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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, 2011

¨	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
Class A Common Units representing limited partnership interests		New York Stock Exchange
Senior Notes 7.25%, due February 15, 2012		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		New York Stock Exchange
Senior Notes 6.85%, due February 15, 2040		New York Stock Exchange
Senior Notes 6.10%, due February 15, 2042		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 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. x

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

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

The aggregate value of the Common Units held by non-affiliates of the registrant (treating all executive officers and directors of the registrant and holders of 10 percent or more of the Common Units outstanding (including the General Partner of the registrant, Sunoco Partners LLC, as if they may be affiliates of the registrant)) was $2.0 billion as of June 30, 2011, based on $28.72 per unit, the closing price of the Common Units as reported on the New York Stock Exchange on that date.

At February 24, 2012, the number of the registrant’s Common Units and Class A Units outstanding were 99,601,231 and 3,939,435, respectively.

DOCUMENTS INCORPORATED BY REFERENCE: NONE

TABLE OF CONTENTS


PART I			3
	ITEM 1.	BUSINESS	3
	ITEM 1A.	RISK FACTORS	21
	ITEM 1B.	UNRESOLVED STAFF COMMENTS	34
	ITEM 2.	PROPERTIES	34
	ITEM 3.	LEGAL PROCEEDINGS	35
	ITEM 4.	RESERVED	35

PART II			36
	ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SECURITYHOLDER MATTERS AND PURCHASES OF EQUITY SECURITIES	36
	ITEM 6.	SELECTED FINANCIAL DATA	38
	ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	42
	ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	62
	ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	64
	ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	111
	ITEM 9A.	CONTROLS AND PROCEDURES	111
	ITEM 9B.	OTHER INFORMATION	111

PART III			112
	ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	112
	ITEM 11.	EXECUTIVE COMPENSATION	117
	ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SECURITYHOLDER MATTERS	156
	ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	159
	ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	160

PART IV			161
	ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	161

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 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;

•

The loss of Sunoco as a customer or a significant reduction in its current level of throughput and storage with us;

•

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 petroleum products;

•

Our ability to manage growth and/or control costs;

•

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 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 Sunoco’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., 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 products. The principal executive offices of Sunoco Partners LLC, our general partner, are located at 1818 Market Street, Suite 1500, Philadelphia, Pennsylvania 19103 (telephone (215) 977-3000). Our website address is www.sunocologistics.com.

Sunoco, Inc., and its wholly owned subsidiaries including Sunoco, Inc. (R&M), own 33.8 percent of our partnership interests, including a 2 percent general partner interest. Sunoco, Inc. and Sunoco, Inc. (R&M) are collectively referred to as “Sunoco.”

(b) Financial Information about Segments

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

(c) Narrative Description of Business

During the third quarter 2011, we realigned our reporting segments. The updated reporting segments are: Refined Products Pipelines, Terminal Facilities, Crude Oil Pipelines and Crude Oil Acquisition and Marketing. Prior to this date, the former Crude Oil Pipelines segment included both crude oil pipeline and crude oil acquisition and marketing operations. We have determined it is more meaningful to segregate these operations into different reporting segments, given the growth in the crude oil acquisition and marketing business. For the purpose of comparability, all prior year segment disclosures have been recast to conform to the current year presentation. Such recasts have no impact on previously reported consolidated net income.

•

The Refined Products Pipelines serve Sunoco and other third parties and consists of approximately 2,500 miles of refined product pipelines, including a two-thirds undivided interest in the approximately 100-mile refined product Harbor pipeline and joint venture interests in four refined products pipelines in selected areas of the United States.

•

The Terminal Facilities consist of 42 active refined product terminals with an aggregate storage capacity of 8 million barrels, which provide storage, terminalling, blending and other ancillary services primarily to our 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 Sunoco’s Philadelphia refinery; the Eagle Point terminal, a 5 million barrel refined product and crude oil terminal and dock facility; and a 1 million barrel liquefied petroleum gas (“LPG”) terminal near Detroit, Michigan.

•

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, including a 37 percent undivided interest in the approximately 100-mile Mesa Pipe Line system; 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 using approximately 170 crude oil transport trucks and approximately 110 crude oil truck unloading facilities.

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 strategic and accretive acquisitions that provide organic growth opportunities that will complement our existing asset base and improving operating efficiencies. We believe that these strategies will result in continued increases in distributions to our unitholders.

For the year ended December 31, 2011, Sunoco accounted for 45 percent of the Refined Products Pipelines’ total revenues, 27 percent of the Terminal Facilities’ total revenues, 2 percent of the Crude Oil Pipelines’ total revenues and 2 percent of Crude Oil Acquisition and Marketing’s total revenues.

In March 2011, Sunoco completed the sale of its Toledo refinery to affiliates of PBF Holding Company LLC (“PBF”). Certain of our 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. The sale of the refinery did not have a material impact on our results of operations, financial position or cash flows.

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. Sunoco continues to pursue a sale of both the Philadelphia and Marcus Hook facilities, however Sunoco does not believe that the Marcus Hook facility will be sold and restarted as an operating refinery. If arrangements for sale cannot be made, Sunoco intends to permanently idle the facilities by July 2012. We assessed the impact that Sunoco’s decision to exit its refining business in the northeast will have on our assets that have historically served the refineries and determined that our refined products pipelines and terminals continue to have expected future cash flows that support their carrying values. However, we recognized a $42 million charge in the fourth quarter 2011 for certain crude oil terminal assets which would be negatively impacted if the Philadelphia refinery is permanently idled. The charge includes a $31 million non-cash impairment for asset write-downs at the Fort Mifflin Terminal Complex and $11 million for regulatory obligations which would be incurred if these terminal assets are permanently idled.

Our pipeline and terminal assets provide a cost effective and efficient outlet to supply Sunoco’s retail marketing network, and as such, we expect that Sunoco will continue to utilize our assets going forward. We will continue to evaluate how changes in Sunoco’s northeast refining operations will impact our pipeline and terminal assets.

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, Texas and Canada. 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 Federal Energy Regulatory Commission (“FERC”) and the Pennsylvania Public Utility Commission (“PA PUC”), among other state regulatory agencies.

Since December 31, 2008, we completed the following acquisitions of refined products pipelines:

•

Controlling Financial Interest in 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 expect to assume operatorship of the pipeline during the first half of 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 in barrels per day (“bpd”):

Year Ended
December 31,

2011

2010

2009

Average shipments (thousands of bpd)⁽¹⁾⁽²⁾

522

468

577

(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			Pipeline Mileage
Explorer Pipeline Company⁽¹⁾		9.4	%		1,900
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 ConocoPhillips, 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.

Terminal Facilities

Refined Products Terminals

Our 42 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 pipelines, 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.

We completed the following acquisitions since December 31, 2008:

•

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 a sale of the Big Sandy terminal to Delek US Holdings, Inc.

•

Butane Blending—In July 2010, we acquired a butane blending business from Texon L.P. (“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 gasoline terminals. We hold U.S. patents for these systems.

•

Romulus Terminal—In September 2009, we acquired a refined products terminal facility located in Romulus, Michigan. Total active terminal storage capacity for this facility is less than a half of a million barrels.

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,

2011

2010

2009

Refined products throughput (thousands of bpd)

492

488

462

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


State	Number of Terminals		Storage Capacity
			(thousands of bbls)
Indiana		1		206
Maryland		1		715
Massachusetts		1		1,145
Michigan		3		763
New Jersey		4		746
New York⁽¹⁾		4		920
Ohio		7		916
Pennsylvania		14		1,772
Virginia		1		403
Louisiana		1		162
Texas		5		716

Total		42		8,464

⁽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, 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 Shell Houma to Houston pipeline from Louisiana;

•

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 398 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;

•

the Total pipelines to its Port Arthur, Texas refinery; and

•

the Shell pipeline to various refineries in Houston, Texas.

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

Year Ended December 31,

2011

2010

2009

Crude oil and refined products throughput (thousands of bpd)

757

729

597

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 supplies Sunoco’s Philadelphia refinery with all of its crude oil. The complex 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. Substantially all of the revenues from the Fort Mifflin Terminal Complex are derived from Sunoco. Sunoco’s intention to sell or idle its Philadelphia refinery resulted in our recognition of a charge related to the Fort Mifflin Terminal Complex during the fourth quarter 2011 for asset write-downs and regulatory obligations which would be incurred if certain terminal assets are permanently idled. We continue to evaluate the impact of changes in Sunoco’s refining operations on our assets.

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 Sunoco’s 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 Sunoco’s Philadelphia refinery in each of the years presented:


	Year Ended December 31,
	2011		2010		2009
Crude oil throughput (thousands of bpd)		267		267		266
Refined products throughput (thousands of bpd)		9		32		14

Total (thousands of bpd)		276		299		280

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.

In December 2011, the main processing units at the Marcus Hook refinery were idled indefinitely. Although Sunoco does not believe that the Marcus Hook refinery will be sold and restarted as an operating refinery, we expect to utilize our Marcus Hook tank farm assets to provide terminalling services to both Sunoco and third-party customers. As such, the expected future cash flows for these assets continue to support their carrying values. If arrangements for sale cannot be made, Sunoco intends to permanently idle the Marcus Hook refinery by July 2012. We continue to evaluate the impact of changes in Sunoco’s refining operations on our assets.

The table below summarizes the total average daily throughput for the Marcus Hook tank farm in each of the years presented:

Year Ended December 31,

2011

2010

2009

Refined products throughput (thousands of bpd)

133

152

130

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. The shutdown of the Eagle Point refinery did not have a material impact on our results of operations, financial position or cash flows, as our assets that were affected by the shut-down were re-deployed for alternate uses. 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,
	2011		2010		2009
Crude oil throughput (thousands of bpd)		4		13		99
Refined products throughput (thousands of bpd)		30		1		82

Total (thousands of bpd)		34		14		181

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 LPGs from Canada and a refinery in Toledo, which was sold by Sunoco to PBF 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.

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, 2008:

•

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 the Nederland Terminal 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.

•

Excel Pipeline LLC—In September 2009, we acquired a 100% membership interest in Excel Pipeline LLC (“Excel”) from affiliates of Gary-Williams Energy Corporation (“Gary-Williams”). The pipeline consists of approximately 50 miles of crude oil pipeline originating in Duncan, Oklahoma and terminating at Gary-Williams’ refinery in Wynnewood, Oklahoma. We were the operator of the pipeline prior to the acquisition. In connection with the transaction, we assumed a 20-year throughput and deficiency contract with Gary-Williams. Pursuant to this contract, Gary-Williams guarantees minimum amounts of crude oil throughput on the pipeline and we agree to provide transportation of such crude oil.

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,

2011

2010

2009

Crude oil and other feedstocks throughput (thousands of bpd)⁽¹⁾⁽²⁾

1,587

1,183

658

⁽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 these 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, the West Texas Gulf 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 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 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 170 crude oil transport trucks and approximately 110 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 acquisitions since December 31, 2008:

•

Crude Oil Acquisition and Marketing Business—In August 2011, we acquired a crude oil acquisition and marketing business from Texon L.P. consisting 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 margin, 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 margin 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 margin, which is equal to sales and other operating revenue less cost of products sold, operating expenses and depreciation and amortization, 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 generally 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, 2011, we purchased 224 thousand bpd from approximately 4 thousand producers and from approximately 48 thousand active leases, and undertook 439 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,
	2011		2010		2009
	(in thousands of bpd)
Lease purchases:
Available for sale		215		181		172
Exchanged		9		8		9
Other exchanges and bulk purchases		439		449		411

Total Purchases		663		638		592

Sales:
Sunoco refineries⁽¹⁾		7		30		26
Third parties		274		220		205
Exchanges:
Purchased at the lease		9		8		9
Other		370		382		353

Total Sales		660		640		593

⁽¹⁾	In 2011 and 2009, Sunoco sold its Toledo and Tulsa refineries, respectively. Changes associated with the sales of both refineries have not had a material impact on our financial results.

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 110 crude oil truck unloading facilities in the mid-continent United States with the majority located on our pipeline system. Approximately 300 crude oil truck drivers are employed by an affiliate of our general partner and approximately 170 crude oil transport trucks are owned. 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.

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

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. Sunoco has announced its intention to exit its refining business in the northeast by July 2012. Despite this change, Sunoco will continue to operate its retail marketing network and we expect that Sunoco will continue to utilize our Refined Products Pipelines as a cost-effective 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 Sunoco.”

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 product 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.

Terminal Facilities

The majority of the throughput at our crude oil facilities in the northeast is related to Sunoco’s refining operations. Although we face limited competition at these facilities, Sunoco’s intention to exit its refining business in the northeast and the potential permanent idling of the Philadelphia refinery is expected to negatively impact our crude oil terminals in the northeast. For further information on the impact, see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Agreements with Sunoco.”

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 42 active refined product 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.

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. Our management believes that high capital costs make it unlikely that other companies will build new competing crude oil pipeline systems in the pipeline corridors served by our Crude Oil Pipelines. However, changes in refiners’ supply sources may negatively impact existing throughput on our 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.

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, 2011, 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, during 2009, 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 customer’s 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 financial position at December 31, 2011. 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 Oklahoma Corporation Commission. The operations of our joint venture interests are also subject to regulation in the states in which they operate. The applicable state statutes require that pipeline rates be nondiscriminatory and provide no more than a fair return on the aggregate value of the pipeline property used to render services. State commissions generally have not initiated an investigation of rates or practices of petroleum pipelines in the absence of shipper complaints. Complaints to state agencies have been infrequent and are usually resolved informally. Although management cannot be certain that our intrastate rates ultimately would be upheld if challenged, we believe that, given this history, the tariffs now in effect are not likely to be challenged or, if challenged, are not likely to be ordered to be reduced.

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 1,500 people at December 31, 2011 who provide direct support to the operations. Labor unions or associations represent approximately 700 of these employees at December 31, 2011.

(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.

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.

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

For the year ended December 31, 2011, Sunoco accounted for 45 percent of our Refined Products Pipelines’ total revenues, 27 percent of our Terminal Facilities’ total revenues, 2 percent of our Crude Oil Pipelines’ total revenue and 2 percent of our Crude Oil Acquisition and Marketing’s total revenues. The balance of our revenues was received from unaffiliated customers.

Sunoco, historically a refiner and marketer of petroleum and petrochemical products, is operated and managed separately from us and is subject to different business and operational risks than us. Sunoco actively manages its assets and operations independently of ours, and therefore, changes of some nature, possibly material to our business relationship, may occur at some point in the future. Because several of our terminal facilities in the northeast are located at, and dedicated to, refineries that are owned and operated by Sunoco, if Sunoco were to significantly decrease throughput volumes at these terminals, because of business or operational difficulties or strategic decisions by its management, it is unlikely that we would be able to utilize any additional capacity at these terminal facilities to service third party customers without substantial capital outlays and delays, if at all, which could materially and adversely affect our results of operations, financial condition and cash flows. Further, if Sunoco were to significantly decrease the throughput transported on our pipelines or the volumes of refined products handled at our other terminals in the northeast, our results of operations, financial condition, and cash flows could be materially and adversely affected.

Sunoco executed a number of strategies during 2011 to facilitate its shift away from manufacturing. In addition to the sale of its Toledo, Ohio refinery in March 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. Sunoco continues to pursue a sale of both the Philadelphia and Marcus Hook facilities, however Sunoco does not believe that the Marcus Hook facility will be sold and restarted as an operating refinery. If arrangements for sale cannot be made, Sunoco intends to permanently idle the facilities by July 2012.

Sunoco announced its intention to continue to grow its distribution and retail marketing assets. Our refined products pipeline and terminal assets provide a cost effective and 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 reduces its use of our facilities, it could materially and adversely affect our results of operations, financial condition, or cash flows.

We assessed the impact that Sunoco’s decision to exit its refining business in the northeast will have on our assets that have historically served the refineries and determined that our refined products pipeline and terminal assets continue to have expected future cash flows that support their carrying values. However, we recognized a $42 million charge in the fourth quarter 2011 for certain crude oil terminal assets which would be negatively impacted if the Philadelphia refinery is permanently idled. The charge includes a $31 million non-cash impairment for asset write-downs at the Fort Mifflin Terminal Complex and $11 million for regulatory obligations which would be incurred if these terminal assets are permanently idled.

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:

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

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

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

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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

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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.

Sunoco and the other 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.

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 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 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, 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 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 ratemaking 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 resources 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, current EPA regulations will require specified large domestic GHG sources to report emissions above a certain threshold occurring after January 1, 2010. Our facilities will not be 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, and we are subject 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 right-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, covered under our Omnibus Agreement with Sunoco, 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.

As a result of Sunoco’s outsourcing initiatives, more third parties are involved in processing 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.

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, and regulatory penalties, disrupt our operations, and damage 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 the members of our general partner, all of which are wholly-owned subsidiaries of Sunoco. 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.

Sunoco and its affiliates have conflicts of interest and limited fiduciary responsibilities, which may permit them to favor their own interests to the detriment of our unitholders.

Sunoco indirectly owns and controls our general partner and owns 33.8 percent of our partnership interests, including a 2 percent general partner interest. Conflicts of interest may arise between Sunoco 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 over the interests of our unitholders. These conflicts include, among others, the following situations:

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Sunoco, as a shipper on our pipelines, and a customer at our terminals, could seek lower tariff rates or terminalling fees, or could determine not to utilize our facilities;

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neither our partnership agreement nor any other agreement requires Sunoco to pursue a business strategy that favors us or utilizes our assets, including whether to increase or decrease refinery production, whether to shut down or reconfigure a refinery, or what markets to pursue or grow. Sunoco’s directors and officers have a fiduciary duty to make these decisions in the best interests of the shareholders of Sunoco;

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our general partner is allowed to take into account the interests of parties other than us, such as Sunoco, in resolving conflicts of interest;

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under our partnership agreement, our general partner has limited liability and restricted fiduciary duties with respect to actions that, without these limitations and restrictions, might otherwise constitute breaches of fiduciary duty;

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under our partnership agreement, the remedies available to our unitholders with respect to conduct by our general partner that may constitute a breach of fiduciary duty have been limited;

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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 Sunoco and its affiliates are reimbursable by us;

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

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our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including the pipelines and terminals storage and throughput agreements with Sunoco.

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 Sunoco, and Sunoco owns 33.8 percent of our partnership interests, including a 2 percent general partner interest, and all of our IDRs. Our general partner may cause us to borrow funds from affiliates of Sunoco 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.

Sunoco and its affiliates may engage in limited competition with us.

Sunoco and its affiliates may engage in limited competition with us. Pursuant to the Omnibus Agreement, Sunoco and its affiliates have agreed not to engage in the business of purchasing crude oil at the wellhead or operating refined products or crude oil pipelines or terminals or liquefied petroleum gas (“LPG”) terminals in the continental United States. The Omnibus Agreement, however, does not apply to:

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certain businesses operated by Sunoco or any of its subsidiaries;

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any logistics asset constructed by Sunoco or any of its subsidiaries within a manufacturing or refining facility in connection with the operation of that facility;

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any business that Sunoco or any of its subsidiaries acquires or constructs that has a fair market value of less than $5 million; and

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any business that Sunoco or any of its subsidiaries acquires or constructs that has a fair market value of $5 million or more if we have been offered the opportunity to purchase the business for fair market value, and we decline to do so with the concurrence of our conflicts committee.

Upon a change of control of Sunoco or a sale of our general partner by Sunoco, the non-competition provisions of the Omnibus Agreement may terminate.

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, 2011, our total outstanding indebtedness was $1.70 billion. 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:

•

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

•

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

•

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

•

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

•

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

•

place us at a competitive disadvantage against less leveraged competitors.

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

As of December 31, 2011, we had no floating-rate debt outstanding. However, we have exposure to changes in short-term interest rates when we have outstanding borrowing under our revolving credit facilities. 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 Sunoco’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 Sunoco, any down-grading in Sunoco’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 AND CLASS A 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.

Our partnership will be considered to have technically terminated for federal income tax purposes if there is a sale or exchange of 50 percent or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest

will be counted only once. A sale or exchange would occur, for example, if we sold our business or merged with another company, or if any of our unitholders, including Sunoco, Inc. or any of their affiliates, sold or transferred their partnership interests in us. Our termination would, among other things, result in the closing of our taxable year for all of our unitholders which could result in us filing two tax returns (and unitholders receiving two Schedule K-1s) for one calendar year. Our termination could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs.

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 29 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 Partnership paid the assessed fine and is currently completing mandated corrective actions.

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 have agreed upon a settlement of $0.3 million. The Partnership has executed the settlement papers and awaits the EPA finalization.

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% 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 totaling $0.4 million in connection with a crude oil release that occurred at the Colorado City, Texas station on the West Texas Gulf Pipeline in June 2009. The Partnership has appealed the finding of violation and the proposed penalty. The timing or outcome of this appeal cannot be reasonably determined at this time.

In December 2010, PHMSA proposed penalties totaling $0.1 million for alleged violations of various pipeline safety requirements relating to our rights of way and equipment within the Crude Oil Pipelines segment. In January 2011, the Partnership paid the assessed fine and completed mandated corrective actions. The Partnership is awaiting a response from PHMSA.

There are certain other pending legal proceedings related to matters arising after the IPO that are not indemnified by Sunoco. Our management believes that any liabilities that may arise from these legal proceedings will not be material to our results of operations, financial position or expected cash flows at December 31, 2011.

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.

ITEM 4.

RESERVED

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 23, 2012, there were 78 holders of record of our common units. These holders of record included the general partner with 29.6 million common units registered in its name, and Cede & Co., a clearing house for stock transactions, with 69.8 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 and 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 2011 and 2010 were as follows:


	2011						2010
	Unit Price				Declared Distributions		Unit Price				Declared Distributions
Quarter	High		Low		Declared Distributions		High		Low		Declared Distributions
1^st	$	29.97	$	27.10	$	0.3983	$	24.11	$	20.73	$	0.3717
2^nd	$	30.34	$	26.00	$	0.4050	$	24.16	$	16.79	$	0.3800
3^rd	$	30.31	$	24.40	$	0.4133	$	26.38	$	23.50	$	0.3900
4^th	$	39.98	$	28.50	$	0.4200	$	28.06	$	24.08	$	0.3933

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 “Quarterly Cash Distribution Amount per Unit,” 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 (Please 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, the Operating Partnership issued a total of $500 million in 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 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 2 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.”

SUNOCO LOGISTICS PARTNERS L.P.


	Year Ended December 31,
	2011		2010		2009		2008		2007
	(in millions, except per unit data)
*Income Statement Data:*
Revenues:
Sales and other operating revenue:
Affiliates	$	432	$	1,117	$	706	$	2,572	$	1,682
Unaffiliated customers		10,473		6,691		4,696		7,540		5,695
Other income⁽¹⁾		13		30		28		24		28

Total revenues		10,918		7,838		5,430		10,136		7,405
Operating income		436		301		295		245		156
Gain on investments in affiliates		—		128		—		—		—
Income before income tax expense		347		356		250		214		121

Net Income		322		348		250		214		121
Net Income attributable to noncontrolling interests		9		2		—		—		—

Net Income attributable to Sunoco Logistics Partners L.P.	$	313	$	346	$	250	$	214	$	121


Net Income attributable to Sunoco Logistics Partners L.P. per Limited Partner unit:
Basic	$	2.56	$	3.13	$	2.17	$	2.06	$	1.13

Diluted	$	2.54	$	3.11	$	2.16	$	2.05	$	1.12

Cash distributions per unit to Limited Partners:⁽²⁾
Paid	$	1.61	$	1.51	$	1.37	$	1.22	$	1.11

Declared	$	1.64	$	1.54	$	1.40	$	1.26	$	1.13

*Other Data:*
Adjusted EBITDA⁽³⁾	$	544	$	366	$	343	$	291	$	193
Distributable Cash Flow⁽³⁾	$	388	$	248	$	266	$	236	$	134

⁽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 table reconciles the difference

between net income and net cash provided by operating activities, as determined under United States generally accepted accounting principles (“GAAP”), and Adjusted EBITDA and distributable cash flow:


	Year Ended December 31,
	2011			2010			2009			2008			2007
	(in millions)
Net Income attributable to Sunoco Logistics Partners L.P.	$	313		$	346		$	250		$	214		$	121
Interest cost, net		89			73			45			31			35
Depreciation and amortization expense		86			64			48			40			37
Impairment charge		31			3			—			6			—
Provision for income taxes		25			8			—			—			—
Gain on investments in affiliates		—			(128	)		—			—			—

Adjusted EBITDA⁽ⁱ⁾	$	544		$	366		$	343		$	291		$	193
Interest cost, net		(89	)		(73	)		(45	)		(31	)		(35	)
Maintenance capital expenditures		(42	)		(37	)		(32	)		(26	)		(25	)
Sunoco reimbursements		—			—			—			2			1
Provision for income taxes		(25	)		(8	)		—			—			—

Distributable cash flow	$	388		$	248		$	266		$	236		$	134


	Year Ended December 31,
	2011			2010			2009			2008			2007
	(in millions)
Net cash provided by operating activities	$	430		$	341		$	176		$	229		$	207
Interest cost, net		89			73			45			31			35
Amortization expense and bond discount		(2	)		(2	)		(2	)		(1	)		(1	)
Deferred income tax expense		2			—			—			—			—
Restricted unit incentive plan expense		(6	)		(5	)		(5	)		(4	)		(5	)
Regulatory charges excluded from impairment		(11	)		—			—			—			—
Net change in working capital pertaining to operating activities		35			(55	)		121			38			(40	)
Net proceeds from insurance recovery		—			—			—			—			(4	)
Provision for income taxes		25			8			—			—			—
Net Income attributable to noncontrolling interests		(9	)		(2	)		—			—			—
Other		(9	)		8			8			(2	)		1

Adjusted EBITDA⁽ⁱ⁾	$	544		$	366		$	343		$	291		$	193

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

⁽ⁱ⁾

Amounts exclude earnings attributable to noncontrolling interests and include an $11 million charge for regulatory obligations recognized in the fourth quarter 2011 in connection with our assessment of the impact on certain of our crude oil terminal assets by Sunoco’s decision to exit its refining business in the northeast. The total charge recognized for the impact was $42 million, which also included a $31 million non-cash impairment for asset write-downs at the Fort Mifflin Terminal Complex.

SUNOCO LOGISTICS PARTNERS L.P.


	Year Ended December 31,
	2011⁽¹⁾			2010⁽²⁾			2009⁽³⁾			2008⁽⁴⁾			2007⁽⁵⁾
	(in millions)
*Cash Flow Data:*
Net cash provided by operating activities	$	430		$	341		$	176		$	229		$	207
Net cash used in investing activities	$	(609	)	$	(426	)	$	(226	)	$	(332	)	$	(119	)
Net cash provided by (used in) financing activities	$	182		$	85		$	50		$	103		$	(95	)
Capital expenditures:
Maintenance⁽⁶⁾	$	42		$	37		$	32		$	26		$	25
Expansion⁽⁷⁾		171			137			144			120			82
Major acquisitions		396			252			50			186			13

Total capital expenditures	$	609		$	426		$	226		$	332		$	120

⁽¹⁾

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.

⁽²⁾

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.

⁽³⁾

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.

⁽⁴⁾

Cash flows related to major acquisitions in 2008 consists of $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.

⁽⁵⁾

Cash flows related to major acquisitions in 2007 consists of approximately $13 million related to the acquisition of the Syracuse Terminal. Expansion capital expenditures in 2007 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.

SUNOCO LOGISTICS PARTNERS L.P.


	Year Ended December 31,
	2011		2010		2009		2008		2007
	(in millions)
*Balance Sheet Data (at period end):*
Net properties, plants and equipment	$	2,522	$	2,128	$	1,534	$	1,375	$	1,089
Total assets	$	5,477	$	4,188	$	3,099	$	2,308	$	2,505
Total debt	$	1,698	$	1,229	$	868	$	748	$	515
Total Sunoco Logistics Partners L.P. Equity	$	1,096	$	965	$	862	$	670	$	591
Noncontrolling interests		98		77		—		—		—

Total equity	$	1,194	$	1,042	$	862	$	670	$	591

*Operating Data:*
Refined Products Pipelines⁽¹⁾⁽²⁾
Pipeline throughput (thousands of barrels per day)		522		468		577		510		491
Pipeline revenue per barrel (cents)		68.3		70.0		60.7		55.4		54.8
Terminal Facilities⁽³⁾
Terminal throughput (thousands of barrels per day)
Refined products terminals		492		488		462		436		434
Nederland Terminal		757		729		597		526		507
Refinery terminals		443		465		591		654		696
Crude Oil Pipelines^(1)(4)(5)
Pipeline throughput (thousands of barrels per day)		1,587		1,183		658		683		674
Pipeline revenue per barrel (cents)		55.0		50.7		77.5		68.5		49.6
Crude Oil Acquisition and Marketing⁽⁴⁾⁽⁶⁾
Crude oil purchases (thousands of barrels per day)		663		638		592		579		578
Gross margin per barrel purchased (cents)⁽⁷⁾		61.9		20.0		24.2		21.9		8.0
Average crude oil price (per barrel)	$	95.14	$	79.55	$	61.93	$	99.65	$	72.40

⁽¹⁾	Excludes amounts attributable to equity ownership interests in corporate joint ventures which are not consolidated.

⁽²⁾

⁽³⁾	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.

⁽⁴⁾

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.

⁽⁵⁾

⁽⁶⁾	Includes results from the crude oil acquisition and marketing business acquired from Texon L.P. in August 2011 from the acquisition date.

⁽⁷⁾	Represents total segment sales and other operating revenue minus cost of products sold and operating expenses and depreciation and amortization divided by crude oil pipeline throughput.

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 29 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 for refined products, crude oil and other hydrocarbons 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.

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 and, pursue strategic and accretive acquisitions that complement our existing asset base and improve operating efficiencies. 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, 2011, we completed eleven acquisitions for a total of $796 million.

2011 Acquisitions

•

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;

•

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. Total active storage capacity for the terminal is approximately 1 million barrels. The terminal was included in the Terminal Facilities 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 clean products and dark oils. The tank farm was included in the Terminal Facilities segment from the date of acquisition; and,

•

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 consists of a lease crude business and gathering assets in 16 states, primarily in the western United States. The current crude oil volume of the business is approximately 75,000 bpd at the wellhead. The business was included in the Crude Oil Acquisition and Marketing 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 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 L.P. The acquisition included patented technology for blending of butane into gasoline, contracts with customers currently utilizing the patented technology, butane inventories and other related assets. The acquisition was included within the Terminal Facilities as of the date of acquisition;

•

Controlling Financial Interest 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 our Nederland Terminal, and extends to Longview, Texas, where deliveries are made to several pipelines, including Mid-Valley. As we now have a controlling financial interest in both entities, each is reflected as a consolidated subsidiary as of the respective acquisition dates, and are included in the Crude Oil Pipelines; 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.

2009 Acquisitions

•

Romulus Terminal Acquisition—In September 2009, we acquired a refined products terminal located in Romulus, Michigan from R.K.A. Petroleum LLC. The terminal has storage capacity of less than a half of a million barrels and services the Detroit metropolitan area and has been integrated into our Terminal Facilities from the date of acquisition; and

•

Excel Pipeline LLC Acquisition—In September 2009, we acquired Excel Pipeline LLC (“Excel”) the owner of an approximately 50-mile crude oil pipeline in Oklahoma, from affiliates of Gary-Williams Energy Corporation (“Gary-Williams”). The system originates in Duncan, Oklahoma and terminates in Wynnewood, Oklahoma and has been operated by us since 2007. The pipeline has been included in our Crude Oil Pipelines from the date of acquisition.

Growth Capital Program

In 2011, we completed $171 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 2011, these 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.

During 2012, we expect to spend approximately $300 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, as well as Project Mariner West and the West Texas crude expansion. A summary of our previously announced growth projects is as follows:

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 received binding commitments in an open season to 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 underway and we expect operations to commence by July 2013.

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”). The West Texas Crude Expansion is expected to add a minimum 100,000 barrels per day of capacity and will utilize existing pipelines. The project is expected to be completed by the first quarter 2013. In February 2012, we commenced an Open Season for these pipelines, which will serve to prioritize service for shippers making long-term volume commitments.

Mariner East

We also continue to develop 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. We are currently in the engineering phase of Project Mariner East.

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, 2011. For the quarter ended December 31, 2011, the distribution increased to $0.42 per common unit, ($1.68 annualized). The distribution for the fourth quarter of 2011 was paid on February 14, 2012.

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 2% 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 12 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 three years ended December 31, 2011:


	Year Ended December 31,
	2011		2010		2009
	(in millions)
Statements of Income
Sales and other operating revenue:
Affiliates	$	432	$	1,117	$	706
Unaffiliated customers		10,473		6,691		4,696
Other income		13		30		28

Total revenues		10,918		7,838		5,430

Cost of products sold and operating expenses		10,264		7,398		5,023
Depreciation and amortization expense		86		64		48
Impairment charge and related matters⁽¹⁾		42		3		—
Selling, general and administrative expenses		90		72		64

Total costs and expenses		10,482		7,537		5,135

Operating income		436		301		295
Net interest expense		89		73		45
Gain on investments in affiliates		—		128		—

Income before provision for income taxes	$	347	$	356	$	250
Provision for income taxes		25		8		—

Net Income	$	322	$	348	$	250
Net Income attributable to noncontrolling interests		9		2		—

Net Income attributable to Sunoco Logistics Partners L.P.	$	313	$	346	$	250

Net Income attributable to Sunoco Logistics Partners L.P. per Limited Partner unit:
Basic	$	2.56	$	3.13	$	2.17

Diluted	$	2.54	$	3.11	$	2.16

⁽¹⁾

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. If arrangements for sale cannot be made, Sunoco intends to permanently idle the facilities by July 2012. We assessed the impact

that Sunoco’s decision to exit its refining business in the northeast will have on our assets that have historically served the refineries and we recognized a $42 million charge in the fourth quarter 2011 for certain crude oil terminal assets which would be negatively impacted if the refineries are permanently idled. The charge includes a $31 million non-cash impairment for asset write-downs at the Fort Mifflin Terminal Complex and $11 million for regulatory obligations which would be incurred if these terminal assets are permanently idled.

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 it 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, 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. 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 difference between net income and net cash provided by operating activities, as determined under GAAP, and Adjusted EBITDA and distributable cash flow:


	Year Ended December 31,
	2011			2010			2009
	(in millions)
Net Income attributable to Sunoco Logistics Partners L.P.	$	313		$	346		$	250
Interest cost, net		89			73			45
Depreciation and amortization expense		86			64			48
Impairment charge		31			3			—
Provision for income taxes		25			8			—
Gain on investments in affiliates		—			(128	)		—

Adjusted EBITDA⁽¹⁾	$	544		$	366		$	343
Interest cost, net		(89	)		(73	)		(45	)
Maintenance capital expenditures		(42	)		(37	)		(32	)
Sunoco reimbursements		—			—			—
Provision for income taxes		(25	)		(8	)		—

Distributable cash flow	$	388		$	248		$	266


	Year Ended December 31,
	2011			2010			2009
	(in millions)
Net cash provided by operating activities	$	430		$	341		$	176
Interest cost, net		89			73			45
Amortization expense and bond discount		(2	)		(2	)		(2	)
Deferred income tax expense		2			—			—
Restricted unit incentive plan expense		(6	)		(5	)		(5	)
Regulatory charges excluded from impairment		(11	)		—			—
Net change in working capital pertaining to operating activities		35			(55	)		121
Provision for income taxes		25			8			—
Net Income attributable to noncontrolling interests		(9	)		(2	)		—
Other		(9	)		8			8

Adjusted EBITDA⁽¹⁾	$	544		$	366		$	343

⁽¹⁾

Amounts exclude earnings attributable to noncontrolling interests and include an $11 million charge for regulatory obligations recognized in the fourth quarter 2011 in connection with our assessment of the impact on certain of our crude oil terminal assets affected by Sunoco’s decision to exit its refining business in the northeast. The total charge recognized for the impact was $42 million, which included a $31 million non-cash impairment for asset write-downs at the Fort Mifflin Terminal Complex.

Analysis of Consolidated Operating Results

Net income attributable to the partnership interests was $313, $346 and $250 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Net income attributable to partnership interests 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 be negatively impacted if Sunoco’s Philadelphia refinery is permanently idled. Excluding the gain and the charge, net income increased $137 million compared to 2010. Higher income from our operations was 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.

The $96 million increase in net income attributable to partnership interests from 2009 to 2010 was primarily the result of a $128 million non-cash gain on our acquisition of additional interests in Mid-Valley and West Texas Gulf. Excluding the gain, net income decreased $32 million compared to 2009, due to an increase in interest expense, related to debt issuances which were used to finance the IDR repurchase and exchange transaction and fund growth initiatives. Higher interest expense was partially offset by increased operating income associated primarily with improved Terminal Facilities volumes and contributions from acquisitions and organic projects.

Analysis of Operating Segments

We manage our operations through four operating segments: Refined Products Pipelines, Terminal Facilities, Crude Oil Pipelines and Crude Oil Acquisition and Marketing. Prior to 2011, our crude oil pipeline and crude oil acquisition and marketing operations were reported as a single Crude Oil Pipeline segment. For purposes of comparability, all prior year segment disclosures have been recast to conform to the current year presentation. Such recasts have no impact on previously reported consolidated net income.

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 6 states and Canada. Rates for shipments on these pipelines are regulated by the Federal Energy Commission (“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 for the three years ended December 31, 2011:


	Year Ended December 31,
	2011		2010		2009
	(in millions, except for barrel amounts)
Sales and other operating revenue
Affiliates	$	64	$	76	$	79
Unaffiliated customers		65		44		49
Intersegment revenue		1		—		—

Total sales and other operating revenue	$	130	$	120	$	128

Depreciation and amortization expense	$	17	$	15	$	13
Operating Income	$	33	$	44	$	45
Pipeline throughput (thousands of bpd)⁽¹⁾⁽²⁾		522		468		577
Pipeline revenue per barrel (cents)⁽²⁾		68.3		70.0		60.7

⁽¹⁾

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 has 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.

⁽²⁾	Excludes amounts attributable to equity ownership interests in corporate joint ventures which are not consolidated.

Operating income for the Refined Products Pipelines decreased $11 million to $33 million for the year ended December 31, 2011. The decrease in operating income was partially offset by contributions from the acquisition of a controlling financial interest in the Inland pipeline system in the second quarter 2011 ($8 million). Excluding results from this acquisition, operating income 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. Further contributing to lower results in 2011 were the following:

•

decreased equity income from our joint venture pipelines ($2 million);

•

absence of one- time billing from 2010 ($2 million);

•

higher operating expenses ($3 million) driven largely by increased employee and maintenance costs, partially offset by decreased utility costs related to the volume reductions; and

•

higher selling, general and administrative expenses ($3 million), primarily associated with incentive compensation.

Operating income for the Refined Products Pipelines decreased $1 million to $44 million for the year ended December 31, 2010. The decrease was primarily related to lower pipeline volumes driven by refinery maintenance activity and the fourth quarter 2009 closure of Sunoco’s Eagle Point, New Jersey refinery ($17 million) and increased depreciation expense related to various capital projects ($2 million). Partially offsetting these reductions were higher pipeline fees ($9 million), higher equity income from our joint venture interests ($4 million), and reduced operating expenses driven by increased operating gains and reduced utility, environmental and tax expenses ($5 million).

Terminal Facilities

Our Terminal Facilities segment consists primarily of crude oil and refined product terminals and a refined product 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 for the three years ended December 31, 2011:


	Year Ended December 31,
	2011⁽¹⁾		2010		2009
	(in millions, except for barrel amounts)
Sales and other operating revenue
Affiliates	$	115	$	122	$	100
Unaffiliated customers		297		142		91
Intersegment revenue		23		23		16

Total sales and other operating revenue	$	435	$	287	$	207
Depreciation and amortization expense	$	34	$	26	$	19
Operating Income	$	85	$	95	$	84
Terminal throughput (thousands of bpd)
Refined products terminals		492		488		462
Nederland Terminal		757		729		597
Refinery terminals		443		465		591

⁽¹⁾	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.

Operating income for the Terminal Facilities decreased $10 million to $85 million for the year ended December 31, 2011. The decrease in operating income from 2010 was due to a $42 million charge taken in the fourth quarter 2011 for certain crude oil terminal assets which would be negatively impacted if Sunoco’s Philadelphia refinery is permanently idled. The charge includes a $31 million non-cash impairment for asset write-downs at the Fort Mifflin Terminal Complex and $11 million for regulatory obligations which would be incurred if these terminal assets are permanently idled. Excluding this charge, operating income increased by $32 million compared to 2010 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 refined products terminal ($4 million) and higher volumes and fees from our Nederland Terminal ($4 million).

Operating income for the Terminal Facilities increased $11 million from $84 million for the year ended December 31, 2009 to $95 million for the year ended December 31, 2010. The increase in income was due primarily to higher volumes and fees at the refined products terminals ($10 million), additional volumes at the Nederland Terminal ($10 million) and increased refined products acquisition and marketing activities in 2010 ($7 million). These increases were partially offset by a non-cash impairment charge of $3 million related to the cancellation of a construction project and reduced refinery terminal volumes driven by the permanent shut-down of Sunoco’s Eagle Point refinery. Increased depreciation and amortization expenses associated with organic growth projects and acquisitions further offset the improved performance.

Crude Oil Pipelines

Our Crude Oil Pipelines 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 for the three years ended December 31, 2011:


	Year Ended December 31,
	2011⁽¹⁾		2010⁽¹⁾		2009⁽¹⁾
	(in millions, except for barrel amounts)
Sales and other operating revenue
Affiliates	$	6	$	25	$	25
Unaffiliated customers		196		117		68
Intersegment revenue		117		79		92

Total sales and other operating revenue	$	319	$	221	$	185
Depreciation and amortization expense	$	25	$	21	$	14
Operating Income	$	181	$	126	$	123
Pipeline throughput (thousands of bpd)⁽²⁾⁽³⁾		1,587		1,183		658
Pipeline revenue per barrel (cents)⁽²⁾⁽³⁾		55.0		50.7		77.5

⁽¹⁾

⁽²⁾

⁽³⁾	Excludes amounts attributable to equity ownership interests in corporate joint ventures which are not consolidated.

Operating income for the Crude Oil Pipelines increased $55 million to $181 million for the year ended December 31, 2011. The increase in operating income was driven primarily by full year results of the 2010 acquisitions of controlling financial interests in the Mid-Valley and West Texas Gulf pipelines ($30 million) 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.

Operating income increased for the Crude Oil Pipelines by $3 million to $126 million for the year ended December 31, 2010. The increase in operating income was driven primarily by contributions from the acquisitions of additional interests in the Mid-Valley and West Texas Gulf pipelines and the Excel pipeline ($19 million). These increases were partially offset by lower pipeline volumes on our wholly owned pipelines ($13 million), increased depreciation associated with capital projects ($2 million) and increased tax expenses ($1 million).

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 margin, 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 margin 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 margin, which is equal to sales and other operating revenue less cost of products sold, operating expenses and depreciation and amortization, 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 three years ended December 31, 2011:


	Year Ended December 31,
	2011⁽¹⁾⁽²⁾		2010⁽¹⁾		2009⁽¹⁾
	(in millions, except for barrel amounts)
Sales and other operating revenue
Affiliates	$	247	$	894	$	502
Unaffiliated customers		9,915		6,388		4,488
Intersegment revenue		1		—		—

Total sales and other operating revenue	$	10,163	$	7,282	$	4,990

Depreciation and amortization expense	$	10	$	2	$	2
Operating Income	$	137	$	36	$	43
Crude oil purchases (thousands of bpd)		663		638		592
Gross margin per barrel purchased (cents)⁽³⁾		61.9		20.0		24.2
Average crude oil price (per barrel)	$	95.14	$	79.55	$	61.93

⁽¹⁾

⁽²⁾	Includes results from the crude oil acquisition and marketing business acquired from Texon L.P. in August 2011 from the acquisition date.

⁽³⁾	Represents total segment sales and other operating revenue minus cost of products sold and operating expenses and depreciation and amortization, divided by crude oil purchases.

Operating income for the Crude Oil Acquisition and Marketing segment in 2011 increased $101 million to $137 million compared to the prior year period. The increase in operating income 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 L.P., 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.

Operating income for the Crude Oil Acquisition and Marketing segment in 2010 decreased $7 million to $36 million compared to the prior year period. The decrease in operating income was driven primarily by reduced crude oil margins ($10 million) which were partially offset by increased volumes ($4 million).

Liquidity and Capital Resources

Liquidity

Cash generated from operations and borrowings under our $550 million of credit facilities are our primary sources of liquidity. At December 31, 2011, we had net working capital deficit of $29 million and available borrowing

capacity under the credit facilities of $550 million. The primary driver of the working capital deficit is an increase in current liabilities related to $250 million of 7.25 percent Senior Notes, which matured and were repaid in February 2012. 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. If the inventories had been valued at their current replacement cost, we would have had working capital of $167 million at December 31, 2011. We periodically supplement our cash flows from operations with proceeds from debt and equity financing activities.

Capital Resources

Credit Facilities

In August 2011, we replaced our existing $458 million of credit facilities with two new credit facilities totaling $550 million. The new credit facilities consist of 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”).

The $350 million Credit Facility is available to fund the Operating Partnership’s working capital requirements, to finance acquisitions, to finance capital projects and for general partnership purposes. The $350 million Credit Facility matures in August 2016 and may be prepaid at any time. It bears interest at LIBOR or the Base Rate (defined as the highest of (a) the Federal Funds Rate plus 0.50%, (b) the Citibank prime rate or (c) LIBOR plus an applicable margin) or the Federal Funds Rate (each plus the applicable margin).

The $200 million Credit Facility, entered into by Sunoco Partners Marketing & Terminals LP (a wholly-owned subsidiary of the Partnership), is available to fund certain inventory activities. The $200 million Credit Facility matures in August 2012 and may be prepaid at any time. It bears interest at LIBOR or Base Rate (defined as the highest of (a) the Federal Funds Rate plus 0.50%, (b) the Citibank prime rate or (c) LIBOR plus an applicable margin) (each plus the applicable margin).

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 to Adjusted EBITDA was 3.13 to 1 at December 31, 2011, as calculated in accordance with the bank covenants.

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

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 2022 and 2042 Senior Notes are redeemable, at a make-whole premium, and are not subject to sinking fund provisions. The 2022 and 2042 Senior Notes contain various covenants limiting our ability to incur certain liens, engage in sale/leaseback transactions, or merge, consolidate or sell substantially all of our assets. The net proceeds of $595 million from the 2022 and 2042 Senior Notes were used to pay down the outstanding borrowings under our prior $63 and $395 million revolving credit facilities, which were used to fund the acquisitions of a controlling financial interest in Inland, 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 15, 2020 and February 15, 2040, respectively (“2020 and 2040 Senior Notes”). The 2020 and 2040 Senior Notes are redeemable, at a make-whole premium, and are not subject to sinking fund provisions. The 2020 and 2040 Senior Notes contain various covenants limiting our

ability to incur certain, engage in sale/leaseback transactions, or merge, consolidate or sell substantially all of our assets. The net proceeds from the 2020 and 2040 Senior Notes were used to repay the $201 million promissory note issued in connection with our repurchase and exchange of our general partner’s IDR interests, to repay outstanding borrowings under the prior $395 million Credit Facility and for general partnership purposes.

Equity Offerings

In July 2011, we issued Class A Units with an estimated fair value of $98 million to Sunoco in connection with the acquisition of the Eagle Point tank farm and related assets. The 3.9 million units are a new class of units that are not entitled to receive quarterly distributions and that will convert to common units, on a one-to-one basis, on the one-year anniversary of their issuance. Given that this was a related party transaction, GAAP required this issuance to be recorded at the net of Sunoco’s historical carrying value of the assets acquired ($22 million) and our $2 million cash payment.

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 prior $395 million credit facility. In connection with this offering, the General Partner contributed $3 million to the Partnership to maintain its 2 percent general partner interest.

In April and May 2009, we completed a public offering of 6.7 million limited partnership units. Net proceeds of $110 million were used to reduce outstanding borrowings under the prior $395 million Credit Facility and for general partnership purposes. In connection with this offering, the general partner contributed $2 million to the Partnership to maintain its 2 percent general partner interest.

Cash Flows and Capital Expenditures

Net cash provided by operating activities for the years ended December 31, 2011, 2010 and 2009 was $430, $341 and $176 million, respectively. 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 were non-cash charges of depreciation and amortization of $86 million and a $42 million charge, which is comprised of a $31 million asset impairment for crude oil terminal assets which are expected to be negatively impacted by the idling of Sunoco’s Philadelphia refinery and $11 million for regulatory obligations which would be incurred if these assets are permanently idled along with the refinery. These increases were partially offset by a $35 million increase in working capital. The change in working capital was primarily the result 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 of 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 provided by operating activities for 2009 was primarily the result of net income of $250 million and depreciation and amortization of $48 million, offset by an increase working capital of $121 million, which was the result of an increase in accounts receivable associated with liquidation of contango inventory positions.

Net cash used in investing activities for the years ended December 31, 2011, 2010 and 2009 was $609, $426 and $226 million, respectively. Investing activities in 2011 included $396 million of acquisitions, including a crude oil acquisition and marketing business from Texon; a controlling financial interest in Inland; a refined products terminal located in East Boston, Massachusetts and the Eagle Point tank farm. In addition to acquisitions, investments 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. Investing activities

in 2010 included $252 million of acquisitions, including a butane blending business; a controlling financial interest in Mid-Valley and West Texas Gulf; an additional ownership interest in West Shore; a refined products and crude oil terminal in Bay City, Texas and a refined products terminal and pipeline segment in Big Sandy, Texas. Also included in the cash used in investing activities for 2010 are expansion capital costs related to construction projects to expand services at our refined products terminals, increase tankage at the Nederland facility and expand on our refined products platform in the southwest United States. In 2009, cash used in investing activities included $50 million for the Romulus, Michigan terminal and Excel Pipeline acquisitions, as well as construction costs associated with the completion of the project to connect the Nederland Terminal to Motiva’s Port Arthur, Texas refinery, construction of additional storage tanks at Nederland and refined products butane blending projects.

Net cash provided by financing activities for the years ended December 31, 2011, 2010 and 2009 was $182, $85 and $50 million, respectively.

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 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 partners IDRs. Cash provided by these sources were further offset by $189 million of quarterly distributions to the limited and general partners and $238 million of net repayments under our prior $395 million Credit Facility.

For the year ended December 31, 2009, the $50 million of cash provided by financing activities was primarily attributable to net proceeds of $173 million related to the February 2009 issuance of 8.75 percent senior notes and $110 million of net proceeds from the April and May offering of 6.7 million common units. These sources were partially offset by $173 million of distributions and $54 million of net repayments under our prior $395 million Credit Facility. Cash provided by financing activities was primarily used to fund the 2009 expansion capital.

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, 2011 and 2010 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 years presented:


	Year Ended December 31,
	2011		2010		2009
	(in millions)
Maintenance	$	42	$	37	$	32
Expansion		171		137		144
Major Acquisitions		396		252		50

Total	$	609	$	426	$	226

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 $50 million in 2012.

Expansion capital expenditures increased by $34 million to $171 million for the year ended December 31, 2011. Expansion capital for 2011 includes 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. Expansion capital expenditures for 2009 included the construction pursuant to our agreement to connect our Nederland Terminal to a Port Arthur, Texas refinery. Expansion capital also included butane blending projects and construction of additional crude oil storage tanks at Nederland.

Major acquisitions during the year ended December 31, 2011 include the East Boston 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. Major acquisitions during the year ended December 31, 2009 included a refined products terminal in Romulus, Michigan and the Excel pipeline.

Management expects to invest approximately $300 million in expansion capital projects in 2012, excluding acquisitions. Projected expansion capital includes projects to capture more value from existing assets such as Eagle Point, Nederland and our patented butane blending technology, as well as the previously announced Project Mariner West and the West Texas crude expansion projects.

We expect to fund our capital expenditures, including any additional acquisitions, from cash provided by operations and, to the extent necessary, from the proceeds of borrowing under the credit facilities, other borrowings and issuance of additional common units.

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, 2011:


	Year Ended December 31,
	2012		2013		2014		2015		2016		Thereafter		Total
	(in millions)
Long-term debt:
Principal	$	250	$	—	$	175	$	—	$	175	$	1,100	$	1,700
Interest		91		89		76		74		67		970		1,367
Operating leases		6		4		4		3		2		3		22
Purchase obligations		2,491		—		—		—		—		—		2,491

	$	2,838	$	93	$	255	$	77	$	244	$	2,073	$	5,580

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 group and non-cancelable contracts to purchase butane for terms of one year or less by our butane blending business.

Substantially all of the above purchase obligations include actual crude oil purchases for the month of January 2012. 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, 2011 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 10 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 Sunoco.”

For more information concerning environmental matters, please 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 1 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 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.

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 2011, we recognized a $42 million charge for certain crude oil terminal assets which would be negatively impacted if Sunoco permanently idles its Philadelphia refinery. The charge includes a $31 million non-cash impairment for asset write-downs at the Fort Mifflin Terminal Complex and $11 million for regulatory obligations which would be incurred if these assets are permanently idled. For further discussion see “Agreements with Sunoco” discussed below. In 2010, we recognized an impairment of $3 million related to the cancellation of a terminal construction project. There were no asset impairments for the year ended December 31, 2009.

Environmental Remediation. At December 31, 2011, our accrual for environmental remediation activities was $4 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, 2011. 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 Sunoco” for more 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 the 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, 2011, see Note 1 to the consolidated financial statements included in Item 8. “Financial Statements and Supplementary Data.”

Agreements with Sunoco

We have entered into material agreements with Sunoco and their affiliates, as discussed below.

Pipeline and Terminalling Agreements

•

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 is expected to be renegotiated during the first quarter 2012.

•

We have a tank farm agreement under which Sunoco may throughput refined products through our Marcus Hook tank farm. The agreements contain no minimum throughput obligations for Sunoco. The agreement was extended on a month to month basis beginning in February 2012.

•

We have an agreement with Sunoco relating to the Fort Mifflin Terminal Complex. Under this agreement, Sunoco will deliver a minimum average of 300,000 bpd of crude oil and refined products per contract year at the Fort Mifflin Terminal Complex. This minimum average throughput is an annual amount for each contract period running from March 1 to February 28. Sunoco 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 Sunoco to meet its minimum requirements under the agreement. This agreement was extended on a month to month basis beginning in February 2012.

•

We have a three-year agreement with Sunoco to provide approximately 2.5 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.

•

Under a 20-year lease agreement which expires in February 2022, Sunoco leases our interrefinery pipelines between Sunoco’s Philadelphia and Marcus Hook refineries for an annual fee which escalates at 1.67 percent each January 1 for the term of the agreement. The lease agreement also requires Sunoco 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 2009 through 2011.

•

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.

•

We have an agreement with Sunoco whereby Sunoco purchases from us, at market-based rates, refined products at certain of our terminal facilities. This agreement is negotiated annually and the current agreement expires in May 2012.

During 2011, Sunoco continued executing its strategy to exit its refining operations, which included selling its Toledo, Ohio refinery in March 2011 and initiating a process in September 2011 to sell its northeast refineries located in Philadelphia and Marcus Hook, Pennsylvania. In December 2011, the main processing units at the Marcus Hook refinery were idled indefinitely. Sunoco continues to pursue a sale of both the Philadelphia and Marcus Hook facilities, however Sunoco does not believe that the Marcus Hook facility will be sold and restarted as an operating refinery. If arrangements for sale cannot be made, Sunoco intends to permanently idle the facilities by July 2012. We assessed the impact that Sunoco’s decision to exit its refining business in the northeast will have on our assets that have historically served the refineries and determined that our refined products pipeline and terminal assets continue to have expected future cash flows that support their carrying values. However, we recognized a $42 million charge in the fourth quarter 2011 for crude oil terminal assets which would be negatively impacted if the Philadelphia refinery is permanently idled. The charge includes a $31 million non-cash impairment for asset write-downs at the Fort Mifflin Terminal Complex and $11 million for regulatory obligations which would be incurred if these terminal assets are permanently idled.

Sunoco has also announced its intention to continue to grow its distribution and retail marketing assets. Our pipeline and terminal assets provide a cost effective and 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 reduces its use of our facilities, it could materially and adversely affect our results of operations, financial condition or cash flows. We continue to monitor how operating changes of these refineries will impact future cash flows.

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;

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Sunoco’s and its affiliates’ agreement not to compete with us under certain circumstances;

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our agreement to undertake to develop and construct or acquire an asset if requested by Sunoco;

•

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

Under the Omnibus Agreement, we pay Sunoco or our general partner 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 $13 million, $5 million and $6 million for the years ended December 31, 2011, 2010, and 2009, respectively. This fee does 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. We have no employees, and reimburse Sunoco and its affiliates for these costs and other direct expenses incurred on our behalf. In addition, we have incurred additional general and administrative costs which we pay directly.

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 of the following years and again for 2012. The 2012 annual fee has increased to $18 million to cover additional consolidation of services provided by Sunoco that were previously provided by third parties and includes an allocation of management costs for the Chief Executive Officer; Vice President, Chief Financial Officer; Vice President, Chief Human Resources Officer; and others from Sunoco that were previously included in our direct 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. There can be no assurance that Section 4.1 of the Omnibus Agreement will be extended beyond 2012, or that, if extended, the administrative fee charged by Sunoco will be at or below the current administrative fee. 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 income include the allocation of shared insurance costs of $4 million for each of the years ended December 31, 2011, 2010 and 2009. 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 $26, $29 and $28 million for the years ended December 31, 2011, 2010 and 2009, respectively. These expenses are reflected in cost of products sold and operating expenses and selling, general and administrative expenses in the consolidated statements of income.

Development or Acquisition of an Asset by the Partnership

The Omnibus Agreement contains a provision pursuant to which Sunoco may at any time propose to us that we undertake a project to develop and construct or acquire an asset. If our general partner determines in its good faith judgment, with the concurrence of its Conflicts Committee, that the project, including the terms on which Sunoco would agree to use such asset, will be beneficial on the whole and that proceeding with the project will not effectively preclude us from undertaking another project that will be more beneficial to us, we will be required to use commercially reasonable efforts to finance, develop, and construct or acquire the asset.

Noncompetition

Sunoco agreed, and will cause its affiliates to agree, for so long as Sunoco controls our general partner, not to engage in, whether by acquisition or otherwise, the business of purchasing crude oil at the wellhead or operating crude oil pipelines or terminals, refined products pipelines or terminals, or LPG terminals in the continental United States. This restriction does not apply to:

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certain businesses currently operated by Sunoco or any of its subsidiaries;

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any logistics asset constructed by Sunoco or any of its subsidiaries within a manufacturing or refining facility in connection with the operation of that facility;

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any business that Sunoco or any of its subsidiaries acquires or constructs that has a fair market value of less than $5 million; and

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any business that Sunoco or any of its subsidiaries acquires or constructs that has a fair market value of $5 million or more if we have been offered the opportunity to purchase the business for fair market value not later than six months after completion of such acquisition or construction, and we decline to do so with the concurrence of the Conflicts Committee.

In addition, the limitations on the ability of Sunoco and its affiliates to compete with us may terminate upon a change of control of Sunoco.

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.

License Agreement

We have granted to Sunoco and certain of its affiliates, including our general partner, a license to our intellectual property so that our general partner can manage its operations and create new intellectual property using our intellectual property. Our general partner will assign to us the new intellectual property it creates in operating our business. Our general partner has also licensed to us certain of its own intellectual property for use in the conduct of our business and we have licensed to our general partner certain intellectual property for use in the conduct of its business. The license agreement has also granted to us a license to use the trademarks, trade names, and service marks of Sunoco in the conduct of our business.

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 intercompany account. The intercompany balance will be 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.

Other Agreements

We have also entered into various other agreements with Sunoco and their affiliates, including throughput agreements regarding certain acquired assets or improvements or expansions of existing assets. Our management believes the terms of these agreements to be comparable to those that could be negotiated with an unrelated third party.

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, 2011, we had no 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, 2011, we had $1.70 billion of fixed-rate borrowings, which is comprised of $250 million of 2012 Senior Notes, $175 million of 2014 Senior Notes, $175 million of 2016 Senior Notes, $250 million of 2020 Senior Notes, $300 million of 2022 Senior Notes, $250 million of 2040 Senior Notes and, $300 million of 2042 Senior Notes. The fair value of these borrowings at December 31, 2011 was $1.91 billion. A hypothetical one-percent decrease in interest rates would increase the fair value of our fixed-rate borrowings at December 31, 2011 by $166 million.

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

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, 2011, the fair market value of our open derivative positions was a net asset of $4 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, 2011 was estimated to be $14 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 14 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, 2011. 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, 2011, 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.

Lynn L. Elsenhans

Chairman and Chief Executive Officer

Brian P. MacDonald

Vice President and 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, 2011, 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, 2011, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2011 consolidated financial statements of Sunoco Logistics Partners L.P. and our report dated February 24, 2012 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Philadelphia, Pennsylvania

February 24, 2012

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, 2011 and 2010, and the related consolidated statements of income, equity, and cash flows for each of the three years in the period ended December 31, 2011. 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, 2011 and 2010, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, 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, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2012 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Philadelphia, Pennsylvania

February 24, 2012

SUNOCO LOGISTICS PARTNERS L.P.

CONSOLIDATED STATEMENTS OF INCOME

(in millions, except units and per unit amounts)


	Year Ended December 31,
	2011			2010			2009
Revenues
Sales and other operating revenue:
Affiliates (Note 3)	$	432		$	1,117		$	706
Unaffiliated customers		10,473			6,691			4,696
Other income		13			30			28

Total Revenues		10,918			7,838			5,430

Costs and Expenses
Cost of products sold and operating expenses		10,264			7,398			5,023
Depreciation and amortization expense		86			64			48
Impairment charge and related matters		42			3			—
Selling, general and administrative expenses		90			72			64

Total Costs and Expenses		10,482			7,537			5,135

Operating Income		436			301			295
Net interest cost to affiliates (Note 3)		3			2			—
Other interest cost and debt expense, net		93			76			49
Capitalized interest		(7	)		(5	)		(4	)
Gain on investments in affiliates (Note 2)		—			128			—

Income Before Provision for Income Taxes	$	347		$	356		$	250
Provision for income taxes (Note 1)		25			8			—

Net Income	$	322		$	348		$	250
Net Income attributable to noncontrolling interests		9			2			—

Net Income attributable to Sunoco Logistics Partners L.P.	$	313		$	346		$	250

Calculation of Limited Partners’ interest:
Net Income attributable to Sunoco Logistics Partners L.P.	$	313		$	346		$	250
Less: General Partner’s interest		(54	)		(48	)		(52	)

Limited Partners’ interest	$	259		$	298		$	198

Net Income attributable to Sunoco Logistics Partners L.P. per Limited Partner unit (Note 4):⁽¹⁾
Basic	$	2.56		$	3.13		$	2.17

Diluted	$	2.54		$	3.11		$	2.16

Weighted average Limited Partners’ units outstanding:⁽¹⁾
Basic		101.3			95.2			91.0

Diluted		101.8			95.7			91.6

⁽¹⁾	Reflects the fourth quarter 2011 three-for-one unit split.

(See Accompanying Notes)

SUNOCO LOGISTICS PARTNERS L.P.

CONSOLIDATED BALANCE SHEETS

(in millions)


	December 31,
	2011			2010
Assets
Current Assets
Cash and cash equivalents	$	5		$	2
Advances to affiliated companies (Note 3)		107			44
Accounts receivable, affiliated companies (Note 3)		—			154
Accounts receivable, net		2,188			1,536
Inventories (Note 5)		206			63

Total Current Assets		2,506			1,799

Properties, plants and equipment		3,234			2,799
Less accumulated depreciation and amortization		(712	)		(671	)

Properties, plants and equipment, net (Note 6)		2,522			2,128

Investment in affiliates (Note 7)		73			73
Goodwill (Note 8)		77			63
Intangible assets, net (Note 8)		277			109
Other assets		22			16

Total Assets	$	5,477		$	4,188

Liabilities and Equity
Accounts payable	$	2,111		$	1,591
Current portion of long-term debt (Note 9)		250			—
Accrued liabilities		112			76
Accrued taxes payable (Note 1)		62			44

Total Current Liabilities		2,535			1,711

Long-term debt, affiliated companies (Notes 3 & 9)		—			100
Long-term debt (Note 9)		1,448			1,129
Other deferred credits and liabilities		78			42
Deferred income taxes (Note 1)		222			164
Commitments and contingent liabilities (Note 10)

Total Liabilities		4,283			3,146

Equity
Sunoco Logistics Partners L.P. equity
Limited Partners’ interest (99,386,301 and 99,197,496 units outstanding, respectively)⁽¹⁾		1,039			940
General Partner’s interest		34			28
Class A interest (3,939,435 and 0 units outstanding, respectively)⁽¹⁾		22			—
Accumulated other comprehensive gain/(loss)		1			(3	)

Total Sunoco Logistics Partners L.P. equity		1,096			965

Noncontrolling interests		98			77

Total Equity		1,194			1,042

Total Liabilities and Equity	$	5,477		$	4,188

⁽¹⁾	Reflects the fourth quarter 2011 three-for-one unit split.

(See Accompanying Notes)

SUNOCO LOGISTICS PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)


	Year Ended December 31,
	2011			2010			2009
Cash Flows from Operating Activities:
Net Income	$	322		$	348		$	250
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization expense		86			64			48
Impairment charge and related matters		42			3			—
Deferred income tax expense		(2	)		—			—
Amortization of financing fees and bond discount		2			2			2
Restricted unit incentive plan expense		6			5			5
Gain on investments in affiliates		—			(128	)		—
Changes in working capital pertaining to operating activities:
Accounts receivable, affiliated companies		154			(106	)		30
Accounts receivable, net		(647	)		(248	)		(627	)
Inventories		(108	)		38			3
Accounts payable and accrued liabilities		548			360			463
Accrued taxes payable		18			11			10
Other		9			(8	)		(8	)

Net cash provided by operating activities		430			341