Edgar Filing: SUNOCO LOGISTICS PARTNERS L.P.

Year Ended December 31,

2008⁽¹⁾

Total shipments (in thousands of barrel miles per day)

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, 2008

¨	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.)

Mellon Bank Center 1735 Market Street, Suite LL, Philadelphia, PA		19103-7583
(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

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 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. ¨

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 $778.2 million as of June 30, 2008, based on $46.90 per unit, the closing price of the Common Units as reported on the New York Stock Exchange on that date.

At February 23, 2009, the number of the registrant’s Common Units outstanding was 28,728,432.

DOCUMENTS INCORPORATED BY REFERENCE: NONE

TABLE OF CONTENTS


PART I			3
	ITEM 1.	BUSINESS	3
	ITEM 1A.	RISK FACTORS	20
	ITEM 1B.	UNRESOLVED STAFF COMMENTS	32
	ITEM 2.	PROPERTIES	32
	ITEM 3.	LEGAL PROCEEDINGS	32
	ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS	32

PART II			33
	ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SECURITYHOLDER MATTERS AND PURCHASES OF EQUITY SECURITIES	33
	ITEM 6.	SELECTED FINANCIAL DATA	34
	ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	38
	ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	57
	ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	59
	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	133
	ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS	135
	ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	137

PART IV			138
	ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	138

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 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 concerning required composition of refined petroleum products, that result in changes in throughput volumes, pipeline tariffs and/or terminalling and storage fees;

•

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

•

Our ability to manage growth and/or control costs;

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

Risks related to labor relations and workplace safety;

•

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

•

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

•

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

•

Restrictive covenants in our or Sunoco’s credit agreements;

•

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

•

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

•

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

•

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

•

Claims of our non-compliance with regulatory and statutory requirements; 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 Mellon Bank Center, 1735 Market Street, Suite LL, Philadelphia, Pennsylvania 19103 (telephone (866) 248-4344). Our website address is www.sunocologistics.com.

Sunoco, Inc., and its wholly-owned subsidiaries including Sunoco, Inc. (R&M), own approximately 43.3 percent of our partnership interests at December 31, 2008, 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 25 percent of our total revenues for the year ended December 31, 2008. The business comprises three segments:

•

The Eastern Pipeline System serves the northeast and midwest United States operations of Sunoco and includes: approximately 1,650 miles of refined product pipelines, including a two-thirds undivided interest in the 80-mile refined product Harbor pipeline, and 58 miles of interrefinery pipelines between two of Sunoco’s refineries; approximately 140 miles of crude oil pipelines; a 9.4 percent interest in Explorer Pipeline Company, a joint venture that owns a 1,881-mile refined product pipeline; a 31.5 percent interest in Wolverine Pipe Line Company, a joint venture that owns a 721-mile refined product pipeline; a 12.3 percent interest in West Shore Pipe Line Company, a joint venture that owns a 652-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 Eastern Pipeline System also includes the MagTex refined product pipeline system which was acquired from an affiliate of Exxon Mobil Corporation, in November 2008. The system consists of approximately 480 miles of refined product pipelines located in Texas. Although these assets are physically located in the southwestern United States, we have included these assets in the Eastern Pipeline System along with our existing refined products pipelines.

•

The Terminal Facilities consist of 36 refined product terminals with an aggregate storage capacity of 6.2 million shell barrels, primarily serving our Eastern Pipeline System in the northeast and midwest United States; 5 refined product terminals located in Texas and Louisiana serving the MagTex refined product pipeline system with an aggregate storage capacity of 0.5 million shell barrels, the Nederland Terminal, a 17.1 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; a ship and barge dock which serves Sunoco’s Eagle Point refinery; and a 1.0 million barrel liquefied petroleum gas (“LPG”) terminal near Detroit, Michigan.

•

The Western Pipeline System gathers, purchases, sells, and transports crude oil principally in Oklahoma and Texas and consists of approximately 3,200 miles of crude oil trunk pipelines, including a 37.0 percent undivided interest in the 80-mile Mesa Pipe Line system, and approximately 500 miles of crude oil gathering lines that supply the trunk pipelines; approximately 110 crude oil transport trucks; approximately 120 crude oil truck unloading facilities; a 55.3 percent economic interest (50 percent voting interest) in the Mid-Valley Pipeline Company, a joint venture that owns a 994-mile crude pipeline and a 43.8 percent interest in West Texas Gulf Pipe Line Company, a joint venture that owns a 579-mile crude oil pipeline.

Revenues are generated by charging tariffs for transporting refined products, crude oil and other hydrocarbons through the pipelines and by charging fees for storing refined products, crude oil, and other hydrocarbons, and for providing other services at our terminals. We also generate revenue by purchasing domestic crude oil and selling it to our customers. Generally, as crude oil is purchased, corresponding sale transactions are simultaneously entered into involving physical deliveries of crude oil, which enables us to secure a profit on the transaction at the time of purchase and establish a substantially balanced position, thereby minimizing exposure to price volatility after the initial purchase. We do not enter into futures contracts or other derivative instruments in connection with these purchases and sales unless they result in the physical delivery of crude oil.

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 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, 2008, Sunoco accounted for approximately 66 percent of the Eastern Pipeline segment’s total revenues, approximately 61 percent of the Terminal Facilities segment’s total revenues, and approximately 24 percent of the Western Pipeline System segment’s total revenues.

Eastern Pipeline System

Refined Product Pipelines

We own and operate approximately 1,650 miles of refined product pipelines in the northeast and midwest United States. The refined product pipelines, located in the northeast and midwest, transport refined products from Sunoco’s Philadelphia and Marcus Hook, Pennsylvania, Toledo, Ohio and Eagle Point, New Jersey refineries, as well as from third party locations, to markets in New York, New Jersey, Pennsylvania, Ohio, and Michigan. The refined products transported in these pipelines include multiple grades of gasoline, middle distillates (such as heating oil, diesel and jet fuel), liquefied petroleum gas (“LPGs”) (such as propane and butane). The Federal Energy Regulatory Commission (“FERC”) regulates the rates for interstate shipments on the Eastern 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.

In addition, our refined product pipelines include the following assets acquired since December 31, 2005:

•

MagTex Refined Products Pipeline Acquisition. On November 18, 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 for $157.1 million, subject to certain adjustments 5 years following the date of closing, based on the throughput of certain customers. 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 product 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 Eastern 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 results from the MagTex refined products pipeline from the acquisition date.

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

Crude Oil Pipelines

The Eastern Pipeline system includes a 123-mile, 16-inch 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.

The table below sets forth the average number of barrels per day (“bpd”) of crude oil transported through this crude oil pipeline in each of the years presented:

Explorer Pipeline

We own a 9.4 percent interest in Explorer Pipeline Company (“Explorer”), a joint venture that owns a 1,881-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 721-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 652-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 Product Terminals

Our 41 refined product 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 product terminals include the following assets acquired since December 31, 2005:

•

MagTex Refined Products Terminals. On November 18, 2008, we acquired five refined products terminal facilities located in Texas and Louisiana from affiliates of Exxon Mobil Corporation for $28.3 million. Total active terminal storage capacity of these facilities is approximately 0.5 million shell barrels, which represents the design capacity of a petroleum storage tank.

•

Syracuse Terminal Acquisition. On June 1, 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 for approximately $13.4 million. Total terminal storage capacity is approximately 0.5 million shell barrels, which represents the design capacity of a petroleum storage tank.

Our refined product 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, including ethanol blending, injecting additives, and filtering jet fuel. Refined product terminals generate the balance of their revenues from the handling of other hydrocarbons. Our refined product pipelines, including the MagTex 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 results from the MagTex and Syracuse refined products terminals from the acquisition dates.

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


State	Number of Terminals	Storage Capacity
		(bbls)
Indiana	1	206,500
Maryland	1	714,000
Michigan	2	406,700
New Jersey	4	756,200
New York^(1,2)	4	915,800
Ohio	7	915,900
Pennsylvania	16	2,017,300
Virginia	1	276,900
Louisiana	1	160,500
Texas	4	370,100

Total	41	6,739,900

⁽¹⁾	We have a 45 percent ownership interest in a terminal at Inwood, New York. The storage capacity included in the table represents the proportionate share of capacity attributable to our ownership interest.

⁽²⁾	We have a 50 percent ownership interest in a terminal at Syracuse, New York. The storage capacity 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 that provides 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 17.1 million shell barrels in 138 aboveground storage tanks with individual capacities of up to 660,000 barrels. During 2008, we continued construction of eight new tanks including continued construction around our agreement with Motiva Enterprises LLC for three crude oil storage tanks at our Nederland Terminal and a crude oil pipeline from Nederland 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 pipeline from Louisiana, the Cameron Highway pipeline, 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. In the first quarter of 2006 ExxonMobil reversed the flow of crude oil on its Pegasus pipeline from Patoka, Illinois to the Nederland Terminal, which resulted in the flow of Canadian crude oil to the Nederland Terminal beginning in April 2006.

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 12 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. In December 2006, we executed an agreement with Motiva Enterprises LLC to construct three additional crude oil storage tanks, with a combined capacity of approximately 2.0 million shell barrels of storage capacity, and provide a new approximately 8 mile 30”crude oil pipeline connection from the Nederland Terminal to Motiva’s Port Arthur, Texas refinery. Construction of these assets is expected to be completed on or before January 2010.

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 2008 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. These assets include 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 tank capacity and 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 oil carrier-class 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,
	2006	2007	2008
Crude oil throughput (bpd)	305,539	296,976	284,813
Refined products throughput (bpd)	14,256	13,972	14,914

Total (bpd)	319,795	310,948	299,727

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, which supplies the Eastern 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 Dock

The Eagle Point Dock is located on the Delaware River and is connected to the Sunoco Eagle Point refinery. It can accommodate three ships or barges and supplies the Eagle Point refinery with all of its crude oil. The dock can also receive and deliver crude oil, intermediate products and refined products to outbound ships and barges.

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


	Year Ended December 31,
	2006	2007	2008
Crude oil throughput (bpd)	136,473	138,159	132.428
Refined products throughput (bpd)	80,448	100,649	93,433

Total (bpd)	216,921	238,808	225,861

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.

Western Pipeline System

Crude Oil Pipelines

We own and operate approximately 3,200 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 for Sunoco and other third parties from points in Texas and Oklahoma.

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 the Millennium and Kilgore crude oil pipelines and the Amdel and White Oil crude oil pipelines 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.

Our Texas crude oil pipeline system also includes the following assets acquired since December 31, 2005:

•

Millennium and Kilgore Pipeline Acquisition. On March 1, 2006, we purchased a Texas crude oil pipeline system from affiliates of Black Hills Energy, Inc. for approximately $40.9 million. The acquisition consists of (a) the Millennium Pipeline, a 200-mile, 12-inch crude oil pipeline with approximately 65,000 bpd operating capacity, originating near the Nederland Terminal, and terminating at Longview Texas; (b) the Kilgore Pipeline, a 190-mile, 10-inch crude oil pipeline with approximately 35,000 barrel per day capacity originating in Kilgore, Texas and terminating at the Oil Tanking terminal in the Houston, Texas region; (c) approximately 0.9 million barrels of shell storage capacity at Kilgore, and Longview, Texas, approximately 0.6 million of which were inactive; (d) a crude oil sales and marketing business; and (e) crude oil line fill and working inventory.

•

Amdel and White Oil Pipeline Acquisition. On March 1, 2006, we acquired a Texas crude oil pipeline system from Alon USA Energy, Inc. for approximately $68.0 million. The system consists of (a) the Amdel Pipeline, a 503-mile, 10-inch common carrier crude oil pipeline with approximately 27,000 bpd operating capacity, originating at the Nederland Terminal, and terminating at Midland, Texas, and (b) the White Oil Pipeline, a 25-mile, 10-inch crude oil pipeline with approximately 40,000 bpd operating capacity, originating at the Amdel Pipeline and terminating at Alon’s Big Spring, Texas refinery. Alon has agreed to ship a minimum of 15,000 bpd on the pipelines under a 10-year, throughput and deficiency agreement. The pipelines were idle at the time of purchase and were re-commissioned by the Partnership during the second quarter 2006. The pipelines began making deliveries during the fourth quarter 2006. During the first quarter of 2007, we completed a project to

expand the capacity on the Amdel Pipeline from approximately 27,000 to 40,000 bpd. We also completed construction of new tankage at the Nederland Terminal to service these new volumes more efficiently.

•

Mid-Valley Pipeline Acquisition. On August 18, 2006, we purchased from Sunoco a 100 percent interest in Sun Pipe Line Company of Delaware LLC, the owner of a 55.3 percent equity interest (50 percent voting rights) in Mid-Valley Pipeline Company (“Mid-Valley”) for $65 million, subject to certain adjustments five years following the date of closing, based on the throughput of Sunoco. Mid-Valley owns a 994-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.

Oklahoma

We own and operate a crude oil pipeline and gathering system in Oklahoma. This system contains approximately 800 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. Additionally, deliveries are made on the Oklahoma system to Sunoco and other third-party refiners. During 2008, Sunoco announced their intention to sell the Tulsa refinery or to convert it to a terminal by the end of 2009. We are currently assessing the impact of this change to our volumes within Oklahoma, but do not anticipate that this change will result in a material reduction in cash flows.

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.

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 579-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.

Crude Oil Acquisition and Marketing

In addition to receiving tariff revenues for transporting crude oil on the Western 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:

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

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storing inventory during contango market conditions;

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

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

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marketing crude oil to major integrated oil companies, independent refiners, including Sunoco for its Tulsa and Toledo refineries, 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. Although margins may be affected during transitional periods, our crude oil acquisition and marketing 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. 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 Western 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 crude oil futures contracts or enter into other commodity derivative contracts.

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 competitive prices 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, 2008, we purchased 177,000 bpd from approximately 3,300 producers and from approximately 33,000 leases, and undertook 402,000 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,
	2006	2007	2008
	(in thousands of bpd)
Lease purchases:
Available for sale	176	164	167
Exchanged	16	14	10
Other exchanges and bulk purchases	295	400	402

Total Purchases	487	578	579

Sales:
Sunoco refineries:
Toledo	32	20	8
Tulsa	78	50	63
Third parties	103	166	200
Exchanges:
Purchased at the lease	16	14	10
Other	256	330	295

Total Sales	485	580	576

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 leased 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 Western 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 the our Eastern Pipeline System, and the Sugar Land control center primarily monitors and controls our Western 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, Toledo, Tulsa, and Eagle Point refineries, or refined products transported from the Philadelphia, Marcus Hook, Toledo, and Eagle Point refineries. For further information on this agreement, see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Agreements with Sunoco.” For the year ended December 31, 2008, Sunoco accounted for approximately 25 percent of our total revenues.

Eastern Pipeline System

Nearly all of the Eastern 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 Eastern 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 product 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 MagTex refined product pipeline system, however, at this time, the existing pipelines have the capacity to satisfy the 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 all of the 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 41 refined product terminals, including the MagTex 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.

The primary competitors for the Nederland Terminal are its refinery customers’ docks and other terminal facilities, located in the Beaumont, Texas area.

The Inkster Terminal’s primary competition comes from other nearby facilities located in Michigan and Windsor, Canada.

Western Pipeline System

The Western 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 Western Pipeline System, however changes in refiners’ supply sources may negatively impact existing throughput on the Western 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. In addition, we must permit access to and copying of records and must prepare certain reports and provide information required by the Secretary of Transportation.

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 clear 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.

In connection with the February 2002 IPO, and the contribution of pipeline and terminalling assets to us by affiliates of Sunoco, Sunoco 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. 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, 2008, 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. Although no assurances can be given, our management believes implementation of the 1990 Clean Air Act Amendments will not have a material adverse effect on our financial condition or results of operations.

Our customers, including Sunoco, are also subject to, and affected by, environmental regulations. As a result of these regulations, Sunoco could be required to make significant capital expenditures, operate these refineries at reduced levels, and pay significant penalties. It is uncertain what Sunoco’s responses to these emerging issues will be. Those responses could reduce Sunoco’s 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, and our predecessor has in the past owned or leased, 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.

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, 2008. 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.

Sunoco and its subsidiaries are the only current shippers on several of the pipelines. In an agreement which expires on February 28, 2009, Sunoco has agreed not to challenge, cause others to challenge, or assist others in challenging, the tariff rates for the term of the pipelines and terminals storage and throughput agreement. Subsequent to that date, it is possible that any new shippers, current shippers, or other interested parties as well as Sunoco, may decide to challenge the tariff rates. If any rate challenge or challenges were successful, revenues, cash flows, and the cash available for distribution could be materially reduced.

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 Texas Railroad Commission, 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 management’s 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 to it 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. 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 1,270 people at December 31, 2008 who provide direct support to the operations. Labor unions or associations represent approximately 620 of these employees at December 31, 2008. 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 crude oil and 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, 2008, Sunoco accounted for approximately 66 percent of our Eastern Pipeline System total revenues, 61 percent of our Terminal Facilities total revenues, and 24 percent of our Western 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 currently have any minimum throughput obligations at our refined products terminals or the Marcus Hook Tank Farm. As of February 28, 2009 Sunoco will have no minimum storage or throughput obligations at Fort Mifflin Terminal or our crude oil pipelines, and as of March 31, 2009, Sunoco’s remaining obligations under the pipeline storage and throughput agreements will expire. 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 and 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 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

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

A material decrease in demand or distribution of crude oil available for transport through our Western 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 and 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 and 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;

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unplanned increases in the cost of construction materials or labor;

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

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

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

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

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

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

Potential future acquisitions and expansions, if any, 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 (including hurricanes), 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 receive from or deliver to us, 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.

Our operations may incur substantial liabilities to comply with climate change legislation and regulatory initiatives.

The U.S. Congress is considering legislation to reduce emissions of greenhouse gases (including carbon dioxide and methane). In addition, more than one-third of the states have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the development of greenhouse gas emission

inventories and/or regional greenhouse gas cap and trade programs. Also, on April 2, 2007, the U.S. Supreme Court in Massachusetts, et al. v. EPA held that carbon dioxide may be regulated as an “air pollutant” under the federal Clean Air Act and that EPA must consider whether it is required to regulate greenhouse gas emissions from mobile sources such as cars and trucks. Moreover, the Court’s holding in the Massachusetts decision that greenhouse gases fall under the federal Clean Air Act’s definition of “air pollutant” also may result in future regulation of greenhouse gas emissions from stationary sources. In July 2008, EPA released an “Advance Notice of Proposed Rulemaking” regarding possible future regulation of greenhouse gas emissions under the Clean Air Act. Although the notice did not propose any specific, new regulatory requirements for greenhouse gases, it indicates that federal regulation of greenhouse gas emissions could occur in the near future. Thus, there may be restrictions imposed on the emission of greenhouse gases even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations could result in increased compliance costs 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 and owns a 41.3 percent limited partner interest in us 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:

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

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

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

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

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

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our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities, and reserves, each of which can affect the amount of cash available for distribution to our unitholders and the amount received by our general partner in respect of its incentive distribution rights;

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

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

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

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

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

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

Our general partner is a wholly owned subsidiary of Sunoco, and Sunoco indirectly owns approximately 41.3 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 product or crude oil pipelines or terminals or LPG terminals in the continental United States. The Omnibus Agreement, however, does not apply to:

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any business operated by Sunoco or any of its subsidiaries at the closing of our initial public offering;

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

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

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any business that Sunoco or any of its subsidiaries acquires or constructs that has a fair market value of $5.0 million or more if we have been offered the opportunity to purchase the business for fair market value, and we decline to do so with the concurrence of our conflicts committee.

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

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

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

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

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

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

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

RISKS RELATED TO OUR DEBT

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

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.

Due to current economic conditions, our ability to obtain funding under our revolving credit facilities could be impaired.

We operate in a capital intensive industry and periodically rely on our revolving credit facilities to finance a portion of our capital expenditures and for other general partnership purposes. Our ability to draw from our revolving credit facilities may be impaired because of the recent downturn in the financial market, including the issues surrounding the solvency of many institutional lenders and the recent failure of several banks.

If we are unable to draw from our revolving credit facilities we will need to meet our capital requirements through other sources. If the cash generated from our operations or the funds we are able to obtain under our revolving credit facilities or other sources of liquidity are not sufficient to meet our capital requirements then we may need to curtail certain of our operations which could adversely affect our revenues, results of operations and limit our growth.

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

As of December 31, 2008, our total outstanding long-term indebtedness was approximately $747.6 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. The termination of our pipelines and terminals storage and throughput agreements with Sunoco would constitute an event of default under our credit facilities. 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. Since Sunoco owns and controls our general partner, we are not permitted to incur additional debt if the effect would be to cause an event of default under Sunoco’s revolving credit agreements. Similarly a default by Sunoco on its debt agreement could cause a default under our debt agreements. Any subsequent refinancing of Sunoco’s or our current debt or any new debt could have similar or greater restrictions.

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

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

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

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

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

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

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

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place us at a competitive disadvantage against less leveraged competitors.

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

As of December 31, 2008, we had $323.4 million of floating-rate debt, which includes $50.0 million in borrowings under our revolving credit facilities which effectively have a fixed rate under a floating to fixed interest rate swap agreement that matures in January 2010. 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 would 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.

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 Western Pipeline System. We are currently in discussions with PHMSA to resolve this matter.

In November 2007 and February 2008, we received notice of administrative fines from the Delaware County Regional Water Control Authority (DELCORA) totaling approximately $0.6 million relating to alleged non-compliance with monthly average arsenic limits. In December 2008, we entered into a Compliance Order with DELCORA settling and resolving the penalty assessment and, pursuant to the agreement, we paid DELCORA $10,000.

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.

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, 2008.

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 were listed on the New York Stock Exchange under the symbol “SXL” beginning on February 5, 2002. Prior to February 5, 2002, our equity securities were not traded on any public trading market. At the close of business on February 23, 2009, there were 94 holders of record of our common units. These holders of record included the general partner with 12,063,734 common units registered in its name, and Cede & Co. with 16,575,382 common units registered to it.

The high and low closing sales price ranges (composite transactions) and distributions declared by quarter for 2007 and 2008 were as follows:


	2007						2008
	Unit Price				Declared Distributions		Unit Price				Declared Distributions⁽¹⁾
Quarter	High		Low		High		High		Low		Declared Distributions⁽¹⁾
1^st	$	59.24	$	49.68	$	0.8250	$	53.94	$	45.55	$	0.8950
2^nd	$	62.84	$	55.54	$	0.8375	$	52.65	$	46.90	$	0.9350
3^rd	$	62.98	$	48.92	$	0.8500	$	49.43	$	43.17	$	0.9650
4^th	$	58.81	$	48.69	$	0.8700	$	49.15	$	29.11	$	0.9900

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.

We issued 11,383,639 subordinated units to our general partner in connection with the initial public offering in February 2002. These subordinated units were convertible to common units on a one-for-one basis provided we met applicable financial tests set forth in the Partnership Agreement. Once converted, subordinated units are no longer subordinated to the rights of the holders of common units. We met the minimum quarterly distribution requirements on all outstanding units for each of the four-quarter periods ended December 31, 2005 and 2006. As a result, the subordinated units converted to common units during 2005 through 2007.

We will, in general, pay cash distributions each quarter in the following manner:


Quarterly Cash Distribution Amount per Unit	Percentage of Distributions
Quarterly Cash Distribution Amount per Unit	Unitholders		General Partner
Up to minimum quarterly distribution ($0.45 per Unit)	98	%	2	%
Above $0.45 per Unit up to $0.50 per Unit	98	%	2	%
Above $0.50 per Unit up to $0.575 per Unit	85	%	15	%
Above $0.575 per Unit up to $0.70 per Unit	75	%	25	%
Above $0.70 per Unit	50	%	50	%

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 “Percentage of 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”).

For equity compensation plan information, see Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Securityholder Information”.

ITEM 6.

SELECTED FINANCIAL DATA

For the periods presented, Sunoco was the primary or exclusive user of the refined product terminals, 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 expand the existing operating capacity of the assets, whether through construction or acquisition. 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 Eastern Pipeline System than throughput as certain refined product 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,
	2004⁽¹⁾			2005⁽²⁾			2006⁽³⁾			2007⁽⁴⁾			2008⁽⁵⁾
	(in thousands, except per unit and operating data)
*Income Statement Data:*
Revenues:
Sales and other operating revenue:
Affiliates	$	1,751,612		$	1,986,019		$	1,842,634		$	1,682,042		$	2,571,947
Unaffiliated customers		1,699,673			2,496,593			3,994,601			5,695,413			7,540,373
Other income⁽⁶⁾		13,932			14,295			17,315			28,381			24,298

Total revenues		3,465,217			4,496,907			5,854,550			7,405,836			10,136,618

Costs and expenses:
Cost of products sold and operating expenses		3,307,480			4,326,713			5,644,021			7,156,142			9,786,014
Depreciation and amortization		31,933			33,838			36,649			37,341			40,054
Selling, general and administrative expenses		48,449			53,048			55,686			56,198			59,284
Impairment charge		—			—			—			—			5,674

Total costs and expenses		3,387,862			4,413,599			5,736,356			7,249,681			9,891,026

Operating income		77,355			83,308			118,194			156,155			245,592
Net interest cost and debt expense		20,324			21,599			27,853			35,280			31,112

Income before income tax expense		57,031			61,709			90,341			120,875			214,480
Income tax expense		—			—			—			—			—

Net Income	$	57,031		$	61,709		$	90,341		$	120,875		$	214,480

Net Income per limited partner unit:
Basic	$	2.29		$	2.37		$	2.87		$	3.38		$	5.01

Diluted	$	2.27		$	2.35		$	2.85		$	3.37		$	4.98

Cash distributions per unit to limited partners:⁽⁷⁾
Paid	$	2.32		$	2.56		$	3.03		$	3.33		$	3.67

Declared	$	2.40		$	2.65		$	3.13		$	3.38		$	3.79

*Cash Flow Data:*
Net cash provided by operating activities	$	106,622		$	90,835		$	141,480		$	207,499		$	228,587
Net cash used in investing activities	$	(95,583	)	$	(180,654	)	$	(241,220	)	$	(119,351	)	$	(331,244	)
Net cash provided by/(used in) financing activities	$	(8,460	)	$	58,804		$	87,507		$	(95,560	)	$	102,657
Capital expenditures:
Maintenance	$	30,829		$	31,194		$	29,872		$	24,946		$	25,652
Expansion		64,754	⁽¹⁾		149,460	⁽²⁾		209,135	⁽³⁾		94,666	⁽⁴⁾		305,592	⁽⁵⁾

Total capital expenditures	$	95,583		$	180,654		$	239,007		$	119,612		$	331,244

EBITDA⁽⁸⁾	$	109,288		$	117,146		$	154,843		$	193,496		$	291,320
Distributable Cash Flow⁽⁸⁾	$	65,182		$	72,378		$	102,844		$	134,467		$	236,982


	Year Ended December 31,
	2004⁽¹⁾		2005⁽²⁾		2006⁽³⁾		2007⁽⁴⁾		2008⁽⁵⁾
	(in thousands, except per unit and operating data)
*Balance Sheet Data (at period end):*
Net properties, plants and equipment	$	647,200	$	814,836	$	1,006,668	$	1,089,262	$	1,375,429
Total assets	$	1,368,786	$	1,680,685	$	2,082,077	$	2,504,642	$	2,308,249
Total debt	$	313,305	$	355,573	$	491,910	$	515,104	$	747,631
Total Partners’ Capital	$	460,594	$	523,411	$	582,911	$	591,045	$	669,900
*Operating Data (bpd):*
Eastern Pipeline System total shipments (in thousands of barrel miles per day)⁽⁹⁾		59,173		56,907		61,764		65,737		64,786
Terminal Facilities throughput (bpd)		1,464,254		1,549,427		1,541,470		1,636,977		1,615,493
Western Pipeline System throughput⁽⁹⁾ (bpd)		298,797		356,129		526,014		527,491		535,015
Crude oil purchases at wellhead (bpd)		186,827		186,224		191,644		177,981		177,662

⁽¹⁾

During the year ended December 31, 2004, we completed the following acquisitions: the Eagle Point logistics assets were purchased for approximately $20.0 million on March 30, 2004; two refined product terminals located in Baltimore, Maryland and Manassas, Virginia were purchased for $12.0 million on April 28, 2004; an additional 33.3 percent undivided interest in the Harbor pipeline was acquired on June 28, 2004 for approximately $7.3 million; and a refined product terminal located in Columbus, Ohio was purchased for approximately $8.0 million on November 30, 2004. The aggregate purchase price for these acquisitions is included within the 2004 expansion capital expenditures.

⁽²⁾

Expansion capital expenditures in 2005 includes approximately $100.0 million related to the August 1, 2005 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.

⁽³⁾

Expansion capital expenditures in 2006 includes approximately $40.9 million related to the March 1, 2006 acquisition of the Millennium and Kilgore crude oil pipeline system, approximately $68.0 million related to the March 1, 2006 acquisition of the Amdel and White Oil crude oil pipeline system and approximately $12.5 million related to the August 18, 2006 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.

⁽⁴⁾

Expansion capital expenditures in 2007 includes approximately $13.4 million related to the June 1, 2007 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.

⁽⁵⁾

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 five 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,
	2004			2005			2006			2007			2008
Net income	$	57,031		$	61,709		$	90,341		$	120,875		$	214,480
Interest paid to affiliates		439			468			1,411			2,287			558
Capitalized interest		—			(480	)		(3,005	)		(3,419	)		(3,855	)
Interest expense		20,476			21,999			30,392			36,723			34,433
Interest income		(591	)		(388	)		(945	)		(311	)		(24	)
Depreciation and amortization		31,933			33,838			36,649			37,341			40,054
Impairment Charge		—			—			—			—			5,674

EBITDA		109,288			117,146			154,843			193,496			291,320
Interest expense, net		(20,324	)		(21,599	)		(27,853	)		(35,280	)		(31,112	)
Maintenance capital expenditures		(30,829	)		(31,194	)		(29,872	)		(24,946	)		(25,652	)
Sunoco reimbursements		7,047			8,025			5,726			1,197			2,426

Distributable cash flow	$	65,182		$	72,378		$	102,844		$	134,467		$	236,982


	Year Ended December 31,
	2004			2005			2006			2007			2008
Net cash provided by operating activities	$	106,622		$	90,835		$	141,480		$	207,499		$	228,587
Interest expense, net		20,324			21,599			27,853			35,280			31,112
Amortization fees and bond discount		239			(400	)		(508	)		(666	)		(633	)
Restricted unit incentive plan expense		(3,204	)		(3,221	)		(3,686	)		(5,310	)		(4,277	)
Net change in working capital pertaining to operating activities		(13,467	)		6,167			(11,456	)		(40,221	)		38,381
Proceeds from insurance recovery		—			—			—			(4,389	)		—
Other		(1,226	)		2,166			1,160			1,303			(1,850	)

EBITDA	$	109,288		$	117,146		$	154,843		$	193,496		$	291,320

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

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 on October 15, 2001 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, 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:

2008 Acquisition

•

MagTex Acquisition. On November 18, 2008, we acquired a refined products pipeline system located in Texas from affiliates of Exxon Mobil Corporation for approximately $185.4 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 combined active storage capacity of 0.5 million shell barrels.

2007 Acquisition

•

2006 Acquisitions

•

Mid-Valley owns a 994-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.

•

Millenium and Kilgore Pipeline Acquisition. On March 1, 2006, we purchased a Texas crude oil pipeline system from affiliates of Black Hills Energy, Inc. for approximately $40.9 million. The system consists of (a) the Millennium Pipeline, a 200-mile, 12-inch crude oil pipeline with approximately 65,000 bpd operating capacity, originating near the Nederland Terminal, and terminating at Longview Texas; (b) the Kilgore Pipeline, a 190-mile, 10-inch crude oil pipeline with approximately 35,000 barrel per day capacity originating in Kilgore, Texas and terminating at refineries in the Houston, Texas region; (c) approximately 900,000 shell barrels of active storage capacity at Kilgore, and Longview, Texas, approximately 550,000 of which are inactive; (d) a crude oil sales and marketing business; and (e) crude oil line fill and working inventory.

•

Amdel and White Oil Pipeline Acquisition. On March 1, 2006, the Partnership acquired a Texas crude oil pipeline system from Alon USA Energy, Inc. for approximately $68.0 million. The system consists of (a) the Amdel Pipeline, a 503-mile, 10-inch common carrier crude oil pipeline with approximately 27,000 bpd operating capacity, originating at the Nederland Terminal, and terminating at Midland, Texas, and (b) the White Oil Pipeline, a 25-mile, 10-inch crude oil pipeline with approximately 40,000 bpd operating capacity, originating at the Amdel Pipeline and terminating at Alon’s Big Spring, Texas refinery. The pipelines were idle at the time of purchase, were re-commissioned by us during the second quarter 2006 and began making deliveries during the fourth quarter 2006. During the first quarter of 2007, we completed a project to expand the capacity on the Amdel Pipeline from approximately 27,000 to 40,000 bpd. Construction on new tankage at the Nederland Terminal to service these new volumes more efficiently was completed during 2008.

Growth Capital Program

In December 2006, we announced an agreement with Motiva Enterprises LLC to construct three additional crude oil storage tanks, with a combined capacity of 2.0 million shell barrels of capacity, and a 12-mile 30” crude oil pipeline from the Nederland Terminal to Motiva’s Port Arthur, Texas refinery. Construction of these assets is expected to be completed during 2009 at a cost of approximately $90 million. During 2009, we expect to spend approximately $100 million to $125 million on expansion capital expenditures related to organic growth, which includes the completion of the Motiva project and the continued integration of the MagTex refined product pipeline system.

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 (“Credit Facility”). In connection with the MagTex acquisition, the Operating Partnership has also entered into a $100 million 364-day revolving credit facility on May 28, 2008 (See “Liquidity and Capital Resources” for further information.). We will maintain our conservative capital structure by combining debt and equity issuances to finance our future growth.

In February 2009, the Operating Partnership issued $175 million of 8.75 percent Senior Notes, due February 15, 2014, the “2014 Senior Notes”, at 99.995 percent of the principal amount. In May 2006, the Operating Partnership issued $175 million of 6.125 percent Senior Notes, due May 15, 2016, the “2016 Senior Notes”, at 99.858 percent of the principal amount, for net proceeds of $173.3 million after the underwriter’s commission and legal, accounting and other transaction expenses. We also completed an equity issuance during 2006, through which we issued an aggregate of 2.8 million limited partner units, generating $110.3 million of net proceeds. Proceeds from this equity issue were used to repay a portion of the debt incurred to fund acquisitions, and to fund our organic growth program.

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 quarter of the three years ended December 31, 2008. For the year ended December 31, 2008, the distribution increased to $0.990 per common unit, ($3.96 annualized), from $0.7125 per common unit paid in February 2006. The distribution for the fourth quarter of 2008 was paid in February 2009 and represents a 13.8 percent increase over the fourth quarter 2007 distribution.

Results of Operations


	Year Ended December 31,
	2006		2007			2008
	(in thousands)
Statements of Income
Sales and other operating revenue:
Affiliates	$	1,842,634	$	1,682,042		$	2,571,947
Unaffiliated customers		3,994,601		5,695,413			7,540,373
Other income		17,315		28,381			24,298

Total revenues		5,854,550		7,405,836			10,136,618

Cost of products sold and operating expenses		5,644,021		7,156,142			9,786,014
Depreciation and amortization		36,649		37,341			45,728
Selling, general and administrative expenses		55,686		56,198			59,284

Total costs and expenses		5,736,356		7,249,681			9,891,026

Operating income		118,194		156,155			245,592
Net interest expense		27,853		35,280			31,112

Net income	$	90,341	$	120,875		$	214,480

Segment Operating Income:
Eastern Pipeline System
Sales and other operating revenue:
Affiliate	$	77,228	$	81,866		$	88,773
Unaffiliated customers		28,408		35,475			37,012
Other income		11,201		13,932			8,535

Total revenues		116,837		131,273			134,320

Operating expenses		45,516		52,298			46,120
Depreciation and amortization		9,550		9,165			10,247
Selling, general and administrative expenses		17,532		20,404			19,776

Total costs and expenses		72,598		81,867			76,143

Operating income	$	44,239	$	49,406		$	58,177

Terminal Facilities
Sales and other operating revenue:
Affiliates	$	82,607	$	92,156		$	99,976
Unaffiliated customers		40,635		49,466			62,448
Other income		37		(39	)		833

Total revenues		123,279		141,583			163,257

Cost of products sold and operating expenses		53,427		57,528			64,283
Depreciation and amortization		15,364		15,338			16,446
Impairment charge		—		—			5,674
Selling, general and administrative expenses		15,348		16,049			18,379

Total costs and expenses		84,139		88,915			104,782

Operating income	$	39,140	$	52,668		$	58,475

Western Pipeline System
Sales and other operating revenue:
Affiliates	$	1,682,799	$	1,508,020		$	2,383,198
Unaffiliated customers		3,925,558		5,610,472			7,440,913
Other income		6,077		14,488			14,930

Total revenues		5,614,434		7,132,980			9,839,041

Cost of products sold and operating expenses		5,545,078		7,046,316			9,675,611
Depreciation and amortization		11,735		12,838			13,361
Selling, general and administrative expenses		22,806		19,745			21,129

Total costs and expenses		5,579,619		7,078,899			9,710,101

Operating income	$	34,815	$	54,081		$	128,940

Operating Highlights


	Year Ended December 31,
	2006	2007	2008
Eastern Pipeline System⁽¹⁾⁽⁶⁾:
Total shipments (barrel miles per day)⁽²⁾	61,763,923	65,736,878	64,786,424
Revenue per barrel mile (cents)	0.469	0.489	0.530
Terminal Facilities:
Terminal throughput (bpd):
Refined product terminals⁽³⁾⁽⁶⁾	391,718	433,797	436,213
Nederland Terminal	461,943	507,312	525,954
Fort Mifflin Terminal Complex	319,795	310,948	299,727
Marcus Hook Tank Farm	151,093	146,112	127,738
Eagle Point Dock.	216,921	238,808	225,861
Western Pipeline System⁽¹⁾⁽⁴⁾:
Crude oil pipeline throughput (bpd)	526,014	527,491	535,015
Crude oil purchases at wellhead (bpd)	191,644	177,981	177,662
Gross margin per barrel of pipeline throughput (cents)⁽⁵⁾	26.8	30.8	69.0

⁽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⁾	Includes results from our purchases of the Millennium and Kilgore pipeline system and the Amdel pipeline system from acquisition dates.

⁽⁵⁾	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.

⁽⁶⁾	Includes results from our purchase of the MagTex refined product pipeline system and terminal assets from the acquisition date.

Analysis of Consolidated Net Income

Net income was $90.3 million, $120.9 million and $214.5 million for the years ended December 31, 2006, 2007 and 2008 respectively.

The $93.6 million increase in net income from 2007 to 2008 was primarily due to higher fees across all segments, significantly improved lease acquisition margins, increased volumes within the Western Pipeline system and the addition of assets through organic projects and acquisitions. Decreased interest expense contributed further to the increase in net income.

The $30.6 million increase in net income from 2006 to 2007 was primarily the result of strong operating performance in our Terminal Facilities and Western Pipeline segments, the August 2006 acquisition of an equity interest in the Mid-Valley Pipeline Company, and the March 2006 acquisitions of the Kilgore and Millennium pipelines. Partially offsetting the increase in operating income was higher interest expense related to the Partnership’s organic growth program, and 2006 and 2007 acquisitions.

Net interest expense was $31.1 million for the year ended December 31, 2008, a decrease of $4.2 million from the prior year due to lower interest rates on the Partnership’s credit facility.

Net interest expense was $35.3 million for the year ended December 31, 2007, a $7.4 million increase from the prior year primarily due to increased borrowings related to financing our organic growth program, the previously mentioned 2007 acquisition and higher inventory levels during the first half of the year.

Analysis of Segment Operating Income

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

Eastern Pipeline System

Operating income for the Eastern Pipeline system increased $8.8 million to $58.2 million for the twelve months ended December 31, 2008 compared to the prior year period. Sales and other operating revenue increased by $8.4 million to $125.8 million due primarily to higher fees across our refined product and crude oil pipelines, increased volumes on the crude oil pipelines as well as the 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 product 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 $6.2 million to $46.1 million as increased operating gains, driven by higher crude oil and refined product prices, offset operating expenses. Environmental charges were also lower compared to the prior year.

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.

Western Pipeline System

Operating income for the Western Pipeline system increased $74.9 million to $128.9 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 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.

Year Ended December 31, 2007 versus Year Ended December 31, 2006

Eastern Pipeline System

Operating income for the Eastern Pipeline System increased $5.2 million to $49.4 million for the year ended December 31, 2007 compared to $44.2 million for the prior year. Sales and other operating revenue increased by $11.7 million to $117.3 million due to increased shipments on the expanded Marysville crude oil line, and in the aggregate, higher volumes and fees across our refined products pipelines. A $2.7 million increase in other income was related to an increase in equity income associated with our joint venture interests. Operating expenses increased by $6.8 million due to higher maintenance activity, additional utility expense related to higher throughput, and environmental charges due to third party contractor pipeline damage, partially offset by an increase in product operating gains. A $2.9 million increase in selling, general and administrative expenses was largely associated with a decrease in capitalized engineering costs and higher employee costs.

Terminal Facilities

Operating income for the Terminal Facilities segment increased by $13.6 million to $52.7 million for the year ended December 31, 2007 compared to $39.1 million for the prior year. Total revenue increased $18.3 million to $141.6 million due primarily to increased throughput at the Nederland crude oil terminal and refined product terminals as well as higher refined product additive fees. Cost of products sold and operating expenses increased $4.1 million for the year ended December 31, 2007 to $57.5 million primarily due to increased maintenance activity and costs associated with the purchase of product additives. The increase in selling, general and administrative expense of $0.7 million was largely due to higher employee costs and was partially offset by an insurance recovery related to the 2005 hurricane loss.

Western Pipeline System

Operating income for the Western Pipeline System increased $19.3 million to $54.1 million for the year ended December 31, 2007 compared to $34.8 million for the prior year. The increase resulted from improved asset utilization and higher crude oil pipeline volume from the 2006 acquisitions previously mentioned. Total revenue and cost of products sold and operating expenses increased compared with the year ended December 31, 2006 due principally to higher crude prices and an increase in bulk purchase and sale activity. The average price of West Texas Intermediate crude oil at Cushing, Oklahoma increased to $72.40 per barrel for the year ended December 31, 2007 from $66.25 per barrel for the year ended December 31, 2006. Operating expenses were higher as a result of increased costs associated with operating the assets acquired in 2006. Selling, general and administrative expenses decreased $3.1 million from 2006 due primarily to the Western Area office relocation which was completed during the first quarter of 2006 and an increase in capitalized engineering costs associated with our organic growth program. Depreciation and amortization expense increased $1.1 million during the year ended December 31, 2007 to $12.8 million as a result of 2006 acquisitions.

Liquidity and Capital Resources

Liquidity

Cash generated from operations and borrowings under our credit facilities are our primary sources of liquidity. At December 31, 2008, we had a net working capital deficit of $33.8 million and available borrowing capacity under our credit facilities of $171.6 million. Our working capital position also reflects crude oil inventories under the LIFO method of accounting. If the inventories had been valued at their current replacement cost, we would have had working capital of $10.9 million at December 31, 2008.

Capital Resources

We periodically supplement our cash flows from operations with proceeds from debt and equity financing activities.

Credit Facilities

On August 8, 2007, Sunoco Logistics Partners Operations L.P. (the “Operating Partnership”), a wholly-owned subsidiary, entered into a five-year $400 million revolving credit facility (“$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 $400 million Credit Facility, which has a syndicate of 10 participating banks, matures in November 2012. At December 31, 2008, there was $323.4 million outstanding under the 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. All obligations under the $400 million Credit Facility are unsecured. Indebtedness under the $400 million Credit Facility will rank equally with all outstanding unsecured and subordinated debt of the Operating Partnership. All loans may be prepaid at any time without penalty subject to reimbursement or breakage and redeployment costs in the case of prepayment of LIBOR borrowing.

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 requires the Operating Partnership to maintain, on a rolling four-quarter basis, 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. The Operating Partnership is in compliance with this requirement as of December 31, 2008.

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.

In anticipation of the MagTex Acquisition that closed on November 18, 2008, the Operating Partnership entered into a $100 million 364 day revolving credit facility (“$100 million Credit Facility”) on May 28, 2008. This $100 million Credit Facility is available to fund the same activities as the $400 million Credit Facility described above. The $100 million Credit Facility matures in May 2009 and can be prepaid at any time. Interest on outstanding borrowings is calculated, at the Operating Partnership’s option, using either (i) LIBOR plus and applicable margin or (ii) the higher of (a) the federal funds rates plus 0.50 percent plus an applicable margin, and (b) the Citibank prime rate plus an applicable margin. The $100 million Credit Facility contains the same covenant requirements as the $400 million Credit Facility described above. As of December 31, 2008 there were no borrowings outstanding under the $100 million 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 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 our $400 million Credit Facility.

In May 2006, the Operating Partnership issued $175 million of 6.125 percent Senior Notes, due May 16, 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 Operating Partnership is in compliance with these covenants as of December 31, 2008. The net proceeds from the 2016 Senior Notes, together with the $110.3 million in net proceeds from the concurrent offering of approximately 2.7 million limited partner common units, described below, 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.

We and the operating partnerships of the Operating Partnership served as joint and several guarantors of the senior notes and of any obligations under the previous credit facility. We continue to serve as guarantor of the senior notes and of any obligations under the current credit facilities. These guarantees are full and unconditional. In connection with the $400 million Credit Facility, the Subsidiary Guarantors (as defined in Note 18 to the financial statements included in Item 8) were released from their obligations both under the previous credit facility, and the 2012 and 2016 Senior Notes.

Equity Offerings

In May 2006, we sold 2.4 million common units in a public offering. In June 2006, we sold an additional 280,000 common units to cover over-allotments in connection with the May 2006 sale. The purchase price for the over allotment was equal to the offering price in the May 2006 sale. The total sale of units resulted in gross proceeds of $115.2 million, and net proceeds of $110.4 million, after the underwriters’ commission and legal, accounting and other transaction expenses. Net proceeds of the offering, together with the $173.3 million in net proceeds from the concurrent offering of the 2016 Senior Notes, described above, were used to repay $216.1 million of the debt incurred under the Operating Partnership’s previous revolving credit facility, to fund our 2006 organic growth program, and for our general partnership purposes. Also as a result of the issuance of these units, our general partner contributed $2.4 million to us to maintain its 2.0 percent general partner interest.

Cash Flows and Capital Expenditures

Net cash provided by operating activities for the years ended December 31, 2006, 2007 and 2008 was $141.5 million, $207.5 million and $228.6 million, respectively. Net cash provided by operating activities for 2008 was primarily the result of net income of $214.5 million and depreciation and amortization of $45.7 million, offset by an increase working capital of $38.4 million. 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 provided by operating activities for 2006 consists primarily of net income of $90.3 million, depreciation and amortization of $36.6 million, and an increase in the working capital deficit of $11.5 million. The increase in net cash flow provided by operating activities from 2007 to 2008 was primarily attributable to an increase in net income partially offset by increased crude oil inventories associated with contango inventory positions. The increase in net cash provided by operating activities from 2006 to 2007 was primarily attributable to an increase in net income and a decrease in inventory associated with the reduction of contango inventory positions.

Net cash used in investing activities for the years ended December 31, 2006, 2007 and 2008 was $241.2 million, $119.4 million, and $331.2 million respectively. The increase in cash used by investing activities from 2007 to 2008 was primarily attributable to the MagTex refined product system acquisition. The decrease in cash used in investing activities from 2006 to 2007 is due primarily to the 2006 acquisitions.

Cash used for acquisitions was $121.4 million in 2006, $13.5 million in 2007, and $185.4 million in 2008. Acquisitions completed in 2008 include the MagTex refined products pipeline 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 for approximately $13.5 million. Acquisitions completed in 2006 include the Amdel and White Oil pipeline for approximately $68.0 million, the Millennium and Kilgore pipeline system, storage facilities, sales

and marketing business and crude oil inventory for approximately $40.9 million and a 55.3 percent equity interest (50 percent voting rights) in Mid-Valley Pipeline Company for approximately $65.0 million. Since the acquisition was from a related party, the interest in the entity was recorded by us at Sunoco’s historical cost of $12.5 million 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.

Net cash provided by / (used in) financing activities for the years ended December 31, 2006, 2007 and 2008 was, $87.5 million, $(95.6) million and $102.7 million respectively.

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.

For the year ended December 31, 2006, we received $173.3 million of net proceeds from the issuance of the 2016 Senior Notes and net proceeds of $110.4 million from the concurrent public offerings completed in May 2006 and net borrowings of $38.6 million drawn against the previous credit facility to fund the acquisitions of two Texas crude oil pipelines and the 55.3 percent interest in the Mid-Valley pipeline. The $173.3 million net proceeds from the 2016 Senior Notes, together with the $110.4 million in net proceeds from the concurrent public offering were used to repay all of the $216.1 million in outstanding borrowings under the previous credit facility. Additionally, we received $5.7 million of capital contributions for reimbursement of certain maintenance capital expenditures and operating expenses under agreements with Sunoco. The net proceeds from these sources were partially offset by $98.0 million in distributions paid to our limited partners and our general partner, $47.4 million in capital distributions to Sunoco due primarily to the acquisition of a 55.3 percent interest (50 percent voting rights) in the Mid-Valley Pipeline Company and net advances to affiliates of $13.2 million.

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 2007 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 (roll-forward table):


	Year Ended December 31,
	2006			2007			2008
	(in thousands of dollars)
Maintenance	$	29,872		$	24,946		$	25,652
Expansion		209,135	⁽¹⁾		94,666	⁽²⁾		305,592	⁽³⁾

Total	$	239,007		$	119,612		$	331,244

⁽¹⁾

Includes $40.9 million related to the acquisition of the Millennium and Kilgore crude oil pipeline system, $68.0 million related to the acquisition of the Amdel and White Oil crude oil pipeline system and $12.5 million related to the acquisition of a 55.3 percent equity interest in Mid-Valley Pipeline Company.

⁽²⁾	Includes $13.4 million related to the acquisition of a 50 percent undivided interest in a refined products terminal located in Syracuse, New York.

⁽³⁾

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 the Partnerships agreement to connect the Nederland terminal to a Port Arthur, Texas refinery. Also includes construction of five additional crude oil storage tanks at the Nederland terminal.

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”). Maintenance capital for the year ended December 31, 2006 includes $2.8 million related to the Western Area office move that was completed in the first quarter of 2006. As of December 31, 2006, we had received the maximum aggregate reimbursements defined within the Omnibus Agreement with Sunoco. Management expects maintenance capital expenditures to be approximately $30.0 million in 2009.

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 five 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 $100.0 million to $125.0 million in expansion capital projects in 2009, which includes the continued construction of new tankage and pipeline connections associated with the previously discussed agreement with Motiva Enterprises LLC, the continued construction of tankage at the Nederland and further integration of the MagTex refined product pipeline 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, 2008), annual rentals applicable to noncancelable operating leases, and purchase commitments related to future periods at December 31, 2008 (in thousands of dollars):


	Year Ended December 31,										Thereafter		Total
	2009		2010		2011		2012		2013		Thereafter		Total
Long-term debt⁽¹⁾:
Principal	$	—	$	—	$	—	$	573,385	$	—	$	175,000	$	748,385
Interest		34,093		34,093		34,093		15,284		10,719		25,010		153,293
Operating leases		3,079		2,625		2,477		2,418		599		1,984		13,182
Purchase obligations		964,301		—		—		—		—		—		964,301

	$	1,001,473	$	36,718	$	36,570	$	591,087	$	11,318	$	201,995	$	1,879,161

⁽¹⁾	Excludes $175 million of 8.75 percent Senior Notes issued in February 2009, due 2014.

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 2009. 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, 2008 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—Western 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, 2006 and 2007. 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 reflects 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, 2008, our accrual for environmental remediation activities was $3.5 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, FASB Interpretation No. 14, “Reasonable Estimation of the Amount of a Loss” requires that the minimum of the range be 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, 2008. 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, 2008, 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

Under this 2002 agreement, Sunoco is paying us fees which are generally comparable to those charged by third parties to:

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transport on the refined product pipelines existing at the time of the agreement an amount of refined products that will produce at least $55.2 million of revenue in the contract year commencing March 1, 2008. Sunoco will pay the published tariffs on the pipelines. Based upon the prorated minimum amount noted, Sunoco has exceeded the minimum revenue amount through December 31, 2008 and our management expects Sunoco to exceed the minimum amount under the agreement for the contract year from March 1, 2008 through February 28, 2009;

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store 975,734 barrels of liquefied petroleum gas (“LPG”) per contract year at the Inkster Terminal, which represents all of the LPG storage capacity at this facility. This storage is an annual amount for the contract period from April 1 to March 31 for the seven-year term of the agreement ending March 31, 2009. For the calendar year ended December 31, 2008, we received a fee of $2.281 per barrel of committed storage, a fee of $0.228 per barrel for receipts greater than 975,734 barrels per contract year and a fee of $0.228 per barrel for deliveries greater than 975,734 barrels per contract year. Based upon the prorated minimum storage amount noted, Sunoco has exceeded the minimum storage amount through December 31, 2008 and our management expects Sunoco to exceed the minimum storage amount under the agreement for the contract year from April 1, 2008 through March 31, 2009;

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receive and deliver at least 290,000 bpd of crude oil or refined products per contract year at the Fort Mifflin Terminal Complex for seven years ending February 28, 2009. This throughput is an annual amount for the contract period from March 1 to February 28 for the term of the agreement. For the year ended December 31, 2008, we received a fee of $0.1797 per barrel for the first 180,000 bpd and $0.0898 per barrel for volume in excess of 180,000 bpd. Based upon the prorated minimum throughput amount noted, Sunoco has exceeded the minimum throughput amount through December 31, 2008 and our management expects Sunoco to exceed the minimum throughput amount under the agreement for the contract year from March 1, 2008 through February 28, 2009; and

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transport or cause to be transported an aggregate of at least 140,000 bpd of crude oil per contract year on the Marysville to Toledo, Nederland to Longview, Cushing to Tulsa, Barnsdall to Tulsa, and Bad Creek to Tulsa crude oil pipelines at the published tariffs for a term of seven years ending February 28, 2009. This throughput is an annual amount for the contract period from March 1 to February 28 for the term of the agreement. Based upon the prorated minimum throughput amount noted, Sunoco has exceeded the minimum throughput amount through December 31, 2008 and our management expects Sunoco to exceed the minimum throughput amount under the agreement for the contract year from March 1, 2008 through February 28, 2009.

Sunoco’s obligations under this agreement may be permanently reduced or suspended if Sunoco (1) shuts down or reconfigures one of its refineries (other than planned maintenance turnarounds), or is prohibited from using MTBE in the gasoline it produces, and (2) reasonably believes in good faith that such event will jeopardize its ability to satisfy these obligations. Although Sunoco no longer uses MTBE, it has not requested any reductions in its obligations.

Sunoco actively manages its assets and operations, and, therefore, changes of some nature, possibly material to our business relationship, may occur at some point in the future.

There can be no assurance that Sunoco will renew all or a portion of the remaining obligations under the pipelines and terminals storage and throughput agreement, or that, if renewed, the rates will be at or above the

current rates. Our assets were constructed or purchased to service Sunoco’s refining and marketing supply chain and are well-situated to suit Sunoco’s needs. As a result, our management would expect that even if all or a portion of these agreements are not renewed, Sunoco would continue to use the pipelines and terminals. However, there can be no assurance that Sunoco will continue to use our facilities or that additional 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:

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

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

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

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

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

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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

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

Reimbursement of Expenses and Completion of Certain Projects by Sunoco. The Omnibus Agreement requires Sunoco to:

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reimburse us for any operating expenses and capital expenditures in excess of $8.0 million per year in each calendar year from 2002 to 2006 that are made to comply with the DOT’s pipeline integrity management rule, subject to a maximum aggregate reimbursement of $15.0 million over the five-year period ended December 31, 2006;

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complete, at its expense, certain tank maintenance and inspection projects at the Darby Creek Tank Farm; and

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reimburse us for up to $10.0 million of required expenditures at the Marcus Hook Tank Farm and the Darby Creek Tank Farm to maintain compliance with existing industry standards and regulatory requirements, including: cathodic protection upgrades at these facilities; raising tank farm pipelines above ground level at these facilities; and repairing or demolishing two riveted tanks at the Marcus Hook Tank Farm.

We report outlays for these programs as operating expenses or capital expenditures, as appropriate, in the financial statements. Capital expenditures are depreciated over their useful lives. Reimbursements by Sunoco are reflected as capital contributions to Partners’ Capital within our balance sheets. As of December 31, 2006, we have received the cumulative reimbursement under these agreements 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 $7.7 million, $6.5 million and $6.0 million for the years ended December 31, 2006, 2007 and 2008, 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 by one year in January 2009 for an annual fee of $6.0 million. These costs may be increased if the acquisition or construction of new assets or businesses require 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 2009, 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 $3.2 million, $3.9 million and $3.2 million for the years ended December 31, 2006, 2007 and 2008, 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 $22.5 million, $23.0 million and $21.0 million for the years ended December 31, 2006, 2007 and 2008, 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:

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any business currently operated by Sunoco or any of its subsidiaries;

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

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

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any business that Sunoco or any of its subsidiaries acquires or constructs that has a fair market value of $5.0 million or more if we have been offered the opportunity to purchase the business for fair market value 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:

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the assets contributed, 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;

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certain defects in title to the assets contributed 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;

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

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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^st for the term of the agreement. The annual fee for the year ended December 31, 2008 was $6.0 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.

Crude Oil Purchase Agreement

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. Sunoco cancelled four of these agreements during 2007 in accordance with the terms, but the cancellation did not have a material impact on our results of operations or cash flows. During the year ended December 31, 2008, Sunoco purchased all the barrels offered pursuant to these agreements. During 2008, Sunoco announced their intention to sell the Tulsa refinery or to convert it to a terminal by the end of 2009. We are currently assessing the impact this change could have on these agreements, but do not anticipate this change will result in a material reduction in our cash flow.

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. The purchase agreement requires Sunoco to reimburse us for certain maintenance capital and expenses incurred regarding the assets acquired, as defined, up to $5.0 million within the first 10 years of the closing of the transaction. At December 31, 2008, we have received a cumulative reimbursement of $4.7 million relative to the $5.0 million maximum reimbursement.

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:

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receive or deliver all crude oil to and from the Eagle Point refinery, other than those received or shipped via rail car, tanker truck or pipeline for twelve years ending March 31, 2016. This throughput is an annual amount for the contract period from April 1 to March 31 for the term of the agreement. For the calendar year ended December 31, 2008, we received a fee of $0.0968 per barrel for the first 130,000 bpd of crude oil and $0.0540 per barrel for volumes in excess of 130,000 bpd. These fees escalate based on the Consumer Price Index (“CPI”) each January 1 for the term of the agreement;

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receive and deliver at least 41,800 bpd of refined and intermediate products per year at the Eagle Point dock for twelve years ending March 31, 2016. This throughput is an annual amount for the contract period from April 1 to March 31 for the term of the agreement. For the calendar year ended December 31, 2008, we received a fee of $0.0855 per barrel for the first 14,200 bpd of refined and intermediate products and $0.0427 per barrel for volume in excess of 14,200 bpd and also received a fee of $0.0748 per barrel for each shipment that required vapor combustion services. These fees escalate based on CPI each January 1 for the term of the agreement; and

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receive and deliver at least 32,000 bpd of refined and intermediate products per year at the Eagle Point Refined Products Terminal for twelve years ending March 31, 2016. This throughput is an annual amount for the contract period from April 1 to March 31 for the term of the agreement. For the year ended December 31, 2008, we received per barrel fees as set forth in the contract by refined and intermediate product shipped. These fees will escalate based on CPI each January 1 for the term of the

agreement. Under the agreement, Sunoco will pay us any shortfall if it does not exceed the minimum throughput amount under the agreement for the contract year from April 1, 2008 through March 31, 2009.

Product Terminal Services and Marcus Hook Tank Farm Agreements

On February 28, 2007 certain obligations of Sunoco under the pipelines and terminals storage throughput agreement with us, related to throughput of refined products through our terminals and the Marcus Hook Tank Farm, expired. Sunoco entered into agreements with us, effective March 1, 2007, pursuant to which Sunoco may throughput refined products through these terminals at agreed upon fees that escalate over the five-year term of the agreement. The agreements contains no minimum throughput obligations for Sunoco. Our refined product terminals and the Marcus Hook Tank Farm were constructed or purchased to service Sunoco’s refining and marketing supply chain and are well situated to suit Sunoco’s needs. As a result, our management would expect Sunoco to continue to use the terminals. However, there can be no assurance that Sunoco will continue to use our terminals or that additional revenues can be generated from third parties.

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 it 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, 2008, we had $323.4 million of variable-rate borrowings under our revolving credit facilities. On January 8, 2008, we entered into an interest rate swap agreement (the “Swap”) with a notional amount of $50.0 million maturing January 2010. Under the Swap, we receive interest equivalent to the three-month LIBOR and pay a fixed rate of interest of 3.489 percent with settlements occurring quarterly. To maintain hedge accounting for the Swap, we are committed to maintaining at least $50.0 million in borrowings on the $400 million Credit Facility at an interest rate based on the three-month LIBOR, plus an applicable margin, through January 2010. The remaining $273.4 million bears interest cost of LIBOR plus an applicable margin. An increase in short-term interest rates will have a favorable impact on the $50 million in borrowings related to the Swap and a negative impact on funds borrowed in excess of the $50 million. Our weighted average variable interest rate on our variable-rate borrowings, not related to the swap, was 1.62 percent at December 31, 2008. A one percent change in the weighted average rate would have impacted annual interest expense by approximately $2.7 million.

At December 31, 2008, we had $425 million of fixed-rate borrowings, which is comprised of $250.0 million of 2012 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, 2008 by approximately $17.3 million.

Commodity Market Risk

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 do not acquire and hold futures contracts or other derivative products for the purpose of speculating on price changes, as these activities could expose us to significant losses. 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 generally accepted accounting principles.

The Partnership’s management assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2008. 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, 2008, 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, 2008, 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, 2008, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2008 financial statements of Sunoco Logistics Partners L.P. and our report dated February 24, 2009 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Philadelphia, Pennsylvania

February 24, 2009

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, 2007 and 2008, and the related statements of income, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2008. 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, 2007 and 2008, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, 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, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2009 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Philadelphia, Pennsylvania

February 24, 2009

SUNOCO LOGISTICS PARTNERS L.P.

STATEMENTS OF INCOME

(in thousands, except units and per unit amounts)


	Year Ended December 31,
	2006			2007			2008
Revenues
Sales and other operating revenue:
Affiliates	$	1,842,634		$	1,682,042		$	2,571,947
Unaffiliated customers		3,994,601			5,695,413			7,540,373
Other income		17,315			28,381			24,298

Total Revenues		5,854,550			7,405,836			10,136,618

Costs and Expenses
Cost of products sold and operating expenses		5,644,021			7,156,142			9,786,014
Depreciation and amortization		36,649			37,341			40,054
Selling, general and administrative expenses		55,686			56,198			59,284
Impairment charge		—			—			5,674

Total Costs and Expenses		5,736,356			7,249,681			9,891,026

Operating Income		118,194			156,155			245,592
Net interest cost paid to affiliates		1,411			2,287			558
Other interest cost and debt expense, net		29,447			36,412			34,409
Capitalized interest		(3,005	)		(3,419	)		(3,855	)

Net Income	$	90,341		$	120,875		$	214,480

Calculation of Limited Partners’ interest in Net Income:
Net Income	$	90,341		$	120,875		$	214,480
Less: General Partner’s interest in Net Income		(11,166	)		(24,139	)		(70,851	)

Limited Partners’ interest in Net Income	$	79,175		$	96,736		$	143,629

Net Income per Limited Partner unit:
Basic	$	2.87		$	3.38		$	5.01

Diluted	$	2.85		$	3.37		$	4.98

Weighted average Limited Partners’ units outstanding:
Basic		27,608,565			28,581,032			28,650,069

Diluted		27,738,016			28,729,153			28,836,603

(See Accompanying Notes)

SUNOCO LOGISTICS PARTNERS L.P.

BALANCE SHEETS

(in thousands)


	December 31,
	2007		2008
Assets
Current Assets
Cash and cash equivalents	$	2,000	$	2,000
Advances to affiliates		8,060		2,549
Accounts receivable, affiliated companies		62,167		77,692
Accounts receivable, net		1,200,782		652,840
Inventories		30,669		90,156

Total Current Assets		1,303,678		825,237
Properties, plants and equipment, net		1,089,262		1,375,429
Investment in affiliates		84,985		82,882
Deferred charges and other assets		26,717		24,701

Total Assets	$	2,504,642	$	2,308,249

Liabilities and Partners’ Capital
Current Liabilities
Accounts payable	$	1,289,402	$	792,674
Accrued liabilities		45,159		45,648
Accrued taxes		34,277		20,738

Total Current Liabilities		1,368,838		859,060
Long-term debt		515,104		747,631
Other deferred credits and liabilities		29,655		31,658
Commitments and contingent liabilities

Total Liabilities		1,913,597		1,638,349

Partners’ Capital:
Limited partners’ interest		582,357		653,289
General partner’s interest		8,688		19,741
Accumulated other comprehensive loss		—		(3,130	)

Total Partners’ Capital		591,045		669,900

Total Liabilities and Partners’ Capital	$	2,504,642	$	2,308,249

(See Accompanying Notes)

SUNOCO LOGISTICS PARTNERS L.P.

STATEMENTS OF CASH FLOWS

(in thousands)


	Year Ended December 31,
	2006			2007			2008
Cash Flows from Operating Activities:
Net Income	$	90,341		$	120,875		$	214,480
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		36,649			37,341			40,054
Impairment charge		—			—			5,674
Amortization of financing fees and bond discount		508			666			633
Restricted unit incentive plan expense		3,686			5,310			4,277
Changes in working capital pertaining to operating activities:
Accounts receivable, affiliated companies		37,584			36,785			(15,525	)
Accounts receivable, net		(191,996	)		(424,277	)		547,942
Inventories		(39,834	)		39,615			(59,487	)
Accounts payable and accrued liabilities		203,819			376,690			(497,772	)
Accrued taxes		1,883			11,408			(13,539	)
Proceeds from insurance recovery		—			4,389			—
Other		(1,160	)		(1,303	)		1,850

Net cash provided by operating activities		141,480			207,499			228,587

Cash Flows from Investing Activities:
Capital expenditures		(119,838	)		(105,862	)		(145,834	)
Acquisitions		(121,382	)		(13,489	)		(185,410	)

Net cash used in investing activities		(241,220	)		(119,351	)		(331,244	)

Cash Flows from Financing Activities:
Distributions paid to Limited Partners and General Partner		(97,987	)		(117,451	)		(137,203	)
Net proceeds from issuance of Limited Partner units		110,338			—			—
Contribution from General Partner for Limited Partner unit transactions		2,427			58			76
Repayments from (advances to) affiliates, net		(13,181	)		(629	)		5,511
Borrowings under credit facility		177,500			279,900			343,385
Repayments under credit facility		(216,100	)		(256,900	)		(111,000	)
Net proceeds from issuance of Senior Notes		173,307			—			—
Payments of statutory withholding on net issuance of Limited Partner units under restricted unit incentive plan		(1,443	)		(1,479	)		(538	)
Contributions from / (Distributions to) affiliate		(47,354	)		941			2,426

Net cash provided by/(used in) financing activities		87,507			(95,560	)		102,657

Net change in cash and cash equivalents		(12,233	)		(7,412	)		—
Cash and cash equivalents at beginning of year		21,645			9,412			2,000

Cash and cash equivalents at end of year	$	9,412		$	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, 2005	17,231	$	358,954		8,538		$	156,558		$	7,899			—		$	523,411
Net income	—		63,029		—			16,146			11,166			—			90,341
Issuance of Limited Partner units to the public	2,680		110,338		—			—			2,353			—			112,691
Conversion of Subordinated units to Common units held by affiliate (Note 12)	2,846		52,185		(2,846	)		(52,185	)		—			—			—
Contribution from affiliate	—		2,964		—			2,647			115			—			5,726
Distribution to affiliate	—		(27,475	)	—			(24,543	)		(1,062	)		—			(53,080	)
Unissued units under incentive plans	—		3,686		—			—			—			—			3,686
Distribution equivalent rights	—		(508	)	—			—			—			—			(508	)
Units issued under incentive plans	87		—		—			—			74			—			74
Tax withholding under incentive plans	—		(1,443	)	—			—			—			—			(1,443	)
Cash distributions	—		(65,104	)	—			(19,245	)		(13,638	)		—			(97,987	)

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	—		171,317		—			—			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
Unissued units under incentive plans	—		4,277		—			—			—			—			4,277
Distribution equivalent rights	—		(1,533	)	—			—			—			—			(1,533	)
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	$	653,289		—			—		$	19,741		$	(3,130	)	$	669,900

(See Accompanying Notes)

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Principles of Consolidation

Sunoco Logistics Partners L.P. (the “Partnership”) is a Delaware limited partnership formed by Sunoco, Inc. (“Sunoco”) in October 2001 to acquire, own and operate 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 located in the northeast, midwest and soutwest United States. Sunoco, Inc. and its wholly-owned subsidiaries including Sunoco, Inc. (R&M) are collectively referred to as “Sunoco”. The consolidated financial statements reflect the results of Sunoco Logistics Partners L.P. and its wholly-owned partnerships, including Sunoco Logistics Partners Operations L.P. (the “Operating Partnership”). We eliminate all significant intercompany accounts and transactions. Equity ownership interests in corporate joint ventures, which are not consolidated, are accounted for under the equity method. 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.

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 based upon the concepts set forth in APB Opinion No. 29, “Accounting for Nonmonetary Transactions” as amended by Emerging Issues Task Force Issue 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty”.

Affiliated revenues consist of sales of crude oil as well as the provision of crude oil and refined product 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. Sunoco’s remaining minimum throughput obligations for refined products, intermediates, liquefied petroleum gas and crude oil in the Partnership’s Inkster Terminal, Fort Mifflin Terminal Complex, Eagle Point dock and terminal and certain crude oil pipelines expire in the first quarter of 2009.

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, 2007 and 2008, these cash equivalents consist principally of money market accounts.

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

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 collectibility 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 inventory cost has been determined using the last-in, first-out method (“LIFO”). Under this methodology, the cost of products sold consists of the actual crude oil acquisition costs of the Partnership, which includes transportation and storage costs. Such costs are adjusted to reflect increases or decreases in crude oil 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 inventory balances declined in the Partnership’s Western Pipeline business segment during 2007, which resulted in liquidating a portion of the prior year layer carried at lower costs prevailing in 2006. 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.

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 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, 2006, 2007 and 2008, the amount of interest capitalized was $3.0 million, $3.4 million and $3.9 million, respectively. The weighted average rate used to capitalize interest on borrowed funds was 6.6 percent, 6.5 percent and 5.9 percent for 2006, 2007 and 2008, respectively.

Investment in Affiliates

Investments in affiliates, which consist of corporate joint ventures, are accounted for under the equity method of accounting as required by Accounting Principles Board Opinion 18, “The Equity Method of Accounting for Investments in Common Stock” (“APB 18”). 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 our corporate joint venture interests is presented within other income on our statements of income. The Partnership had $3.9 million of undistributed earnings from its investments in corporate joint ventures within Partners’ Capital at December 31, 2008. During the years ended December 31, 2006, 2007 and 2008 the Partnership received dividends of $15.9 million, $23.9 million and $22.2 million respectively, from its investments in corporate joint ventures.

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

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.

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.

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, 2007 and 2008, the Partnership had $16.2 million of goodwill and accumulated amortization of $1.3 million related to goodwill. In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 142, “Goodwill and Other Intangible Assets,” goodwill and indefinite-lived intangible assets are tested for impairment at least annually. The Partnership determined during 2006, 2007 and 2008 that such assets were not impaired.

Deferred financing fees of $3.1 million and $2.5 million, net of accumulated amortization of $1.9 million and $2.6 million have been included within deferred charges and other assets on the balance sheets as of December 31, 2007 and 2008, respectively. The Partnership deferred total fees of $0.3 million paid in 2007 related to the $400 million Credit Facility entered into in August 2007 (see Note 9). Amortization expense of $0.5 million, $0.7 million and $0.6 million for the years ended December 31, 2006, 2007 and 2008, 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.

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

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

impose income taxes. Our 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 we are subject to state and local income taxes.

We adopted the provisions of Financial Accounting Standards Board (“FASB”) Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an Interpretation of SFAS 109, Accounting for Income Taxes (“FIN 48”), as of January 1, 2007. This interpretation clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with SFAS 109 by prescribing the minimum recognition threshold and measurement attribute a tax position taken or expected to be taken on a tax return is required to meet before being recognized in the financial statements. The adoption of FIN 48 had no material impact on our financial statements.

Long-Term Incentive Plan

On January 1, 2006, the Partnership adopted SFAS No. 123R, “Share-Based Payment” (“SFAS No. 123R”), using the modified-prospective method. Among other things, SFAS No. 123R requires a fair-value-based method of accounting for share-based payment transactions. SFAS No. 123R also requires the use of a non-substantive vesting period approach for share-based payment transactions that vest when an employee becomes retirement eligible as is the case under the Partnership’s Long-Term Incentive Plan (i.e., the vesting period cannot exceed the date an employee becomes retirement eligible). The effect is to accelerate expense recognition for units awarded to retirement-eligible participants or those participants who will become retirement-eligible during the vesting period. Expense related to this plan is included in selling general and administrative expenses on the income statement.

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 at December 31, 2007 and 2008. During 2006, the Partnership increased the liability for asset retirement obligations and properties, plant and equipment by $1.1 million related to the obligations associated with two crude oil pipelines acquired in March 2006. This change did not have a significant impact on the Partnership’s statement of income for the year ended December 31, 2006. During 2007 and 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

Effective January 1, 2008, the Partnership adopted the provisions of Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“SFAS No. 157”) which pertain to certain balance sheet items

measured at fair value on a recurring basis. SFAS No. 157 defines fair value, establishes a framework for

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

measuring fair value and expands disclosures about such measurements that are permitted or required under other accounting pronouncements. While SFAS No. 157 may change the method of calculating fair value, it does not require any new fair value measurements.

In accordance with SFAS No. 157, 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. As required, 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 SFAS No. 157. The Partnership generally applies the “market approach” to determine fair value. This method uses pricing and other information generated by market transactions for identical or comparable assets and liabilities. Assets and liabilities are classified within the fair value hierarchy based on the lowest level (least observable) input that is significant to the measurement in its entirety. The Partnership’s financial instruments recorded at fair value were not material at December 31, 2008.

In addition, in February 2007, Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”) was issued and became effective January 1, 2008. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other eligible items at fair value that were not previously required to be measured at fair value, with unrealized gains and losses on such items reported in earnings. The Partnership did not adopt the use of fair value measurements for any new items as of the January 1, 2008 effective date of this new standard.

Lease Accounting

The Partnership applies the provisions of Emerging Issues Task Force Issue 01-8, “Determining Whether an Arrangement Contains a Lease” (“EITF 01-8”). EITF 01-8 provides guidance in determining whether an arrangement meets the definition of a lease under the provisions of SFAS No. 13, “Accounting for Leases” (“SFAS No. 13”). SFAS No. 13 defines a lease as an agreement conveying the right to use property, plant or equipment for a stated period of time. EITF 01-8 provides criteria to determine whether an arrangement conveys the right to use property, plant and equipment under SFAS No. 13. The accounting requirements under EITF 01-8 could affect an arrangement’s timing of revenue and expense recognition, and revenues previously reported as transportation and storage services might have to be reported as rental or leasing income. However, the timing of the cash receipts associated with these agreements would not be impacted by the accounting requirements under EITF 01-8. The provisions of EITF 01-8 are to be applied prospectively to arrangements agreed to, modified, or acquired in business combinations after July 1, 2003. During 2006, 2007 and 2008 previous arrangements that would be leases or would contain a lease according to this pronouncement were recorded in accordance with their prior accounting treatment. The Partnership is continually analyzing its agreements that were in existence prior to July 1, 2003 to determine if the accounting for these agreements would be impacted upon renewal or amendment. The provisions of EITF 01-8 had no material impact on the Partnership’s financial statements for the years ended December 31, 2006, 2007 and 2008.

Earnings Per Unit

In March 2008, the Emerging Issues Task Force (“EITF”) ratified its consensus on Issue No. 07-04, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships.” EITF 07-04 will require incentive distribution rights (“IDRs”) in a master limited partnership to be treated as participating securities for the purpose of computing earnings per unit. EITF 07-04 also requires that when earnings differ from cash distributions, undistributed or over distributed earnings are to be allocated to the IDR holders, the general partner, and limited partners based on the contractual terms of the partnership

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

agreement. EITF 07-04 is effective for the reporting periods beginning after December 15, 2008 and is to be applied retrospectively as a change in accounting principle on an arrangement by arrangement basis. The Partnership will adopt the requirements of EITF 07-04 effective January 1, 2009.

2. Equity Offerings

In May 2006, the Partnership sold 2.4 million common units in a public offering. In June 2006, the Partnership sold an additional 280,000 common units to cover over-allotments in connection with the May 2006 sale. The purchase price for the over allotment was equal to the offering price in the May 2006 sale. The sale of units resulted in total gross proceeds of $115.2 million, and net proceeds of $110.3 million, after the underwriters’ commission and legal, accounting and other transaction expenses. Net proceeds of the offering, together with the $173.3 million in net proceeds from the concurrent offering of Senior Notes (see Note 9), were used to repay $216.1 million of the debt incurred under the previous credit facility, to fund the Partnership’s 2006 organic growth program, and for general partnership purposes. Also as a result of the issuance of these units, the general partner contributed $2.4 million to the Partnership to maintain its 2.0 percent general partner interest. At December 31, 2008, Sunoco’s ownership in the Partnership, including its 2.0 percent general partner interest, was 43.3 percent.

3. Related Party Transactions

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 $7.7 million, $6.5 million and $6.0 million for the years ended December 31, 2006, 2007, and 2008, 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 2009. The 2009 annual fee remains at $6.0 million. These costs may be increased if the acquisition or construction of new assets or businesses require an increase in the level of general and administrative services

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

received by the Partnership. There can be no assurance that Section 4.1 of the Omnibus Agreement will be extended beyond 2009, 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 $3.2 million, $3.9 million and $3.2 million for the years ended December 31, 2006, 2007 and 2008 respectively. The Partnership’s share of allocated Sunoco employee benefit plan expenses, including non-contributory defined benefit retirement plans, defined contribution 401(k) plans, employee and retiree medical, dental and life insurance plans, incentive compensation plans and other such benefits was $22.5 million, $23.0 million and $22.8 million for the years ended December 31, 2006, 2007 and 2008 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 and storage services to Sunoco. Sales of crude oil are priced using market based rates. Pipeline revenues are generally determined using posted tariffs. In 2002, the Partnership entered into a pipelines and terminals storage and throughput agreement and various other agreements with Sunoco under which the Partnership is charging Sunoco fees for services provided under these agreements that, in management’s opinion, are comparable to those charged in arm’s-length, third-party transactions. Under the pipelines and terminals storage and throughput agreement, Sunoco has agreed to pay the Partnership a minimum level of revenues for transporting refined products. Sunoco also has agreed to minimum throughputs of crude oil and liquefied petroleum gas in the Partnership’s Inkster Terminal, Fort Mifflin Terminal Complex and certain crude oil pipelines. During the first quarter of 2007, the agreement to throughput at the Partnership’s refined product terminals and to receive and deliver refined product into the Partnership’s Marcus Hook Tank Farm expired. On March 1, 2007 the Partnership entered into new five year agreements with Sunoco to provide these services. These new agreements contain no minimum throughput obligations for Sunoco.

Under various other agreements entered into in 2002, Sunoco is, among other things, purchasing from the Partnership, at market-based rates, particular grades of crude oil that the Partnership’s crude oil acquisition and marketing business purchases for delivery to certain pipelines. These agreements automatically renew on a monthly basis unless terminated by either party on 30 days’ written notice. During the years ended December 31, 2005 and 2006 two of these agreements were terminated by Sunoco, however the cancellations have not had a material impact on the Partnership’s results of operations. Sunoco also leases the Partnership’s 58 miles of interrefinery pipelines between Sunoco’s Philadelphia and Marcus Hook refineries for a term of 20 years.

Capital Contributions

The Omnibus Agreement requires Sunoco to: reimburse the Partnership for any operating expenses and capital expenditures in excess of $8.0 million per year in each calendar year through 2006 that are made to comply with the U.S. Department of Transportation’s (“DOT”) pipeline integrity management rule, subject to a maximum aggregate reimbursement of $15.0 million over the five-year period ending December 31, 2006; complete, at its expense, certain tank maintenance and inspection projects at the Darby Creek Tank Farm; and reimburse the Partnership for up to $10.0 million of expenditures required at the Marcus Hook Tank Farm and

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

the Darby Creek Tank Farm to maintain compliance with existing industry standards and regulatory requirements. As of December 31, 2008, the Partnership has received the cumulative reimbursement under these agreements and does not expect to be reimbursed by Sunoco for these expenditures going forward.

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, 2006, 2007 and 2008 the Partnership incurred maintenance capital expenditures of $2.3 million, $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.

In February 2008, 2007 and 2006 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 May 2006, the Partnership sold 2.4 million common units in a public offering. In June 2006, the Partnership sold an additional 280,000 common units to cover over-allotments in connection with the May 2006 sale (see Note 2). As a result of this issuance of 2.68 million common units, the general partner contributed $2.4 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.

Asset Acquisitions

4. Acquisitions

On November 18, 2008, the Partnership purchased a refined products pipeline system 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 product facilities located in Hearne, Hebert, Waco, Center and Waskom, Texas and Arcadia, Louisiana with active storage capacity of 0.5 million shell barrels. The purchase price of the acquisition was initially funded with borrowings under the Operating Partnership’s $400 million Credit Facility. The purchase price has been preliminarily allocated to the

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NOTES TO FINANCIAL STATEMENTS—(Continued)

assets and liabilities acquired based on their relative fair values on the acquisition date. The following is a summary of the effects of the transaction on the Partnership’s consolidated financial position (in thousands of dollars):


Increase in:
Inventories	$	553
Environmental liabilities		(2,093	)
Properties, plants and equipment, net		187,503

Cash paid for acquisition	$	185,963

The results of the acquisition are included in the financial statements within the Eastern Pipeline System and Terminal Facilities business segments from the date of acquisition.

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 from the date of acquisition.

On August 18, 2006, the Partnership purchased from Sunoco a 100 percent interest in Sun Pipe Line Company of Delaware LLC, the owner of a 55.3 percent equity interest (50 percent voting rights) in Mid-Valley Pipeline Company (“Mid-Valley”) for approximately $65.0 million, subject to certain adjustments five years following the date of closing, based on the throughput of Sunoco. Mid-Valley owns a 994-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 shell barrels of storage capacity. Mid-Valley provides crude oil to a number of refineries, primarily in the Midwest United States. The purchase price of the acquisition was initially funded with $46.0 million in borrowings under the Operating Partnership’s previous credit facility and with cash on hand. Since the acquisition was from a related party, the interest in the entity was recorded by the Partnership at Sunoco’s historical cost of approximately $12.5 million and the $52.5 million difference between the purchase price and the cost basis of the assets was recorded by the Partnership as a capital distribution. The results of the acquisition are included in the financial statements within the Western Pipeline System business segment from the date of acquisition.

On March 1, 2006, the Partnership purchased a Texas crude oil pipeline system from affiliates of Black Hills Energy, Inc. for approximately $40.9 million. The system consists of (a) the Millennium Pipeline, a 200-mile, 12-inch crude oil pipeline with approximately 65,000 bpd operating capacity, originating near the Partnership’s Nederland Terminal, and terminating at Longview Texas; (b) the Kilgore Pipeline, a 190-mile, 10-inch crude oil pipeline with approximately 35,000 barrel per day capacity originating in Kilgore, Texas and terminating at refineries in the Houston, Texas region; (c) approximately 900,000 shell barrels of active storage capacity at Kilgore, and Longview, Texas, approximately 550,000 of which are inactive; (d) a crude oil sales and marketing business; and (e) crude oil line fill and working inventory. The purchase price of the acquisition was initially funded with borrowings under the Operating Partnership’s previous credit facility. The purchase price

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NOTES TO FINANCIAL STATEMENTS—(Continued)

has been allocated to the assets acquired based on their relative fair values at the acquisition date. The following is a summary of the effects of the transaction on the Partnership’s consolidated financial position (in thousands of dollars):


Increase in:
Inventories	$	2,189
Properties, plants and equipment, net		38,711

Cash paid for acquisition	$	40,900

The results of the acquisition are included in the financial statements within the Western Pipeline System business segment from the date of acquisition.

On March 1, 2006, the Partnership acquired a Texas crude oil pipeline system from Alon USA Energy, Inc. for approximately $68.0 million. The system consists of (a) the Amdel Pipeline, a 503-mile, 10-inch common carrier crude oil pipeline with approximately 27,000 bpd operating capacity, originating at the Nederland Terminal, and terminating at Midland, Texas, and (b) the White Oil Pipeline, a 25-mile, 10-inch crude oil pipeline with approximately 40,000 bpd operating capacity, originating at the Amdel Pipeline and terminating at Alon’s Big Spring, Texas refinery. The pipelines were idle at the time of purchase, were re-commissioned by the Partnership during the second quarter 2006 and began making deliveries during the fourth quarter 2006. During the first quarter of 2007, the Partnership completed a project to expand the capacity on the Amdel Pipeline from approximately 27,000 to 40,000 bpd. Construction on new tankage at the Nederland Terminal to service these new volumes more efficiently was completed during 2008. The purchase price of the acquisition was initially 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 Western Pipeline System business segment from the date of acquisition.

5. Net Income Per Unit Data

Basic and diluted net income per limited partner unit is calculated by dividing net income, after deducting the amount allocated to the general partner’s interest, by the weighted-average number of limited partner common and subordinated units outstanding during the period.

Emerging Issues Task Force Issue No. 03-06 (“EITF 03-06”) “Participating Securities and the Two-Class Method under FASB Statement No. 128” addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity. EITF 03-06 provides that the general partner’s interest in net income is to be calculated based on the amount that would be allocated to the general partner if all the net income for the period were distributed, and not on the basis of actual cash distributions for the period. The application of EITF 03-06 results in an income allocation for earnings per limited partner unit which may be different than the income allocation of the capital accounts, which is based on the partnership agreement.

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 $11.2 million (representing 12.4 percent of total net income for the period) for the year ended December 31, 2006, $24.1 million (representing 20.0 percent of total net income for the period) for the year ended December 31, 2007, and $70.9 million

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NOTES TO FINANCIAL STATEMENTS—(Continued)

(representing 33.0 percent of total net income for the period) for the year ended December 31, 2008. 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, 2006, 2007 and 2008:


	2006	2007	2008
Weighted average number of limited partner units outstanding—basic	27,608,565	28,581,032	28,650,069
Add effect of dilutive unit incentive awards	129,451	148,121	186,534

Weighted average number of limited partner units—diluted	27,738,016	28,729,153	28,836,603

6. Inventories

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


	December 31,
	2007		2008
Crude oil	$	29,145	$	87,645
Refined product		682		1,670
Materials, supplies and other		842		841

	$	30,669	$	90,156

The current replacement cost of crude oil inventory exceeded its carrying value by $165.2 million and $44.7 million at December 31, 2007 and 2008, respectively.

7. Properties, Plants and Equipment

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


	Estimated Useful Lives	December 31,
	Estimated Useful Lives	2007			2008
Land and land improvements (including rights of way)	—	$	80,832		$	89,457
Pipeline and related assets	38 - 60		779,058			967,469
Terminals and storage facilities	5 - 44		475,717			537,702
Other	5 - 48		210,517			225,827
Construction-in-progress	—		79,658			125,362

			1,625,782			1,945,817
Less: Accumulated depreciation and amortization			(536,520	)		(570,388	)

		$	1,089,262		$	1,375,429

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NOTES TO FINANCIAL STATEMENTS—(Continued)

8. Investment in Affiliates

The Partnership’s ownership percentages in corporate joint ventures as of December 31, 2007 and 2008 are as follows:


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

⁽¹⁾	Mid-Valley Pipeline Company was acquired in August 2006 and includes 50 percent voting rights.

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


	2006		2007		2008
Income Statement Data:
Total revenues	$	454,258	$	513,302	$	470,146
Income before income taxes	$	177,876	$	208,067	$	151,446
Net income	$	111,521	$	132,654	$	95,700
Balance Sheet Data (as of year-end):
Current assets	$	104,276	$	181,683	$	115,097
Non-current assets	$	489,514	$	692,331	$	682,453
Current liabilities	$	111,476	$	122,229	$	123,423
Non-current liabilities	$	399,826	$	661,777	$	591,101
Net equity	$	83,028	$	90,008	$	83,026

The Partnership’s investments in Wolverine, West Shore, Yellowstone, and West Texas Gulf at December 31, 2008 include an excess investment amount of approximately $53.7 million, net of accumulated amortization of $3.9 million. The excess investment is the difference between the investment balance and the Partnership’s proportionate share of the net assets of the entities.

9. Long-Term Debt & Revolving Credit Facilities

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


	December 31,
	2007			2008
$400 million Credit Facility – due November 2012	$	91,000		$	323,385
$100 million Credit Facility – due May 2009		—			—
Senior Notes—7.25%, due February 15, 2012		250,000			250,000
Senior Notes—6.125%, due May 15, 2016		175,000			175,000
Less unamortized bond discount		(896	)		(754	)

	$	515,104		$	747,631

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NOTES TO FINANCIAL STATEMENTS—(Continued)

$400 Million Credit Facility

Sunoco Logistics Partners Operations L.P. (the “Operating Partnership”), a wholly-owned entity of the Partnership, has a five-year $400 million revolving credit facility (“$400 million Credit Facility”) with a syndicate of 10 participating financial institutions. The $400 million Credit Facility is available to fund the Operating Partnership’s working capital requirements, to finance future acquisitions, to finance future capital projects and for general partnership purposes. The $400 million Credit Facility matures in November 2012 and may be prepaid at any time. It bears interest at the Operating Partnership’s option, at either (i) LIBOR plus an applicable margin, (ii) the higher of the federal funds rate plus 0.50 percent or the Citibank prime rate (each plus the applicable margin) or (iii) the federal funds rate plus an applicable margin. The $400 million Credit Facility contains various covenants limiting the Operating Partnership’s ability to incur indebtedness; grant certain liens; make certain loans, acquisitions and investments; make any material change to the nature of its business; acquire another company; or enter into a merger or sale of assets, including the sale or transfer of interests in the Operating Partnership’s subsidiaries. The $400 million Credit Facility also limits the 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. The Operating Partnership is in compliance with this requirement as of December 31, 2008.

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

$100 Million Credit Facility

In anticipation of the MagTex Acquisition, the Operating Partnership, entered into a $100 million 364 day revolving credit facility (“$100 million Credit Facility”) on May 28, 2008. The $100 million Credit Facility is available to fund the same activities as the $400 million Credit Facility described above. The $100 million Credit Facility matures in May 2009 and can be prepaid at any time. Interest on outstanding borrowings is calculated, at the Operating Partnership’s option, using either (i) LIBOR plus an applicable margin or (ii) the higher of (a) the Federal funds rates plus 0.50 percent plus an applicable margin, and (b) the Citibank prime rate plus an applicable margin. The $100 million Credit Facility contains the same covenant requirements as the $400 million Credit Facility described above. As of December 31, 2008 there were no borrowings outstanding under the $100 million Credit Facility.

Interest Rate Swap

The Partnership uses interest rate swaps, a type of derivative financial instrument, to manage interest costs and minimize the effects of interest rate fluctuations on cash flows associated with its credit facilities. The Partnership does not use derivatives for trading or speculative purposes. While interest rate swaps are subject to fluctuations in value, these fluctuations are generally offset by the value of the underlying exposures being hedged. The Partnership minimizes the risk of credit loss by entering into these agreements with financial institutions that have high credit ratings. The Partnership accounts for its interest rate swaps in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), which requires that all derivatives be recorded on the balance sheet at fair value. SFAS 133 also requires that changes in the fair value be recorded each period in current earnings or other comprehensive income, depending on whether a derivative has been designated as part of a hedge transaction and, if it is, depending on the type of hedge transaction. Interest rate swaps are designated as cash flow hedges. Changes in the fair value of a cash flow hedge, to the extent the hedge is effective, are recorded, net of tax, in other comprehensive income (loss), a component of Partners’ capital, until earnings are affected by the variability of the hedged cash flows. Cash flow

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NOTES TO FINANCIAL STATEMENTS—(Continued)

hedge ineffectiveness, defined as the extent that the changes in the fair value of the derivative exceed the variability of cash flows of the forecasted transaction, is recorded currently in earnings.

In January 2008, the Partnership entered into a $50.0 million floating to fixed interest rate swap agreement (the “Swap”), maturing January 2010. Under the Swap, the Partnership receives interest equivalent to the three-month LIBOR and pays a fixed rate of interest of 3.489 percent, with settlements occurring quarterly. The objective of the hedge is to eliminate the variability of cash flows in interest payments for $50.0 million of floating rate debt. To maintain hedge accounting for the Swap, the Partnership is committed to maintaining at least $50.0 million in borrowings at an interest rate based on the three-month LIBOR, plus an applicable margin, through January 2010. The Swap’s fair value of ($1.1) million as of December 31, 2008, is included in accrued liabilities on the balance sheet and the corresponding change in fair value is included in other comprehensive income, a component of Partners’ equity. There was no cash flow hedge ineffectiveness recorded during 2008.

Senior Notes

In 2002, the Operating Partnership issued $250 million of 7.25 percent Senior Notes, due February 15, 2012 (the “2012 Senior Notes”) at 99.325 percent of the principal amount, for net proceeds of $244.8 million after the underwriter’s commission and legal, accounting and other transaction expenses. The 2012 Senior Notes are redeemable, at a make-whole premium, and are not subject to sinking fund provisions. The 2012 Senior Notes contain various covenants limiting the Operating Partnership’s ability to incur certain liens, engage in sale/leaseback transactions, or merge, consolidate or sell substantially all of its assets. The Operating Partnership is in compliance with these covenants as of December 31, 2008. In addition, the 2012 Senior Notes are also subject to repurchase by the Operating Partnership at a price equal to 100 percent of their principal amount, plus accrued and unpaid interest upon a change of control to a non-investment grade entity.

On May 2, 2006, the Operating Partnership issued $175 million of 6.125 percent Senior Notes, due May 15, 2016 (the “2016 Senior Notes”) at 99.858 percent of the principal amount, for net proceeds of $173.3 million after the underwriter’s commission and legal, accounting and other transaction expenses. The 2016 Senior Notes are redeemable, at a make-whole premium, and are not subject to sinking fund provisions. The 2016 Senior Notes contain various covenants limiting the Operating Partnership’s ability to incur certain liens, engage in sale/leaseback transactions, or merge, consolidate or sell substantially all of its assets. The Operating Partnership is in compliance with these covenants as of December 31, 2008.

The Partnership has no operations and its only assets are its investments in its wholly-owned partnerships and subsidiaries. The Operating Partnership also has no operations and its assets are limited primarily to its investments in its wholly-owned operating partnerships, deferred charges, and cash and cash equivalents of $2.0 million. Except for amounts associated with the 2012 Senior Notes and 2016 Senior Notes, the $400 million and $100 million Credit Facilities, cash and cash equivalents and advances to affiliate, the assets and liabilities in the balance sheets and the revenues and costs and expenses in the statements of income are primarily attributable to the operating partnerships. See Note 17 for supplemental condensed consolidating financial information.

The Partnership and the operating partnerships of the Operating Partnership served as joint and several guarantors of the 2012 Senior Notes and 2016 Senior Notes and of any obligations under the previous credit facility. The Partnership continues to serve as guarantor of the 2012 Senior Notes and 2016 Senior Notes and of any obligations under the $400 million and $100 million Credit Facilities. These guarantees are full and unconditional. In connection with the Partnership’s $400 million credit facility the Subsidiary Guarantors (as defined in Note 17) were released from their obligations under the previous credit facility, and the 2012 and 2016 Senior Notes. See Note 17 for supplemental condensed consolidating financial information.

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NOTES TO FINANCIAL STATEMENTS—(Continued)

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


Year Ended December 31:
2012	$	573,385
Thereafter		175,000

	$	748,385

Cash payments for interest related to long-term debt, net of capitalized interest (see Note 1), were, $24.7 million, $32.0 million and $32.4 million in 2006, 2007 and 2008, respectively.

10. Commitments and Contingent Liabilities

Total rental expense for 2006, 2007 and 2008 amounted to $5.8 million, $6.6 million and $6.1 million, respectively. The Partnership, as lessee, has noncancelable operating leases for land, office space and equipment for which the aggregate amount of future minimum annual rentals as of December 31, 2008 is as follows (in thousands of dollars):


Year Ended December 31:
2009	$	3,079
2010		2,625
2011		2,477
2012		2,418
2013		599
Thereafter		1,985

Total	$	13,182

The Partnership is subject to numerous federal, state and local laws which regulate the discharge of materials into the environment or that otherwise relate to the protection of the environment. These laws and regulations result in liabilities and loss contingencies for remediation at the Partnership’s facilities and at third-party or formerly owned sites. At December 31, 2007 and 2008, there were accrued liabilities for environmental remediation in the balance sheets of $1.1 million and $3.6 million, respectively. The accrued liabilities for environmental remediation do not include any amounts attributable to unasserted claims, nor have any recoveries from insurance been assumed. Charges against income for environmental remediation totaled $1.3 million, $4.8 million and $2.1 million for the years ended December 31, 2006, 2007 and 2008, respectively.

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

The Partnership is a party to certain pending and threatened claims. Although the ultimate outcome of these claims cannot be ascertained at this time, it is reasonably possible that some portion of them could be resolved unfavorably to the Partnership and its predecessor. Management does not believe that any liabilities which may

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NOTES TO FINANCIAL STATEMENTS—(Continued)

arise from such claims and the environmental matters discussed above would be material in relation to the financial position of the Partnership at December 31, 2008. Furthermore, management does not believe that the overall costs for such matters will have a material impact, over an extended period of time, on the Partnership’s operations, cash flows or liquidity.

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

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

Management of the Partnership does not believe that any liabilities which may arise from claims indemnified by Sunoco would be material in relation to the financial position of the Partnership at December 31, 2008. There are certain other pending legal proceedings related to matters arising after the February 2002 IPO that are not indemnified by Sunoco. Management believes that any liabilities that may arise from these legal proceedings will not be material in relation to the financial position of the Partnership at December 31, 2008.

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

11. Management Incentive Plan

Sunoco Partners LLC, the general partner of the Partnership, has adopted the Sunoco Partners LLC Long-Term Incentive Plan (“LTIP”) for employees and directors of the general partner who perform services for the Partnership. The LTIP is administered by the independent directors of the Compensation Committee of the general partner’s board of directors with respect to employee awards, and by the non-independent members of

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NOTES TO FINANCIAL STATEMENTS—(Continued)

the general partners’ board of directors with respect to awards granted to the independent members. The LTIP currently permits the grant of restricted units and unit options covering an aggregate of 1,250,000 common units.

Restricted Units

A restricted unit entitles the grantee to receive a common unit or, at the discretion of the Compensation Committee, an amount of cash equivalent to the value of a common unit upon the vesting of the unit, which may include the attainment of predetermined performance targets. The Compensation Committee may make additional grants under the LTIP to employees and directors containing such terms as the Compensation Committee shall determine. Common units to be delivered to the grantee upon vesting may be common units acquired by the general partner in the open market, common units already owned by the general partner, common units acquired by the general partner directly from the Partnership or any other person, or any combination of the foregoing. The general partner will be entitled to reimbursement by the Partnership for the cost incurred in acquiring common units. If the Partnership issues new common units upon vesting of the restricted units, the total number of common units outstanding will increase. The Compensation Committee, in its discretion, may grant tandem distribution equivalent rights (“DERs”) with respect to the restricted units. Subject to applicable vesting criteria, DERs entitle the grantee to receive an amount of cash equal to the per unit cash distributions made by the Partnership during the period the restricted unit is outstanding. During the years ended December 31, 2006, 2007 and 2008, the Partnership granted 59,930, 79,190 and 62,048 restricted units, respectively. Although some of these awards are time-vested only, most are subject to the Partnership achieving certain market-based and cash distribution performance targets as compared to a peer group average, which can cause the actual amount of units that ultimately vest to range from between 0% to 200% of the original units granted. These restricted unit awards generally vest over a three-year period,.

The following table summarizes information regarding restricted unit award activity during the year ended December 31, 2008:

Restricted Unit Award Activity


	Number of Units ⁽¹⁾		Weighted Average Grant- Date Fair Value
Non-vested and outstanding, beginning of year	129,342		$	51.72
Granted	62,048		$	52.92
Performance Factor Adjustment	52,726		$	44.32
Vested	(108,523	)	$	44.75
Cancelled/forfeited	(1,457	)	$	52.53

Non-vested and outstanding, end of year	134,136		$	55.00

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

The total intrinsic value of restricted unit awards vested during the years ended December 31, 2006, 2007 and 2008 was $3.6 million, $4.3 million, and $4.9 million, respectively. Non-vested and outstanding restricted unit awards at December 31, 2008 had a contractual life of one to five years.

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

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NOTES TO FINANCIAL STATEMENTS—(Continued)

accordance with SFAS No. 123R, the Partnership is recognizing compensation expense on a straight-line basis over the requisite service period as well as estimating forfeitures over the requisite service period when recognizing compensation expense.

Fair Value Assumptions


Year Ended December 31,	2006		2007		2008
Expected unit-price volatility		19.2%		17.2%		18.7%
Dividend Yield		7.0%		6.1%		7.1%
Risk-free interest rate		4.9%		4.9%		2.3%
Weighted average fair value of performance units granted during the year	$	44.31	$	56.27	$	52.96

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

As of December 31, 2008, total compensation cost related to non-vested awards not yet recognized was $1.9 million, and the weighted-average period over which this cost is expected to be recognized in expense is 1.6 years. The number of restricted stock units outstanding and the total compensation cost related to non-vested awards not yet recognized reflects the Partnership’s estimates of performance factors for certain restricted unit awards.

The Partnership recognized share-based compensation expense related to the LTIP of $3.7 million, $5.3 million, and $4.3 million in the years ended December 31, 2006, 2007 and 2008 respectively under SFAS No. 123R related to the unit grants and performance factor adjustments noted in the table above. Each of the restricted unit grants also have tandem DERs which are recognized as a reduction of Partners’ Capital when earned.

Unit Options

A unit option entitles the grantee to purchase a common unit at a price determined at the date of grant by the Compensation Committee. There have been no grants of unit options for the years ended December 31, 2006, 2007 and 2008, and there are no unit options outstanding as of December 31, 2008. However, the Compensation Committee may, in the future, make grants under the LTIP to employees and directors containing such terms as the Compensation Committee shall determine, provided that unit options have an exercise price no less than the fair market value of the units on the date of grant.

12. Cash Distributions

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

The Partnership issued 11,383,639 subordinated units to its general partner in connection with the initial public offering in February 2002. These subordinated units were convertible to common units on a one-for-one

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NOTES TO FINANCIAL STATEMENTS—(Continued)

basis provided the Partnership met applicable financial tests set forth in the Partnership Agreement. Once converted, subordinated units are no longer subordinated to the rights of the holders of common units. The Partnership met the minimum quarterly distribution requirements on all outstanding units for each of the four- quarter periods ended December 31, 2005 and 2006. As a result, the subordinated units converted to common units during 2005 through 2007.

After the subordination period, the Partnership will, in general, pay cash distributions each quarter in the following manner:


	Percentage of Distributions
Quarterly Cash Distribution Amount per Unit	Unitholders		General Partner
Up to minimum quarterly distribution ($0.45 per Unit)	98	%	2	%
Above $0.45 per Unit up to $0.50 per Unit	98	%	2	%
Above $0.50 per Unit up to $0.575 per Unit	85	%	15	%
Above $0.575 per Unit up to $0.70 per Unit	75	%	25	%
Above $0.70 per Unit	50	%	50	%

If cash distributions exceed $0.50 per unit in a quarter, the 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 “Percentage of Distributions” are the percentage interests of the general partner and the 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 the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

Distributions paid by the Partnership during the years ended December 31, 2006, 2007 and 2008 were as follows:


Date Cash Distribution Paid	Cash Distribution per Limited Partner Unit		Annualized Cash Distribution per Limited Partner Unit		Total Cash Distribution to the Limited Partners		Total Cash Distribution to the General Partner
					($ in millions)		($ in millions)
February 14, 2006	$	0.7125	$	2.85	$	18.4	$	2.0
May 15, 2006	$	0.75	$	3.00	$	21.4	$	3.3
August 14, 2006	$	0.775	$	3.10	$	22.1	$	4.0
November 14, 2006	$	0.7875	$	3.15	$	22.4	$	4.4

February 14, 2007	$	0.8125	$	3.25	$	23.2	$	5.1
May 15, 2007	$	0.8250	$	3.30	$	23.6	$	5.4
August 14, 2007	$	0.8375	$	3.35	$	23.9	$	5.8
November 14, 2007	$	0.8500	$	3.40	$	24.3	$	6.1

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

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

On January 28, 2009, the Partnership declared a cash distribution of $0.990 per unit ($3.96 per unit annualized) on its outstanding common and subordinated units, representing the distribution for the quarter ended December 31, 2008. The $38.6 million distribution, including $10.2 million to the general partner, was paid on February 13, 2009 to unitholders of record at the close of business on February 9, 2009.

13. Financial Instruments and Concentration of Credit Risk

The estimated fair value of financial instruments has been determined based on the Partnership’s assessment of available market information and appropriate valuation methodologies. The Partnership’s current assets (other than inventories) and current liabilities are financial instruments. The estimated fair value of these financial instruments approximates their carrying amounts. The estimated fair value of the $91.0 million and $323.4 million of borrowings under the $400 million Credit Facility at December 31, 2007 and 2008 approximate their carrying amounts as these borrowings bear interest based upon short-term interest rates. The estimated fair value of the 2012 and 2016 Senior Notes at December 31, 2007 and 2008 was $449.3 million and $416.2 million, respectively, compared to the carrying amount of $425.0 million at December 31, 2007 and 2008. The 2012 and 2016 Senior Notes, which are publicly traded, were valued based upon quoted market prices.

Approximately 25 percent of total revenues recognized by the Partnership during 2008 was derived from Sunoco. The Partnership sells crude oil to Sunoco, transports crude oil and refined products to/from Sunoco’s refineries and provides terminalling and storage services for Sunoco. Sunoco has been issued an investment grade credit rating by three recognized agencies and, accordingly, management of the Partnership does not believe that the transactions with Sunoco expose it to significant credit risk.

The Partnership’s other trade relationships are primarily with major integrated oil companies, independent oil companies and other pipelines and wholesalers. These concentrations of customers may affect the Partnership’s overall credit risk in that the customers (including Sunoco) may be similarly affected by changes in economic, regulatory or other factors. The Partnership’s customers’ credit positions are analyzed prior to extending credit and periodically after the credit has been extended. The Partnership manages its exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions may utilize letters of credit, prepayments and guarantees.

14. Business Segment Information

The Partnership operates in three principal business segments: Eastern Pipeline System, Terminal Facilities and Western Pipeline System.

•

The Eastern Pipeline System also includes the MagTex refined product pipeline system which was acquired from Mobil Pipeline Company, an affiliate of Exxon Mobil Corporation, in November 2008. The system consists of approximately 500 miles of refined product pipelines located in Texas. Although

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

these assets are physically located in the southwestern United States, we have included these assets in the Eastern Pipeline System along with our existing refined products pipelines.

•

The Terminal Facilities consist of 41 refined product terminals with an aggregate storage capacity of 6.7 million barrels, primarily serving the Partnership’s Eastern Pipeline System; the Nederland Terminal, a 17.1 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; a ship and barge dock which serves Sunoco’s Eagle Point refinery; and a 1.0 million barrel liquefied petroleum gas (“LPG”) terminal near Detroit, Michigan.

•

The Western Pipeline System gathers, purchases, sells, and transports crude oil principally in Oklahoma and Texas and consists of approximately 3,200 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 115 crude oil transport trucks; approximately 100 crude oil truck unloading facilities; a 55.3 percent interest in the Mid-Valley Pipeline Company, a joint venture that owns a 994-mile crude oil pipeline and a 43.8 percent interest in West Texas Gulf Pipe Line Company, a joint venture that owns a 579-mile crude oil pipeline.

Segment Information (in thousands of dollars)


	Year Ended December 31, 2006
	Eastern Pipeline System			Terminal Facilities		Western Pipeline System			Total
Sales and other operating revenue:
Affiliates	$	77,228		$	82,607	$	1,682,799		$	1,842,634

Unaffiliated customers	$	28,408		$	40,635	$	3,925,558		$	3,994,601

Operating income	$	44,239	⁽¹⁾	$	39,140	$	34,815	⁽²⁾	$	118,194

Net interest expense										(27,853	)

Net income									$	90,341

Depreciation and amortization	$	9,550		$	15,364	$	11,735		$	36,649

Capital expenditures	$	31,176		$	61,046	$	27,616	⁽³⁾	$	119,838

Investment in affiliates	$	58,849		$	—	$	23,085		$	81,934

Identifiable assets	$	367,718		$	341,878	$	1,346,232		$	2,082,077	⁽⁴⁾

⁽¹⁾	Includes equity income of $11,012 attributable to the Partnership’s equity ownership interests in Explorer, Wolverine, West Shore and Yellowstone.

⁽²⁾	Includes equity income of $5,870 attributable to the Partnership’s equity ownership interest in West Texas Gulf and Mid-Valley.

⁽³⁾	Excludes $108,900 for the acquisition of the Amdel and White Oil crude oil pipeline system, and Millennium and Kilgore crude oil pipeline system and, $12,482 related to the acquisition of a 55.3 percent equity interest in Mid-Valley Pipeline Company.

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

⁽⁴⁾	Identifiable assets include the Partnership’s unallocated $9,412 cash and cash equivalents, $7,431 advances to affiliates, $7,204 deferred financing costs, $2,198 to properties, plants and equipment, net and $4 attributable to corporate activities.


	Year Ended December 31, 2007
	Eastern Pipeline System			Terminal Facilities		Western Pipeline System			Total
Sales and other operating revenue:
Affiliates	$	81,866		$	92,156	$	1,508,020		$	1,682,042

Unaffiliated customers	$	35,475		$	49,466	$	5,610,472		$	5,695,413

Operating income	$	49,406	⁽¹⁾	$	52,668	$	54,081	⁽²⁾	$	156,155

Net interest expense										(35,280	)

Net income									$	120,875

Depreciation and amortization	$	9,165		$	15,338	$	12,838		$	37,341

Capital expenditures	$	11,916	⁽³⁾	$	64,381	$	25,703		$	105,862	⁽⁴⁾

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

Identifiable assets	$	370,278		$	400,509	$	1,710,093		$	2,504,642	⁽⁵⁾

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

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

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

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

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

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)


	Year Ended December 31, 2008
	Eastern Pipeline System			Terminal Facilities		Western Pipeline System			Total
Sales and other operating revenue:
Affiliates	$	88,773		$	99,976	$	2,383,198		$	2,571,947

Unaffiliated customers	$	37,012		$	62,448	$	7,440,913		$	7,540,373

Operating income	$	58,177	⁽¹⁾	$	58,475	$	128,940	⁽²⁾	$	245,592

Net interest expense										(31,112	)

Net income									$	214,480

Depreciation and amortization	$	10,247		$	16,446	$	13,361		$	40,054
Impairment charge		—			5,674		—			5,674

Capital expenditures	$	12,799	⁽³⁾	$	74,115	$	52,998		$	145,834	⁽⁴⁾

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

Identifiable assets	$	529,705		$	484,349	$	1,270,341		$	2,308,249	⁽⁵⁾

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

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

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

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

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

The following table sets forth total sales and other operating revenue by product or service (in thousands of dollars):


	Year Ended December 31,
	2006		2007		2008
Affiliates:
Crude oil sales	$	1,672,381	$	1,499,437	$	2,376,575
Pipeline		87,646		90,449		95,396
Terminalling and other		82,607		92,156		99,976

	$	1,842,634	$	1,682,042	$	2,571,947

Unaffiliated Customers:
Crude oil sales	$	3,887,795	$	5,565,975	$	7,385,321
Pipeline		66,171		79,972		92,604
Terminalling and other		40,635		49,466		62,448

	$	3,994,601	$	5,695,413	$	7,540,373

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

15. Quarterly Financial Data (Unaudited)

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


	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2007
Sales and other operating revenue:
Affiliates	$	452,069	$	391,370	$	439,776	$	398,827
Unaffiliated customers	$	1,097,501	$	1,238,910	$	1,496,439	$	1,862,563
Gross margin⁽¹⁾	$	41,408	$	40,543	$	50,945	$	51,076
Operating income	$	30,928	$	34,754	$	45,922	$	44,551
Net income	$	22,307	$	25,254	$	37,514	$	35,800
Net income per Limited Partner unit—basic⁽²⁾	$	0.71	$	0.76	$	0.97	$	0.94
Net income per Limited Partner unit—diluted⁽²⁾	$	0.70	$	0.76	$	0.97	$	0.94

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2008
Sales and other operating revenue:
Affiliates	$	636,386	$	756,718	$	760,551	$	418,292
Unaffiliated customers	$	1,758,003	$	2,558,703	$	2,068,956	$	1,154,711
Gross margin⁽¹⁾	$	55,806	$	64,730	$	66,888	$	93,154
Operating income	$	45,201	$	59,387	$	57,863	$	83,141
Net income	$	37,503	$	51,323	$	50,334	$	75,320
Net income per Limited Partner unit—basic⁽²⁾	$	0.97	$	1.21	$	1.20	$	1.63
Net income per Limited Partner unit—diluted⁽²⁾	$	0.97	$	1.21	$	1.19	$	1.62

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

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

16. Subsequent Event

17. Supplemental Condensed Consolidating Financial Information

The Partnership and the operating partnerships of the Operating Partnership served as joint and several guarantors of the Senior Notes and of any obligations under the previous credit facility. The Partnership continues to serve as guarantor of the Senior Notes and of any obligations under the $400 million and $100 million Credit Facilities. These guarantees are full and unconditional. In connection with the Partnership’s $400 million Credit Facility the Subsidiary Guarantors were released from their obligations both under the previous credit facility, and the 2012 and 2016 Senior Notes. Given that certain, but not all subsidiaries of the Partnership

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

were guarantors, the Partnership was required to present the following supplemental condensed consolidating financial information. For purposes of the following footnote, Sunoco Logistics Partners L.P. is referred to as “Parent” and Sunoco Logistics Partners Operations L.P. is referred to as “Subsidiary Issuer.” In the 2007 and 2008 schedules Sunoco Partners Marketing and Terminals L.P., Sunoco Pipeline L.P., Sun Pipeline Company of Delaware LLC, Sunoco Pipeline Acquisition LLC, Sunoco Logistics Partners GP LLC, Sunoco Logistics Partners Operations GP LLC and Sunoco Partners Lease Acquisition & Marketing LLC, are collectively referred to as “Non-Guarantor Subsidiaries.” In the 2006 schedules Sunoco Partners Marketing and Terminals L.P., Sunoco Pipeline L.P., Sun Pipeline Company of Delaware LLC and Sunoco Pipeline Acquisition LLC are collectively referred to as the “Subsidiary Guarantors”, and Sunoco Logistics Partners GP LLC, Sunoco Logistics Partners Operations GP LLC and Sunoco Partners Lease Acquisition & Marketing LLC, are referred to as “Non-Guarantor Subsidiaries.”

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

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

Balance Sheet

December 31, 2007


	Parent		Subsidiary Issuer		Non- Guarantor Subsidiaries			Consolidating Adjustments			Total
Assets
Current Assets
Cash and cash equivalents	$	—	$	2,000	$	—		$	—		$	2,000
Advances to affiliates		4,348		46,000		(42,288	)		—			8,060
Accounts receivable, affiliated companies		—		—		62,167			—			62,167
Accounts receivable, net		—		—		1,200,782			—			1,200,782
Inventories
Crude oil		—		—		29,145			—			29,145
Refined product		—		—		682			—			682
Materials, supplies and other		—		—		842			—			842

Total Current Assets		4,348		48,000		1,251,330			—			1,303,678

Properties, plants and equipment, net		—		—		1,089,262			—			1,089,262
Investment in affiliates		584,060		1,101,139		85,084			(1,685,298	)		84,985
Deferred charges and other assets		—		3,278		23,439			—			26,717

Total Assets	$	588,408	$	1,152,417	$	2,449,115		$	(1,685,298	)	$	2,504,642

Liabilities and Partners’ Capital
Current Liabilities
Accounts payable	$	—	$	—	$	1,289,402		$	—		$	1,289,402
Accrued liabilities		980		3,863		40,316			—			45,159
Accrued taxes		—		—		34,277			—			34,277

Total Current Liabilities		980		3,863		1,363,995			—			1,368,838

Long-term debt		—		515,104		—			—			515,104
Other deferred credits and liabilities		—		—		29,655			—			29,655

Total Liabilities		980		518,967		1,393,650			—			1,913,597

Total Partners’ Capital		587,428		633,450		1,055,465			(1,685,298	)		591,045

Total Liabilities and Partners’ Capital	$	588,408	$	1,152,417	$	2,449,115		$	(1,685,298	)	$	2,504,642

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

Balance Sheet

December 31, 2008


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

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

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

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

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

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

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

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

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

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

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

Statement of Income

Year Ended December 31, 2006


	Parent		Subsidiary Issuer			Subsidiary Guarantors		Non- Guarantor Subsidiaries		Consolidating Adjustments			Total
Revenues
Sales and other operating revenue:
Affiliates	$	—	$	—		$	1,842,634	$	—	$	—		$	1,842,634
Unaffiliated customers		—		—			3,994,601		—		—			3,994,601
Equity in earnings of subsidiaries		90,331		116,967			—		12		(207,310	)		—
Other income		—		—			17,315		—		—			17,315

Total Revenues		90,331		116,967			5,854,550		12		(207,310	)		5,854,550

Costs and Expenses
Cost of products sold and operating expenses		—		—			5,644,021		—		—			5,644,021
Depreciation and amortization		—		—			36,649		—		—			36,649
Selling, general and administrative expenses		—		—			55,686		—		—			55,686

Total Costs and Expenses		—		—			5,736,356		—		—			5,736,356

Operating Income		90,331		116,967			118,194		12		(207,310	)		118,194
Net interest cost paid to affiliates		—		194			1,215		2		—			1,411
Other interest cost and debt expenses, net		—		29,447			—		—		—			29,447
Capitalized interest		—		(3,005	)		—		—		—			(3,005	)

Net Income	$	90,331	$	90,331		$	116,979	$	10	$	(207,310	)	$	90,341

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

Statement of Income

Year Ended December 31, 2007


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

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

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

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

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

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

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

Statement of Income

Year Ended December 31, 2008


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

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

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

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

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

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

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

Statement of Cash Flows

Year Ended December 31, 2006


	Parent			Subsidiary Issuer			Subsidiary Guarantors			Non- Guarantor Subsidiaries			Consolidating Adjustments			Total
Net Cash Flows from Operating Activities	$	90,501		$	91,142		$	167,137		$	10		$	(207,310	)	$	141,480

Cash Flows from Investing Activities:
Capital expenditures		—			—			(119,838	)		—			—			(119,838	)
Acquisitions		—			—			(121,382	)		—			—			(121,382	)
Intercompany		(42,703	)		(190,082	)		25,485			(10	)		207,310			—

		(42,703	)		(190,082	)		(215,735	)		(10	)		207,310			(241,220	)

Cash Flows from Financing Activities:
Distribution paid to Limited Partners and General Partner		(97,987	)		—			—			—			—			(97,987	)
Net proceeds from issuance of Limited Partner units		110,338			—			—			—			—			110,338
Contribution from General Partner for Limited Partner unit transactions		2,427			—			—			—			—			2,427
Net proceeds from issuance of Senior Notes		—			173,307			—			—			—			173,307
Repayments from (advances to) affiliates, net		(9,496	)		(48,000	)		44,315			—			—			(13,181	)
Borrowings under credit facility		—			177,500												177,500
Repayments under credit facility		—			(216,100	)											(216,100	)
Payments of statutory withholding on net issuance of Limited Partner units under restricted unit incentive plan		—			—			(1,443	)		—			—			(1,443	)
Contributions from (distributions to) affiliate		(53,080	)		—			5,726			—			—			(47,354	)

		(47,798	)		86,707			48,598			—			—			87,507

Net change in cash and cash equivalents		—			(12,233	)		—			—			—			(12,233	)
Cash and cash equivalents at beginning of year		—			21,645			—			—			—			21,645

Cash and cash equivalents at end of year	$	—		$	9,412		$	—		$	—		$	—		$	9,412

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

Statement of Cash Flows

Year Ended December 31, 2007


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

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

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

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

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

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

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

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO FINANCIAL STATEMENTS—(Continued)

Statement of Cash Flows

Year Ended December 31, 2008


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

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

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

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

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

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

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

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None

ITEM 9A.

CONTROLS AND PROCEDURES

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

As of December 31, 2008, the Partnership carried out an evaluation, under the supervision and with the participation of the management of the general partner (including the President and Chief Executive Officer and the Vice President and Chief Financial Officer), of the effectiveness of the design and operation of the Partnership’s disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, the general partner’s President and Chief Executive Officer, and its Vice President and Chief Financial Officer, concluded that the Partnership’s disclosure controls and procedures are effective.

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

No change in the Partnership’s internal control over financial reporting has occurred during the fiscal quarter ended December 31, 2008 that has materially affected, or that is reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

ITEM 9B.

OTHER INFORMATION

None.

PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Sunoco Partners LLC, our general partner, is a wholly-owned, indirect subsidiary of Sunoco, Inc. Our general partner manages our operations and activities. Our general partner’s Board of Directors held nine meetings during 2008. The Board has established standing committees to consider designated matters. The standing committees of the Board are the Audit/Conflicts Committee and the Compensation Committee. The Board has adopted governance guidelines for the Board and charters for the standing committees.

The Audit/Conflicts Committee, in its role as an Audit Committee, oversees external financial reporting, engages independent auditors, and reviews procedures for internal auditing and the adequacy of internal accounting controls. In addition, the Audit/Conflicts Committee, in its role as a “Conflicts” Committee, reviews specific matters that the Board believes may involve conflicts of interest between us and Sunoco, Inc. and determines if the resolution of the conflict of interest is fair and reasonable to the Partnership. The Audit/Conflicts Committee met as an Audit Committee eight times during 2008, and met as a Conflicts Committee one time during 2008. The current members of the Audit/Conflicts Committee are: L. Wilson Berry, Jr. (chairman), Stephen L. Cropper, and Philip L. Frederickson. The members of the Audit/Conflicts Committee consist of those directors of our general partner who are not also executive officers of our general partner or its parent, all of whom must meet certain independence and experience standards to serve on an audit committee of a Board of Directors established by the New York Stock Exchange, the NYSE. Our general partner’s Board of Directors has determined that, based upon relevant experience, each member of the Audit/Conflicts Committee (Messrs. Berry, Cropper, and Frederickson) is an “audit committee financial expert,” as defined in Item 407 of Regulation S-K of the Securities Exchange Act of 1934, as amended. A description of each member’s qualifications may be found elsewhere in this Item 10. Our general partner’s Board of Directors has also determined affirmatively that Messrs. Berry, Cropper and Frederickson are independent, as described in the governance guidelines and the New York Stock Exchange rules. In conjunction with regular meetings, the Audit/Conflicts Committee meets in executive session without members of management present. Mr. Berry leads these executive session meetings, the purpose of which is to promote open and candid discussion among the non-management and independent members of the general partner’s Board of Directors.

Because we are a limited partnership and meet the definition of a “controlled company” under the listing standards of the NYSE, we are not required to have a majority of independent directors or a standing nominating or compensation committee of our general partner’s Board of Directors. However, our general partner’s Board of Directors has elected to have a standing compensation committee.

The Compensation Committee of the general partner’s Board of Directors oversees compensation decisions for the officers of the general partner and the administration of the compensation plans described below. The Compensation Committee held four meetings during 2008. The current members of the Compensation Committee are: L. Wilson Berry, Jr., Stephen L. Cropper (chairman), Lynn L. Elsenhans, and Philip L. Frederickson. Since Ms. Elsenhans is also is an officer and director of Sunoco, Inc., she recuses herself from Compensation Committee decisions relating to equity compensation awards.

In order that interested parties may be able to make their concerns known to the non-management directors, our unitholders and other interested parties may communicate directly with the general partner’s Board of Directors, with the non-management directors as a group, or with any director or committee chairperson by writing to such parties in care of Bruce D. Davis, Jr., Vice President, General Counsel and Secretary, Sunoco Partners LLC, Mellon Bank Center, 1735 Market Street, Suite LL, Philadelphia, PA 19103-7583. Communications addressed to the Board generally will be forwarded either to the appropriate committee chairperson or to all directors. Communications may be submitted confidentially and anonymously. Under certain circumstances, we may or the general partner may be required by law to disclose the information or identity of the person submitting the communication. There were no material actions taken by the Board of

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Directors as a result of communications received during 2008 from unitholders or others. Certain concerns communicated to the general partner’s Board of Directors also may be referred to the general partner’s internal auditor or its General Counsel, in accordance with the general partner’s regular procedures for addressing such concerns. The chairman of the general partner’s Board of Directors, or the chairman of the general partner’s Audit/Conflicts Committee may direct that certain concerns be presented to the Audit/Conflicts Committee, or to the full Board, or that they otherwise receive special treatment, including retention of external counsel or other advisors.

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

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

We make available, free of charge within the “Corporate Governance” section of our website at www.sunocologistics.com, and in print to any unitholder who so requests, the Code of Ethics for Senior Officers, the Code of Business Conduct and Ethics, the Audit/Conflicts Committee Charter, the Compensation Committee Charter, the Corporate Governance Guidelines and the our limited partnership agreement. Requests for print copies may be directed to: Investor Relations, Sunoco Logistics Partners L.P., 1735 Market Street, Suite LL, Philadelphia, PA 19103-7583, or telephone (866) 248-4344. The information contained on, or connected to, our internet website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with, or furnishes to, the SEC.

On March 17, 2008, Deborah M. Fretz, President and Chief Executive Officer of Sunoco Partners LLC (our general partner), submitted to the NYSE the Written Affirmation required by the rules of the NYSE certifying our compliance with the NYSE corporate governance listing standards.

The certifications of Ms. Fretz, principal executive officer and Mr. Murphy, principal financial officer of the general partner, made pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, regarding the quality of our public disclosure, have been filed as exhibits to our 2008 Annual Report to the SEC on Form 10-K.

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

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


Name	Age	Position with the General Partner
Lynn L. Elsenhans	52	Chairman and Director
Deborah M. Fretz	60	President, Chief Executive Officer and Director
Cynthia A. Archer	55	Director
L. Wilson Berry, Jr.	65	Director
Stephen L. Cropper	58	Director
Terence P. Delaney	53	Director
Bruce G. Fischer	53	Director
Philip L. Frederickson	52	Director
Bruce D. Davis, Jr.	52	Vice President, General Counsel and Secretary
David A. Justin	56	Vice President, Operations
Christopher W. Keene	43	Vice President, Business Development
Neal E. Murphy	51	Vice President and Chief Financial Officer

Ms. Elsenhans was elected to the Board of Directors in August 2008 and was elected Chairman of the Board in October 2008. Ms. Elsenhans has been President and Chief Executive Officer of Sunoco, Inc. since August 2008 and Chairman of Sunoco, Inc. since January 1, 2009. Prior to that, she was Executive Vice President of Global Manufacturing for Shell Downstream, Inc. from 2005 to 2008. From 2003 to 2005, Ms. Elsenhans served concurrently as President of Shell Oil Company and President and CEO at Shell Oil Products US. Ms. Elsenhans is a director of International Paper Company.

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

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

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

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

Mr. Delaney was elected to the Board of Directors in September 2007. Mr. Delaney has been interim Chief Financial Officer of Sunoco, Inc. since December 1, 2008. Prior to that, Mr. Delaney served as Vice President, Investor Relations and Planning for Sunoco, Inc. since January 2003.

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

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

Mr. Davis was elected Vice President, General Counsel and Secretary in January 2004. From November 2003 to January 2004, he was General Counsel and Secretary. From September 2000 to November 2003, Mr. Davis was Associate General Counsel for Mirant Corporation.

Mr. Justin was elected Vice President, Operations in April 2007. From November 2001 to April 2007, he served as Vice President, Eastern Operations. Prior to that, Mr. Justin served as Manager, Eastern Area Operations for Sun Pipe Line Company.

Mr. Keene was elected Vice President, Business Development in January 2005. From February 2002 to December 2004, Mr. Keene was the Director, Midstream Development for Unocal Midstream & Trade (UMT), a division of Unocal Corporation. Prior to that, he had been the Director, Business Development, Unocal Global Trade, a division of Unocal Corporation, and Vice President, Unocal Pipeline Company from April 1999 to January 2002.

Mr. Murphy was elected Vice President and Chief Financial Officer in April 2007. Prior to that, he was employed by Quaker Chemical Corporation, where he served as Vice President and Chief Financial Officer from July 2004 through March 2007. From January 2002 to July 2004, Mr. Murphy was Senior Vice President and Chief Financial Officer of International Specialty Products.

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

Section 16(a) of the Securities Exchange Act of 1934 requires directors, executive officers and persons who beneficially own more than 10 percent of the units to file certain ownership reports with the Securities and Exchange Commission and the New York Stock Exchange. The Securities and Exchange Commission regulations also require that copies of these Section 16(a) reports be furnished us by such reporting persons. Based upon a review of copies of these reports, we believe all applicable Section 16(a) reports were timely filed, with the exception of a Form 3 for Terence P. Delaney, which, due to administrative oversight, was not filed until December 23, 2008.

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ITEM 11.

EXECUTIVE COMPENSATION

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

COMPENSATION DISCUSSION AND ANALYSIS

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

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

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

The master limited partnership group consists of the LTIP Peer Group (as discussed on page 107) as well as a broader group of publicly traded master limited partnerships composed of companies of varying revenue and market-cap sizes, with varying market maturity including: Atlas Pipeline Partners LP, Energy Transfer Partners LP, Hiland Partners LP, Markwest Partners LP, Martin Midstream Partners LP, Williams Partners LP, Amerigas Partners LP, Ferrellgas Partners LP, Star Gas Partners LP, Suburban Propane Partners LP and Alliance Resource Partners LP, that may compete with the general partner for executive talent (together, the “MLP Group”). This MLP Group is reviewed annually with the assistance of Towers Perrin and the composition of the MLP Group may be updated in order to reflect mergers, acquisitions, business bankruptcies and other similar events.

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

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

The three basic components of compensation for executives of the general partner consist of base salary; annual incentives; and long-term incentives. For most of the general partner’s executives, the grant-date value of each of these components is targeted to the 50th percentile of the corporate-level competitive market data for general industry. This median targeted percentile was chosen to enhance the general partner’s ability to attract and retain a highly skilled and motivated executive leadership team. However, based upon the individual performance of the executive and our performance as a whole, actual realized compensation may be higher or lower than the target. As a tool to assist in its review of executive compensation, the Compensation Committee uses tally sheets that reflect all components of the executive’s total compensation, including salary, annual incentives, and long-term incentives. Additionally, in consultation with the compensation consultant, management and other outside advisors, the Compensation Committee has reviewed the estimated compensation to be received by the CEO and the other NEOs under various scenarios, including normal retirement, voluntary or involuntary termination, and involuntary termination due to a change in control of the Partnership or Sunoco, Inc.

Elements of Compensation:

•

Base Salary: Base salary is designed to compensate executives for their level of responsibility and sustained individual performance (including experience, scope of responsibility, results achieved and future potential). The salaries of the NEOs are reviewed on an annual basis, as well as at the time of promotion and other change in responsibilities. The compensation consultant provides benchmarking data on the compensation of the NEOs compared to the compensation of executives in the Compensation Comparative Group. The general partner and the Compensation Committee attempt to establish and maintain base salaries for the NEOs at or near the median level of competitive market base salary data. Base salaries also are influenced by internal equity (fair and consistent application of compensation practices). The Compensation Committee, with input from the compensation consultant and the CEO (who provides input for the NEOs other than herself), approves all base salaries for the NEOs. Factors impacting base salary levels are not independently assigned specific weights rather, the Committee reviews and makes base pay decisions that reflect the Committee’s analysis of the aggregate impact of these factors. The Summary Compensation Table on page 113 includes the base salaries of the NEOs that were approved for 2008. At the NEO level, the balance of compensation is weighted toward pay-at-risk compensation (annual and long-term incentives).

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•

Annual Incentive Awards:

•

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

•

Determination of the Amounts Awarded Under the Annual Incentive Plan. Under the plan, an individual’s annual incentive payout amount is determined by multiplying the product of his or her base salary and individual incentive guideline by a factor ranging from zero to 200 percent, based upon the level of attainment of pre-established goals for our cash flow from operations. The annual incentive guideline is based on general industry market data as well as internal equity considerations. Following the end of each year, the Compensation Committee reviews performance data with management and the compensation consultant, and determines the extent to which these goals have been achieved. That amount then may be adjusted up or down (by no more than 20 percent) to reflect financial performance of our lease crude acquisition business. This adjusted amount may be further adjusted up or down (by no more than 10 percent) to reflect our actual performance with regard to certain health, environment and safety criteria. Finally, a potential upwards adjustment of 5 percent may be made if the pipeline and terminals segments of our business successfully achieve a first quartile OSHA safety performance ranking relative to its pipeline industry group. The health, environment and safety component does not apply if our minimum performance goals are not attained. If we do not achieve at least the minimum threshold performance goals, no award payment will be made.

The respective payout percentages for these criteria were established at levels that the Compensation Committee believes provide meaningful incentives to achieve the established performance goals. The following performance goals, assigned weights and performance factors were approved by the Compensation Committee for purposes of calculating the eventual payout for awards made for the 2008 plan year under the Annual Incentive Plan:


Cash Flow from Operations	Payout
£ 80% of cash flow target	0	%
Cash flow target	100	%
³ 120% of cash flow target	200	%

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

Use of cash flow from operations as the primary criterion for payout of the 2008 annual incentive award ensures that management will continue to be focused on operations excellence. Our cash flow from operations measure, which we define as net income plus depreciation minus maintenance capital and EBITDA from our lease acquisition business, is not determined in accordance with GAAP. The lease EBITDA component represents the operating income of the lease group before corporate allocations plus depreciation. Use of health, environment and safety performance to further adjust the payout reinforces that, along with financial success, management is focused on continuing to protect our employees and the communities in which we operate.

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2008 Annual Incentive Payout Amount. Based upon our level of attainment of pre-established goals for cash flow from operations during the 2008 plan year, the payout factor was 197 percent, which includes the applicable health, environmental and safety factor for each business unit. The annual incentive reinforces the links between strategy, goal-setting and results. The individual incentive guidelines (as a percentage of base salary) for each of the NEOs for 2008 are as follows:


Name	Title	Annual Incentive Plan Guideline Incentive 2008
Deborah M. Fretz	President and Chief Executive Officer	80%
Neal E. Murphy	Vice President and Chief Financial Officer	45%
Christopher W. Keene	Vice President, Business Development	40%
Bruce D. Davis, Jr.	Vice President, General Counsel and Secretary	40%
David A. Justin	Vice President, Operations	45%

Under the general partner’s Annual Incentive Plan, the Compensation Committee has the discretion to reduce the amounts payable to participants, or to determine that no amount will be paid, even if all performance criteria for payout are met. The annual incentive awards are paid in cash. The annual incentives earned by NEOs for 2008 are included in the Summary Compensation Table on page 113 under “Non-Equity Incentive Plan Compensation.”

•

Long-Term Incentive Awards:

•

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

•

The LTIP Peer Group. The Compensation Committee utilizes the Peer Group to measure financial performance under the LTIP and to develop appropriate LTIP payout targets that enable us to remain competitive on a total compensation basis (the “LTIP Peer Group”). The LTIP Peer Group consists of other publicly traded master limited partnerships having a business mix comparable to ours. For the 2008 fiscal year, the LTIP Peer Group consisted of the following companies: Buckeye Partners LP; Crosstex Energy LP; Enbridge Energy Partners LP; Enterprise Products Partners LP; Holly Energy Partners LP; Kinder Morgan Energy Partners LP; Magellan Midstream Partners LP; ONEOK Partners LP; Plains All American Pipeline LP; TEPPCO Partners LP; and NuStar Energy LP. This LTIP Peer Group is reviewed annually with the assistance of Towers Perrin.

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•

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

•

Restricted Units. Each restricted unit entitles the grantee to receive a common unit upon vesting or, in the discretion of the Compensation Committee, an amount of cash equivalent to the value of a common unit. From time to time, the Compensation Committee may make grants under the plan to employees and/or directors containing such terms as the Compensation Committee shall determine under the plan. Special one-time grants of restricted units may be made at any time during the year, subject to the approval of the Compensation Committee. These grants are infrequent, and generally are used for new hires, promotions and recognition of extraordinary accomplishments. The Compensation Committee will determine the period over which restricted units granted to employees and/or directors will vest, and whether or not any such restricted units will have distribution equivalent rights entitling the grantee to receive an amount in cash equal to cash distributions made by us with respect to a like number of our common units during the period such restricted units are outstanding. Performance-based restricted units are designed to pay out only if certain objective Partnership-specific performance measures have been met over the applicable performance period, generally three years. As a result, the payout under an LTIP award of performance-based restricted units is influenced not only by performance in the year in which the award is paid, but also by performance for the two prior years. Thus, extreme positive or negative performance during the two years prior to the payout of an award may influence the actual award more than performance in the year in which the award vests. In addition, the value received from restricted unit awards will be affected by any changes in the trading price of our common units during the period of time between the grant date and the payment date.

•

2008 Awards. For the 2008 awards, payout will depend upon our achievement of certain performance levels based on two equally weighted performance measures relative to our LTIP Peer Group: total unitholder return (including cash distributions plus appreciation in unit price) and growth in cash distributions to unitholders, both measured over a three-year performance cycle. The performance period for these awards ends December 31, 2010. Actual payout may range from zero percent to 200 percent of the target amount, with payments increasing as our percentile ranking against our peer companies improves with respect to each of these two performance measures. The respective payout factor is zero for a ranking below the fortieth percentile on each performance measure. Maximum potential payout is achieved at a ranking at or above the ninetieth percentile on each performance measure. Payout factors applicable to performance between points will be interpolated along a straight line. The following objective performance goals, assigned weights, and performance factors were approved by the Compensation Committee for purposes of calculating the eventual payout for performance-based restricted unit awards made for the 2008 plan year under the LTIP (the payout factors applicable to performance between points will be interpolated along a straight line):

Total Unitholder Return and Growth in Cash Distributions to Unitholders

(each weighted 50%)


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

In selecting total unitholder return and growth in distributable cash as the performance measures applicable to the payout of performance-based restricted units, consideration was given to a balanced incentive approach, utilizing those measures deemed most important to

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

As an additional incentive to promote the growth of cash distributions to our unitholders, during the performance period, distribution equivalent rights were granted in tandem with the 2008 awards of performance-based restricted units. At the end of the performance period, to the extent that the performance-based restricted units are paid out, these distribution equivalent rights entitle the grantee of performance-based restricted units to receive an amount equal to the cumulative cash distributions that otherwise would have been paid over the performance period had the grantee been the holder of record of our common units equal to the number of performance-based restricted units paid out. This amount may be taken in the form of cash or additional common units (fractional units are cashed out).

•

2008 Payout for Prior Awards. The performance period for the performance-based restricted units awarded in April 2006 ended December 31, 2008, and the level of payout of these awards reflects our level of achievement of the applicable performance measures over the three-year performance period. The performance measures for these awards were total unitholder return and growth in cash distributions to unitholders.

•

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

•

Determination of the Amounts Awarded under the LTIP. In conjunction with the review and approval of other elements of the NEO’s compensation, the annual LTIP awards were reviewed and approved at the Compensation Committee’s January 2008 meeting, and the grant date was the date of the meeting. In determining the appropriate long-term value for each executive, the Compensation Committee reviews the level of responsibility and total compensation of each senior executive, and the competitive market data presented by the compensation consultant. The Compensation Committee approves the specific amounts granted to each employee. In general, the target number of restricted units granted to each NEO under the LTIP is calculated by taking the product of the NEO’s base salary and the applicable guideline percentage for that NEO, and then dividing by the average daily closing market price of our common units during the last thirty (30) trading days prior to the December 31 preceding the meeting at which the LTIP grant will be approved. Under no circumstances may the aggregate number of units granted to a single employee exceed the maximum applicable limit(s) under the LTIP. When approving grants to the executives, the Compensation Committee considers information or recommendations provided by the CEO, except with respect to the CEO’s own grants. The Compensation Committee utilizes Towers Perrin to assist in the evaluation of grant recommendations. For the LTIP grants made during the 2008 fiscal year, the applicable NEO guideline percentages were as follows:

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Name	Title	LTIP Guideline Percentage
Deborah M. Fretz	President and Chief Executive Officer	230	%
Neal E. Murphy	Vice President and Chief Financial Officer	85	%
Christopher W. Keene	Vice President, Business Development	85	%
Bruce D. Davis, Jr.	Vice President, General Counsel and Secretary	76	%
David A. Justin	Vice President, Operations	85	%

The long-term incentive compensation is based upon the common units representing limited partnership interests in us. The accounting treatment for the long-term incentive compensation is specified by Statement of Financial Accounting Standards No. 123 (revised 2004) “Share-Based Payment” (“SFAS No. 123R”). The expenses for LTIP equity awards are recognized ratably over the vesting period, and are accelerated for vesting at retirement eligibility dates.

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

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

•

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

•

Savings Restoration Plan is a non-qualified deferred compensation plan available to those SunCAP participants subject to compensation and/or contribution limitations under the Internal Revenue Code. Participants may contribute amounts in excess of the applicable limits, up to five percent of base salary. The amounts of the company match for the NEOs in 2008 under the Capital Accumulation Plan and the Savings Restoration Plan are included in the Summary Compensation Table on page 113 under “All Other Compensation” and are further described in the notes accompanying the table.

•

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

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•

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

•

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

The present values of each NEO’s accumulated pension benefit, as of year-end 2008 are included in the Pension Benefits Table on page 120 More detailed descriptions of Retirement Plan, the Pension Restoration Plan and Executive Retirement Plan are included in the narrative accompanying the table.

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

Perquisites: In 2008, certain NEOs also received a limited number of personal benefits, or “perquisites”. The dollar amount of the perquisites received by the NEOs is included in the Summary Compensation Table on page 113 under “All Other Compensation.”

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

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

The Sunoco Partners LLC Special Executive Severance Plan provides severance benefits in case of termination (whether actual or constructive and other than for just cause, death or disability) occurring within two years of a change of control of the Partnership, as defined in the plan. The plan was adopted to retain executives in the event of a major transaction or change in control, and to eliminate the uncertainty and questions which such a transaction may raise among management, and which may result in the departure or distraction of key management personnel to our detriment and/or our general partner. Our general partner’s Board of Directors has determined that appropriate steps should be taken to reinforce and encourage the continued attention and dedication of key management personnel to their assigned duties without distraction. The Board believes that in the context of a change in control, potential acquirers may otherwise have an incentive to constructively terminate the executive’s employment to avoid paying severance, and it is therefore appropriate to provide severance benefits in this circumstance. Severance under this plan would be payable in a lump sum, equal to three times annual compensation for the CEO, and two times annual compensation for the other NEOs. Our general partner’s Board of Directors believes that the potential severance payments provide an appropriate level of protection to the executive for the critical period following a change in control at a reasonable cost to us. For

these purposes, annual compensation consists of: (i) annual base salary in effect immediately prior to a change in

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control or immediately prior to the employment termination date, whichever is greater, plus (ii) the greater of annual guideline incentive in effect immediately before the change in control or employment termination date, or the highest bonus awarded in any of the three years ending prior to the change in control, or any subsequent year ending before the employment termination date.

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

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

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

Additional information regarding these plans can be found under “Other Potential Post-Employment Payments” on page 124.

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SUMMARY COMPENSATION TABLE

The Summary Compensation Table reflects the total compensation earned by the CEO, CFO and each of the three other most highly compensated executive officers of the general partner, who served in those capacities as of December 31, 2008, for each of the past three fiscal years:


Name and Principal Position	Year		Salary ($)		Bonus ($)		Stock Awards⁽¹⁾ ($)	Option Awards⁽²⁾ ($)	Non-Equity Incentive Plan Compensation⁽³⁾ ($)		Change in Pension Value and Nonqualified Deferred Compensation Earnings⁽⁴⁾ ($)		All Other Compensation⁽⁵⁾ ($)	Total ($)
D. M. Fretz⁽⁶⁾	2008		500,000		None		2,205,898	None	788,000		1,215,056		41,036	4,749,990
President and Chief	2007		480,000		None		1,760,147	None	630,144		703,277		40,658	3,614,226
Executive Officer	2006		455,000		None		2,163,672	None	407,680		448,440		53,381	3,528,173

N. E. Murphy	2008		297,440		None		354,928	None	263,681		45,433		11,682	973,164
Vice President and	2007		203,500	⁽⁷⁾	182,850	⁽⁸⁾	209,914	None	136,668	⁽⁹⁾	16,056		552	749,540
Chief Financial Officer	2006	⁽¹⁰⁾	—		—		—	—	—		—		—	—

C. W. Keene	2008		264,368		None		543,134	None	208,322		49,797		13,930	1,079,551
Vice President,	2007		254,200		None		482,975	None	166,857		33,262		13,396	950,690
Business Development	2006		244,400		None		212,149	None	125,133		33,601		13,428	628,711

B. D. Davis, Jr.	2008		266,090		None		412,154	None	209,679		54,747		14,005	956,675
Vice President, General	2007		241,900		None		295,004	None	158,783		34,980		12,745	743,412
Counsel and Secretary	2006		228,230		None		414,568	None	87,640		32,698		15,176	778,312

D. A. Justin	2008		262,500		None		422,149	None	232,706		204,955		13,829	1,136,139
Vice President,	2007		244,216	⁽¹¹⁾	None		352,059	None	164,100		0	⁽¹²⁾	11,934	772,309
Operations	2006		216,840		None		378,116	None	84,112		51,882		11,827	742,777

NOTES TO TABLE:

⁽¹⁾

The amounts shown in this column reflect the amounts recognized as compensation expense on our financial statements at year-end 2008, 2007 and 2006, respectively, relating to performance-based restricted unit awards under the Sunoco Partners LLC Long-Term Incentive Plan (the “LTIP”), approved by the Compensation Committee at its regularly scheduled meetings in January 2008, January 2007 and April 2006 as well as similar expense for outstanding prior year awards, approved by the Compensation Committee at its regularly scheduled meetings in January 2005 and 2004, calculated in accordance with the requirements of SFAS No. 123 and SFAS No. 123R. Such compensation expense includes tandem distribution equivalent rights related to the restricted unit awards. These awards have a three-year restriction period. Compensation expense for the 2008 and 2007 awards was calculated assuming an eventual target payout of 100 percent. Compensation expense for the 2006 awards (which were paid out on February 9, 2009, in the form of common units), the 2005 awards (which were paid out on February 8, 2008, in the form of common units) and the 2004 awards (which were paid out on February 8, 2007, in the form of common units) were calculated using the actual performance-adjusted payout percentage of 200 percent, 163.2 percent, and 176.8 percent respectively. At the time of the filing of this report, Ms. Fretz and Mr. Justin are retirement eligible and the compensation expense has been recognized immediately upon grant for their 2007 and 2008 awards, in accordance with SFAS No. 123R. See the “Compensation, Discussion and Analysis” on page 108 for the specific performance measures applicable to the payout and vesting of these awards. These awards were granted with tandem distribution equivalent rights.

⁽²⁾

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

⁽³⁾

The amounts shown in this column reflect annual incentive amounts earned under the Sunoco Partners LLC Annual Incentive Plan, for performance during 2008, 2007, and 2006 and payable on or before March 13, 2009, March 14, 2008 and March 17, 2007, respectively.

⁽⁴⁾

The amounts shown in this column reflect the change in each NEO’s pension value between December 31, 2008 and December 31, 2007, December 31, 2007 and December 31, 2006, and December 31, 2006 and December 31, 2005, respectively. The NEOs did not have any above-market or

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preferential payments on deferred compensation during 2008, 2007 or 2006. Certain of the NEOs have deferred amounts under the Sunoco, Inc. Savings Restoration Plan, an excess 401(k) benefit plan available to employees of Sunoco, Inc. and subsidiaries such as the Partnership’s general partner. However, the earnings received from participation in this plan are the same as dividends earned on Sunoco, Inc. common stock (in the case of the Sunoco stock-related funds), and/or are based on the gains/losses of certain mutual funds, which are calculated in the same manner and at the same rate of earnings as for all other employees invested in those funds in the Sunoco, Inc. Capital Accumulation Plan (the “SunCAP”), the broad-based 401(k) qualified defined contribution plan for Sunoco, Inc. and its subsidiaries.

⁽⁵⁾

The table below shows the components of this column for 2008, 2007 and 2006:


Name	Year	Company Match Under Defined Contribution Plan ($)	Cost of Basic Life Insurance ($)	Financial Counseling ($)	Amounts Reimbursed for Payment of Certain Taxes ($)	Perquisites >$10,000 ($)	Amounts Paid in Connection with Termination of Employment ($)	Amounts Reimbursed for Moving & Relocation Expenses ($)	Total ($)
D. M. Fretz	2008	24,977	1,368	—	—	14,691	—	—	41,036
	2007	23,976	1,313	—	—	15,369	—	—	40,658
	2006	22,736	1,245	2,500	7,075	19,825	—	—	53,381

N.E. Murphy	2008	10,868	814	—	—	—	—	—	11,682
	2007	—	552	—	—	—	—	—	552
	2006	—	—	—	—	—	—	—	—

C.W. Keene	2008	13,207	723	—	—	—	—	—	13,930
	2007	12,701	695	—	—	—	—	—	13,396
	2006	11,759	669	1,000	—	—	—	—	13,428

B. D. Davis, Jr.	2008	13,277	728	—	—	—	—	—	14,005
	2007	12,083	662	—	—	—	—	—	12,745
	2006	11,403	624	3,149	—	—	—	—	15,176

D. A. Justin	2008	13,111	718	—	—	—	—	—	13,829
	2007	11,250	684	—	—	—	—	—	11,934
	2006	10,834	593	400	—	—	—	—	11,827

•

For Ms. Fretz, the amount shown for perquisites in 2008, 2007 and 2006 includes: (1) an allowance for parking at the headquarters office and (2) reimbursements for certain fees and dues relating to country and social club memberships. Our general partner provides Ms. Fretz with tax gross-ups for business club memberships and, through April 2006, provided for country club memberships.

•

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

•

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

•

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

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⁽⁶⁾

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

⁽⁷⁾

Mr. Murphy began his employment with our general partner on April 9, 2007. This figure represents the portion of his annual salary of $286,000 that was earned in 2007.

⁽⁸⁾

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

⁽⁹⁾

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

⁽¹⁰⁾

Colin Oerton served as the principal financial officer for part of the fiscal year ending December 31, 2006 and his employment with our general partner was terminated on September 30, 2006. Information regarding Mr. Oerton’s 2006 compensation was disclosed in our Form 10-K for the year ending December 31, 2006.

⁽¹¹⁾

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

⁽¹²⁾

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

GRANTS OF PLAN-BASED AWARDS

The following table sets forth the grants of awards to the CEO, CFO and each of the three other most highly compensated executive officers of our general partner in 2008:


Name	Grant Date	Estimated Future Payouts Under Non-Equity Incentive Plan Awards⁽¹⁾			Estimated Future Payouts Under Equity Incentive Plan Awards				All Other Stock Awards: Number of Shares of Stock or Units (#)	All Other Option Awards: Number of Securities Underlying Options⁽³⁾ (#)	Exercise or Base Price of Option Awards ($/Unit)	Grant date fair value of stock and option awards⁽⁴⁾
Name	Grant Date	Threshold ($)	Target ($)	Maximum ($)	Threshold (#)	Target (#)		Maximum (#)			Exercise or Base Price of Option Awards ($/Unit)	Grant date fair value of stock and option awards⁽⁴⁾
D. M. Fretz	01-23-2008	—	400,000	800,000	—	22,950	⁽²⁾	45,900	—	—	—	1,215,432
President and Chief Executive Officer

N.E. Murphy	01-23-2008	—	133,848	267,696	—	5,045	⁽²⁾	10,090	—	—	—	267,183
Vice President and Chief Financial Officer

C. W. Keene	01-23-2008	—	105,747	211,494		4,484	⁽²⁾	8,968	—	—	—	237,473
Vice President, Business
Development

B. D. Davis, Jr.	01-23-2008	—	106,436	212,872	—	4,036	⁽²⁾	8,072	—	—	—	213,747
Vice President, General Counsel and Secretary

D. A. Justin	01-23-2008	—	118,125	236,250	—	4,453	⁽²⁾	8,906	—	—	—	235,831
Vice President, Operations

NOTES TO TABLE:

⁽¹⁾

This reflects a target and maximum annual incentive award amounts for each NEO equal to the target percentages set forth above in the section entitled “2008 Annual Incentive Payout Amount.” The maximum reflects that the NEO may receive up to 200% of the target bonus award amount. The annual incentive is paid out in cash, and any amounts earned for performance during the 2008 year will be paid out no later than March 13, 2009.

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⁽²⁾

The performance-based restricted units were awarded under the Sunoco Partners LLC Long-Term Incentive Plan (the “LTIP”) on January 23, 2008. These performance- based restricted units were granted with tandem distribution equivalent rights. Actual payout of these awards will depend upon our achievement of certain specified performance levels, ranked against our peer group of companies, based upon equally weighted annual objectives for total unitholder return and growth cash distributions to unitholders. The portion of each award that may be earned during the performance period (which runs from January 1, 2008 to December 31, 2010) ranges from a threshold value of zero, to a target value equal to 100 percent of the award, and a maximum value of 200 percent of the award. Payment of any amounts earned will occur following such period, assuming continued employment with the general partner at such time.

⁽³⁾

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

⁽⁴⁾

Grant date fair value was calculated in accordance with SFAS No. 123R.

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OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END

The following table provides information concerning the unvested and outstanding equity awards to the CEO, CFO and each of the three other most highly compensated executive officers of the Partnership’s general partner as of December 31, 2008:


Name	Option Awards⁽¹⁾					Stock Awards
Name	Number of Securities Underlying Unexercised Options (#) Exercisable	Number of Securities Underlying Unexercised Options (#) Unexercisable	Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)	Option Exercise Price ($)	Option Expiration Date	Number of Shares or Units of Stock That Have Not Vested (#)		Market Value of Shares or Units of Stock That Have Not Vested ($)		Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)		Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ⁽³⁾ ($)
D. M. Fretz
President										22,362	⁽⁴⁾
and Chief Executive	—	—	—	—	—	—		—		22,950	⁽⁵⁾	2,045,384
Officer

N.E. Murphy	—	—	—	—	—	3,070	⁽²⁾	138,580	⁽²⁾	4,208	⁽⁴⁾	417,680
Vice President and Chief										5,045	⁽⁵⁾
Financial Officer

C. W. Keene										4,393	⁽⁴⁾
Vice President,										4,484	⁽⁵⁾
Business Development	—	—	—	—	—	—		—		4,981	⁽⁶⁾	625,550

B. D. Davis, Jr.										3,737	⁽⁴⁾
Vice President, General										4,036	⁽⁵⁾	350,873
Counsel and Secretary	—	—	—	—	—	—		—

D. A. Justin										4,185	⁽⁴⁾
Vice President,	—	—	—	—	—	—		—		4,453	⁽⁵⁾	389,919
Operations

NOTES TO TABLE:

⁽¹⁾

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

⁽²⁾

Amounts shown reflect awards of time-vested restricted units (i.e., not performance-based), granted under the terms of the LTIP. On April 20, 2007, in connection with his hiring, Mr. Murphy was granted a one-time award of 9,212 restricted units, together with applicable distribution equivalent rights, pursuant to the LTIP; this special award vests and becomes payable in one-third increments on each December 31, 2007 through 2009, contingent only upon Mr. Murphy’s continued employment with the general partner through the end of the restriction periods. Mr. Murphy earned 3,071 units upon each of the first and second incremental vestings on December 31, 2007 and December 31, 2008. The market value or payout value of the unearned restricted units is based on the trading price of our common units, on December 31, 2008 of $ 45.14.

⁽³⁾

The market value or payout value of the unearned restricted units is based on the trading price of our common units on December 31, 2008 of $45.14, and assumes a payout at the target of 100 percent.

117

⁽⁴⁾

These performance-based restricted units were awarded January 26, 2007 and the performance period ends on December 31, 2009, except that Mr. Murphy’s performance-based restricted units were awarded on April 20, 2007, in connection with his hiring. Actual payout of these awards will depend upon our achievement of certain specified performance levels, ranked against our peer group of companies, based upon total unitholder return and growth in cash distributions to unitholders. The portion of each award that may be earned during the performance period ranges from a threshold value of zero, to a target value equal to 100 percent of the award, and a maximum value of 200 percent of the award. Payment of any amounts earned will occur following such period, assuming continued employment with the general partner at such time. At the end of the performance period, to the extent that the performance-based restricted units are paid out, each holder of performance-based restricted units also will receive an amount equal to the cumulative cash distributions that would have been paid over the performance period had he or she been the holder of record of our common units, equal to the number of the performance-based restricted units, if any, paid out.

⁽⁵⁾

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

⁽⁶⁾

Mr. Keene was granted a special unit award of 4,981 performance-based restricted units on January 26, 2007. The award vests incrementally over a five year restricted period with 25% vesting on December 31, 2009, 25% vesting on December 31, 2010 and the remaining units vesting on December 31, 2011. The portion of each unit award earned at each vesting period ranges from a threshold value of 50 percent, to a target value equal to 100 percent of the award, and a maximum value of 200 percent of the award. Actual payout of these awards will depend upon our achievement of certain specified performance levels, ranked against our peer group of companies, based upon equally weighted annual objectives for total unitholder return and growth cash distributions to unitholders. At the end of the performance period, to the extent that the performance-based restricted units are paid out, Mr. Keene will also receive an amount equal to the cumulative cash distributions that would have been paid over the performance period had he been the holder of record of our common units, equal to the number of the performance-based restricted units paid out.

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OPTION EXERCISES AND STOCK VESTED

The following table provides information concerning the amounts related to the vesting, during 2008, of certain awards for the CEO, CFO and each of the three other most highly compensated executive officers of our general partner in 2008, upon the vesting of restricted units, previously awarded under the Sunoco Partners LLC Long-Term Incentive Plan (the “LTIP”):


Name	Option Awards ⁽¹⁾		Stock Awards
Name	Number of Shares Acquired on Exercise (#)	Value Realized on Exercise ($)	Number of Shares Acquired on Vesting (#)		Value Realized on Vesting⁽³⁾ ($)
D. M. Fretz	—	—	44,782	⁽²⁾	$	2,910,047
President and Chief Executive Officer
N.E. Murphy	—	—	3,071	⁽⁴⁾		189,964
Vice President and Chief Financial Officer
C. W. Keene	—	—	10,360	⁽²⁾		673,218
Vice President, Business Development
B. D. Davis, Jr.	—	—	8,984	⁽²⁾		583,803
Vice President, General Counsel and Secretary
D. A. Justin	—	—	8,424	⁽²⁾		547,413
Vice President, Operations

NOTES TO TABLE:

⁽¹⁾

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

⁽²⁾

Amounts shown in this column reflect the vesting and payout of performance-based restricted unit awards granted in April 2006 under the LTIP, and the Partnership’s level of attainment of certain performance goals over the three-year performance period running from January 1, 2006 through December 31, 2008. The number of units shown in the table reflects a payout percentage of 200 percent, applicable to the actual level of achievement of certain specified performance goals (based upon annual objectives for growth in cash flow per common unit, and total unitholder return ranked against peers) during the performance period. The value upon vesting was determined by multiplying (i) the product of the target number of such restricted units and the applicable performance factor (200 percent) at the end of the performance period; by (ii) the closing market price of our common units on the last trading day before the units were paid out ($54.69), and then adding the cumulative cash value of earned distribution equivalents. The performance measures for these awards were growth in operating cash flow, and total unitholder return during the performance period.

⁽³⁾

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


Name		Value of Cumulative Distribution Equivalents Realized Upon Vesting ($)
D. M. Fretz		460,919
N.E. Murphy		22,011
B. D. Davis, Jr.		92,468
C.W. Keene		106,630
D. A. Justin		86,704

⁽⁴⁾

For Mr. Murphy, the amount shown is the number of restricted units earned upon vesting of his special restricted unit award, granted in April 2007, in connection with his hiring, the payout of which was conditioned only upon his continued employment through the end of the second of three incremental restriction periods, running from January 1, 2008 through December 31, 2008, and the related cumulative distribution equivalents.

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PENSION BENEFITS

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


Name	Plan	Number of Years Credited Service⁽¹⁾ (#)	Present Value of Accumulated Benefit⁽²⁾ ($)	Payments During Last Fiscal Year ($)
D. M. Fretz	SCIRP	31.84	1,564,320	0
President and Chief Executive Officer	Pension Restoration	31.84	5,439,120	0
	SERP	31.84	0	0
N.E. Murphy	SCIRP	1.73	38,353	0
Vice President and Chief Financial Officer	Pension Restoration	1.73	23,136	0
	SERP	Not applicable	Not applicable	0
C. W. Keene	SCIRP	3.98	77,777	0
Vice President, Business Development	Pension Restoration	3.98	57,654	0
	SERP	Not applicable	Not applicable	0
B. D. Davis, Jr.	SCIRP	5.14	113,625	0
Vice President, General Counsel and Secretary	Pension Restoration	5.14	62,059	0
	SERP	Not applicable	Not applicable	0
D. A. Justin	SCIRP	25.22	469,989	0
Vice President, Operations	Pension Restoration	25.22	107,263	0
	SERP	25.22	860,016	0

NOTES TO TABLE:

⁽¹⁾

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

⁽²⁾

An actuarial present value of the benefits is calculated by estimating expected future payments starting at an assumed retirement age, weighting the estimated payments by the estimated probability of surviving to each post-retirement age, and discounting weighted payments at an assumed discount rate to reflect the time value of money. The actuarial present value represents an estimate of the amount which, if invested as of December 31, 2008 at a discount rate of 6.00%, would be sufficient on an average basis to provide estimated future payments based on the current accumulated benefit. Estimated future payments are assumed to be in the form of a single lump sum payment at retirement determined using interest rate and mortality table assumptions applicable under current IRS regulations for qualified pension plans. The conversion interest rate[s] assumed for lump sum payments are based on three segment rates under the Pension Protection Act and the lump sum mortality table is derived from IRS regulations. In addition, the value of the lump sum payment includes the estimated value of the 50% postretirement death benefit payable to the spouse of a retired participant under the SERP and Final Average Pay formula benefits described below, if married. It is assumed that 90% of all male members are married and 60% of females are married, with wives assumed to be 3 years younger than husbands. The assumed retirement age for each executive is the earliest age at which the executive could retire without any benefit reduction due to age. For NEOs, the assumed retirement age is 60 (i.e.,

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the earliest age at which the executive could retire without any benefit reduction due to age), or actual age, if older than 60. Actual benefit present values will vary from these estimates depending on many factors, including an executive’s actual retirement age, final service, future compensation levels, interest rate movements and regulatory changes.

The Sunoco, Inc. Retirement Plan

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

(1)

Final Average Pay formula

•

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

•

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

•

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

(2)

Career Pay (cash balance) formula

•

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

•

Pay credits equal 7 percent of pay for the year up to the Social Security (FICA) Wage Base, ($102,000 in 2008) plus 12 percent of pay for the year that exceeds the Wage Base.

•

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

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

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

121

The SCIRP is subject to qualified plan Internal Revenue Code (the “Code”) limits on the amount of annual benefit that may be paid, and on the amount of compensation that may be taken into account in calculating retirement benefits, under the plan. For 2008, the limit on the compensation that may be used was $230,000, and will be $245,000 for 2009. The limit on annual benefits payable for an employee retiring in 2008 was $185,000, and for 2009 is $195,000. Benefits in excess of those permitted under the statutory limits are paid from the Pension Restoration Plan, described below.

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

Pension Restoration Plan

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

Sunoco, Inc. Executive Retirement Plan

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

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

(1)

SCIRP Final Average Pay formula (described on page 121).

(2)

Minimum Benefit formula

•

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

•

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

•

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

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(3)

Executive Service formula

•

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

•

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

•

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

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

NONQUALIFIED DEFERRED COMPENSATION

The following table includes deferred compensation provided to the CEO, CFO and each of the three other most highly compensated executive officers of our general partner in 2008 under the Sunoco, Inc. Savings Restoration Plan. Each NEO may participate in the Sunoco, Inc. Savings Restoration Plan, a nonqualified plan that is made available to employees who participate in SunCAP (Sunoco, Inc.’s 401(k) plan) and who may be subject to compensation limitations and/or a contributions limitation under SunCAP pursuant to the Internal Revenue Code. Under this plan, the participant may contribute to an account in excess of the applicable limits. The executive’s contributions and our general partner’s matching contributions are credited to the extent they would be credited under SunCAP. The investment funds available under the Savings Restoration Plan are the same as those available to all employees participating in SunCAP and the executive receives earnings, depending on the fund the contributions are allocated to, which are calculated in the same matter and at the same rate of earnings as for all other employees invested in those funds in the SunCAP.

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


Name	Source	Executive Contributions in 2008 ($)	Registrant Contributions in 2008 ($)		Aggregate Earnings in 2008 ⁽²⁾ ($)		Aggregate Withdrawals/ Distributions ($)	Aggregate Balance at December 31, 2008 ($)
D. M. Fretz	Savings Restoration Plan	13,477	13,477	⁽¹⁾	(134,594	)⁽²⁾	—	251,988
N.E. Murphy	Savings Restoration Plan	3,359	3,359	⁽¹⁾	956	⁽²⁾	—	7,674
C.W. Keene	Savings Restoration Plan	1,707	1,707	⁽¹⁾	(3,413	)⁽²⁾	—	5,471
B. D. Davis, Jr.	Savings Restoration Plan	1,776	1,776	⁽¹⁾	(755	)⁽²⁾	—	5,316
D. A. Justin	Savings Restoration Plan	1,611	1,611	⁽¹⁾	42	⁽²⁾	—	3,868
	Financial Counseling	—	—		—		—	3,000	⁽³⁾

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⁽¹⁾

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

⁽²⁾

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

⁽³⁾

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

OTHER POTENTIAL POST-EMPLOYMENT PAYMENTS

Certain plans, described below, provide for payments of benefits to the NEOs in connection with termination, or separation from employment, or a change in control of our general partner, or in some cases, Sunoco, Inc. The following describes the benefits that the NEOs would receive if such an event occurred. The actual amounts paid can be determined only at the time of such NEO’s separation from employment with our general partner.

Retirement: The benefits paid to the NEOs upon retirement are described above, on pages 121-123.

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

•

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

•

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

•

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

•

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

•

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

124

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

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

•

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

•

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

•

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

Involuntary Termination—Not for Cause:

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

Involuntary Termination—Change of Control

•

Sunoco Partners LLC Special Executive Severance Plan: This plan was adopted to retain executives in the event of a change of control, and to eliminate the distraction and uncertainty such a transaction may create among management personnel, to the detriment of the organization. Payment of severance

125

benefits under this plan provides severance allowances to executives whose employment is terminated in connection with, or following, a change of control. A “change of control” is defined as any one or more of the following events:

•

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

•

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

•

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

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

•

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

•

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

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

•

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

•

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

126

•

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

•

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

•

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

•

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

•

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

Change of Control—Regardless of Termination

•

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

•

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

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

•

Insurance:

•

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

•

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

•

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

•

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

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•

SCIRP:

•

For an NEO who is eligible for Final Average Pay formula benefits under SCIRP (Ms. Fretz): A married NEO’s spouse would receive the greater of 50 percent of the benefit under the Final Average Pay formula or 100 percent of the benefit accrued under the Career Earnings Formula. A non-married NEO’s beneficiary(ies) or estate would receive 100 percent of the benefit accrued under the Career Earnings Formula. This benefit is the same for all similarly situated employees.

•

For an NEO that is eligible for Career Pay Formula benefits only under SCIRP (Messrs. Davis, Keene, Justin and Murphy): A married or non-married NEO’s spouse, beneficiary(ies) or estate would receive 100 percent of the benefit accrued under the Career Earnings Formula. This benefit is the same for all similarly situated employees.

•

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

•

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

•

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

•

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

Disability: In the case of disability, an NEO would be eligible for the following benefits:

•

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

•

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

•

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

•

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

•

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

The following table reflects estimated compensation and benefits for the NEOs under various scenarios involving a termination of employment. These amounts are estimates of the amounts that would be paid to the NEOs and the actual amounts paid can only be determined at the time of a named executive officer’s termination of employment. The estimates are based on the following assumptions:

•

the applicable provisions in the agreements and arrangements governing the NEOs’ benefits and payment which are summarized in the “Other Potential Post-Employment Payments” section on pages 105 to 108;

•

the triggering event occurred on December 31, 2008;

•

the price of the Partnership’s stock is the price at the close on December 31, 2008 ($45.14);

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•

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

•

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

•

each NEO has exhausted all available vacation benefits as of December 31, 2008.


Name	Voluntary Resignation		Involuntary Not for Cause Termination		Involuntary Termination— Change in Control
D.M. Fretz President and Chief Executive Officer	$	13,252,441	$	14,622,493	$	17,050,229

N.E. Murphy Vice President and Chief Financial Officer		451,437		1,130,091		2,591,393

C.W. Keene Vice President, Business Development		913,946		1,500,705		3,011,298

B.D. Davis, Jr. Vice President, General Counsel and Secretary		900,400		1,299,989		2,555,439

D.A. Justin Vice President, Operations		3,212,279		3,802,296		4,235,666

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DIRECTOR COMPENSATION

Directors, who are employees of Sunoco Partners LLC, Sunoco, and their respective affiliates, including the CEO, receive no additional compensation for service on the general partner’s Board of Directors or any committees of the Board.

Compensation Philosophy: The general partner’s Board of Directors believes that the compensation program for the non-employee directors should be designed to attract experienced and highly qualified individuals; provide appropriate compensation for their commitment and contributions to us and our unitholders; and align the interests of the non-employee directors and unitholders. The general partner’s Board of Directors engages a third-party compensation consultant to benchmark director compensation against our LTIP Peer Group, other pipeline companies, and general industry. For 2008, the Board of Directors engaged a consultant from Fredrick W. Cook, Inc. & Co. This director compensation consultant provides advice regarding “best practices” and trends in director compensation. Non-employee directors are compensated partly in cash and partly in common units, representing limited partnership interests in us. Currently, equity-based compensation represents a substantial portion of the total compensation package.

Retainers and Fees: In April 2008, the Board of Directors implemented changes to the cash and equity components of the compensation for directors who were not employees of Sunoco Partners LLC or its affiliates (“non-employee directors”). During 2008, each non-employee director received an annual retainer of $41,000 in cash, paid quarterly, (adjusted April 1, 2008 from $21,000) and a number of restricted units, paid quarterly, under the Sunoco Partners LLC Long-Term Incentive Plan. These restricted units had an aggregate fair market value equal to $41,000 (adjusted April 1, 2008 from $21,000) on an annual basis (the fair market value of each quarterly payment of restricted units is calculated as of the payment date). These restricted units are required to be deferred, and are credited to each non-employee director’s mandatory deferred compensation account in the Directors’ Deferred Compensation Plan. Amounts thus deferred in the form of restricted units are treated as if invested in common units of the Partnership, and include a credit for distribution equivalent rights (in the form of additional restricted units), credited on the applicable date(s) for Partnership cash distributions. During 2008, the chairman of the Audit/Conflicts Committee received an annual committee chair retainer of $8,000 in cash, and the chairman of the Compensation Committee received an annual chair retainer of $3,500 in cash. In addition, the non-employee directors received fees of $1,500 in cash for each Board meeting attended, and $1,000 in cash for each committee meeting attended.

Directors’ Deferred Compensation Plan: Directors are permitted voluntarily to defer all or a portion of their cash retainers and fees under the Sunoco Partners LLC Directors’ Deferred Compensation Plan. Voluntarily deferred cash compensation amounts are credited in the form of restricted units, the value of which varies as though invested in our common units. Amounts voluntarily deferred in the form of restricted units also are credited with distribution equivalent rights (in the form of additional restricted units), on the applicable date(s) for our cash distributions. Payments of compensation deferred under the Directors’ Deferred Compensation Plan are restricted in terms of the earliest and latest dates that payments may begin. All deferrals, whether mandatory or voluntary, will be paid out in cash.

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

Directors’ Unit Ownership Guidelines: Each non-employee director is expected to own common units, representing limited partnership interests in us, with a market value equal to at least three times the total (cash and restricted unit) annual retainer and Board /committee meeting fees. Directors who do not meet the criteria for independence established by the New York Stock Exchange must own at least one thousand (1,000) of our common units. Included in the determination of unit ownership for purposes of these

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guidelines are all common units beneficially owned, as well as any restricted units in the Directors’ Deferred Compensation Plan. New directors are allowed a five-year phase-in period to comply with the guidelines.

Indemnification: Each director will be indemnified fully by us for actions associated with being a director to the extent permitted under Delaware law.

The following table reflects the compensation earned by each of the non-employee directors of our general partner during 2008:


Name	Fees Earned or Paid in Cash⁽¹⁾ ($)	Stock Awards⁽²⁾ ($)	Option Awards⁽³⁾ ($)	Non-Equity Incentive Plan Compensation ($)	Change in Pension Value and Nonqualified Deferred Compensation Earnings	All Other Compensation⁽⁴⁾ ($)	Total ($)
L.W. Berry, Jr⁽⁵⁾. Non-employee Director	69,500	46,250	—	—	—	21,319	137,069

S.L. Cropper⁽⁵⁾ Non-employee Director	61,550	46,250	—	—	—	10,565	118,365

G.W. Edwards⁽⁵⁾⁽⁶⁾ Non-employee Director	29,250	15,500	—	—	—	21,912	66,662

P.L. Frederickson Non-employee Director	61,500	46,250	—	—	—	1,099	108,849

NOTES TO TABLE:

⁽¹⁾

The amounts shown in this column include: the 2008 annual cash retainer for outside directors (totaling $36,000 for Messrs. Berry, Cropper and Frederickson and $15,500 for Mr. Edwards for the portion of 2008 that he served as a director); regular and special Board meeting fees (totaling $13,500 for Messrs. Berry and Frederickson, $12,000 for Mr. Cropper, and $6,000 for Mr. Edwards), committee meeting fees (totaling $12,000 for Messrs. Berry, Cropper and Frederickson and $6,000 for Mr. Edwards) and, as applicable, committee chair retainers ($8,000 for the Audit/Conflicts Committee and $3,500 for the Compensation Committee). Pursuant to the Sunoco Partners LLC Directors’ Deferred Compensation Plan, the directors are permitted voluntarily to defer, all or a portion of their fees and/or retainers. These amounts are deferred in the form of restricted units. As of December 31, 2008, the following directors had the following aggregate numbers of restricted units accumulated in their respective voluntary deferred compensation accounts for their years of service (these figures include distribution equivalents credited to such accounts in the form of additional restricted units):


• L. W. Berry, Jr.:		3,445
• G.W. Edwards:		3,602

⁽²⁾

The amounts shown in this column reflect the dollar value of the portion of the annual retainer (approximately half) that is paid quarterly, in the form of restricted units issued pursuant to the Sunoco Partners LLC Long-Term Incentive Plan (“LTIP”) during 2008 calculated in accordance with the requirements of Statement of Financial Accounting Standards No.123 (Revised December 2004) “Share-Based Payment” (“SFAS 123R”). For each director, this restricted unit retainer is automatically and mandatorily deferred, in accordance with terms of the Sunoco Partners LLC Directors’ Deferred Compensation Plan. As of December 31, 2008, these directors had the following aggregate numbers of

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restricted units accumulated in their respective mandatory deferred compensation accounts as a result of the involuntary deferrals of the restricted unit retainer for their years of service (these figures include distribution equivalents credited to such accounts in the form of additional restricted units):


• L. W. Berry, Jr.:		3,338
• S. L. Cropper:		3,708
• G.W. Edwards:		3,020
• P.L. Frederickson :		1,001

⁽³⁾

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

⁽⁴⁾

Amounts shown in this column reflect distribution equivalents earned on deferred compensation during 2008.

⁽⁵⁾

In 2008, Mr. Berry was Chair of the Audit/Conflicts Committee. Mr. Edwards served Chair of the Compensation Committee for the first quarter and the first portion of the second quarter of 2008. Effective July 22, 2008, Mr. Cropper was appointed Chair of the Compensation Committee.

⁽⁶⁾

Mr. Edwards resigned from the Board effective May 16, 2008. Reported compensation reflects amounts earned for 2008 through his resignation date.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

There are no Compensation Committee interlocks.

COMPENSATION COMMITTEE REPORT

The Compensation Committee (the “Committee”) of the Board of Directors of Sunoco Partners LLC (the “Company”) reviews and approves the Company’s executive compensation philosophy; reviews and recommends to the Board for approval the Company’s short- and long-term compensation plans; reviews and approves the executive compensation programs and awards; and annually reviews, determines and approves the compensation for the Chief Executive Officer (“CEO”) and the other executive officers (collectively, the “Named Executive Officers” or “NEOs”) of the Company named in the Summary Compensation Table contained in the Annual Report on SEC Form 10-K of Sunoco Logistics Partners L.P. (the “Partnership”). The Company is the general partner of the Partnership. The Committee Chair reports Committee actions, decisions and recommendations at the meetings of the full Board. The Committee has authority to directly engage and consult outside advisors, experts and others to assist the Committee at the expense of the Partnership.

As required by applicable regulations of the Securities and Exchange Commission, the Committee has reviewed the executive compensation disclosures contained in the report captioned “Compensation Discussion and Analysis,” which report is required pursuant to Item 402(b) of SEC Regulation S-K, as amended. As part of this review, the Committee met with management and with such outside consultants and experts as it has deemed necessary or advisable (with and without management present), to discuss the scope and overall quality of the disclosure.

In reliance on the reviews and discussions referred to above, the Committee recommended to the Board of Directors, and the Board has approved, the inclusion of the “Compensation Discussion and Analysis” in the Partnership’s Annual Report on SEC Form 10-K for the fiscal year ended December 31, 2008, for filing with the Securities and Exchange Commission.

Respectfully submitted on February 24, 2009 by the members of the Compensation Committee of the Board of Directors of Sunoco Partners LLC:

L. Wilson Berry, Jr.

Stephen L. Cropper (Chair)

Lynn L. Elsenhans

Philip L. Frederickson

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ITEM 12.

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

Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides information, as of December 31, 2008, regarding our common units that may be issued upon conversion (assuming a one-for-one conversion) of outstanding restricted units granted under the general partner’s Long-Term Incentive Plan to executive officers, directors, and other key employees. For more information about this plan (which did not require approval by our limited partners at the time of its adoption in 2002), refer to “Item 11—Executive Compensation.”

EQUITY COMPENSATION PLAN INFORMATION⁽¹⁾


Plan Category	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights	(b) Weighted-average exercise price of outstanding options, warrants and rights	(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders	—	—	—
Equity compensation plans not approved by security holders	372,558	—	513,691

Total	372,558	—	513,691

NOTES TO TABLE:

⁽¹⁾

The amounts in column (a) of this table reflect only restricted units that have been granted under the Sunoco Partners LLC Long-Term Incentive Plan, since the inception of the Plan. No unit options have been granted. Each restricted unit shown in the table represents a right to receive (upon vesting and payout) a specified number of our common units. Vesting and payout may be conditioned upon achievement of pre-determined financial or other performance objectives for, or attainment of certain length of service goals with us and our affiliates. No value is shown in column (b) of the table, since the restricted units do not have an exercise, or “strike,” price. For illustrative purposes, a maximum payment (i.e., a 200 percent ratio) has been assumed for vesting and payout of performance-related grants, and a target payout (i.e., a 100 percent ratio) has been assumed for vesting and payout of grants conditioned only upon service.

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Beneficial Ownership Table

The following table sets forth the beneficial ownership of our common units by directors of Sunoco Partners LLC (the general partner), by each named executive officer and by all directors and executive officers of Sunoco Partners LLC as a group as of December 31, 2008. Unless otherwise noted, each individual exercises sole voting or investment power over the Partnership common units shown in the table. For purposes of this table, beneficial ownership includes Partnership common units as to which the person has sole or shared voting or investment power, as well as: (a) those Partnership common units actually acquired by LTIP participants as a result of the vesting and payout on February 9, 2009, of performance-based restricted units awarded April 17, 2006; and (b) any additional Partnership common units that a person has the right to acquire within 60 days of December 31, 2008, through the conversion of restricted units. During 2008, Sunoco Partners LLC was owned by the following members: Sun Pipe Line Company (67%); Sunoco, Inc. (R&M) (13%); and Atlantic Refining & Marketing Corp. (20%), each of which is a direct or indirect wholly-owned subsidiary of Sunoco, Inc.


Name of Beneficial Owner⁽¹⁾	Number of Common Units Beneficially Owned⁽¹⁾	Percentage of Common Units Beneficially Owned	Number of Restricted Units Owned⁽²⁾
Sunoco Partners LLC⁽³⁾	12,063,734	42.1	0
Lynn L. Elsenhans⁽⁴⁾	1,000	*	0
Deborah M. Fretz	135,359	*	0
Cynthia A. Archer	2,000	*	0
L. Wilson Berry, Jr.	0	*	6,783
Stephen L. Cropper	9,200	*	3,708
Terence P. Delaney	2,563	*	0
Bruce G. Fischer	5,000	*	0
Philip L. Frederickson	0	*	1,001
Bruce D. Davis, Jr.	16,448	*	0
David A. Justin	24,943	*	0
Christopher W. Keene	13,955	*	0
Neal E. Murphy	4,120	*	0
All directors and executive officers as a group (12 persons)	12,278,322

*	Less than 0.5 percent.

NOTES TO TABLE:

⁽¹⁾	The address of each beneficial owner named above is: 1735 Market Street, Suite LL, Philadelphia, PA 19103.

⁽²⁾

The amounts shown in this column represent the balance, as of December 31, 2008, of restricted units credited to the respective deferred compensation accounts established for each independent director pursuant to the terms of the Sunoco Partners LLC Director’s Deferred Compensation Plan. These restricted units cannot be converted to our common units, and will be paid out in cash (as a lump sum or series of installments), commencing on: (1) the later of: (a) the first day of the calendar year following the date of separation from Board service, or (b) the first day following the six (6) month anniversary of separation from Board service; or (2) in the event of death, the later of: (a) the first day of the calendar year following the year of death, (b) the first day following the six (6) month anniversary of separation from Board service, or (c) the date that is thirty (30) days after the Participant’s death. In no event will payment be made within six (6) months of the compensation being earned or awarded. A portion of these restricted units, credited quarterly to each such director’s mandatory deferred compensation account, reflects payment of the applicable Board restricted unit retainer.

⁽³⁾	Sunoco, Inc. is the ultimate parent company of Sunoco Partners LLC and may, therefore, be deemed to beneficially own the units that are held by Sunoco Partners LLC.

⁽⁴⁾	Ms. Elsenhans has joint voting and investment power with respect to these shares.

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In addition to the foregoing, Tortoise Capital Advisors LLC, a Delaware limited liability company (“TCA”), filed a Schedule 13G on February 12, 2009, to report that, as of December 31, 2008, it had shared voting power over 1,715,904 common units of the Partnership, and beneficial ownership of, and shared dispositive power over, 1,759,847 common units of the Partnership, representing 6.1 percent of the total outstanding common units of the Partnership, as of that date.

The following table sets forth certain information regarding beneficial ownership of Sunoco, Inc.’s common stock, as of December 31, 2008, by directors of Sunoco Partners LLC, by each named executive officer and by all directors and executive officers of Sunoco Partners LLC as a group. Unless otherwise noted, each individual exercises sole voting or investment power over the shares of Sunoco, Inc. common stock shown in the table. For purposes of this table, beneficial ownership includes shares of Sunoco, Inc. common stock as to which the person has sole or shared voting or investment power and also any shares of Sunoco, Inc. common stock that such person has the right to acquire within 60 days of December 31, 2008, through the exercise of any option, warrant, or right.


Name of Beneficial Owner	Shares of Sunoco, Inc. Common Stock Beneficially Owned	Percentage of Sunoco, Inc. Common Stock Beneficially Owned
Lynn L. Elsenhans⁽¹⁾	18,000	*
Deborah M. Fretz	2,271	*
Cynthia A. Archer	9,255	*
L. Wilson Berry, Jr.	0	*
Stephen L. Cropper	4,000	*
Terence P. Delaney	24,177	*
Bruce G. Fischer	72,346	*
Philip L. Frederickson	0	*
Bruce D. Davis, Jr.	14	*
David A. Justin	0	*
Christopher W. Keene	0	*
Neal E. Murphy	300	*
All directors and executive officers as a group (12 persons)	130,363

*	Less than 0.5 percent.

⁽¹⁾	Ms. Elsenhans has joint voting and investment power with respect to these shares.

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

As of December 31, 2008, our general partner owned 12,063,734 common units, representing a 41.3 limited partner interest in us. In addition, the general partner owns a 2 percent general partner interest in us. The general partner’s ability to manage and operate us and its ownership of a 43.3 percent partnership interest effectively gives the general partner the ability to control us.

Distribution and Payments to the General Partner and Its Affiliates

The following table summarizes the distribution and payments made and to be made us to the general partner and its affiliates in connection with the ongoing operation and liquidation. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

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Operational Stage

Payments to the general partner and its affiliates

We paid the general partner an administrative fee, $6.0 million for the year ended December 31, 2008, for the provision of various general and administrative services for our benefit. In addition, the general partner is entitled to reimbursement for all expenses it incurs on our behalf, including other general and administrative expenses. These reimbursable expenses include the salaries and the cost of employee benefits of employees of the general partner who provide services to us. The general partner has sole discretion in determining the amount of these expenses.

Removal or withdrawal of the general partner

If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests as provided in the Partnership Agreement.

Liquidation Stage

Liquidation

Upon liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.

Concurrently with the closing of the February 2002 IPO, we entered into several agreements with Sunoco, Inc. (R&M), and/or one or more of its affiliates. These agreements include the Omnibus Agreement, the Pipelines and Terminals Storage and Throughput Agreement, the Interrefinery Lease Agreement, an intellectual property license agreement, certain crude oil purchase and sale agreements, a treasury services agreement and other agreements, all of which are discussed in detail under “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Agreements with Sunoco R&M and Sunoco, Inc.”

Subsequent to the February 2002 IPO, we entered into other agreements with Sunoco, Inc., Sunoco R&M and the general partner, including various throughput agreements regarding certain recently acquired assets or improvements or expansions at existing assets not covered by the Pipelines and Terminals Storage and Throughput Agreement; the purchase agreements with Sunoco R&M to acquire the Eagle Point refinery logistics assets and an undivided interest in the Mesa Pipe Line system; and certain redemption and expense-sharing agreements with Sunoco, Inc. (and/or its affiliates) that were ancillary to our April 2004 and May 2005 offerings of common units for sale to the public. For further information on these agreements, please refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Agreements with Sunoco R&M and Sunoco, Inc.”

Approval and Review of Related Party Transactions

Our Partnership Agreement and the Omnibus Agreement each contain provisions for our Conflicts Committee, comprised of our general partner’s independent directors, to review transactions with Sunoco, Inc. In some cases review is required and in others it is at the discretion of our general partner. Generally, transactions with Sunoco, Inc. that are material to us are referred to the Conflicts Committee for review and approval. In determining materiality, our general partner evaluates several factors including, the term of the transaction, the capital investment required, and the revenues expected from the transaction.

136

With respect to other related party transactions, we have in place a Code of Business Conduct and Ethics that is applicable to all directors, officers and employees of the Partnership and its subsidiaries and affiliates, a Code of Ethics for Senior Officers of the Partnership and its subsidiaries and affiliates, and a Conflict of Interest Policy applicable to all directors, officers and employees of the Partnership and its subsidiaries and affiliates. Each of these policies requires the approval by a supervisor, officer, or the Board of Directors, prior to entering into any related party transaction that could present a potential conflict of interest. Each of the Partnership Agreement, Code of Business Conduct and Ethics, and Code of Ethics for Senior Officers is publicly available on our website.

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following table presents the aggregate fees for audit and other professional services by our independent registered public accounting firm, Ernst & Young LLP, for each of the last two fiscal years:


	For the Year Ended December 31,
Type of Fee	2007		2008
Audit Fees⁽¹⁾	$	1,140,000	$	1,393,000
Audit Related Fees		—		—
Tax Fees		—		—
All Other Fees		—		—

	$	1,140,000	$	1,393,000

NOTE TO TABLE:

⁽¹⁾

Audit fees consist of fees for the audit of the Partnership’s annual financial statements, review of financial statements included in the Partnership’s quarterly reports on Form 10-Q and review registration statements and issuance of comfort letters, consents and review of documents filed with the SEC. Audit fees also include the fees for the audit of the Partnership’s internal control as required by Section 404 of the Sarbanes-Oxley Act of 2002.

Each of the services listed above were approved by the Audit/Conflicts Committee of the general partner’s board of directors prior to their performance. All services rendered by Ernst & Young LLP, are performed pursuant to a written engagement letter with the general partner.

The Audit/Conflicts Committee of the general partner’s board of directors is responsible for pre-approving all audit services, and permitted non-audit services, to be performed by the independent registered public accounting firm for the Partnership, or its general partner. The Committee reviews the services to be performed to determine whether provision of such services potentially could impair the independence of the Partnership’s independent registered public accounting firm. The Committee’s approval procedures include reviewing a detailed budget for each particular service to be rendered, as well as a description of, and budgeted amounts for, specific categories of anticipated non-audit services. Pre-approval is generally granted for up to one year. Committee approval is required to exceed the budgeted amount for any particular category of services or to engage the independent registered public accounting firm for services not included in the budget. Additional services or specific engagements may be approved, on a case-by-case basis, prior to the independent registered public accounting firm undertaking such services.

Subject to the requirements of applicable law, the Audit/Conflicts Committee may delegate such pre-approval authority to the Audit/Conflicts Committee chairman. However, any pre-approvals granted by the chairman, acting pursuant to such delegated authority, are reviewed by the full membership of the Audit/Conflicts Committee at its next regular meeting. Management of the general partner provides periodic updates to the Audit/Conflicts Committee regarding the extent of any services provided in accordance with this pre-approval process, as well as the cumulative fees incurred to date for all non-audit services, to ensure that such services are within the parameters approved by the Audit/Conflicts Committee.

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PART IV

ITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) The following documents are filed as part of this report:

(1) The financial statements are included in Item 8. Financial Statements and Supplementary Data.

(2) All financial statement schedules required are included in the financial statements or notes thereto.

(3) Exhibits:


Exhibit No.		Description
2.1*		Purchase and Sale Agreement by and between Mobil Pipeline Company and Sunoco Pipeline L.P., executed May 6, 2005 (incorporated by reference to Exhibit 2.1 of Form 10-Q, file No. 1-31219, filed May 9, 2005)

2.1.1*		List of Schedules and Exhibits to Purchase and Sale Agreement omitted from this filing. Registrant hereby undertakes, pursuant to Regulation S-K Item 601(2) to furnish any such schedules and exhibits to the SEC supplementally, upon request (incorporated by reference to Exhibit 2.1.1 of Form 10-Q, file No. 1-31219, filed May 9, 2005)

2.2*		Sale and Purchase Agreement for MagTex Refined Products Pipeline System between Mobil Pipe Line Company and Sunoco Pipeline L.P., executed April 28, 2008 (incorporated by reference to Exhibit 2.1. of Form 10-Q, file No. 1-31219, filed August 6, 2008)

2.2.1*		List of Schedules and Exhibits to Sale and Purchase Agreement omitted from this filing. Registrant hereby undertakes, pursuant to Regulation S-K Item 601(2) to furnish any such schedules and exhibits to the SEC supplementally, upon request (incorporated by reference to Exhibit 2.1.1 of Form 10-Q, file No. 1-31219, filed August 6, 2008)

2.3*		Terminals Sale and Purchase Agreement for Center, TX, Hearne (East), TX, Waco, TX and Waskom, TX Terminals between ExxonMobil Oil Corporation and Sunoco Partners Marketing & Terminals L.P., executed April 28, 2008 (incorporated by reference to Exhibit 2.2 of Form 10-Q, file No. 1-31219, filed August 6, 2008)

2.3.1*		List of Schedules and Exhibits to Terminals and Purchase Agreement omitted from this filing. Registrant hereby undertakes, pursuant to Regulation S-K Item 601(2) to furnish any such schedules and exhibits to the SEC supplementally, upon request (incorporated by reference to Exhibit 2.2.1 of Form 10-Q, file No. 1-31219, filed August 6, 2008)

2.4*		Terminal Sale and Purchase Agreement for Arcadia, LA Terminal between Exxon Mobil Corporation and Sunoco Partners Marketing & Terminals L.P., executed April 28, 2008 (incorporated by reference to Exhibit 2.3 of Form 10-Q, file No. 1-31219, filed August 6, 2008)

2.4.1*		List of Schedules and Exhibits to Terminals and Purchase Agreement omitted from this filing. Registrant hereby undertakes, pursuant to Regulation S-K Item 601(2) to furnish any such schedules and exhibits to the SEC supplementally, upon request (incorporated by reference to Exhibit 2.3.1 of Form 10-Q, file No. 1-31219, filed August 6, 2008)

2.5*		Terminal Sale and Purchase Agreement for Hearne, TX (West) Terminal between Mobil Pipe Line Company and Sunoco Partners Marketing & Terminals L.P., executed April 28, 2008 (incorporated by reference to Exhibit 2.4 of Form 10-Q, file No. 1-31219, filed August 6, 2008)

2.5.1*		List of Schedules and Exhibits to Terminal and Purchase Agreement omitted from this filing. Registrant hereby undertakes, pursuant to Regulation S-K Item 601(2) to furnish any such schedules and exhibits to the SEC supplementally, upon request ( incorporated by reference to Exhibit 2.4.1 of Form 10-Q, file No. 1-31219, filed August 6, 2008)

138


Exhibit No.		Description
3.1*		Certificate of Limited Partnership of Sunoco Logistics Partners L.P. (incorporated by reference to Exhibit 3.1 to Form S-1 Registration Statement, file No. 333-71968, filed October 22, 2001)

3.2*		Certificate of Limited Partnership of Sunoco Logistics Operations L.P. (incorporated by reference to Exhibit 3.1 to Amendment No. 1 to Form S-1 filed December 18, 2001)

3.3*		First Amended and Restated Agreement of Limited Partnership of Sunoco Logistics Partners Operations L.P., dated as of February 8, 2002 (incorporated by reference to Exhibit 3.5 of Form 10-K, file No. 1-31219, filed April 1, 2002)

3.4*		Second Amended and Restated Agreement of Limited Partnership of Sunoco Logistics Partners L.P., dated as of July 20, 2004 (incorporated by reference to Exhibit 3.1 of Form 10-Q, file No. 1-31219, filed August 5, 2004)

3.4.1*		Amendment No. 1 to the Second Amended and Restated Agreement of Limited Partnership of Sunoco Logistics Partners L.P. dated as of January 23, 2008 (incorporated by reference to Exhibit 3.4.1 of Current Report of Form 10-K, file No. 1-31219, filed February 26, 2008)

3.4.2*		Amendment No. 2 to the Second Amended and Restated Agreement of Limited Partnership of Sunoco Logistics Partners L.P., dated as of November 18, 2008 (incorporated by reference to Exhibit 3.1 of Current Report on Form 8-K, File No. 1-31219, filed November 20, 2008)

10.1*		Credit Agreement dated as of August 8, 2007, by and among Sunoco Logistics Partners Operations L.P., as Borrower; Sunoco Logistics Partners L.P., as Guarantor; Citibank, N.A., as Administrative Agent, Swingline Lender and L/C Issuer and the other lenders parties thereto (incorporated by reference to Exhibit 10.1 of Form 10-Q/A, file No. 1-31219, filed November 19, 2007)

10.2*		Indenture, dated as of February 7, 2002, between Sunoco Logistics Partners Operations L.P. and First Union National Bank (incorporated by reference to Exhibit 10.2 of Form 10-K, file No. 1-31219, filed April 1, 2002)

10.3*		Indenture, dated as of December 16, 2005 (incorporated by reference to Exhibit 4.4 of Registration Statement on Form S-3, File No. 333-130564, filed December 21, 2005)

10.4*		Registration Rights Agreement, dated as of February 8, 2002, among Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners L.P., Sunoco Pipeline L.P., Sunoco Partners Marketing & Terminals L.P., and the following Initial Purchasers: Lehman Brothers, Inc., Credit Suisse First Boston Corporation, Banc of America Securities LLC, Salomon Smith Barney Inc., UBS Warburg LLC and First Union Securities, Inc. (incorporated by reference to Exhibit 10.3 of Form 10-K, file No. 1-31219, filed April 1, 2002)

10.5*		Contribution, Conveyance and Assumption Agreement, dated as of February 8, 2002, among Sunoco, Inc., Sun Pipe Line Company of Delaware, Sunoco, Inc. (R&M), Atlantic Petroleum Corporation; Sunoco Texas Pipe Line Company, Sun Oil Line of Michigan (Out) LLC, Mid-Continent Pipe Line (Out) LLC, Sun Pipe Line Services (Out) LLC, Atlantic Petroleum Delaware Corporation, Atlantic Pipeline (Out) L.P., Sunoco Partners LLC, Sunoco Partners Lease Acquisition & Marketing LLC, Sunoco Logistics Partners L.P., Sunoco Logistics Partners GP LLC, Sunoco Pipeline L.P., Sunoco Partners Marketing & Terminals L.P., Sunoco Mid-Con (In) LLC, Atlantic (In) L.P., Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners Operations GP LLC, Atlantic R&M (In) L.P., Sun Pipe Line Services (In) L.P., Sunoco Michigan (In) LLC, Atlantic (In) LLC, Sunoco Logistics Pipe Line GP LLC, Sunoco R&M (In) LLC, and Atlantic Refining & Marketing Corp. (incorporated by reference to Exhibit 10.4 of Form 10-K, file No. 1-31219, filed April 1, 2002)

139


Exhibit No.		Description
10.6*		Omnibus Agreement, dated as of February 8, 2002, by and among Sunoco, Inc., Sunoco, Inc. (R&M), Sunoco Logistics Pipe Line Company of Delaware, Atlantic Petroleum Corporation, Sunoco Texas Pipe Line Company, Sun Pipe Line Services (Out) LLC, Sunoco Logistics Partners L.P., Sunoco Logistics Partners Operations L.P., and Sunoco Partners LLC (incorporated by reference to Exhibit 10.5 of Form 10-K, file No. 1-31219, filed April 1, 2002)

10.6.1		Amendment No. 2009-1 to Omnibus Agreement, dated as of February 23, 2009, and effective January 1, 2009, by and among Sunoco, Inc., Sunoco, Inc. (R&M), Sunoco Logistics Pipe Line Company of Delaware, Atlantic Petroleum Corporation, Sun Pipe Line Company, Sun Pipe Line Delaware (Out) LLC, Sunoco Logistics Partners L.P., Sunoco Logistics Partners Operations L.P., and Sunoco Partners LLC

10.7*		Pipelines and Terminals Storage and Throughput Agreement, dated as of February 8, 2002, among Sunoco, Inc. (R&M), Sunoco Logistics Partners L.P., Sunoco Logistics Partners Operations L.P., Sunoco Partners LLC, Sunoco Partners Marketing & Terminals L.P., Sunoco Pipeline L.P., Sunoco Logistics Partners GP LLC, and Sunoco Logistics Partners Operations GP LLC (incorporated by reference to Exhibit 10.6 of Form 10-K, file No. 1-31219, filed April 1, 2002)

10.8*		Amended and Restated Treasury Services Agreement, dated as of November 26, 2003, by and among Sunoco, Inc., Sunoco Logistics Partners L.P., and Sunoco Logistics Partners Operations L.P. (incorporated by reference to Exhibit 10.7.1 of Form 10-K, file No. 1-31219, filed March 4, 2004)

10.9*		Intellectual Property and Trademark License Agreement, dated as of February 8, 2002 among Sunoco, Inc., (“Sunoco”), Sunoco, Inc. (R&M), Sunmarks, Inc., Sunoco Logistics Partners L.P., Sunoco Logistics Partners Operations L.P., Sunoco Partners Marketing & Terminals L.P., Sunoco Pipeline L.P., and Sunoco Partners LLC (incorporated by reference to Exhibit 10.8 of Form 10-K, file No. 1-31219, filed April 1, 2002)

10.10*		Inter-refinery Lease, dated as of February 8, 2002, between Sunoco Pipeline L.P., and Sunoco, Inc. (R&M) (incorporated by reference to Exhibit 10.9 of Form 10-K, file No. 1-31219, filed April 1, 2002)

10.11*		Sunoco Partners LLC Executive Involuntary Severance Plan, as amended and restated as of January 23, 2008 (incorporated by reference to Exhibit 10.10 of Form 10-K, file No. 1-31219, filed February 26, 2008)

10.12*		Sunoco Partners LLC Long-Term Incentive Plan, as amended and restated as of October 20, 2007 (incorporated by reference to Exhibit 10.11 of Form 10-K, file No. 1-31219, filed February 26, 2008)

10.12.1*		Form of Restricted Unit Agreement under the Sunoco Partners LLC Long-Term Incentive Plan (incorporated by reference to Exhibit 10.11.1 of Form 10-K, file No. 1-31219, filed February 26, 2008)

10.12.2*		Form of Restricted Unit Agreement under the Sunoco Partners LLC Long-Term Incentive Plan (incorporated by reference to Exhibit 10.11.2 of Form 10-K, file No. 1-31219, filed February 26, 2008)

10.13		Sunoco Partners LLC Annual Incentive Plan, as amended and restated as of January 28, 2009

10.14*		Sunoco Partners LLC Directors’ Deferred Compensation Plan, as amended and restated as of October 20, 2007 (incorporated by reference to Exhibit 10.13 of Form 10-K, file No. 1-31219, filed February 26, 2008)

10.15*		Sunoco Partners LLC Special Executive Severance Plan, as amended and restated as of October 20, 2007 (incorporated by reference to Exhibit 10.14 of Form 10-K, file No. 1-31219, filed February 26, 2008)

140


Exhibit No.		Description
10.16		Sunoco Partners LLC Executive Compensation Summary Sheet for 2009

10.17		Sunoco Partners LLC Independent Director Compensation Summary Sheet for 2009

10.18**		Throughput and Deficiency Agreement, executed May 6, 2005 (incorporated by reference to Exhibit 10.17 to Form 10-K, File No. 1-31219, filed February 23, 2007)

10.19*		Purchase and Sale Agreement, between Alon Petroleum Pipe Line, LP and Sunoco Pipeline L.P., dated as of February 13, 2006 (incorporated by reference to Exhibit 10.1 of Form 8-K, file No. 1-31219, filed February 16, 2006)

10.20***		Crude Oil Pipeline Throughput and Deficiency Agreement between Motiva Enterprises LLC and Sunoco Pipeline L.P., dated as of December 19, 2006 (incorporated by reference to Exhibit 10.19 of Form 10-K, file no. 1-31219, filed February 23, 2007)

10.21***		Marine Dock and Terminaling Agreement between Motiva Enterprises LLC and Sunoco Partners Marketing & Terminals L.P., dated as of December 19, 2006 (incorporated by reference to Exhibit 10.20 of Form 10-K, file no. 1-31219, filed February 23, 2007)

10.22*		Membership Interest Purchase Agreement, effective as of July 27, 2006, between Sunoco, Inc. and Sunoco Pipeline Acquisition LLC (incorporated by reference to Exhibit 10.1 of Form 10-Q, file No. 1-31219, filed August 2, 2006)

10.23†		Product Terminal Services Agreement, dated as of May 1, 2007, among Sunoco, Inc. (R&M) and Sunoco Partners Marketing & Terminals L.P. (incorporated by reference to Exhibit 10.1 of Form 10-Q, file No. 1-31219, filed July 31, 2007)

12.1		Statement of Computation of Ratio of Earnings to Fixed Charges

14.1*		Code of Ethics for Senior Officers (incorporated by reference to Exhibit 10.14.1 to Form 10-K, File No. 1-31219, filed March 4, 2004)

21.1		Subsidiaries of Sunoco Logistics Partners L.P.

23.1		Consent of Independent Registered Public Accounting Firm

24.1		Power of Attorney

31.1		Chief Executive Officer Certification Pursuant to Exchange Act Rule 13a-14(a)

31.2		Chief Financial Officer Certification Pursuant to Exchange Act Rule 13a-14(a)

32.1		Officer Certification Pursuant to Exchange Act Rule 13a-14(b) and 18 U.S.C. § 1350

99.1		Audited Balance Sheet of Sunoco Partners LLC as of December 31, 2008

*	Each such exhibit has heretofore been filed with the Securities and Exchange Commission as part of the filing indicated and is incorporated herein by reference.

**	Confidential status has been granted for certain portions of this exhibit pursuant to a Confidential Treatment Request filed May 9, 2005. Such provisions have been separately filed with the Commission.

***	Confidential status has been requested for certain portions thereof pursuant to a Confidential Treatment Request filed February 23, 2007. Such provisions have been separately filed with the Commission.

†	Confidential status has been requested for certain portions thereof pursuant to a Confidential Treatment Request filed July 31, 2007. Such provisions have been separately filed with the Commission.

141

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


SUNOCO LOGISTICS PARTNERS L.P. (Registrant)

By:	Sunoco Partners LLC (its General Partner)

	By:	/s/ NEAL E. MURPHY
		Neal E. Murphy Vice President and Chief Financial Officer

February 24, 2009

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by or on behalf of the following persons on behalf of the registrant and in the capacities indicated on February 24, 2009.



CYNTHIA A. ARCHER*		PHILIP L. FREDERICKSON*
Cynthia A. Archer Director of Sunoco Partners LLC, General Partner of Sunoco Logistics Partners L.P.		Philip L. Frederickson Director of Sunoco Partners LLC, General Partner of Sunoco Logistics Partners L.P.

STEPHEN L. CROPPER*		MICHAEL D. GALTMAN*
Stephen L. Cropper Director of Sunoco Partners LLC, General Partner of Sunoco Logistics Partners L.P.		Michael D. Galtman Controller (Principal Accounting Officer)

TERENCE P. DELANEY*		BRUCE G. FISCHER*
Terence P. Delaney Director of Sunoco Partners LLC, General Partner of Sunoco Logistics Partners L.P.		Bruce G. Fischer Director of Sunoco Partners LLC, General Partner of Sunoco Logistics Partners L.P.

LYNN L. ELSENHANS*		DEBORAH M. FRETZ*
Lynn L. Elsenhans Director and Chairman of Sunoco Partners LLC, General Partner of Sunoco Logistics Partners L.P.		Deborah M. Fretz Chief Executive Officer and Director of Sunoco Partners LLC, General Partner of Sunoco Logistics Partners L.P. (Principal Executive Officer)

L. WILSON BERRY, JR.*
L. Wilson Berry, Jr. Director of Sunoco Partners LLC, General Partner of Sunoco Logistics Partners L.P

142