SEC Filing | Energy Transfer

Year Ended December 31,

Total shipments (in thousands of barrel miles per day)⁽¹⁾

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Sunoco Logistics Partners LP--Form 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 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;

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

•

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;

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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:

•

certain businesses 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, 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

•

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:

•

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

•

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

•

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

•

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

•

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

•

place us at a competitive disadvantage against less leveraged competitors.

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

As of December 31, 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”).

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. 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):