. 1-31219, filed July 31, 2007)

10.15.1*		Letter Agreement, dated January 19, 2012, amending Product Terminal Services Agreement (incorporated by reference to Exhibit 10.17.1 of Form 10-K, file No. 1-31219, filed February 24, 2012)

10.16*		Repurchase Agreement between Sunoco Logistics Partners L.P. and Sunoco Partners LLC, dated January 26, 2010 (incorporated by reference to Exhibit 10.1 of Form 8-K, file No. 1-31219, filed January 28, 2010)

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Exhibit No.		Description

10.17*		Contribution Agreement, dated as of June 29, 2011, to be effective July 1, 2011, by and among Sunoco, Inc. (R&M), Sunoco Logistics Partners L.P., and certain subsidiaries and affiliates of Sunoco Logistics Partners L.P. (incorporated by reference to Exhibit 10.1 of Form 10-Q/A, file No. 1-31219, filed August 8, 2011).

10.18*		Letter Agreement dated November 2, 2011, by and between Sunoco Partners LLC and Michael J. Hennigan, President and Chief Operating Officer (incorporated by reference to Exhibit 10.3 of Form 10-Q, file No. 1-31219, filed November 3, 2011)

10.19*		Letter Agreement with Michael J. Hennigan, President and Chief Executive Officer, dated October 4, 2012 (incorporated by reference to Exhibit 10.3 of Form 10-Q, file No. 1-31219, filed November 8, 2012)

12.1		Statement of Computation of Ratio of Earnings to Fixed Charges

14.1*		Code of Ethics for Senior Officers (incorporated by reference to Exhibit 10.14.1 to Form 10-K, file No. 1-31219, filed March 4, 2004)

21.1		Subsidiaries of Sunoco Logistics Partners L.P.

23.1		Consent of Independent Registered Public Accounting Firm

24.1		Power of Attorney

31.1		Officer Certification Pursuant to Exchange Act Rule 13a-14(a)

31.2		Officer Certification Pursuant to Exchange Act Rule 13a-14(a)

32.1		Officer Certification Pursuant to Exchange Act Rule 13a-14(b) and 18 U.S.C. § 1350

99.1*		Agreement and Plan of Merger, dated as of April 29, 2012 by and among Sunoco, Inc., Energy Transfer Partners, L.P., Sam Acquisition Corporation, Energy Transfer Partners GP, L.P., and, for certain limited purposes set forth therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 99.1 of Form 8-K, file No. 1-31219, filed May 2, 2012)

99.2*		Termination Agreement by and between Sunoco, Inc., and Lynn L. Elsenhans, dated April 29, 2012 (incorporated by reference to Exhibit 99.1 of Form 8-K, file No. 1-31219, filed May 3, 2012)

101.1		The following consolidated financial information from Sunoco Logistics Partners L.P.’s Annual Report on Form 10-K for the year ended December 31, 2012 formatted in XBRL (eXtensible Business Reporting Language): (i) the Statements of Comprehensive Income; (ii) the Balance Sheets; (iii) the Statements of Cash Flows; (iv) the Statements of Equity; and, (v) the Notes to Financial Statements.

*	Each such exhibit has heretofore been filed with the Securities and Exchange Commission as part of the filing indicated and is incorporated herein by reference.

**	Confidential status has been requested for certain portions thereof pursuant to a Confidential Treatment Request filed February 23, 2007. Such provisions have been separately filed with the Commission.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


Sunoco Logistics Partners L.P.
(Registrant)

BY:		Sunoco Partners LLC (its General Partner)

By:		/S/ MARTIN SALINAS, JR.
		Martin Salinas, Jr.
		Chief Financial Officer

March 1, 2013

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by or on behalf of the following persons on behalf of the registrant and in the capacities indicated on March 1, 2013.



STEVEN R. ANDERSON* Steven R. Anderson Director of Sunoco Partners LLC, General Partner of Sunoco Logistics Partners L.P.		MICHAEL J. HENNIGAN* Michael J. Hennigan Director, President and Chief Executive Officer of Sunoco Partners LLC, General Partner of Sunoco Logistics Partners L.P. (Principal Executive Officer)

SCOTT A. ANGELLE* Scott A. Angelle Director of Sunoco Partners LLC, General Partner of Sunoco Logistics Partners L.P.		THOMAS P. MASON* Thomas P. Mason Director of Sunoco Partners LLC, General Partner of Sunoco Logistics Partners L.P.

BASIL LEON BRAY* Basil Leon Bray Director of Sunoco Partners LLC, General Partner of Sunoco Logistics Partners L.P.		MARSHALL S. MCCREA III* Marshall S. McCrea III Director (Chairman) of Sunoco Partners LLC, General Partner of Sunoco Logistics Partners L.P.

MICHAEL D. GALTMAN* Michael D. Galtman Controller and Chief Accounting Officer of Sunoco Partners LLC, General Partner of Sunoco Logistics Partners L.P. (Principal Accounting Officer)

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