Energy Transfer Operating, L.P. - FORM 10-K

Energy Transfer Operating, L.P. - FORM 10-K - February 23, 2010

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EX-10.6.1 - AMENDMENT NO. 2010-1 TO OMNIBUS AGREEMENT - Energy Transfer Operating, L.P.	dex1061.htm
EX-31.1 - SECTION 302 CEO CERTIFICATION - Energy Transfer Operating, L.P.	dex311.htm
EX-21.1 - SUBSIDIARIES OF SUNOCO LOGISTICS PARTNERS L.P. - Energy Transfer Operating, L.P.	dex211.htm
EX-12.1 - STATEMENT OF COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES - Energy Transfer Operating, L.P.	dex121.htm
EX-24.1 - POWER OF ATTORNEY - Energy Transfer Operating, L.P.	dex241.htm
EX-31.2 - SECTION 302 CFO CERTIFICATION - Energy Transfer Operating, L.P.	dex312.htm
EX-99.1 - AUDITED BALANCE SHEET - Energy Transfer Operating, L.P.	dex991.htm
EX-32.1 - SECTION 906 CEO & CFO CERTIFICATIONS - Energy Transfer Operating, L.P.	dex321.htm
EX-10.16 - INDEPENDENT DIRECTOR COMPENSATION SUMMARY SHEET - Energy Transfer Operating, L.P.	dex1016.htm
EX-10.15 - EXECUTIVE SUMMARY COMPENSATION SHEET - Energy Transfer Operating, L.P.	dex1015.htm
EX-23.1 - CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM - Energy Transfer Operating, L.P.	dex231.htm

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, 2009

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

For the transition period from to

Commission file number 1-31219

SUNOCO LOGISTICS PARTNERS L.P.

(Exact name of registrant as specified in its charter)


Delaware		23-3096839
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

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

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

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


Title of each class		Name of each exchange on which registered
Common Units representing limited partnership interests		New York Stock Exchange
Senior Notes 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 6.85%, due February 15, 2040		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 ¨ 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 approximately $1.02 billion as of June 30, 2009, based on $54.22 per unit, the closing price of the Common Units as reported on the New York Stock Exchange on that date.

At February 22, 2010, the number of the registrant’s Common Units outstanding was 31,047,272.

DOCUMENTS INCORPORATED BY REFERENCE: NONE

TABLE OF CONTENTS


PART I			3
	ITEM 1.	BUSINESS	3
	ITEM 1A.	RISK FACTORS	19
	ITEM 1B.	UNRESOLVED STAFF COMMENTS	30
	ITEM 2.	PROPERTIES	30
	ITEM 3.	LEGAL PROCEEDINGS	31
	ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS	31

PART II			32
	ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SECURITYHOLDER MATTERS AND PURCHASES OF EQUITY SECURITIES	32
	ITEM 6.	SELECTED FINANCIAL DATA	34
	ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	39
	ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	56
	ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	57
	ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	99
	ITEM 9A.	CONTROLS AND PROCEDURES	99
	ITEM 9B.	OTHER INFORMATION	99

PART III			100
	ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	100
	ITEM 11.	EXECUTIVE COMPENSATION	104
	ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SECURITYHOLDER MATTERS	135
	ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS	137
	ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	139

PART IV			140
	ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	140

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, included, but not limited to the following:

•

Our ability to successfully consummate announced acquisitions or expansions and integrate them into its 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, refined petroleum products and natural gas liquids that impact demand for our pipeline, terminalling and storage services;

•

Changes in the short-term and long-term demand for crude oil we both 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 petroleum products terminals, pipelines and crude oil 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 refined petroleum 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;

•

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;

•

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 it has 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 it has an ownership interest, is 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, operates and acquires a geographically diverse portfolio of complementary pipeline, terminalling, and crude oil acquisition and marketing assets. 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 approximately 33.2 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

We are principally engaged in the transport, terminalling and storage of refined products and crude oil and the purchase and sale of crude oil in 13 states located in the northeast, midwest and southwest United States. Sunoco accounted for approximately 13.1 percent of our total revenues for the year ended December 31, 2009.

On January 1, 2009 we re-aligned our reporting segments. Prior to this date, the reporting segments were designated by geographic region. We determined it more meaningful to functionally align our reporting segments. As such, the updated reporting segments as of January 1, 2009 are Refined Products Pipeline System, Terminal Facilities, and Crude Oil Pipeline System. The primary difference in the new reporting is the consolidation of approximately 120 miles of a crude oil pipeline formerly in the eastern pipeline system with the formerly western pipeline system. For comparative purposes all prior period amounts have been recast to reflect the new segment reporting and do not impact consolidated net income.

•

The Refined Products Pipeline System serves the United States operations of Sunoco and selected other third parties and consists of: approximately 2,200 miles of refined product pipelines, including a two-thirds undivided interest in the 80-mile refined product Harbor pipeline, and 60 miles of interrefinery pipelines between two of Sunoco’s refineries; a 9.4 percent interest in Explorer Pipeline Company, a joint venture that owns a 1,880-mile refined product pipeline; a 31.5 percent interest in Wolverine Pipe Line Company, a joint venture that owns a 720-mile refined product pipeline; a 12.3 percent interest in West Shore Pipe Line Company, a joint venture that owns a 650-mile refined product pipeline; and a 14.0 percent interest in Yellowstone Pipe Line Company, a joint venture that owns a 690-mile refined product pipeline.

•

The Terminal Facilities consist of 41 active refined product terminals with an aggregate storage capacity of 7.0 million shell barrels, primarily serving our Refined Product Pipeline System; the Nederland Terminal, a 19.6 million barrel marine crude oil terminal on the Texas Gulf Coast; a 2.0 million barrel refined product terminal serving Sunoco’s Marcus Hook refinery near Philadelphia, Pennsylvania; one inland and two marine crude oil terminals with a combined capacity of 3.4 million barrels, and related pipelines, which serve Sunoco’s Philadelphia refinery and; a 1.0 million barrel liquefied petroleum gas (“LPG”) terminal near Detroit, Michigan.

•

The Crude Oil Pipeline System gathers, purchases, sells, and transports crude oil principally in Oklahoma, Texas and Michigan and consists of approximately 3,350 miles of crude oil trunk pipelines, including a 37.0 percent undivided interest in the 80-mile Mesa Pipe Line system, and approximately 500 miles of crude oil gathering lines that supply the trunk pipelines; approximately 110 crude oil transport trucks; approximately 100 crude oil truck unloading facilities; a 55.3 percent economic interest (50 percent voting interest) in the Mid-Valley Pipeline Company, a joint venture that owns a 990-mile crude pipeline and a 43.8 percent interest in West Texas Gulf Pipe Line Company, a joint venture that owns a 580-mile crude oil pipeline.

Our primary business strategies are to generate stable cash flows, increase pipeline and terminal throughput, pursue strategic and accretive acquisitions and pursue economically accretive organic growth opportunities that complement our existing asset base and improve operating efficiencies. We also utilize our pipeline system to take advantage of market dislocations. We believe that these strategies will result in continuing increases in distributions to our unitholders.

For the year ended December 31, 2009, Sunoco accounted for approximately 61 percent of the Refined Product Pipeline segment’s total revenues, approximately 52 percent of the Terminal Facilities segment’s total revenues, and approximately 10 percent of the Crude Oil Pipeline System segment’s total revenues.

Refined Products Pipeline System

Refined Products Pipelines

We own and operate approximately 2,200 miles of refined products pipelines in selected areas of the United States. The refined products pipelines transport refined products from refineries in the northeast, midwest and southwest United States to markets in New York, New Jersey, Pennsylvania, Ohio, Michigan and Texas. The refined products transported in these pipelines include multiple grades of gasoline, middle distillates (such as heating oil, diesel and jet fuel) and liquefied petroleum gas (“LPGs”) (such as propane and butane). The Federal Energy Regulatory Commission (“FERC”) regulates the rates for interstate shipments on the Refined Products Pipeline System and the Pennsylvania Public Utility Commission (“PA PUC”) regulates the rates for intrastate shipments in Pennsylvania. We also lease to Sunoco three bi-directional, 18-mile interrefinery pipelines carrying feedstocks and jet fuel and a four-mile pipeline spur extending to the Philadelphia International Airport.

Our Refined Products Pipeline System includes the following assets acquired since December 31, 2006:

•

MagTex Refined Products Pipeline Acquisition. In November 2008, we acquired a refined products pipeline system and certain other real and personal property interests and assets located in Texas from an affiliate of Exxon Mobil Corporation. The system consists of approximately 480 miles of refined products pipelines originating in Beaumont and Port Arthur, Texas and terminating in Hearne and Waskom, Texas. The refined products transported in these pipelines include multiple grades of gasoline and middle distillates (such as diesel and jet fuel). The Texas Railroad Commission regulates the rates for intrastate shipments in Texas and the FERC regulates the rates for interstate shipments.

The following table details the total shipments on the refined products pipelines in each of the years presented. Total shipments represent the total average daily pipeline throughput multiplied by the number of miles of pipeline through which each barrel has been shipped. Our management believes that total shipments is a better performance indicator for the Refined Products Pipeline System than barrels transported as certain refined product pipelines such as transfer pipelines transport large volumes over short distances and generate minimal revenues. The following excludes amounts attributable to the interrefinery pipelines and equity ownership interests in the corporate joint ventures:

⁽¹⁾	Includes the results of acquired refined product pipelines from the acquisition date.

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 Pipeline System affect both the demand for, and the mix of, the refined products delivered through the Refined Products Pipeline System, although historically any overall impact on the total volume shipped has been short-term.

Explorer Pipeline

We own a 9.4 percent interest in Explorer Pipeline Company (“Explorer”), a joint venture that owns a 1,880-mile common carrier refined product pipeline. 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.

Wolverine Pipe Line

We own a 31.5 percent interest in Wolverine Pipe Line Company (“Wolverine”), a joint venture that owns a 720-mile common carrier pipeline that transports primarily refined products. 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.

West Shore Pipe Line

We own a 12.3 percent interest in West Shore Pipe Line Company (“West Shore”), a joint venture that owns a 650-mile common carrier refined product pipeline. The system, which is operated by CITGO, 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.

Yellowstone Pipe Line

We own a 14.0 percent interest in Yellowstone Pipe Line Company (“Yellowstone”), a joint venture that owns a 690-mile common carrier refined product pipeline. 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.

Terminal Facilities

Refined Products Terminals

Our 41 active refined products terminals receive refined products from pipelines, barges, rail, 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 refined products are transferred to or from storage or a transportation system, such as a pipeline, to another transportation system, such as trucks or another pipeline. The operation of these facilities is called “terminalling.” Terminals play a key role in moving product to the end-user market by providing the following services: storage; distribution; blending to achieve specified grades of gasoline; and other ancillary services that include the injection of additives and the filtering of jet fuel. Typically, our terminal facilities consist of multiple storage tanks and are equipped with automated truck loading equipment that is available 24 hours a day. This automated system provides for control of allocations, credit, and carrier certification.

Our refined products terminals include the following assets acquired since December 31, 2006:

•

Romulus Refined Products Terminal. In October 2009, we acquired a refined products terminal facility located in Romulus, MI from RKA Petroleum. Total active terminal storage capacity for this facility is approximately 0.4 million shell barrels.

•

MagTex Refined Products Terminals. In November 2008, we acquired five refined products terminal facilities located in Texas and Louisiana from affiliates of Exxon Mobil Corporation. Total active terminal storage capacity of these facilities is approximately 0.4 million shell barrels.

•

Our refined products terminals derive most of their 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 blending, injecting additives, and filtering jet fuel. Revenue is also derived through recovering and selling refined product that is accumulated through operating gains and transferred to the terminal facilities in accordance with certain contracts. Our refined product pipelines supply the majority of our refined product terminals, with third-party pipelines and barges supplying the remainder.

The table below sets forth the total average daily throughput for the refined product terminals in each of the years presented:

⁽¹⁾	Includes the results of acquired terminals from the acquisition date.

The following table outlines the number of active terminals and storage capacity in barrels (“bbls”) by state:


State	Number of Terminals	Storage Capacity
		(bbls)
Indiana	1	206,500
Maryland	1	717,100
Michigan	3	766,200
New Jersey	4	733,100
New York⁽¹⁾	4	920,300
Ohio	7	916,100
Pennsylvania	15	1,837,000
Virginia	1	403,800
Louisiana	1	160,500
Texas	4	375,000

Total	41	7,035,600

⁽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 represents the proportionate share of capacity attributable to our ownership interest.

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 shell storage capacity of approximately 19.6 million shell barrels in 138 aboveground storage tanks with individual capacities of up to 660,000 barrels. During 2009, we completed construction of four new tanks and the Port Arthur Network System (PANS) a crude oil pipeline from the Nederland terminal to Motiva’s Port Arthur, Texas refinery.

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 1.0 million bpd of crude oil. The terminal can also receive crude oil through a number of pipelines, including the Shell Houma to Houston pipeline from Louisiana, the Cameron Highway pipeline, which is jointly owned by Enterprise Products and Valero Energy, the ExxonMobil Pegasus pipeline, the Department of Energy (“DOE”) Big Hill pipeline, the DOE West Hackberry pipeline, and our Western Pipeline System. 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 370 million barrels.

The Nederland Terminal can deliver crude oil and other petroleum products via pipeline, barge, ship, rail, or truck. In the aggregate, the terminal is capable of delivering over 2.1 million bpd of crude oil to 13 connecting pipelines. The connecting pipelines include 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; the Shell pipeline to Houston, Texas refineries; West Texas Gulf and our pipelines to the Mid-Valley pipeline at Longview, Texas and to the CITGO pipeline at Sour Lake, Texas; our pipeline to Seabreeze, Texas; and our pipeline to the Alon Big Spring, Texas refinery and Midland, Texas.

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

Revenues are generated at the Nederland Terminal primarily by providing term or spot storage services and throughput capability to a number of customers. The majority of the terminal’s revenues in 2009 were from unaffiliated 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.

The Fort Mifflin Terminal consists of two ship docks with 40-foot freshwater drafts and nine tanks with a total storage capacity of approximately 570,000 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 26 tanks with a total storage capacity of approximately 2.9 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,
	2007	2008	2009
Crude oil throughput (bpd)	296,976	284,813	266,174
Refined products throughput (bpd)	13,972	14,914	13,721

Total (bpd)	310,948	299,727	279,895

Marcus Hook Tank Farm

The Marcus Hook Tank Farm stores substantially all of the gasoline and middle distillates that Sunoco ships from its Marcus Hook refinery. This facility has 16 tanks with a total storage capacity of approximately 2.0 million barrels. After receipt of refined products from the Marcus Hook refinery, the tank farm either stores or delivers them to our Twin Oaks terminal, to the Twin Oaks pump station, an origin location for the Refined Product Pipeline System or to a third party terminal via pipeline.

The table below sets forth the total average daily throughput for the Marcus Hook Tank Farm in each of the years presented:

Eagle Point Docks

The Eagle Point Docks are located on the Delaware River and are connected to the Sunoco Eagle Point refinery.They can accommodate three ships or barges and supplies the Eagle Point refinery with all of its crude oil. The docks can also receive and deliver crude oil, intermediate products and refined products to outbound ships and barges. On February 1, 2010 Sunoco announced its permanent shutdown of the Eagle Point refinery. Sunoco expects to continue to distribute refined products through our Eagle Point terminal. Our assets, including docks, terminals and pipelines, which provide logistics support to the Eagle Point refinery had a net book value of $62.0 million as of December 31, 2009 and generated revenues of $15.6 million for the year ended December 31, 2009. We do not expect the shutdown of the Eagle Point refinery to have a material impact on our operating results and continue to assess how changes in operating performance could impact the net book value of our assets. We did not recognize an impairment charge during 2009 as a result of the shutdown.

The table below sets forth the total average daily throughput for the Eagle Point Docks in each of the years presented:


	Year Ended December 31,
	2007	2008	2009
Crude oil throughput (bpd)	138,159	132,428	99,136
Refined products throughput (bpd)	100,649	93,433	82,250

Total (bpd)	238,808	225,861	181,386

Inkster Terminal

The Inkster Terminal, located near Detroit, Michigan, consists of eight salt caverns with a total storage capacity of approximately 975,000 barrels. We use the Inkster Terminal’s storage in connection with its Toledo, Ohio to Sarnia, Canada pipeline system and for the storage of LPGs from Sunoco’s Toledo refinery and from Canada. The terminal can receive and ship LPGs in both directions at the same time and has a propane truck loading rack.

Crude Oil Pipeline System

Crude Oil Pipelines

We own and operate approximately 3,350 miles of crude oil trunk pipelines and approximately 500 miles of crude oil gathering pipelines in Texas and Oklahoma which deliver crude oil and other feedstocks to points in Texas and Oklahoma. This also includes approximately 120 miles of crude oil pipeline originating in Michigan which delivers to points in Michigan and Ohio.

Our pipelines also 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 sets forth the average daily number of barrels of crude oil and other feedstocks transported on our crude oil pipelines in each of the years presented (excluding results from joint venture interests):

⁽¹⁾	Includes results from acquired crude oil pipeline systems from the acquisition dates.

Texas

We own and operate approximately 2,400 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 and West Texas Gulf pipelines which are 55.3 percent and 43.8 percent, respectively, owned by us, 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 Texas Railroad Commission and the FERC.

Oklahoma

We 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. During 2009, Sunoco completed the sale of its Tulsa refinery to an affiliate of Holly Corp. Effective with the closing of the sale, we entered into a long-term agreement with Holly Refining & Marketing MidCon, L.L.C. to sell crude oil to the Tulsa refinery in volumes expected to be commensurate with historical volumes supplied to Sunoco.

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.

Michigan and Ohio

We own approximately 120-miles of crude oil pipeline that runs from Marysville, Michigan to Toledo, Ohio. This pipeline receives crude oil from the Enbridge pipeline system for delivery to Sunoco and BP refineries located in Toledo, Ohio and to Marathon’s Samaria, Michigan tank farm, which supplies its refinery in Detroit, Michigan. Marysville is also a truck injection point for local production.

West Texas Gulf Pipe Line

We own a 43.8 percent interest in the West Texas Gulf Pipe Line Company (“West Texas Gulf”), a joint venture that owns a 580-mile common carrier crude oil pipeline. The system originates from the West Texas oil fields at Colorado City and the Nederland crude oil import terminals and extends to Longview, Texas where deliveries are made to several pipelines, including the Mid-Valley pipeline. We are also the operator of this system.

Mid-Valley Pipeline Company

We own a 100 percent interest in Sun Pipeline Company of Delaware LLC, the owner of a 55.3 percent equity interest (50 percent voting rights) in Mid-Valley Pipeline Company (“Mid-Valley”). Mid-Valley owns a 990-mile pipeline, which originates in Longview, Texas and terminates in Samaria, Michigan, and has operating capacity of approximately 238,000 bpd and 4.2 million barrels of shell storage capacity. Mid-Valley provides crude oil to a number of refineries, primarily in the midwest United States.

Crude Oil Acquisition and Marketing

In addition to receiving tariff revenues for transporting crude oil on the Crude Oil Pipeline System, we generate most of our revenues through our crude oil acquisition and marketing activities. These activities are primarily in Oklahoma and Texas and 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 profit;

•

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.

The crude oil acquisition and marketing operations generate substantial revenue and cost of products sold because they reflect the sales price and cost 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 its 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. Our management believes gross margin, which is equal to sales and other operating revenue less cost of products sold and operating expenses and depreciation and amortization, is a key measure of financial performance for the Crude Oil Pipeline System.

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.

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, 2009, we purchased 172,142 bpd from approximately 2,518 producers and from approximately 46,414 leases, and undertook 411,030 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,
	2007	2008	2009
	(in thousands of bpd)
Lease purchases:
Available for sale	164	167	172
Exchanged	14	10	9
Other exchanges and bulk purchases	400	402	411

Total Purchases	578	579	592

Sales:
Sunoco refineries:
Toledo	20	8	9
Tulsa	50	63	17
Third parties	166	200	205
Exchanges:
Purchased at the lease	14	10	9
Other	330	295	353

Total Sales	580	576	593

Crude Oil Price Volatility

Crude oil commodity prices have historically been volatile and cyclical. Profitability from our crude oil acquisition and marketing operations is dependent on our ability to sell crude oil at prices in excess of our aggregate cost. Although margins may be impacted during transition periods, 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.

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 current prices. A contango market generally has a negative impact on our lease gathering margins, but is favorable to commercial strategies associated with tankage. Access to crude oil storage during a contango market allows us to simultaneously purchase crude oil inventories at current prices for storage and sell 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 current prices. 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.

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 segment.

When the market is in contango, we will use our storage capabilities to improve our lease gathering margins by storing crude oil we have purchased for delivery in future months that are selling at higher prices. In a

backwardated market, increased lease gathering margins provide an offset to reduced use of storage capacity. This combination of lease gathering activities and integrated assets within the Crude Oil Pipeline System and Terminal Facilities segment, improve our ability to generate ratable cash flows in various market conditions.

Crude Oil Trucking

We own approximately 100 crude oil truck unloading facilities in Oklahoma, Texas, and New Mexico, the majority of which are located on our pipeline system. Approximately 210 crude oil truck drivers are used by a subsidiary of our general partner and approximately 110 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 Product Pipeline System, and the Sugar Land control center primarily monitors and controls our Crude Oil Pipeline System. 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 our 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

As a result of the physical integration with Sunoco, we believe that we will not face significant competition for crude oil transported to the Philadelphia and Toledo refineries, or refined products transported from the Philadelphia, Marcus Hook and Toledo, refineries. For further information on related party agreements, see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Agreements with Sunoco.” For the year ended December 31, 2009, Sunoco accounted for approximately 13.1 percent of our total revenues.

Refined Products Pipeline System

Nearly all of the Refined Products Pipeline System located in the northeast and midwest United States is directly linked to Sunoco’s refineries. Sunoco constructed or acquired these assets as the most cost-effective means to access raw materials and distribute refined products. 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 served 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 Pipeline System 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, the existing pipelines have the capacity to satisfy expected future demand.

In addition, we, including our interests in corporate joint ventures, 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 that are served by trucks. The availability of truck transportation places a significant competitive constraint on our ability to increase tariff rates.

Terminal Facilities

Historically, except for the Nederland Terminal, essentially the entire throughput at the Terminal facilities located in the northeast and midwest has come from Sunoco. We expect to continue receiving a significant portion of the throughput at these facilities from Sunoco. The primary competitors for the Nederland Terminal are its refinery customers’ docks and other terminal facilities, located in the Beaumont, Texas area.

The 41 active refined product terminals compete with other independent terminals regarding 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.

Crude Oil Pipeline System

The Crude Oil Pipeline System faces competition from a number of major oil companies and smaller entities. Competition among common carrier pipelines is based primarily on transportation charges and access to crude oil supply and 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 the Crude Oil Pipeline System, however changes in refiners’ supply sources may negatively impact existing throughput on the Crude Oil Pipeline System. Crude oil purchasing 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 regulation 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.

Our management believes 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 our management does not believe they would likely have a material adverse effect relative to our financial position.

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 not insured, 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. 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. In addition, this indemnification applies to the interests in the Mesa Pipeline system and the Mid-Valley Pipeline purchased from Sunoco following the IPO. 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 February 8, 2002, 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, 2009, all material environmental liabilities incurred by, and known to, us are either covered by the environmental indemnification or reserved for by us within our 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 is currently reviewing various legislative and regulatory proposals relating to restrictions on emissions of greenhouse gases, or GHGs. While the effect of these various proposals cannot be predicted, the adoption of any 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. As a result of these regulations, they 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 ability to make distributions or satisfy its 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 are 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 analogous 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. The Federal Water Pollution Control Act of 1972, also known as the Clean Water Act, and analogous 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 diking and similar structures 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 have 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 its financial condition or results of operations.

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 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, 2009. 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.

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 rules and orders promulgated pursuant thereto. 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 the Partnership’s, 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.

During 2006 and 2007, we were granted permission by the FERC to charge market-based rates in most of the refined products markets we serve. In those markets where market-based rates were 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 Railroad Commission of Texas, the Pennsylvania Public Utility Commission, and the Oklahoma Corporation Commission. The operations of our joint venture interests are also subject to regulation in the states in which they operate. The applicable state statutes require that pipeline rates be nondiscriminatory and provide no more than a fair return on the aggregate value of the pipeline property used to render services. State commissions generally have not been

aggressive in regulating common carrier pipelines or investigating 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 some 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 it upon the closing of the February 2002 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 all of the assets contributed in connection with the February 2002 IPO, or are entitled to indemnification from Sunoco under the Omnibus Agreement for title defects to these assets and for failures to obtain certain consents and permits necessary to conduct its business that arise within ten years after the closing of the February 2002 IPO. Record title to some of the assets may continue to be held by affiliates of Sunoco until we have made the appropriate filings in the jurisdictions in which such assets are located and obtained any consents and approvals that were not obtained prior to the closing of the February 2002 IPO. We expect that the title to all material assets will be transferred to us prior to the expiration of this ten year period for indemnification. 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

To carry out our operations, our general partner and its affiliates employed approximately 1,340 people at December 31, 2009 who provide direct support to the operations. Labor unions or associations represent approximately 640 of these employees at December 31, 2009. Our general partner considers its employee relations to be good. We have no employees.

(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, cash flows and financial condition, 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 for a substantial portion of the refined products transported on our 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 financial condition, results of operations or cash flows.

For the year ended December 31, 2009, Sunoco accounted for approximately 61 percent of our Refined Products Pipeline System total revenues, 52 percent of our Terminal Facilities total revenues, and 10 percent of our Crude Oil Pipeline System total revenues. The balance of our revenues was received from unaffiliated customers. We expect to continue to derive a substantial portion of our revenues from Sunoco for the foreseeable future.

Sunoco is a refiner and marketer of petroleum and petrochemical products that 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 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 financial condition, results of operations and cash flows. Further, if Sunoco were to significantly decrease the throughput transported on our pipelines or the volumes of crude oil or refined products handled at our other terminals, our financial condition, results of operations, and cash flows could be materially and adversely affected. Sunoco does not have any minimum throughput obligations at our refined products

terminals or the Marcus Hook Tank Farm. Sunoco currently has minimum storage and throughput obligation at our Fort Mifflin Terminal Complex and at our Inkster Terminal. Because our facilities are well situated to handle Sunoco’s refining and marketing supply chain needs we expect that Sunoco will continue to utilize our pipelines and terminals. However, if Sunoco reduces its use of our facilities, it could materially and adversely affect our financial condition, results of operations or cash flows.

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

The following are the 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 product 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;

•

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

•

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

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

The volume of crude oil transported in our crude oil pipelines depends on the availability of attractively priced crude oil produced in the areas accessible to our crude oil pipelines and received from other common carrier pipelines. A period of sustained crude oil price declines could lead to a decline in drilling activity and production levels or the shutting-in or abandonment of wells 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 from these areas. In either case, the volumes of crude oil transported in our pipelines 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 financial position, results of operations 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 financial position, results of operations 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 financial condition, results of operations 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;

•

unplanned increases in the cost of construction materials or labor;

•

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

•

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

•

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

•

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

•

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

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

Potential 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.

From time to time, 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 and the businesses associated with them and new geographic areas. 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, or 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 financial condition, results of operations 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 financial condition, results of operations 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 financial condition, results of operations or cash flows.

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

The primary rate-making methodology of the Federal Energy Regulatory Commission, or FERC, is price indexing. We use this methodology in many of our interstate markets. In an order issued March 21, 2006, FERC announced that, effective July 1, 2006, the index would equal the change in the producer price index for finished goods plus 1.3 percent (previously, the index was equal to the change in the producer price index for finished goods). This index is to be in effect through July 2011. 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.” Most of our revenues are derived from grandfathered rates on our FERC-regulated refined products pipelines. 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 complaining 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 financial condition, results of operations 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.

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

On June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009,” or “ACESA,” which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of carbon dioxide and other greenhouse gases (“GHG”) that may contribute to the warming of the

Earth’s atmosphere and other climatic changes. ACESA would require a 17 percent reduction in GHG emissions from 2005 levels by 2020 and just over an 80 percent reduction of such emissions by 2050. Under this legislation, the U.S. Environmental Protection Agency (“EPA”) would issue a capped and steadily declining number of tradable emissions allowances to certain major sources of GHG emissions so that such sources could continue to emit GHGs into the atmosphere. These allowances would be expected to escalate significantly in cost over time. The net effect of ACESA would be to impose increasing costs on the combustion of carbon-based fuels such as refined petroleum products, oil and natural gas. The U.S. Senate has begun work on its own legislation for restricting domestic GHG emissions and President Obama has indicated his support of legislation to reduce GHG emissions through an emission allowance system. At the state level, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of GHGs. Also, on December 15, 2009, the EPA published its findings that emissions of GHGs constitute an endangerment to public health and the environment. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Accordingly, the EPA has already proposed two sets of regulations that would require a reduction in emissions of GHGs from motor vehicles and could trigger permit review for GHG emissions from certain stationary sources. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, including facilities that emit more than 25,000 tons of GHGs on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010. Our facilities will not be subject to this September 22, 2009 EPA reporting requirement since our GHG emissions are below the applicable threshold; however, the adoption and implementation of any federal, regional or state laws or regulations limiting emissions of GHGs in the U.S. could adversely affect the demand for our crude oil or refined product transportation and storage services. Although it is not possible at this time to predict how pending legislation or new regulations that may be adopted to address GHGs would impact our business, any such future laws could 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 financial condition, results of operations or cash flows.

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 cannot remove our general partner without its consent, which could lower the trading price of the common units.

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 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.

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

Our general partner may 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 choices.

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, which owns a 2 percent general partner interest, a 31.2 percent limited partner interest and owns all of our incentive distribution rights. 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:

•

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;

•

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;

•

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

•

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;

•

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;

•

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;

•

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

•

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

•

our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, 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 indirectly owns approximately 31.2 percent of our outstanding common units and all of our incentive distribution rights. 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 incentive distribution rights.

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 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 $5.0 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 $5.0 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:

•

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.

We may not be able to obtain funding, or obtain funding on acceptable terms, to meet our future capital needs because of the deterioration of the credit and capital markets.

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, 2009, our total outstanding long-term indebtedness was approximately $868.4 million. Our payment of principal and interest on the debt will reduce the cash available for distribution on our units, as

will our obligation to repurchase the senior notes upon the occurrence of specified events involving a change in control of our general partner. In addition, we are prohibited by our credit facilities and the senior notes from making cash distributions during an event of default, or if the payment of a distribution would cause an event of default, under any of our debt agreements. Our leverage and various limitations in our credit facilities and our senior notes may reduce our ability to incur additional debt, engage in some transactions, and capitalize on acquisition or other business opportunities. Any subsequent refinancing of our current debt or any new debt could have similar or greater restrictions.

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

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

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

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

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

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

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

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place us at a competitive disadvantage against less leveraged competitors.

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

As of December 31, 2009, we had $269.0 million of floating-rate debt. As a result, we have exposure to changes in short-term interest rates. Rising short-term rates could materially and adversely affect our financial condition, results of operations or cash flows.

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

We currently maintain an investment grade rating by Moody’s and by S&P. 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 or S&P 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 UNIT HOLDERS

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, or 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 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. Our termination would, among other things, result in the closing of our taxable year for all of our unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income.

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 foreign 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 United States 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 more than a dozen 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.

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

Sunoco Partners Marketing & Terminals L.P. (“SPMT”), which is our wholly owned subsidiary, has received a proposed penalty assessment from the Internal Revenue Service (“IRS”) in the aggregate amount of $5.1 million based on a failure to timely file excise tax information returns relating to its terminal operations during the calendar years 2004 and 2005. SPMT became current on its information return filings with the IRS in July of 2006. SPMT believes it had reasonable cause for the failure to not file the information returns on a timely basis, and provided this information to the IRS on October 19, 2007 in a formal filing. SPMT is currently awaiting a response from the IRS. The proposed penalties are for the failure to file information returns rather than any failure to pay taxes due, as no taxes were owed by SPMT in connection with such information. The timing or outcome of this claim, and the total costs to be incurred by SPMT in connection therewith, cannot be reasonably estimated at this time.

There are certain legal and administrative proceedings arising prior to the February 2002 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 February 2002 IPO.

Additionally, we have received notices for violations and potential fines under various federal, state or 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 January 2007, the Pipeline Hazardous Materials Safety Administration (PHMSA) proposed penalties totaling $0.2 million based on alleged violations of various pipeline safety requirements relating to our meter facilities in the Crude Oil Pipeline System. The Partnership has responded to this penalty assessment and is currently awaiting resolution.

In August 2009, the Pipeline Hazardous Materials Safety Administration (PHMSA) proposed penalties totaling approximately $0.2 million based on alleged violations of various pipeline safety regulations relating to the November 2008 product release by Sunoco Pipeline, L.P. in Murrysville, Pennsylvania. The Partnership has appealed the finding of violation and the proposed penalty. The timing or outcome of this appeal cannot reasonably be determined at this time.

In September 2009, PHMSA issued a final order for $0.2 million relating to a tank overfill incident that occurred at the Darby Creek Tank Farm in November 2005. In October 2009, PHMSA denied the Partnership’s request for reconsideration of this final decision and the Partnership subsequently paid the assessed fine.

There are certain other pending legal proceedings related to matters arising after the February 2002 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 financial position at December 31, 2009.

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS

None.

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 22, 2010, there were 91 holders of record of our common units. These holders of record included the general partner with 9,863,734 common units registered in its name, and Cede & Co. with 21,083,722 common units registered to it.

On February 1, 2010, we amended our registration statement for our limited partnership interests and debt securities. The amendment allows our general partner to sell in one or more offerings, the common units it owns under our registration statement. 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 2008 and 2009 were as follows:


	2008						2009
	Unit Price				Declared Distributions		Unit Price				Declared Distributions⁽¹⁾
Quarter	High		Low		Declared Distributions		High		Low		Declared Distributions⁽¹⁾
1^st	$	55.42	$	42.01	$	0.895	$	56.00	$	44.65	$	1.015
2^nd	$	54.39	$	46.27	$	0.935	$	56.60	$	49.10	$	1.040
3^rd	$	51.66	$	41.00	$	0.965	$	59.96	$	52.72	$	1.065
4^th	$	50.00	$	27.62	$	0.990	$	69.87	$	57.00	$	1.090

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 $0.45 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 $0.50 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 is existing, 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”).

partner of new incentive distribution rights 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 $201.2 million. On February 12, 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”. The new incentive distribution rights provide for target distribution levels and distribution “splits” between the general partner and the holders of our common units equal to those applicable to the cancelled incentive distribution rights, except that (i) the general partner’s distribution split for distributions above the current second target distribution of $0.575 per common unit per quarter (or $2.30 per common unit on an annualized basis) and up to the third target distribution will increase to 37% from 25% (these percentages include the general partners 2.0% interest); and (ii) the third target distribution will be increased from $0.70 to $1.5825 per common unit per quarter (or from $2.80 to $6.33 per common unit on an annualized basis).

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 incentive distribution rights and under the new incentive distribution rights:


	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	$	0.450	2	%	98	%
First Target Distribution	up to $	0.500	2	%	98	%		No change
Second Target Distribution	above $ up to $	0.500 0.575	15	%*	85	%
Third Target Distribution	above $ up to $	0.575 0.700	25	%*	75	%	above $0.575 up to $1.5825	37	%*	63	%
Thereafter	above $	0.700	50	%*	50	%	above $1.5825	50	%*	50	%

*	Includes 2 percent general partner interest.

ITEM 6.

SELECTED FINANCIAL DATA

For the periods presented, Sunoco was the primary or exclusive user of the refined products terminals located in the northeast and midwest, the Fort Mifflin Terminal Complex, the Eagle Point Dock and the Marcus Hook Tank Farm.

Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of the assets and to extend their useful lives. Expansion capital expenditures are capital expenditures made to acquire complementary assets to grow the business, to improve operational efficiencies or reduce costs and to expand existing and construct new facilities, such as projects that increase storage or throughput volume. We treat repair and maintenance expenditures that do not extend the useful life of existing assets as operating expenses as incurred.

Throughput is the total number of barrels per day transported on a pipeline system or through a terminal. Total shipments represent the total average daily pipeline throughput multiplied by the number of miles of pipeline through which each barrel has been shipped. Our management believes that total shipments is a better performance indicator for the Refined Products Pipeline System than throughput as certain refined products pipelines such as transfer pipelines, transport large volumes over short distances and generate minimal revenues.

The following table should be read together with, and is qualified in its entirety by reference to, the financial statements and the accompanying notes of Sunoco Logistics Partners L.P. included in Item 8. “Financial Statements and Supplementary Data”. The table 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,
	2005			2006			2007			2008			2009
	(in thousands, except per unit and operating data)
*Income Statement Data:*
Revenues:
Sales and other operating revenue:
Affiliates	$	1,986,019		$	1,842,634		$	1,682,042		$	2,571,947		$	705,511
Unaffiliated customers		2,496,593			3,994,601			5,695,413			7,540,373			4,696,293
Other income⁽⁶⁾		14,295			17,315			28,381			24,298			27,873

Total revenues		4,496,907			5,854,550			7,405,836			10,136,618			5,429,677

Costs and expenses:
Cost of products sold and operating expenses		4,326,713			5,644,021			7,156,142			9,786,014			5,023,307
Depreciation and amortization		33,838			36,649			37,341			40,054			48,020
Selling, general and administrative expenses		53,048			55,686			56,198			59,284			63,306
Impairment charge		—			—			—			5,674			—

Total costs and expenses		4,413,599			5,736,356			7,249,681			9,891,026			5,134,633

Operating income		83,308			118,194			156,155			245,592			295,044
Net interest cost and debt expense		21,599			27,853			35,280			31,112			44,682

Income before income tax expense		61,709			90,341			120,875			214,480			250,362
Income tax expense		—			—			—			—			—

Net Income	$	61,709		$	90,341		$	120,875		$	214,480		$	250,362

Net Income per limited partner unit:⁽⁹⁾
Basic	$	2.28		$	2.68		$	3.39		$	6.19		$	6.52

Diluted	$	2.26		$	2.67		$	3.37		$	6.15		$	6.48

Cash distributions per unit to limited partners:⁽⁷⁾
Paid	$	2.56		$	3.03		$	3.33		$	3.67		$	4.11

Declared	$	2.65		$	3.13		$	3.38		$	3.79		$	4.21

*Cash Flow Data:*
Net cash provided by operating activities	$	90,835		$	141,480		$	207,499		$	228,587		$	176,182
Net cash used in investing activities	$	(180,654	)	$	(241,220	)	$	(119,351	)	$	(331,244	)	$	(225,828	)
Net cash provided by/(used in) financing activities	$	58,804		$	87,507		$	(95,560	)	$	102,657		$	49,646
Capital expenditures:
Maintenance	$	31,194		$	29,872		$	24,946		$	25,652		$	32,172
Expansion		149,460	⁽¹⁾		209,135	⁽²⁾		94,666	⁽³⁾		305,592	⁽⁴⁾		193,656	⁽⁵⁾

Total capital expenditures	$	180,654		$	239,007		$	119,612		$	331,244		$	225,828

EBITDA⁽⁸⁾	$	117,146		$	154,843		$	193,496		$	291,320		$	343,064
Distributable Cash Flow⁽⁸⁾	$	72,378		$	102,844		$	134,467		$	236,982		$	266,210


	Year Ended December 31,
	2005		2006		2007		2008		2009
	(in thousands, except per unit and operating data)
*Balance Sheet Data (at period end):*
Net properties, plants and equipment	$	814,836	$	1,006,668	$	1,089,262	$	1,375,429	$	1,533,721
Total assets	$	1,680,685	$	2,082,077	$	2,504,642	$	2,308,249	$	3,098,606
Total debt	$	355,573	$	491,910	$	515,104	$	747,631	$	868,424
Total Partners’ Capital	$	523,411	$	582,911	$	591,045	$	669,900	$	861,614
*Operating Data (bpd):*
Refined Product Pipeline System total shipments (in thousands of barrel miles per day)^(10)(11)		45,588		46,573		49,147		46,868		57,741
Terminal Facilities
Terminal throughput (bpd)
Refined products terminals		389,523		391,718		433,797		436,213		462,219
Nederland terminal		457,655		461,943		507,312		525,954		597,144
Refinery terminals		702,249		687,809		695,868		653,326		591,180
Crude Oil Pipeline System
Crude oil pipeline throughput (bpd)⁽¹⁰⁾		448,908		650,527		673,724		682,616		657,991
Crude oil purchases at wellhead (bpd)		186,224		191,644		177,981		177,662		181,564

⁽¹⁾

Expansion capital expenditures in 2005 includes approximately $100.0 million related to the acquisition of the Corsicana to Wichita Falls, Texas crude oil pipeline system and storage facilities, and approximately $5.5 million related to the December 2005 acquisition of an undivided joint interest in the Mesa Pipe Line. The total purchase price of the Mesa interest was approximately $6.6 million, however since a portion of the interest was acquired from a related party, it was recorded by us at Sunoco’s historical cost and the $1.1 million difference between the purchase price and the cost basis of the assets was recorded by us as a capital distribution.

⁽²⁾

Expansion capital expenditures in 2006 includes approximately $40.9 million related to the acquisition of the Millennium and Kilgore crude oil pipeline system, approximately $68.0 million related to the acquisition of the Amdel and White Oil crude oil pipeline system and approximately $12.5 million related to the acquisition of a 55.3 percent equity interest in Mid-Valley Pipeline Company. The total purchase price of Mid-Valley was approximately $65.0 million, however since a portion of the interest was acquired from a related party, it was recorded by us at Sunoco’s historical cost and the $52.5 million difference between the purchase price and the cost basis of the assets was recorded by us as a capital distribution.

⁽³⁾

Expansion capital expenditures in 2007 includes approximately $13.4 million related to the acquisition of the Syracuse Terminal, construction of tankage and pipeline assets in connection with the Partnership’s 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⁾

Expansion capital expenditures in 2008 include $185.4 million related to the acquisition of the MagTex refined products pipeline system, construction of tankage and pipeline assets in connection with the Partnership’s 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⁾

Expansion capital expenditures in 2009 include $50.2 million related to the acquisition of Excel Pipeline LLC and a refined products terminal in Romulus Michigan and the construction of tankage and pipeline assets in connection with the Partnership’s 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⁾

Includes equity income from the investments in the following joint ventures: Explorer Pipeline Company, Wolverine Pipe Line Company, West Shore Pipe Line Company, Yellowstone Pipe Line Company, West Texas Gulf Pipe Line Company, and Mid-Valley Pipeline Company. Equity income from these investments has been included based on our respective ownership percentages of each, and from the dates of acquisition forward.

⁽⁷⁾

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.

⁽⁸⁾

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, and EBITDA and distributable cash flow (in thousands):


	Year Ended December 31,
	2005			2006			2007			2008			2009
Net income	$	61,709		$	90,341		$	120,875		$	214,480		$	250,362
Interest paid to affiliates		468			1,411			2,287			558			131
Capitalized interest		(480	)		(3,005	)		(3,419	)		(3,855	)		(4,325	)
Interest expense		21,999			30,392			36,723			34,433			48,892
Interest income		(388	)		(945	)		(311	)		(24	)		(16	)
Depreciation and amortization		33,838			36,649			37,341			40,054			48,020
Impairment Charge		—			—			—			5,674			—

EBITDA		117,146			154,843			193,496			291,320			343,064
Interest expense, net		(21,599	)		(27,853	)		(35,280	)		(31,112	)		(44,682	)
Maintenance capital expenditures		(31,194	)		(29,872	)		(24,946	)		(25,652	)		(32,172	)
Sunoco reimbursements		8,025			5,726			1,197			2,426			—

Distributable cash flow	$	72,378		$	102,844		$	134,467		$	236,982		$	266,210


	Year Ended December 31,
	2005			2006			2007			2008			2009
Net cash provided by operating activities	$	90,835		$	141,480		$	207,499		$	228,587		$	176,182
Interest expense, net		21,599			27,853			35,280			31,112			44,682
Amortization fees and bond discount		(400	)		(508	)		(666	)		(633	)		(1,558	)
Restricted unit incentive plan expense		(3,221	)		(3,686	)		(5,310	)		(4,277	)		(5,329	)
Net change in working capital pertaining to operating activities		6,167			(11,456	)		(40,221	)		38,381			121,388
Proceeds from insurance recovery		—			—			(4,389	)		—			—
Other		2,166			1,160			1,303			(1,850	)		7,699

EBITDA	$	117,146		$	154,843		$	193,496		$	291,320		$	343,064

Our management believes 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 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. 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 United States generally accepted accounting principles and may not be comparable to other similarly titled measures of other businesses.

⁽⁹⁾	Net income per unit for 2005, 2006, 2007 and 2008 have been revised as a result of our January 2009 adoption of new guidance regarding the application of the two-class method to calculate earnings per unit for master limited partnerships.

⁽¹⁰⁾	Excludes amounts attributable to the equity ownership interests in corporate joint ventures.

⁽¹¹⁾

Total shipments represent the total average daily pipeline throughput multiplied by the number of miles of pipeline through which each barrel has been shipped. We believe that total shipments is a better performance indicator for the Refined Products Pipeline System than throughput as certain refined products pipelines, including inter-refinery and transfer pipelines, transport large volumes over short distances and generate minimal revenues.

ITEM 7.

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

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

Overview

We are a Delaware limited partnership formed to acquire, own, and operate, a geographically diverse portfolio of complementary pipeline, terminalling, and crude oil acquisition and marketing assets.

We are principally engaged in the transport, terminalling, and storage of refined products and crude oil and in the purchase and sale of crude oil in 13 states located in the northeast, midwest and southwest 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 storing refined products, crude oil and other hydrocarbons in, and for providing other services at, our terminals. Revenues are also generated by purchasing domestic crude oil and selling it to Sunoco and other customers. Generally, as we purchase crude oil, we simultaneously enter into corresponding sale transactions involving physical deliveries of crude oil, 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, 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 strategic initiatives, including:

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 approximately 0.4 million shell barrels and services the Detroit metropolitan area and has been integrated into our Terminal Facilities segment from the date of acquisition and;

•

Excel Pipeline LLC Acquisition. In September 2009 we acquired the owner of a 52-mile crude oil pipeline in Oklahoma, from affiliates of Gary-Williams Energy Corporation. The system originates in Duncan, OK and terminates in Wynnewood, OK and has been operated by us for Gary-Williams Energy Corporation since 2007. The pipeline has been included in our Crude Oil Pipeline System segment from the date of acquisition.

2008 Acquisition

•

MagTex Acquisition. In November 2008, we acquired a refined products pipeline system located in Texas from affiliates of Exxon Mobil Corporation. The system consists of approximately 280 miles of refined products pipeline originating in Beaumont and Port Arthur and terminating in Hearne, Texas; another 200 miles of refined products pipeline originating in Beaumont and terminating in Waskom, Texas; and refined products facilities located in Hearne, Hebert, Waco, Center and Waskom, Texas and Arcadia, Louisiana with combined active storage capacity of approximately 1.2 million shell barrels. The results of operations for the MagTex assets have been included in the Refined Products Pipeline and Terminals segments from the acquisition date.

2007 Acquisition

•

Syracuse Terminal Acquisition. In June 2007, we purchased a 50 percent undivided interest in a refined products terminal located in Syracuse, New York from Mobil Pipe Line Company, an affiliate of Exxon Mobil Corporation. Total terminal storage capacity is approximately 0.6 million barrels. The results of operations for the Syracuse Terminal acquisition have been included in the Terminals segment from the date of acquisition.

Growth Capital Program

In 2009, we completed construction of three crude oil storage tanks, with a combined capacity of 2.0 million shell barrels, and a 12-mile 30” crude oil pipeline from the Nederland Terminal to Motiva’s Port Arthur, Texas refinery. Construction of these assets cost approximately $93.8 million. During 2010, we expect to spend approximately $175.0 million to $200.0 million on expansion capital expenditures related to organic growth.

Conservative Capital Structure

Our goal is to maintain a conservative capital structure and substantial liquidity. Sunoco Logistics Partners Operations L.P. (the “Operating Partnership”), our wholly-owned subsidiary, has a five-year $400 million credit facility (“$400 million credit facility”) and a $62.5 million credit facility (“$62.5 million credit facility”). We will maintain our conservative capital structure by combining debt and equity issuances to finance our future growth.

In February 2010, the Operating Partnership issued $250.0 million of 5.50 percent Senior Notes (the “2020 Senior Notes”) and $250.0 million of 6.85 percent Senior Notes (the “2040 Senior Notes”), due February 15, 2020 and February 15, 2040, respectively. Net proceeds of $494.6 million were received after the underwriter’s commission and legal, accounting and other transaction expenses. In February 2009, the Operating Partnership issued $175 million of 8.75 percent Senior Notes, due February 15, 2014, the “2014 Senior Notes”, and received net proceeds of $173.3 million after the underwriter’s commission and legal, accounting and other transaction expenses. In May 2006, the Operating Partnership issued $175 million of 6.125 percent Senior Notes, due May 15, 2016, the “2016 Senior Notes” for net proceeds of $173.3 million after the underwriter’s commission and legal, accounting and other transaction expenses.

In April and May 2009, the Partnership completed a public offering of 2.25 million common units. Net proceeds of $109.5 million were used to reduce outstanding borrowings under the Partnership’s $400 million revolving credit facility and for general partnership purposes. In connection with these offerings, the general partner contributed $2.3 million to the Partnership to maintain its 2.0 percent general partner interest.

Cash Distribution Increases

As a result of our continued growth, our general partner increased our cash distributions to limited partners in all quarters during each of the three years ended December 31, 2009. For the year ended December 31, 2009, the distribution increased to $1.09 per common unit, ($4.36 annualized), from $0.8125 per common unit paid in February 2007. The distribution for the fourth quarter of 2009 was paid on February 12, 2010 and represents a 10.1 percent increase over the fourth quarter 2008 distribution.

Results of Operations


	Year Ended December 31,
	2007			2008		2009
	(in thousands)
Statements of Income
Sales and other operating revenue:
Affiliates	$	1,682,042		$	2,571,947	$	705,511
Unaffiliated customers		5,695,413			7,540,373		4,696,293
Other income		28,381			24,298		27,873

Total revenues		7,405,836			10,136,618		5,429,677

Cost of products sold and operating expenses		7,156,142			9,786,014		5,023,307
Depreciation and amortization		37,341			45,728		48,020
Selling, general and administrative expenses		56,198			59,284		63,306

Total costs and expenses		7,249,681			9,891,026		5,134,633

Operating income		156,155			245,592		295,044
Net interest expense		35,280			31,112		44,682

Net income	$	120,875		$	214,480	$	250,362

Segment Operating Income:
Refined Products Pipeline System
Sales and other operating revenue:
Affiliate	$	71,836		$	76,964	$	78,379
Unaffiliated customers		26,387			26,493		49,350
Other income		13,932			8,535		12,629

Total revenues		112,155			111,992		140,358

Operating expenses		51,265			48,433		60,152
Depreciation and amortization		8,336			9,351		13,711
Selling, general and administrative expenses		20,404			19,776		21,807

Total costs and expenses		80,005			77,560		95,670

Operating income	$	32,150		$	34,432	$	44,688

Terminal Facilities
Sales and other operating revenue:
Affiliates	$	92,156		$	99,976	$	100,207
Unaffiliated customers		49,466			62,448		91,077
Other income		(39	)		833		1,860

Total revenues		141,583			163,257		193,144

Cost of products sold and operating expenses		57,528			64,283		71,137
Depreciation and amortization		15,338			16,446		18,937
Impairment charge		—			5,674		—
Selling, general and administrative expenses		16,049			18,379		19,406

Total costs and expenses		88,915			104,782		109,480

Operating income	$	52,668		$	58,475	$	83,664

Crude Oil Pipeline System
Sales and other operating revenue:
Affiliates	$	1,518,050		$	2,395,007	$	526,925
Unaffiliated customers		5,619,560			7,451,432		4,555,866
Other income		14,488			14,930		13,384

Total revenues		7,152,098			9,861,369		5,096,175

Cost of products sold and operating expenses		7,047,349			9,673,298		4,892,018
Depreciation and amortization		13,667			14,257		15,372
Selling, general and administrative expenses		19,745			21,130		22,093

Total costs and expenses		7,080,761			9,708,685		4,929,483

Operating income	$	71,337		$	152,684	$	166,692

Operating Highlights


	Year Ended December 31,
	2007	2008	2009
Refined Products Pipeline System⁽¹⁾⁽⁵⁾:
Total shipments (barrel miles per day)⁽²⁾	49,146,699	46,867,934	57,741,323
Revenue per barrel mile (cents)	0.548	0.603	0.606
Terminal Facilities:
Terminal throughput (bpd):
Refined products terminals⁽³⁾⁽⁵⁾	433,797	436,213	462,219
Nederland Terminal	507,312	525,954	597,144
Fort Mifflin Terminal Complex	310,948	299,727	279,895
Marcus Hook Tank Farm	146,112	127,738	129,899
Eagle Point Dock.	238,808	225,861	181,386
Crude Oil Pipeline System⁽¹⁾:
Crude oil pipeline throughput (bpd)	673,724	682,616	657,991
Crude oil purchases at wellhead (bpd)	177,981	177,662	181,564
Gross margin per barrel of pipeline throughput (cents)⁽⁴⁾	31.9	63.0	73.0

⁽¹⁾	Excludes amounts attributable to equity ownership interests in the corporate joint ventures.

⁽²⁾	Represents total average daily pipeline throughput multiplied by the number of miles of pipeline through which each barrel has been shipped.

⁽³⁾	Includes results from our purchase of a 50 percent undivided interest in a refined products terminal in Syracuse, New York from the acquisition date.

⁽⁴⁾	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.

⁽⁵⁾	Includes results from our purchase of the MagTex refined products pipeline system and terminal assets from the acquisition date.

Analysis of Consolidated Net Income

Net income was $120.9 million, $214.5 million and $250.4 million for the years ended December 31, 2007, 2008 and 2009 respectively.

The $35.9 million increase in net income from 2008 to 2009 was primarily the result of increased operating income driven by higher fees across all segments, full year of results from the MagTex acquisition, additional tankage at the Nederland terminal facility, and higher lease acquisition earnings. This increase in operating income was partially offset by a $13.6 million increase in net interest expense due primarily to higher borrowings associated with the $185.4 million MagTex acquisition, increased contango inventory positions and organic growth projects.

The $93.6 million increase in net income from 2007 to 2008 was primarily the result of increased operating income driven by higher fees across all segments, significantly improved lease acquisition margins, increased volumes within the Crude Oil Pipeline System and the addition of assets through organic projects and acquisitions. A $4.2 million decrease in net interest expense further contributed to the increase in net income.

The $30.6 million increase in net income from 2006 to 2007 was primarily the result of increased operating income driven by strong operating performance in our Terminal Facilities and Crude Oil Pipeline System segments, full year results from the 2006 acquisitions of an equity interest in the Mid-Valley Pipeline Company and Kilgore and Millennium pipelines. This increase in operating income was partially offset by a $7.4 million increase in net interest expense related to higher borrowings from the Partnership’s organic growth program, and 2006 and 2007 acquisitions.

Analysis of Segment Operating Income

Year Ended December 31, 2009 versus Year Ended December 31, 2008

Refined Products Pipeline System

Operating income for the Refined Products Pipeline System increased $10.3 million to $44.7 million for the year ended December 31, 2009 compared to the prior year. Sales and other operating revenue increased by $24.3 million to $127.7 million due primarily to full year results from the MagTex refined products pipeline acquisition, along with increased pipeline fees. Other income increased $4.1 million compared to the prior year as a result of an increase in equity income associated with the Partnership’s joint venture interests. Operating expenses increased by $11.7 million to $60.2 million due primarily to the MagTex acquisition, a reduction in pipeline operating gains and increased environmental remediation expenses. Depreciation and amortization expense increased $4.4 million during 2009 due primarily to the MagTex acquisition. Selling, general and administrative expense increased $2.0 million compared to the prior year due primarily to increased employee benefits costs.

Terminal Facilities

Operating income for the Terminal Facilities segment increased by $25.2 million to $83.7 million for the year ended December 31, 2009 compared to the prior year. Sales and other operating revenue increased by $28.9 million to $191.3 million due primarily to increased terminal fees, additional tankage at the Nederland terminal facility, full year results from the MagTex refined products terminal acquisition and the addition of refined product sales. Partially offsetting these increases were reduced volumes at the Partnership’s refinery terminals. Other income increased $1.0 million in 2009 as a result of an insurance recovery associated with the Partnership’s refinery terminals. Cost of goods sold and operating expenses increased by $6.9 million to $71.1 million for the year ended December 31, 2009 due primarily to the commencement of terminal optimization projects, increased terminal operating losses and the addition of the MagTex acquisition. These increases were partially offset by reduced utility expenses and the absence of hurricane damages incurred during 2008. Depreciation and amortization expense increased to $18.9 million for the twelve months of 2009 due to the MagTex acquisition and increased tankage at the Nederland facility. During 2008, a $5.7 million non-cash impairment charge was recognized related to the Partnership’s decision to discontinue efforts to expand LPG storage capacity at its Inkster, Michigan facility. Selling, general and administrative expense increased $1.0 million compared to the prior year due primarily to increased employee benefits costs.

Crude Oil Pipeline System

Operating income for the Crude Oil Pipeline system increased $14.0 million to $166.7 million for the year ended December 31, 2009 compared to the prior year due primarily to increased pipeline fees and higher lease acquisition earnings which benefited from the contango market structure. These increases were partially offset by a reduction in pipeline operating gains. Other income decreased $1.5 million compared to the prior year due primarily to decreased equity income associated with the Partnership’s joint venture interests and the absence of an insurance gain recognized in 2008.

Lower crude oil prices were a key driver of the overall decrease in total revenue, cost of products sold and operating expenses from the prior year. The average price of West Texas Intermediate crude oil at Cushing, Oklahoma decreased to $61.93 per barrel for 2009 from $99.65 per barrel for 2008.

Year Ended December 31, 2008 versus Year Ended December 31, 2007

Refined Products Pipeline System

Operating income for the Refined Products Pipeline system increased $2.3 million to $34.4 million for the twelve months ended December 31, 2008 compared to the prior year period. Sales and other operating revenue

increased by $5.2 million to $103.5 million due primarily to higher fees across our refined products pipeline and additional refined products volumes from the acquisition of the MagTex refined products pipeline. Other income decreased $5.4 million compared to the prior year period primarily resulting from decreased refined products volumes experienced during 2008 by our joint venture interests. Despite higher utility and operating costs associated with the MagTex refined products pipeline acquisition, operating expenses decreased by $2.8 million to $48.4 million due primarily to a decrease in environmental charges incurred during 2007.

Terminal Facilities

Operating income for the Terminal Facilities segment increased by $5.8 million to $58.5 million for the twelve months ended December 31, 2008 compared to the prior year period, despite a $5.7 million non-cash impairment charge in 2008 related to our decision to discontinue efforts to expand LPG storage capacity at our Inkster, Michigan facility. Sales and other operating revenue increased by $20.8 million to $162.4 million due primarily to the increased terminal fees, additional tankage at the Nederland terminal, increased product additive revenues and the impact of the refined products terminals acquired during 2007 and 2008. These increases were partially offset by decreased volumes in our refinery terminals. Other income increased $0.8 million from the twelve months of 2007 as a result of an insurance recovery recorded during the second quarter associated with hurricane damage sustained in 2005. Cost of products sold and operating expenses increased by $6.8 million to $64.3 million for the period ended December 31, 2008 due primarily to increased product additive cost, damages incurred at our Nederland terminal from the hurricanes experienced during the third quarter of 2008 and the impact of the refined products terminals acquired during 2007 and 2008. These higher costs were partially offset by product overages which were favorably impacted by the increased price of crude oil during 2008. Selling, general and administrative expenses increased by $2.3 million to $18.4 million for the twelve months ended December 31, 2008 due primarily to increased employee and environmental costs.

Crude Oil Pipeline System

Operating income for the Crude Oil Pipeline system increased $81.3 million to $152.7 million for the twelve months ended December 31, 2008 compared to the prior year period due primarily to improved lease acquisition margin resulting from a backwardated market, the full year impact of a bi-directional pipeline connection to our Nederland terminal established in 2007, increased volumes on certain pipeline segments and increased pipeline fees. Additionally, hurricane disruptions, refinery production issues and a shift in the crude oil market structure resulted in increased inventory levels at year end. The timing of this inventory increase resulted in the deferral of approximately $12.0 million of costs that would have otherwise reduced 2008 results and which will negatively impact earnings at such time as this inventory is sold in the future.

Higher crude oil prices were a key driver of the overall increase in total revenue, cost of products sold and operating expenses from the prior year period. The average price of West Texas Intermediate crude oil at Cushing, Oklahoma increased to $99.65 per barrel for the twelve months of 2008 from $72.40 per barrel for the twelve months of 2007.

Liquidity and Capital Resources

Liquidity

Cash generated from operations and borrowings under the $400 million Credit Facility and the $62.5 million Credit Facility are our primary sources of liquidity. At December 31, 2009, we had net working capital of $92.2 million and available borrowing capacity under the credit facilities of $188.5 million. Our working capital position reflects crude oil inventories based on historical costs under the LIFO method of accounting. If the inventories had been valued at their current replacement cost, we would have had working capital of $239.5 million at December 31, 2009. We periodically supplement our cash flows from operations with proceeds from debt and equity financing activities.

Capital Resources

Credit Facilities

The Operating Partnership has a five-year $400 million Credit Facility, which is available to fund the Operating Partnership’s working capital requirements, to finance future acquisitions, to finance future capital projects and for general partnership purposes. The Credit Facility matures in November 2012. At December 31, 2009, there was $237.7 million outstanding under this credit facility.

The $400 million Credit Facility bears interest at the Operating Partnership’s option, at either (i) LIBOR plus an applicable margin, (ii) the higher of the federal funds rate plus 0.50 percent or the Citibank prime rate (each plus the applicable margin) or (iii) the federal funds rate plus an applicable margin.

The $400 million Credit Facility contains various covenants limiting the Operating Partnership’s ability to a) incur indebtedness, b) grant certain liens, c) make certain loans, acquisitions and investments, d) make any material change to the nature of its business, e) acquire another company, f) or enter into a merger or sale of assets, including the sale or transfer of interests in the Operating Partnership’s subsidiaries. The $400 million Credit Facility also limits the Operating Partnership, on a rolling four-quarter basis, to a maximum total debt to EBITDA ratio of 4.75 to 1, which can generally be increased to 5.25 to 1 during an acquisition period.

In September 2008, Lehman Brothers, one of the participating banks with a commitment under the Credit Facility amounting to $5.0 million declared bankruptcy and its loan commitment is no longer in effect.

On March 13, 2009, the Operating Partnership entered into a $62.5 million revolving credit facility (“$62.5 million Credit Facility”) with 2 participating financial institutions. The $62.5 million Credit Facility is available to fund the Operating Partnership’s working capital requirements, to finance future acquisitions and for general partnership purposes. The $62.5 million Credit Facility matures in September 2011 and may be repaid at any time. It bears interest at the Operating Partnership’s option, at either (i) LIBOR plus an applicable margin or (ii) the higher of (a) the federal funds rate plus 0.50 percent plus an applicable margin, (b) Toronto Dominion’s prime rate plus an applicable margin or (c) LIBOR plus 1.0 percent plus an applicable margin. The $62.5 million Credit Facility contains various covenants similar to the $400 million credit facility and also requires the Operating Partnership to maintain, on a rolling four-quarter basis, a maximum total debt to EBITDA ratio of 4.0 to 1, which can generally be increased to 4.5 to 1 during an acquisition period. At December 31, 2009, there was $31.3 million outstanding under this credit facility.

Senior Notes

In connection with the February 2002 IPO, the Operating Partnership issued $250 million of 7.25 percent Senior Notes, due February 15, 2012 (“2012 Senior Notes”). The 2012 Senior Notes are redeemable, at a make-whole premium, and are not subject to sinking fund provisions. The 2012 Senior Notes contain various covenants limiting the Operating Partnership’s ability to incur certain liens, engage in sale/leaseback transactions, or merge, consolidate or sell substantially all of its assets.

In May 2006, the Operating Partnership issued $175 million of 6.125 percent Senior Notes, due May 15, 2016 (“2016 Senior Notes”). The 2016 Senior Notes are redeemable, at a make-whole premium, and are not subject to sinking fund provisions. The 2016 Senior Notes contain various covenants limiting the Operating Partnership’s ability to incur certain liens, engage in sale/leaseback transactions, or merge, consolidate or sell substantially all of its assets. The net proceeds from the 2016 Senior Notes, together with $110.3 million in net proceeds from a concurrent offering of approximately 2.7 million limited partner common units, were used to repay all of the $216.1 million in outstanding borrowings under the Operating Partnership’s previous credit facility. The balance of the proceeds from the offerings were used to fund our organic growth program and for our general partnership purposes, including to finance future acquisitions.

In February 2009, the Operating Partnership issued $175 million of 8.75 percent Senior Notes, due February 15, 2014 (“2014 Senior Notes”). The 2014 Senior Notes are redeemable, at a make-whole premium, and are not subject to sinking fund provisions. The 2014 Senior Notes contain various covenants limiting the Operating Partnership’s ability to incur certain liens, engage in sale/leaseback transactions, or merge, consolidate or sell substantially all of its assets. The net proceeds from the 2014 Senior Notes were used to repay outstanding borrowings under the $400 million Credit Facility, which were associated with the MagTex acquisition.

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 the Operating Partnership’s ability to incur certain liens, engage in sale/leaseback transactions, or merge, consolidate or sell substantially all of its assets. The net proceeds from the 2020 and 2040 Senior Notes were used to repay the $201.2 promissory note issued in connection with our repurchase and exchange of our general partner’s IDR interests, to repay outstanding borrowings under the $400 million Credit Facility and for general partnership purposes.

Equity Offerings

Cash Flows and Capital Expenditures

Net cash provided by operating activities for the years ended December 31, 2007, 2008 and 2009 was $207.5 million, $228.6 million and $176.2 million, respectively. Net cash provided by operating activities for 2009 was primarily the result of net income of $250.4 million and depreciation and amortization of $48.0 million, offset by an increase working capital of $121.4 million, which is the result of an increase in accounts receivable associated with contango inventory positions. Net cash provided by operating activities for 2008 was primarily the result of net income of $214.5 million and depreciation and amortization of $40.1 million, offset by an increase working capital of $38.4 million, resulting from contango inventory positions. Net cash provided by operating activities for 2007 consists primarily of net income of $120.9 million, depreciation and amortization of $37.3 million, and an increase in the working capital deficit of $40.2 million.

Net cash used in investing activities for the years ended December 31, 2007, 2008 and 2009 was $119.4 million, $331.2 million, and $225.8 million respectively. The decrease in cash used by investing activities from 2008 to 2009 was primarily attributable to acquisitions completed in 2009 as compared to 2008, partially offset by an increase in expansion capital which includes construction costs associated with the completed project to connect the Nederland terminal to Motiva’s Port Arthur, Texas refinery, construction of additional storage tanks at Nederland and refined products terminal optimization projects. The increase in cash used by investing activities from 2007 to 2008 was primarily attributable to the MagTex refined products system acquisition. Cash used for acquisitions was $13.5 million in 2007, $185.4 million in 2008, and $50.2 million in 2009. Acquisitions completed in 2009 include a refined products terminal in Romulus, MI and Excel Pipeline LLC, the owner of a crude oil pipeline which services Gary Williams’ Wynnewood, OK refinery. Acquisitions completed in 2008 include the MagTex refined products pipeline and terminal system located in Texas and Louisiana from affiliates of Exxon Mobil Corporation. Acquisitions completed in 2007 include a 50 percent undivided interest in a refined products terminal located in Syracuse, New York from an affiliate of Exxon Mobil Corporation.

Net cash provided by / (used in) financing activities for the years ended December 31, 2007, 2008 and 2009 was, $(95.6) million, $102.7 million and $49.6 million respectively.

For the year ended December 31, 2009, the $49.6 million of cash provided by financing activities was primarily attributable to net proceeds of $282.8 million related to the February 2009 issuance of 8.75 percent senior notes and the April and May offering of 2.25 million common units. These sources were partially offset by $172.9 million of distributions and $54.4 million of net repayments under our $400 million Credit Facility.

For the year ended December 31, 2008, the $102.7 million of cash provided by financing activities was primarily attributable to $232.4 million increase in net borrowings under our $400 million Credit Facility. This amount was partially offset by $137.2 in distributions paid to our limited partners and our general partner.

For the year ended December 31, 2007, the $95.6 million of cash used in financing activities was primarily the result of $117.5 million in distributions paid to our limited partners and our general partner. This use of funds was partially offset by a $23.0 million increase in net borrowings under our credit facilities related to funding our expansion capital.

Under a treasury services agreement with Sunoco, we participate in Sunoco’s centralized cash management program. Advances to affiliates in our balance sheets at December 31, 2008 and 2009 represent amounts due from Sunoco under this agreement.

Capital Requirements

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

•

Maintenance capital expenditures, such as those required to maintain equipment reliability, tankage and pipeline integrity and safety, to address environmental regulations and,

•

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

The following table summarizes maintenance and expansion capital expenditures, including amounts paid for acquisitions, for the years presented:


	Year Ended December 31,
	2007		2008		2009
	(in thousands of dollars)
Maintenance	$	24,946	$	25,652	$	32,172
Expansion		94,666		305,592		193,656

Total	$	119,612	$	331,244	$	225,828

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, crude trucks and related equipment, and the upgrade of pump stations. In addition to these recurring projects, maintenance capital includes certain expenditures for which we received reimbursement from Sunoco under the terms of agreements between the parties (see “Agreements with Sunoco”). We have received the maximum aggregate reimbursements defined within the Omnibus Agreement with Sunoco. Management expects maintenance capital expenditures to be approximately $32.0 million in 2010.

Expansion capital expenditures decreased by $111.9 million to $193.7 million for the year ended December 31, 2009. Expansion capital expenditures for 2009 include the acquisitions of a refined products terminal in Romulus, Michigan and Excel Pipeline LLC, the owner of a crude oil pipeline which services Gary Williams’ Wynnewood, Oklahoma refinery, and the construction pursuant to our agreement to connect our Nederland Terminal to a Port Arthur, Texas refinery. Expansion capital also includes refined products terminal optimization and construction of additional crude oil storage tanks at Nederland. Expansion capital expenditures increased by $210.9 million to $305.6 million for the year ended December 31, 2008. Expansion capital for 2008 includes $185.4 million related to the acquisition of the MagTex refined products pipeline system and construction of tankage and pipelines assets in connection with our agreement to connect the Nederland terminal to a Port Arthur, Texas refinery. Expansion capital also includes construction of additional crude oil storage tanks at the Nederland terminal. Expansion capital for 2007 included the $13.4 million acquisition of a 50 percent interest in a Syracuse, New York refined products terminal.

Management expects to invest approximately $175 million to $200 million in expansion capital projects in 2010, excluding acquisitions. These projects include additional tankage at the Nederland terminal, refined products terminal optimization projects and organic growth projects associated with the MagTex refined products pipeline and terminal system.

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 (including interest commitments based upon the interest rate in effect at December 31, 2009), annual rentals applicable to noncancelable operating leases, and purchase commitments related to future periods at December 31, 2009 (in thousands of dollars):


	Year Ended December 31,										Thereafter		Total
	2010		2011		2012		2013		2014		Thereafter		Total
Long-term debt⁽¹⁾:
Principal	$	—	$	31,250	$	487,723	$	—	$	175,000	$	175,000	$	868,973
Interest		47,932		47,725		30,973		26,031		12,633		14,738		180,032
Operating leases		4,295		3,947		3,702		1,433		1,305		5,337		20,019
Purchase obligations		1,732,230		—		—		—		—		—		1,732,230

	$	1,784,457	$	82,922	$	522,398	$	27,464	$	188,938	$	195,075	$	2,801,254

⁽¹⁾	Excludes maturities and interest related to the February 2010 issuance of $250.0 million of 5.50% Senior Notes due in 2020 and $250.0 million of 6.85% Senior Notes due in 2040

Our operating leases reported above include leases of office space, third-party pipeline capacity, and other property and equipment, with initial or remaining noncancelable 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 of noncancelable contracts to purchase crude oil for terms of one year or less by our Crude Oil Acquisition and Marketing group. The majority of the above purchase obligations include actual crude oil purchases for the month of January 2010. 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, 2009 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 and Marketing activities, see Item 1. “Business—Crude Oil Pipeline System—Crude Oil Acquisition and Marketing”.

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 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 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 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 financial statements with useful and reliable information about our operating results and financial condition. The preparation of our 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 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 properties, plants and equipment, less estimated salvage value, is generally depreciated on a straight-line basis over the estimated useful lives of the assets. Useful lives are based on historical experience 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.

There were no asset impairments for the years ended December 31, 2007 and 2009. In the first quarter of 2008, we recognized an impairment of $5.7 million related to our decision to discontinue efforts to expand liquefied petroleum gas storage capacity at our Inkster, Michigan facility. The impairment charge reflected the entire cost associated with the project.

Environmental Remediation. The operation of our pipelines, terminals and associated facilities are subject to numerous federal, state and local laws and regulations which regulate the discharge of materials into the environment or that otherwise relate to the protection of the environment. As a result of compliance with these laws and regulations, site restoration costs have been and will be incurred in the future at our facilities and properties, including liabilities for environmental remediation obligations.

At December 31, 2009, our accrual for environmental remediation activities was $2.8 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, 2009. 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 February 2002 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 February 2002 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, 2009, see Note 1 to the consolidated financial statements.

Agreements with Sunoco

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

Pipelines and Terminals Storage and Throughput Agreement

In 2002, we entered into a pipelines and terminals storage and throughput agreement with Sunoco under which Sunoco agreed to pay us a minimum level of revenues for the transportation and throughput of refined products and agreed to minimum volume levels of storage and throughput of crude oil and liquefied petroleum gas. Sunoco’s obligations under this agreement have since expired and have been replaced by the following agreements:

•

In February 2007, certain obligations under the agreement relating to throughput of refined products through our refined products marketing terminals and our Marcus Hook Tank Farm expired. On March 1, 2007 we entered into (i) a new five year product terminal services agreement with Sunoco under which Sunoco may throughput refined products through our terminals, and (ii) a new 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.

•

In the first quarter of 2009, Sunoco’s remaining obligations under the 2002 agreement relating to minimum volume levels of storage and throughput of crude oil and refined products at the Fort Mifflin Terminal Complex and minimum volume levels of storage and throughput of liquefied petroleum gas at the Inkster Terminal expired. We entered into a new three year agreement with Sunoco, effective April 1, 2009, relating to the Inkster Terminal. Under this agreement, Sunoco will annually throughput a minimum of 968,550 barrels of liquefied petroleum gas originating at Sunoco’s Toledo, Ohio refinery to and from the Inkster Terminal. This minimum throughput is an annual amount for each contract period running from April 1 to March 31. Additionally, Sunoco will annually throughput a minimum of 250,000 barrels of propane across the Inkster Terminal loading rack. This minimum propane throughput is an annual amount for each contract period running from April 1 to March 31, and will be pro-rated for the 2009-2010 term to account for the rack installation.

•

We also entered into a new three year agreement with Sunoco, effective March 1, 2009, relating to the Fort Mifflin Terminal Complex. Under this agreement, Sunoco will deliver an average of 300,000 barrels per day 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.

Subject to a minimum of 180 days advance written notice, Sunoco’s obligations under the Fort Mifflin Terminal Complex agreement and the Inkster agreement may be permanently reduced or suspended if Sunoco shuts down or reconfigures (i) its Philadelphia refinery such that the refinery does not require (in the case of crude oil) or produce (in the case of petroleum products) volumes sufficient for Sunoco to satisfy its minimum obligations under the Fort Mifflin agreement; or (ii) its Toledo refinery such that the refinery does not produce the volumes sufficient for Sunoco to satisfy its minimum obligations under the Inkster agreement.

Our facilities are well situated to handle Sunoco’s refining and marketing supply chain needs, and we expect that Sunoco will continue to utilize our pipelines and terminals. The strategic interplay between our assets and Sunoco’s assets results in a mutually beneficial relationship between us and Sunoco. However, Sunoco actively manages its assets and operations and changes of some nature, possibly material to our business relationship, may occur at some point in the future. There can be no assurance of the levels at which Sunoco will continue will continue to utilize our pipelines or terminals or that revenues can be generated from third parties.

Omnibus Agreement

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

•

Sunoco’s obligation to reimburse us for specified operating expenses and capital expenditures or otherwise to complete certain tank maintenance and inspection projects;

•

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

•

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

•

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;

•

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 initial public offering and for environmental and toxic tort liabilities related to the assets to the extent Sunoco is not required to indemnify us; and

•

our option to purchase certain pipeline, terminalling, and storage assets retained by Sunoco or its affiliates.

As of December 31, 2006, we have received the cumulative reimbursement under this agreement and do not expect to be reimbursed by Sunoco for these expenditures going forward.

General and Administrative Services Fee. 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 $6.5 million, $6.0 million and $6.0 million for the years ended December 31, 2007, 2008 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 (including senior executives), 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 for 2010 the annual fee is $5.4 million. These costs may be increased if the acquisition or construction of new assets or businesses requires an increase in the level of general and administrative services received by us. There can be no assurance that Section 4.1 of the Omnibus Agreement will be extended beyond 2010, 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 financial condition and results of operations may be adversely impacted.

In addition to the fees for the centralized corporate functions, selling, general and administrative expenses in the statements of income include the allocation of shared insurance costs of $3.9 million, $3.2 million and $3.5 million for the years ended December 31, 2007, 2008 and 2009, respectively. Our share of allocated Sunoco employee benefit plan expenses, including non-contributory defined benefit retirement plans, defined contribution 401(k) plans, employee and retiree medical, dental and life insurance plans, incentive compensation plans and other such benefits, was $23.0 million, $21.0 million and $27.7 million for the years ended December 31, 2007, 2008 and 2009, respectively.

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 Audit/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:

•

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

•

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;

•

any business that Sunoco or any of its subsidiaries acquires or constructs that has a fair market value of less than $5.0 million; and

•

any business that Sunoco or any of its subsidiaries acquires or constructs that has a fair market value of $5.0 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 Audit/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 February 2002 IPO. Sunoco is obligated to indemnify us for 100 percent of all losses asserted within the first 21 years of closing of the February 2002 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 February 2002 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 interests in the Mesa Pipeline system and the Mid-Valley pipeline purchased from Sunoco following the IPO. 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 February 2002 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 February 2002 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 February 2002 IPO;

•

legal actions related to the period prior to the February 2002 IPO currently pending against Sunoco or its affiliates; and

•

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

Interrefinery Lease Agreement

Under a 20-year lease agreement entered into by us and Sunoco upon the closing of the February 2002 IPO, Sunoco leases our 58 miles of interrefinery pipelines between Sunoco’s Philadelphia and Marcus Hook refineries for an annual fee which escalates at 1.67 percent each January 1^stfor the term of the agreement. The annual fee for the year ended December 31, 2009 was $6.1 million.

The lease agreement also requires Sunoco to reimburse us for any non-routine maintenance expenditures, as defined, incurred during the term of the agreement. For the year ended December 31, 2008, we were reimbursed by Sunoco for maintenance operating expenses and capital expenditures associated with this provision. The reimbursement was recorded as a capital contribution to Partners’ Capital within our balance sheet. There were no reimbursements under this agreement in 2009.

Crude Oil Purchase Agreements

We have agreements with Sunoco whereby Sunoco purchases from us, at market-based rates, particular grades of crude oil that are purchased by our crude oil acquisition and marketing business. These agreements automatically renew on a monthly basis unless terminated by either party on 30 days’ written notice. During the year ended December 31, 2008, Sunoco purchased all the barrels offered pursuant to these agreements. On June 1, 2009, Sunoco completed a sale of its Tulsa refinery to Holly Corporation and our crude oil purchase agreements relating to this facility were terminated. The termination of the agreements did not have a material impact on our results of operations and our cash flow, as we have entered into contracts to sell crude oil to Holly Corporation which are commensurate with historical Sunoco volumes.

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 its business.

Treasury Services Agreement

We have a treasury services agreement with Sunoco pursuant to which, among other things, we are participating 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 $400 million Credit Facility.

Eagle Point Logistics Assets Purchase and Throughput Agreements

On March 30, 2004, we entered into a purchase agreement with Sunoco to acquire the Eagle Point refinery logistics assets for approximately $20 million. On January 24, 2008, we executed an Amended and Restated Dock and Terminal Throughput Agreement with Sunoco which amended certain terms that were included in the original throughput agreement entered into with Sunoco upon acquiring the Eagle Point assets. The fees we are charging Sunoco for services provided under this agreement are comparable to those charged in arm’s length, third-party transactions to receive or deliver crude oil and refined products to and from the Eagle Point refinery. Also included in this agreement were fees to receive and deliver refined and intermediate products through our Eagle Point terminal facility.

On February 1, 2010 Sunoco announced its permanent shutdown of the Eagle Point refinery. Sunoco expects to continue to distribute refined products through our Eagle Point terminal. Our assets, including docks, terminals and pipelines, which provide logistics support to the Eagle Point refinery had a net book value of $62.0 million as of December 31, 2009 and generated revenues of $15.6 million for the year ended December 31, 2009. We do not expect the shutdown of the Eagle Point refinery to have a material impact on us or our results of operations and continue to work with Sunoco to evaluate the impact, if any, that the shutdown of the Eagle Point refinery will have on our operating results and the net book value of our assets. We did not recognize an impairment charge during 2009 as a result of the shutdown.

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 at existing assets.

Although these agreements did not result from arm’s-length negotiations, 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 volatility in crude oil commodity prices and interest rates. To manage such exposure, inventory levels and expectations of future commodity prices and interest rates are monitored when making decisions with respect to risk management. We have not entered into derivative transactions that would expose us to price risk.

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, 2009, we had an interest rate swap agreement (the “Swap”) with a notional amount of $50.0 million which matured January 2010. Under the Swap, we received interest equivalent to the three-month LIBOR and pay a fixed rate of interest of 3.489 percent with settlements occurring quarterly. Our weighted average variable interest rate on our variable-rate borrowings, not related to the swap, was 0.86 percent at December 31, 2009. A one percent change in the weighted average rate would have impacted annual interest expense by approximately $2.2 million.

At December 31, 2009, we had $600.0 million of fixed-rate borrowings, which is comprised of $250.0 million of 2012 Senior Notes, $175.0 million of 2014 Senior Notes and $175.0 million of 2016 Senior Notes. A hypothetical one-percent decrease in interest rates would increase the fair value of our fixed-rate borrowings at December 31, 2009 by approximately $23.0 million.

Commodity Market Risk

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. We are exposed to volatility in crude oil 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. In the ordinary course of doing business, we enter into crude purchase contracts with third parties generally for a term of one year or less, with a majority of the transactions on a 30-day renewable basis. Simultaneously, we enter into contracts for the future physical sale and delivery on a specified date of the related crude purchased. Contracts that qualify as derivatives have been designated as normal purchases and sales and are accounted for using traditional accrual accounting. 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.

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, 2009. 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, 2009, 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.

Deborah M. Fretz

President and Chief Executive Officer

Neal E. Murphy

Vice President and Chief Financial Officer

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The Board of Directors of

Sunoco Partners LLC

We have audited Sunoco Logistics Partners L.P.’s internal control over financial reporting as of December 31, 2009, 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 company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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

In our opinion, Sunoco Logistics Partners L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2009 financial statements of Sunoco Logistics Partners L.P. and our report dated February 23, 2010 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Philadelphia, Pennsylvania

February 23, 2010

REPORT OF INDEPENDENT REGISTERED

PUBLIC ACCOUNTING FIRM ON FINANCIAL STATEMENTS

To the Board of Directors of

Sunoco Partners LLC

We have audited the accompanying balance sheets of Sunoco Logistics Partners L.P. (the “Partnership”) as of December 31, 2008 and 2009, and the related statements of income, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2009. 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 financial statements referred to above present fairly, in all material respects, the financial position of Sunoco Logistics Partners L.P. at December 31, 2008 and 2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, 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, 2009, 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 23, 2010 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Philadelphia, Pennsylvania

February 23, 2010

SUNOCO LOGISTICS PARTNERS L.P.

STATEMENTS OF INCOME

(in thousands, except units and per unit amounts)


	Year Ended December 31,
	2007			2008			2009
Revenues
Sales and other operating revenue:
Affiliates	$	1,682,042		$	2,571,947		$	705,511
Unaffiliated customers		5,695,413			7,540,373			4,696,293
Other income		28,381			24,298			27,873

Total Revenues		7,405,836			10,136,618			5,429,677

Costs and Expenses
Cost of products sold and operating expenses		7,156,142			9,786,014			5,023,307
Depreciation and amortization		37,341			40,054			48,020
Selling, general and administrative expenses		56,198			59,284			63,306
Impairment charge		—			5,674			—

Total Costs and Expenses		7,249,681			9,891,026			5,134,633

Operating Income		156,155			245,592			295,044
Net interest cost paid to affiliates		2,287			558			131
Other interest cost and debt expense, net		36,412			34,409			48,876
Capitalized interest		(3,419	)		(3,855	)		(4,325	)

Net Income	$	120,875		$	214,480		$	250,362

Calculation of Limited Partners’ interest in Net Income:
Net Income	$	120,875		$	214,480		$	250,362
Less: General Partner’s interest in Net Income		(24,098	)		(37,097	)		(52,665	)

Limited Partners’ interest in Net Income	$	96,777		$	177,383		$	197,697

Net Income per Limited Partner unit:
Basic	$	3.39		$	6.19		$	6.52

Diluted	$	3.37		$	6.15		$	6.48

Weighted average Limited Partner units outstanding:
Basic		28,581,032			28,650,069			30,310,618

Diluted		28,729,153			28,836,603			30,517,891

(See Accompanying Notes)

SUNOCO LOGISTICS PARTNERS L.P.

BALANCE SHEETS

(in thousands)


	December 31,
	2008			2009
Assets
Current Assets
Cash and cash equivalents	$	2,000		$	2,000
Advances to affiliates		2,549			8,691
Accounts receivable, affiliated companies		77,692			47,791
Accounts receivable, net		652,840			1,280,062
Inventories		90,156			86,974

Total Current Assets		825,237			1,425,518
Properties, plants and equipment, net		1,375,429			1,533,721
Investment in affiliates		82,882			88,286
Deferred charges and other assets		24,701			51,081

Total Assets	$	2,308,249		$	3,098,606

Liabilities and Partners’ Capital
Current Liabilities
Accounts payable	$	792,674		$	1,253,742
Accrued liabilities		45,648			49,298
Accrued taxes		20,738			30,296

Total Current Liabilities		859,060			1,333,336
Long-term debt		747,631			868,424
Other deferred credits and liabilities		31,658			35,232
Commitments and contingent liabilities

Total Liabilities		1,638,349			2,236,992

Partners’ Capital:
Limited partners’ interest		653,283			837,120
General partner’s interest		19,747			26,987
Accumulated other comprehensive loss		(3,130	)		(2,493	)

Total Partners’ Capital		669,900			861,614

Total Liabilities and Partners’ Capital	$	2,308,249		$	3,098,606

(See Accompanying Notes)

SUNOCO LOGISTICS PARTNERS L.P.

STATEMENTS OF CASH FLOWS

(in thousands)


	Year Ended December 31,
	2007			2008			2009
Cash Flows from Operating Activities:
Net Income	$	120,875		$	214,480		$	250,362
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		37,341			40,054			48,020
Impairment charge		—			5,674			—
Amortization of financing fees and bond discount		666			633			1,558
Restricted unit incentive plan expense		5,310			4,277			5,329
Changes in working capital pertaining to operating activities:
Accounts receivable, affiliated companies		36,785			(15,525	)		29,901
Accounts receivable, net		(424,277	)		547,942			(627,222	)
Inventories		39,615			(59,487	)		3,182
Accounts payable and accrued liabilities		376,690			(497,772	)		463,193
Accrued taxes		11,408			(13,539	)		9,558
Proceeds from insurance recovery		4,389			—			—
Other		(1,303	)		1,850			(7,699	)

Net cash provided by operating activities		207,499			228,587			176,182

Cash Flows from Investing Activities:
Capital expenditures		(105,862	)		(145,834	)		(175,596	)
Acquisitions		(13,489	)		(185,410	)		(50,232	)

Net cash used in investing activities		(119,351	)		(331,244	)		(225,828	)

Cash Flows from Financing Activities:
Distributions paid to Limited Partners and General Partner		(117,451	)		(137,203	)		(172,856	)
Net proceeds from issuance of Limited Partner units		—			—			109,514
Contribution from General Partner for Limited Partner unit transactions		58			76			2,402
Repayments from (advances to) affiliates, net		(629	)		5,511			(6,142	)
Borrowings under credit facility		279,900			343,385			632,973
Repayments under credit facility		(256,900	)		(111,000	)		(687,385	)
Net proceeds from issuance of Senior Notes		—			—			173,289
Payments of statutory withholding on net issuance of Limited Partner units under restricted unit incentive plan		(1,479	)		(538	)		(2,149	)
Contributions from affiliate		941			2,426			—

Net cash provided by/(used in) financing activities		(95,560	)		102,657			49,646

Net change in cash and cash equivalents		(7,412	)		—			—
Cash and cash equivalents at beginning of year		9,412			2,000			2,000

Cash and cash equivalents at end of year	$	2,000		$	2,000		$	2,000

(See Accompanying Notes)

SUNOCO LOGISTICS PARTNERS L.P.

STATEMENTS OF PARTNERS’ CAPITAL

(in thousands)


	Limited Partners									General Partner			Accumulated Other Comprehensive Loss			Total Partners’ Capital
	Common				Subordinated					General Partner			Accumulated Other Comprehensive Loss			Total Partners’ Capital
	Units	$			Units		$			$			$			$
Balance at December 31, 2006	22,844	$	496,626		5,692		$	79,378		$	6,907			—		$	582,911

Net income	—		96,736		—			—			24,139			—			120,875
Cumulative effect of adoption of FIN No. 48	—		405		—			—			8			—			413
Conversion of Subordinated units to Common units held by affiliate (Note 12)	5,692		79,378		(5,692	)		(79,378	)		—			—			—
Contribution from affiliate	—		1,173		—			—			24			—			1,197
Distribution to affiliate	—		(251	)	—			—			(5	)		—			(256	)
Unissued units under incentive plans	—		5,310		—			—			—			—			5,310
Distribution equivalent rights	—		(533	)	—			—			—			—			(533	)
Units issued under incentive plans	50		—		—			—			58			—			58
Tax withholding under incentive plans	—		(1,479	)	—			—			—			—			(1,479	)
Cash distributions	—		(95,008	)	—			—			(22,443	)		—			(117,451	)

Balance at December 31, 2007	28,586	$	582,357		—			—		$	8,688			—		$	591,045

Comprehensive Income:
Net income	—		171,311		—			—			43,169			—			214,480
Unrealized loss on cash flow hedges	—		—		—			—			—			(1,130	)		(1,130	)

Total comprehensive income																	213,350
Adjustment to recognize the funded status of our affiliates’ postretirement plans	—		—		—			—			—			(2,000	)		(2,000	)
Contribution from affiliate	—		2,377		—			—			49			—			2,426
Accruals of LITP Awards	—		2,744		—			—			—			—			2,744
Units issued under incentive plans	71		—		—			—			76			—			76
Tax withholding under incentive plans	—		(504	)	—			—			—			—			(504	)
Cash distributions	—		(104,968	)	—			—			(32,235	)		—			(137,203	)
Other	—		(34	)	—			—						—			(34	)

Balance at December 31, 2008	28,657	$	653,283		—			—		$	19,747		$	(3,130	)	$	669,900

Comprehensive Income:
Net income	—		197,697		—			—			52,665			—			250,362
Recovery of unrealized loss on cash flow hedges	—		—		—			—			—			1,080			1,080

Total comprehensive income																	251,442
Adjustment to recognize the funded status of our affiliates’ postretirement plans	—		—		—			—			—			(443	)		(443	)
Issuance of Limited Partners units to the public	2,250		109,514		—			—			2,321			—			111,835
Unissued units under incentive plans	—		5,329		—			—			—			—			5,329
Distribution equivalent rights	—		(1,525	)	—			—			—			—			(1,525	)
Units issued under incentive plans	74		—		—			—			81						81
Tax withholding under incentive plans	—		(2,149	)	—			—			—			—			(2,149	)
Cash distributions	—		(125,029	)	—			—			(47,827	)		—			(172,856	)

Balance at December 31, 2009	30,981	$	837,120		—			—		$	26,987		$	(2,493	)	$	861,614

(See Accompanying Notes)

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Nature of Operations

Sunoco Logistics Partners L.P. (the “Partnership”) is a publicly traded Delaware limited partnership that owns, operates and acquires a substantial portion of Sunoco’s logistics business, consisting of refined product pipelines, terminalling and storage assets, crude oil pipelines, and crude oil acquisition and marketing assets. Sunoco, Inc. and its wholly-owned subsidiaries including Sunoco, Inc. (R&M) are collectively referred to as “Sunoco”. The Partnership is principally engaged in the transport, terminalling and storage of refined products and crude oil and the purchase and sale of crude oil in 13 states located in the northeast, midwest and southwest United States. Sunoco accounted for approximately 13.1 percent of the Partnership’s total revenues for the year ended December 31, 2009.

Principles of Consolidation

The consolidated financial statements reflect the results of Sunoco Logistics Partners L.P. and its wholly-owned subsidiaries, including Sunoco Logistics Partners Operations L.P. (the “Operating Partnership”) and include the accounts of entities in which the Partnership has a controlling financial interest. A controlling financial interest is evidenced by either a voting interest greater than 50% or a risk and rewards model that identifies the Partnership or one of its subsidiaries as the primary beneficiary of a variable interest entity (VIE). All significant intercompany accounts and transactions are eliminated in consolidation. Equity ownership interests in corporate joint ventures, in which the Partnership does not have a controlling financial interest, are accounted for under the equity method of accounting. In management’s opinion, the consolidated financial statements reflect all normal and recurring adjustments needed to fairly present the Partnership’s financial position and operating results at the dates and for the periods presented. The Partnership has evaluated subsequent events through February 23, 2010.

Variable Interest Entities

In June 2009, accounting guidance was issued which retains the fundamental requirement that a variable interest entity (“VIE”) be consolidated by a company if that company is the primary beneficiary. The new guidance clarifies when a company is to be deemed the primary beneficiary and also requires an analysis to be performed to make this determination. In addition, this pronouncement requires ongoing reassessments of whether an entity is the primary beneficiary of a VIE. Implementation of this guidance is required beginning January 1, 2010. The Partnership is evaluating the impact this guidance will have on its financial statements.

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual amounts could differ from these estimates.

Revenue Recognition

Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil gathering and marketing revenues are recognized when title to the crude oil is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to the Partnership’s end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of income.

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NOTES TO FINANCIAL STATEMENTS—(Continued)

Affiliated revenues consist of sales of crude oil as well as the provision of crude oil and refined products pipeline transportation, terminalling and storage services to Sunoco. Sales of crude oil to affiliates are priced using market based rates. Sunoco pays fees for transportation or terminalling services based on the terms and conditions of an established agreement or utilizing published tariffs.

Cash Equivalents

The Partnership considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. At December 31, 2008 and 2009, these cash equivalents consist principally of money market accounts.

Accounts Receivable, net

Accounts receivable represent valid claims against non-affiliated customers (see Note 3 for affiliated receivables) for products sold or services rendered. The Partnership extends credit terms to certain customers after review of various credit indicators, including the customer’s credit rating. Outstanding customer receivable balances are regularly reviewed for possible non-payment indicators and reserves are recorded for doubtful accounts based upon management’s estimate of collectability at the time of review. Actual balances are charged against the reserve when all collection efforts have been exhausted.

Inventories

Inventories are valued at the lower of cost or market. Crude oil and refined product inventory costs have been determined using the last-in, first-out method (“LIFO”). Under this methodology, the cost of products sold consists of the actual acquisition costs of the Partnership, which includes transportation and storage costs. Such costs are adjusted to reflect increases or decreases in inventory quantities, which are valued based on the changes in the LIFO inventory layers. The cost of materials, supplies and other inventories is principally determined using the average cost method. Crude oil inventory balances declined in the Partnership’s Crude Pipeline business segment during 2007 and 2009, which resulted in liquidating a portion of the prior year layer carried at lower costs. The reduction resulted predominately from the elimination of contango inventory positions, and had the effect of increasing results of operations by $11.0 million in 2007 and $1.1 million in 2009.

Properties, Plants and Equipment

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

Capitalized Interest

The Partnership capitalizes interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. During the years ended December 31, 2007, 2008 and 2009, the amount of interest capitalized was $3.4 million, $3.9 million and $4.3 million, respectively. The weighted average rate used to capitalize interest on borrowed funds was 6.5 percent, 5.9 percent and 5.4 percent for 2007, 2008 and 2009, respectively.

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NOTES TO FINANCIAL STATEMENTS—(Continued)

Investment in Affiliates

Investments in affiliates, which consist of corporate joint ventures, are accounted for under the equity method of accounting. Under this method, an investment is carried at acquisition cost, increased for the equity in income or decreased for the equity in loss from the date of acquisition, reduced for dividends received and increased or decreased for adjustments in other comprehensive income. Income recognized from the Partnership’s corporate joint venture interests is presented within other income on the statements of income. The Partnership had $10.4 million of undistributed earnings from its investments in corporate joint ventures within Partners’ Capital at December 31, 2009. During the years ended December 31, 2007, 2008 and 2009 the Partnership received dividends of $23.9 million, $22.2 million and $19.2 million respectively, from its investments in corporate joint ventures.

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

Acquisitions

The purchase price of acquired businesses is allocated between tangible and intangible assets acquired and liabilities assumed based on their estimated fair values. Any excess of purchase price over the estimated fair values of net assets acquired is recorded as goodwill. The results of operations of acquired businesses are included in the Partnership’s results from the dates of acquisition. The purchase price of acquired assets is allocated to the underlying assets based on their relative fair values.

Beginning January 1, 2009, the Partnership adopted revisions to accounting guidance on the topic of business combinations. The revised guidance provides a new model for the initial recognition and measurement, subsequent measurement and accounting and disclosure of identifiable assets and goodwill acquired, liabilities assumed, including assets and liabilities from contingencies, in a business combination. The new guidance impacts only those acquisitions completed after January 1, 2009. The revised guidance addresses the mechanics of determining and allocating the purchase price to the underlying net assets; however, it does not change the overall policy of the Partnership to allocate the purchase price between tangible and intangible assets acquired and liabilities assumed based on their estimated fair values.

Impairment of Long-Lived Assets

Long-lived assets other than those held for sale are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. An asset is considered to be impaired when the undiscounted estimated net cash flows expected to be generated by the asset are less than its carrying amount. The impairment recognized is the amount by which the carrying amount exceeds the estimated fair value of the impaired asset. Long-lived assets held for sale are recorded at the lower of their carrying amount or estimated fair value less cost to sell the assets. During 2008, the Partnership recognized an impairment of $5.7 million related to Management’s decision to discontinue efforts to expand liquefied petroleum gas storage capacity at its Inkster, Michigan facility. The impairment charge reflects the entire cost associated with the project.

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NOTES TO FINANCIAL STATEMENTS—(Continued)

Goodwill and Other Intangible Assets

Goodwill, which represents the excess of the purchase price over fair value of net assets acquired, is presented net of accumulated amortization within deferred charges and other assets on the balance sheets. As of December 31, 2008 and 2009, the Partnership had $16.2 million of goodwill and accumulated amortization of $1.3 million related to goodwill. Goodwill and indefinite-lived intangible assets are tested for impairment at least annually. The Partnership determined during 2007, 2008 and 2009 that such assets were not impaired.

Deferred financing fees of $2.5.million and $4.1 million, net of accumulated amortization of $2.6 million and $3.9 million have been included within deferred charges and other assets on the balance sheets as of December 31, 2008 and 2009, respectively. The Partnership incurred $2.9 million in additional deferred financing fees during 2009 related to the February 2009 issue of senior notes. Amortization expense of $0.7 million, $0.6 million and $1.3 million for the years ended December 31, 2007, 2008 and 2009, respectively, has been included within other interest cost and debt expense on the statements of income. The Partnership amortizes deferred financing fees over the life of the respective debt agreement.

The Partnership acquires throughput and deficiency contracts from time to time, generally associated with acquisitions of businesses or assets. The value assigned to these contracts is amortized on a straight-line basis through operating expenses in the statements of income over the term of the underlying contract. At December 31, 2009, the Partnership recorded $22.1 million of throughput and deficiency contracts net of accumulated amortization of $0.5 million. Amortization of these contracts for the year ended December 31, 2009 was $0.5 million and is included with depreciation and amortization in the statement of income. Amortization expense for these contracts is estimated to be $1.2 million each of the next five years ending in 2014.

Environmental Remediation

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

Income Taxes

No provision for U.S. federal income taxes is included in the accompanying financial statements. As a partnership, we are not a taxable entity for U.S. federal income tax purposes, or for the majority of states that impose income taxes. The Partnership’s taxable income, which may vary substantially from the net income reported for financial reporting purposes, is includable in the federal and state income tax returns of our unitholders. There are some states, however, in which the Partnership operates where it is subject to state and local income taxes.

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

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NOTES TO FINANCIAL STATEMENTS—(Continued)

Long-Term Incentive Plan

The Partnership accounts for the compensation cost of all unit-based payment awards at fair value and reports the related expense within selling, general and administrative expenses in the income statement. Unit- based compensation cost for awards of restricted units is derived from the fair market value of common units on the grant date using a Monte Carlo Simulation or grant date market price of the underlying unit. The Partnership recognizes unit-based compensation cost as expense ratably on a straight-line basis over the requisite service period unless the participant is retirement eligible, in which case, the recognition of the compensation cost is accelerated in the period the participant becomes retirement-eligible.

Asset Retirement Obligations

Asset retirement obligations (ARO’s) represent the fair value of a liability related to the retirement of long-lived assets and are recorded at the time a legal obligation is incurred. A corresponding asset is also recorded at that time and is depreciated over the remaining useful life of the related asset. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, future inflation rates and credit-adjusted risk-free interest rates. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.

The Partnership’s balance sheet includes liabilities for asset retirement obligations, as a component of other deferred credits and liabilities, of $22.5 million and $25.1 million at December 31, 2008 and 2009, respectively. During 2009, the Partnership increased the liability for asset retirement obligations and properties, plants and equipment by $2.5 million related to the obligations associated with late 2008 and 2009 acquisitions of crude oil and refined product pipelines and terminals. This change did not have a significant impact on the Partnership’s statement of income for the year ended December 31, 2009. During 2008, the Partnership had no changes to the liability for asset retirement obligations and properties, plant and equipment. The Partnership believes it may have additional asset retirement obligations related to its pipeline assets and storage tanks, for which it is not possible to estimate when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time.

Fair Value Measurements

The Partnership applies fair value accounting for all financial assets and liabilities that are recognized or disclosed at fair value in the financial statements. The Partnership’s financial assets and liabilities consist primarily of debt and an interest rate swap. Beginning January 1, 2009, the Partnership applied fair value accounting to its non-financial assets and liabilities. The Partnership’s non-financial assets and liabilities consist principally of goodwill (for its annual impairment test) and asset retirement obligations. Applying fair value accounting to non-financial assets and liabilities did not have a material effect on the consolidated financial statements.

The Partnership determines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Partnership utilizes valuation techniques that maximize the use of observable inputs (levels 1 and 2) and minimize the use of unobservable inputs (level 3) within the fair value hierarchy established by the Financial Accounting Standards Board (“FASB”). This hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable other than quoted prices in active markets for identical assets and liabilities, quoted prices for identical or similar assets or liabilities in inactive markets, or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities. Level 3 inputs are generally unobservable and typically reflect management’s estimates of assumptions that market participants would use in pricing the asset or liability.

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NOTES TO FINANCIAL STATEMENTS—(Continued)

The Partnership generally applies a “market approach” to determine fair value. This method uses pricing and other information generated by market transactions for identical or comparable assets and liabilities. When determining the fair value measurements for assets and liabilities, which are required to be recorded or disclosed at fair value, the Partnership considers the principal or most advantageous market in which the Partnership would transact and the market-based risk measurements or assumptions that market participants would use in pricing the asset or liability, such as inherent risk, transfer restrictions and credit risk. Assets and liabilities are classified within the fair value hierarchy based on the lowest level (least observable) input that is significant to the measurement in its entirety. The Partnership’s financial instruments recorded at fair value are not material at December 31, 2009.

The Partnership is permitted to irrevocably elect to measure eligible financial instruments and certain other items at fair value that are currently not required to be measured at fair value. The Partnership has not elected the fair value option for any eligible financial instruments.

Lease Accounting

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

Earnings Per Unit

The Partnership uses the two-class method to determine basic and diluted earnings per unit. The two-class method is an earnings allocation formula that determines the earnings per unit for each class of equity ownership and participating security according to dividends declared and participation rights in undistributed earnings. The Partnership calculates basic and diluted net income per limited partner unit by dividing net income, after deducting the amount allocated to the general partner’s interest and incentive distribution rights, by the weighted-average number of limited partner units outstanding during the period. The general partner holds all of the incentive distribution rights.

On January 1, 2009 the Partnership adopted updated revisions to the FASB’s Accounting Standards Codification (ASC) whereby, incentive distribution rights (“IDRs”) in a master limited partnership are treated as participating securities for the purpose of computing earnings per unit. In addition, when earnings differ from cash distributions, undistributed or over distributed earnings are to be allocated to the IDR holders and limited partners based on the contractual terms of the partnership agreement. Previously, earnings per unit was calculated as if all earnings for the period had been distributed, which resulted in an additional allocation of income to the general partner (the IDR holder) in quarterly periods where earnings exceeded the actual distribution and a lesser allocation of income to the general partner in quarterly periods where distributions exceeded earnings.

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NOTES TO FINANCIAL STATEMENTS—(Continued)

The Partnership has retrospectively applied this new method to all periods presented. The Partnership’s adoption of this guidance only impacts the allocation of earnings for purposes of calculating our earnings per limited partner unit and has no impact on our results of operations or distributions of available cash to unitholders and our general partner. The following table illustrates the impact of this change in accounting principle on the basic and diluted earnings per unit for the years ended December 31,:


	Basic				Diluted
	As Reported		Restated		As Reported		Restated
2008	$	5.01	$	6.19	$	4.98	$	6.15
2007		3.38		3.39		3.37		3.37

2. Equity Offerings

On February 1, 2010, the Partnership amended its registration statement for its limited partnership interests and debt securities. The amendment allows the general partner to sell, in one or more offerings, the common units it owns under the Partnership’s registration statement. For each offering of the general partner’s limited partnership units, the Partnership provides a prospectus supplement that contains specific information about the terms of that offering and the securities offered by the general partner in that offering. On February 5, 2010, Sunoco executed a registered secondary offering of 2.2 million common units which resulted in reducing their ownership to 33.2 percent, including their 2 percent general partner interest. The Partnership did not receive any proceeds from this offering.

3. Related Party Transactions

Incentive Distribution Rights Exchange

On January 26, 2010, the Partnership entered into a repurchase agreement with its general partner, whereby the Partnership agreed to repurchase from the general partner the existing incentive distribution rights for $201.2 million and the issuance of new incentive distribution rights. Pursuant to this transaction, the Partnership executed the third amended and restated agreement of limited partnership of the Partnership (the “new partnership agreement”). The new partnership agreement reflects the cancellation of the original incentive distribution rights and the authorization and issuance of the new incentive distribution rights (Note 12).

The Partnership is financing this arrangement with a promissory note to the general partner that is due December 31, 2010. Proceeds from the February 2010 issuance of $500.0 million in Senior Notes were used to repay this promissory note (Note 9).

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NOTES TO FINANCIAL STATEMENTS—(Continued)

Pipelines and Terminals Storage and Throughput Agreement

In 2002, the Partnership entered into a pipelines and terminals storage and throughput agreement with Sunoco under which Sunoco agreed to pay the Partnership a minimum level of revenues for the transportation and throughput of refined products and agreed to minimum volume levels of storage and throughput of crude oil and liquefied petroleum gas. Sunoco’s obligations under this agreement have since expired and have been replaced by the following agreements:

•

In February 2007, certain obligations under the agreement relating to throughput of refined products through the Partnership’s refined products marketing terminals and our Marcus Hook Tank Farm expired. On March 1, 2007 the Partnership entered into (i) a new five-year product terminal services agreement with Sunoco under which Sunoco may throughput refined products through our terminals, and (ii) a new 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.

•

In the first quarter of 2009, Sunoco’s remaining obligations under the 2002 agreement relating to minimum volume levels of storage and throughput of crude oil and refined products at the Fort Mifflin Terminal Complex and minimum volume levels of storage and throughput of liquefied petroleum gas at the Inkster Terminal expired. The Partnership entered into a new three-year agreement with Sunoco, effective April 1, 2009, relating to the Inkster Terminal. Under this agreement, Sunoco will annually throughput a minimum of 968,550 barrels of liquefied petroleum gas originating at Sunoco’s Toledo, Ohio refinery to and from the Inkster Terminal. This minimum throughput is an annual amount for each contract period running from April 1 to March 31. Additionally, Sunoco will annually throughput a minimum of 250,000 barrels of propane across the Inkster Terminal loading rack. This minimum propane throughput is an annual amount for each contract period running from April 1 to March 31, and will be pro-rated for the 2009-2010 term to account for the rack installation.

•

The Partnership also entered into a new three year-agreement with Sunoco, effective March 1, 2009, relating to the Fort Mifflin Terminal Complex. Under this agreement, Sunoco will deliver an average of 300,000 barrels per day 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 the Partnership is obligated to provide the necessary tanks, marine docks and pipelines for Sunoco to meet its minimum requirements under the agreement.

Eagle Point Logistics Assets Purchase and Throughput Agreements

On March 30, 2004, the Partnership entered into a purchase agreement with Sunoco to acquire the Eagle Point refinery logistics assets for approximately $20 million. On January 24, 2008, the Partnership executed an Amended and Restated Dock and Terminal Throughput Agreement with Sunoco which amended certain terms that were included in the original throughput agreement entered into with Sunoco upon acquiring the Eagle Point assets. Also included in this agreement were fees to receive and deliver refined and intermediate products through the Partnership’s Eagle Point terminal facility.

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NOTES TO FINANCIAL STATEMENTS—(Continued)

On February 1, 2010 Sunoco announced its permanent shutdown of the Eagle Point refinery. Sunoco expects to continue to distribute refined products through the Partnership’s Eagle Point terminal. The Partnership’s assets, including docks, terminals and pipelines, which provide logistics support to the Eagle Point refinery had a net book value of $62.0 million as of December 31, 2009 and generated revenues of $15.6 million for the year ended December 31, 2009. The Partnership does not expect the shutdown of the Eagle Point refinery to have a material impact on the Partnership’s results of operations and continue to work with Sunoco to evaluate the impact, if any, that the shutdown of the Eagle Point refinery will have on our operating results and the net book value of the Partnership’s assets. The Partnership did not recognize an impairment charge during 2009 as a result of the shutdown.

Advances to/from Affiliate

The Partnership has a treasury services agreement with Sunoco pursuant to which it, among other things, participates in Sunoco’s centralized cash management program. Under this program, all of the Partnership’s cash receipts and cash disbursements are processed, together with those of Sunoco and its other subsidiaries, through Sunoco’s cash accounts with a corresponding credit or charge to an intercompany account. The intercompany balances are settled periodically, but no less frequently than monthly. Amounts due from Sunoco earn interest at a rate equal to the average rate of the Partnership’s third-party money market investments, while amounts due to Sunoco bear interest at a rate equal to the interest rate provided in the Operating Partnership’s $400 million Credit Facility.

Administrative Services

Under the Omnibus Agreement, the Partnership pays Sunoco or the 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 $6.5 million, $6.0 million and $6.0 million for the years ended December 31, 2007, 2008, and 2009, respectively. This fee does not include the costs of shared insurance programs (which are allocated to the Partnership based upon its share of the cash premiums incurred), the salaries of pipeline and terminal personnel or other employees of the general partner (including senior executives), or the cost of their employee benefits. The Partnership has no employees, and reimburses Sunoco and its affiliates for these costs and other direct expenses incurred on the Partnership’s behalf. In addition, the Partnership has incurred additional general and administrative costs which it pays directly. The term of Section 4.1 of the Omnibus Agreement (which concerns the Partnership’s obligation to pay the annual fee for provision of certain general and administrative services) was extended by one year in January 2010. The 2010 annual fee is $5.4 million. These costs may be increased if the acquisition or construction of new assets or businesses requires an increase in the level of general and administrative services received by the Partnership. There can be no assurance that Section 4.1 of the Omnibus Agreement will be extended beyond 2010, or that, if extended, the administrative fee charged by Sunoco will be at or below the current administrative fee. In the event that the Partnership is unable to obtain such services from Sunoco or other third parties at or below the current cost, the Partnership’s financial condition and results of operations may be adversely impacted.

In addition to the fees for the centralized corporate functions, selling, general and administrative expenses in the statements of income include the allocation of shared insurance costs of $3.9 million, $3.2 million and $3.5 million for the years ended December 31, 2007, 2008 and 2009 respectively. The Partnership’s share of allocated Sunoco employee benefit plan expenses, including non-contributory defined benefit retirement plans, defined contribution 401(k) plans, employee and retiree medical, dental and life insurance plans, incentive compensation

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NOTES TO FINANCIAL STATEMENTS—(Continued)

plans and other such benefits was $23.0 million, $22.8 million and $27.7 million for the years ended December 31, 2007, 2008 and 2009 respectively. These expenses are reflected in cost of products sold and operating expenses and selling, general and administrative expenses in the statements of income.

Affiliated Revenues and Accounts Receivable, Affiliated Companies

Affiliated revenues in the statements of income consist of sales of crude oil as well as the provision of crude oil and refined product pipeline transportation, terminalling, storage and blending services to Sunoco. Sales of crude oil are priced using market based rates under agreements which automatically renew on a monthly basis unless terminated by either party on 30 days’ written notice. Additionally, the Partnership has entered into the following agreements to provide terminalling services to Sunoco:

Capital Contributions

Under the terms of the Interrefinery Lease Agreement, Sunoco is required to reimburse the Partnership for any non-routine maintenance expenditures, as defined, incurred during the term of the agreement. The Eagle Point purchase agreement requires Sunoco to reimburse the Partnership for certain maintenance capital and expense expenditures incurred regarding the assets acquired, as defined, up to $5.0 million within the first 10 years of closing of the transaction. The Partnership also entered into other various agreements with Sunoco following the Eagle Point agreement for additional reimbursements. For the years ended December 31, 2007, and 2008 the Partnership incurred maintenance capital expenditures of $1.2 million and $1.9 million, respectively, under the provisions within these agreements and was reimbursed by Sunoco. The reimbursements were recorded as capital contributions to Partners’ Capital within the Partnership’s balance sheet. The maximum reimbursement under these contracts was attained during 2008.

In February 2007, 2008 and 2009 the Partnership issued 0.1 million common units, in each year, to participants in the Sunoco Partners LLC Long-Term Incentive Plan (“LTIP”) upon completion of award vesting requirements. As a result of these issuances of common units, the general partner contributed $0.1 million in each period to the Partnership to maintain its 2.0 percent general partner interest. The Partnership recorded these amounts as capital contributions to Partners’ Capital within its consolidated balance sheets.

In April and May 2009, the Partnership sold 2.25 million common units in a public offering. As a result of the issuance, the general partner contributed $2.3 million to the Partnership to maintain its 2.0 percent general partner interest. The Partnership recorded this amount as a capital contribution to Partners’ Capital within its consolidated balance sheet.

4. Acquisitions

A key component of the Partnership’s primary business strategy is to pursue strategic and accretive acquisitions that compliment its existing asset base. To that end, the Partnership has made the following acquisitions during the three year period ended December 31, 2009.

On September 1, 2009, the Partnership purchased a refined products terminal located in Romulus, Michigan from R.K.A. Petroleum LLC (“RKA”) for approximately $18.0 million. Total terminal storage capacity is approximately 350,000 barrels, services the Detroit metropolitan area and is connected to the Partnership’s pipeline system. The purchase price of the acquisition was funded with borrowings under the Operating Partnership’s $400 million Credit Facility, and has been allocated to properties, plants and equipment. The agreement included a contingency clause which requires additional payments to RKA up to $1.5 million, if

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NOTES TO FINANCIAL STATEMENTS—(Continued)

revenue generated as a result of certain customers/products exceeds a pre-determined amount. The estimated fair value of the contingency is included in the purchase price. The results of the acquisition are included in the financial statements within the Terminal Facilities segment.

On September 9, 2009, the Partnership purchased a 100% membership interest in Excel Pipeline LLC (“Excel”) from affiliates of Gary-Williams Energy Corporation (“Gary-Williams”) for approximately $32.2 million. The tangible assets of Excel consist of approximately 52 miles of a crude oil pipeline originating in Duncan, OK and terminating at Gary-Williams’ refinery in Oklahoma. The Partnership was the operator of the pipeline prior to the acquisition. The purchase price of the acquisition was funded with borrowings under the Operating Partnership’s $400 million Credit Facility and was preliminarily allocated to the underlying assets based on their relative fair values. In connection with the transaction, the Partnership assumed a 20-year throughput and deficiency contract with Gary-Williams. Pursuant to the contract, Gary-Williams guarantees minimum amounts of crude oil throughput on the pipelines and the Partnership agrees to provide transportation of such crude oil. We estimated the fair value of the contract based on the discounted expected cash flows attributable to that contract. We estimated the fair value of properties, plants and equipment based on comparable transactions and replacement costs of those same assets in the same condition and stage of usefulness. The following is a summary of the effects of the transaction on the Partnership’s consolidated financial position (in thousands of dollars) as of the acquisition date:


Increase in:
Throughput and deficiency arrangement	$	21,311
Properties, plants and equipment		10,921

Cash paid for acquisition	$	32,232

The results of the acquisition are included in the financial statements within the Crude Oil Pipeline System segment.

On November 18, 2008, the Partnership purchased a refined products pipeline system from affiliates of Exxon Mobil Corporation for approximately $186.0 million. The system consists of approximately 280 miles of refined products pipeline originating in Beaumont and Port Arthur and terminating in Hearne, Texas; another 200 miles of refined products pipeline originating in Beaumont and terminating in Waskom, Texas; and refined product facilities located in Hearne, Hebert, Waco, Center and Waskom, Texas and Arcadia, Louisiana with active storage capacity of 1.2 million shell barrels. The purchase price of the acquisition was funded with borrowings under the Operating Partnership’s $400 million Credit Facility. The purchase price has been allocated to the assets and liabilities acquired based on their relative fair values on the acquisition date. The final purchase price allocation was $190,559, which includes cash paid of $185,963, the assumption of an environmental liability of $2,093 and the assumption of asset retirement obligations of approximately $2,503. The final purchase price allocation was as follows:


Allocation:
Inventories	$	553
Throughput and deficiency arrangement		1,231
Rights of way and land		25,776
Pipeline and terminal assets		162,999

Purchase price	$	190,559

The results of the acquisition are included in the financial statements within the Refined Products Pipeline System and Terminal Facilities business segments.

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

On June 1, 2007, the Partnership purchased a 50 percent undivided interest in a refined products terminal located in Syracuse, New York from Mobil Pipe Line Company, an affiliate of Exxon Mobil Corporation for approximately $13.4 million. Total terminal storage capacity is approximately 550,000 barrels. The purchase price of the acquisition was funded with borrowings under the Operating Partnership’s previous credit facility, and has been allocated to property, plants and equipment based on the relative fair value of the assets acquired on the acquisition date. The results of the acquisition are included in the financial statements within the Terminal Facilities business segment.

5. Net Income Per Unit Data

The general partner’s interest in net income consists of its 2.0 percent general partner interest and “incentive distributions”, which are increasing percentages, up to 50 percent of quarterly distributions in excess of $0.50 per limited partner unit (see Note 12). The general partner was allocated net income $24.1 million (representing 19.9 percent of total net income for the period) for the year ended December 31, 2007, $37.1 million (representing 17.3 percent of total net income for the period) for the year ended December 31, 2008, and $52.7 million (representing 21.0 percent of total net income for the period) for the year ended December 31, 2009. Diluted net income per limited partner unit is calculated by dividing net income applicable to limited partners by the sum of the weighted-average number of common and subordinated units outstanding and the dilutive effect of incentive unit awards (see Note 11), as calculated by the treasury stock method.

The following table sets forth the reconciliation of the weighted average number of limited partner units used to compute basic net income per limited partner unit to those used to compute diluted net income per limited partner unit for the years ended December 31, 2007, 2008 and 2009:


	2007	2008	2009
Weighted average number of limited partner units outstanding—basic	28,581,032	28,650,069	30,310,618
Add effect of dilutive unit incentive awards	148,121	186,534	207,273

Weighted average number of limited partner units—diluted	28,729,153	28,836,603	30,517,891

6. Inventories

The components of inventories are as follows (in thousands of dollars):


	December 31,
	2008		2009
Crude oil	$	87,645	$	82,511
Refined products		—		1,857
Refined products additives		1,670		1,765
Materials, supplies and other		841		841

	$	90,156	$	86,974

The current replacement cost of crude oil and refined products inventory exceeded its carrying value by $44.7 million and $147.3 million at December 31, 2008 and 2009, respectively.

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

7. Properties, Plants and Equipment

The components of net properties, plants and equipment are as follows (in thousands of dollars):


	Estimated Useful Lives	December 31,
	Estimated Useful Lives	2008			2009
Land and land improvements (including rights of way)	—	$	89,457		$	119,535
Pipeline and related assets	38 - 60		967,469			1,046,939
Terminals and storage facilities	5 - 44		537,702			620,246
Other	5 - 48		225,827			296,607
Construction-in-progress			125,362			67,166

			1,945,817			2,150,493
Less: Accumulated depreciation and amortization			(570,388	)		(616,772	)

		$	1,375,429		$	1,533,721

8. Investment in Affiliates

The corporate joint ventures own and operate refined product pipeline systems or crude oil pipeline systems. The Partnership’s ownership percentages in corporate joint ventures as of December 31, 2008 and 2009 are as follows:


	Partnership Ownership Percentage
Explorer Pipeline Company	9.4	%
Wolverine Pipe Line Company	31.5	%
West Shore Pipe Line Company	12.3	%
Yellowstone Pipe Line Company	14.0	%
West Texas Gulf Pipe Line Company	43.8	%
Mid-Valley Pipeline Company⁽¹⁾	55.3	%

⁽¹⁾	Mid-Valley Pipeline Company includes 50 percent voting rights.

The following table provides summarized unaudited financial information on a 100 percent basis for the Partnership’s equity ownership interests (in thousands of dollars):


	2007		2008		2009
Income Statement Data:
Total revenues	$	513,302	$	470,146	$	457,809
Income before income taxes	$	208,067	$	151,446	$	190,159
Net income	$	132,654	$	95,700	$	118,998
Balance Sheet Data (as of year-end):
Current assets	$	181,683	$	115,097	$	126,330
Non-current assets	$	692,331	$	682,453	$	679,955
Current liabilities	$	122,229	$	123,423	$	123,506
Non-current liabilities	$	661,777	$	591,101	$	568,349
Net equity	$	90,008	$	83,026	$	114,430

The Partnership’s investments in Wolverine, West Shore, Yellowstone, and West Texas Gulf at December 31, 2009 include an excess investment amount of approximately $53.0 million, net of accumulated amortization of $4.6 million. The excess investment is the difference between the investment balance and the

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

Partnership’s proportionate share of the net assets of the entities. During the years ended December 31, 2007, 2008 and 2009, the Partnership has not provided additional financial support to any of the joint ventures.

9. Long-Term Debt & Revolving Credit Facilities

The components of long-term debt and revolving credit facilities are as follows (in thousands of dollars):


	December 31,
	2008			2009
$400 million Credit Facility – due November 2012	$	323,385		$	237,722
$62.5 million Credit Facility – due September 2011		—			31,250
Senior Notes—7.25%, due February 15, 2012		250,000			250,000
Senior Notes—6.125%, due May 15, 2016		175,000			175,000
Senior Notes—8.75%, due February 15, 2014		—			175,000
Less unamortized bond discount		(754	)		(548	)

	$	747,631		$	868,424

$400 Million Credit Facility

The Operating Partnership has a five-year $400 million revolving credit facility (“$400 million Credit Facility”) with a current syndicate of 10 participating financial institutions. The $400 million Credit Facility is available to fund the Operating Partnership’s working capital requirements, to finance future acquisitions, to finance future capital projects and for general partnership purposes. The $400 million Credit Facility matures in November 2012 and may be prepaid at any time. It bears interest at the Operating Partnership’s option, at either (i) LIBOR plus an applicable margin, (ii) the higher of the federal funds rate plus 0.50 percent or the Citibank prime rate (each plus the applicable margin) or (iii) the federal funds rate plus an applicable margin. The $400 million Credit Facility contains various covenants limiting the Operating Partnership’s ability to incur indebtedness; grant certain liens; make certain loans, acquisitions and investments; make any material change to the nature of its business; acquire another company; or enter into a merger or sale of assets, including the sale or transfer of interests in the Operating Partnership’s subsidiaries. The $400 million Credit Facility also limits the Partnership, on a rolling four-quarter basis, to a maximum total consolidated debt to consolidated EBITDA ratio of 4.75 to 1, which can generally be increased to 5.25 to 1 during an acquisition period. The Partnership is in compliance with this covenant at December 31, 2009.

In September 2008, Lehman Brothers, one of the participating banks with a commitment under the facility amounting to $5 million, declared bankruptcy and then failed to fund its share of the Partnership’s borrowings under this facility.

$62.5 Million Credit Facility

On March 13, 2009, the Operating Partnership entered into a $62.5 million revolving credit facility (“$62.5 million Credit Facility”) with a syndicate of two participating financial institutions. This credit facility is available to fund the Operating Partnership’s working capital requirements, to finance future acquisitions and for general partnership purposes. The $62.5 million Credit Facility matures in September 2011 and may be prepaid at any time. It bears interest at the Operating Partnership’s option, at either (i) LIBOR plus an applicable margin or (ii) the higher of (a) the federal funds rate plus 0.50 percent plus an applicable margin, (b) Toronto Dominion’s prime rate plus an applicable margin or (c) LIBOR plus 1.0 percent plus an applicable margin. The $62.5 million Credit Facility contains various covenants similar to the $400 million Credit Facility and limits the

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

Operating Partnership, on a rolling four-quarter basis, to a maximum debt to EBITDA ratio of 4.0 to 1, which can generally be increased to 4.5 to 1 during an acquisition period. The Partnership is in compliance with this covenant at December 31, 2009.

Interest Rate Swap

The Partnership uses interest rate swaps, a type of derivative financial instrument, to manage interest costs and minimize the effects of interest rate fluctuations on cash flows associated with its credit facilities. The Partnership does not use interest rate derivatives for trading or speculative purposes. While interest rate swaps are subject to fluctuations in value, these fluctuations are generally offset by the value of the underlying exposures being hedged. The Partnership minimizes the risk of credit loss by entering into these agreements with financial institutions that have high credit ratings. The Partnership records all derivatives on the balance sheet at fair value. Changes in fair value are recorded each period in current earnings or other comprehensive income, depending on whether a derivative has been designated as part of a hedge transaction and, if it is, depending on the type of hedge transaction. Interest rate swaps are designated as cash flow hedges. Changes in the fair value of a cash flow hedge, to the extent the hedge is effective, are recorded, net of tax, in other comprehensive income (loss), a component of Partners’ capital, until earnings are affected by the variability of the hedged cash flows. Cash flow hedge ineffectiveness, defined as the extent that the changes in the fair value of the derivative exceed the variability of cash flows of the forecasted transaction, is recorded currently in earnings.

In January 2008, the Partnership entered into a $50.0 million floating to fixed interest rate swap agreement (the “Swap”) that matured during January 2010. Under the Swap, the Partnership received interest equivalent to the three-month LIBOR and pays a fixed rate of interest of 3.489 percent, with settlements occurring quarterly. The objective of the hedge was to eliminate the variability of cash flows in interest payments for $50.0 million of floating rate debt. The Swap’s fair value was $(1.1) million and $0.1 million as of December 31, 2008 and 2009. The corresponding change in fair value is included in other comprehensive income, a component of Partners’ equity. There was no cash flow hedge ineffectiveness recorded during 2008 or 2009.

Senior Notes

In 2002, the Operating Partnership issued $250 million of 7.25 percent Senior Notes, due February 15, 2012 (the “2012 Senior Notes”) at 99.325 percent of the principal amount, for net proceeds of $244.8 million after the underwriter’s commission and legal, accounting and other transaction expenses. The 2012 Senior Notes are redeemable, at a make-whole premium, and are not subject to sinking fund provisions. The 2012 Senior Notes contain various covenants limiting the Operating Partnership’s ability to incur certain liens, engage in sale/leaseback transactions, or merge, consolidate or sell substantially all of its assets. The Operating Partnership is in compliance with these covenants as of December 31, 2009. In addition, the 2012 Senior Notes are also subject to repurchase by the Operating Partnership at a price equal to 100 percent of their principal amount, plus accrued and unpaid interest upon a change of control to a non-investment grade entity.

In May 2006, the Operating Partnership issued $175 million of 6.125 percent Senior Notes, due May 15, 2016 (the “2016 Senior Notes”) at 99.858 percent of the principal amount, for net proceeds of $173.3 million after the underwriter’s commission and legal, accounting and other transaction expenses. The 2016 Senior Notes are redeemable, at a make-whole premium, and are not subject to sinking fund provisions. The 2016 Senior Notes contain various covenants limiting the Operating Partnership’s ability to incur certain liens, engage in sale/leaseback transactions, or merge, consolidate or sell substantially all of its assets. The Operating Partnership is in compliance with these covenants as of December 31, 2009.

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

Operating Partnership’s ability to incur certain liens, engage in sale/leaseback transactions, or merge, consolidate or sell substantially all of its assets. The net proceeds of $173.3 million from the 2014 Senior Notes, were used to repay outstanding borrowings under the Operating Partnership’s $400 million Credit Facility. The Operating Partnership is in compliance with these covenants as of December 31, 2009.

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 the Operating Partnership’s ability to incur certain liens, engage in certain sale/leaseback transactions, or merge, consolidate or sell substantially all of its assets. The net proceeds of $494.6 million from the 2020 and 2040 Senior Notes, were used to repay the $201.2 million promissory note issued in connection with the Partnership’s repurchase and exchange of its IDR interest, repay outstanding borrowings under the Operating Partnership’s $400 million Credit Facility and for general partnership purposes.

The Partnership has no operations and its only assets are its investments in its wholly-owned partnerships and subsidiaries. The Operating Partnership also has no operations and its assets are limited primarily to its investments in its wholly-owned operating partnerships, deferred charges, and cash and cash equivalents of $2.0 million. Except for amounts associated with the 2012 Senior Notes, 2014 Senior Notes and 2016 Senior Notes, the $400 million and $100 million Credit Facilities, cash and cash equivalents and advances to affiliate, the assets and liabilities in the balance sheets and the revenues and costs and expenses in the statements of income are primarily attributable to the operating partnerships. See Note 16 for supplemental condensed consolidating financial information.

The Partnership currently serves as guarantor of the 2012 Senior Notes, 2014 Senior Notes, 2016 Senior Notes, 2020 Senior Notes and 2040 Senior Notes and of any obligations under the $400 million and $62.5 million Credit Facilities. These guarantees are full and unconditional. See Note 16 for supplemental condensed consolidating financial information.

The aggregate amount of long-term debt maturities is as follows (in thousands of dollars):


Year Ended December 31:⁽¹⁾
2011	$	31,250
2012		487,723
2014		175,000
Thereafter		175,000

	$	868,973

⁽¹⁾	Excludes maturities and interest related to the February 2010 issuance of $250.0 million of 5.50% senior notes due in 2020 and $250.0 million of 6.85% senior notes due in 2040

The fair values of our credit facilities are determined by a valuation model which is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. At December 31, 2009, the fair values of the credit facilities approximates their carrying values since the interest rates charged reflect current market rates. The fair value of senior notes is determined using observable market prices as these notes are actively traded. At December 31, 2009, the fair value of senior notes is estimated to be $664.4 million.

Cash payments for interest related to long-term debt, net of capitalized interest (see Note 1), were, $32.0 million, $32.4 million and $41.2 million in 2007, 2008 and 2009, respectively.

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

10. Commitments and Contingent Liabilities

Total rental expense for 2007, 2008 and 2009 amounted to $6.6 million, $6.1 million and $6.6 million, respectively. The Partnership, as lessee, has noncancelable operating leases for land, office space and equipment for which the aggregate amount of future minimum annual rentals as of December 31, 2009 is as follows (in thousands of dollars):


Year Ended December 31:
2010	$	4,295
2011		3,947
2012		3,702
2013		1,433
2014		1,305
Thereafter		5,337

Total	$	20,019

The Partnership is subject to numerous federal, state and local laws which regulate the discharge of materials into the environment or that otherwise relate to the protection of the environment. These laws and regulations result in liabilities and loss contingencies for remediation at the Partnership’s facilities and at third-party or formerly owned sites. At December 31, 2008 and 2009, there were accrued liabilities for environmental remediation in the balance sheets of $3.6 million and $2.8 million, respectively. The accrued liabilities for environmental remediation do not include any amounts attributable to unasserted claims, nor have any recoveries from insurance been assumed. Charges against income for environmental remediation totaled $4.8 million, $2.1 million and $2.5 million for the years ended December 31, 2007, 2008 and 2009, respectively.

Total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the technology available and needed to meet the various existing legal requirements, the nature and extent of future environmental laws, inflation rates and the determination of the Partnership’s liability at multi-party sites, if any, in light of uncertainties with respect to joint and several liability, and the number, participation levels and financial viability of other parties. As discussed below, the Partnership’s current and future costs have been and will be partially impacted by an indemnification from Sunoco.

The Partnership is a party to certain pending and threatened claims. Although the ultimate outcome of these claims cannot be ascertained at this time, it is reasonably possible that some portion of them could be resolved unfavorably to the Partnership and its predecessor. Management does not believe that any liabilities which may arise from such claims and the environmental matters discussed above would be material in relation to the financial position of the Partnership at December 31, 2009. Furthermore, management does not believe that the overall costs for such matters will have a material impact, over an extended period of time, on the Partnership’s operations, cash flows or liquidity.

Sunoco has indemnified the Partnership for 30 years from environmental and toxic tort liabilities related to the assets contributed to the Partnership that arise from the operation of such assets prior to the closing of the February 2002 IPO. Sunoco has indemnified the Partnership for 100 percent of all losses asserted within the first 21 years of closing of the February 2002 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 February 2002 IPO, Sunoco would be required to indemnify the Partnership for 80 percent of its loss. There is no

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

monetary cap on the amount of indemnity coverage provided by Sunoco. The Partnership has agreed to indemnify Sunoco for events and conditions associated with the operation of the Partnership’s assets that occur on or after the closing of the February 2002 IPO and for environmental and toxic tort liabilities to the extent Sunoco is not required to indemnify the Partnership.

Sunoco also has indemnified the Partnership for liabilities, other than environmental and toxic tort liabilities related to the assets contributed to the Partnership, that arise out of Sunoco’s ownership and operation of the assets prior to the closing of the February 2002 IPO and that are asserted within 10 years after closing of the February 2002 IPO. In addition, Sunoco has indemnified the Partnership from liabilities relating to certain defects in title to the assets contributed to the Partnership and associated with failure to obtain certain consents and permits necessary to conduct its business that arise within 10 years after closing of the February 2002 IPO, as well as from liabilities relating to legal actions currently pending against Sunoco or its affiliates and events and conditions associated with any assets retained by Sunoco or its affiliates.

Management of the Partnership does not believe that any liabilities which may arise from claims indemnified by Sunoco would be material in relation to the financial position of the Partnership at December 31, 2009. There are certain other pending legal proceedings related to matters arising after the February 2002 IPO that are not indemnified by Sunoco. Management believes that any liabilities that may arise from these legal proceedings will not be material in relation to the financial position of the Partnership at December 31, 2009.

Sunoco Partners Marketing & Terminals L.P. (“SPMT”), which is wholly owned by the Partnership, has received a proposed penalty assessment from the Internal Revenue Service (“IRS”) in the aggregate amount of $5.1 million based on a failure to timely file excise tax information returns relating to its terminal operations during the calendar years 2004 and 2005. SPMT became current on its information return filings with the IRS in July of 2006. SPMT believes it had reasonable cause for the failure to not file the information returns on a timely basis, and provided this information to the IRS on October 19, 2007 in a formal filing. SPMT is currently awaiting a response from the IRS. The proposed penalties are for the failure to file information returns rather than any failure to pay taxes due, as no taxes were owed by SPMT in connection with such information. The timing or outcome of this claim, and the total costs to be incurred by SPMT in connection therewith, cannot be reasonably estimated at this time.

11. Management Incentive Plan

Sunoco Partners LLC, the general partner of the Partnership, has adopted the Sunoco Partners LLC Long-Term Incentive Plan (“LTIP”) for employees and directors of the general partner who perform services for the Partnership. The LTIP is administered by the independent directors of the Compensation Committee of the general partner’s board of directors with respect to employee awards, and by the non-independent members of the general partners’ board of directors with respect to awards granted to the independent members. The LTIP currently permits the grant of restricted units and unit options covering an aggregate of 1,250,000 common units.

Restricted Units

A restricted unit entitles the grantee to receive a common unit or, at the discretion of the Compensation Committee, an amount of cash equivalent to the value of a common unit upon the vesting of the unit, which may include the attainment of predetermined performance targets. The Compensation Committee may make additional grants under the LTIP to employees and directors containing such terms as the Compensation Committee shall determine. Common units to be delivered to the grantee upon vesting may be common units acquired by the general partner in the open market, common units already owned by the general partner, common

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

units acquired by the general partner directly from the Partnership or any other person, or any combination of the foregoing. The general partner will be entitled to reimbursement by the Partnership for the cost incurred in acquiring common units. If the Partnership issues new common units upon vesting of the restricted units, the total number of common units outstanding will increase. The Compensation Committee, in its discretion, may grant tandem distribution equivalent rights (“DERs”) with respect to the restricted units. Subject to applicable vesting criteria, DERs entitle the grantee to receive an amount of cash equal to the per unit cash distributions made by the Partnership during the period the restricted unit is outstanding. During the years ended December 31, 2007, 2008 and 2009, the Partnership granted 79,190, 62,048 and 99,801 restricted units, respectively, which included tandem DERs. Although some of these awards are time-vested only, most are subject to the Partnership achieving certain market-based and cash distribution performance targets as compared to a peer group average, which can cause the actual amount of units that ultimately vest to range from between 0% to 200% of the original units granted. These restricted unit awards generally vest over a three-year period.

The following table summarizes information regarding restricted unit award activity during the year ended December 31, 2009:

Restricted Unit Award Activity


	Number of Units ⁽¹⁾		Weighted Average Grant- Date Fair Value
Non-vested and outstanding, beginning of year	134,136		$	55.00
Granted	99,801		$	59.76
Performance Factor Adjustment	49,762		$	56.05
Vested	(107,575	)	$	56.26
Cancelled/forfeited	(20,129	)	$	55.83

Non-vested and outstanding, end of year	155,995		$	57.40

⁽¹⁾	The number of restricted units issued related to performance shares may range from 0 to 200 percent of the number of units shown in the table above based on our achievement of performance goals for total shareholder return and cash distributions relative to a selected peer group of competitors.

The total intrinsic value of restricted unit awards vested during the years ended December 31, 2007, 2008 and 2009 was $4.3 million, $4.9 million, and $7.2 million, respectively. Non-vested and outstanding restricted unit awards at December 31, 2009 had a contractual life of two to three years.

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

The Partnership is recognizing compensation expense on a straight-line basis over the requisite service period as well as estimating forfeitures over the requisite service period when recognizing compensation expense.

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

Fair Value Assumptions


Year Ended December 31,	2007		2008		2009
Expected unit-price volatility		17.2%		18.7%		29.1%
Dividend Yield		6.1%		7.1%		7.4%
Risk-free interest rate		4.9%		2.3%		1.3%
Weighted average fair value of performance units granted during the year	$	56.27	$	52.96	$	59.76

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

As of December 31, 2009 estimated compensation cost related to non-vested awards not yet recognized was $2.6 million, and the weighted-average period over which this cost is expected to be recognized in expense is 1.2 years. The number of restricted stock units outstanding and the total compensation cost related to non-vested awards not yet recognized reflects the Partnership’s estimates of performance factors for certain restricted unit awards.

The Partnership recognized unit-based compensation expense related to the LTIP of $5.3 million, $4.3 million, and $5.3 million in the years ended December 31, 2007, 2008 and 2009 respectively, related to the unit grants and performance factor adjustments noted in the table above. Each of the restricted unit grants also have tandem DERs which are recognized as a reduction of Partners’ Capital when earned.

Unit Options

A unit option entitles the grantee to purchase a common unit at a price determined at the date of grant by the Compensation Committee. There have been no grants of unit options for the years ended December 31, 2007, 2008 and 2009, and there are no unit options outstanding as of December 31, 2009. However, the Compensation Committee may, in the future, make grants under the LTIP to employees and directors containing such terms as the Compensation Committee shall determine, provided that unit options have an exercise price no less than the fair market value of the units on the date of grant.

12. Cash Distributions

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

If cash distributions exceed $0.50 per unit in a quarter, the general partner receives increasing percentages, up to 50 percent, of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions”. The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

On January 26, 2010, we repurchased, and our general partner transferred and assigned to us for cancellation, the incentive distribution rights 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 incentive distribution rights 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 $201.2 million. On February 12, 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. The new incentive distribution rights provide for target distribution levels and distribution “splits” between the general partner and the holders of our common units equal to those applicable to the cancelled incentive distribution rights, except that (i) the general partner’s distribution split for distributions above the current second target distribution of $0.575 per common unit per quarter (or $2.30 per common unit on an annualized basis) and up to the third target distribution will increase to 37% from 25% (these percentages include the general partners 2.0% interest); and (ii) the third target distribution will be increased from $0.70 to $1.5825 per common unit per quarter (or from $2.80 to $6.33 per common unit on an annualized basis).

Cancelled IDRs

New IDRs

Total Quarterly
Distribution Target
Amount

Marginal Percentage
Interest in Distributions

Total
Quarterly
Distribution
Target
Amount

Marginal Percentage Interest
in Distributions

General
Partner

Unitholders

General
Partner

Unitholders

Minimum Quarterly Distribution

$0.450

98%

First Target Distribution

up to $0.500

98%

No change

Second Target Distribution

above $0.500

up to $0.575

15%

85%

Third Target Distribution

above $0.575

up to $0.700

25%

75%

above $0.575

up to $1.5825

37%*

63%

Thereafter

above $0.700

50%

above $1.5825

50%*

50%

*	Includes 2 percent general partner interest.

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

Distributions paid by the Partnership during the years ended December 31, 2007, 2008 and 2009 were as follows:


Date Cash Distribution Paid	Cash Distribution per Limited Partner Unit		Annualized Cash Distribution per Limited Partner Unit		Total Cash Distribution to the Limited Partners		Total Cash Distribution to the General Partner
					($ in millions)		($ in millions)
February 14, 2007	$	0.8125	$	3.25	$	23.2	$	5.1
May 15, 2007	$	0.8250	$	3.30	$	23.6	$	5.4
August 14, 2007	$	0.8375	$	3.35	$	23.9	$	5.8
November 14, 2007	$	0.8500	$	3.40	$	24.3	$	6.1

February 14, 2008	$	0.8700	$	3.48	$	24.9	$	6.7
May 15, 2008	$	0.8950	$	3.58	$	25.6	$	7.5
August 14, 2008	$	0.9350	$	3.74	$	26.8	$	8.6
November 14, 2008	$	0.9650	$	3.86	$	27.6	$	9.5

February 14, 2009	$	0.9900	$	3.96	$	28.4	$	10.2
May 15, 2009	$	1.0150	$	4.06	$	31.4	$	11.8
August 14, 2009	$	1.0400	$	4.16	$	32.2	$	12.6
November 14, 2009	$	1.0650	$	4.26	$	33.0	$	13.3

On January 26, 2010, the Partnership declared a cash distribution of $1.09 per unit ($4.36 per unit annualized) on its outstanding common units, representing the distribution for the quarter ended December 31, 2009. The $47.9 million distribution, including $14.1 million to the general partner, was paid on February 12, 2010 to unitholders of record at the close of business on February 8, 2010.

13. Financial Instruments and Concentration of Credit Risk

The estimated fair value of financial instruments has been determined based on the Partnership’s assessment of available market information and appropriate valuation methodologies. The Partnership’s current assets (other than inventories) and current liabilities are financial instruments. The estimated fair value of these financial instruments approximates their carrying amounts due to their short-term nature. The estimated fair value of the outstanding borrowings under the $400 million Credit Facility at December 31, 2009 approximate their carrying amounts as these borrowings bear interest based upon short-term floating market interest rates. The aggregate estimated fair value of the 2012, 2014 and 2016 Senior Notes at December 31, 2009 was $664.4 million, compared to the carrying amount of $600.0 million at December 31, 2009. The 2012, 2014 and 2016 Senior Notes are publicly traded and were valued based upon their quoted market prices.

Approximately 13.1 percent of total revenues recognized by the Partnership during 2009 was derived from Sunoco. The Partnership sells crude oil to Sunoco, transports crude oil and refined products to/from Sunoco’s refineries and provides terminalling and storage services for Sunoco. Sunoco has been issued an investment grade credit rating by three recognized agencies and, accordingly, management of the Partnership does not believe that the transactions with Sunoco expose it to significant credit risk.

The Partnership’s other trade relationships are primarily with major integrated oil companies, independent oil companies and other pipelines and wholesalers. These concentrations of customers may affect the Partnership’s overall credit risk in that the customers (including Sunoco) may be similarly affected by changes in

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

economic, regulatory or other factors. The Partnership’s customers’ credit positions are analyzed prior to extending credit and periodically after the credit has been extended. The Partnership manages its exposure to credit risk through credit analysis, credit approvals, credit limits, monitoring procedures and the utilization of netting agreements. For certain transactions the Partnership may utilize letters of credit, prepayments and guarantees.

14. Business Segment Information

On January 1, 2009 the Partnership re-aligned its reporting segments. Prior to this date, the reporting segments were designated by geographic region. The Partnership has determined it more meaningful to functionally align its reporting segments. As such, the updated reporting segments as of January 1, 2009 are Refined Products Pipeline System, Terminal Facilities, and Crude Oil Pipeline System. The primary difference in the new reporting is the consolidation of a formerly eastern area crude oil pipeline with the formerly western area crude oil pipelines. For comparative purposes all prior period amounts have been recast to reflect the new segment reporting and do not impact consolidated net income.

The Partnership operates in three principal business segments: Refined Products Pipeline System, Terminal Facilities and Crude Oil Pipeline System.

•

The Refined Products Pipeline System serves the United States operations of Sunoco and selected other third parties and consists of: approximately 2,200 miles of refined products pipelines, including a two-thirds undivided interest in the 80-mile refined products Harbor pipeline, and 60 miles of interrefinery pipelines between two of Sunoco’s refineries; a 9.4 percent interest in Explorer Pipeline Company, a joint venture that owns a 1,880-mile refined products pipeline; a 31.5 percent interest in Wolverine Pipe Line Company, a joint venture that owns a 720-mile refined products pipeline; a 12.3 percent interest in West Shore Pipe Line Company, a joint venture that owns a 650-mile refined products pipeline; and a 14.0 percent interest in Yellowstone Pipe Line Company, a joint venture that owns a 690-mile refined products pipeline.

•

The Terminal Facilities consist of 41 active refined products terminals with an aggregate storage capacity of 7.0 million shell barrels, primarily serving our Refined Products Pipeline System; the Nederland Terminal, a 19.6 million barrel marine crude oil terminal on the Texas Gulf Coast; a 2.0 million barrel refined products terminal serving Sunoco’s Marcus Hook refinery near Philadelphia, Pennsylvania; one inland and two marine crude oil terminals with a combined capacity of 3.4 million barrels, and related pipelines, which serve Sunoco’s Philadelphia refinery and; a 1.0 million barrel liquefied petroleum gas (“LPG”) terminal near Detroit, Michigan.

•

The Crude Oil Pipeline System gathers, purchases, sells, and transports crude oil principally in Oklahoma, Texas and Michigan and consists of approximately 3,350 miles of crude oil trunk pipelines, including a 37.0 percent undivided interest in the 80-mile Mesa Pipe Line system, and approximately 500 miles of crude oil gathering lines that supply the trunk pipelines; approximately 110 crude oil transport trucks; approximately 120 crude oil truck unloading facilities; a 55.3 percent economic interest (50 percent voting interest) in the Mid-Valley Pipeline Company, a joint venture that owns a 990-mile crude pipeline and a 43.8 percent interest in West Texas Gulf Pipe Line Company, a joint venture that owns a 580-mile crude oil pipeline.

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

The following tables sets forth condensed statement of income information concerning the Partnership’s recast business segments and reconciles total segment operating income to net income for the years ended December 31, 2007, 2008 and 2009, respectively (in thousands of dollars).


	Year Ended December 31, 2007
	Refined Products Pipeline System			Terminal Facilities		Crude Oil Pipeline System			Total
Sales and other operating revenue:
Affiliates	$	71,836		$	92,156	$	1,518,050		$	1,682,042

Unaffiliated customers	$	26,387		$	49,466	$	5,619,560		$	5,695,413

Operating income	$	32,150	⁽¹⁾	$	52,668	$	71,337	⁽²⁾	$	156,155

Net interest expense										(35,280	)

Net income									$	120,875

Depreciation and amortization	$	8,336		$	15,338	$	13,667		$	37,341

Capital expenditures	$	9,652	⁽³⁾	$	64,381	$	27,967		$	105,862	⁽⁴⁾

Investment in affiliates	$	59,776		$	—	$	25,209		$	84,985

Identifiable assets	$	337,670		$	400,509	$	1,742,701		$	2,504,642	⁽⁵⁾

⁽¹⁾	Includes equity income of $13,051 attributable to the Partnership’s equity ownership interests in Explorer, Wolverine, West Shore and Yellowstone.

⁽²⁾	Includes equity income of $14,062 attributable to the Partnership’s equity ownership interest in West Texas Gulf and Mid-Valley.

⁽³⁾	Excludes $13,416 for the acquisition of the Syracuse refined products terminal.

⁽⁴⁾	Capital expenditures include the Partnership’s $3,862 of capital expenditures attributable to corporate activities.

⁽⁵⁾	Identifiable assets include the Partnership’s unallocated $2,000 cash and cash equivalents, $8,060 advances to affiliates, $6,038 deferred financing costs, $7,661 to properties, plants and equipment, net and $3 attributable to corporate activities.

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)


	Year Ended December 31, 2008
	Refined Products Pipeline System			Terminal Facilities		Crude Oil Pipeline System			Total
Sales and other operating revenue:
Affiliates	$	76,964		$	99,976	$	2,395,007		$	2,571,947

Unaffiliated customers	$	26,493		$	62,448	$	7,451,432		$	7,540,373

Operating income	$	34,432	⁽¹⁾	$	58,475	$	152,685	⁽²⁾	$	245,592

Net interest expense										(31,112	)

Net income									$	214,480

Depreciation and amortization	$	9,351		$	16,446	$	14,257		$	40,054
Impairment charge		—			5,674		—			5,674

Capital expenditures	$	12,435	⁽³⁾	$	74,115	$	53,362		$	145,834	⁽⁴⁾

Investment in affiliates	$	56,918		$	—	$	25,964		$	82,882

Identifiable assets	$	497,464		$	484,349	$	1,302,582		$	2,308,249	⁽⁵⁾

⁽¹⁾	Includes equity income of $8,463 attributable to the Partnership’s equity ownership interests in Explorer, Wolverine, West Shore and Yellowstone.

⁽²⁾	Includes equity income of $13,953 attributable to the Partnership’s equity ownership interest in West Texas Gulf and Mid-Valley.

⁽³⁾	Excludes $185,410 for the acquisition of the MagTex refined product pipeline system.

⁽⁴⁾	Capital expenditures include the Partnership’s $5,922 of capital expenditures attributable to corporate activities.

⁽⁵⁾	Identifiable assets include the Partnership’s unallocated $2,000 cash and cash equivalents, $2,549 advances to affiliates, $3,767 deferred financing costs, $15,536 to properties, plants and equipment, net and $2 attributable to corporate activities.


	Year Ended December 31, 2009
	Refined Products Pipeline System			Terminal Facilities			Crude Oil Pipeline System			Total
Sales and other operating revenue:
Affiliates	$	78,379		$	100,207		$	526,925		$	705,511

Unaffiliated customers	$	49,350		$	91,077		$	4,555,866		$	4,696,293

Operating income	$	44,688	⁽¹⁾	$	83,664		$	166,692	⁽²⁾	$	295,044

Net interest expense											(44,682	)

Net income										$	250,362

Depreciation and amortization	$	13,711		$	18,937		$	15,372		$	48,020

Capital expenditures	$	12,091	⁽³⁾	$	109,875	⁽³⁾	$	40,800		$	175,596	⁽⁴⁾

Investment in affiliates	$	61,388		$	—		$	26,899		$	88,287

Identifiable assets	$	476,484		$	597,502		$	1,988,065		$	3,098,606	⁽⁵⁾

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

⁽¹⁾	Includes equity income of $12,441 attributable to the Partnership’s equity ownership interests in Explorer, Wolverine, West Shore and Yellowstone.

⁽²⁾	Includes equity income of $13,247 attributable to the Partnership’s equity ownership interest in West Texas Gulf and Mid-Valley.

⁽³⁾	Excludes $50,232 for the acquisitions of the Romulus refined products terminal and the Excel crude oil pipeline .

⁽⁴⁾	Capital expenditures include the Partnership’s $12,830 of capital expenditures attributable to corporate activities.

⁽⁵⁾	Identifiable assets include the Partnership’s unallocated $2,000 cash and cash equivalents, $8,691 advances to affiliates, $4,353 deferred financing costs, $21,507 to properties, plants and equipment, net and $4 attributable to corporate activities.

15. Quarterly Financial Data (Unaudited)

Summarized quarterly financial data is as follows (in thousands of dollars, except per unit amounts):


	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2008
Sales and other operating revenue:
Affiliates	$	636,386	$	756,718	$	760,551	$	418,292
Unaffiliated customers	$	1,758,003	$	2,558,703	$	2,068,956	$	1,154,711
Gross margin⁽¹⁾	$	55,806	$	64,730	$	66,888	$	93,154
Operating income	$	45,201	$	59,387	$	57,863	$	83,141
Net income	$	37,503	$	51,323	$	50,334	$	75,320
Net income per Limited Partner unit—basic^{(2) (3)}	$	1.05	$	1.48	$	1.42	$	2.25
Net income per Limited Partner unit—diluted^{(2) (3)}	$	1.04	$	1.47	$	1.41	$	2.23



	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2009
Sales and other operating revenue:
Affiliates	$	198,844	$	217,560	$	114,905	$	174,202
Unaffiliated customers	$	839,189	$	1,065,137	$	1,305,159	$	1,486,808
Gross margin⁽¹⁾	$	102,759	$	86,395	$	65,822	$	75,501
Operating income	$	90,450	$	78,327	$	59,881	$	66,386
Net income	$	80,906	$	66,643	$	48,460	$	54,353
Net income per Limited Partner unit—basic⁽²⁾	$	2.38	$	1.76	$	1.13	$	1.31
Net income per Limited Partner unit—diluted⁽²⁾	$	2.36	$	1.74	$	1.13	$	1.30

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

⁽²⁾	Net income included within this calculation excludes amounts attributable to the general partner’s interest in net income.

⁽³⁾	Retrospective adjustment for our change in accounting for earnings per unit as described in Note 1.

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

16. Supplemental Condensed Consolidating Financial Information

The Partnership serves as guarantor of the Senior Notes and of any obligations under the $400 million and $62.5 million Credit Facilities. These guarantees are full and unconditional. For purposes of the following footnote, Sunoco Logistics Partners L.P. is referred to as “Parent” and Sunoco Logistics Partners Operations L.P. is referred to as “Subsidiary Issuer.” Sunoco Partners Marketing and Terminals L.P., Sunoco Pipeline L.P., Sun Pipeline Company of Delaware LLC, Sunoco Pipeline Acquisition LLC, Sunoco Logistics Partners GP LLC, Sunoco Logistics Partners Operations GP LLC and Sunoco Partners Lease Acquisition & Marketing LLC, are collectively referred to as “Non-Guarantor Subsidiaries.”

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

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

Balance Sheet

December 31, 2008


	Parent			Subsidiary Issuer		Non- Guarantor Subsidiaries			Consolidating Adjustments			Total
Assets
Current Assets
Cash and cash equivalents	$	—		$	2,000	$	—		$	—		$	2,000
Advances to affiliates		(161	)		48,000		(45,290	)		—			2,549
Accounts receivable, affiliated companies		—			—		77,692			—			77,692
Accounts receivable, net		—			—		652,840			—			652,840
Inventories
Crude oil		—			—		87,645			—			87,645
Refined product		—			—		1,670			—			1,670
Materials, supplies and other		—			—		841			—			841

Total Current Assets		(161	)		50,000		775,398			—			825,237

Properties, plants and equipment, net		—			—		1,375,429			—			1,375,429
Investment in affiliates		670,672			1,415,691		83,012			(2,086,493	)		82,882
Deferred charges and other assets		—			2,566		22,135			—			24,701

Total Assets	$	670,511		$	1,468,257	$	2,255,974		$	(2,086,493	)	$	2,308,249

Liabilities and Partners’ Capital
Current Liabilities
Accounts payable	$	—		$	—	$	792,674		$	—		$	792,674
Accrued liabilities		980			2,034		42,634			—			45,648
Accrued taxes		—			—		20,738			—			20,738

Total Current Liabilities		980			2,034		856,046			—			859,060

Long-term debt		—			747,631		—			—			747,631
Other deferred credits and liabilities		—			—		31,658			—			31,658

Total Liabilities		980			749,665		887,704			—			1,638,349

Total Partners’ Capital		669,531			718,592		1,368,270			(2,086,493	)		669,900

Total Liabilities and Partners’ Capital	$	670,511		$	1,468,257	$	2,255,974		$	(2,086,493	)	$	2,308,249

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

Balance Sheet

December 31, 2009


	Parent		Subsidiary Issuer		Non- Guarantor Subsidiaries			Consolidating Adjustments			Total
Assets
Current Assets
Cash and cash equivalents	$	—	$	2,000	$	—		$	—		$	2,000
Advances to affiliates		8,306		48,000		(47,615	)		—			8,691
Accounts receivable, affiliated companies		—		—		47,791			—			47,791
Accounts receivable, net		—		—		1,280,062			—			1,280,062
Inventories
Crude oil		—		—		82,511			—			82,511
Refined product		—		—		3,622			—			3,622
Materials, supplies and other		—		—		841			—			841

Total Current Assets		8,306		50,000		1,367,212			—			1,425,518

Properties, plants and equipment, net		—		—		1,533,721			—			1,533,721
Investment in affiliates		603,959		1,428,508		88,432			(2,032,613	)		88,286
Deferred charges and other assets		—		4,096		46,985			—			51,081

Total Assets	$	612,265	$	1,482,604	$	3,036,350		$	(2,032,613	)	$	3,098,606

Liabilities and Partners’ Capital
Current Liabilities
Accounts payable	$	—	$	1	$	1,253,741		$	—		$	1,253,742
Accrued liabilities		980		3,339		44,979			—			49,298
Accrued taxes		—		—		30,296			—			30,296

Total Current Liabilities		980		3,340		1,329,016			—			1,333,336

Long-term debt		—		868,424		—			—			868,424
Other deferred credits and liabilities		—		—		35,232			—			35,232

Total Liabilities		980		871,764		1,364,248			—			2,236,992

Total Partners’ Capital		611,285		610,840		1,672,102			(2,032,613	)		861,614

Total Liabilities and Partners’ Capital	$	612,265	$	1,482,604	$	3,036,350		$	(2,032,613	)	$	3,098,606

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

Statement of Income

Year Ended December 31, 2007


	Parent		Subsidiary Issuer			Non- Guarantor Subsidiaries		Consolidating Adjustments			Total
Revenues
Sales and other operating revenue:
Affiliates	$	—	$	—		$	1,682,042	$	—		$	1,682,042
Unaffiliated customers		—		—			5,695,413		—			5,695,413
Equity in earnings of subsidiaries		120,866		152,846			15		(273,727	)		—
Other income		—		—			28,381		—			28,381

Total Revenues		120,866		152,846			7,405,851		(273,727	)		7,405,836

Costs and Expenses
Cost of products sold and operating expenses		—		—			7,156,142		—			7,156,142
Depreciation and amortization		—		—			37,341		—			37,341
Selling, general and administrative expenses		—		—			56,198		—			56,198

Total Costs and Expenses		—		—			7,249,681		—			7,249,681

Operating Income		120,866		152,846			156,170		(273,727	)		156,155
Net interest cost (received from) / paid to affiliates		—		(1,013	)		3,300		—			2,287
Other interest cost and debt expenses, net		—		36,412			—		—			36,412
Capitalized interest		—		(3,419	)		—		—			(3,419	)

Net Income	$	120,866	$	120,866		$	152,870	$	(273,727	)	$	120,875

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

Statement of Income

Year Ended December 31, 2008


	Parent		Subsidiary Issuer			Non- Guarantor Subsidiaries		Consolidating Adjustments			Total
Revenues
Sales and other operating revenue:
Affiliates	$	—	$	—		$	2,571,947	$	—		$	2,571,947
Unaffiliated customers		—		—			7,540,373		—			7,540,373
Equity in earnings of subsidiaries		214,474		242,277			24		(456,775	)		—
Other income		—		—			24,298		—			24,298

Total Revenues		214,474		242,277			10,136,642		(456,775	)		10,136,618

Costs and Expenses
Cost of products sold and operating expenses		—		—			9,786,014		—			9,786,014
Depreciation and amortization		—		—			40,054		—			40,054
Selling, general and administrative expenses		—		—			59,284		—			59,284
Impairment Charge		—		—			5,674		—			5,674

Total Costs and Expenses		—		—			9,891,026		—			9,891,026

Operating Income		214,474		242,277			245,616		(456,775	)		245,592
Net interest cost (received from) / paid to affiliates		—		(2,751	)		3,309		—			558
Other interest cost and debt expenses, net		—		34,409			—		—			34,409
Capitalized interest		—		(3,855	)		—		—			(3,855	)

Net Income	$	214,474	$	214,474		$	242,307	$	(456,775	)	$	214,480

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

Statement of Income

Year Ended December 31, 2009


	Parent		Subsidiary Issuer			Non- Guarantor Subsidiaries		Consolidating Adjustments			Total
Revenues
Sales and other operating revenue:
Affiliates	$	—	$	—		$	705,511	$	—		$	705,511
Unaffiliated customers		—		—			4,696,293		—			4,696,293
Equity in earnings of subsidiaries		250,340		291,722			29		(542,091	)		—
Other income		—		—			27,873		—			27,873

Total Revenues		250,340		291,722			5,429,706		(542,091	)		5,429,677

Costs and Expenses
Cost of products sold and operating expenses		—		—			5,023,307		—			5,023,307
Depreciation and amortization		—		—			48,020		—			48,020
Selling, general and administrative expenses		—		—			63,306		—			63,306

Total Costs and Expenses		—		—			5,134,633		—			5,134,633

Operating Income		250,340		291,722			295,073		(542,091	)		295,044
Net interest cost (received from) / paid to affiliates		—		(3,169	)		3,300		—			131
Other interest cost and debt expenses, net		—		48,876			—		—			48,876
Capitalized interest		—		(4,325	)		—		—			(4,325	)

Net Income	$	250,340	$	250,340		$	291,773	$	(542,091	)	$	250,362

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

Statement of Cash Flows

Year Ended December 31, 2007


	Parent			Subsidiary Issuer			Non- Guarantor Subsidiaries			Consolidating Adjustments			Total
Net Cash Flows from Operating Activities	$	120,737		$	117,812		$	242,677		$	(273,727	)	$	207,499

Cash Flows from Investing Activities:
Capital expenditures		—			—			(105,862	)		—			(105,862	)
Acquisitions		—			—			(13,489	)		—			(13,489	)
Intercompany		(2,545	)		(150,224	)		(120,958	)		273,727			—

		(2,545	)		(150,224	)		(240,309	)		273,727			(119,351	)

Cash Flows from Financing Activities:
Distribution paid to Limited Partners and General Partner		(117,451	)		—			—			—			(117,451	)
Contribution from General Partner for Limited Partner unit transactions		58			—			—			—			58
Repayments from (advances to) affiliates, net		(799	)		2,000			(1,830	)		—			(629	)
Borrowings under credit facility		—			279,900									279,900
Repayments under credit facility		—			(256,900	)								(256,900	)
Payments of statutory withholding on net issuance of Limited Partner units under restricted unit incentive plan		—			—			(1,479	)		—			(1,479	)
Contributions from affiliate		—			—			941			—			941

		(118,192	)		25,000			(2,368	)		—			(95,560	)

Net change in cash and cash equivalents		—			(7,412	)		—			—			(7,412	)
Cash and cash equivalents at beginning of year		—			9,412			—			—			9,412

Cash and cash equivalents at end of year	$	—		$	2,000		$	—		$	—		$	2,000

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

Statement of Cash Flows

Year Ended December 31, 2008


	Parent			Subsidiary Issuer			Non- Guarantor Subsidiaries			Consolidating Adjustments			Total
Net Cash Flows from Operating Activities	$	214,474		$	213,357		$	257,531		$	(456,775	)	$	228,587

Cash Flows from Investing Activities:
Capital expenditures		—			—			(145,834	)		—			(145,834	)
Acquisitions		—			—			(185,410	)		—			(185,410	)
Intercompany		(81,856	)		(443,742	)		68,823			456,775			—

		(81,856	)		(443,742	)		(262,421	)		456,775			(331,244	)

Cash Flows from Financing Activities:
Distribution paid to Limited Partners and General Partner		(137,203	)		—			—			—			(137,203	)
Contribution from General Partner for Limited Partner unit transactions		76			—			—			—			76
Repayments from (advances to) affiliates, net		4,509			(2,000	)		3,002			—			5,511
Borrowings under credit facility		—			343,385			—			—			343,385
Repayments under credit facility		—			(111,000	)		—						(111,000	)
Payments of statutory withholding on net issuance of Limited Partner units under restricted unit incentive plan		—			—			(538	)		—			(538	)
Contributions from affiliate		—			—			2,426			—			2,426

		(132,618	)		230,385			4,890			—			102,657

Net change in cash and cash equivalents		—			—			—			—			—
Cash and cash equivalents at beginning of year		—			2,000			—			—			2,000

Cash and cash equivalents at end of year	$	—		$	2,000		$	—		$	—		$	2,000

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

Statement of Cash Flows

Year Ended December 31, 2009


	Parent			Subsidiary Issuer			Non- Guarantor Subsidiaries			Consolidating Adjustments			Total
Net Cash Flows from Operating Activities	$	250,340		$	250,116		$	217,817		$	(542,091	)	$	176,182

Cash Flows from Investing Activities:
Capital expenditures		—			—			(175,596	)		—			(175,596	)
Acquisitions		—			—			(50,232	)		—			(50,232	)
Intercompany		(180,933	)		(368,993	)		7,835			542,091			—

		(180,933	)		(368,993	)		(217,993	)		542,091			(225,828	)

Cash Flows from Financing Activities:
Distribution paid to Limited Partners and General Partner		(172,856	)		—			—			—			(172,856	)
Net proceeds from issuance of Limited Partner units		109,514			—			—			—			109,514
Contribution from General Partner for Limited Partner unit transactions		2,402			—			—			—			2,402
Net proceeds from issuance of Senior Notes		—			173,289			—			—			173,289
Repayments from (advances to) affiliates, net		(8,467	)		—			2,325			—			(6,142	)
Borrowings under credit facility		—			632,973			—			—			632,973
Repayments under credit facility		—			(687,385	)		—						(687,385	)
Payments of statutory withholding on net issuance of Limited Partner units under restricted unit incentive plan		—			—			(2,149	)		—			(2,149	)

		(69,407	)		118,877			176			—			49,646

Net change in cash and cash equivalents		—			—			—			—			—
Cash and cash equivalents at beginning of year		—			2,000			—			—			2,000

Cash and cash equivalents at end of year	$	—		$	2,000		$	—		$	—		$	2,000

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None

ITEM 9A.

CONTROLS AND PROCEDURES

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

As of December 31, 2009, the Partnership carried out an evaluation, under the supervision and with the participation of the management of the general partner (including the President and Chief Executive Officer and the Vice President and Chief Financial Officer), of the effectiveness of the design and operation of the Partnership’s disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, the general partner’s President and Chief Executive Officer, and its Vice President and Chief Financial Officer, concluded that the Partnership’s disclosure controls and procedures are effective.

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

No change in the Partnership’s internal control over financial reporting has occurred during the fiscal quarter ended December 31, 2009 that has materially affected, or that is reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

ITEM 9B.

OTHER INFORMATION

None.

PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Sunoco Partners LLC, our general partner, is a wholly-owned, indirect subsidiary of Sunoco, Inc. Our general partner manages our operations and activities. Our general partner’s Board of Directors held seven meetings during 2009. The Board has established standing committees to consider designated matters. The standing committees of the Board are the Audit/Conflicts Committee and the Compensation Committee. The listing standards of the New York Stock Exchange, or NYSE, do not require boards of directors of publicly-traded master limited partnerships to be composed of a majority of independent directors nor are they required to have a standing nominating or compensation committee. However, our general partner’s Board of Directors has elected to have a standing compensation committee. The Board has adopted governance guidelines for the Board and charters for the standing committees.

The Audit/Conflicts Committee, in its role as an Audit Committee, oversees external financial reporting, engages independent auditors, and reviews procedures for internal auditing and the adequacy of internal accounting controls. In addition, the Audit/Conflicts Committee, in its role as a “Conflicts” Committee, reviews specific matters that the Board believes may involve conflicts of interest between us and Sunoco, Inc. and determines if the resolution of the conflict of interest is fair and reasonable to the Partnership. The Audit/Conflicts Committee met as an Audit Committee eight times during 2009, and met as a Conflicts Committee 16 times during 2009. The current members of the Audit/Conflicts Committee are: L. Wilson Berry, Jr. (chairman), Stephen L. Cropper, and Philip L. Frederickson. The members of the Audit/Conflicts Committee consist of those directors of our general partner who are not also executive officers of our general partner or its parent, all of whom must meet certain independence and experience standards established by the NYSE to serve on an audit committee of a Board of Directors. To be considered an independent director under the NYSE listing standards, the Board of Directors must affirmatively determine that a director has no material relationship with us or our general partner. In making this determination, the Board of Directors adheres to all of the specific tests for independence included in the NYSE listing standards and our corporate governance guidelines, and considers all of the facts and circumstances it deems necessary or advisable to make such a determination. Our general partner’s Board of Directors has determined affirmatively that Messrs. Berry, Cropper and Frederickson each qualify as “independent” under our governance guidelines and the NYSE rules. Our general partner’s Board of Directors has also determined that, based upon relevant experience, each member of the Audit/Conflicts Committee (Messrs. Berry, Cropper, and Frederickson) is an “audit committee financial expert,” as defined in Item 407 of Regulation S-K of the Securities Exchange Act of 1934, as amended. A description of each member’s qualifications may be found elsewhere in this Item 10. In conjunction with regular meetings, the Audit/Conflicts Committee meets in executive session without members of management present. Mr. Berry leads these executive session meetings, the purpose of which is to promote open and candid discussion among the non-management and independent members of the general partner’s Board of Directors.

The Compensation Committee of the general partner’s Board of Directors oversees compensation decisions for the officers of the general partner and the administration of the compensation plans described below. The Compensation Committee held four meetings during 2009. The current members of the Compensation Committee are: L. Wilson Berry, Jr., Stephen L. Cropper (chairman), Lynn L. Elsenhans, and Philip L. Frederickson. Since Ms. Elsenhans is also is an officer and director of Sunoco, Inc., she recuses herself from Compensation Committee decisions relating to equity compensation awards.

In order that interested parties may be able to make their concerns known to the non-management directors, our unitholders and other interested parties may communicate directly with the general partner’s Board of Directors, with the non-management directors as a group, or with any director or committee chairperson by writing to such parties in care of Bruce D. Davis, Jr., Vice President, General Counsel and Secretary, Sunoco Partners LLC, 1818 Market Street, Suite 1500, Philadelphia, PA 19103-3615. Communications addressed to the Board generally will be forwarded either to the appropriate committee chairperson or to all directors.

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Communications may be submitted confidentially and anonymously. Under certain circumstances, we or the general partner may be required by law to disclose the information or identity of the person submitting the communication. There were no material actions taken by the Board of Directors as a result of communications received during 2009 from unitholders or others. Certain concerns communicated to the general partner’s Board of Directors also may be referred to the general partner’s internal auditor or its General Counsel, in accordance with the general partner’s regular procedures for addressing such concerns. The chairman of the general partner’s Board of Directors or the chairman of the general partner’s Audit/Conflicts Committee may direct that certain concerns be presented to the Audit/Conflicts Committee, or to the full Board, or that they otherwise receive special treatment, including retention of external counsel or other advisors.

The executive officers of our general partner spend all of their time managing our business and affairs.

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

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

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

Our common unit holders do not nominate candidates for, or vote for the election of, the directors of the general partner. The general partner is a limited liability company, and its directors are elected by its members, all of which are corporate affiliates of Sunoco, Inc. The executive officers of the general partner are appointed by its directors. The following table shows information for the current directors and executive officers of Sunoco Partners LLC, our general partner. Executive officers and directors are elected for one-year terms.


Name	Age	Position with the General Partner
Lynn L. Elsenhans	53	Chairman and Director
Deborah M. Fretz	61	President, Chief Executive Officer and Director
Cynthia A. Archer	56	Director
L. Wilson Berry, Jr.	66	Director
Stephen L. Cropper	59	Director
Bruce G. Fischer	54	Director
Philip L. Frederickson	53	Director
Brian P. MacDonald	44	Director
Bruce D. Davis, Jr.	53	Vice President, General Counsel and Secretary
David A. Justin	57	Vice President, Operations
Michael J. Hennigan	50	Vice President, Business Development
Neal E. Murphy	52	Vice President and Chief Financial Officer

Ms. Elsenhans was elected to the Board of Directors in August 2008 and was elected Chairman of the Board in October 2008. Ms. Elsenhans has been President and Chief Executive Officer of Sunoco, Inc. since August 2008 and Chairman of Sunoco, Inc. since January 1, 2009. Prior to that, she was Executive Vice President of Global Manufacturing for Shell Downstream, Inc. from 2005 to 2008. Ms. Elsenhans is a director of International Paper Company.

Ms. Fretz was elected President, Chief Executive Officer and director in October 2001. Ms. Fretz is a director of GATX Corporation.

Ms. Archer was elected to the Board of Directors in April 2002. Ms. Archer has been Vice President, Marketing and Development, Sunoco, Inc. since January 2001.

Mr. Berry was elected to the Board of Directors in March 2003. He is currently a consultant in the energy field. From 1998 until his retirement in 2000, Mr. Berry was Chief Executive Officer and President of Motiva Enterprises LLC, a refining and marketing joint venture in the Eastern United States, established by Shell Norco Refining Company, Texaco Refining and Marketing (East) Inc., and Saudi Refining Inc.

Mr. Cropper was elected to the Board of Directors in May 2002. Mr. Cropper is currently a private investor. From January 1996 until the time of his retirement in December 1998, he served as President and Chief Executive Officer of Williams Energy Services, a diversified energy company. He is a director of Berry Petroleum, NRG Energy, Inc. and Rental Car Finance Corporation, a subsidiary of Dollar Thrifty Automotive Group, Inc.

Mr. Fischer was elected to the Board of Directors in April 2002. He has been Senior Vice President, Strategy and Portfolio for Sunoco, Inc. since October 2008. From January 2002 to October 2008, Mr. Fischer served as Senior Vice President, Sunoco Chemicals.

Mr. Frederickson was elected to the Board of Directors in January 2008. Mr. Frederickson was formerly Executive Vice President, Planning, Strategy & Corporate Affairs, for Conoco Phillips from 2006 until his retirement in January 2008. Prior to that, he was Executive Vice President, Commercial from 2002 to 2006. Mr. Frederickson is a director of Rosetta Resources, Inc.

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Mr. MacDonald was elected to the Board of Directors in September 2009. He has been Senior Vice President and Chief Financial Officer of Sunoco, Inc. since August 2009. He was Chief Financial Officer of the Commercial Business Unit at Dell, Inc. from December 2008 until July 2009, and Corporate Vice President and Treasurer at Dell, Inc. from December 2002 until January 2009.

Mr. Davis was elected Vice President, General Counsel and Secretary in January 2004.

Mr. Hennigan was elected Vice President, Business Development in May 2009. Prior to that he was Senior Vice President, Business Improvement from October 2008 to May 2009, Senior Vice President, Supply, Trading, Sales and Transportation from February 2006 to October 2008, and Vice President, Product Trading, Sales and Supply March 2001 to February 2006 for Sunoco, Inc.

Mr. Justin was elected Vice President, Operations in April 2007. From November 2001 to April 2007, he served as Vice President, Eastern Operations.

Mr. Murphy was elected Vice President and Chief Financial Officer in April 2007. Prior to that, he was employed by Quaker Chemical Corporation, where he served as Vice President and Chief Financial Officer from July 2004 through March 2007.

COMPLIANCE WITH SECTION 16(a) OF THE SECURITIES EXCHANGE ACT OF 1934

Section 16(a) of the Securities Exchange Act of 1934 requires directors, executive officers and persons who beneficially own more than 10 percent of the units to file certain ownership reports with the Securities and Exchange Commission and the New York Stock Exchange. The Securities and Exchange Commission regulations also require that copies of these Section 16(a) reports be furnished us by such reporting persons. Based upon a review of copies of these reports, we believe all applicable Section 16(a) reports were timely filed.

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ITEM 11.

EXECUTIVE COMPENSATION

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

COMPENSATION DISCUSSION AND ANALYSIS

Overview: Our general partner seeks to improve our financial and operating performance and provide a desirable return on investment to holders of our common units, while maintaining financial strength and flexibility. Our general partner provides a competitive compensation package in order to attract highly competent and skilled executives to meet these objectives. In addition, where doing so has been determined to be a cost-effective and administratively efficient means of providing benefits to its employees, our general partner is a participating employer in certain benefit plans sponsored by Sunoco, Inc., including its defined benefit pension plan. We reimburse the general partner for such benefits purchased through our participation in these plans.

Compensation Philosophy: The compensation program for the Named Executive Officers (“NEOs”) of the general partner utilizes objectives and measurement criteria based upon performance relative to other publicly traded master limited partnerships and general industry companies (as adjusted for size), and is designed to provide the competitive level of total compensation needed to attract, retain and motivate talented and experienced executives who can contribute to our success. The compensation program emphasizes performance-based compensation (pay-at-risk), to promote achievement of short-term and long-term business objectives consistent with our strategic plan and is structured so that the target compensation (base salary and performance-based annual and long term opportunities) is generally at the median of the general industry market data. Executive compensation is aligned with the interests of our unitholders by providing annual incentive awards directly tied to cash flow generation and long term incentives in the form of restricted units and requiring significant holdings of common units, representing limited partnership interests in us. The general partner has adopted unit ownership guidelines requiring executives and certain other key employees to own common units, as further described herein. The Compensation Committee reviews the compensation program and makes changes deemed appropriate and in our best interests and in our unitholders’ best interests. The general partner’s eligible executives participate in the defined benefit programs and the qualified and non-qualified defined contribution plans of Sunoco, Inc.

Compensation Methodology: The Compensation Committee utilizes Towers Watson as a consultant to assist in evaluating the effectiveness and competitiveness of the compensation program. Towers Watson assists the Compensation Committee by providing comparative market data on compensation practices and programs based on an analysis of other publicly traded master limited partnerships and general industry companies. Towers Watson provides market data on base salaries paid to executive officers with responsibilities similar in breadth and scope to the general partner at the publicly traded master limited partnership and general industry company level, for which such applicable data exists, as well as a comparison of the mix of total compensation (including base salary, annual incentive award levels, long-term incentive award levels and short- and long-term incentive practices) paid to executive officers in similar positions at such companies. The Compensation Committee retains authority over all compensation decisions for executive officers.

The master limited partnership group consists of the LTIP Peer Group (as discussed on pages 108-109) as well as a broader group of publicly traded master limited partnerships composed of companies of varying revenue and market-cap sizes, with varying market maturity including: Markwest Partners LP, Amerigas Partners LP, Star Gas Partners LP, and Suburban Propane Partners LP, that may compete with the general partner for executive talent (together, the “MLP Group”). This MLP Group is reviewed annually with the assistance of Towers Watson and the composition of the MLP Group may be updated in order to reflect mergers, acquisitions, business bankruptcies and other similar events.

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

The Compensation Committee reviewed the compensation data for each individual NEO compared to the compensation of executives in similar positions with similar responsibility levels in the Compensation Comparative Group. In its review for Mr. Davis, Mr. Keene, Mr. Justin, Mr. Hennigan and Mr. Murphy, the Committee looked primarily at the general industry compensation data, but also reviewed the MLP Group data when such data was applicable to the specific executive position. For Ms. Fretz, the Committee reviewed general industry compensation data, MLP Group data and compensation data for peer executives at Sunoco, Inc.

The three basic components of compensation for executives of the general partner consist of base salary, annual incentives, and long-term incentives. The NEOs total compensation levels were chosen to enhance the general partner’s ability to attract and retain a highly skilled and motivated executive leadership team. Based upon the individual performance of the executive, as well as our performance as a whole, actual realized compensation may be higher or lower than the target. In each case, an executive’s salary and incentive opportunities were determined by the unique responsibilities of his or her position. As a tool to assist in its review of executive compensation, the Compensation Committee uses tally sheets that reflect all components of the executive’s total compensation, including salary, annual incentives, and long-term incentives. Additionally, in consultation with the compensation consultant, management and other outside advisors, the Compensation Committee has reviewed the estimated compensation to be received by the CEO and the other NEOs under various scenarios, including normal retirement, voluntary or involuntary termination, and involuntary termination due to a change in control of the Partnership or Sunoco, Inc.

Elements of Compensation:

•

Base Salary: Base salary is designed to compensate executives for their level of responsibility and sustained individual performance (including experience, scope of responsibility, and results achieved). The salaries of the NEOs are reviewed on an annual basis. The compensation consultant provides benchmarking data on the compensation of the NEOs compared to the compensation of executives in the Compensation Comparative Group. The general partner and the Compensation Committee attempt to establish and maintain base salaries for the NEOs at or near the median level of competitive market base salary data. Base salaries also are influenced by internal equity (fair and consistent application of compensation practices). The Compensation Committee, with input from the compensation consultant and the CEO (who provides input for the NEOs other than herself), approves all base salaries for the NEOs. The Summary Compensation Table on page 113 includes the base salaries of the NEOs that were approved for 2009, or for those NEOs that were employed for only a partial year, the salaries actually earned in 2009. At the NEO level, the balance of compensation is weighted toward pay-at-risk compensation (annual and long-term incentives).

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•

Annual Incentive Awards:

•

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

•

Determination of the Amounts Awarded Under the Annual Incentive Plan. Under the plan, an individual’s annual incentive payout amount is determined by multiplying the product of his or her base salary and individual incentive guideline by a factor ranging from zero to 200 percent, based upon the level of attainment of pre-established goals for our cash flow from operations. The annual incentive guideline is based on general industry market data as well as internal equity considerations. Following the end of each year, the Compensation Committee reviews performance data with management and the compensation consultant, and determines the extent to which these goals have been achieved. This adjusted amount may be adjusted up or down (by no more than 10 percent) to reflect our actual performance with regard to certain health, environment and safety criteria. Additionally, a potential upwards or downwards adjustment of 5 percent may be made if the pipeline and terminals segments of our business places within either the first quartile OSHA performance ranking (+ 5 percent) or bottom quartile OSHA performance ranking (-5 percent) ranking relative to its pipeline industry group. The health, environment and safety component does not apply if our minimum performance goals are not attained. If we do not achieve at least the minimum threshold performance goals, no award payment will be made.

The respective payout percentages for these criteria were established at levels that the Compensation Committee believes provide meaningful incentives to achieve the established performance goals. The following performance goals, assigned weights and performance factors were approved by the Compensation Committee for purposes of calculating the eventual payout for awards made for the 2009 plan year under the Annual Incentive Plan:


Cash Flow from Operations	Payout
<71% of cash flow target	0	%
71% of cash flow target	25	%
Cash flow target - 113% of cash flow target	100	%
142% of cash flow target	200	%

As described above, the performance factors may be adjusted (up or down) by the relative achievement of certain health, environment and safety performance goals. Payout for performance between specified performance goals will be interpolated on a straight-line basis. In no event can the annual incentive payout amount exceed 200 percent of the individual’s guideline amount, even after taking the applicable adjustments into account.

Use of cash flow from operations as the primary criterion for payout of the 2009 annual incentive award ensures that management will continue to be focused on operations excellence. Our cash flow from operations measure, which we define as net income plus depreciation minus maintenance capital, (as may be adjusted by Compensation Committee for any unique events to reflect the actual annual performance of our business) is not determined in accordance with GAAP. Use of health, environment and safety performance to further adjust the payout reinforces that, along with financial success, management is focused on continuing to protect our employees and the communities in which we operate.

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2009 Annual Incentive Payout Amount. Based upon our level of attainment of goals for cash flow from operations during the 2009 plan year, the payout factor was 107.5 percent, which includes the applicable health, environmental and safety factor for each business unit. The annual incentive reinforces the links between strategy, goal-setting and results. The individual incentive guidelines (as a percentage of base salary) for each of the NEOs for 2009 were as follows:


Name	Title	Annual Incentive Plan Guideline Incentive 2009
Deborah M. Fretz	President and Chief Executive Officer	80%
Neal E. Murphy	Vice President and Chief Financial Officer	45%
Michael J. Hennigan	Vice President, Business Development	65%
Bruce D. Davis, Jr.	Vice President, General Counsel and Secretary	45%
David A. Justin	Vice President, Operations	45%

Under the general partner’s Annual Incentive Plan, the Compensation Committee has the discretion to reduce the amounts payable to participants, or to determine that no amount will be paid, even if all performance criteria for payout are met. The annual incentive awards are paid in cash. The annual incentives earned by NEOs for 2009 are included in the Summary Compensation Table on page 113 under “Non-Equity Incentive Plan Compensation.”

•

Long-Term Incentive Awards:

•

Why the Long-Term Incentive Plan was Adopted. Long-term incentive awards for the NEOs are granted under the Sunoco Partners LLC Long-Term Incentive Plan (the “LTIP”), in order to promote achievement of our long-term strategic business objectives. This plan was designed to align the economic interests of key employees and directors with those of our common unitholders; to provide competitive compensation opportunities that can be realized through attainment of performance goals; and to provide an incentive to management for continuous employment with the general partner and its affiliates. Long-term incentive compensation is based upon the common units representing limited partnership interests in us, although it may be payable in common units, or in cash. The Compensation Committee administers the plan and, in its discretion, may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. However, no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the participant. The Compensation Committee also has the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted, subject to unitholder approval as required by the exchange upon which the common units are listed at that time.

•

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

•

Restricted Units. Each restricted unit entitles the grantee to receive a common unit upon vesting or, in the discretion of the Compensation Committee, an amount of cash equivalent to the value of a common unit. From time to time, the Compensation Committee may make grants under the plan to employees and/or directors containing such terms as the Compensation Committee shall determine under the plan. Special one-time grants of restricted units may be made at any time during the year, subject to the approval of the Compensation Committee. These grants are infrequent, and generally are used for new hires, promotions and recognition of extraordinary accomplishments. The Compensation Committee will determine the period over which restricted units granted to employees and/or directors will vest, and whether or not any such restricted units will have distribution equivalent rights entitling the grantee to receive an amount in cash equal to cash distributions made by us with respect to a like number of our common units during the period such restricted units are outstanding. Performance-based restricted units are designed to pay out only if certain objective Partnership-specific performance measures have

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been met over the applicable performance period, generally three years. As a result, the payout under an LTIP award of performance-based restricted units is influenced not only by performance in the year in which the award is paid, but also by performance for the two prior years. In addition, the value received from restricted unit awards will be affected by any changes in the trading price of our common units during the period of time between the grant date and the payment date.

•

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

•

Determination of the Amounts Awarded under the LTIP. In conjunction with the review and approval of other elements of each NEO’s compensation, the annual LTIP awards were reviewed and approved at the Compensation Committee’s January 2009 meeting, and for Mr. Hennigan at the July 2009 meeting, and the grant date was the date of each meeting. As appropriate, the Compensation Committee may also review and approve specific LTIP awards to NEOs at other times during the year in connection with their hiring. In determining the appropriate long-term value for each executive, the Compensation Committee reviews the level of responsibility and total compensation of each NEO executive, and the competitive market data presented by the compensation consultant. The Compensation Committee approves the specific amounts granted to each employee. In general, the target number of restricted units granted to each NEO under the LTIP is calculated by taking the product of the NEO’s base salary and the applicable guideline percentage for that NEO, and then dividing by the average daily closing market price of our common units during the last thirty (30) trading days prior to the December 31 preceding the meeting at which the LTIP grant will be approved. Under no circumstances may the aggregate number of units granted to a single executive exceed the maximum applicable limit(s) under the LTIP. When approving grants to the executives, the Compensation Committee considers information or recommendations provided by the CEO, except with respect to the CEO’s own grants. The Compensation Committee utilizes Towers Watson to assist in the evaluation of grant recommendations. For the LTIP grants made during 2009, the applicable NEO guideline percentages were as follows:


Name	Title	LTIP Guideline Percentage
Deborah M. Fretz	President and Chief Executive Officer	194	%
Neal E. Murphy	Vice President and Chief Financial Officer	75	%
Michael J. Hennigan	Vice President, Business Development	91	%
Bruce D. Davis, Jr.	Vice President, General Counsel and Secretary	75	%
David A. Justin	Vice President, Operations	80	%

The long-term incentive compensation is based upon the common units representing limited partnership interests in us. The expenses for LTIP equity awards are recognized ratably over the vesting period, and are accelerated for vesting at retirement eligibility dates.

•

Determination of LTIP Award Payout. The LTIP awards are designed to provide long-term incentive compensation that is designed to payout only if certain pre-established, objective performance measures have been met over an applicable performance period as measured against peer companies. For 2009, the Compensation Committee has determined that eventual payout of the awards will depend upon our achievement of certain performance levels based on two equally weighted performance measures relative to peer companies: total unitholder return (including cash distributions plus appreciation in unit price) and growth in cash distributions to unitholders, both measured over a three-year performance cycle. Our peer companies consist of other publicly traded master limited partnerships having a business mix comparable to ours (the “LTIP Peer Group”).

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For the 2009 fiscal year, the LTIP Peer Group consisted of the following companies: Buckeye Partners LP; Crosstex Energy LP; Enbridge Energy Partners LP; Energy Transfer Partners L.P.; Enterprise Products Partners LP; Holly Energy Partners LP; Kinder Morgan Energy Partners LP; Magellan Midstream Partners LP; NuStar Energy LP; ONEOK Partners LP; Plains All American Pipeline LP; and TEPPCO Partners LP. This LTIP Peer Group is reviewed annually with the assistance of Towers Watson. The performance period for the 2009 awards ends December 31, 2011. Actual payout may range from zero percent to 200 percent of the units granted to each NEO based on our percentile ranking against our peer companies improves with respect to each of these two performance measures. The respective payout factor is zero for a ranking below the fortieth percentile on each performance measure. Maximum potential payout is achieved at a ranking at or above the ninetieth percentile on each performance measure. The following objective performance goals, assigned weights, and payout factors were approved by the Compensation Committee for the 2009 plan year:

Total Unitholder Return and Growth in Cash Distributions to Unitholders

(each weighted 50%)


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

In selecting total unitholder return and growth in distributable cash as the performance measures applicable to the payout of performance-based restricted units, consideration was given to a balanced incentive approach, utilizing those measures deemed most important to our common unitholders, while recognizing the difficulty of accurately predicting market conditions over time. The Compensation Committee believes that performance relative to the peer companies is an important criterion for payout since market conditions are outside the control of management, and management will realize greater than median levels of compensation only when we outperform our LTIP Peer Group. Conversely, regardless of market conditions, management will realize less than median compensation levels when we underperform as compared to our LTIP Peer Group. Total unitholder return is a measure of investment performance expressed as total return to unitholders based upon the cumulative return over a three-year period reflecting price appreciation and reinvestment of cash distributions during the performance period and is a non-GAAP metric. Total unitholder return is measured using a one-month average stock price at the beginning and end of the three-year performance period. Similarly, growth in distributable cash is also a non-GAAP financial measure. Growth in cash distributions per unit is measured over a three-year performance period using a point-to-point approach in which performance is measured at the beginning and end of the performance cycle.

As an additional incentive to promote the growth of cash distributions to our unitholders during the performance period, distribution equivalent rights were granted in tandem with the 2009 performance based restricted unit awards. At the end of the performance period, to the extent that the restricted units are paid out, these distribution equivalent rights entitle the grantee of the restricted units to receive an amount equal to the cumulative cash distributions that otherwise would have been paid over the performance period had the grantee been the holder of record of our common units equal to the number of restricted units paid out. This amount may be taken in the form of cash or additional common units (fractional units are cashed out).

109

•

2009 Payout for 2007 LTIP Award Grants. The performance period for the performance-based restricted units awarded in January 2007 and April 2007 ended December 31, 2009, and the level of payout of these awards reflects our level of achievement of the applicable performance measures over the three-year performance period. The performance measures for these awards were total unitholder return and growth in cash distributions to unitholders.

Unit Ownership Guidelines: Sunoco Partners LLC has established guidelines for the ownership of our common units, applicable to its directors, executives and certain key employees. Under these guidelines, the independent directors must own our common units having a market value at all times equal to at least three times their average annual compensation (including retainers and fees). The other directors must own at least 1,000 of our common units. All directors are granted a five-year eligibility period to meet these unit ownership guidelines. For the NEOs, the applicable unit ownership guidelines are denominated as a multiple of base salary, and the amount of common units required to be owned increases with the level of responsibility, with the Chief Executive Officer expected to own common units with a value equal to at least five times base salary, and the other NEOs expected to own stock with a minimum value of two times their base salary. The general partner and the Compensation Committee believe that the ownership of our common units, as reflected in these guidelines, is an important means of tying the financial risks and rewards for our executives to our total unitholder return and better aligning the interests of such executives with those of our unitholders. NEOs who have not yet met their respective guideline must accumulate our common units until such guideline is met. Except for sales of common units in settlement of tax obligations relating to the receipt and payment of LTIP awards, such persons are prohibited from disposing of any of our common units until the applicable ownership guideline has been attained. However, those individuals who have met or exceeded their applicable ownership guideline may dispose of our common units in a manner consistent with applicable law and our policy, but only to the extent that such individual’s remaining ownership of common units would continue to exceed the applicable ownership guideline.

Other Plans: Employees of the general partner and its affiliates, including the NEOs, also may participate in the following Sunoco, Inc. benefit plans:

•

Capital Accumulation Plan (“SunCAP”) is a defined contribution 401(k) plan, designed for long-term investment, to assist in accumulating funds for retirement. For employees having at least one year of service, we match the first five percent of base pay contributed, on a dollar-for-dollar basis. The employee chooses from among various funds provided for investment of contributions, and matching contributions. An employee who terminates employment may elect to take a lump-sum distribution from the plan.

•

Savings Restoration Plan is a non-qualified deferred compensation plan available to those SunCAP participants subject to compensation and/or contribution limitations under the Internal Revenue Code. Participants may contribute amounts in excess of the applicable limits, up to five percent of base salary. The amounts of the company match for the NEOs in 2009 under the Capital Accumulation Plan and the Savings Restoration Plan are included in the Summary Compensation Table on page 113 under “All Other Compensation” and are further described in the notes accompanying the table.

•

Retirement Plan is a qualified defined benefit plan, under which benefits are subject to IRS limits for pay and amount. Under the Retirement Plan, executives hired before January 1, 1987 participate in a “final average pay” formula. Those executives hired on or after January 1, 1987 participate in a “cash balance” formula, which provides a benefit based on career pay rather than final average pay.

•

Pension Restoration Plan is a non-qualified, unfunded plan that provides retirement benefits that otherwise would be provided under the Retirement Plan, except for the Internal Revenue Code limits.

•

Executive Retirement Plan is a non-qualified, unfunded plan which provides supplemental pension benefits to certain eligible NEOs (Mr. Justin is the only currently eligible NEO) over and above an NEO’s benefits under the Retirement Plan and the Pension Restoration Plan. This plan was designed to attract mid-career senior executives by providing competitive retirement benefits and by accelerating benefit accruals for the first 12 years of service as an executive. Such benefits otherwise would not be available, due to the break in service when leaving a prior employer. Benefits under this plan are offset by those provided under the Retirement Plan and the Pension Restoration Plan.

110

The present values of each NEO’s accumulated pension benefit, as of year-end 2009 are included in the Pension Benefits Table on page 121. More detailed descriptions of the Retirement Plan, the Pension Restoration Plan and Executive Retirement Plan are included in the narrative accompanying the table.

Consistent with actions taken by employers in other industries, effective June 30, 2010, Sunoco, Inc. is freezing pension benefits for all salaried employees, including the NEOs, and many non-union employees. This includes any pension benefits that the NEOs may have accrued and are vested under the Executive Retirement Plan. The Partnership has no employees and reimburses Sunoco, Inc. for our allocated share of Sunoco, Inc. employee benefit plans. In addition to the freezing of retirement benefits, Sunoco, Inc. is phasing out access to medical benefits for the majority of future retirees—employees who retire after July 1, 2010.

To replace these legacy plans, effective July 1, 2010, for all employees, including the NEOs, with at least one year of service who are affected by the pension freeze, we may make a discretionary profit sharing contribution of up to 3% of base pay, and an additional discretionary profit sharing contribution of up to 4% of base pay for such employees who, on June 30, 2010, had at least 10 years of service plus completed years of age totaling at least 60.

Other Benefits: Employees of our general partner and its affiliates, including the NEOs, participate in a variety of other benefits, including medical, dental, life insurance, disability, holidays and vacation. These benefits generally are provided on an enterprise-wide basis to employees of the general partner and its affiliates. The executives receive the same benefits at the same rates as other employees.

Perquisites: In 2009, certain NEOs also received a limited number of personal benefits, or “perquisites”. The dollar amount of the perquisites received by the NEOs is included in the Summary Compensation Table on page 113 under “All Other Compensation.”

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

The Sunoco Partners LLC Executive Involuntary Severance Plan provides certain severance benefits to the general partner’s NEOs and other key management personnel, involuntarily terminated other than for just cause, death or disability. In recognition of their past service, the plan is intended to alleviate the financial hardship that may be experienced by certain employees whose employment is terminated. The amount or kind of benefit to be provided is based on the executive’s position and compensation at the time of termination. Depending upon salary level, NEOs would receive severance payments ranging from one to one and one-half times base salary plus their guideline annual incentive in effect on the termination date.

The Sunoco Partners LLC Special Executive Severance Plan provides severance benefits in case of termination (whether actual or constructive and other than for just cause, death or disability) occurring within two years after a change of control of the Partnership, as defined in the plan. The plan was adopted to retain executives in the event of a major transaction or change in control, and to eliminate the uncertainty and questions which such a transaction may raise among management, and which may result in the departure or distraction of key management personnel to our detriment and/or our general partner. Our general partner’s Board of Directors has determined that appropriate steps should be taken to reinforce and encourage the continued attention and dedication of key management personnel to their assigned duties without distraction.

111

The Board believes that in the context of a change in control, potential acquirers may otherwise have an incentive to constructively terminate the executive’s employment to avoid paying severance, and it is therefore appropriate to provide severance benefits in this circumstance. Severance under this plan would be payable in a lump sum, equal to three times annual compensation for the CEO, and two times annual compensation for the other NEOs. Our general partner’s Board of Directors believes that the potential severance payments provide an appropriate level of protection to the executive for the critical period following a change in control at a reasonable cost to us. For these purposes, annual compensation consists of: (i) annual base salary in effect immediately prior to a change in control or immediately prior to the employment termination date, whichever is greater, plus (ii) the greater of annual guideline incentive in effect immediately before the change in control or employment termination date, or the highest bonus awarded in any of the three years ending prior to the change in control, or any subsequent year ending before the employment termination date.

Eligible executives under the Involuntary Severance Plan are entitled to medical coverage during the applicable severance period, at the same rate that such benefits are provided to active employees. Eligible executives under the Special Executive Severance Plan are entitled to medical, dental and life insurance coverage during the applicable severance period, at the same rate that such benefits are provided to active employees.

The Annual Incentive Plan provides that, upon a change in control, as defined in the plan, the participants will receive a pro rata portion of the annual incentive award based on the level of attainment of applicable performance targets.

The Sunoco Partners LLC Long-Term Incentive Plan provides that, upon a change in control, as defined in the plan, all awards of restricted units or unit options automatically vest and become payable or exercisable, as the case may be. Restricted units that have been outstanding for more than one year will be paid out at the greater of the target amount, or an amount in line with our actual performance immediately prior to the change in control. Those restricted units that have been outstanding for one year or less will be paid out at the target amount.

Additional information regarding these plans can be found under “Other Potential Post-Employment Payments” on page 125.

112

SUMMARY COMPENSATION TABLE

The Summary Compensation Table reflects the total compensation earned in 2009 by the CEO, CFO and each of the three other most highly compensated executive officers of the general partner as of December 31, 2009, as well as one former executive officer (together, the “NEOs”), and for those NEOs previously on the table, for 2008 and 2007:


Name and Principal Position	Year	Salary ($)		Bonus ($)		Stock Awards⁽¹⁾ ($)		Option Awards⁽²⁾ ($)	Non-Equity Incentive Plan Compensation⁽³⁾ ($)		Change in Pension Value and Nonqualified Deferred Compensation Earnings⁽⁴⁾ ($)		All Other Compensation⁽⁵⁾ ($)	Total ($)
D. M. Fretz⁽⁶⁾	2009	515,000		None		1,985,105		None	412,000		545,996		24,349	3,482,450
President and Chief	2008	500,000		None		2,205,898		None	788,000		1,215,056		41,036	4,749,990
Executive Officer	2007	480,000		None		1,760,147		None	630,144		703,277		40,658	3,614,226

N. E. Murphy	2009	306,400		None		477,964		None	148,221		67,556		13,088	1,013,229
Vice President and	2008	297,440		None		354,928		None	263,681		45,433		11,682	973,164
Chief Financial Officer	2007	203,500	⁽⁷⁾	182,850	⁽⁸⁾	209,914		None	136,668	⁽⁹⁾	16,056		552	749,540

M.J. Hennigan	2009	269,622	⁽¹⁰⁾	None		52,578		None	184,426	⁽¹¹⁾	850,952		15,905	1,373,483
Vice President,
Business Development

B. D. Davis, Jr.	2009	279,400		None		333,146		None	135,160		68,930		13,014	829,650
Vice President, General	2008	266,090		None		412,154		None	209,679		54,747		14,005	956,675
Counsel and Secretary	2007	241,900		None		295,004		None	158,783		34,980		12,745	743,412

D. A. Justin	2009	271,700		None		413,766		None	131,435		609,375		13,493	1,439,769
Vice President,	2008	262,500		None		422,149		None	232,706		204,955		13,829	1,136,139
Operations	2007	244,216	⁽¹²⁾	None		352,059		None	164,100		0	⁽¹³⁾	11,934	772,309

C. W. Keene	2009	108,675	⁽¹⁴⁾	None		121,216	⁽¹⁵⁾	None	Not Applicable		66,687		602,957	899,535
Former Vice President,	2008	264,368		None		543,134		None	208,322		49,797		13,930	1,079,551
Business Development	2007	254,200		None		482,975		None	166,857		33,262		13,396	950,690

NOTES TO TABLE:

⁽¹⁾

The amounts shown in this column reflect the amounts recognized as compensation expense on our financial statements at year-end 2009, 2008 and 2007, respectively, relating to performance-based restricted unit awards under the Sunoco Partners LLC Long-Term Incentive Plan (the “LTIP”), approved by the Compensation Committee at its regularly scheduled meetings in January 2009, July 2009, January 2008, January and April 2007 as well as similar expense for outstanding prior year awards, approved by the Compensation Committee at its regularly scheduled meetings in April 2006 and January 2005. Such compensation expense includes tandem distribution equivalent rights related to the restricted unit awards. These awards have a three-year restriction period. Compensation expense for the 2009 and 2008 awards was calculated assuming an eventual target payout of 100 percent. Compensation expense for the 2007 awards (which were paid out on February 9, 2010, in the form of common units), the 2006 awards (which were paid out on February 9, 2009, in the form of common units) and the 2005 awards (which were paid out on February 8, 2008, in the form of common units) were calculated using the actual performance-adjusted payout percentage of 200 percent, 200 percent, 163.2 percent, respectively. At the time of the filing of this report, Ms. Fretz and Mr. Justin are retirement eligible and the compensation expense has been recognized immediately upon grant for their 2008 and 2009 awards. See the “Compensation, Discussion and Analysis” on page 104 for the specific performance measures applicable to the payout and vesting of these awards. These awards were granted with tandem distribution equivalent rights.

⁽²⁾

Although permitted by the terms of the LTIP, no Unit Options have been awarded at this time.

⁽³⁾

The amounts shown in this column reflect annual incentive amounts earned under the Sunoco Partners LLC Annual Incentive Plan, for performance during 2009, 2008 and 2007 and payable on or before March 12, 2010, March 13, 2009, and March 14, 2008, respectively.

113

⁽⁴⁾

The amounts shown in this column reflect the change in each NEO’s pension value between December 31, 2009 and December 31, 2008, December 31, 2008 and December 31, 2007, and December 31, 2007 and December 31, 2006, respectively. The NEOs did not have any above-market or preferential payments on deferred compensation during 2009, 2008, or 2007. Certain of the NEOs have deferred amounts under the Sunoco, Inc. Savings Restoration Plan, an excess 401(k) benefit plan available to employees of Sunoco, Inc. and subsidiaries such as the Partnership’s general partner. However, the earnings received from participation in this plan are the same as dividends earned on Sunoco, Inc. common stock (in the case of the Sunoco stock-related funds), and/or are based on the gains/losses of certain mutual funds, which are calculated in the same manner and at the same rate of earnings as for all other employees invested in those funds in the Sunoco, Inc. Capital Accumulation Plan (the “SunCAP”), the broad-based 401(k) qualified defined contribution plan for Sunoco, Inc. and its subsidiaries.

⁽⁵⁾

The table below shows the components of this column for 2009, 2008 and 2007:


Name	Year	Company Match Under Defined Contribution Plan ($)	Cost of Basic Life Insurance ($)	Financial Counseling ($)	Amounts Reimbursed for Payment of Certain Taxes ($)	Perquisites >$10,000 ($)	Amounts Paid in Connection with Termination of Employment ($)	Amounts Reimbursed for Moving & Relocation Expenses ($)	Total ($)
D. M. Fretz	2009	12,250	1,409	—	—	10,690	—	—	24,349
	2008	24,977	1,368	—	—	14,691	—	—	41,036
	2007	23,976	1,313	—	—	15,369	—	—	40,658

N.E. Murphy	2009	12,250	838	—	—	—	—	—	13,088
	2008	10,868	814	—	—	—	—	—	11,682
	2007	—	552	—	—	—	—	—	552

M.J. Hennigan	2009	12,250	1,155	2,500	—	—	—	—	15,905

B. D. Davis, Jr.	2009	12,250	764	—	—	—	—	—	13,014
	2008	13,277	728	—	—	—	—	—	14,005
	2007	12,083	662	—	—	—	—	—	12,745

D. A. Justin	2009	12,250	743	500	—	—	—	—	13,493
	2008	13,111	718	—	—	—	—	—	13,829
	2007	11,250	684	—	—	—	—	—	11,934

C.W. Keene	2009	5,447	297	—	—	—	597,213	—	602,957
	2008	13,207	723	—	—	—	—	—	13,930
	2007	12,701	695	—	—	—	—	—	13,396

•

For Ms. Fretz, the amount shown for perquisites in 2009, 2008 and 2007 includes: (1) an allowance for parking and (2) reimbursements for certain fees and dues relating to business club memberships. Our general partner provides Ms. Fretz with tax gross-ups for business club memberships.

•

Sunoco Partners LLC, our general partner, is a participating employer in two Sunoco, Inc. defined contribution plans: (1) the SunCAP, a 401(k) plan open to most employees; and (2) the Sunoco, Inc. Savings Restoration Plan, for executive-level SunCAP participants otherwise subject to certain Internal Revenue Code limitations on 401(k) plan contributions. The Savings Restoration Plan permits such participants to continue to receive matching contributions after exceeding the applicable limits.

•

Basic life insurance coverage is provided to employees of our general partner, including the NEOs. The coverage/premium amount is one times base salary, at a monthly rate of $0.228 for each $1,000 of base salary.

114

•

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

•

For Mr. Keene, the amounts shown in the column captioned “Amounts Paid in Connection with Termination of Employment” represent cash severance benefits payable to Mr. Keene under the Sunoco Partners LLC Executive Involuntary Severance Plan, following his departure on May 14, 2009 consisting of:

•

78 weeks’ worth of annual base salary, increased by the portion of applicable target annual bonus amount;

•

vacation benefits accrued through his employment termination date ($20,946); and

•

certain medical plan benefits (excluding dental coverage but including COBRA dental continuation coverage), and running for a period of 78 weeks

⁽⁶⁾

Ms. Fretz is a director of Sunoco Partners LLC, our general partner. However, she does not receive separate compensation for her service as a director.

⁽⁷⁾

Mr. Murphy began his employment with our general partner on April 9, 2007. This figure represents the portion of his base salary that was earned in 2007.

⁽⁸⁾

This figure represents the sign-on bonus received by Mr. Murphy relating to his employment with our general partner.

⁽⁹⁾

The award amount granted to Mr. Murphy under the Sunoco Partners LLC Annual Incentive Plan was pro-rated to reflect Mr. Murphy’s initiation of employment with our general partner on April 9, 2007.

⁽¹⁰⁾

Mr. Hennigan began his employment with our general partner on May 15, 2009. This figure represents the portion of his salary earned in 2009. Prior to joining the general partner, Mr. Hennigan was a senior executive at Sunoco, Inc. Mr. Hennigan’s base salary is equivalent to his prior Sunoco, Inc. base salary. Pursuant to an agreement between the Partnership and Sunoco, Inc., the Partnership will pay a portion of Mr. Hennigan’s base salary. Sunoco, Inc. will reimburse the Partnership for that portion of Mr. Hennigan’s base salary in excess of this amount and pro-rated for 2009 (for a total reimbursement of $98,707).

⁽¹¹⁾

The award amount granted to Mr. Hennigan under the Sunoco Partners LLC Annual Incentive Plan was pro-rated to reflect Mr. Hennigan’s initiation of employment with our general partner on May 15, 2009.

⁽¹²⁾

Mr. Justin’s 2007 base salary was increased from $227,700 to $250,000 effective March 25, 2007 to coincide with his appointment as Vice President, Operations. Mr. Justin had previously served as Vice President, Eastern Operations.

⁽¹³⁾

The positive value of the year-over-year change in the actuarial value of benefits earned under the Sunoco, Inc. Retirement Plan of $43,221 and the Pension Restoration Plan of $16,355 is offset by the negative value of year-over-year change in actuarial value of benefits earned under the Sunoco Inc. Executive Retirement Plan of $79,453, resulting in a negative sum.

⁽¹⁴⁾

This figure represents the portion of the 2009 salary paid to Mr. Keene, prior to the date of his termination of employment.

⁽¹⁵⁾

The amounts shown reflect the amounts recognized as compensation expense for 2009 related to the special unit award granted to Mr. Keene on January 26, 2007 pursuant to the LTIP Plan that vested at 100% of the payout percentage (inclusive of applicable distribution equivalent rights) on May 28, 2009. All of Mr. Keene’s other outstanding restricted unit awards were forfeited upon his termination of employment.

115

GRANTS OF PLAN-BASED AWARDS

The following table sets forth the grant of awards to the CEO, CFO and each of the three other most highly compensated NEOs as well as one former NEO in 2009:


Name	Grant Date	Estimated Future Payouts Under Non-Equity Incentive Plan Awards⁽¹⁾					Estimated Future Payouts Under Equity Incentive Plan Awards				All Other Stock Awards: Number of Shares of Stock or Units (#)	All Other Option Awards: Number of Securities Underlying Options⁽³⁾ (#)	Exercise or Base Price of Option Awards ($/Unit)	Grant date fair value of stock and option awards⁽⁴⁾
Name	Grant Date	Threshold ($)		Target ($)		Maximum ($)	Threshold (#)	Target (#)		Maximum (#)
D. M. Fretz	01-28-2009	—		412,000		824,000	—	23,414	⁽²⁾	46,828	—	—	—	1,399,221
President and Chief Executive Officer

N.E. Murphy	01-28-2009	—		137,880		275,760	—	5,380	⁽²⁾	10,760	—	—	—	321,509
Vice President and Chief Financial Officer

M.J. Hennigan	—	171,559	⁽⁵⁾	171,559	⁽⁵⁾	343,118
Vice President, Business Development	07-20-2009	—		—		—		4,719	⁽²⁾	9,438	—	—	—	282,007

B. D. Davis, Jr.	01-28-2009	—		125,730		251,460	—	4,906	⁽²⁾	9,812	—	—	—	293,183
Vice President, General Counsel and Secretary

D. A. Justin	01-28-2009	—		122,265		244,530	—	5,089	⁽²⁾	10,178	—	—	—	304,119
Vice President, Operations

C. W. Keene ⁽⁶⁾ Former Vice President, Business Development	—	—		—		—	—	—		—	—	—	—	—

NOTES TO TABLE:

⁽¹⁾

This reflects a target and maximum annual incentive award amounts for each NEO equal to the target percentages set forth above in the section entitled “2009 Annual Incentive Payout Amount.” The maximum reflects that the NEO may receive up to 200% of the target bonus award amount. The annual incentive is paid out in cash, and any amounts earned for performance during the 2009 year will be paid out no later than March 12, 2010.

⁽²⁾

The performance-based restricted units were awarded under the Sunoco Partners LLC Long-Term Incentive Plan (the “LTIP”) on January 28, 2009 except that Mr. Hennigan’s performance-based restricted units were awarded on July 20, 2009, in connection with his hiring. These performance-based restricted units were granted with tandem distribution equivalent rights. Actual payout of these awards will depend upon our achievement of certain specified performance levels, ranked against our peer group of companies, based upon equally weighted annual objectives for total unitholder return and growth cash distributions to unitholders. The portion of each award that may be earned during the performance period (which runs from January 1, 2009 to December 31, 2011) ranges from a threshold value of zero, to a target value equal to 100 percent of the award, and a maximum value of 200 percent of the award. Payment of any amounts earned will occur following such period, assuming continued employment with the general partner at such time.

⁽³⁾

Although permitted by the terms of the LTIP, no Unit Options have been awarded at this time.

⁽⁴⁾

Grant date fair value was calculated in accordance with accounting guidance.

⁽⁵⁾

Pursuant to the agreement between Sunoco, Inc. and the Partnership, this amount represents the pro-rated portion of Mr. Hennigan’s 2009 Sunoco, Inc. target incentive compensation to be paid by us under the Sunoco Partners LLC Annual Incentive Plan.

⁽⁶⁾

Effective May 14, 2009, Mr. Keene’s employment terminated and all of his then-outstanding restricted units were forfeited at that time, with the exception of his special unit award granted on January 26, 2007, which vested and was paid out in cash (inclusive of the applicable distribution equivalent rights) on May 28, 2009.

116

OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END

The following table provides information concerning the unvested and outstanding equity awards to each current NEO as of December 31, 2009:


Name	Option Awards⁽¹⁾					Stock Awards
Name	Number of Securities Underlying Unexercised Options (#) Exercisable	Number of Securities Underlying Unexercised Options (#) Unexercisable	Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)	Option Exercise Price ($)	Option Expiration Date	Number of Shares or Units of Stock That Have Not Vested (#)	Market Value of Shares or Units of Stock That Have Not Vested ($)	Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)		Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ⁽²⁾ ($)
D. M. Fretz
President								22,950	⁽³⁾
and Chief Executive	—	—	—	—	—	—	—	23,414	⁽⁴⁾	3,101,288
Officer

N.E. Murphy	—	—	—	—	—	—	—	5,045	⁽³⁾
Vice President and Chief								5,380	⁽⁴⁾	697,328
Financial Officer

M.J. Hennigan	—	—	—	—	—	—	—	4,719	⁽⁴⁾	315,654
Vice President,
Business Development

B. D. Davis, Jr.								4,036	⁽³⁾
Vice President, General								4,906	⁽⁴⁾	598,130
Counsel and Secretary	—	—	—	—	—	—	—

D. A. Justin								4,453	⁽³⁾
Vice President,	—	—	—	—	—	—	—	5,089	⁽⁴⁾	638,264
Operations

NOTES TO TABLE:

⁽¹⁾

Although permitted by the terms of the Sunoco Partners LLC Long-Term Incentive Plan (the “LTIP”), no Unit Options have been awarded at this time.

⁽²⁾

The market value or payout value of the unearned restricted units is based on the trading price of our common units on December 31, 2009 of $66.89, and assumes a payout at the target of 100 percent.

⁽³⁾

These performance-based restricted units were awarded January 23, 2008 and the performance period ends on December 31, 2010. Actual payout of these awards will depend upon our achievement of certain specified performance levels, ranked against our peer group of companies, based upon total unitholder return and growth in cash distributions to unitholders. The portion of each award that may be earned during the performance period ranges from a threshold value of zero, to a target value equal to 100 percent of the award, and a maximum value of 200 percent of the award. Payment of any amounts earned will occur following such period, assuming continued employment with the general partner at such time. At the end of the performance period, to the extent that the performance-based restricted units are paid out, each holder of performance-based restricted units also will receive an amount equal to the cumulative cash distributions that would have been paid over the performance period had he or she been the holder of record of our common units, equal to the number of the performance-based restricted units, if any, paid out.

⁽⁴⁾

These performance-based restricted units were awarded January 28, 2009, except that Mr. Hennigan’s performance-based restricted units were awarded on July 20, 2009, in connection with his hiring, and the performance period for all awards ends on December 31, 2011.

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Actual payout of these awards will depend upon our achievement of certain specified performance levels, ranked against our peer group of companies, based upon total unitholder return and growth in cash distributions to unitholders. The portion of each award that may be earned during the performance period ranges from a threshold value of zero, to a target value equal to 100 percent of the award, and a maximum value of 200 percent of the award. Payment of any amounts earned will occur following such period, assuming continued employment with the general partner at such time. At the end of the performance period, to the extent that the performance-based restricted units are paid out, each holder of performance-based restricted units also will receive an amount equal to the cumulative cash distributions that would have been paid over the performance period had he or she been the holder of record of our common units, equal to the number of the performance-based restricted units, if any, paid out.

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OPTION EXERCISES AND STOCK VESTED

The following table provides information concerning the amounts related to the vesting in 2009 of certain restricted units, previously awarded under the Sunoco Partners LLC Long-Term Incentive Plan (the “LTIP”) to our current NEOs, as well as one former NEO:


Name	Option Awards ⁽¹⁾		Stock Awards
Name	Number of Shares Acquired on Exercise (#)	Value Realized on Exercise ($)	Number of Shares Acquired on Vesting (#)		Value Realized on Vesting⁽³⁾ ($)
D. M. Fretz	—	—	44,724	⁽²⁾	$	3,410,540
President and Chief Executive Officer
N.E. Murphy	—	—	8,416	⁽²⁾	$	875,894
Vice President and Chief Financial Officer			3,070	⁽⁴⁾
M.J. Hennigan	—	—	—			—
Vice President, Business Development
B. D. Davis, Jr.	—	—	7,474	⁽²⁾	$	569,948
Vice President, General Counsel and Secretary
D. A. Justin	—	—	8,370	⁽²⁾	$	638,276
Vice President, Operations
C.W. Keene	—	—	4,981	⁽⁵⁾	$	294,589
Former Vice President, Business Development

NOTES TO TABLE:

⁽¹⁾

Although permitted by the terms of the LTIP, no Unit Options have been awarded at this time.

⁽²⁾

Amounts shown in this column reflect the vesting and payout of performance-based restricted unit awards granted in January 2007 and for Mr. Murphy in April 2007 under the LTIP, and the Partnership’s level of attainment of certain performance goals over the three-year performance period running from January 1, 2007 through December 31, 2009. The number of units shown in the table reflects a payout percentage of 200 percent, applicable to the actual level of achievement of certain specified performance goals (based upon annual objectives for growth in cash flow per common unit, and total unitholder return ranked against peers) during the performance period. The value upon vesting was determined by multiplying (i) the product of the target number of such restricted units and the applicable performance factor (200 percent) at the end of the performance period; by (ii) the closing market price of our common units on the last trading day before the units were paid out ($64.88), and then adding the cumulative cash value of earned distribution equivalents. The performance measures for these awards were growth in operating cash flow, and total unitholder return during the performance period.

⁽³⁾

Amounts shown in this column include the following amounts paid out in respect of the earned cumulative distribution equivalents on the restricted units:


Name	Value of Cumulative Distribution Equivalents Realized Upon Vesting ($)
D. M. Fretz	$	287,348
N.E. Murphy	$	74,733
B. D. Davis, Jr.	$	57,252
D. A. Justin	$	66,090
C.W. Keene	$	40,757

⁽⁴⁾

For Mr. Murphy, the amount shown is the number of restricted units earned upon vesting of his special restricted unit award, granted in April 2007, in connection with his hiring, at 100% of value, the payout

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of which was conditioned only upon his continued employment through the final of three incremental restriction periods, running from January 1, 2009 through December 31, 2009, and the related cumulative distribution equivalents.

⁽⁵⁾

For Mr. Keene, the amount shown is the number of restricted units earned upon vesting of his special restricted unit award, granted in January 2007, and paid out in cash at 100% of value on May 28, 2009 along with the related cumulative distribution equivalents. The value upon vesting was determined by multiplying the number of such restricted units by the closing market price of our common units on the last trading day before the units were paid out ($50.96), and then adding the cumulative cash value of earned distribution equivalents.

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PENSION BENEFITS

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


Name	Plan	Number of Years Credited Service⁽¹⁾ (#)	Present Value of Accumulated Benefit⁽²⁾ ($)	Payments During Last Fiscal Year ($)
D. M. Fretz	SCIRP	32.84	1,490,736	0
President and Chief Executive Officer	Pension Restoration	32.84	6,058,700	0
	SERP	32.84	0	0
N.E. Murphy	SCIRP	2.73	65,330	0
Vice President and Chief Financial Officer	Pension Restoration	2.73	63,715	0
	SERP	Not applicable	Not applicable	0
M.J. Hennigan	SCRIP	28.76	840,772	0
Vice President, Business Development	Pension Restoration	28.76	1,676,411	0
	SERP	28.76	0	0
B. D. Davis, Jr.	SCIRP	6.14	147,752	0
Vice President, General Counsel and Secretary	Pension Restoration	6.14	96,862	0
	SERP	Not applicable	Not applicable	0
D. A. Justin	SCIRP	24.25	527,529	0
Vice President, Operations	Pension Restoration	24.25	146,661	0
	SERP	24.25	1,372,453	0
C. W. Keene⁽³⁾	SCIRP	4.97	0	103,867
Former Vice President, Business Development	Pension Restoration	4.97	0	98,251
	SERP	Not applicable	Not applicable	0

NOTES TO TABLE:

⁽¹⁾

Credited years of service reflect actual service with the general partner, including years of service credited with Sunoco, Inc., prior to the Partnership’s initial public offering in February 2002.

⁽²⁾

An actuarial present value of the benefits is calculated by estimating expected future payments starting at an assumed retirement age, weighting the estimated payments by the estimated probability of surviving to each post-retirement age, and discounting weighted payments at an assumed discount rate to reflect the time value of money. The actuarial present value represents an estimate of the amount which, if invested as of December 31, 2009 at a discount rate of 5.50%, would be sufficient on an average basis to provide estimated future payments based on the current accumulated benefit. Estimated future payments are assumed to be in the form of a single lump sum payment at retirement determined using interest rate and mortality table assumptions applicable under current IRS regulations for qualified pension plans. The conversion interest rate[s] assumed for lump sum payments are based on three segment rates under the Pension Protection Act and the lump sum mortality table is derived from IRS regulations. In addition, the value of the lump sum payment includes the estimated value of the 50% postretirement death benefit payable to the spouse of a retired participant under the SERP and Final Average Pay formula benefits described below, if married. It is assumed that 90% of all male

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members are married and 60% of females are married, with wives assumed to be 3 years younger than husbands. The assumed retirement age for each executive is the earliest age at which the executive could retire without any benefit reduction due to age. For NEOs, the assumed retirement age is 60 (i.e., the earliest age at which the executive could retire without any benefit reduction due to age), or actual age, if older than 60. Actual benefit present values will vary from these estimates depending on many factors, including an executive’s actual retirement age, final service, future compensation levels, interest rate movements and regulatory changes.

⁽³⁾

Mr. Keene departed from the Partnership in May 2009. His benefits were paid out in accordance with IRC Section 409A prior to December 31, 2009.

The Sunoco, Inc. Retirement Plan

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

(1)

Final Average Pay formula

•

Benefit equals 1-²/3 percent of Final Average Pay (the average earnings during the 36 consecutive months of highest earnings in the last ten years prior to retirement) multiplied by the credited service up to 30 years, plus ³/4 percent of final average pay multiplied by the credited service over 30 years.

•

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

•

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

(2)

Career Pay (cash balance) formula

•

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

•

Pay credits equal 7 percent of pay for the year up to the Social Security (FICA) Wage Base, ($106,800 in 2009) plus 12 percent of pay for the year that exceeds the Wage Base.

•

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

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

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

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value of the employee’s account, and under the Final Average Pay formula, the lump sum is the actuarial equivalent of the annuity benefit, based on Internal Revenue Service prescribed interest rates and mortality tables.

The SCIRP is subject to qualified plan Internal Revenue Code (the “Code”) limits on the amount of annual benefit that may be paid, and on the amount of compensation that may be taken into account in calculating retirement benefits, under the plan. For 2009, the limit on the compensation that may be used was $245,000, and will remain at $245,000 for 2010. The limit on annual benefits payable for an employee retiring in 2009 was $195,000, and will remain at $195,000 for 2010. Benefits in excess of those permitted under the statutory limits are paid from the Pension Restoration Plan, described below.

The amounts presented in the table above are actuarial present values based on accrued annual benefits, using pay and service through December 31, 2009. If the benefit is paid in a lump sum, the actual amount distributed would vary depending on the actual interest rate and the mortality assumptions used to calculate the distribution at the time of retirement. The mortality table and interest rates to be used in determining a lump sum have changed beginning in 2008 under the Pension Protection Act of 2006, or PPA. Under the PPA, the method for computing the lump sum interest rate is being phased in 20% annually through 2012. The effect of this change is expected to reduce lump sum amounts in the future. The estimated amounts above do not take into account future credited service, potential future changes in base salary, the annual guideline incentive opportunity, or future annual incentives that may be paid as a result of Company performance.

Pension Restoration Plan

The Pension Restoration Plan is a non-qualified plan that provides retirement benefits that would be provided under the SCIRP, but are prohibited from being paid from the SCIRP by the Code limits. (See the discussion regarding the SCIRP above for the limits.) The benefit paid by the Pension Restoration Plan is the excess of the total benefit accrued under the SCIRP over the amount of benefit that the SCIRP is permitted to provide under the Code. All benefits under the Pension Restoration Plan that are paid in a lump sum are calculated using the same actuarial factors applicable under the SCIRP. Payment of benefits is made upon termination of employment, except that payment of amounts subject to Code Section 409A is delayed until six months after separation from service for any specified employee as defined under Code Section 409A.

Sunoco, Inc. Executive Retirement Plan

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

For Mr. Justin, the SERP benefit (before offset by the SCIRP and Pension Restoration Plan benefits) equals the highest benefit resulting from three calculations:

(1)

SCIRP Final Average Pay formula (described on page 122).

(2)

Minimum Benefit formula

•

The benefit equals 3-¹/3% of final average pay multiplied by credited service up to 12 years, with the maximum benefit under this formula equal to 40 percent of final average pay.

•

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

•

The minimum benefit is offset by the value of benefits paid by a prior employer’s qualified and non-qualified retirement plans.

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(3)

Executive Service formula

•

The benefit equals 2-¹/4 percent of final average pay multiplied by length of executive service, with the maximum benefit under this formula equal to 50 percent of final average pay.

•

The executive service benefit is reduced by ⁵/12 percent for each month that retirement precedes age 62 (down to age 55), with the early retirement benefit at age 55 being 65 percent of the unreduced executive service benefit. There is no reduction when payments start at age 62 or later.

•

Executive service means service with the Partnership’s general partner while the participant was an executive level employee. In the case of principal officers who become participants after December 31, 2002, executive service includes only service while a principal officer.

SERP benefits that are paid in a lump sum are calculated using the same actuarial factors applicable under the SCIRP, with payment delayed until six months after separation from service, pursuant to Code Section 409A for any specified employee as defined in Code Section 409A. The two non-qualified plans are unfunded. The benefits from the non-qualified plans are paid from general assets that are subject to the claims of our general creditors under federal and state law in the event of insolvency.

NONQUALIFIED DEFERRED COMPENSATION

The following table includes deferred compensation provided to the CEO, CFO and each of the three other most highly compensated executive officers of our general partner, and one former executive officer under the Sunoco, Inc. Savings Restoration Plan in 2009. Each NEO may participate in the Sunoco, Inc. Savings Restoration Plan, a nonqualified plan that is made available to employees who participate in SunCAP (Sunoco, Inc.’s 401(k) plan) and who may be subject to compensation limitations and/or a contributions limitation under SunCAP pursuant to the Internal Revenue Code. Under this plan, the participant may contribute to an account in excess of the applicable limits. The executive’s contributions and our general partner’s matching contributions are credited to the extent they would be credited under SunCAP. The investment funds available under the Savings Restoration Plan are the same as those available to all employees participating in SunCAP and the executive receives earnings, depending on the fund the contributions are allocated to, which are calculated in the same matter and at the same rate of earnings as for all other employees invested in those funds in the SunCAP.

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


Name	Source	Executive Contributions in 2009 ($)		Registrant Contributions in 2009 ($)			Aggregate Earnings in 2009 ⁽²⁾ ($)			Aggregate Withdrawals/ Distributions ($)		Aggregate Balance at December 31, 2009 ($)
D. M. Fretz	Savings Restoration Plan	$	14,467	$	14,467	⁽¹⁾	$	46,837	⁽²⁾	—		$	327,760
N.E. Murphy	Savings Restoration Plan		3,056		3,056	⁽¹⁾		2,445	⁽²⁾	—			16,231
M.J. Hennigan	Savings Restoration Plan		9,376		9,376	⁽¹⁾		11,190	⁽²⁾	—			60,839
	Financial Counseling		—		—			—		—			4,500	⁽³⁾
B. D. Davis, Jr.	Savings Restoration Plan		2,237		2,237	⁽¹⁾		1,350	⁽²⁾	—			11,140
D. A. Justin	Savings Restoration Plan		1,843		1,843	⁽¹⁾		145	⁽²⁾	—			7,700
	Financial Counseling		—		—			—		—			3,000	⁽³⁾
C.W. Keene	Savings Restoration Plan		—		—			3,826	⁽²⁾	8,737	⁽⁴⁾		—

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⁽¹⁾

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

⁽²⁾

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

⁽³⁾

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

⁽⁴⁾

This amount reflects the distribution payable to Mr. Keene subsequent to his termination of employment in May 2009 and paid in accordance IRC Section 409A prior to December 31, 2009.

OTHER POTENTIAL POST-EMPLOYMENT PAYMENTS

Certain plans, described below, provide for payments of benefits to the NEOs in connection with termination, or separation from employment, or a change in control of our general partner, or in some cases, Sunoco, Inc. The following describes the benefits that the NEOs would receive if such an event occurred. The actual amounts paid can be determined only at the time of such NEO’s separation from employment with our general partner. Mr. Keene departed from the Partnership in May 2009 and the amounts paid to him with respect to his termination of employment can be found in the Summary Compensation Table on page 113, the Pension Benefits Table on page 121 and the Nonqualified Deferred Compensation Table on page 124,

Retirement: The benefits paid to the NEOs upon retirement are described above, on pages 121-124.

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

•

Sunoco, Inc. Retirement Plan (the “SCIRP”): Retirement eligible NEOs hired prior to January 1, 1987 (Ms. Fretz and Mr. Hennigan) would receive benefits based upon the Final Average Pay formula of the SCIRP, which is a qualified defined benefit retirement plan. Effective January 1, 1987, for employees hired subsequent to that date, the SCIRP was converted from a final average pay plan to a cash balance pension plan. SCIRP benefits for NEOs hired after this conversion (Messrs. Davis, Justin, Keene and Murphy) are calculated using the Career Pay formula, based on a percentage of pay each year and an indexing adjustment. Normal retirement age under the SCIRP is 65 years. To the extent that the amount payable exceeds the amount available under the SCIRP, the remaining amount would be paid under the Pension Restoration Plan.

•

Sunoco, Inc. Executive Retirement Plan (the “SERP”): The SERP provides pension benefits over and above benefits available under the SCIRP to participants who are at least 55 years of age, with a minimum of five (5) years service as an executive. SERP benefits are offset by benefits payable under other qualified or non-qualified plans of Sunoco, Inc. The maximum benefit payable under any SERP formula cannot exceed 50 percent of final average earnings. Under the terms of the SERP, only Mr. Justin would be eligible to receive benefits under this plan.

•

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

•

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

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•

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

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

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

•

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

•

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

•

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

Involuntary Termination—Not for Cause:

•

Sunoco Partners LLC Executive Involuntary Severance Plan (“Involuntary Severance Plan”): Executives whose employment is terminated by the Partnership’s general partner, other than for just cause, or as a result of death or disability, receive a severance allowance under the Involuntary Severance Plan. The plan is available to the general partner’s NEOs and certain other executive level employees. However, any NEO receiving benefits under the SERP would not also be eligible to receive benefits under this plan. The following is a summary of the benefits available under this plan:

•

In the case of the CEO, severance payments would be for a period of and equal to one and one half (1-¹/2) years of base salary, plus guideline annual incentive in effect on the termination date, as defined in the plan.

•

The other NEOs would receive severance payments for periods ranging from one (1) to one and one-half (1-¹/2) years of base salary plus guideline, depending upon employment grade level.

•

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

•

If an NEO is not retirement eligible, outstanding performance-based restricted units would be cancelled as of the termination date. If the NEO is eligible for retirement, unvested restricted units would continue to vest, and would pay out, along with the accompanying distribution equivalent rights, if the performance measures are met.

•

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

•

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

•

SERP: SERP benefits are offset by benefits payable under the SCIRP and Pension Restoration Plan. Under the terms of the SERP, only Mr. Justin would be eligible to receive benefits under this plan.

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Involuntary Termination—Change of Control

•

Sunoco Partners LLC Special Executive Severance Plan: This plan was adopted to retain executives in the event of a change of control, and to eliminate the distraction and uncertainty such a transaction may create among management personnel, to the detriment of the organization. Payment of severance benefits under this plan provides severance allowances to executives whose employment is terminated in connection with, or following, a change of control. A “change of control” is defined as any one or more of the following events:

•

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

•

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

•

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

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

•

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

•

the greater of 100 percent of the executive’s annual incentive guideline in effect immediately before the change of control or employment termination date, or the highest annual incentive awarded to the NEO in any of the three years ending before the change of control or in any subsequent year ending before the employment termination date.

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

•

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

•

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

•

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

127

•

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

•

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

•

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

•

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

Change of Control—Regardless of Termination

•

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

•

LTIP: If a change of control occurs, (a “single trigger”) all outstanding restricted units, along with the accompanying distribution equivalent rights, become fully vested. The units that have been outstanding for more than one year will be paid out at the greater of target or in amount in line with actual performance results. The units that have been outstanding for less than one year will be paid out at target. Retention-based units will be paid out at as awarded.

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

•

Insurance:

•

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

•

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

•

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

•

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

•

SCIRP:

•

For an NEO who is eligible for Final Average Pay formula benefits under SCIRP (Ms. Fretz and Mr. Hennigan): A married NEO’s spouse would receive the greater of 50 percent of the benefit under the Final Average Pay formula or 100 percent of the benefit accrued under the Career Earnings Formula. A non-married NEO’s beneficiary(ies) or estate would receive 100 percent of the benefit accrued under the Career Earnings Formula. This benefit is the same for all similarly situated employees.

128

•

For an NEO that is eligible for Career Pay Formula benefits only under SCIRP (Messrs. Davis, Keene, Justin and Murphy): A married or non-married NEO’s spouse, beneficiary(ies) or estate would receive 100 percent of the benefit accrued under the Career Earnings Formula. This benefit is the same for all similarly situated employees.

•

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

•

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

•

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

•

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

Disability: In the case of disability, an NEO would be eligible for the following benefits:

•

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

•

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

•

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

•

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

•

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

The following table reflects estimated compensation and benefits for the NEOs under various scenarios involving a termination of employment. These amounts are estimates of the amounts that would be paid to the NEOs and the actual amounts paid can only be determined at the time of a named executive officer’s termination of employment. The estimates are based on the following assumptions:

•

the applicable provisions in the agreements and arrangements governing the NEOs’ benefits and payment which are summarized in the “Other Potential Post-Employment Payments” section on pages 125 to 129;

•

the triggering event occurred on December 31, 2009;

•

the price of the Partnership’s stock is the price at the close on December 31, 2009 ($66.89);

•

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

•

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

•

each NEO has exhausted all available vacation benefits as of December 31, 2009.

129


Name	Voluntary Resignation		Involuntary Not for Cause Termination		Involuntary Termination— Change in Control
D.M. Fretz President and Chief Executive Officer	$	16,914,228	$	18,324,842	$	20,763,363

N.E. Murphy Vice President and Chief Financial Officer		1,183,083		1,882,108		3,595,061

M.J. Hennigan Vice President, Business Development		2,844,609		4,198,060		5,419,257

B.D. Davis, Jr. Vice President, General Counsel and Secretary		976,907		1,409,699		3,032,493

D.A. Justin Vice President, Operations		4,198,834		4,808,897		5,343,474

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DIRECTOR COMPENSATION

Directors, who are employees of Sunoco Partners LLC, Sunoco, and their respective affiliates, including the CEO, receive no additional compensation for service on the general partner’s Board of Directors or any committees of the Board.

Compensation Philosophy: The general partner’s Board of Directors believes that the compensation program for the non-employee directors should be designed to attract experienced and highly qualified individuals; provide appropriate compensation for their commitment and contributions to us and our unitholders; and align the interests of the non-employee directors and unitholders. The general partner’s Board of Directors engages a third-party compensation consultant to benchmark director compensation against our LTIP Peer Group, other pipeline companies, and general industry. For 2009, the Board of Directors engaged a consultant from Fredrick W. Cook, Inc. & Co. This director compensation consultant provides advice regarding “best practices” and trends in director compensation. Non-employee directors are compensated partly in cash and partly in common units, representing limited partnership interests in us. Currently, equity-based compensation represents a substantial portion of the total compensation package.

Retainers and Fees: During 2009, each non-employee director received an annual retainer of $41,000 in cash, paid quarterly, and a number of restricted units, paid quarterly, under the Sunoco Partners LLC Long-Term Incentive Plan. These restricted units had an aggregate fair market value equal to $41,000 on an annual basis (the fair market value of each quarterly payment of restricted units is calculated as of the payment date). These restricted units are required to be deferred, and are credited to each non-employee director’s mandatory deferred compensation account in the Directors’ Deferred Compensation Plan. Amounts thus deferred in the form of restricted units are treated as if invested in common units of the Partnership, and include a credit for distribution equivalent rights (in the form of additional restricted units), credited on the applicable date(s) for Partnership cash distributions. During 2009, the chairman of the Audit/Conflicts Committee received an annual committee chair retainer of $8,000 in cash, and the chairman of the Compensation Committee received an annual chair retainer of $3,500 in cash. In addition, the non-employee directors received fees of $1,500 in cash for each Board meeting attended, and $1,000 in cash for each committee meeting attended.

Directors’ Deferred Compensation Plan: Directors are permitted voluntarily to defer all or a portion of their cash retainers and fees under the Sunoco Partners LLC Directors’ Deferred Compensation Plan. Voluntarily deferred cash compensation amounts are credited in the form of restricted units, the value of which varies as though invested in our common units. Amounts voluntarily deferred in the form of restricted units also are credited with distribution equivalent rights (in the form of additional restricted units), on the applicable date(s) for our cash distributions. Payments of compensation deferred under the Directors’ Deferred Compensation Plan are restricted in terms of the earliest and latest dates that payments may begin. All deferrals, whether mandatory or voluntary, will be paid out in cash.

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

Directors’ Unit Ownership Guidelines: Each non-employee director is expected to own common units, representing limited partnership interests in us, with a market value equal to at least three times the total (cash and restricted unit) annual retainer and Board /committee meeting fees. Directors who do not meet the criteria for independence established by the New York Stock Exchange and pursuant to our corporate governance guidelines must own at least one thousand (1,000) of our common units. Included in the determination of unit ownership for purposes of these guidelines are all common units beneficially owned, as well as any restricted units in the Directors’ Deferred Compensation Plan. New directors are allowed a five-year phase-in period to comply with the guidelines.

131

Indemnification: Each director will be indemnified fully by us for actions associated with being a director to the extent permitted under Delaware law.

The following table reflects the compensation earned by each of the non-employee directors of our general partner during 2009:


Name	Fees Earned or Paid in Cash⁽¹⁾⁽⁶⁾ ($)	Stock Awards⁽²⁾ ($)	Option Awards⁽³⁾ ($)	Non-Equity Incentive Plan Compensation ($)	Change in Pension Value and Nonqualified Deferred Compensation Earnings	All Other Compensation⁽⁴⁾ ($)	Total ($)
L.W. Berry, Jr⁽⁵⁾. Non-employee Director	71,500	41,000	—	—	—	29,891	142,391

S.L. Cropper⁽⁵⁾ Non-employee Director	65,500	41,000	—	—	—	16,888	123,388

P.L. Frederickson Non-employee Director	63,500	41,000	—	—	—	6,648	111,148

NOTES TO TABLE:

⁽¹⁾

The amounts shown in this column include: the 2009 annual cash retainer for outside directors (totaling $41,000 for Messrs. Berry, Cropper and Frederickson ); regular and special Board meeting fees (totaling $10,500 for Messrs. Berry and Frederickson, $9,000 for Mr. Cropper), committee meeting fees (totaling $12,000 for Messrs. Berry, Cropper and Frederickson) and, as applicable, committee chair retainers ($8,000 for the Audit/Conflicts Committee and $3,500 for the Compensation Committee). Pursuant to the Sunoco Partners LLC Directors’ Deferred Compensation Plan, the directors are permitted voluntarily to defer, all or a portion of their fees and/or retainers. These amounts are deferred in the form of restricted units. As of December 31, 2009, the following directors had the following aggregate numbers of restricted units accumulated in their respective voluntary deferred compensation accounts for their years of service (these figures include distribution equivalents credited to such accounts in the form of additional restricted units):


• L. W. Berry, Jr.:		3,708
• P.L. Frederickson:		734

⁽²⁾

The amounts shown in this column reflect the dollar value of the portion of the annual retainer that is paid quarterly, in the form of restricted units issued pursuant to the Sunoco Partners LLC Long-Term Incentive Plan (“LTIP”) during 2009. For each director, this restricted unit retainer is automatically and mandatorily deferred, in accordance with terms of the Sunoco Partners LLC Directors’ Deferred Compensation Plan. As of December 31, 2009, these directors had the following aggregate numbers of restricted units accumulated in their respective mandatory deferred compensation accounts as a result of the involuntary deferrals of the restricted unit retainer for their years of service (these figures include distribution equivalents credited to such accounts in the form of additional restricted units):


• L. W. Berry, Jr.:		4,327
• S. L. Cropper:		4,725
• P.L. Frederickson :		1,812

⁽³⁾

Although permitted by the terms of the LTIP, no Unit Options have been awarded to directors at this time.

⁽⁴⁾

Amounts shown in this column reflect distribution equivalents earned on deferred compensation during 2009.

⁽⁵⁾

In 2009, Mr. Berry was Chair of the Audit/Conflicts Committee. In 2009, Mr. Cropper was Chair of the Compensation Committee.

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⁽⁶⁾

As members of the Conflicts Committee, the independent directors met multiple times in 2009 to review the incentive distribution rights repurchase transaction between the general partner and the Partnership that was completed on January 26, 2010. The fees earned for these meetings have not been included herein, and will be paid to the directors in 2010.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

There are no Compensation Committee interlocks.

COMPENSATION COMMITTEE REPORT

The Compensation Committee (the “Committee”) of the Board of Directors of Sunoco Partners LLC (the “Company”) reviews and approves the Company’s executive compensation philosophy; reviews and recommends to the Board for approval the Company’s short- and long-term compensation plans; reviews and approves the executive compensation programs and awards; and annually reviews, determines and approves the compensation for the Chief Executive Officer (“CEO”) and the other executive officers (collectively, the “Named Executive Officers” or “NEOs”) of the Company named in the Summary Compensation Table contained in the Annual Report on SEC Form 10-K of Sunoco Logistics Partners L.P. (the “Partnership”). The Company is the general partner of the Partnership. The Committee Chair reports Committee actions, decisions and recommendations at the meetings of the full Board. The Committee has authority to directly engage and consult outside advisors, experts and others to assist the Committee at the expense of the Partnership.

As required by applicable regulations of the Securities and Exchange Commission, the Committee has reviewed the executive compensation disclosures contained in the report captioned “Compensation Discussion and Analysis,” which report is required pursuant to Item 402(b) of SEC Regulation S-K, as amended. As part of this review, the Committee met with management and with such outside consultants and experts as it has deemed necessary or advisable (with and without management present), to discuss the scope and overall quality of the disclosure.

In reliance on the reviews and discussions referred to above, the Committee recommended to the Board of Directors, and the Board has approved, the inclusion of the “Compensation Discussion and Analysis” in the Partnership’s Annual Report on SEC Form 10-K for the fiscal year ended December 31, 2009, for filing with the Securities and Exchange Commission.

Respectfully submitted on February 23, 2010 by the members of the Compensation Committee of the Board of Directors of Sunoco Partners LLC:

L. Wilson Berry, Jr.

Stephen L. Cropper (Chair)

Lynn L. Elsenhans

Philip L. Frederickson

133

AUDIT COMMITTEE REPORT

The Audit Committee (the “Committee”) of the Board of Directors of Sunoco Partners LLC (the “Company”) reviews the Partnership’s financial reporting process on behalf of the Board of Directors of the Company. The Company is the general partner of the Partnership. Our management is responsible for the financial statements and the reporting process, including the internal control over financial reporting. The independent registered public accounting firm is responsible for expressing an opinion on the conformity of the audited financial statements with U.S. generally accepted accounting principles, and an opinion on the effectiveness of our internal control over financial reporting. The Committee monitors and oversees these processes.

The Committee discussed with our internal audit department and independent registered public accounting firm the overall scope and plans for their respective audits. In addition, the Committee has reviewed and discussed the audited financial statements and management’s and the independent registered public accounting firm’s evaluations of the Partnership’s system of internal control over financial reporting contained in the 2009 Annual Report on Form 10-K. As part of this review, the Committee met with the General Auditor and the independent registered public accounting firm, with and without management present, to discuss the results of their audits and the overall quality of the Partnership’s financial reporting.

As required by the standards of the Public Company Accounting Oversight Board, the Committee has discussed with the independent registered public accounting firm (1) the matters specified in Statement on Auditing Standards No. 61, “Communication with Audit Committees,” (Codification of Statements of Auditing Standards, August 2, 2007 AU 380), as amended, as adopted by the Public Company Accounting Oversight Board in Rule 3200T; and (2) the independence of the independent registered public accounting firm from the Partnership and management. The independent registered public accounting firm has provided the Committee the written disclosures and letter concerning independence, pursuant to applicable requirements of the Public Company Accounting Oversight Board. The Committee also considered the compatibility of non-audit services with the independent registered public accounting firm’s independence.

In reliance on the reviews and discussions referred to above, the Committee recommended to the Board of Directors, and the Board has approved, the inclusion of the audited financial statements and management’s report on internal control over financial reporting in the Partnership’s Annual Report on Form 10-K for the fiscal year ended December 31, 2009, for filing with the Securities and Exchange Commission.

Respectfully submitted on February 23, 2010 by the members of the Audit Committee of the Board of Directors of Sunoco Partners LLC:

L. Wilson Berry, Jr. (Chair)

Stephen L. Cropper

Philip L. Frederickson

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ITEM 12.

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

Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides information, as of December 31, 2009, regarding our common units that may be issued upon conversion (assuming a one-for-one conversion) of outstanding restricted units granted under the general partner’s Long-Term Incentive Plan to executive officers, directors, and other key employees. For more information about this plan (which did not require approval by our limited partners at the time of its adoption in 2002), refer to “Item 11—Executive Compensation.”

EQUITY COMPENSATION PLAN INFORMATION⁽¹⁾


Plan Category	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights	(b) Weighted-average exercise price of outstanding options, warrants and rights	(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders	—	—	—
Equity compensation plans not approved by security holders	409,002	—	403,167

Total	409,002	—	403,167

NOTES TO TABLE:

⁽¹⁾

The amounts in column (a) of this table reflect only restricted units that have been granted under the Sunoco Partners LLC Long-Term Incentive Plan, since the inception of the Plan. No unit options have been granted. Each restricted unit shown in the table represents a right to receive (upon vesting and payout) a specified number of our common units. Vesting and payout may be conditioned upon achievement of pre-determined financial or other performance objectives for, or attainment of certain length of service goals with us and our affiliates. No value is shown in column (b) of the table, since the restricted units do not have an exercise, or “strike,” price. For illustrative purposes, a maximum payment (i.e., a 200 percent ratio) has been assumed for vesting and payout of performance-related grants, and a target payout (i.e., a 100 percent ratio) has been assumed for vesting and payout of grants conditioned only upon service.

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Beneficial Ownership Table

The following table sets forth the beneficial ownership of our common units by directors of Sunoco Partners LLC (the general partner), by each NEO and by all current directors and executive officers of Sunoco Partners LLC as a group as of December 31, 2009. Unless otherwise noted, each individual exercises sole voting or investment power over the Partnership common units shown in the table. For purposes of this table, beneficial ownership includes Partnership common units as to which the person has sole or shared voting or investment power, as well as: (a) those Partnership common units actually acquired by LTIP participants as a result of the vesting and payout on February 9, 2010 of performance-based restricted units awarded January 26, 2007 and April 20, 2007 and of time-based restricted units granted on April 20, 2007; and (b) any additional Partnership common units that a person has the right to acquire within 60 days of December 31, 2009, through the conversion of restricted units. During 2009, Sunoco Partners LLC was owned by the following members: Sun Pipe Line Company (67%); Sunoco, Inc. (R&M) (13%); and Atlantic Refining & Marketing Corp. (20%), each of which is a direct or indirect wholly-owned subsidiary of Sunoco, Inc.


Name of Beneficial Owner⁽¹⁾	Number of Common Units Beneficially Owned⁽¹⁾	Percentage of Common Units Beneficially Owned	Number of Restricted Units Owned⁽²⁾
Sunoco Partners LLC⁽³⁾	9,863,734	31.8	0
Lynn L. Elsenhans⁽⁴⁾	1,000	*	0
Deborah M. Fretz	102,112	*	0
Cynthia A. Archer	2,000	*	0
L. Wilson Berry, Jr.	0	*	8,035
Stephen L. Cropper	9,200	*	4,725
Bruce G. Fischer	5,000	*	0
Philip L. Frederickson	2,000	*	2,546
Brian P. MacDonald	0	*	0
Bruce D. Davis, Jr.	21,408	*	0
David A. Justin	27,180	*	0
Michael J. Hennigan	0	*	0
Neal E. Murphy	11,768	*	0
All directors and executive officers as a group (12 persons)	196,974

*	Less than 0.5 percent.

NOTES TO TABLE:

⁽¹⁾	The address of each beneficial owner named above is: 1818 Market Street, Suite 1500, Philadelphia, PA 19103.

⁽²⁾

The amounts shown in this column represent the balance, as of December 31, 2009, of restricted units credited to the respective deferred compensation accounts established for each independent director pursuant to the terms of the Sunoco Partners LLC Director’s Deferred Compensation Plan. These restricted units cannot be converted to our common units, and will be paid out in cash (as a lump sum or series of installments), commencing on: (1) the later of: (a) the first day of the calendar year following the date of separation from Board service, or (b) the first day following the six (6) month anniversary of separation from Board service; or (2) in the event of death, the later of: (a) the first day of the calendar year following the year of death, (b) the first day following the six (6) month anniversary of separation from Board service, or (c) the date that is thirty (30) days after the Participant’s death. In no event will payment be made within six (6) months of the compensation being earned or awarded. A portion of these restricted units, credited quarterly to each such director’s mandatory deferred compensation account, reflects payment of the applicable Board restricted unit retainer.

⁽³⁾

On February 5, 2010, Sunoco Partners LLC completed the sale of 2,200,000 common units of the Partnership in a registered public secondary offering. The number of units beneficially owned by Sunoco Partners LLC prior to the offering was 12,063,734. Sunoco, Inc. is the ultimate parent company of Sunoco Partners LLC and may, therefore, be deemed to beneficially own the units that are held by Sunoco Partners LLC.

⁽⁴⁾	Ms. Elsenhans has joint voting and investment power with respect to these shares.

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In addition to the foregoing, Tortoise Capital Advisors LLC, a Delaware limited liability company (“TCA”), filed a Schedule 13G on February 11, 2010, to report that, as of December 31, 2009, it had shared voting power over 1,920,683 common units of the Partnership, and beneficial ownership of, and shared dispositive power over, 2,104,368 common units of the Partnership, representing 6.8 percent of the total outstanding common units of the Partnership, as of that date.

The following table sets forth certain information regarding beneficial ownership of Sunoco, Inc.’s common stock, as of December 31, 2009, by directors of Sunoco Partners LLC, by each NEO and by all directors and executive officers of Sunoco Partners LLC as a group. Unless otherwise noted, each individual exercises sole voting or investment power over the shares of Sunoco, Inc. common stock shown in the table. For purposes of this table, beneficial ownership includes shares of Sunoco, Inc. common stock as to which the person has sole or shared voting or investment power and also any shares of Sunoco, Inc. common stock that such person has the right to acquire within 60 days of December 31, 2009, through the exercise of any option, warrant, or right.


Name of Beneficial Owner	Shares of Sunoco, Inc. Common Stock Beneficially Owned	Percentage of Sunoco, Inc. Common Stock Beneficially Owned
Lynn L. Elsenhans⁽¹⁾	121,133	*
Deborah M. Fretz	0	*
Cynthia A. Archer	5,179	*
L. Wilson Berry, Jr.	0	*
Stephen L. Cropper	4,000	*
Bruce G. Fischer	103,874	*
Philip L. Frederickson	0	*
Brian P. MacDonald	0	*
Bruce D. Davis, Jr.	32	*
Michael J. Hennigan⁽²⁾	68,173	*
David A. Justin	0	*
Neal E. Murphy	70	*
All directors and executive officers as a group (12 persons)	302,461

*	Less than 0.5 percent.

⁽¹⁾	Ms. Elsenhans has joint voting and investment power with respect to 28,000 of these shares.

⁽²⁾	Mr. Hennigan has joint voting and investment power with respect to 6,111 of these shares.

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

On February 5, 2010, our general partner, Sunoco Partners LLC, completed the sale of 2,200,000 common units of the Partnership in a registered public secondary offering. As of February 5, 2010 our general partner owns 9,863,734 common units, representing a 31.2 percent limited partner interest in us. In addition, the general partner owns a 2 percent general partner interest in us. The general partner’s ability to manage and operate us and its ownership of a 33.2 percent partnership interest effectively gives the general partner the ability to control us.

Distribution and Payments to the General Partner and Its Affiliates

The following table summarizes the distribution and payments made and to be made us to the general partner and its affiliates in connection with the ongoing operation and liquidation. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

137

Operational Stage

Payments to the general partner and its affiliates

We paid the general partner an administrative fee, $6.0 million for the year ended December 31, 2009, for the provision of various general and administrative services for our benefit. In addition, the general partner is entitled to reimbursement for all expenses it incurs on our behalf, including other general and administrative expenses. These reimbursable expenses include the salaries and the cost of employee benefits of employees of the general partner who provide services to us. The general partner has sole discretion in determining the amount of these expenses.

Removal or withdrawal of the general partner

If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests as provided in the Partnership Agreement.

Liquidation Stage

Liquidation

Upon liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.

Concurrently with the closing of the February 2002 IPO, we entered into several agreements with Sunoco, Inc. (R&M), and/or one or more of its affiliates. These agreements include the Omnibus Agreement, the Pipelines and Terminals Storage and Throughput Agreement (which expired in 2009), the Interrefinery Lease Agreement, an intellectual property license agreement, certain crude oil purchase and sale agreements, a treasury services agreement and other agreements, all of which are discussed in detail under “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Agreements with Sunoco R&M and Sunoco, Inc.”

Subsequent to the February 2002 IPO, we entered into other agreements with Sunoco, Inc., Sunoco R&M and the general partner, including various throughput agreements regarding certain recently acquired assets or improvements or expansions at existing assets not covered by the Pipelines and Terminals Storage and Throughput Agreement; the purchase agreements with Sunoco R&M to acquire the Eagle Point refinery logistics assets and an undivided interest in the Mesa Pipe Line system; and certain redemption and expense-sharing agreements with Sunoco, Inc. (and/or its affiliates) that were ancillary to our April 2004 and May 2005 offerings of common units for sale to the public. For further information on these agreements, please refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Agreements with Sunoco R&M and Sunoco, Inc.”

Approval and Review of Related Party Transactions

Our Partnership Agreement and the Omnibus Agreement each contain provisions for our Conflicts Committee, comprised of our general partner’s independent directors, to review transactions with Sunoco, Inc. In some cases review is required and in others it is at the discretion of our general partner. Generally, transactions with Sunoco, Inc. that are material to us are referred to the Conflicts Committee for review and approval. In determining materiality, our general partner evaluates several factors including, the term of the transaction, the capital investment required, and the revenues expected from the transaction.

138

With respect to other related party transactions, we have in place a Code of Business Conduct and Ethics that is applicable to all directors, officers and employees of the Partnership and its subsidiaries and affiliates, a Code of Ethics for Senior Officers of the Partnership and its subsidiaries and affiliates, and a Conflict of Interest Policy applicable to all directors, officers and employees of the Partnership and its subsidiaries and affiliates. Each of these policies requires the approval by a supervisor, officer, or the Board of Directors, prior to entering into any related party transaction that could present a potential conflict of interest. Each of the Partnership Agreement, Code of Business Conduct and Ethics, and Code of Ethics for Senior Officers is publicly available on our website.

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following table presents the aggregate fees for audit and other professional services by our independent registered public accounting firm, Ernst & Young LLP, for each of the last two fiscal years:


	For the Year Ended December 31,
Type of Fee	2008		2009
Audit Fees⁽¹⁾	$	1,393,000	$	1,066,000
Audit Related Fees		—		—
Tax Fees		—		—
All Other Fees		—		—

	$	1,393,000	$	1,066,000

NOTE TO TABLE:

⁽¹⁾

Audit fees consist of fees for the audit of the Partnership’s annual financial statements, review of financial statements included in the Partnership’s quarterly reports on Form 10-Q and review registration statements and issuance of comfort letters, consents and review of documents filed with the SEC. Audit fees also include the fees for the audit of the Partnership’s internal control as required by Section 404 of the Sarbanes-Oxley Act of 2002.

Each of the services listed above were approved by the Audit/Conflicts Committee of the general partner’s board of directors prior to their performance. All services rendered by Ernst & Young LLP, are performed pursuant to a written engagement letter with the general partner.

The Audit/Conflicts Committee of the general partner’s board of directors is responsible for pre-approving all audit services, and permitted non-audit services, to be performed by the independent registered public accounting firm for the Partnership, or its general partner. The Committee reviews the services to be performed to determine whether provision of such services potentially could impair the independence of the Partnership’s independent registered public accounting firm. The Committee’s approval procedures include reviewing a detailed budget for each particular service to be rendered, as well as a description of, and budgeted amounts for, specific categories of anticipated non-audit services. Pre-approval is generally granted for up to one year. Committee approval is required to exceed the budgeted amount for any particular category of services or to engage the independent registered public accounting firm for services not included in the budget. Additional services or specific engagements may be approved, on a case-by-case basis, prior to the independent registered public accounting firm undertaking such services.

Subject to the requirements of applicable law, the Audit/Conflicts Committee may delegate such pre-approval authority to the Audit/Conflicts Committee chairman. However, any pre-approvals granted by the chairman, acting pursuant to such delegated authority, are reviewed by the full membership of the Audit/Conflicts Committee at its next regular meeting. Management of the general partner provides periodic updates to the Audit/Conflicts Committee regarding the extent of any services provided in accordance with this pre-approval process, as well as the cumulative fees incurred to date for all non-audit services, to ensure that such services are within the parameters approved by the Audit/Conflicts Committee.

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PART IV

ITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) The following documents are filed as part of this report:

(1) The financial statements are included in Item 8. Financial Statements and Supplementary Data.

(2) All financial statement schedules required are included in the financial statements or notes thereto.

(3) Exhibits:


Exhibit No.		Description
2.1*		Purchase and Sale Agreement by and between Mobil Pipeline Company and Sunoco Pipeline L.P., executed May 6, 2005 (incorporated by reference to Exhibit 2.1 of Form 10-Q, file No. 1-31219, filed May 9, 2005)

2.1.1*		List of Schedules and Exhibits to Purchase and Sale Agreement omitted from this filing. Registrant hereby undertakes, pursuant to Regulation S-K Item 601(2) to furnish any such schedules and exhibits to the SEC supplementally, upon request (incorporated by reference to Exhibit 2.1.1 of Form 10-Q, file No. 1-31219, filed May 9, 2005)

2.2*		Sale and Purchase Agreement for Magtex Refined Products Pipeline System between Mobil Pipe Line Company and Sunoco Pipeline L.P., executed April 28, 2008 (incorporated by reference to Exhibit 2.1. of Form 10-Q, file No. 1-31219, filed August 6, 2008).

2.2.1*		List of Schedules and Exhibits to Sale and Purchase Agreement omitted from this filing. Registrant hereby undertakes, pursuant to Regulation S-K Item 601(2) to furnish any such schedules and exhibits to the SEC supplementally, upon request (incorporated by reference to Exhibit 2.1.1 of Form 10-Q, file No. 1-31219, filed August 6, 2008).

2.3*		Terminals Sale and Purchase Agreement for Center, TX, Hearne(East), TX, Waco, TX and Waskom, TX Terminals between ExxonMobil Oil Corporation and Sunoco Partners Marketing & Terminals L.P., executed April 28, 2008 (incorporated by reference to Exhibit 2.2 of Form 10-Q, file No. 1-31219, filed August 6, 2008).

2.3.1*		List of Schedules and Exhibits to Terminals and Purchase Agreement omitted from this filing. Registrant hereby undertakes, pursuant to Regulation S-K Item 601(2) to furnish any such schedules and exhibits to the SEC supplementally, upon request (incorporated by reference to Exhibit 2.2.1 of Form 10-Q, file No. 1-31219, filed August 6, 2008).

2.4*		Terminals Sale and Purchase Agreement for Arcadia, LA Terminal between Exxon Mobil Corporation and Sunoco Partners Marketing & Terminals L.P., executed April 28, 2008 (incorporated by reference to Exhibit 2.3 of Form 10-Q, file No. 1-31219, filed August 6, 2008).

2.4.1*		List of Schedules and Exhibits to Terminals and Purchase Agreement omitted from this filing. Registrant hereby undertakes, pursuant to Regulation S-K Item 601(2) to furnish any such schedules and exhibits to the SEC supplementally, upon request (incorporated by reference to Exhibit 2.3.1 of Form 10-Q, file No. 1-31219, filed August 6, 2008).

2.5*		Terminals Sale and Purchase Agreement for Hearne, TX (West) Terminal between Mobil Pipe Line Company and Sunoco Partners Marketing & Terminals L.P., executed April 28, 2008 (incorporated by reference to Exhibit 2.4 of Form 10-Q, file No. 1-31219, filed August 6, 2008).

2.5.1*		List of Schedules and Exhibits to Terminals and Purchase Agreement omitted from this filing. Registrant hereby undertakes, pursuant to Regulation S-K Item 601(2) to furnish any such schedules and exhibits to the SEC supplementally, upon request (incorporated by reference to Exhibit 2.4.1 of Form 10-Q, file No. 1-31219, filed August 6, 2008)

140


Exhibit No.		Description
3.1*		Certificate of Limited Partnership of Sunoco Logistics Partners L.P. (incorporated by reference to Exhibit 3.1 to Form S-1 Registration Statement, file No. 333-71968, filed October 22, 2001)

3.2*		Certificate of Limited Partnership of Sunoco Logistics Operations L.P. (incorporated by reference to Exhibit 3.1 to Amendment No. 1 to Form S-1 filed December 18, 2001)

3.3*		First Amended and Restated Agreement of Limited Partnership of Sunoco Logistics Partners Operations L.P., dated as of February 8, 2002 (incorporated by reference to Exhibit 3.5 of Form 10-K, file No. 1-31219, filed April 1, 2002)

3.4*		Third Amended and Restated Agreement of Limited Partnership of Sunoco Logistics Partners L.P., dated as of January 26, 2010 (incorporated by reference to Exhibit 3.1 of Sunoco Logistics Partners L.P.’s Current Report on Form 8-K, File No. 1-31219, filed January 28, 2010).

10.1*		Credit Agreement dated as of August 8, 2007, by and among Sunoco Logistics Partners Operations L.P., as Borrower; Sunoco Logistics Partners L.P., as Guarantor; Citibank, N.A., as Administrative Agent, Swingline Lender and L/C Issuer and the other lenders parties thereto (incorporated by reference to Exhibit 10.1 of Form 10-Q/A, file No. 1-31219, filed November 19, 2007)

10.2*		Indenture, dated as of February 7, 2002 (incorporated by reference to Exhibit 10.2 of Form 10-K, file No. 1-31219, filed April 1, 2002)

10.3*		Indenture, dated as of December 16, 2005 (incorporated by reference to Exhibit 4.4 of Registration Statement on Form S-3, File No. 333-130564, filed December 21, 2005)

10.4*		Registration Rights Agreement, dated as of February 8, 2002, among Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners L.P., Sunoco Pipeline L.P., Sunoco Partners Marketing & Terminals L.P., and the following Initial Purchasers: Lehman Brothers, Inc., Credit Suisse First Boston Corporation, Banc of America Securities LLC, Salomon Smith Barney Inc., UBS Warburg LLC and First Union Securities, Inc. (incorporated by reference to Exhibit 10.3 of Form 10-K, file No. 1-31219, filed April 1, 2002)

10.5*		Contribution, Conveyance and Assumption Agreement, dated as of February 8, 2002, among Sunoco, Inc., Sun Pipe Line Company of Delaware, Sunoco, Inc. (R&M), Atlantic Petroleum Corporation; Sunoco Texas Pipe Line Company, Sun Oil Line of Michigan (Out) LLC, Mid-Continent Pipe Line (Out) LLC, Sun Pipe Line Services (Out) LLC, Atlantic Petroleum Delaware Corporation, Atlantic Pipeline (Out) L.P., Sunoco Partners LLC, Sunoco Partners Lease Acquisition & Marketing LLC, Sunoco Logistics Partners L.P., Sunoco Logistics Partners GP LLC, Sunoco Pipeline L.P., Sunoco Partners Marketing & Terminals L.P., Sunoco Mid-Con (In) LLC, Atlantic (In) L.P., Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners Operations GP LLC, Atlantic R&M (In) L.P., Sun Pipe Line Services (In) L.P., Sunoco Michigan (In) LLC, Atlantic (In) LLC, Sunoco Logistics Pipe Line GP LLC, Sunoco R&M (In) LLC, and Atlantic Refining & Marketing Corp. (incorporated by reference to Exhibit 10.4 of Form 10-K, file No. 1-31219, filed April 1, 2002)

10.6*		Omnibus Agreement, dated as of February 8, 2002, by and among Sunoco, Inc., Sunoco, Inc. (R&M), Sunoco Logistics Pipe Line Company of Delaware, Atlantic Petroleum Corporation, Sunoco Texas Pipe Line Company, Sun Pipe Line Services (Out) LLC, Sunoco Logistics Partners L.P., Sunoco Logistics Partners Operations L.P., and Sunoco Partners LLC (incorporated by reference to Exhibit 10.5 of Form 10-K, file No. 1-31219, filed April 1, 2002)

10.6.1		Amendment No. 2010-1 to Omnibus Agreement, dated as of February 22, 2010, and effective January 1, 2010, by and among Sunoco, Inc., Sunoco, Inc. (R&M), Sun Pipe Line Company of Delaware LLC, Atlantic Petroleum Corporation, Sunoco Logistics Partners L.P., Sunoco Logistics Partners Operations L.P., Sunoco Pipeline L.P. and Sunoco Partners LLC

141


Exhibit No.		Description
10.7*		Amended and Restated Treasury Services Agreement, dated as of November 26, 2003, by and among Sunoco, Inc., Sunoco Logistics Partners L.P., and Sunoco Logistics Partners Operations L.P. (incorporated by reference to Exhibit 10.7.1 of Form 10-K, file No. 1-31219, filed March 4, 2004)

10.8*		Intellectual Property and Trademark License Agreement, dated as of February 8, 2002 among Sunoco, Inc., (“Sunoco”), Sunoco, Inc. (R&M), Sunmarks, Inc., Sunoco Logistics Partners L.P., Sunoco Logistics Partners Operations L.P., Sunoco Partners Marketing & Terminals L.P., Sunoco Pipeline L.P., and Sunoco Partners LLC (incorporated by reference to Exhibit 10.8 of Form 10-K, file No. 1-31219, filed April 1, 2002)

10.9*		Inter-refinery Lease, dated as of February 8, 2002, between Sunoco Pipeline L.P., and Sunoco, Inc. (R&M) (incorporated by reference to Exhibit 10.9 of Form 10-K, file No. 1-31219, filed April 1, 2002)

10.10*		Sunoco Partners LLC Executive Involuntary Severance Plan, as amended and restated as of January 23, 2008 (incorporated by reference to Exhibit 10.10 of Form 10-K, file No. 1-31219, filed February 26, 2008)

10.11*		Sunoco Partners LLC Long-Term Incentive Plan, as amended and restated as of October 20, 2007 (incorporated by reference to Exhibit 10.11 of Form 10-K, file No. 1-31219, filed February 26, 2008)

10.11.1*		Form of Restricted Unit Agreement under the Sunoco Partners LLC Long-Term Incentive Plan (incorporated by reference to Exhibit 10.11.1 of Form 10-K, file No. 1-31219, filed February 26, 2008)

10.11.2*		Form of Restricted Unit Agreement under the Sunoco Partners LLC Long-Term Incentive Plan (incorporated by reference to Exhibit 10.11.2 of Form 10-K, file No. 1-31219, filed February 26, 2008)

10.12*		Sunoco Partners LLC Annual Incentive Plan, as amended and restated as of January 28, 2009 (incorporated by reference to Exhibit 10.13 of Form 10-K, file No. 1-31219, filed February 24, 2009)
10.13*		Sunoco Partners LLC Directors’ Deferred Compensation Plan, as amended and restated as of October 20, 2007 (incorporated by reference to Exhibit 10.13 of Form 10-K, file No. 1-31219, filed February 26, 2008)

10.14*		Sunoco Partners LLC Special Executive Severance Plan, as amended and restated as of October 20, 2007 (incorporated by reference to Exhibit 10.14 of Form 10-K, file No. 1-31219, filed February 26, 2008)

10.15		Sunoco Partners LLC Executive Summary Compensation Sheet for 2010

10.16		Sunoco Partners LLC Independent Director Compensation Summary Sheet for 2010

10.17**		Throughput and Deficiency Agreement, executed May 6, 2005 (incorporated by reference to Exhibit 10.17 to Form 10-K, File No. 1-31219, filed February 23, 2007)

10.18*		Purchase and Sale Agreement, between Alon Petroleum Pipe Line, LP and Sunoco Pipeline L.P., dated as of February 13, 2006 (incorporated by reference to Exhibit 10.1 of Form 8-K, file No. 1-31219, filed February 16, 2006)

10.19***		Crude Oil Pipeline Throughput and Deficiency Agreement between Motiva Enterprises LLC and Sunoco Pipeline L.P., dated as of December 19, 2006 (incorporated by reference to Exhibit 10.19 of Form 10-K, file no. 1-31219, filed February 23, 2007)

142


Exhibit No.		Description
10.20***		Marine Dock and Terminaling Agreement between Motiva Enterprises LLC and Sunoco Partners Marketing & Terminals L.P., dated as of December 19, 2006 (incorporated by reference to Exhibit 10.20 of Form 10-K, file no. 1-31219, filed February 23, 2007)

10.21*		Membership Interest Purchase Agreement, effective as of July 27, 2006, between Sunoco, Inc. and Sunoco Pipeline Acquisition LLC (incorporated by reference to Exhibit 10.1 of Form 10-Q, file No. 1-31219, filed August 2, 2006)

10.22†		Product Terminal Services Agreement, dated as of May 1, 2007, among Sunoco, Inc. (R&M) and Sunoco Partners Marketing & Terminals L.P. (incorporated by reference to Exhibit 10.1 of Form 10-Q, file No. 1-31219, filed July 31, 2007)

10.23*		Repurchase Agreement between Sunoco Logistics Partners L.P. and Sunoco Partners LLC, dated January 26, 2010 (incorporated by reference to Exhibit 10.1 of Form 8-K, file No. 1-31219, filed January 28, 2010)

10.24*		Promissory Note between Sunoco Logistics Partners L.P. and Sunoco Partners LLC, dated January 26, 2010 (incorporated by reference to Exhibit 10.2 of Form 8-K, file No. 1-31219, filed January 28, 2010)

12.1		Statement of Computation of Ratio of Earnings to Fixed Charges

14.1*		Code of Ethics for Senior Officers (incorporated by reference to Exhibit 10.14.1 to Form 10-K, File No. 1-31219, filed March 4, 2004)

21.1		Subsidiaries of Sunoco Logistics Partners L.P.

23.1		Consent of Independent Registered Public Accounting Firm

24.1		Power of Attorney

31.1		Officer Certification Pursuant to Exchange Act Rule 13a-14(a)

31.2		Officer Certification Pursuant to Exchange Act Rule 13a-14(a)

32.1		Officer Certification Pursuant to Exchange Act Rule 13a-14(b) and 18 U.S.C. § 1350

99.1		Audited Balance Sheet of Sunoco Partners LLC as of December 31, 2009

*	Each such exhibit has heretofore been filed with the Securities and Exchange Commission as part of the filing indicated and is incorporated herein by reference.

**	Confidential status has been granted for certain portions of this exhibit pursuant to a Confidential Treatment Request filed May 9, 2005. Such provisions have been separately filed with the Commission.

***	Confidential status has been requested for certain portions thereof pursuant to a Confidential Treatment Request filed February 23, 2007. Such provisions have been separately filed with the Commission.

†	Confidential status has been requested for certain portions thereof pursuant to a Confidential Treatment Request filed July 31, 2007. Such provisions have been separately filed with the Commission.

143

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


Sunoco Logistics Partners L.P. (Registrant)

By:		Sunoco Partners LLC (its General Partner)

	By:	/S/ NEAL E. MURPHY
		Neal E. Murphy
		Vice President and Chief Financial Officer

February 23, 2010

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by or on behalf of the following persons on behalf of the registrant and in the capacities indicated on February 23, 2010.


CYNTHIA A. ARCHER*				PHILIP L. FREDERICKSON*
Cynthia A. Archer Director of Sunoco Partners LLC, General Partner of Sunoco Logistics Partners L.P.				Philip L. Frederickson Director of Sunoco Partners LLC, General Partner of Sunoco Logistics Partners L.P.

STEPHEN L. CROPPER* Stephen L. Cropper Director of Sunoco Partners LLC, General Partner of Sunoco Logistics Partners L.P.				MICHAEL D. GALTMAN* Michael D. Galtman Controller (Principal Accounting Officer)

BRIAN P. MACDONALD* Brian P. MacDonald Director of Sunoco Partners LLC, General Partner of Sunoco Logistics Partners L.P.				BRUCE G. FISCHER* Bruce G. Fischer Director of Sunoco Partners LLC, General Partner of Sunoco Logistics Partners L.P.

LYNN L. ELSENHANS* Lynn L. Elsenhans Director and Chairman of Sunoco Partners LLC, General Partner of Sunoco Logistics Partners L.P.				DEBORAH M. FRETZ* Deborah M. Fretz Chief Executive Officer and Director of Sunoco Partners LLC, General Partner of Sunoco Logistics Partners L.P. (Principal Executive Officer)

L. WILSON BERRY, JR.* L. Wilson Berry, Jr. Director of Sunoco Partners LLC, General Partner of Sunoco Logistics Partners L.P.

144

Year Ended December 31,

Total shipments (in thousands of barrel miles per day)⁽¹⁾