Sunoco Logistics--Form 10-K
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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, 2003

 

OR

 

¨ 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.)

Ten Penn Center

1801 Market Street, Philadelphia, PA

 

19103-1699

(Address of principal executive offices)   (Zip Code)

 

Registrant’s telephone number, including area code: (215) 977-3000

 


 

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

 

Securities registered pursuant to Section 12(g) of the Act: None

 


 

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 amendments of this Form 10-K.  x

 

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).    Yes  x    No  ¨

 

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 $163.8 million as of June 27, 2003, based on $28.49 per unit, the closing price of the Common Units as reported on the New York Stock Exchange on that date.

 

At February 27, 2004, the number of the registrant’s Common Units outstanding was 11,388,154, and its Subordinated Units outstanding was 11,383,639.

 

DOCUMENTS INCORPORATED BY REFERENCE: NONE

 



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TABLE OF CONTENTS

 

PART I

   1
     ITEM 1.   

BUSINESS

   1
     ITEM 2.   

PROPERTIES

   22
     ITEM 3.   

LEGAL PROCEEDINGS

   22
     ITEM 4.   

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

   22

PART II

   23
     ITEM 5.   

MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED SECURITYHOLDER MATTERS

   23
     ITEM 6.   

SELECTED FINANCIAL DATA

   24
     ITEM 7.   

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

   28
     ITEM 7A.   

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

   50
     ITEM 8.   

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

   51
     ITEM 9.   

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

   80
     ITEM 9A.   

CONTROLS AND PROCEDURES

   80

PART III

   81
     ITEM 10.   

DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

   81
     ITEM 11.   

EXECUTIVE COMPENSATION

   84
     ITEM 12.   

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

   89
     ITEM 13.   

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

   91
     ITEM 14.   

PRINCIPAL ACCOUNTANT FEES AND SERVICES

   96

PART IV

   97
     ITEM 15.   

EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

   97

SIGNATURES

   100


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Forward-Looking Statements

 

Certain matters discussed in this report, excluding historical information, include forward-looking statements made in reliance on the safe harbor provisions of the Private Securities Litigation Reform Act of 1995.

 

Forward-looking statements discuss Sunoco Logistics Partners L.P.’s (the “Partnership”) expected future results based on current and pending business operations, and may be identified by words such as “anticipates”, “believes”, “expects”, “planned”, “scheduled” or similar expressions. Although management of the Partnership believes these forward-looking statements are reasonable, they are based upon a number of assumptions, any or all of which ultimately may prove to be inaccurate. Statements made regarding future results are subject to numerous assumptions, uncertainties and risks that may cause future results to be materially different from the results stated or implied in this document.

 

The following are among the important factors that could cause actual results to differ materially from any results projected, forecasted, estimated or budgeted:

 

  Changes in demand both for crude oil we buy and sell, as well as for crude oil and refined petroleum products that we store and distribute;

 

  Changes in demand for storage in the Partnership’s petroleum terminals;

 

  The loss of Sunoco, Inc. (R&M) as a customer or a significant reduction in its current level of throughput and storage with the Partnership;

 

  An increase in the competition encountered by the Partnership’s petroleum terminals, pipelines and crude oil acquisition and marketing operations;

 

  Changes in the throughput on petroleum product pipelines owned and operated by third parties and connected to the Partnership’s petroleum product pipelines and terminals;

 

  Changes in the financial condition or operating results of joint ventures and other holdings in which the Partnership has an equity ownership interest;

 

  Changes in the general economic conditions in the United States;

 

  Changes in laws and regulations to which the Partnership is subject, including federal, state, and local tax, safety, environmental and employment laws;

 

  Phase-outs or restrictions on the use of MTBE;

 

  Improvements in energy efficiency and technology resulting in reduced demand;

 

  The Partnership’s ability to manage rapid growth;

 

  The Partnership’s ability to control costs;

 

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

 

  Global and domestic economic repercussions from terrorist activities and international hostilities and the government’s response thereto;

 

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

 

  Changes in the reliability and efficiency of the Partnership’s operating facilities or those of Sunoco, Inc. (R&M) or third parties;

 

  Changes in the expected level of environmental remediation spending;

 

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


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  The ability of announced acquisitions or expansions to be cash-flow accretive;

 

  The Partnership’s ability to successfully consummate announced acquisitions or expansions and integrate them into existing business operations;

 

  Risks related to labor relations;

 

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

 

  Price trends and overall demand for refined petroleum products, crude oil and natural gas liquids in the United States, economic activity, weather, alternative energy sources, conservation and technological advances may affect price trends and demand for the Partnership’s business activities;

 

  Changes in the Partnership’s tariff rates, implemented by federal and/or state government regulators;

 

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

 

  Restrictive covenants in the Partnership’s or Sunoco, Inc.’s credit agreements;

 

  Changes in the Partnership’s or Sunoco, Inc.’s credit ratings, as assigned by ratings agencies;

 

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

 

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

 

  The political and economic stability of the oil producing nations of the world; and

 

  The costs and effects of legal and administrative claims and proceedings against the Partnership or its subsidiaries, and changes in the status of litigation to which the Partnership 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 the Partnership’s forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on future results. The Partnership undertakes no obligation to update publicly any forward-looking statement whether as a result of new information or future events.


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PART I

 

ITEM 1. BUSINESS

 

(a) General Development of Business

 

The Partnership is a Delaware limited partnership formed on October 15, 2001. The principal executive offices of Sunoco Partners LLC, the Partnership’s general partner (the “General Partner”), are located at Ten Penn Center, 1801 Market Street, Philadelphia, Pennsylvania 19103 (telephone (215) 977-3000). The Partnership’s website address is www.sunocologistics.com.

 

In February 2002, 5,750,000 common units, representing approximately 24.8 percent of the partnership interests, were sold to the public in an initial public offering (“IPO”). Sunoco, Inc., through its wholly-owned subsidiaries (collectively, “Sunoco”), currently owns approximately 75.3 percent of the partnership interests, including the 2 percent general partner interest.

 

(b) Financial Information about Segments

 

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

 

(c) Narrative Description of Business

 

The Partnership is a limited partnership formed by Sunoco, Inc. to own, operate and acquire a geographically diversified portfolio of complementary energy assets. The Partnership is principally engaged in the transport, terminalling and storage of refined products and crude oil and the purchase and sale of crude oil. Sunoco, Inc. (R&M), a wholly-owned refining and marketing subsidiary of Sunoco (“Sunoco R&M”), accounted for approximately 52 percent of the Partnership’s total revenues for the year ended December 31, 2003. The business comprises three segments:

 

  The Eastern Pipeline System primarily serves the Northeast and Midwest United States operations of Sunoco R&M and includes: approximately 1,700 miles of refined product pipelines, including a one-third interest in an 80-mile refined product pipeline, and 58 miles of interrefinery pipelines between two of Sunoco R&M’s refineries; a 123-mile crude oil pipeline; a 9.4 percent interest in Explorer Pipeline Company, a joint venture that owns a 1,410-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 656-mile refined product pipeline.

 

  The Terminal Facilities consist of 31 inland refined product terminals with an aggregate storage capacity of 4.8 million barrels, primarily serving the Partnership’s Eastern Pipeline System; a 2.0 million barrel refined product terminal serving Sunoco R&M’s Marcus Hook refinery near Philadelphia, Pennsylvania; a 12.5 million barrel marine crude oil terminal on the Texas Gulf Coast, the Nederland Terminal; one inland and two marine crude oil terminals with a combined capacity of 3.4 million barrels, and related pipelines, all of which serve Sunoco R&M’s Philadelphia 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 1,868 miles of crude oil trunk pipelines and approximately 822 miles of crude oil gathering lines that supply the trunk pipelines; approximately 113 crude oil transport trucks; approximately 130 crude oil truck unloading facilities; and a 43.8 percent interest in West Texas Gulf Pipe Line Company, a joint venture that owns a 579-mile crude oil pipeline.

 

The Partnership and its equity interests 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 17 states. Revenues are generated by

 

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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 the Partnership’s terminals. The Partnership also generates revenue by purchasing domestic crude oil and selling it to Sunoco R&M and other customers. Generally, as crude oil is purchased, corresponding sale transactions are simultaneously entered into involving physical deliveries of crude oil, which enables the Partnership 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. The Partnership’s practice is to not enter into futures contracts.

 

Upon the closing of the Partnership’s IPO on February 8, 2002, the Eastern Pipeline System, Terminal Facilities and Western Pipeline System were transferred to the Partnership, including certain related liabilities. Certain other liabilities, including environmental and toxic tort liabilities, have been retained by Sunoco, Inc. under the indemnification provisions of an omnibus agreement (the “Omnibus Agreement”) (see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Agreements with Sunoco R&M and Sunoco, Inc.”). The following discussion has been prepared as if the assets were operated as a stand-alone business throughout the periods presented. Unless otherwise noted, the Partnership owns and operates all of the assets described.

 

Eastern Pipeline System

 

Sunoco R&M accounted for approximately 68 percent of the Eastern Pipeline segment’s total revenues for the year ended December 31, 2003.

 

Refined Product Pipelines

 

The refined product pipelines transport refined products from Sunoco R&M’s Philadelphia and Marcus Hook, Pennsylvania and Toledo, Ohio refineries, as well as from third parties, 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), LPGs (such as propane, butane, isobutane, and a butane/butylene mixture), refining feedstocks, and other hydrocarbons (such as toluene and xylene). 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.

 

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. Management of the Partnership believes that total shipments is a better performance indicator for the Eastern Pipeline System than barrels transported as certain refined product pipelines, including interrefinery and transfer pipelines, transport large volumes over short distances and generate minimal revenues. The following excludes amounts attributable to equity ownership interests in the corporate joint ventures:

 

     Year Ended December 31,

     1999

   2000

   2001

   2002

   2003

Total shipments (in thousands of barrel miles
per day)

   56,109    54,880    55,165    56,736    55,293

 

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 being higher 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.

 

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The following table sets forth, for each of the refined product pipeline systems, the origin and destination, miles of pipeline and diameter. Except as indicated below, the Partnership owns 100 percent of the refined product pipeline systems.

 

Origin and Destination

 

     December 31, 2003

     Miles of
Pipeline


   Diameter

          (inches)

Montello, PA to Kingston, PA(1)

   70    8,6

Montello, PA to Kingston, PA(2)

   84    6

Philadelphia, PA to Linden, NJ(3)

   88    16,12

Twin Oaks, PA to Newark, NJ

   118    14

Philadelphia, PA to Montello, PA

   210    12,8

Montello, PA to Pittsburgh, PA

   221    8

Toledo, OH to Sarnia, Canada

   241    8,6

Toledo, OH to Blawnox, PA

   260    10,8

Montello, PA to Buffalo, NY

   300    14,8
    
    

Subtotal

   1,592    N.M.

Interrefinery Pipelines(4)

   58    8,6,4

Transfer Pipelines(5)

   85    N.M.
    
    

Total

   1,735    N.M.
    
    

N.M. Not meaningful.

(1) Mileage excludes the northern-most 160 miles of this pipeline the Partnership idled in January 2003. These assets were idled as a result of a long-term agreement entered into by the Partnership in December 2002 to lease throughput capacity on a third-party refined product pipeline which allows it to provide the same service as existed on the idled pipeline while reducing operating expenses.
(2) The Partnership is seeking permission from the PA PUC to idle 74 miles of this pipeline.
(3) The Partnership owns a one-third interest in 80 miles of this pipeline.
(4) The Partnership leases these pipelines to Sunoco R&M.
(5) Consists of the Toledo, Twin Oaks, and Linden transfer pipelines.

 

Crude Oil Pipeline

 

This 123-mile, 16-inch crude oil pipeline runs from Marysville, Michigan to Toledo, Ohio. This pipeline receives crude oil from the Enbridge pipeline system for delivery to Sunoco R&M and BP refineries located in Toledo, Ohio and to Marathon Ashland’s (“MAP”) Samaria, Michigan tank farm, which supplies its refinery in Detroit, Michigan. Marysville is also a truck injection point for local production. Sunoco R&M is the major shipper on the pipeline.

 

The table below sets forth the average daily number of barrels of crude oil transported through this crude oil pipeline in each of the years presented:

 

     Year Ended December 31,

     1999

   2000

   2001

   2002

   2003

Crude oil throughput (in barrels
per day (“bpd”))

   81,464    91,464    98,226    95,311    91,951

 

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Explorer Pipeline

 

The Partnership owns a 9.4 percent interest in Explorer Pipeline Company (“Explorer”), a joint venture that owns a 1,410-mile common carrier refined product pipeline. Other owners of Explorer are Shell, MAP, ChevronTexaco, CITGO, and ConocoPhillips. 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. Shippers on the pipeline include most of the affiliates of the owners and non-affiliated customers. Sunoco R&M does not regularly ship on the pipeline. In 2000, the FERC approved Explorer’s application for market-based rates for all its tariffs. The Partnership receives a quarterly cash dividend from Explorer that is commensurate with its ownership interest.

 

During the third quarter of 2003, Explorer completed its $100 million plus expansion of the system’s capacity. The capacity from Port Arthur to Tulsa was expanded by 130,000 bpd to 690,000 bpd and the capacity from Tulsa to Chicago was expanded by 100,000 bpd to 450,000 bpd.

 

Wolverine Pipe Line

 

On November 15, 2002, the Partnership acquired 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. Other owners of Wolverine are Citgo, ExxonMobil, MAP, and Shell. The system, which is operated by ExxonMobil and Wolverine employees, originates from Chicago, Illinois and extends to Detroit, Grand Haven, and Bay City, Michigan and Toledo, Ohio with delivery points along the way. Shippers on the pipeline include affiliates of most of the owners and non-affiliated customers. The Partnership and its affiliates do not ship on the pipeline. In 2002, the FERC approved Wolverine’s application for market-based rates for the Detroit, Jackson, Niles, Hammond, and Lockport destinations. The Partnership receives a quarterly cash dividend from Wolverine that is commensurate with its ownership interest.

 

In 1999, Wolverine purchased pipeline assets belonging to Total in Michigan that supported the Alma refinery. Wolverine has used these assets to make deliveries to Lansing and Bay City. Since the purchase, Wolverine has been expanding the pipeline capacity to these cities and expects to complete the last phase of the additional planned expansion when permits are obtained.

 

West Shore Pipe Line

 

On November 15, 2002, the Partnership acquired a 9.2 percent interest in West Shore Pipe Line Company (“West Shore”), a joint venture that owns a 652-mile common carrier refined product pipeline. On September 30, 2003, the Partnership acquired an additional 3.1 percent interest in West Shore increasing its overall ownership percentage to 12.3 percent. Other owners of West Shore are Citgo, ExxonMobil, BP, Buckeye, and Shell. The system, which is operated by Citgo employees, originates from the Chicago, Illinois refining center and extends to Madison and Green Bay, Wisconsin with delivery points along the way. Shippers on the pipeline include affiliates of most of the owners and non-affiliated customers. The Partnership and its affiliates do not ship on the pipeline. In 2002, the FERC approved West Shore’s application for market-based rates for the Chicago area. The Partnership receives a quarterly cash dividend from West Shore that is commensurate with its ownership interest.

 

Yellowstone Pipe Line

 

On November 15, 2002, the Partnership acquired a 14.0 percent interest in Yellowstone Pipe Line Company (“Yellowstone”), a joint venture that owns a 656-mile common carrier refined product pipeline. Other owners of Yellowstone are ExxonMobil and ConocoPhillips. The system, which is operated by ConocoPhilips employees, originates from the Billings, Montana refining center and extends to Moses Lake, Washington with delivery points along the way. Shippers on the pipeline include affiliates of the owners and non-affiliated customers. Tariff rates are regulated by the FERC for interstate shipments and the Montana Public Service Commission for intrastate shipments in Montana. The Partnership and its affiliates do not ship on the pipeline.

 

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In 1997, the Yellowstone board of directors established a dividend policy whereby dividends would not be paid to owners until the debt incurred to finance a multi-year pipeline upgrade program was repaid. While the last payment on the debt is projected to be made in 2004, there are no assurances that dividends will be paid in 2004 or in future years.

 

Terminal Facilities

 

Sunoco R&M accounted for approximately 65 percent of the Terminal Facilities segment’s total revenues for the year ended December 31, 2003.

 

Refined Product Terminals

 

The Partnership’s 31 inland refined product terminals receive refined products from pipelines and distribute them to Sunoco R&M and to third parties, who in turn deliver them to end-users and retail outlets. Terminals play a key role in moving product to the end-user market by providing the following services: storage and inventory management; 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, the Partnership’s 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.

 

The Partnership’s 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, the Partnership’s revenues are generated by charging customers fees for blending, injecting additives, and filtering jet fuel. Refined product terminals generate the balance of their revenues from the handling of other hydrocarbons for Sunoco R&M at Vanport, Pennsylvania and Toledo, Ohio and from lubricants handled for Sunoco R&M at Cleveland, Ohio. Sunoco R&M accounts for substantially all of the Partnership’s refined product terminal revenues. The Eastern Pipeline System supplies the majority of the Partnership’s refined product terminals, with third-party pipelines supplying the remainder.

 

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

 

     Year Ended December 31,

     1999

   2000

   2001

   2002

   2003

Refined products throughput (bpd)

   251,627    266,212    272,698    272,784    283,071

 

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    207,000

Michigan

   2    411,700

New Jersey

   3    757,100

New York(1)(2)

   3    652,000

Ohio

   6    778,800

Pennsylvania

   16    1,987,800
    
  

Total

   31    4,794,400
    
  

(1) Excludes a terminal at Binghamton, New York, which was idled in early 2003.
(2) The Partnership has 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 the Partnership’s ownership interest.

 

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The 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 inventory management, storage, and distribution services for refiners and other large end-users 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). In addition, it also blends lubricants and is equipped with petroleum laboratory facilities. The terminal currently has a total shell storage capacity of approximately 12.5 million barrels in 128 aboveground storage tanks with individual capacities of up to 660,000 barrels. During 2003, construction of two new tanks was completed, which added approximately 1.3 million barrels of storage capacity to the terminal.

 

The Nederland Terminal can receive crude oil at each of its five ship docks and three barge berths, which can accommodate any vessel capable of navigating the 40-foot freshwater draft of the Sabine-Neches Ship Channel. 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 Department of Energy (“DOE”) Big Hill pipeline, the DOE West Hackberry pipeline, and the Partnership’s 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 caverns near Winnie, Texas, which have an aggregate storage capacity of 370 million barrels. The Nederland Terminal’s pipeline connections to major markets in the Lake Charles, Beaumont, Port Arthur, Houston, and Midwest areas provide customers with maximum flexibility.

 

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 1.0 million bpd of crude oil to 12 connecting pipelines. The connecting pipelines include the ExxonMobil pipelines to Wichita Falls, Texas and to its Beaumont, Texas refinery, the DOE pipelines to the Big Hill and West Hackberry Strategic Petroleum Reserve caverns, the Premcor pipeline to its Port Arthur, Texas refinery, the TotalFinaElf pipelines to its Port Arthur, Texas refinery, the Shell pipeline to Houston, Texas refineries, the West Texas Gulf and the Partnership’s pipelines to the Mid-Valley pipeline at Longview, Texas and to the Citgo pipeline at Sour Lake, Texas, the Partnership’s pipeline to Seabreeze, Texas, and the Alon pipeline to its Big Spring, Texas refinery.

 

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

 

     Year Ended December 31,

     1999

   2000

   2001

   2002

   2003

Crude oil and refined products
throughput (bpd)

   544,624    566,941    427,194    437,381    441,701

 

Revenues are generated at the Nederland Terminal primarily by providing long-term and short-term, or spot, storage services and throughput capability to a number of customers. Most of the terminal’s total revenues in 2003 were from unaffiliated third parties.

 

Fort Mifflin Terminal Complex

 

The Fort Mifflin Terminal Complex is located on the Delaware River in Philadelphia and supplies Sunoco R&M’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 R&M.

 

Fort Mifflin Terminal. The Fort Mifflin Terminal consists of two ship docks with 40-foot freshwater drafts and nine tanks with a total storage capacity of 570,000 barrels. Two of the 80,000-barrel tanks can be used to

 

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store refined products. This terminal also has a connection from the Colonial Pipeline System. Crude oil and some refined products enter the Fort Mifflin Terminal primarily from marine vessels on the Delaware River. One Fort Mifflin dock is designed to handle crude oil from very large crude carrier-class tankers and smaller crude oil vessels. The other dock can accommodate only smaller crude oil vessels.

 

Hog Island Wharf. The Hog Island Wharf is located next to the Fort Mifflin Terminal on the Delaware River. The Hog Island Wharf 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. Hog Island Wharf supplies the Partnership’s Darby Creek Tank Farm and Fort Mifflin Terminal with crude oil.

 

Darby Creek Tank Farm. The Darby Creek Tank Farm is a primary crude oil storage terminal for Sunoco R&M’s Philadelphia refinery. This facility has 26 tanks with a total storage capacity of 2.9 million barrels. Darby Creek receives crude oil from the Fort Mifflin Terminal and Hog Island Wharf via the Partnership’s pipelines. The tank farm then stores the crude oil and pumps it to the Philadelphia refinery via the Partnership’s pipelines.

 

The table below sets forth the average daily number of barrels of crude oil and refined products delivered to Sunoco R&M’s Philadelphia refinery in each of the years presented:

 

     Year Ended December 31,

     1999

   2000

   2001

   2002

   2003

Crude oil throughput (bpd)

   297,271    306,121    309,435    310,980    311,455

Refined products throughput (bpd)

   9,263    8,502    9,110    11,631    10,934
    
  
  
  
  

Total (bpd)

   306,534    314,623    318,545    322,611    322,389
    
  
  
  
  

 

Marcus Hook Tank Farm

 

The Marcus Hook Tank Farm stores substantially all of the gasoline and middle distillates that Sunoco R&M 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 the Partnership’s Twin Oaks terminal or to the Twin Oaks pump station, which supplies the Eastern Pipeline System.

 

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

 

     Year Ended December 31,

     1999

   2000

   2001

   2002

   2003

Refined products throughput (bpd)

   142,404    133,455    138,490    150,008    157,233

 

The Inkster Terminal

 

The Inkster Terminal, located near Detroit, Michigan, consists of eight salt caverns with a total storage capacity of 975,000 barrels. The Partnership uses the Inkster Terminal’s storage in connection with its Toledo, Ohio to Sarnia, Canada pipeline system and for the storage of LPGs from Sunoco R&M’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

 

Sunoco R&M accounted for approximately 51 percent of the Western Pipeline System segment’s total revenues for the year ended December 31, 2003.

 

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Crude Oil Pipelines

 

The Partnership owns and operates approximately 1,868 miles of crude oil trunk pipelines and approximately 822 miles of crude oil gathering pipelines in three primary geographic regions—Oklahoma, West Texas, and the Texas Gulf Coast and East Texas region. The Partnership is the primary shipper on the Western Pipeline System. The Partnership also delivers crude oil for Sunoco R&M and for various third parties from points in Texas and Oklahoma. Refineries directly connected to the Western Pipeline System include Sunoco R&M’s and Sinclair’s Tulsa, Oklahoma refineries and the Gary-Williams refinery in Wynnewood, Oklahoma.

 

The Partnership’s pipelines also access several trading hubs, including the largest and most significant trading hub for crude oil in the United States located in Cushing, Oklahoma (“Cushing”), as well as other trading hubs located in Colorado City and Longview, Texas. The Partnership’s crude oil pipelines also connect with other pipelines that deliver crude oil to a number of third-party refineries.

 

The table below sets forth the average aggregate daily number of barrels of crude oil transported on the Partnership’s crude oil pipelines in each of the years presented:

 

     Year Ended December 31,

     1999

   2000

   2001

   2002

   2003

Crude oil throughput (bpd)(1)

   252,098    295,991    287,237    286,912    304,471

(1) Includes lube extracted feedstocks transported from Sunoco R&M’s Tulsa, Oklahoma refinery.

 

In each geographic region, the Partnership has major crude oil trunk line systems that ship crude oil across a number of different-sized trunk pipeline segments. The following table details the mileage and diameter of the pipelines in each major crude oil trunk line system. The Partnership transports most of the crude oil to and lube extracted feedstock from Sunoco R&M’s Tulsa, Oklahoma refinery.

 

Major System

 

    

Miles of

Trunk

Pipeline


   Diameter

          (inches)

Oklahoma

         

Enid to Tulsa

   304    4,6,8,10,12

Velma to Tulsa

   248    4,6,8,10

Other

   129    4,6,8,12

West Texas

         

Hearne to Hawley

   453    6,8,12,16

Hawley to Dixon

   242    8,10

Jameson and Salt Creek to Colorado City

   93    6,8

Other

   29    8

Texas Gulf Coast and East Texas

         

Nederland to Longview

   199    10,12

Nederland to Baytown

   124    6,8

Seabreeze and Orange to Nederland

   39    6,10

Thomas to Longview

   3    8

Other

   5    8

 

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Oklahoma

 

The Partnership owns and operates a large crude oil pipeline and gathering system in Oklahoma. This system contains 681 miles of crude oil trunk pipelines and 435 miles of crude oil gathering pipelines. The Partnership has the ability to deliver substantially all of the crude oil gathered on its Oklahoma system to Cushing. Additionally, deliveries are made on the Oklahoma system to:

 

  Sunoco R&M’s and Sinclair’s Tulsa refineries;

 

  Gary-Williams’ Wynnewood refinery; and

 

  ConocoPhillips’ pipeline, which is connected to its Ponca City refinery.

 

Revenues are generated on the Partnership’s Oklahoma system from tariffs paid by shippers utilizing the Partnership’s transportation services. The Partnership files these tariffs with the Oklahoma Corporation Commission and the FERC. The Partnership is the largest purchaser of crude oil from producers in the state, and is the primary shipper on its Oklahoma system. Other significant shippers are Sunoco R&M and Sinclair, which ship primarily on the Enid to Tulsa segment.

 

West Texas

 

The Partnership owns and operates approximately 817 miles of crude oil trunk pipelines and approximately 244 miles of crude oil gathering pipelines in West and North Central Texas. Deliveries are made on the West Texas system to:

 

  a Valero, L.P. pipeline at Dixon, Texas that delivers crude oil to Valero Energy Corporation’s refinery in McKee, Texas;

 

  a ConocoPhillips’ pipeline at South Bend, Texas that makes deliveries to ConocoPhillips’s Ponca City refinery;

 

  a TEPPCO pipeline at South Bend that makes deliveries to Gary-Williams’ Wynnewood refinery;

 

  the West Texas Gulf pipeline, which is 43.8 percent owned by the Partnership, at Tye and Colorado City, Texas that connects to the Mid-Valley pipeline in Longview, Texas, which is 55.3 percent owned by Sunoco and makes deliveries to Sunoco R&M’s Toledo refinery and other Midwest refineries; and

 

  other third-party pipelines at Colorado City that deliver crude oil to Cushing.

 

The Partnership is the shipper of substantially all the volume on this system. Revenues are generated in West Texas from tariffs paid by shippers utilizing the Partnership’s transportation services. These tariffs are filed with the Texas Railroad Commission.

 

Texas Gulf Coast and East Texas

 

The Partnership owns and operates approximately 370 miles of crude oil trunk pipelines and approximately 143 miles of crude oil gathering pipelines that extend between the Texas Gulf Coast region near Beaumont and Baytown, Texas and the East Texas field near Longview, Texas. The Partnership transports multiple grades of crude oil, including foreign imports, and other refinery and petrochemical feedstocks, such as condensate and naphtha, on these pipelines. Crude oil is received for these systems from other pipelines, the Nederland Terminal, the Partnership’s trucks, third-party trucks, and the Partnership’s pipeline gathering systems. This system provides access to major delivery points with interconnecting pipelines in Texas at Longview, Sour Lake, and Nederland.

 

Revenues are generated from tariffs paid by shippers utilizing the Partnership’s transportation services. These tariffs are filed with the Texas Railroad Commission and the FERC. The Partnership is the primary shipper

 

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on the Texas Gulf Coast and East Texas system. Sunoco R&M ships on the Nederland to Longview segment, which connects with the Mid-Valley pipeline for deliveries to Sunoco R&M’s Toledo refinery.

 

West Texas Gulf Pipe Line

 

On November 15, 2002, the Partnership acquired a 43.8 percent interest in West Texas Gulf Pipe Line Company (“West Texas Gulf”), a joint venture that owns and operates a 579-mile common carrier crude oil pipeline. Other owners of West Texas Gulf are ChevronTexaco, BP, and Citgo. The system, which is operated by ChevronTexaco, 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. Shippers on the pipeline are the Partnership, Sunoco, an affiliate of one other owner and several unaffiliated customers. The Partnership receives a quarterly cash dividend from West Texas Gulf that is commensurate with its ownership interest.

 

Crude Oil Acquisition and Marketing

 

In addition to receiving tariff revenues for transporting crude oil on the Western Pipeline System, the Partnership generates most of its revenues through its crude oil acquisition and marketing operations, primarily in Oklahoma and Texas. These activities include: purchasing crude oil at the wellhead from producers and in bulk from aggregators at major pipeline interconnections and trading locations; transporting crude oil on the Partnership’s pipelines and trucks or, when necessary or cost effective, pipelines or trucks owned and operated by third parties; and marketing crude oil to refiners or resellers.

 

The marketing of crude oil is complex and requires detailed knowledge of the crude oil market and a familiarity with a number of factors, including types of crude oil, individual refinery demand for specific grades of crude oil, area market price structures for different grades of crude oil, location of customers, availability of transportation facilities, timing, and customers’ costs (including storage). The Partnership sells crude oil to major integrated oil companies, independent refiners, including Sunoco R&M for its Tulsa and Toledo refineries, and resellers in various types of sale and exchange transactions, at market prices for terms generally ranging from one month to one year.

 

The Partnership mitigates most of its pricing risk on purchase contracts by selling crude oil for an equal term on a similar pricing basis. The Partnership also mitigates most of its 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.

 

The Partnership enters 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, 2003, the Partnership purchased 193,176 bpd from approximately 3,400 producers and from approximately 34,000 leases, and undertook approximately 300,000 bpd of exchanges and bulk purchases during the same period.

 

Crude Oil Lease 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, sand, and other contaminants and then moves it to an on-site storage tank. When the tank is full, the producer contacts the Partnership’s field personnel to purchase and transport the crude oil to market. The crude oil in producers’ tanks is then either delivered to the Partnership’s pipeline or transported via truck to the Partnership’s pipeline or a third party’s pipeline. The trucking services are performed either by the Partnership’s truck fleet or third-party trucking operations.

 

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The Partnership also enters into exchange agreements to enhance margins throughout the acquisition and marketing process. When opportunities arise to increase its margin or to acquire a grade of crude oil that more nearly matches its delivery requirement or the preferences of its refinery customers, the Partnership’s physical crude oil is exchanged with third parties. Generally, the Partnership enters 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 the Partnership’s end-markets, thereby reducing transportation costs.

 

The following table shows the Partnership’s average daily volume for crude oil lease purchases and exchanges for the years presented:

 

     Year Ended December 31,

     1999

   2000

   2001

   2002

   2003

     (in thousands of bpd)

Lease purchases:

                        

Available for sale

   103    137    141    157    167

Exchanged

   38    36    33    32    26

Other exchanges and bulk purchases

   145    234    218    215    300
    
  
  
  
  

Total

   286    407    392    404    493
    
  
  
  
  

 

The Partnership’s business practice is generally to purchase only crude oil for which there is a corresponding sale agreement for physical delivery of crude oil to a third party or a Sunoco R&M refinery. Through this process, the Partnership seeks to maintain a position that is substantially balanced between crude oil purchases and future delivery obligations. The Partnership does not acquire and hold crude oil futures contracts or enter into other commodity derivative contracts.

 

The following table shows the average daily sales and exchange volume of crude oil for the years presented:

 

     Year Ended December 31,

     1999

   2000

   2001

   2002

   2003

     (in thousands of bpd)

Sunoco R&M refineries:

                        

Toledo

   26    29    28    35    26

Tulsa

   63    73    71    73    80

Third parties

   20    41    52    63    79

Exchanges:

                        

Purchased at the lease

   38    36    33    32    26

Other

   139    227    208    202    282
    
  
  
  
  

Total

   286    406    392    405    493
    
  
  
  
  

 

Market Conditions

 

Market conditions impact the Partnership’s sales and marketing strategies. During periods when demand for crude oil is weak, the market for crude oil is often in contango, meaning that the price of crude oil in a given month is less than the price of crude oil for delivery in a subsequent month. In a contango market, storing crude oil is favorable because storage owners at major trading locations can simultaneously purchase production at low current prices for storage and sell 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 in a given month exceeds the price of crude oil for delivery in a subsequent month. A backwardated market has a positive impact on marketing margins because crude oil marketers can continue to purchase crude oil from producers at a fixed premium to posted prices while selling crude oil at a higher premium to such prices.

 

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Producer Services

 

Crude oil purchasers who buy from producers compete on the basis of competitive prices and highly responsive services. Through its team of crude oil purchasing representatives, the Partnership maintains ongoing relationships with more than 3,400 producers. Management of the Partnership believes that its ability to offer competitive pricing and high-quality field and administrative services to producers is a key factor in its ability to maintain its volume of lease purchased crude oil and to obtain new volume. Field services include efficient gathering capabilities, availability of trucks, willingness to construct gathering pipelines where economically justified, timely pickup of crude oil from storage tanks at the lease or production point, accurate measurement of crude oil volume received, avoidance of spills, and effective management of pipeline deliveries. Accounting and other administrative services include securing division orders (statements from interest owners affirming the division of ownership in crude oil purchased by the Partnership), providing statements of the crude oil purchased each month, disbursing production proceeds to interest owners, and calculating and paying production taxes on behalf of interest owners. In order to compete effectively, records of title and division order interests must be maintained by the Partnership in an accurate and timely manner for purposes of making prompt and correct payment of crude oil production proceeds, together with the correct payment of all production taxes associated with these proceeds.

 

Credit with Customers

 

When crude oil is marketed, the Partnership must determine the amount of any line of credit to be extended to a customer. Since typical sales transactions can involve tens of thousands of barrels of crude oil, the risk of nonpayment and nonperformance by customers is a major consideration in this business. Management of the Partnership believes that its sales are made to creditworthy entities or entities with adequate credit support. Credit review and analysis are also integral to the Partnership’s lease purchases. Payment for substantially all of the monthly lease production is sometimes made to the operator of the lease. The operator, in turn, is responsible for the correct payment and distribution of such production proceeds to the proper parties. In these situations, it must be determined by the Partnership whether the operator has sufficient financial resources to make such payments and distributions and to indemnify and defend the Partnership in the event a third party brings a protest, action, or complaint in connection with the ultimate distribution of production proceeds by the operator.

 

Crude Oil Trucking

 

The Partnership owns approximately 130 crude oil truck unloading facilities in Oklahoma, Texas, and New Mexico, the majority of which are located on the Partnership’s pipeline system. Approximately 270 crude oil truck drivers are employed by the general partner of the Partnership and approximately 113 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 the Partnership’s pipelines and third-party pipelines. Third-party trucking firms are also retained to transport crude oil to certain facilities.

 

Pipeline and Terminal Control Operations

 

All of the Partnership’s 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 Tulsa, Oklahoma. The Montello control center primarily monitors and controls the Partnership’s Eastern Pipeline System, and the Tulsa control center primarily monitors and controls the Western Pipeline System. The Nederland Terminal has its own control center.

 

The control centers operate with System 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, engines, and valves associated with the delivery of refined products and crude oil.

 

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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 Partnership’s pipelines. Pump stations and meter-measurement points along the Partnership’s 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.

 

Acquisitions

 

Wolverine, West Shore and Yellowstone Pipe Line Interest Acquisitions. On November 15, 2002, the Partnership acquired an affiliate of Union Oil Company of California, whose assets included a 31.5 percent interest in Wolverine, a joint venture that owns a 721-mile refined product pipeline; a 9.2 percent interest in West Shore, a joint venture that owns a 652-mile refined product pipeline; and a 14.0 percent interest in Yellowstone, a joint venture that owns a 656-mile refined product pipeline, for $54 million in cash. On September 30, 2003, the Partnership acquired an additional 3.1 percent interest in West Shore for $3.7 million, increasing its overall ownership percentage to 12.3 percent.

 

West Texas Gulf Pipe Line Interest Acquisition. On November 15, 2002, the Partnership acquired a 43.8 percent interest in West Texas Gulf, a joint venture that owns a 579-mile crude oil pipeline, from an affiliate of Sunoco, Inc. for $10.6 million, including the issuance of 4,515 Partnership common units with a fair value at the date of issuance of $0.1 million.

 

The Partnership and its equity interests are principally engaged in the transport, terminalling and storage of refined products and crude oil and in the purchasing and sale of crude oil. Although the Partnership does not currently engage in business unrelated to the transportation or storage of crude oil and refined products and the other businesses described above, management of the Partnership may, in the future, consider and make acquisitions in other business areas.

 

Subsequent Event

 

Eagle Point Logistics Assets. On January 13, 2004, Sunoco closed on its purchase of the Eagle Point Refinery in Westville, New Jersey from El Paso Corporation. Management of the Partnership is currently negotiating with Sunoco for the acquisition of certain pipeline and other logistics assets associated with the refinery.

 

Competition

 

As a result of the physical integration with Sunoco R&M’s refineries and the contractual relationship with Sunoco pursuant to the Omnibus Agreement and Sunoco R&M pursuant to the pipelines and terminals storage and throughput agreement, management of the Partnership believes that it will not face significant competition for crude oil transported to the Philadelphia, Toledo, and Tulsa refineries, or refined products transported from the Philadelphia, Marcus Hook, and Toledo refineries, particularly during the term of the pipelines and terminals storage and throughput agreement with Sunoco R&M. For further information on this agreement, see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Agreements with Sunoco R&M and Sunoco, Inc.” For the year ended December 31, 2003, Sunoco R&M accounted for approximately 52 percent of the Partnership’s total revenues.

 

Eastern Pipeline System

 

Nearly all of the Eastern Pipeline System is directly linked to Sunoco R&M’s refineries. Sunoco R&M 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 the area served by the

 

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Eastern Pipeline System are other pipelines. Management of the Partnership 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 the Partnership’s 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 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 addition, the Partnership, including its interests in corporate joint ventures, faces competition from trucks that deliver refined products in a number of areas that it serves. 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. The availability of truck transportation places a significant competitive constraint on the Partnership’s ability to increase tariff rates.

 

Terminal Facilities

 

Historically, except for the Nederland Terminal, essentially all of the throughput at the Terminal Facilities segment has come from Sunoco R&M. Under the terms of the pipelines and terminals storage and throughput agreement, the Partnership will continue to receive a significant portion of the throughput at these facilities from Sunoco R&M.

 

The 31 inland 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 Beaumont.

 

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

 

Western Pipeline System

 

The Western Pipeline System, including the equity interest in West Texas Gulf pipeline, faces competition from a number of major oil companies and smaller entities. Competition among common carrier pipelines is based primarily on transportation charges, access to producing areas, and demand for the crude oil by end users. Management of the Partnership believes that high capital costs make it unlikely that other companies will build new competing crude oil pipeline systems in areas served by 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.

 

Partnership’s Option to Purchase Pipelines from Sunoco

 

Sunoco has transferred to the Partnership most of its pipeline, terminalling, storage, and related assets that support Sunoco R&M’s refinery operations. Sunoco has retained the assets described below:

 

  Mid-Valley Pipeline. A subsidiary of Sunoco owns a 55 percent interest in the Mid-Valley Pipeline Company (a 50 percent voting interest), which owns and operates a 1,087-mile crude oil pipeline from Longview, Texas to Samaria, Michigan. The Mid-Valley pipeline serves a number of refineries in the Midwest United States.

 

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  Mesa Pipeline. A subsidiary of Sunoco owns an undivided 6 percent interest in the Mesa pipeline, an 80-mile crude oil pipeline from Midland, Texas to Colorado City. Mesa Pipeline connects to West Texas Gulf’s pipeline, which supplies crude oil to Mid-Valley.

 

  Inland Pipeline. A subsidiary of Sunoco owns a 10 percent interest in Inland Corporation, which owns and operates a 611-mile refined products pipeline from Lima and Toledo, Ohio to Canton, Cleveland, Columbus, and Dayton, Ohio. This pipeline transports refined products for Sunoco R&M from its Toledo, Ohio refinery and for the other owners.

 

Sunoco has granted the Partnership a ten-year option, which expires in 2012, to purchase its interest in any of the preceding assets for fair market value at the date of purchase. Sunoco’s interests in these assets are subject to agreements with the other interest owners that include, among other things, consent requirements and rights of first refusal that may be triggered upon certain transfers. The exercise of the option with respect to any of these assets is subject to the terms and conditions of those agreements, which may or may not require consents or trigger rights of first refusal, depending on the facts and circumstances existing at the time of the option exercise. The Partnership has no current intention to purchase the retained assets noted above.

 

Sunoco has also granted the Partnership a ten-year option, which expires in 2012, to purchase an idled 370-mile 6-inch refined product pipeline from Icedale, Pennsylvania to Cleveland, Ohio for fair market value at the date of purchase. The Partnership has no current intention to purchase this pipeline.

 

Both of the ten-year option agreements described above are contained in the Omnibus Agreement that was entered into with Sunoco, Sunoco R&M and the general partner. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Agreements with Sunoco R&M and Sunoco, Inc.” In accordance with this agreement, if the Partnership decides to exercise the option to purchase any of the assets described above, written notice must be provided to Sunoco setting forth the fair market value the Partnership proposes to pay for the asset. If Sunoco does not agree with the proposed fair market value, the Partnership and Sunoco will appoint a mutually agreed-upon, nationally recognized investment banking firm to determine the fair market value of the asset. Once the investment bank submits its valuation of the asset, the Partnership will have the right, but not the obligation, to purchase the asset at the price determined by the investment banking firm.

 

Safety Regulation

 

A majority of the Partnership’s pipelines are subject to United States Department of Transportation (“DOT”) regulations under the Hazardous Liquid Pipeline Safety Act of 1979 (“HLPSA”), and to regulation under comparable state statutes relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. In addition, the Partnership must permit access to and copying of records and must prepare certain reports and provide information required by the Secretary of Transportation.

 

New DOT regulations, adopted in December 2000, 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. The Partnership has prepared its own written Risk Based Integrity Management Program, identified the line segments that could impact high consequence areas and developed Baseline Assessment Plans. Management believes it is on track to complete the assessment of the highest risk 50 percent of line segments by September 30, 2004, with full assessment of the remaining segments by March 31, 2008, the timeframe prescribed by the regulations.

 

The Pipeline Safety Improvement Act of 2002, effective December 17, 2002, mandates, among other things, the delivery to the DOT of data that can be used in a national pipeline mapping system, the implementation of operator examinations and other qualification programs, periodic pipeline safety inspections, and increased civil

 

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penalties for violators. It also includes whistleblower protection provisions for employees who reveal safety violations or operational flaws.

 

Management of the Partnership believes that its 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 management of the Partnership does not believe they would likely have a material adverse effect relative to its financial position.

 

Employee Safety

 

The Partnership is subject to the requirements of the United States Federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes that regulate worker health and safety. Management believes the Partnership is in substantial compliance with Federal OSHA requirements and comparable state statutes, including general industry standards, recordkeeping requirements and monitoring of occupational exposure to hazardous substances.

 

Environmental Regulation

 

General

 

The Partnership’s 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. 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. Management of the Partnership believes it is 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 the Partnership’s operations, such as releases of crude oil or hazardous substances from its pipelines or storage facilities. To the extent not insured, such accidental releases could subject the Partnership 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 the Partnership by affiliates of Sunoco, Inc., Sunoco agreed to indemnify the Partnership 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 the Partnership’s responsibility. The Partnership has agreed to indemnify Sunoco, Inc. 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, Inc. is not required to indemnify the Partnership. 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 the Partnership’s liability at multi-party sites. As of December 31, 2003, the Partnership has not incurred any material environmental liabilities that were not covered by the environmental indemnification.

 

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Air Emissions

 

The Partnership’s operations are subject to the Clean Air Act and comparable state and local statutes. Amendments to the Clean Air Act enacted in late 1990 as well as recent or soon to be adopted changes to state implementation plans for controlling air emissions in regional, non-attainment areas require or will require most industrial operations in the United States to incur capital expenditures in order to meet air emission control standards developed by the Environmental Protection Agency (“EPA”) and state environmental agencies. As a result of these amendments, the Partnership’s facilities that emit volatile organic compounds or nitrogen oxides are subject to increasingly stringent regulations, including requirements that some sources install maximum or reasonably available control technology. In addition, the 1990 Clean Air Act Amendments established a new operating permit for major sources, which applies to some of the Partnership’s facilities. The Partnership 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, management of the Partnership believes implementation of the 1990 Clean Air Act Amendments will not have a material adverse effect on its financial condition or results of operations.

 

The Partnership’s customers, including Sunoco R&M, are also subject to, and affected by, environmental regulations. Since the late 1990s, the EPA has undertaken significant enforcement initiatives under authority of the Clean Air Act. These enforcement initiatives have been targeted at industries that have large manufacturing facilities and that are significant sources of emissions, such as the refining, paper and pulp, and electric power generating industries. As part of these initiatives, Sunoco R&M could be required to make significant capital expenditures, operate these refineries at reduced levels and pay significant penalties.

 

It is uncertain what Sunoco, Inc.’s or Sunoco R&M’s responses to these emerging issues will be. Those responses could reduce Sunoco R&M’s obligations under the pipelines and terminals storage and throughput agreement, thereby reducing the Partnership’s throughput in its pipelines and terminals, cash flow, and ability to make distributions or satisfy its debt obligations.

 

Hazardous Substances and Waste

 

The Comprehensive Environmental Response, Compensation, and Liability Act, referred to as CERCLA and also known as Superfund, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In the course of ordinary operations, the Partnership may generate waste that falls within CERCLA’s 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 the Partnership’s 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”.

 

The Partnership also generates 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. From time to time, the EPA considers the adoption of stricter disposal standards for non-hazardous wastes,

 

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including crude oil and gas wastes. The Partnership is not currently required to comply with a substantial portion of the RCRA requirements because its operations generate minimal quantities of hazardous wastes. However, it is possible that additional wastes, which could include wastes currently generated during the Partnership’s 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 the Partnership’s maintenance capital expenditures and operating expenses.

 

The Partnership currently owns or leases, and the Partnership’s predecessor has in the past owned or leased, properties where hydrocarbons are being or have been handled for many years. Although operating and disposal practices have been utilized that were standard in the industry at the time, hydrocarbons or other waste may have been disposed of or released on or under the properties owned or leased by the Partnership or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under the Partnership’s control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under these laws, the Partnership 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.

 

The Partnership has 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

 

The Partnership’s 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 discharge of regulated substances into regulated waters is prohibited, except in accord with the terms of a permit issued by applicable federal or state authorities. The Oil Pollution Act, enacted in 1990, amends provisions of the Clean Water Act as they pertain to prevention and response to oil releases.

 

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 the Partnership’s oil spill emergency response plans, and management of the Partnership believes it is 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. Management of the Partnership 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.

 

Endangered Species Act

 

The Endangered Species Act restricts activities that may affect endangered species or their habitats. While some of the Partnership’s facilities are in areas that may be designated as a habitat for endangered species, management believes that the Partnership is in substantial compliance with the Endangered Species Act. However, the discovery of previously unidentified endangered species could cause the Partnership to incur additional costs or become subject to operating restrictions or bans in the affected area.

 

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Environmental Remediation

 

Contamination resulting from releases of refined products and crude oil is not unusual within the petroleum pipeline industry. Historic releases along the Partnership’s 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 the Partnership from environmental and toxic tort liabilities related to the assets transferred to the extent such liabilities exist or arise 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.”

 

The Partnership has experienced several petroleum releases for which it is not covered by an indemnity from Sunoco, Inc., and is therefore the responsible party and needs to perform the necessary assessment, remediation, and/or monitoring activities. Remediation programs may be mandated at four sites, one in Texas, two in Pennsylvania, and one in Michigan. Management of the Partnership estimates that the total aggregate cost of performing the currently anticipated assessment, monitoring, and remediation activities at these sites is not material to its financial position at December 31, 2003. The Partnership has implemented an extensive inspection program to prevent releases of refined products or crude oil into the environment from its pipelines, gathering systems, and terminals. Any damages and liabilities incurred due to future environmental releases from the Partnership’s assets have the potential to substantially affect its 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.

 

Index-Based Rates and Other Subsequent Developments. In October 1992, Congress passed the Energy Policy Act of 1992. The Energy Policy Act deemed interstate petroleum pipeline rates in effect during the 365-day period preceding enactment that had not been subject to complaint, protest, or investigation during such period, to be just and reasonable under the Interstate Commerce Act. All of the Partnership’s interstate pipeline rates were deemed just and reasonable, and so “grandfathered” under the Energy Policy Act. The Energy Policy Act also limited the circumstances under which the FERC may change grandfathered rates in response to complaints. In order to challenge grandfathered rates, a complainant must show that it was contractually barred from challenging the rate prior to enactment of the Energy Policy Act (and filed the complaint within 30 days of the expiration of the contractual bar), that the nature of the service underlying the rate has substantially changed, or that the rate is unduly discriminatory or preferential.

 

The Energy Policy Act further required the FERC to issue rules establishing a simplified and generally applicable ratemaking methodology for interstate petroleum pipelines and to streamline procedures in petroleum pipeline proceedings. FERC Order No. 561, effective January 1, 1995, adopted a new indexed rate methodology for interstate petroleum pipelines. Under the resulting regulations, petroleum pipelines were able to change their

 

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rates within prescribed ceiling levels that were tied to changes in the Producer Price Index for Finished Goods, or PPI, minus one percent. Rate increases made under the index are subject to protest, but the scope of the protest proceeding will be limited to an inquiry into whether the portion of the rate increase resulting from application of the index substantially exceeds the pipeline’s increase in costs. The indexing methodology applies to any existing rate, whether grandfathered or established after enactment of the Energy Policy Act. As a result of certain litigation, on February 24, 2003, the FERC ordered that the appropriate index for the current period should be the PPI without the minus one percent adjustment. It further ruled that pipelines may calculate the current ceiling rate using the PPI as though it had been the index in effect since July 1, 2001.

 

Under Order No. 561, as a general rule, pipelines must use the indexing methodology to change their rates. However, the FERC retained cost-of-service ratemaking, market-based rates, and settlement as alternatives to the indexing approach in certain specified circumstances. A pipeline may follow the cost-of-service approach when seeking to increase its rates above index levels (or when seeking to avoid lowering rates to index levels), so long as there is a substantial difference between the actual cost increases (or decreases) experienced by the pipeline and the rate resulting from application of the index. FERC Opinion No. 435, issued in January 1999, affirmed the determination (in the FERC’s earlier Opinion No. 397) that there should not be a corporate income tax allowance built into a petroleum pipeline’s rates for income attributable to noncorporate partners. In subsequent decisions on rehearing, the FERC further defined the scope of the income tax allowance for publicly traded limited partnerships, and resolved a number of other cost of service issues.

 

A pipeline can charge market-based rates if it establishes that it lacks significant market power in the affected markets. The opportunity to charge market-based rates means that the pipeline may charge prices established by competitive market forces. FERC Order No. 572, issued October 25, 1994, established procedural rules governing petroleum pipelines’ applications for a finding that the pipeline lacks significant market power in the relevant market. In addition, a pipeline can establish rates under settlement, resulting from the unanimous agreement of the pipeline and all the shippers using the service to which the rate applies. The FERC, however, will entertain a challenge to settlement rates that alleges the same circumstances required to challenge an indexed rate.

 

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 the Partnership’s 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 the Partnership ultimately will be upheld if challenged, management believes that the tariffs now in effect for the Partnership’s pipelines are within the maximum rates allowed under current FERC guidelines.

 

Sunoco R&M and its subsidiaries are the only current shippers on many of the pipelines. Sunoco R&M 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. Since most of the pipelines are common carrier pipelines, the Partnership may be required to accept new shippers who wish to transport on the pipelines. It is possible that any new shippers, current shippers, or other interested parties, 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.

 

Intrastate Regulation. Some of the Partnership’s pipeline operations are subject to regulation by the Texas Railroad Commission, the PA PUC, the Ohio Public Utility Commission, the Oklahoma Corporation Commission and the Montana Public Service Commission. 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 the Partnership’s intrastate rates ultimately would be upheld if challenged, it believes 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.

 

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Title to Properties

 

Substantially all of the Partnership’s 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, Inc. 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. The Partnership has 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. The Partnership has 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, the Partnership has 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 transferred to the Partnership upon the closing of the February 2002 IPO required the consent of the grantor to transfer these rights, which in some instances is a governmental entity. The Partnership has obtained or is 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. 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 the business.

 

The Partnership has satisfactory title to all of the assets contributed to it in connection with the February 2002 IPO, or is entitled to indemnification from Sunoco, Inc. 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, Inc. until the Partnership has 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 that can be imposed in some jurisdictions for government-initiated action to clean up environmental contamination, liens for current taxes and other burdens, and easements, restrictions, and other encumbrances to which the underlying properties were subject at the time of acquisition by the predecessor or the Partnership, none of these burdens should materially detract from the value of these properties or from the Partnership’s interest in these properties or should materially interfere with their use in the operation of its business.

 

Employees

 

To carry out the Partnership’s operations, the general partner and its affiliates employed approximately 1,150 people at December 31, 2003 who provide direct support to the operations. Labor unions or associations represent approximately 650 of these employees at December 31, 2003. The general partner considers its employee relations to be good. The Partnership has no employees.

 

(d) Financial Information about Geographical Areas

 

The Partnership has no significant amount of revenue or segment profit or loss attributable to international activities.

 

(e) Available Information

 

The Partnership makes available, free of charge on its website, www.sunocologistics.com, all materials that it files electronically with the Securities Exchange Commission, including its 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.

 

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ITEM 2. PROPERTIES

 

See Item 1.(c) for a description of the locations and general character of the Partnership’s material properties.

 

ITEM 3. LEGAL PROCEEDINGS

 

There are certain legal and administrative proceedings arising prior to the February 2002 IPO pending against the Partnership’s Sunoco-affiliated predecessors and the Partnership (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, Inc. has agreed to indemnify the Partnership for any losses it may suffer as a result of these pending legal actions.

 

There are certain other pending legal proceedings related to matters arising after the February 2002 IPO that are not indemnified by Sunoco, Inc. Management believes that any liabilities that may arise from these legal proceedings will not be material to the Partnership’s financial position at December 31, 2003.

 

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

 

No matters were submitted to a vote of the security holders, through solicitation of proxies or otherwise, during fiscal 2003.

 

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PART II

 

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED SECURITYHOLDER MATTERS

 

The Partnership’s common units were listed on the New York Stock Exchange under the symbol “SXL” beginning on February 5, 2002. Prior to February 5, 2002, the Partnership’s equity securities were not traded on any public trading market. At the close of business on February 28, 2004, there were 70 holders of record of the Partnership’s common units. These holders of record included the general partner with 5,638,154 common units registered in its name, and Cede & Co. with 5,682,634 common units (representing approximately 5,800 beneficial owners) registered to it.

 

The high and low closing sales price ranges (composite transactions) and distributions declared by quarter for 2002 and 2003 since the close of the IPO on February 8, 2002 were as follows:

 

     2002

   2003

     Unit Price

  

Declared
Distributions(1)


   Unit Price

  

Declared

Distributions(1)


     High

   Low

      High

   Low

  

1st

   $ 23.44    $ 20.49    $ 0.2600    $ 25.95    $ 22.85    $ 0.4875

2nd

   $ 24.00    $ 20.95    $ 0.4500    $ 30.75    $ 26.20    $ 0.5000

3rd

   $ 23.25    $ 18.85    $ 0.4500    $ 32.45    $ 28.35    $ 0.5125

4th

   $ 24.07    $ 21.10    $ 0.4875    $ 37.11    $ 30.80    $ 0.5500

(1) Distributions were declared and paid within 45 days following the close of each quarter. The distribution for the first quarter of 2002 represents a pro-rated distribution of $0.45 per common and subordinated unit for the period from February 8, 2002 through March 31, 2002.

 

The Partnership also has 11,383,639 subordinated units issued, all of which are held by the general partner and for which there is no established public trading market.

 

The Partnership distributes all cash on hand within 45 days after the end of each 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 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 the general partner.

 

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

 

  First, 98 percent to the holders of common units and 2 percent to the general partner, until each common unit has received a minimum quarterly distribution of $0.45, plus any arrearages from prior quarters;

 

  Second, 98 percent to the holders of subordinated units and 2 percent to the general partner, until each subordinated unit has received a minimum quarterly distribution of $0.45; and

 

  Thereafter, in the manner described in the table below.

 

The subordination period is generally defined as the period that ends on the first day of any quarter beginning after December 31, 2006 if (1) the Partnership has distributed at least the minimum quarterly distribution on all outstanding units with respect to each of the immediately preceding three consecutive, non-overlapping four quarter periods; and (2) the adjusted operating surplus, as defined in the partnership agreement,

 

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during such periods equals or exceeds the amount that would have been sufficient to enable the Partnership to distribute the minimum quarterly distribution on all outstanding units on a fully diluted basis and the related distribution on the 2 percent general partner interest during those periods. The Partnership has met the minimum quarterly distribution requirements on all outstanding units for each of the four quarter periods in 2002 and 2003. In addition, one-quarter of the subordinated units may convert to common units on a one-for-one basis after December 31, 2004, and one-quarter of the subordinated units may convert to common units on a one-for-one basis after December 31, 2005, if the Partnership meets the tests set forth in the partnership agreement. If the subordination period ends, the rights of the holders of subordinated units will no longer be subordinated to the rights of the holders of common units and the subordinated units may be converted into common units.

 

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

 

  First, 98 percent to all unitholders, pro rata, and 2 percent to the general partner, until the Partnership distributes for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

 

  Thereafter, as described in the paragraph and table below.

 

As presented in the table below, 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 below 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 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.

 

     Percentage of Distributions

 

Quarterly Distribution Amount per Unit


   Unitholders

    General Partner

 

Up to minimum quarterly distribution ($0.45)

   98 %   2 %

Up to $0.50

   98 %   2 %

Above $0.50 up to $0.575

   85 %   15 %

Above $0.575 up to $0.70

   75 %   25 %

Above $0.70

   50 %   50 %

 

There is no guarantee that the Partnership will pay the minimum quarterly distribution on the common units in any quarter, and the Partnership will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default is existing, under the credit facility 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

 

On February 8, 2002, the Partnership completed an IPO and related transactions whereby it became the successor to Sunoco Logistics (Predecessor) (“Predecessor”), which consisted of a substantial portion of the wholly-owned logistics operations of Sunoco, Inc. and its subsidiaries. The selected financial and operating data presented is derived from the audited financial statements of Sunoco Logistics Partners L.P., which reflect the Predecessor for 1999, 2000 and 2001, the Partnership and Predecessor for 2002, and the Partnership for 2003.

 

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For the periods presented, Sunoco R&M was the primary or exclusive user of the refined product terminals, the Fort Mifflin Terminal Complex, and the Marcus Hook Tank Farm. Prior to January 1, 2002, most of the terminalling and throughput services provided by Sunoco Logistics (Predecessor) for Sunoco R&M’s refining and marketing operations were at fees that enabled the recovery of costs, but not to generate any operating income. Accordingly, historical earnings before interest expense, income tax expense, and depreciation and amortization (“EBITDA”) for those assets was equal to their depreciation and amortization. Sunoco Logistics Partners L.P. began charging Sunoco R&M fees for these services comparable to those charged in arm’s length, third-party transactions, generally effective January 1, 2002, using the terms included in a pipelines and terminals storage and throughput agreement entered into at the closing of the February 2002 IPO.

 

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. The Partnership treats 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 (“bpd”) 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. Management of the Partnership believes that total shipments is a better performance indicator for the Eastern Pipeline System than throughput as certain refined product pipelines, including interrefinery and 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 should be read together with Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations”.

 

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SUNOCO LOGISTICS PARTNERS L.P.

 

     Predecessor

    Partnership
and
Predecessor


    Partnership

 
     Year Ended December 31,

 
     1999(1)

    2000

    2001

    2002(2)

    2003(3)

 
     (in thousands, except per unit and operating data)  

Income Statement Data:

                                        

Revenues:

                                        

Sales and other operating revenue:

                                        

Affiliates

   $ 764,133     $ 1,301,079     $ 1,067,182     $ 1,147,721     $ 1,383,090  

Unaffiliated customers

     210,069       507,532       545,822       676,307       1,274,383  

Other income(4)

     6,133       5,574       4,774       6,904       16,730  
    


 


 


 


 


Total revenues

     980,335       1,814,185       1,617,778       1,830,932       2,674,203  
    


 


 


 


 


Costs and expenses:

                                        

Cost of products sold and operating expenses

     866,610       1,699,541       1,503,156       1,690,896       2,519,160  

Depreciation and amortization

     19,911       20,654       25,325       31,334       27,157  

Selling, general and administrative expenses…

     27,461       34,683       35,956       43,073       48,412  
    


 


 


 


 


Total costs and expenses

     913,982       1,754,878       1,564,437       1,765,303       2,594,729  
    


 


 


 


 


Operating income

     66,353       59,307       53,341       65,629       79,474  

Net interest cost and debt expense

     6,487       10,304       10,980       17,299       20,040  
    


 


 


 


 


Income before income tax expense

     59,866       49,003       42,361       48,330       59,434  

Income tax expense

     22,488       18,483       15,594       1,555       —    
    


 


 


 


 


Net Income

   $ 37,378     $ 30,520     $ 26,767     $ 46,775     $ 59,434  
    


 


 


 


 


Net Income per limited partner unit:

                                        

Basic

                           $ 1.87 (5)   $ 2.55  
                            


 


Diluted

                           $ 1.86 (5)   $ 2.53  
                            


 


Cash distributions per unit to limited partners:(6)

                                        

Paid

                           $ 1.16     $ 1.9875  
                            


 


Declared

                           $ 1.6475     $ 2.05  
                            


 


Cash Flow Data:

                                        

Net cash provided by operating activities

   $ 125,165     $ 79,116     $ 27,238     $ 2,211     $ 97,212  

Net cash used in investing activities

   $ (75,120 )   $ (77,292 )   $ (73,079 )   $ (85,273 )   $ (39,008 )

Net cash provided by/(used in) financing activities

   $ (50,045 )   $ (1,824 )   $ 45,841     $ 116,902     $ (41,963 )

Capital expenditures:

                                        

Maintenance

   $ 32,312     $ 39,067     $ 53,628     $ 27,934     $ 30,850  

Expansion

     49,556 (1)     18,854       19,055       77,439 (2)   $ 10,226 (3)
    


 


 


 


 


Total capital expenditures

   $ 81,868 (1)   $ 57,921     $ 72,683     $ 105,373 (2)   $ 41,076 (3)
    


 


 


 


 


EBITDA(7)

   $ 86,264     $ 79,961     $ 78,666     $ 96,963     $ 106,631  

Balance Sheet Data (at period end):

                                        

Net properties, plants and equipment

   $ 481,967     $ 518,605     $ 566,359     $ 573,514     $ 583,164  

Total assets

   $ 712,149     $ 845,956     $ 789,201     $ 1,093,880     $ 1,179,998  

Total debt

   $ 95,287     $ 190,043     $ 144,781     $ 317,445     $ 313,136  

Total Partners’ Capital/Net parent investment

   $ 223,083     $ 157,023     $ 274,893     $ 382,350     $ 400,871  

Operating Data (bpd):

                                        

Eastern Pipeline System total shipments(in thousands of barrel miles per day)(8)

     56,136       54,911       55,198       56,768       55,324  

Terminal Facilities Throughput (bpd)

     1,245,189       1,281,231       1,156,927       1,182,784       1,204,394  

Western Pipeline System throughput(8) (bpd)

     252,098       295,991       287,237       286,912       304,471  

Crude oil purchases at wellhead (bpd)

     140,779       172,839       174,182       189,277       193,176  

 

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(1) On October 1, 1999, the Partnership acquired the crude oil transportation and marketing operations of Pride Companies, L.P. (“Pride”) for $29.6 million in cash and the assumption of $5.3 million of debt. The purchase price of this acquisition has been included within the expansion capital expenditures.
(2) On November 15, 2002, the Partnership acquired a company whose assets included equity interests in three products pipeline companies, consisting of a 31.5 percent interest in Wolverine Pipe Line Company, a 9.2 percent interest in West Shore Pipe Line Company, and a 14.0 percent interest in Yellowstone Pipe Line Company for $54.0 million. On November 15, 2002, the Partnership also acquired a 43.8 percent equity interest in West Texas Gulf Pipe Line Company for $10.6 million. The aggregate purchase price for these acquisitions have been included within the 2002 expansion capital expenditures. The equity income from these acquisitions has been included in the Partnership’s statements of income from the dates of their acquisition.
(3) On September 30, 2003, the Partnership acquired an additional 3.1 percent ownership interest in West Shore for $3.7 million, increasing its overall ownership percentage to 12.3 percent. The purchase price for this acquisition has been included within the 2003 expansion capital expenditures, and the equity income has been included in the Partnership’s statements of income from the date of acquisition.
(4) Includes equity income from the investments in the following joint ventures: 9.4 percent in Explorer Pipeline Company and, from November 15, 2002, 31.5 percent in Wolverine Pipe Line Company, 9.2 percent in West Shore Pipe Line Company, 14.0 percent in Yellowstone Pipe Line Company, and 43.8 percent in West Texas Gulf Pipe Line Company. On September 30, 2003, the Partnership acquired an additional 3.1 percent ownership interest in West Shore, increasing the Partnership’s ownership percentage to 12.3 percent. Equity income from this investment has been included at this increased ownership percentage from this date forward.
(5) Based on the portion of net income for 2002 applicable to the period from February 8, 2002 (the date of the IPO) through December 31, 2002, after deduction of the general partner’s interest in net income. Net income for the period from January 1, 2002 to February 7, 2002 totaled $3.4 million.
(6) Cash distributions paid per unit to limited partners include payments made per unit during the period stated. Cash distributions declared per unit to limited partners include distributions declared per unit related to the quarters within the period stated. Declared distributions were paid within 45 days following the close of each quarter. The distributions for 2002 include a $0.26 per limited partner unit distribution for the first quarter, which represents the pro-rata portion of the $0.45 minimum quarterly distribution for the 52-day period from the date of the IPO, February 8, 2002, through March 31, 2002.
(7) EBITDA is defined in the Partnership’s $250 million revolving credit facility (“Credit Facility”) as net income before interest expense, income taxes, depreciation and amortization. The following table reconciles the difference between net income, as determined under United States generally accepted accounting principles, and EBITDA (in thousands):

 

     Year Ended December 31,

     1999

   2000

   2001

   2002

   2003

Net income

   $ 37,378    $ 30,520    $ 26,767    $ 46,775    $ 59,434

Interest expense, net

     6,487      10,304      10,980      17,299      20,040

Provision for income taxes

     22,488      18,483      15,594      1,555      —  

Depreciation and amortization

     19,911      20,654      25,325      31,334      27,157
    

  

  

  

  

EBITDA

   $ 86,264    $ 79,961    $ 78,666    $ 96,963    $ 106,631
    

  

  

  

  

 

Management of the Partnership believes EBITDA information enhances an investor’s understanding of a business’s ability to satisfy principal and interest obligations with respect to its indebtedness and to utilize cash for other purposes, including the payment of distributions. In addition, EBITDA is used as a measure in the Credit Facility in determining the Partnership’s compliance with certain covenants. However, there may be contractual, legal, economic or other reasons which may prevent the Partnership from satisfying principal and interest obligations with respect to indebtedness and may require the Partnership to allocate funds for other purposes. EBITDA does not represent and should not be considered as an alternative to net income, income from operations 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.

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

 

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

The following discussion should be read in conjunction with the historical financial statements of Sunoco Logistics (Predecessor) and 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.

 

Introduction

 

The Partnership is a Delaware limited partnership formed on October 15, 2001 to acquire, own, and operate, through its wholly-owned subsidiaries, refined product pipelines, terminalling and storage assets, crude oil pipelines, and crude oil acquisition and marketing assets located in the Northeast, Midwest and South Central United States. Most of these assets support Sunoco R&M, a wholly-owned refining and marketing subsidiary of Sunoco, Inc.

 

General

 

The Partnership conducts its business through three segments: the Eastern Pipeline System, the Terminal Facilities, and the Western Pipeline System. The Eastern Pipeline System primarily transports refined products in the Northeast and Midwest United States largely for three of Sunoco R&M’s refineries and transports crude oil in Ohio and Michigan. This system also includes the interrefinery pipeline between Sunoco R&M’s Marcus Hook and Philadelphia refineries and ownership interests in four refined product pipeline joint ventures located in the West and Midwest United States: 9.4 percent in Explorer Pipeline Company (“Explorer”), 31.5 percent in Wolverine Pipe Line Company (“Wolverine”), 12.3 percent in West Shore Pipe Line Company (“West Shore”), and 14.0 percent in Yellowstone Pipe Line Company (“Yellowstone”). The interests in Wolverine and Yellowstone and a 9.2 percent interest in West Shore were acquired on November 15, 2002 for a purchase price of $54.0 million. On September 30, 2003, an additional 3.1 percent interest in West Shore was acquired for $3.7 million, increasing the Partnership’s overall ownership interest to 12.3 percent. The Terminal Facilities business includes a network of 31 refined product terminals in the Northeast and Midwest United States that distribute products primarily to Sunoco R&M’s retail outlets, the Nederland marine crude oil terminal on the Texas Gulf Coast, and a liquefied petroleum gas (“LPG”) storage facility in the Midwest. The Terminal Facilities business also owns and operates refinery-related assets, including one inland and two marine crude oil terminals and related pipelines that supply all of the crude oil processed by Sunoco R&M’s Philadelphia refinery and a refined product storage terminal used by Sunoco R&M’s Marcus Hook refinery. The Western Pipeline System owns and operates crude oil trunk and gathering pipelines and purchases and markets crude oil primarily in Oklahoma and Texas for Sunoco R&M’s Tulsa, Oklahoma and Toledo, Ohio refineries and for other customers. The Western Pipeline System also has a 43.8 percent equity ownership interest in West Texas Gulf Pipe Line Company (“West Texas Gulf”), a joint venture that owns a crude oil pipeline in Texas. The interest in West Texas Gulf was acquired on November 15, 2002 for $10.6 million.

 

Eastern Pipeline System

 

Revenues from the Eastern Pipeline System are generated by charging shippers tariffs for transporting refined products and crude oil through the Partnership’s pipelines. The amount of revenue generated depends on the level of these tariffs and the throughput in the pipelines. When transporting barrels, a tariff is charged based on the point of origin and the ultimate destination, even if the barrel moves through more than one pipeline segment to reach its destination. For example, on the Philadelphia, Pennsylvania to Buffalo, New York pipeline segment, there are separate tariffs depending on whether the ultimate destination from Philadelphia is Rochester, New York or Buffalo, New York.

 

The tariffs for the Partnership’s interstate common carrier pipelines are regulated by the Federal Energy Regulatory Commission (“FERC”). The rate making methodology for these pipelines is price indexing. This

 

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methodology provides for increases in tariff rates based upon changes in the producer price index. Competition, however, may constrain the tariffs charged. The Partnership also leases to Sunoco R&M, for a fixed amount escalating annually at 1.67 percent, three pipelines between Sunoco R&M’s Marcus Hook and Philadelphia refineries, as well as a pipeline from the Partnership’s Paulsboro terminal to the Philadelphia International Airport for the delivery of jet fuel.

 

The crude oil and refined product throughput in the Eastern Pipeline System’s pipelines is directly affected by the level of supply and demand for crude oil and refined products in the markets served directly or indirectly by the pipelines. Demand for gasoline in most markets peaks during the summer driving season, which extends from April to September, and declines during the fall and winter months. Demand for heating oil and other distillate fuels tends to peak during the winter heating season, and declines during the spring and summer months. The supply of crude oil to the Eastern Pipeline System depends upon the level of crude oil production in Canada, which has increased in recent years. Demand for crude oil transported to refineries for processing is driven by refining margins (the price of refined products compared to the price of crude oil and refining costs), unscheduled downtime at refineries and the amount of turnaround activity, which is when refiners shut down selected portions of the refinery for scheduled maintenance.

 

The operating income generated by the Eastern Pipeline System depends not only on the volume transported on its pipelines and the level of the tariff charged, but also on the fixed costs and, to a much lesser extent, the variable costs of operating the pipelines. Fixed costs are typically related to maintenance, insurance, control rooms, telecommunications, pipeline field and support personnel and depreciation. Variable costs, such as fuel and power costs to run pump stations along the pipelines, fluctuate with throughput.

 

Terminal Facilities

 

Prior to January 1, 2002, most of the terminalling and throughput services provided to Sunoco R&M were at fees that enabled the Partnership to recover its costs but not generate operating income. The Partnership is now charging Sunoco R&M fees for these services, generally effective January 1, 2002, comparable to those charged in arm’s-length, third-party transactions using the terms included in a pipelines and terminals storage and throughput agreement with Sunoco R&M entered into at the closing of the February 2002 initial public offering (“IPO”). Under this agreement, Sunoco R&M pays the Partnership a minimum level of revenues for terminalling refined products and crude oil and agrees to certain minimum throughputs at the Inkster Terminal, Fort Mifflin Terminal Complex, and Marcus Hook Tank Farm. (See “Agreements with Sunoco R&M and Sunoco, Inc.” and Item 13. “Certain Relationships and Related Transactions”.) Under this agreement, operating income from terminalling and storage activities depends on throughput and storage volume and the level of fees charged for terminalling and storage services, as well as the fixed and variable costs of operating these facilities.

 

The Partnership generates revenue at the Nederland Terminal by charging storage and throughput fees for crude oil and other petroleum products. The operating income generated at this facility depends on storage and throughput volume and the level of fees charged for these services, as well as the fixed and variable costs of operating the terminal. The absolute price level of crude oil and refined products does not directly affect terminalling and storage fees, although they are affected by the absolute levels of supply and demand for these products.

 

Western Pipeline System

 

The Western Pipeline System consists of crude oil pipelines and gathering systems as well as the crude oil acquisition and marketing operations.

 

The factors affecting the operating results of the crude oil pipelines and gathering systems are substantially similar to the factors affecting the operating results of the pipelines in the Eastern Pipeline System described above. The operating results of the crude oil acquisition and marketing operations are dependent on its ability to

 

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sell crude oil at a price in excess of the aggregate cost. Management of the Partnership 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.

 

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.

 

In general, crude oil is purchased at the wellhead from local producers and in bulk at major pipeline connection and marketing points. The Partnership also enters into transactions with third parties in which one grade of crude oil is exchanged for another grade that more nearly matches the delivery requirement or the preferences of customers. Bulk purchases and sales and exchange transactions are characterized by large volume and much smaller margins than are sales of crude oil purchased at the wellhead. As crude oil is purchased, the Partnership establishes a margin by selling or exchanging the crude oil for physical delivery of other crude oil to Sunoco R&M and third-party customers, such as independent refiners or major oil companies, thereby reducing exposure to price fluctuations. This margin is determined by the difference between the price of crude oil at the point of purchase and the price of crude oil at the point of sale, minus the associated costs related to acquisition and transportation. Changes in the absolute price level for crude oil do not materially impact the margin, as attempts are made to maintain positions that are substantially balanced between crude oil purchases and sales.

 

Because attempts are made to maintain balanced positions, the Partnership is able to minimize basis risk, which occurs when crude oil is purchased based on a crude oil specification that is different from the countervailing sales arrangement. Specification differences include grades or types of crude oil, variability in lease crude oil barrels produced, individual refinery demand for specific grades of crude oil, relative market prices for the different grades of crude oil, customer location, availability of transportation facilities, timing, and costs (including storage) involved in delivering crude oil to the customer. The Partnership’s policy is only to purchase crude oil for which there is a market and to structure the sales contracts so that crude oil price fluctuations do not materially affect the margin received. The Partnership does not acquire and hold any futures contracts or other derivative products for any purpose.

 

The Partnership operates the crude oil acquisition and marketing activities differently as market conditions change. During periods when there is a higher demand than supply of crude oil in the near term, the market is in backwardation, meaning that the price of crude oil in a given month exceeds the price of crude oil for delivery in subsequent months. A backwardated market has a positive impact on marketing margins because crude oil marketers can continue to purchase crude oil from producers at a fixed premium to posted prices while selling crude oil at a higher premium to such prices. In backwardated markets, crude oil is purchased and contracted for its sale as soon as possible. When the demand for crude oil is weak, the market for crude oil is often in contango, meaning that the price of crude oil in a given month is less than the price of crude oil for delivery in subsequent months. In a contango market, marketing margins are adversely impacted, as crude oil marketers are unable to capture the premium to posted prices described above. However, this unfavorable market condition can be mitigated by storing crude oil because storage owners at major trading locations can simultaneously purchase production at current prices for storage and sell at higher prices for future delivery. As a result, in a contango market, crude oil will be purchased and contracted for its delivery in future months to capture the price difference.

 

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Agreements with Sunoco R&M and Sunoco, Inc.

 

Upon the closing of the February 2002 IPO, the Partnership entered into the following agreements:

 

Pipelines and Terminals Storage and Throughput Agreement

 

Under this agreement, Sunoco R&M is paying the Partnership fees generally comparable to those charged by third parties to:

 

  transport on the refined product pipelines or throughput in the 31 inland refined product terminals an amount of refined products that will produce at least $76.3 million of revenue for the contract year from March 1, 2003 to February 28, 2004, escalating at 1.67 percent each March 1 for the next three contract years. In addition, Sunoco R&M will pay the Partnership to transport on the refined product pipelines or throughput in the refined product terminals an amount of refined products that will produce at least $54.3 million of revenue in the contract year commencing March 1, 2007, and at least $55.2 million of revenue in the contract year commencing March 1, 2008. Sunoco R&M will pay the published tariffs on the pipelines and contractually agreed upon fees at the terminals. Based upon the prorated minimum amount noted, Sunoco R&M has exceeded the minimum revenue amount through December 31, 2003 and management of the Partnership expects Sunoco R&M to exceed the minimum amount under the agreement for the contract year from March 1, 2003 through February 29, 2004;

 

  receive and deliver at least 130,000 bpd of refined products per year at the Marcus Hook Tank Farm for five years. This throughput is an annual amount for the contract period from March 1 to February 28 for the term of the agreement. For the calendar year ended December 31, 2003, the Partnership received a fee of $0.1654 per barrel for the first 130,000 bpd and $0.0827 per barrel for volume in excess of 130,000 bpd. These fees escalate at the rate of 1.67 percent each January 1 for the term of the agreement. Based upon the prorated minimum throughput amount noted, Sunoco R&M has exceeded the minimum throughput amount through December 31, 2003 and management of the Partnership expects Sunoco R&M to exceed the minimum throughput amount under the agreement for the contract year from March 1, 2003 through February 29, 2004;

 

  store 975,734 barrels of 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. For the calendar year ended December 31, 2003, the Partnership received a fee of $2.078 per barrel of committed storage, a fee of $0.222 per barrel for receipts greater than 975,734 barrels per contract year and a fee of $0.222 per barrel for deliveries greater than 975,734 barrels per contract year. These fees will escalate at the rate of 1.875 percent each January 1 for the term of the agreement. Based upon the prorated minimum storage amount noted, Sunoco R&M has exceeded the minimum storage amount through December 31, 2003 and management of the Partnership expects Sunoco R&M to exceed the minimum storage amount under the agreement for the contract year from April 1, 2003 through March 31, 2004;

 

  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. 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, 2003, the Partnership received a fee of $0.1654 per barrel for the first 180,000 bpd and $0.0827 per barrel for volume in excess of 180,000 bpd. These fees will escalate at the rate of 1.67 percent each January 1 for the term of the agreement. Based upon the prorated minimum throughput amount noted, Sunoco R&M has exceeded the minimum throughput amount through December 31, 2003 and management of the Partnership expects Sunoco R&M to exceed the minimum throughput amount under the agreement for the contract year from March 1, 2003 through February 29, 2004; and

 

 

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. This throughput is an

 

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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 R&M has exceeded the minimum throughput amount through December 31, 2003 and management of the Partnership expects Sunoco R&M to exceed the minimum throughput amount under the agreement for the contract year from March 1, 2003 through February 29, 2004.

 

If Sunoco R&M fails to meet its minimum obligations pursuant to the contract terms set forth above, it will be required to pay in cash the amount of any shortfall, which may be applied as a credit in the following year after Sunoco R&M’s minimum obligations for that year are met.

 

Sunoco R&M’s obligations under this agreement may be permanently reduced or suspended if Sunoco R&M (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 New York and Connecticut began enforcing state-imposed MTBE bans on January 1, 2004, this has not currently affected Sunoco R&M’s obligations under the agreement.

 

From time to time, Sunoco, Inc. may be presented with opportunities by third parties with respect to its refinery assets. These opportunities may include offers to purchase and joint venture propositions. Sunoco, Inc. is also continually considering changes to its refineries. Those changes may involve new facilities, reduction in certain operations or modifications of facilities or operations. Changes may be considered to meet market demands, to satisfy regulatory requirements or environmental and safety objectives, to improve operational efficiency or for other reasons. Sunoco, Inc. has advised the Partnership that although it continually considers the types of matters referred to above, it is not currently proceeding with any transaction or plan that it believes will likely result in any reconfigurations or other operational changes in any of its refineries served by the Partnership’s assets that would have a material effect on Sunoco R&M’s business relationship with the Partnership. Further, Sunoco, Inc. has also advised the management of the Partnership that it is not considering a shutdown of any of its refineries served by the Partnership’s assets. Sunoco, Inc. is, however, actively managing its assets and operations and, therefore, changes of some nature, possibly material to its business relationship with the Partnership, are likely to occur at some point in the future.

 

To the extent Sunoco R&M does not extend or renew the pipelines and terminals storage and throughput agreement, the Partnership’s financial condition and results of operations may be adversely affected. The Partnership’s assets were constructed or purchased to service Sunoco R&M’s refining and marketing supply chain and are well-situated to suit Sunoco R&M’s needs. As a result, management of the Partnership would expect that even if this agreement is not renewed, Sunoco R&M would continue to use the pipelines and terminals. However, management cannot assure investors and other interested parties that Sunoco R&M will continue to use the Partnership’s facilities or that additional revenues can be generated from third parties.

 

Omnibus Agreement

 

Historically, Sunoco has allocated a portion of its general and administrative expenses to its pipeline, terminalling, and storage operations to cover costs of centralized corporate functions such as legal, accounting, treasury, engineering, information technology, insurance and other corporate services. Prior to the IPO, such expenses were based on amounts negotiated between the parties, which approximated Sunoco’s cost of providing such services. Under the Omnibus Agreement entered into with Sunoco concurrent with the IPO, Sunoco provides these centralized corporate functions for three years for an annual administrative fee, which may be increased annually by the lesser of 2.5 percent or the consumer price index for the applicable year. The fee for the annual period ended December 31, 2003 was $8.2 million. These costs may also increase if the Partnership consummates an acquisition or constructs additional assets that require an increase in the level of general and administrative services received by the Partnership from the general partner or Sunoco. The annual fee includes costs incurred by Sunoco to perform the centralized corporate functions described above. This fee does not

 

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include the costs of shared insurance programs, which are allocated to the Partnership based upon its share of the premiums incurred. This fee also does not include 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 is reimbursing Sunoco for these costs and other direct expenses incurred on the Partnership’s behalf. Selling, general and administrative expenses in the statements of income include costs related to the provision of these centralized corporate functions and allocation of shared insurance costs of $10.8 million, $10.2 million and $10.9 million for the years ended December 31, 2001, 2002 and 2003, respectively. The Partnership’s and Predecessor’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 $19.6 million, $19.6 million and $20.6 million for the years ended December 31, 2001, 2002 and 2003, respectively. The Partnership also began incurring additional general and administrative costs from the date of the IPO, including costs for tax return preparation, annual and quarterly reports to unitholders, investor relations, registrar and transfer agent fees, and other costs related to operating as a separate publicly held entity.

 

The Omnibus Agreement also requires Sunoco R&M to: reimburse the Partnership 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 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 the Darby Creek Tank Farm to maintain compliance with existing industry standards and regulatory requirements.

 

For the years ended December 31, 2002 and 2003, the Partnership was reimbursed $0.7 million and $1.9 million, respectively, by Sunoco R&M for maintenance capital expenditures and operating expenses incurred in excess of $8.0 million to comply with the DOT’s pipeline integrity management rule. At December 31, 2003, the Partnership has received a cumulative reimbursement of $2.6 million in regard to the $15.0 million maximum reimbursement over the five-year period for compliance expenditures related to the DOT’s pipeline integrity management rule. For the year ended December 31, 2002, the Partnership was also reimbursed $2.1 million by Sunoco R&M for certain tank maintenance and inspection capital expenditures at the Darby Creek Tank Farm. There were no amounts expended for these tank maintenance and inspection projects at the Darby Creek Tank Farm during 2003. For the years ended December 31, 2002 and 2003, the Partnership was reimbursed by Sunoco R&M for expenditures at the Marcus Hook Tank Farm and the Darby Creek Tank Farm to maintain compliance with existing industry standards and regulatory requirements. These expenditures, which were recorded as maintenance capital and operating expenses, were as follows:

 

     Partnership
and
Predecessor


   Partnership

     Year Ended December 31,

     2002

   2003

     (amounts in thousands)

Maintenance capital

   $ 534    $ 2,982

Operating expenses

     351      467
    

  

     $ 885    $ 3,449
    

  

 

At December 31, 2003, the Partnership has received a cumulative reimbursement of $4.3 million relative to the $10 million maximum reimbursement for compliance expenditures at the Marcus Hook Tank Farm and the Darby Creek Tank Farm. The aggregate amounts reimbursed related to all of the previously mentioned provisions of the Omnibus Agreement of $3.7 million and $5.3 million for the years ended December 31, 2002 and 2003, respectively, by Sunoco R&M related to these projects were recorded by the Partnership as capital contributions.

 

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The Omnibus Agreement also provides that Sunoco, Inc. will indemnify the Partnership for certain environmental, toxic tort and other liabilities. Please read “Environmental Matters”, “Business—Environmental Regulation—Environmental Remediation”, and Item 13. “Certain Relationships and Related Transactions” for a more complete description of these provisions.

 

Interrefinery Lease Agreement

 

Under a 20-year lease agreement entered into by the Partnership and Sunoco R&M upon the closing of the February 2002 IPO, Sunoco R&M leases the Partnership’s 58 miles of interrefinery pipelines between Sunoco R&M’s Philadelphia and Marcus Hook refineries for an annual fee which escalates at 1.67 percent each January 1st for the term of the agreement. The annual fee for the year ended December 31, 2003 was $5.2 million. These fees are recorded as revenue within the Partnership’s statements of income.

 

Crude Oil Purchase Agreement

 

The Partnership has agreements with Sunoco R&M whereby Sunoco R&M purchases from the Partnership, at market-based rates, particular grades of crude oil that are purchased by the crude oil acquisition and marketing business. These agreements automatically renew on a monthly basis unless terminated by either party on 30 days’ written notice. For the years ended December 31, 2002 and 2003, Sunoco R&M has purchased all the barrels offered pursuant to these agreements and has indicated that it has no current intention to terminate these agreements.

 

License Agreement

 

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

 

Treasury Services Agreement

 

The Partnership has a treasury services agreement with Sunoco, Inc. pursuant to which, among other things, it is participating in Sunoco, Inc.’s centralized cash management program. Under this program, all of the cash receipts and cash disbursements are processed, together with those of Sunoco, Inc. and its other subsidiaries, through Sunoco, Inc.’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, Inc. and its subsidiaries earn interest at a rate equal to the average rate of the Partnership’s third-party money market investments, while amounts due to Sunoco, Inc. and its subsidiaries bear interest at a rate equal to the interest rate provided in the revolving credit facility (the “Credit Facility”).

 

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Results of Operations

 

     Predecessor

    Partnership
and
Predecessor


    Partnership

     Year Ended December 31,

     2001

    2002

    2003

     (in thousands)

Statements of Income

                      

Sales and other operating revenue:

                      

Affiliates

   $ 1,067,182     $ 1,147,721     $ 1,383,090

Unaffiliated customers

     545,822       676,307       1,274,383

Other income

     4,774       6,904       16,730
    


 


 

Total revenues

     1,617,778       1,830,932       2,674,203
    


 


 

Cost of products sold and operating expenses

     1,503,156       1,690,896       2,519,160

Depreciation and amortization

     25,325       31,334       27,157

Selling, general and administrative expenses

     35,956       43,073       48,412
    


 


 

Total costs and expenses

     1,564,437       1,765,303       2,594,729
    


 


 

Operating income

     53,341       65,629       79,474

Net interest expense

     10,980       17,299       20,040
    


 


 

Income before income tax expense

     42,361       48,330       59,434

Income tax expense

     15,594       1,555       —  
    


 


 

Net income

   $ 26,767     $ 46,775     $ 59,434
    


 


 

Segment Operating Income:

                      

Eastern Pipeline System

                      

Sales and other operating revenue:

                      

Affiliate

   $ 69,631     $ 72,173     $ 72,533

Unaffiliated customers

     21,059       22,865       21,628

Other income

     4,749       6,925       12,147
    


 


 

Total revenues

     95,439       101,963       106,308
    


 


 

Operating expenses

     42,784       42,982       40,000

Depreciation and amortization

     9,778       15,051       10,630

Selling, general and administrative expenses

     12,984       16,772       18,560
    


 


 

Total costs and expenses

     65,546       74,805       69,190
    


 


 

Operating income

   $ 29,893     $ 27,158     $ 37,118
    


 


 

Terminal Facilities

                      

Sales and other operating revenue:

                      

Affiliates

   $ 43,628     $ 55,971     $ 60,060

Unaffiliated customers

     30,273       31,914       31,608

Other income/(loss)

     (85 )     2       1,146
    


 


 

Total revenues

     73,816       87,887       92,814
    


 


 

Operating expenses

     36,488       35,568       38,521

Depreciation and amortization

     11,094       11,113       10,925

Selling, general and administrative expenses

     10,158       12,367       12,913
    


 


 

Total costs and expenses

     57,740       59,048       62,359
    


 


 

Operating income

   $ 16,076     $ 28,839     $ 30,455
    


 


 

Western Pipeline System

                      

Sales and other operating revenue:

                      

Affiliates

   $ 953,923     $ 1,019,577     $ 1,250,497

Unaffiliated customers

     494,490       621,528       1,221,147

Other income/(loss)

     110       (23 )     3,437
    


 


 

Total revenues

     1,448,523       1,641,082       2,475,081
    


 


 

Cost of products sold and operating expenses

     1,423,884       1,612,346       2,440,639

Depreciation and amortization

     4,453       5,170       5,602

Selling, general and administrative expenses

     12,814       13,934       16,939
    


 


 

Total costs and expenses

     1,441,151       1,631,450       2,463,180
    


 


 

Operating income

   $ 7,372     $ 9,632     $ 11,901
    


 


 

 

35


Table of Contents

Operating Highlights

 

     Predecessor

   Partnership
and
Predecessor


   Partnership

     Year Ended December 31,

     2001

   2002

   2003

Eastern Pipeline System(1):

              

Total shipments (barrel miles per day)(2)

   55,198,189    56,768,267    55,323,880

Revenue per barrel mile (cents)

   0.450    0.459    0.466

Terminal Facilities:

              

Terminal throughput (bpd):

              

Refined product terminals

   272,698    272,784    283,071

Nederland Terminal

   427,194    437,381    441,701

Fort Mifflin Terminal Complex

   318,545    322,611    322,389

Marcus Hook Tank Farm

   138,490    150,008    157,233

Western Pipeline System(1):

              

Crude oil pipeline throughput (bpd)

   287,237    286,912    304,471

Crude oil purchases at wellhead (bpd)

   174,182    189,277    193,176

Gross margin per barrel of pipeline throughput (cents)(3)

   19.1    22.5    22.9

(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) 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.

 

Year Ended December 31, 2003 versus Year Ended December 31, 2002

 

Analysis of Statements of Income

 

Net income was $59.4 million for the year ended December 31, 2003 as compared with $46.8 million for the prior year, an increase of $12.6 million. This increase was primarily the result of a $13.8 million increase in operating income and a $1.6 million decrease in income tax expense, partially offset by a $2.7 million increase in net interest expense. The increase in operating income was principally due to the effect of special items such as the absence in the current year of a $6.3 million write-down of an idled refined product pipeline at the Eastern Pipeline System and a related terminal and a $1.2 million gain in the current year relating to the settlement of a claim at the Nederland Terminal resulting from assets damaged by the May 2003 third-party natural gas pipeline release. The cash received relating to this claim was primarily used to replace or repair damaged assets. The increase in operating income also includes equity income for a full year from the corporate joint ventures acquired in November 2002, higher trunk and gathering pipeline volumes and an increase in gross margins at the Western Pipeline System, and a decline in operating expenses at the Eastern Pipeline System. Partially offsetting these items were increases in selling, general and administrative expenses and operating expenses at the Western Pipeline System and Terminal Facilities.

 

Sales and other operating revenue totaled $2,657.5 million for the year ended December 31, 2003 as compared with $1,824.0 million for the prior year, an increase of $833.5 million. This increase was largely attributable to an increase in crude oil prices and higher lease acquisition and bulk volumes. The average price of West Texas Intermediate crude oil at Cushing, Oklahoma, the benchmark crude oil in the United States, increased to an average price of $31.02 per barrel for 2003 from $26.11 per barrel for the prior year. Other income increased $9.8 million from the prior year to $16.7 million for 2003 due principally to equity income from the interests in corporate joint ventures acquired in November 2002.

 

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Total costs of products sold and operating expenses increased $828.3 million to $2,519.2 million for the year ended December 31, 2003 from $1,690.9 million for the prior year due primarily to the increase in crude oil prices and higher lease acquisition and bulk volumes described previously. Selling, general and administrative expenses increased $5.3 million to $48.4 million for 2003 compared with $43.1 million for the prior year due mainly to higher administrative costs, including employee-related expenses. Depreciation and amortization decreased $4.2 million to $27.2 million for 2003 due to the write-down in 2002 described previously.

 

Net interest expense increased $2.7 million to $20.0 million for the year ended December 31, 2003 compared with $17.3 million for the prior year due principally to a decrease in capitalized interest and the interest on the Credit Facility borrowings as a result of the November 2002 acquisitions.

 

Income tax expense for the year ended December 31, 2003 decreased $1.6 million from the prior year to nil in the current year as the Partnership was not subject to income taxes from its inception on February 8, 2002.

 

Analysis of Segment Operating Income

 

Eastern Pipeline System

 

Operating income for the Eastern Pipeline System was $37.1 million for the year ended December 31, 2003 compared with $27.1 million for the prior year. The $10.0 million increase was the result of a $5.2 million increase in other income and a $5.6 million decrease in total costs and expenses, partially offset by a $0.9 million decrease in sales and other operating revenue. Sales and other operating revenue decreased to $94.2 million for 2003 from $95.0 million in the prior year as a result of a decrease in total shipments, partially offset by higher revenue per barrel mile. The increase in other income to $12.1 million for 2003 was due to equity income from the interests in corporate joint ventures acquired in November 2002, partially offset by a decline in equity income from Explorer Pipeline Company (“Explorer) due to lower volumes.

 

The decrease in total costs and expenses from the prior year was due to a $4.4 million decrease in depreciation and amortization and a $3.0 million decrease in operating expenses, partially offset by a $1.8 million increase in selling, general and administrative expenses. The decrease in depreciation and amortization from $15.1 million for 2002 to $10.6 million for 2003 was principally due to the absence of the write-down previously mentioned. The decrease in operating expenses from $43.0 million for 2002 to $40.0 million for 2003 was primarily due to the absence of costs in the current year associated with a pipeline release in January 2002 and lower pipeline maintenance expenses. As this pipeline release occurred prior to the February 2002 IPO and the Partnership is indemnified by Sunoco, Inc. and its subsidiaries (collectively, “Sunoco”) for liabilities associated with this incident, there was no impact on the Partnership’s post-IPO results. The increase in selling, general and administrative expenses to $18.6 million for 2003 from $16.8 million for 2002 was due to higher allocated administrative expenses.

 

Terminal Facilities

 

The Terminal Facilities business segment experienced a $1.6 million increase in operating income to $30.5 million for the year ended December 31, 2003 compared with $28.9 million for the prior year. This increase was due mainly to a $3.8 million increase in sales and other operating revenue and a $1.1 million increase in other income, partially offset by a $3.3 million increase in total costs and expenses. The increase in sales and other operating revenue to $91.7 million for 2003 compared with $87.9 million for the prior year was principally due to higher throughput volumes at the refined product terminals and the Marcus Hook Tank Farm, partially offset by lower tank rental revenues at the Nederland Terminal. Other income increased to $1.1 million for 2003 due primarily to the gain recognized related to the settlement of a claim at the Nederland Terminal noted previously.

 

The increase in total costs and expenses was due mainly to a $3.0 million increase in operating expenses and a $0.5 million increase in selling, general and administrative expenses. Operating expenses increased to

 

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$38.5 million for 2003 from $35.5 million for the prior year due principally to higher maintenance expenses at the refined product terminals, the Fort Mifflin Terminal Complex, and the Marcus Hook Tank Farm. Selling, general and administrative expenses increased to $12.9 million due to higher allocated administrative expenses.

 

Western Pipeline System

 

Operating income for the Western Pipeline System was $11.9 million for the year ended December 31, 2003 compared with $9.6 million for the prior year. This $2.3 million increase was primarily the result of a $3.5 million increase in other income and a $1.8 million increase in gross margin, partially offset by a $3.0 million increase in selling, general and administrative expenses.

 

Sales and other operating revenue and cost of products sold and operating expenses increased for the year ended December 31, 2003 compared with the prior year due principally to an increase in crude oil prices and an increase in lease acquisition and bulk volumes previously mentioned. The increase in gross margin was due mainly to an increase in lease acquisition volumes and margins and higher trunk and gathering pipeline volumes compared with the prior year. These amounts were partially offset by higher pipeline integrity management and maintenance expenses. Other income increased to $3.4 million for 2003 due mainly to the equity income from the interest in West Texas Gulf Pipe Line acquired in November 2002. Selling, general and administrative expenses increased to $16.9 million for 2003 compared with $13.9 million in the prior year due to higher allocated administrative expenses.

 

Year Ended December 31, 2002 versus Year Ended December 31, 2001

 

Analysis of Statements of Income

 

Net income was $46.8 million for the year ended December 31, 2002 as compared with $26.8 million for the prior year, an increase of $20.0 million. This increase was primarily the result of a $12.3 million increase in operating income and a $14.0 million decrease in income tax expense subsequent to the February 2002 IPO, partially offset by a $6.3 million increase in net interest expense. Operating income was $12.3 million higher in 2002 compared with 2001 due principally to higher revenues at the Terminal Facilities, an increase in total shipments for the Eastern Pipeline System, and higher gross margins from the Western Pipeline System. The increase in revenues at the Terminal Facilities was primarily the result of a change in the pricing arrangement with Sunoco. Effective January 1, 2002, the Partnership began to charge Sunoco market-based fees for most terminalling and throughput services. Prior to this date, terminalling and throughput services provided to Sunoco were at fees that enabled the Partnership to recover costs but not generate any profits (see “Agreements with Sunoco R&M and Sunoco, Inc.”).

 

Sales and other operating revenue totaled $1,824.0 million for the year ended December 31, 2002 as compared with $1,613.0 million for the prior year, an increase of $211.0 million. The increase was largely attributable to higher lease acquisition volumes and an increase in crude oil prices. The average price of West Texas Intermediate crude oil at Cushing, Oklahoma, increased to an average price of $26.11 per barrel for 2002 from $25.95 per barrel for the prior year. Other income increased $2.1 million from the prior year to $6.9 million for 2002 due principally to higher equity income from the Explorer pipeline generated by higher volume and revenue per barrel. Other income also increased due to equity income from the corporate joint venture interests acquired in November 2002. The equity income from these acquisitions has been included within the statements of income from their date of acquisition.

 

Total cost of products sold and operating expenses increased $187.7 million to $1,690.9 million for the year ended December 31, 2002 from $1,503.2 million for the prior year due primarily to an increase in lease acquisition volume and the increase in crude oil prices described previously. Depreciation and amortization increased $6.0 million from $25.3 million for 2001 to $31.3 million for 2002 primarily due to a $6.3 million write-down of an idled refined product pipeline in the Eastern Pipeline System and a related terminal in 2002.

 

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Table of Contents

Selling, general and administrative expenses increased $7.1 million to $43.1 million for 2002 from $36.0 million for the prior year due mainly to public company costs, increased insurance premiums and higher administrative expenses.

 

Net interest expense increased $6.3 million to $17.3 million for the year ended December 31, 2002 compared with $11.0 million for the prior year due principally to interest expense on the $250.0 million, ten year, 7.25 percent Senior Notes, partially offset by lower interest expense on the debt due to Sunoco, which was at a lower variable interest rate than the Senior Notes. The debt due to Sunoco in the prior year was either repaid prior to the February 2002 IPO or not assumed by the Partnership.

 

Income tax expense for the year ended December 31, 2002 of $1.6 million represents a $14.0 million decrease from $15.6 million for the prior year as the Partnership was not subject to income taxes from its inception on February 8, 2002.

 

Analysis of Segment Operating Income

 

Eastern Pipeline System

 

Operating income for the Eastern Pipeline System was $27.2 million for the year ended December 31, 2002 compared with $29.9 million for the prior year. The $2.7 million decrease was primarily the result of a $9.3 million increase in total costs and expenses, partially offset by a $4.4 million increase in sales and other operating revenue and a $2.2 million increase in other income. Sales and other operating revenue increased to $95.0 million for 2002 from $90.7 million for 2001 due mainly to an increase in total shipments. The increase in other income was due principally to higher equity income from the Explorer pipeline resulting from increased volume and revenue per barrel, as well as equity income from the interests in corporate joint ventures acquired in November 2002.

 

The increase in total costs and expenses from the prior year was due mainly to increases in depreciation and amortization of $5.3 million and selling, general and administrative expenses of $3.8 million. The increase in depreciation and amortization to $15.1 million for 2002 from $9.8 million for 2001 was largely attributable to the write-down of the idled refined product pipeline in 2002. The increase in selling, general and administrative expenses to $16.8 million for 2002 from $13.0 million for 2001 was principally due to allocated public company costs, increased insurance premiums and higher administrative expenses.

 

Terminal Facilities

 

Operating income for the Terminal Facilities was $28.8 million for the year ended December 31, 2002 compared with $16.1 million for the prior year. The $12.7 million increase was due to a $14.1 million increase in total revenues, partially offset by a $1.3 million increase in total costs and expenses. Total revenues increased to $87.9 million for 2002 from $73.8 million for 2001 due mainly to the change in the fee arrangement for terminalling and throughput services provided to Sunoco as previously mentioned. Total revenues at the Nederland Terminal also increased due primarily to higher tank rental revenues, including additional revenues from the new tank that was placed into service at the beginning of the second quarter of 2002.

 

The increase in total costs and expenses was due to a $2.2 million increase in selling, general, and administrative expenses, partially offset by a $0.9 million decrease in operating expenses. The increase in selling, general and administrative expenses to $12.4 million for 2002 from $10.2 million for 2001 was largely attributable to allocated public company costs, increased insurance premiums and higher administrative expenses. The decrease in operating expenses to $35.6 million for 2002 from $36.5 million for 2001 was primarily due to lower maintenance expenses at the refined product terminals, the Fort Mifflin Terminal Complex, and the Marcus Hook Tank Farm.

 

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Table of Contents

Western Pipeline System

 

Operating income for the Western Pipeline System was $9.6 million for the year ended December 31, 2002, a $2.3 million increase from the prior year. This increase was primarily the result of a $3.5 million increase in gross margin, partially offset by a $1.1 million increase in selling, general and administrative expenses.

 

Sales and other operating revenue and cost of products sold and operating expenses increased in 2002 compared with the prior year due principally to higher lease acquisition volumes and the increase in crude oil prices previously mentioned. The lease acquisition volume increase was partially due to the acquisition of GulfMark Energy, Inc.’s crude oil pipeline in Texas and its crude oil acquisition business in November 2001 (the “GulfMark Assets”). The $3.5 million increase in gross margin was due to an increase in lease acquisition volume and margins, partially offset by a higher proportion of lower revenue per barrel throughput on the Western Pipeline trunk system. Depreciation and amortization increased $0.7 million to $5.2 million for 2002 compared with the prior year due to higher capital expenditures at the end of 2001, including the acquisition of the GulfMark Assets. Selling, general and administrative expenses increased to $13.9 million for 2002 from $12.8 million for 2001 due to allocated public company costs, increased insurance premiums and higher administrative expenses.

 

Liquidity and Capital Resources

 

General

 

Cash generated from operations and the Credit Facility are the Partnership’s primary sources of liquidity. At December 31, 2003, the Partnership had working capital of $38.8 million and $185.5 million available borrowing capacity under the Credit Facility. The Partnership also has a $500 million universal shelf registration statement which allows the issuance of additional common units or debt securities. In addition, the Partnership’s working capital position reflects crude oil inventories based on historical costs under the LIFO method of accounting. If the inventories had been valued at their current replacement cost, working capital would have increased by $38.1 million at December 31, 2003. Management believes that the Partnership has sufficient liquid assets, cash from operations and borrowing capacity under its credit agreements to meet its financial commitments, debt service obligations, unitholder distributions, contingencies and anticipated capital expenditures. However, the Partnership is subject to business and operations risks that could adversely effect its cash flow. The Partnership may supplement its cash generation with proceeds from financing activities, including borrowings under the Credit Facility and other borrowings and the issuance of additional common units.

 

Cash Flows and Capital Expenditures

 

Net cash provided by operating activities for the years ended December 31, 2001, 2002 and 2003 was $27.2 million, $2.2 million, and $97.2 million, respectively. Net cash provided by operating activities for 2003 was primarily generated by net income of $59.4 million, depreciation and amortization of $27.2 million, and a decrease in working capital of $7.5 million. Net cash provided by operating activities for 2002 was primarily generated by net income of $46.8 million and depreciation and amortization of $31.3 million, partially offset by an increase in working capital of $73.4 million. Net cash provided by operating activities for 2001 principally includes net income of $26.8 million, depreciation and amortization of $25.3 million, and deferred income tax expense of $8.8 million, partially offset by an increase in working capital of $33.6 million. The increase in net cash provided by operating activities of $95.0 million from 2002 to 2003 was primarily attributable to an increase in cash provided by working capital and an increase in net income. The change in working capital between 2002 and 2003 was due mainly to an increase in working capital in 2002 related to the replacement of working capital that was not contributed by Sunoco to the Partnership upon formation. The net proceeds of the IPO were used to replenish the working capital shortfall. The working capital not contributed consisted principally of $81.0 million of affiliated-company accounts receivable and $13.5 million of crude oil inventory. The decrease in net cash provided by operating activities of $25.0 million from 2001 to 2002 was due mainly to an increase in net cash

 

40


Table of Contents

used for working capital and a decrease in deferred income tax expense, partially offset by an increase in net income and depreciation and amortization. The change in working capital between 2001 and 2002 was primarily attributable to the increase in working capital in 2002 previously mentioned.

 

Net cash used in investing activities for the years ended December 31, 2001, 2002, and 2003 was $73.1 million, $85.3 million and $39.0 million, respectively. Capital expenditures were $72.7 million in 2001, $40.8 million in 2002, and $37.4 million in 2003. During 2003, the Partnership acquired an additional 3.1 percent corporate joint venture interest in West Shore for $3.7 million. During 2002, the Partnership acquired equity ownership interests in four corporate joint venture pipeline companies for an aggregate purchase price of $64.5 million in cash and $0.1 million in Partnership common units, consisting of $54.0 million for a 31.5 percent interest in Wolverine, a 9.2 percent interest in West Shore, and a 14.0 percent interest in Yellowstone and $10.6 million for a 43.8 percent interest in West Texas Gulf. The only other significant investing transaction in the three-year period was the repayment of a loan to The Claymont Investment Company, a wholly-owned subsidiary of Sunoco, for $20.0 million in 2002.

 

Net cash provided by/(used in) financing activities for the years ended December 31, 2001, 2002, and 2003 was $45.8 million, $116.9 million, and ($42.0) million, respectively. For the year ended December 31, 2003, the $42.0 million of net cash used in financing activities was primarily due to $46.2 million of distributions paid to unitholders and the general partner and $4.5 million of repayments of long-term debt related to a note payable to a third party, partially offset by net collections of $3.4 million of advances to affiliate and $5.3 million of capital contributions from Sunoco. For the year ended December 31, 2002, the $116.9 million of net cash provided by financing activities was due to net proceeds of $96.5 million from the IPO, $64.5 million of borrowings under the Credit Facility to fund the acquisitions noted earlier, and $43.9 million of capital contributions from Sunoco, partially offset by a $50.0 million repayment of long-term debt due an affiliate, $26.9 million of distributions paid to unitholders and the general partner and net advances to affiliates of $10.7 million. In addition, net proceeds of $244.8 million from the issuance of the Senior Notes in conjunction with the IPO were distributed to Sunoco. For a more detailed discussion of the IPO and related transactions, see “Initial Public Offering” and “Senior Notes” in this section. For the year ended December 31, 2001, the $45.8 million of net cash provided by financing activities was primarily generated by $91.1 million of contributions from Sunoco and its affiliates, partially offset by $45.0 million of repayments of borrowings to The Claymont Investment Company.

 

Under the treasury services agreement entered into with Sunoco upon the closing of the February 2002 IPO, the Partnership, among other things, participates in Sunoco’s centralized cash management program. Advances to affiliates in the Partnership’s balance sheets at December 31, 2002 and 2003 represent amounts due from Sunoco under this treasury services agreement. Prior to the IPO, The Claymont Investment Company served as a lender and borrower of funds to and from Sunoco and its subsidiaries, including the predecessor to the Partnership, to enable those entities to achieve their desired capital structures. Amounts owed to and due from The Claymont Investment Company under these financing arrangements included in the Predecessor’s balance sheets were not assumed by or contributed to the Partnership. Furthermore, subsequent to the IPO, the Partnership has not and will not engage in these types of financing arrangements with The Claymont Investment Company or any other subsidiary of Sunoco.

 

Capital Requirements

 

The pipeline, terminalling, and crude oil storage operations are capital intensive, requiring significant investment to upgrade or 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, and to address environmental regulations; and

 

  Expansion capital expenditures to acquire complementary assets to grow the business and to expand existing facilities, such as projects that increase storage or throughput volume.

 

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Table of Contents

The following table summarizes maintenance and expansion capital expenditures for the years presented:

 

     Predecessor

   Partnership
and
Predecessor


    Partnership

 
     Year Ended December 31,

 
     2001

   2002

    2003

 
     (in thousands)  

Maintenance

   $ 53,628    $ 27,934     $ 30,850  

Expansion

     19,055      77,439 (1)     10,226 (2)
    

  


 


Total

   $ 72,683    $ 105,373     $ 41,076  
    

  


 



(1) Includes the acquisition of the interests in four corporate joint venture pipeline companies in November 2002 for an aggregate purchase price of $64.6 million, including the issuance of $0.1 million in Partnership common units.
(2) Includes the acquisition of an additional interest in one of its corporate joint venture pipeline interests for $3.7 million.

 

Maintenance capital expenditures for the years ended December 31, 2001, 2002 and 2003 were $53.6 million, $27.9 million, and $30.9 million, respectively. 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, repair and replacement of tank floors and roofs, upgrades of cathodic protection systems, and the upgrade of pump stations. In addition to these recurring projects, maintenance capital includes expenditures at the Darby Creek Tank Farm and the Marcus Hook Tank Farm of $2.6 million and $3.0 million for the years ended December 31, 2002 and 2003, respectively, for which the Partnership received reimbursement from Sunoco R&M under the terms of the Omnibus Agreement. The year ended December 31, 2003 includes $1.8 million of expenditures for the replacement of assets at the Nederland Terminal related to the May 2003 third-party natural gas pipeline release. The Partnership received reimbursement in 2003 for these costs and other expenses as settlement of the claim related to this incident. The year ended December 31, 2001 includes several one-time projects undertaken primarily to upgrade the Partnership’s technology, increase reliability, and lower its cost structure. These expenditures were not incurred in 2002 and 2003 and are not expected to be incurred in the near future by the Partnership’s management. Management expects maintenance capital expenditures to be approximately $25.0 million in 2004.

 

Expansion capital expenditures for the years ended December 31, 2001, 2002 and 2003 were $19.1 million, $77.4 million and $10.2 million, respectively. Expansion capital expenditures for the year ended December 31, 2003 includes the purchase of an additional 3.1 percent interest in West Shore Pipe Line Company for $3.7 million, increasing the Partnership’s overall ownership interest to 12.3 percent, and the completion of the construction of two new tanks and a new pump station at the Nederland Terminal. The new tanks added approximately 1.3 million barrels of storage capacity to the terminal. Expansion capital expenditures for the year ended December 31, 2002 includes the acquisition of the four corporate joint venture pipeline interests for an aggregate purchase price of $64.6 million, the construction of the two Nederland tanks previously mentioned, the construction of multiple vapor combustion units at the Nederland Terminal, and pipeline meter modifications at the Eastern Pipeline System to improve throughput efficiency. Expansion capital expenditures for the year ended December 31, 2001 include several projects to create new tankage, increase throughput on existing pipelines and build new connections for deliveries to customers. Management of the Partnership anticipates pursuing both further acquisitions and growth projects similar to those mentioned in the future.

 

Under the terms of the Omnibus Agreement, Sunoco R&M is required, among other things, to: reimburse the Partnership 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 ending December 31, 2006; complete, at its expense, certain tank maintenance and inspection projects at the Darby Creek Tank Farm;

 

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Table of Contents

and reimburse the Partnership for up to $10.0 million of expenditures required at the Marcus Hook Tank Farm and the Darby Creek Tank Farm to maintain compliance with existing industry standards and regulatory requirements.

 

For the years ended December 31, 2002 and 2003, the Partnership was reimbursed $0.7 million and $1.9 million, respectively, by Sunoco R&M for maintenance capital expenditures and operating expenses incurred in excess of $8.0 million to comply with DOT’s pipeline integrity management rule. At December 31, 2003, the Partnership has received a cumulative reimbursement of $2.6 million in regard to the $15.0 million maximum reimbursement over the five-year period for compliance expenditures related to the DOT’s pipeline integrity management rule. For the year ended December 31, 2002, the Partnership also was reimbursed $2.1 million by Sunoco R&M for certain tank maintenance and inspection capital expenditures at the Darby Creek Tank Farm. There were no amounts expended for these tank maintenance and inspection projects at the Darby Creek Tank Farm during 2003. For the years ended December 31, 2002 and 2003, the Partnership was reimbursed by Sunoco R&M for expenditures at the Marcus Hook Tank Farm and the Darby Creek Farm to maintain compliance with existing industry standards and regulatory requirements. These expenditures, which were recorded as maintenance capital and operating expenses, were as follows:

     Partnership
and
Predecessor


   Partnership

     Year Ended December 31,

     2002

   2003

     (amounts in thousands)

Maintenance capital

   $ 534    $ 2,982

Operating expenses

     351      467
    

  

     $ 885    $ 3,449
    

  

 

At December 31, 2003, the Partnership has received a cumulative reimbursement of $4.3 million relative to the $10 million maximum reimbursement for compliance expenditures at the Marcus Hook Tank Farm and the Darby Creek Tank Farm. The aggregate amounts reimbursed related to all of the previously mentioned provisions of the Omnibus Agreement of $3.7 million and $5.3 million for the years ended December 31, 2002 and 2003, respectively, by Sunoco R&M related to these projects were recorded by the Partnership as capital contributions.

 

The Partnership expects to fund capital expenditures, including any acquisitions, from cash provided by operations and, to the extent necessary, from the proceeds of:

 

  borrowing under the Credit Facility discussed below and 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 interest rate in effect at December 31, 2003), annual rentals applicable to noncancellable operating leases, and purchase commitments related to future periods at December 31, 2003 (in thousands):

 

     Year Ended December 31,

         
     2004

   2005

   2006

   2007

   2008

   Thereafter

   Total

Long-term debt:

                                                

Principal

   $ —      $ 64,500    $ —      $ —      $ —      $ 250,000    $ 314,500

Interest

     19,318      18,224      18,125      18,125      18,125      63,438      155,355

Operating leases

     2,785      2,152      1,772      1,437      1,318      6,573      16,037

Purchase obligations

     853,686      —        —        —        —        —        853,686
    

  

  

  

  

  

  

     $ 875,789    $ 84,876    $ 19,897    $ 19,562    $ 19,443    $ 320,011    $ 1,339,578
    

  

  

  

  

  

  

 

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The Partnership’s operating leases include leases of third-party pipeline capacity, office space, and other property and equipment. Operating leases included above have 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. The Partnership’s purchase obligations consist of noncancellable contracts to purchase crude oil for terms of one year or less by its Crude Oil Acquisition and Marketing group. The majority of the above purchase obligations include actual crude oil purchases for the month of January 2004. The remaining purchase obligation amounts are based on the quantities expected to be purchased for the remainder of the year, at December 31, 2003 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 the Partnership’s Crude Oil and Marketing activities, see Item 1. “Business—Western Pipeline System—Crude Oil Acquisition and Marketing”.

 

Initial Public Offering

 

On February 8, 2002, the Partnership issued 5.75 million common units (including 750,000 units issued pursuant to the underwriters’ over-allotment option), representing a 24.8 percent limited partnership interest, in an IPO at a price of $20.25 per unit. Proceeds from this offering, which totaled approximately $96.5 million net of underwriting discounts and offering expenses, were used to establish working capital that was not contributed by Sunoco.

 

Credit Facility

 

In conjunction with the IPO, Sunoco Logistics Partners Operations L.P., a wholly-owned subsidiary of the Partnership (the “Operating Partnership”), entered into its Credit Facility, which currently has an aggregate committed sum of $250 million. The Credit Facility is available to fund working capital requirements, to finance future acquisitions, and for general partnership purposes. It also includes a $20.0 million distribution sublimit that is available for distributions, and may be used to fund the quarterly distributions, provided the total outstanding borrowings for distributions do not at any time exceed $20.0 million. The Partnership will be required to reduce to zero all borrowings under the distribution sublimit under the Credit Facility each year for 15 days. At December 31, 2003, there was $64.5 million drawn under the Credit Facility.

 

Obligations under the Credit Facility are unsecured. Indebtedness under the Credit Facility will rank equally with all the outstanding unsecured and unsubordinated debt of the Operating Partnership. All loans may be prepaid at any time without penalty subject to reimbursement of breakage and redeployment costs in the case of prepayment of LIBOR borrowings.

 

Indebtedness under the Credit Facility will bear interest, at the Partnership’s option, at either (i) LIBOR plus an applicable margin or (ii) the higher of the federal funds rate plus 0.50 percent or the Bank of America prime rate (each plus the applicable margin). The interest rate on the borrowings outstanding under the Credit Facility as of December 31, 2003 was 1.85 percent. Fees are incurred in connection with the Credit Facility. The Credit Facility will mature on January 31, 2005. It is the Partnership’s intent to renew the Credit Facility in 2004.

 

The credit agreement prohibits the Partnership from declaring distributions to unitholders if any event of default, as defined in the credit agreement, occurs or would result from the declaration of distributions. In addition, the Credit Facility contains various covenants limiting the Operating Partnership’s ability to:

 

  incur indebtedness;

 

  grant certain liens;

 

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  make certain loans, acquisitions, and investments;

 

  make any material change to the nature of the business;

 

  acquire another company; or

 

  enter into a merger or sale of assets, including the sale or transfer of interests in the subsidiaries.

 

The Credit Facility also contains covenants requiring the maintenance, on a rolling-four-quarter basis, of:

 

  a maximum ratio of 4.0 to 1 of consolidated total debt to consolidated EBITDA (each as defined in the credit agreement); and

 

  an interest coverage ratio (as defined in the credit agreement) of at least 3.5 to 1.

 

For the year ended December 31, 2003, the Partnership’s ratio of total debt to EBITDA was 3.0 to 1 and the interest coverage ratio was 5.1 to 1.

 

Each of the following will be an event of default under the Credit Facility:

 

  failure to pay any principal, interest, fees, or other amounts when due;

 

  failure of any representation or warranty to be true and correct;

 

  termination of any material agreement, including the pipelines and terminals storage and throughput agreement and the Omnibus Agreement;

 

  default under any material agreement if such default could have a material adverse effect on the Partnership;

 

  bankruptcy or insolvency events involving the Partnership, the general partner, or the subsidiaries;

 

  the entry of monetary judgments, not covered or funded by insurance, against the Partnership, the general partner, or any of its subsidiaries in excess of $20.0 million in the aggregate, or any non-monetary judgment having a material adverse effect;

 

  the sale by Sunoco of a material portion of its refinery assets or other assets related to its agreements with the Partnership unless the purchaser of those assets has a minimum credit rating and fully assumes the rights and obligations of Sunoco under those agreements; and

 

  failure by Sunoco to own, directly or indirectly, 51 percent of the general partnership interest in the Partnership or to control management and that of the Operating Partnership.

 

Senior Notes

 

Also in connection with the February 2002 IPO, the Operating Partnership issued $250 million of Senior Notes, the net proceeds of which were distributed to Sunoco as additional consideration for its contribution of assets to the Partnership. The Senior Notes were issued pursuant to an indenture, and the obligations under the Senior Notes are unsecured. Indebtedness under the Senior Notes rank equally with the Credit Facility and all the outstanding unsecured and unsubordinated debt of the Operating Partnership. The Senior Notes and Credit Facility have been guaranteed by the Partnership and the Operating Partnership’s subsidiaries. The Senior Notes will mature on February 15, 2012 and bears interest at a rate of 7.25 percent per annum, payable semi-annually on February 15 and August 15. The Senior Notes are redeemable, at the Partnership’s option, at a make-whole premium calculated on the basis of a discount rate equal to the yield on United States treasury notes having a constant maturity comparable to the remaining term of the Senior Notes, plus 25 basis points. The Senior Notes are not subject to any sinking fund provisions.

 

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In addition, the 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.

 

Each of the following is an event of default under the indenture governing the Senior Notes:

 

  failure to pay interest on any note for 30 days;

 

  failure to pay the principal or any premium on any note when due;

 

  failure to perform any other covenant in the indenture that continues for 60 days after being given written notice;

 

  the acceleration of the maturity of any other debt of the Partnership or any of the subsidiaries or a default in the payment of any principal or interest in respect of any other indebtedness of the Partnership or any of the subsidiaries having an outstanding principal amount of $10.0 million or more individually or in the aggregate and such default shall be continuing for a period of 30 days; or

 

  the bankruptcy, insolvency, or reorganization of the Operating Partnership.

 

Upon the occurrence of a change of control to a non-investment grade entity, the Operating Partnership must offer to purchase the Senior Notes at a price equal to 100 percent of their principal amount plus accrued and unpaid interest, if any, to the date of purchase. The initial offering of the Senior Notes was not registered under the Securities Act. A registration statement was subsequently filed and declared effective on June 28, 2002, and a exchange offer was completed on August 2, 2002, with all $250 million aggregate principal amount of the Senior Notes being exchanged for a like principal amount of new publicly tradable notes having substantially identical terms issued pursuant to the exchange offer registration statement filed under the Securities Act of 1933, as amended.

 

Shelf Registration Statement

 

On March 14, 2003, the Partnership and Operating Partnership, as co-registrants, filed a shelf registration statement with the Securities and Exchange Commission and became effective. This shelf registration permits the periodic offering and sale of equity securities by the Partnership and debt securities of the Operating Partnership (guaranteed by the Partnership). No offering of equity or debt securities have been made, either by the Partnership or the Operating Partnership, since the shelf registration became effective and, at December 31, 2003, $500 million remains available for issuance. However, the amount, type and timing of any offerings will depend upon, among other things, the funding requirements of the Partnership, prevailing market conditions, and compliance with covenants in applicable debt obligations of the Operating Partnership (including the Credit Facility).

 

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 the Partnership’s accounting policies, liabilities are recorded when site restoration and environmental remediation and cleanup obligations are either known or considered probable and can be reasonably estimated. For a discussion of the accrued liabilities and charges against income related to these activities, see Note 11 to the financial statements included in Item 8. “Financial Statements and Supplementary Data.”

 

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Under the terms of the Omnibus Agreement and in connection with the contribution of assets by affiliates of Sunoco, Sunoco has agreed to indemnify the Partnership 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 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 the loss. There is no monetary cap on the amount of indemnity coverage provided by Sunoco. Any environmental and toxic tort liabilities not covered by this indemnity will be the Partnership’s 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. The Partnership has 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 the Partnership.

 

The use of MTBE continues to be the focus of federal and state government attention due to public health and environmental issues that have been raised by the use of MTBE in gasoline, and specifically the discovery of MTBE in water supplies. MTBE is the primary oxygenate used by Sunoco R&M and other petroleum refiners to meet reformulated gasoline requirements under the Clean Air Act. Several states, including New York and Connecticut, began enforcing state-imposed MTBE bans on January 1, 2004 in response to concerns about MTBE’s adverse impact on ground or surface water. Other states are considering bans or restrictions on MTBE or opting out of the EPA’s reformulated gasoline program, either of which events would reduce the use of MTBE. Any ban or restriction on the use of MTBE may lead to the greater use of ethanol. Unlike MTBE, which can be blended in gasoline at the refinery, ethanol is blended at the terminal and is not transported by the pipelines. While many of the inland-refined product terminals currently blend ethanol, any revenues the Partnership would receive for blending ethanol might not offset the loss of revenues that would be suffered from the reduced volume transported on the Eastern refined product pipelines.

 

Sunoco has disclosed that new rules under the Clean Air Act affecting fuel specifications may have a significant impact on its operations (primarily with respect to the capital and operating expenditures at Sunoco R&M’s refineries), but that such impact ultimately may be affected by technology selection, timing uncertainties related to construction or permitting schedules, any effect on prices due to changes in the levels of gasoline or diesel production, and other factors. The Partnership cannot assure investors that the impact of these new rules, and Sunoco’s responses to them, will not reduce Sunoco R&M’s obligations under the pipelines and terminals storage and throughput agreement, thereby reducing the throughput in the pipelines and the cash flow.

 

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, the Partnership has and will continue to pass along increased costs to customers in the form of higher fees.

 

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Critical Accounting Policies

 

A summary of the Partnership’s 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 it to provide the users of the financial statements with useful and reliable information about the Partnership’s operating results and financial condition. The preparation of the Partnership’s 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 to some extent from the estimates on which the Partnership’s financial statements are prepared at any given point in time. Despite these inherent limitations, management believes the Partnership’s Management’s Discussion and Analysis and financial statements provide a meaningful and fair perspective of the Partnership. Management has reviewed the estimates affecting its critical accounting policies with the Audit Committee of Sunoco Partners LLC’s Board of Directors.

 

Long-Lived Assets. The cost of property, 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 show 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. There have been no significant changes in the useful lives of the Partnership’s plants and equipment to be recognized prospectively during the 2001-2003 period.

 

Long-lived assets, other than those held for sale, 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 the Partnership’s services or for the Partnership’s 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 described under “Forward Looking Statements”, which can be found after the Table of Contents at the front of 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 the Partnership’s 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.

 

The Partnership had asset impairments of $1.4 million and $6.3 million for the years ended December 31, 2001 and 2002. There were no asset impairments for the year ended December 31, 2003. During 2002, the Partnership recorded a $6.3 million provision to write-down an idled refined product pipeline in the Eastern Pipeline System and a related terminal. These assets were idled as a result of a long-term agreement entered into by the Partnership in December 2002 to lease throughput capacity on a third-party refined product pipeline which allows it to provide substantially the same service as existed on the idled pipeline while reducing operating expenses. During 2001, the Predecessor recorded a $1.4 million charge to write-off obsolete refined product terminal equipment due to the purchase of technologically advanced units. These provisions were recorded within depreciation and amortization in the statements of income in the financial statements. For further discussion of these asset impairments, see Note 4 to the financial statements included in Item 8 “Financial Statements and Supplementary Data.”

 

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Environmental Remediation. The operation of the Partnership’s 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 the Partnership’s facilities and properties, including liabilities for environmental remediation obligations.

 

At December 31, 2002 and 2003, the Partnership’s accrual for environmental remediation activities was $0.5 million for both periods. These accruals are 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 the Partnership’s financial position at December 31, 2003. As a result, the Partnership’s 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 the Partnership’s 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 the Predecessor to the Partnership by affiliates of Sunoco, Sunoco has retained these liabilities in connection with its agreement to indemnify the Partnership 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 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 the loss. There is no monetary cap on the amount of indemnity coverage provided by Sunoco. Any environmental and toxic tort liabilities not covered by this indemnity will be the Partnership’s responsibility. The Partnership has 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 the Partnership.

 

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 the Partnership’s liability at the sites, if any, in the light of the number, participation level and financial viability of other parties.

 

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New Accounting Pronouncements

 

In January 2003, FASB Interpretation No. 46, “Consolidation of Variable Interest Entities” (“FASB Interpretation No. 46”), was issued. Among other things, FASB Interpretation No. 46 defines a variable interest entity (“VIE”) as an entity that either has investor voting rights that are not proportional to their economic interests or has equity investors that do not provide sufficient financial resources for the entity to support its activities. FASB Interpretation No. 46 requires a VIE to be consolidated by an entity if that entity is the primary beneficiary. The primary beneficiary is the entity that is subject to a majority of the risk of loss from the VIE’s activities or, if no entity is subject to a majority of such risk, the entity that is entitled to receive a majority of the VIE’s residual returns. The Partnership intends to adopt FASB Interpretation No. 46 effective January 1, 2004. FASB Interpretation No. 46 is not expected to have an impact on the Partnership’s financial statements upon adoption.

 

Effective July 1, 2003, the Partnership adopted 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 Statement of Financial Accounting Standards 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 reported as transportation and storage services might have to be reported as rental or leasing income. 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. Previous arrangements that would be leases or would contain a lease according to this pronouncement will continue to be recorded in accordance with their prior accounting treatment. The Partnership is currently 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 impact on the Partnership’s financial statements for the year ended December 31, 2003.

 

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

The Partnership is 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. The Partnership has not entered into derivative transactions that would expose it to price risk.

 

The $250 million Credit Facility, with outstanding borrowings at December 31, 2003 of $64.5 million, exposes the Partnership to interest rate risk, since it bears interest at a variable rate (1.85 percent at December 31, 2003). A one percent change in interest rates changes annual interest expense by approximately $645,000.

 

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

REPORT OF INDEPENDENT AUDITORS

 

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, 2002 and 2003 and the related statements of income and partners’ capital/net parent investment and cash flows for each of the three years in the period ended December 31, 2003. 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 auditing standards generally accepted in the 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, 2002 and 2003 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States.

 

As discussed in Note 1 to the financial statements, in 2002 the Partnership changed its method of accounting for goodwill and other indefinite-lived intangible assets in accordance with Statement of Financial Accounting Standards No. 142.

 

ERNST & YOUNG LLP

 

Philadelphia, Pennsylvania

February 13, 2004

 

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SUNOCO LOGISTICS PARTNERS L.P.

 

STATEMENTS OF INCOME

(in thousands, except units and per unit amounts)

 

     Predecessor

    Partnership
and
Predecessor


    Partnership

 
     Year Ended December 31,

 
     2001

    2002

    2003

 

Revenues

                        

Sales and other operating revenue:

                        

Affiliates (Note 3)

   $ 1,067,182     $ 1,147,721     $ 1,383,090  

Unaffiliated customers

     545,822       676,307       1,274,383  

Other income

     4,774       6,904       16,730  
    


 


 


Total Revenues

     1,617,778       1,830,932       2,674,203  
    


 


 


Costs and Expenses

                        

Cost of products sold and operating expenses

     1,503,156       1,690,896       2,519,160  

Depreciation and amortization (Note 4)

     25,325       31,334       27,157  

Selling, general and administrative expenses

     35,956       43,073       48,412  
    


 


 


Total Costs and Expenses

     1,564,437       1,765,303       2,594,729  
    


 


 


Operating Income

     53,341       65,629       79,474  

Net interest cost paid to affiliates (Note 3)

     11,727       1,205       15  

Other interest cost and debt expense, net

     393       17,390       20,518  

Capitalized interest

     (1,140 )     (1,296 )     (493 )
    


 


 


Income before income tax expense

     42,361       48,330       59,434  

Income tax expense (Note 5)

     15,594       1,555       —    
    


 


 


Net Income

   $ 26,767     $ 46,775     $ 59,434  
    


 


 


Allocation of 2002 Net Income:

                        

Portion applicable to January 1 through February 7, 2002 (period prior to initial public offering)

           $ 3,421          

Portion applicable to February 8 through December 31, 2002

             43,354          
            


       

Net Income

           $ 46,775          
            


       

Calculation of Limited Partners’ interest in Net Income:

                        

Net Income

           $ 43,354     $ 59,434  

Less: General Partners’ interest in Net Income

             867       1,423  
            


 


Limited Partners’ interest in Net Income

           $ 42,487     $ 58,011  
            


 


Net Income per Limited Partner unit (2002 is for the period from February 8, 2002 through December 31, 2002):

                        

Basic

           $ 1.87     $ 2.55  
            


 


Diluted

           $ 1.86     $ 2.53  
            


 


Weighted average Limited Partners’ units outstanding (Note 6):

                        

Basic

             22,767,899       22,771,793  
            


 


Diluted

             22,785,407       22,894,520  
            


 


 

 

(See Accompanying Notes)

 

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SUNOCO LOGISTICS PARTNERS L.P.

 

BALANCE SHEETS

(in thousands)

 

     Partnership

     December 31,

     2002

   2003

Assets

             

Current Assets

             

Cash and cash equivalents

   $ 33,840    $ 50,081

Advances to affiliates (Note 3)

     10,716      7,288

Accounts receivable, affiliated companies (Note 3)

     105,466      116,936

Accounts receivable, net

     251,071      302,235

Inventories (Note 7)

     25,744      27,268
    

  

Total Current Assets

     426,837      503,808

Properties, plants and equipment, net (Note 8)

     573,514      583,164

Investment in affiliates (Note 9)

     65,733      70,490

Deferred charges and other assets

     27,796      22,536
    

  

Total Assets

   $ 1,093,880    $ 1,179,998
    

  

Liabilities and Partners’ Capital / Net Parent Investment Current Liabilities

             

Accounts payable

   $ 356,977    $ 426,863

Accrued liabilities

     25,090      26,816

Current portion of long-term debt (Note 10)

     303      —  

Accrued taxes other than income

     11,273      11,312
    

  

Total Current Liabilities

     393,643      464,991

Long-term debt (Note 10)

     317,142      313,136

Other deferred credits and liabilities

     745      1,000

Commitments and contingent liabilities (Note 11)

             

Partners’ Capital:

             

Limited partners’ interest

     376,632      394,592

General partner’s interest

     5,718      6,279
    

  

Total Liabilities and Partners’ Capital

   $ 1,093,880    $ 1,179,998
    

  

 

(See Accompanying Notes)

 

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SUNOCO LOGISTICS PARTNERS L.P.

 

STATEMENTS OF CASH FLOWS

(in thousands)

 

     Predecessor

    Partnership
and
Predecessor


    Partnership

 
     Year Ended December 31,

 
     2001

    2002

    2003

 

Cash Flows from Operating Activities:

                        

Net Income

   $ 26,767     $ 46,775     $ 59,434  

Adjustments to reconcile net income to net cash provided by operating activities:

                        

Depreciation and amortization

     25,325       31,334       27,157  

Deferred income tax expense

     8,813       675       —    

Gain on claim settlement

     —         —         (1,175 )

Changes in working capital pertaining to operating activities:

                        

Accounts receivable, affiliated companies

     508       (99,221 )     (11,470 )

Accounts receivable, net

     106,780       (102,253 )     (51,164 )

Inventories

     (1,923 )     (12,127 )     (1,524 )

Accounts payable and accrued liabilities

     (140,340 )     135,244       71,612  

Taxes payable

     1,415       4,972       39  

Other

     (107 )     (3,188 )     4,303  
    


 


 


Net cash provided by operating activities

     27,238       2,211       97,212  
    


 


 


Cash Flows from Investing Activities:

                        

Capital expenditures

     (72,683 )     (40,782 )     (37,377 )

Net cash paid for acquisitions

     —         (64,491 )     (3,699 )

Collection of loan to affiliate

     —         20,000       —    

Net proceeds from claim settlement

     —         —         2,068  

Other

     (396 )     —         —    
    


 


 


Net cash used in investing activities

     (73,079 )     (85,273 )     (39,008 )
    


 


 


Cash Flows from Financing Activities:

                        

Distributions paid to unitholders and general partner

     —         (26,949 )     (46,227 )

Net proceeds from issuance of common units to the public

     —         96,468       —    

Advances to affiliates, net

     —         (10,716 )     3,428  

Net borrowings under credit facility

     —         64,500       —    

Repayments of long-term debt

     (262 )     (303 )     (4,478 )

Repayments of long-term debt to affiliate

     —         (50,000 )     —    

Net proceeds from issuance of long-term debt

     —         244,788       —    

Special distribution to Sunoco

     —         (244,788 )     —    

Contributions from Sunoco

     91,103       43,902       5,314  

Net repayments of short-term borrowings due affiliate

     (45,000 )     —         —    
    


 


 


Net cash provided by / (used in) financing activities

     45,841       116,902       (41,963 )
    


 


 


Net change in cash and cash equivalents

     —         33,840       16,241  

Cash and cash equivalents at beginning of year

     —         —         33,840  
    


 


 


Cash and cash equivalents at end of year

   $ —       $ 33,840     $ 50,081  
    


 


 


 

(See Accompanying Notes)

 

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SUNOCO LOGISTICS PARTNERS L.P.

 

STATEMENTS OF PARTNERS’ CAPITAL/NET PARENT INVESTMENT

(in thousands, except unit amounts)

 

          Partners’ Capital

   

Total
Partners’
Capital /

Net
Parent
Investment


 
      Limited Partners

         
    Net Parent
Investment


    Common

   

Subordinated


    General
Partner


   
    $

    Units

  $

    Units

  $

    $

    $

 

Balance at January 1, 2001

  $ 157,023     —     $ —       —     $ —       $ —       $ 157,023  

Net income

    26,767     —       —       —       —         —         26,767  

Contribution from Sunoco

    91,103     —       —       —       —         —         91,103  
   


 
 


 
 


 


 


Balance at December 31, 2001

  $ 274,893     —     $ —       —     $ —       $ —       $ 274,893  

Net income applicable to the period from January 1 through February 7, 2002

    3,421     —       —       —       —         —         3,421  

Contribution from Sunoco

    40,217     —       —       —       —         —         40,217  

Adjustment to reflect net liabilities not contributed by Sunoco to the Partnership (Note 12)

    190,887     —       —       —       —         —         190,887  

Special distribution to Sunoco

    (244,788 )   —       —       —       —         —         (244,788 )
   


 
 


 
 


 


 


Net assets contributed by Sunoco

    264,630     —       —       —       —         —         264,630  

Allocation of net assets contributed by Sunoco

    (264,630 )   5,633,639     85,855     11,383,639     173,482       5,293       —    

Issuance of common units to the public (Note 2)

    —       5,750,000     96,468     —       —         —         96,468  

Issuance of units to Sunoco in partial consideration for West Texas Gulf Acquisition (Note 14)

    —       4,515     100     —       —         2       102  

Contribution from Sunoco (Note 3)

    —       —       1,539     —       3,111       95       4,745  

Net income applicable to the period from February 8 through December 31, 2002

    —       —       21,248     —       21,239       867       43,354  

Cash distributions

    —       —       (13,205 )   —       (13,205 )     (539 )     (26,949 )
   


 
 


 
 


 


 


Balance at December 31, 2002

    —       11,388,154   $ 192,005     11,383,639   $ 184,627     $ 5,718     $ 382,350  

Contribution from Sunoco

    —       —       1,726     —       3,482       106       5,314  

Net income

    —       —       29,011     —       29,000       1,423       59,434  

Cash distributions

    —       —       (22,634 )   —       (22,625 )     (968 )     (46,227 )
   


 
 


 
 


 


 


Balance at December 31, 2003

  $ —       11,388,154   $ 200,108     11,383,639   $ 194,484     $ 6,279     $ 400,871  
   


 
 


 
 


 


 


 

(See Accompanying Notes)

 

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SUNOCO LOGISTICS PARTNERS L.P.

 

NOTES TO FINANCIAL STATEMENTS

 

1. Summary of Significant Accounting Policies

 

Basis of Presentation and Principles of Combination / Consolidation

 

Sunoco Logistics Partners L.P. (the “Partnership”) is a Delaware limited partnership formed by Sunoco, Inc. in October 2001 to acquire, own and operate a substantial portion of Sunoco, Inc.’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 South Central United States (collectively, “Sunoco Logistics (Predecessor)” or the “Predecessor”).

 

The accompanying financial statements reflect the historical cost-basis accounts of the Predecessor for periods prior to February 8, 2002, the closing date of the Partnership’s initial public offering (the “IPO”—see Note 2), and include charges from Sunoco, Inc. and its subsidiaries (collectively, “Sunoco”) for direct costs and allocations of indirect corporate overhead. Management of the Partnership believes that the allocation methods are reasonable, and that the allocations are representative of the costs that would have been incurred on a stand-alone basis. Beginning on February 8, 2002, the financial statements reflect the consolidated financial statements of the Partnership and its subsidiaries. Equity ownership interests in corporate joint ventures, which are not consolidated, are accounted for under the equity method.

 

Description of Business

 

Most of the assets of the Partnership support Sunoco refining and marketing operations which are conducted primarily by Sunoco, Inc. (R&M) (“Sunoco R&M”). The Partnership operates in three principal business segments: Eastern Pipeline System, Terminal Facilities and Western Pipeline System.

 

The Eastern Pipeline System transports refined products in the Northeast and Midwest largely for Sunoco R&M’s Philadelphia, PA, Marcus Hook, PA and Toledo, OH refineries. The Eastern Pipeline System also transports crude oil on a pipeline in Ohio and Michigan that supplies both Sunoco R&M’s Toledo refinery and third-party refineries. This segment also includes an interrefinery pipeline between Sunoco R&M’s Marcus Hook and Philadelphia refineries and the equity interest in Explorer Pipeline Company (“Explorer”), which transports refined products from the Gulf Coast to numerous terminals throughout the Midwest. During November 2002, the Partnership acquired an equity ownership interest in three Midwestern and Western United States refined product pipelines, consisting of 31.5 percent of Wolverine Pipe Line Company (“Wolverine”), 9.2 percent of West Shore Pipe Line Company (“West Shore”), and 14.0 percent of Yellowstone Pipe Line Company (“Yellowstone”) (see Note 14). In September 2003, the Partnership acquired an additional 3.1 percent interest in West Shore Pipe Line Company, increasing its overall ownership interest to 12.3 percent.

 

The Terminal Facilities segment includes a network of 31 refined product terminals in the Northeast and Midwest that distribute products primarily to Sunoco R&M’s retail outlets, a 12.5 million-barrel marine crude oil terminal on the Texas Gulf Coast and a one million barrel liquefied petroleum gas (“LPG”) storage facility near Detroit, MI. This segment also owns and operates one inland and two marine crude oil terminals and the related storage facilities and pipelines that supply all of the crude oil processed by Sunoco R&M’s Philadelphia refinery. Finally, this segment includes a two million barrel refined product storage terminal in Marcus Hook, PA that is used by Sunoco R&M’s Marcus Hook refinery to source barrels to the Partnership’s pipelines.

 

The Western Pipeline System acquires, transports and markets crude oil principally in Oklahoma and Texas for Sunoco R&M’s Tulsa, OK and Toledo, OH refineries and also for other customers. During November 2002, the Partnership acquired a 43.8 percent equity ownership interest in West Texas Gulf Pipe Line Company (“West Texas Gulf”), a crude oil pipeline company located in Texas (see Note 14), from Sunoco.

 

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SUNOCO LOGISTICS PARTNERS L.P.

 

NOTES TO FINANCIAL STATEMENTS—(Continued)

 

Use of Estimates

 

The preparation of financial statements in conformity with accounting principles generally accepted in the United States 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

 

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. Such amounts are not deemed to be material. 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.

 

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 R&M. Sales of crude oil to affiliates are computed using the formula-based pricing mechanism of a supply agreement with Sunoco R&M. Management of the Partnership believes these terms to be comparable to those that could be negotiated with an unrelated third party. Pipeline revenues from affiliates are generally determined using posted tariffs. Prior to January 1, 2002, affiliated revenues from terminalling and storage were generally equal to all of the costs incurred for these activities, including operating, maintenance and environmental remediation expenditures. Concurrent with the closing of the IPO, the Partnership entered into a pipelines and terminals storage and throughput agreement with Sunoco R&M under which the Partnership is charging Sunoco R&M fees for services provided under these agreements comparable to those charged in arm’s-length, third-party transactions. Under the pipelines and terminals storage and throughput agreement, Sunoco R&M has agreed to pay the Partnership a minimum level of revenue for transporting and terminalling refined products. Sunoco R&M also has agreed to minimum throughputs of refined products and crude oil in the Partnership’s Inkster Terminal, Fort Mifflin Terminal Complex, Marcus Hook Tank Farm and certain crude oil pipelines. Fee arrangements consistent with this contract, generally effective January 1, 2002, were used as the basis for the transfer prices used in the preparation of Sunoco’s segment information. Accordingly, such fees are generally reflected in the financial statements beginning on January 1, 2002.

 

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. These cash equivalents consist principally of money market accounts.

 

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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. The following shows the activity in the allowance for doubtful accounts for the three-year period ended December 31, 2003:

 

     Predecessor

  

Partnership

and
Predecessor


   Partnership

     2001

   2002

   2003

Balance at January 1

   $         —      $         —      $         500

Amounts charged to expense

     —        500      —  
    

  

  

Balance at December 31

   $ —      $ 500    $ 500
    

  

  

 

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. 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. Prior to February 8, 2002, the IPO date, crude oil inventory amounts reflected an allocation to the Predecessor by Sunoco R&M of the Predecessor’s share of Sunoco R&M’s crude oil inventory, the cost of which has been determined under the LIFO method. The cost of materials, supplies and other inventories is determined using principally the average cost method.

 

Properties, Plants and Equipment

 

Properties, plants and equipment are stated at cost. Additions to properties, plants and equipment, including replacements and improvements, are recorded at cost. Repair and maintenance expenditures are charged to expense as incurred. Depreciation is provided principally using the straight-line method based on the estimated useful lives of the related assets. For certain interstate pipelines, the depreciation rate is applied to the net asset value based on FERC requirements. When FERC-regulated property, plant and equipment is retired or otherwise disposed of, the cost less net proceeds is charged to accumulated depreciation and amortization, except that gains and losses for those groups are reflected in other income in the statements of income for unusual disposals. Gains and losses on the disposal of non-FERC properties, plants and equipment are reflected in other income in the statements of income.

 

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. The weighted average rate used to capitalize interest on borrowed funds was 7.8 percent, 7.3 percent, and 7.3 percent for 2001, 2002, and 2003, respectively. During the years ended December 31, 2001, 2002 and 2003, the amount of interest capitalized was $1.1 million, $1.3 million, and $0.5 million, respectively.

 

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SUNOCO LOGISTICS PARTNERS L.P.

 

NOTES TO FINANCIAL STATEMENTS—(Continued)

 

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 fair market value of the impaired asset. Long-lived assets held for sale are recorded at the lower of their carrying amount or fair market value less cost to sell the assets. Effective January 1, 2002, the Partnership adopted Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” (“SFAS No. 144) which, among other things, changed the criteria that would have to be met to classify an asset as held for sale. SFAS No. 144 had no impact on the Partnership’s financial statements during 2002 and 2003.

 

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. At December 31, 2002 and 2003, the Partnership had $16.2 million of unamortized goodwill.

 

Effective January 1, 2002, Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”), was adopted. SFAS No. 142 requires the testing of goodwill and indefinite-lived intangible assets for impairment rather than amortizing them. The Partnership ceased amortizing goodwill and indefinite-lived intangible assets effective January 1, 2002 and determined during 2002 and 2003 that such assets were not impaired. Prior to January 1, 2002, goodwill and indefinite-lived intangible assets were amortized on a straight-line basis over their estimated useful lives. The following table sets forth the reconciliation of net income as reported to net income as adjusted to exclude amortization of goodwill and indefinite-lived intangible assets for the year ended December 31, 2001 (in thousands of dollars):

 

     Predecessor

     Year Ended
December 31, 2001


Net income, as reported

   $             26,767
    

Add back:

      

goodwill amortization

     586

indefinite-lived intangible asset amortization

     300
    

Net income, as adjusted

   $ 27,653
    

 

Deferred financing fees of $3.1 million, net of accumulated amortization of $0.4 million, as of December 31, 2002 and $2.7 million, net of accumulated amortization of $1.0 million, as of December 31, 2003 were included within deferred charges and other assets on the balance sheets. Amortization expense of $0.4 million and $0.6 million for the years ended December 31, 2002 and 2003, respectively, was 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.

 

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

 

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SUNOCO LOGISTICS PARTNERS L.P.

 

NOTES TO FINANCIAL STATEMENTS—(Continued)

 

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, and reduced for dividends received. The Partnership had $0.8 million of undistributed earnings from its investments in corporate joint ventures within Partner’s Capital on its December 31, 2003 balance sheet.

 

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, were amortized using the straight-line method over their estimated useful life of 40 years. The amortization of these amounts are included within depreciation and amortization in the statements of income.

 

Environmental Remediation

 

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

 

Income Taxes

 

For the period prior to the IPO, the Predecessor is included in the consolidated federal income tax return filed by Sunoco. However, the provision for federal income taxes included in the statements of income and the deferred tax amounts reflected in the balance sheet have been determined on a separate-return basis. Any current federal income tax amounts due on a separate-return basis were settled with Sunoco through the net parent investment account. Effective upon the closing date of the IPO, substantially all income taxes are the responsibility of the unitholders and not the Partnership.

 

Long Term Incentive Plan

 

The Partnership follows Statement of Financial Accounting Standards No. 123 (“SFAS 123”) “Accounting for Stock-Based Compensation,” which provides for the recognition of compensation expense for stock-based compensation arrangements based on the fair value of the equity instrument (see Note 13).

 

Asset Retirement Obligations

 

Effective January 1, 2003, the Partnership adopted the provisions of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”). This statement significantly changed the method of accruing for costs that an entity is legally obligated to incur associated with the retirement of fixed assets. Under SFAS No. 143, the fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the fixed asset and depreciated over its estimated useful life. Prior to January 1, 2003, a liability for an asset retirement obligation was recognized using a cost-accumulation measurement approach. The cumulative effect of this accounting change for years prior to 2003 of $0.4 million was included in cost of products sold and operating expenses in the statement of income for the year ended December 31, 2003. The Partnership did not reflect the amount as a cumulative effect of an accounting change as it was not material to the financial statements. Other than the

 

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SUNOCO LOGISTICS PARTNERS L.P.

 

NOTES TO FINANCIAL STATEMENTS—(Continued)

 

cumulative effect, this change did not have a significant impact on the Partnership’s statement of income for the year ended December 31, 2003. At December 31, 2003, the Partnership’s liability for asset retirement obligations was $0.6 million. The Partnership has legal asset retirement obligations for several other assets, including certain pipelines and terminals, for which it is not possible to estimate the time period when the obligations will be settled. Consequently, the fair value of the retirement obligations for these assets cannot be measured and recognized at this time.

 

Exit or Disposal Activities

 

Effective January 1, 2003, the Partnership adopted the provisions of Statement of Financial Accounting Standards No. 146, “Accounting for Costs Associated with Exit or Disposal Activities” (“SFAS No. 146”). This statement superseded Emerging Issues Task Force (“EITF”) Issue No. 94-3, “Liability Recognition for Certain Employee Terminal Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred. SFAS No. 146 also establishes fair value as the objective for initial measurement of the liability. The provisions of SFAS No. 146 are effective for exit or disposal activities that are initiated after December 31, 2002. Under prior accounting principles, certain costs associated with restructuring plans were recognized as of the date of commitment. SFAS No. 146 only applies to prospective activities, and it had no impact on the Partnership’s financial position or results of operations for the year ended December 31, 2003.

 

Guarantees

 

Effective January 1, 2003, the Partnership adopted the provisions of Financial Accounting Standards Board Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (“FASB Interpretation No. 45”). The accounting recognition provisions of FASB Interpretation No. 45 are effective January 1, 2003 on a prospective basis. They require that a guarantor recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. Under prior accounting principles, a guarantee was not recognized as a liability until a loss was probable and reasonably estimable. FASB Interpretation No. 45 had no impact on the Partnership’s financial position or results of operations for the year ended December 31, 2003.

 

New Accounting Principles

 

In January 2003, FASB Interpretation No. 46, “Consolidation of Variable Interest Entities” (“FASB Interpretation No. 46”), was issued. Among other things, FASB Interpretation No. 46 defines a variable interest entity (“VIE”) as an entity that either has investor voting rights that are not proportional to their economic interests or has equity investors that do not provide sufficient financial resources for the entity to support its activities. FASB Interpretation No. 46 requires a VIE to be consolidated by an entity if that entity is the primary beneficiary. The primary beneficiary is the entity that is subject to a majority of the risk of loss from the VIE’s activities or, if no entity is subject to a majority of such risk, the entity that is entitled to receive a majority of the VIE’s residual returns. The Partnership intends to adopt FASB Interpretation No. 46 effective January 1, 2004. FASB Interpretation No. 46 is not expected to have an impact on the Partnership’s financial statements upon adoption.

 

Effective July 1, 2003, the Partnership adopted 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 Statement of

 

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SUNOCO LOGISTICS PARTNERS L.P.

 

NOTES TO FINANCIAL STATEMENTS—(Continued)

 

Financial Accounting Standards 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 reported as transportation and storage services might have to be reported as rental or leasing income. 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. Previous arrangements that would be leases or would contain a lease according to this pronouncement will continue to be recorded in accordance with their prior accounting treatment. The Partnership is currently 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 impact on the Partnership’s financial statements for the year ended December 31, 2003.

 

Reclassifications

 

Certain amounts in the prior years’ financial statements have been reclassified to conform to the current year presentation.

 

2. The Initial Public Offering

 

On February 8, 2002, Sunoco, through its subsidiary, Sunoco Partners LLC, the general partner of the Partnership, contributed the Predecessor to the Partnership in exchange for: (i) a 2 percent general partner interest in the Partnership; (ii) incentive distribution rights (as defined in the Partnership Agreement); (iii) 5,633,639 common units; (iv) 11,383,639 subordinated units; and (v) a special interest representing the right to receive from the Partnership, on the closing of the IPO, the net proceeds from the issuance of $250 million of ten-year senior notes (the “Senior Notes”) by Sunoco Logistics Partners Operations L.P., a wholly-owned subsidiary of the Partnership (the “Operating Partnership”), which totaled $244.8 million. The Partnership concurrently issued 5,750,000 common units (including 750,000 units issued pursuant to the underwriters’ over-allotment option), representing a 24.8 percent limited partnership interest in the Partnership, in an IPO at a price of $20.25 per unit. Proceeds from the IPO, which totaled $96.5 million net of underwriting discounts and offering expenses, were used by the Partnership to provide working capital that was not contributed to the Partnership by Sunoco.

 

3. Related Party Transactions

 

Prior to the IPO, substantially all of the related party transactions discussed below were settled immediately through the net parent investment account. Subsequent to the IPO, normal trade terms apply to transactions with Sunoco as described in various agreements discussed below which were entered into concurrent with the IPO.

 

Advances to Affiliate

 

The Partnership entered into a treasury services agreement with Sunoco at the closing of the IPO 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 Partnership’s revolving credit facility (see Note 10).

 

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SUNOCO LOGISTICS PARTNERS L.P.

 

NOTES TO FINANCIAL STATEMENTS—(Continued)

 

Selling, general and administrative expenses in the statements of income include costs incurred by Sunoco for the provision of centralized corporate functions such as legal, accounting, treasury, engineering, information technology, insurance and other corporate services. Prior to the closing of the IPO, such expenses were based on amounts negotiated between the parties, which approximated Sunoco’s cost of providing such services. Under an omnibus agreement (“Omnibus Agreement”) with Sunoco that the Partnership entered into at the closing of the IPO, Sunoco provides these centralized corporate functions for three years for an annual administrative fee, which may be increased annually by the lesser of 2.5 percent or the consumer price index for the applicable year. The fee for the annual period ended December 31, 2003 was $8.2 million. These costs may also increase if the Partnership consummates an acquisition or constructs additional assets that require an increase in the level of general and administrative services received by the Partnership from the general partner or Sunoco. The annual fee includes expenses incurred by Sunoco to perform the centralized corporate functions described above. This fee does not include the costs of shared insurance programs, which are allocated to the Partnership based upon its share of the premiums incurred. This fee also does not include 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 is reimbursing Sunoco for these costs and other direct expenses incurred on the Partnership’s behalf. Selling, general and administrative expenses in the statements of income include costs related to the provision of these centralized corporate functions and allocation of shared insurance costs of $10.8 million, $10.2 million and $10.9 million for the years ended December 31, 2001, 2002 and 2003, respectively.

 

The Partnership entered into a license agreement at the closing of the IPO with Sunoco and certain of its affiliates, including its general partner, Sunoco Partners LLC, pursuant to which the Partnership granted to Sunoco Partners LLC a license to the Partnership’s intellectual property so that Sunoco Partners LLC can manage the Partnership’s operations and create intellectual property using the Partnership’s intellectual property. Sunoco Partners LLC will assign to the Partnership the new intellectual property it creates in operating the Partnership’s business. Sunoco Partners LLC has also licensed to the Partnership certain of its own intellectual property for use in the conduct of the Partnership’s business and the Partnership licensed to Sunoco Partners LLC certain of the Partnership’s intellectual property for use in the conduct of its business. The license agreement also grants to the Partnership a license to use the trademarks, trade names, and service marks of Sunoco in the conduct of the Partnership’s business.

 

Allocated Sunoco employee benefit plan expenses for employees who work in the pipeline, terminalling, storage and crude oil gathering operations, including senior executives, include 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. The Partnership’s and Predecessor’s share of allocated Sunoco employee benefit plan expenses was $19.6 million, $19.6 million and $20.6 million for the years ended December 31, 2001, 2002 and 2003, respectively. These expenses are reflected in cost of products sold and operating expenses and selling, general and administrative expenses in the statements of income. In connection with the transfer of the Predecessor’s operations to the Partnership, these employees, including senior executives, became employees of the Partnership’s general partner or its affiliates, wholly-owned subsidiaries of Sunoco. The Partnership has no employees.

 

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 R&M. Sales of crude oil are computed using the formula-based pricing mechanism of a supply agreement with Sunoco R&M. Management of the Partnership believes these terms to be comparable to those that could be negotiated with an unrelated third party. Pipeline revenues are generally determined using posted tariffs. Prior to January 1, 2002, revenues from terminalling and storage were generally equal to all of the costs incurred for these activities,

 

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including operating, maintenance and environmental remediation expenditures. Concurrent with the closing of the IPO, the Partnership entered into a pipelines and terminals storage and throughput agreement and various other agreements with Sunoco R&M under which the Partnership is charging Sunoco R&M fees for services provided under these agreements comparable to those charged in arm’s-length, third-party transactions. Under the pipelines and terminals storage and throughput agreement, Sunoco R&M has agreed to pay the Partnership a minimum level of revenues for transporting and terminalling refined products. Sunoco R&M also has agreed to minimum throughputs of refined products and crude oil in the Partnership’s Inkster Terminal, Fort Mifflin Terminal Complex, Marcus Hook Tank Farm and certain crude oil pipelines. Effective January 1, 2002 for most terminals, fee arrangements consistent with this contract were used as the basis for the transfer prices to be used in preparation of Sunoco’s segment information. Accordingly, such fees for most terminals are reflected in the financial statements beginning on January 1, 2002.

 

Under various other agreements entered into at the closing of the IPO, Sunoco R&M 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. Sunoco R&M also leases the Partnership’s 58 miles of interrefinery pipelines between Sunoco R&M’s Philadelphia and Marcus Hook refineries for a term of 20 years.

 

Note Receivable from Affiliate

 

Effective October 1, 2000, the Predecessor loaned $20.0 million to Sunoco. The loan, which was evidenced by a note that was collected on January 1, 2002, earned interest at a rate based on the short-term applicable federal rate established by the Internal Revenue Service.

 

Short-Term Borrowings due Affiliate

 

At December 31, 2000, the Predecessor had two short-term notes totaling $45.0 million due Sunoco, which were repaid during 2001. The notes bore interest at a rate based on the short-term applicable federal rate established by the Internal Revenue Service.

 

Long-term Debt due Affiliate

 

At December 31, 2001, the Predecessor had long-term debt due to affiliate that was not assumed by the Partnership at the date of the IPO. The debt consisted of individual notes payable to Sunoco. One of the notes bore interest at a rate based on the short-term applicable federal rate established by the Internal Revenue Service, while the other notes bore interest based on the prime rate. Cash payments for interest in regards to the debt due affiliate, net of capitalized interest (see Note 1), were $12.1 million and $0.7 million in 2001 and 2002, respectively. There was no cash payment for interest on debt due to affiliate in 2003.

 

Capital Contributions

 

The Omnibus Agreement requires Sunoco R&M to: reimburse the Partnership 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 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 the Darby Creek Tank Farm to maintain compliance with existing industry standards and regulatory requirements.

 

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For the years ended December 31, 2002 and 2003, the Partnership was reimbursed $0.7 million and $1.9 million, respectively, by Sunoco R&M for maintenance capital expenditures and operating expenses incurred in excess of $8.0 million to comply with DOT’s pipeline integrity management rule. At December 31, 2003, the Partnership has received a cumulative reimbursement of $2.6 million in regard to the $15.0 million maximum reimbursement over the five-year period for compliance expenditures relative to the DOT’s pipeline integrity management rule. For the year ended December 31, 2002, the Partnership was also reimbursed $2.1 million by Sunoco R&M for certain tank maintenance and inspection expenditures at the Darby Creek Tank Farm. There were no amounts expended for these tank maintenance and inspection projects at the Darby Creek Tank Farm during 2003. For the years ended December 31, 2002 and 2003, the Partnership was reimbursed by Sunoco R&M for expenditures at the Marcus Hook Tank Farm and the Darby Creek Tank Farm to maintain compliance with existing industry standards and regulatory requirements. These expenditures, which were recorded as maintenance capital and operating expenses, were as follows:

 

     Partnership
and
Predecessor


   Partnership

     Year Ended December 31,

     2002

   2003

     (amounts in thousands)

Maintenance capital

   $         534    $       2,982

Operating expenses

     351      467
    

  

     $ 885    $ 3,449
    

  

 

At December 31, 2003, the Partnership has received a cumulative reimbursement of $4.3 million relative to the $10 million maximum reimbursement for compliance expenditures at the Marcus Hook Tank Farm and the Darby Creek Tank Farm. The aggregate amounts reimbursed related to all of the previously mentioned provisions of the Omnibus Agreement of $3.7 million and $5.3 million for the years ended December 31, 2002 and 2003, respectively, by Sunoco R&M related to these projects were recorded by the Partnership as capital contributions.

 

On November 15, 2002, the Partnership acquired an equity ownership interest in an entity for $10.6 million from Sunoco (see Note 14). Since the acquisition was from a related party, the interest in the entity was recorded by the Partnership at Sunoco’s historical cost of $11.7 million rather than the acquisition price of $10.6 million. The additional $1.1 million was recorded by the Partnership as a capital contribution.

 

4. Write-Down of Assets

 

In December 2002, the Partnership recorded a $6.3 million provision to write-down an idled refined product pipeline in the Eastern Pipeline System and a related terminal. These assets were idled as a result of a long-term agreement entered into by the Partnership in December 2002 to lease throughput capacity on a third-party refined product pipeline which allows it to provide substantially the same service as existed on the idled pipeline while reducing operating expenses. This provision was recorded within depreciation and amortization in the statements of income.

 

In December 2001, the Predecessor recorded a $1.4 million charge to write-off refined product terminal equipment. This provision was recorded within depreciation and amortization in the statements of income.

 

5. Income Taxes

 

As discussed in Note 1, substantially all income taxes are the responsibility of the unitholders and not the Partnership as of February 8, 2002 (the date of the IPO). However, prior to February 8, 2002, the Predecessor was included in the consolidated federal income tax return filed by Sunoco, prepared on a separate-return basis.

 

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The components of income tax expense are as follows (in thousands of dollars):

 

     Predecessor

     Year Ended December 31,

         2001    

       2002    

Income taxes currently payable:

             

U.S. federal

   $ 5,657    $ 841

State

     1,124      39
    

  

       6,781      880
    

  

Deferred taxes:

             

U.S. federal

     7,352      616

State

     1,461      59
    

  

       8,813      675
    

  

     $ 15,594    $ 1,555
    

  

 

The reconciliation of income tax expense at the U.S. statutory rate to income tax expense is as follows (in thousands of dollars):

 

     Predecessor

 
     Year Ended December 31,

 
         2001    

        2002    

 

Income tax expense at the U.S. statutory rate of 35 percent

   $ 14,826     $ 1,742 (1)

Increase (reduction) in income taxes resulting from:

                

State income taxes net of Federal income tax effects

     1,680       64  

Dividend exclusion for joint venture pipeline operations

     (1,059 )     (262 )

Other

     147       11  
    


 


     $ 15,594     $ 1,555  
    


 



(1) Based upon income for the period from January 1, 2002 through February 7, 2002, the date prior to the IPO.

 

Cash payments for income taxes (including amounts paid to Sunoco) amounted to $6.2 million and $0.1 million in 2001 and 2002, respectively.

 

6. Net Income Per Unit Data

 

The computation of basic net income per limited partner unit is calculated by dividing net income, after the deduction of the general partner’s interest in net income, by the weighted-average number of common and subordinated units outstanding during the year. The general partner’s interest in net income is calculated on a quarterly basis based upon its percentage interest in quarterly cash distributions declared. The general partner’s interest in quarterly cash distributions consists of its 2.0 percent general 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 15). The general partner was allocated net income of $1.4 million (representing 2.4 percent of total net income for the period) for the year ended December 31, 2003 and $0.9 million (representing 2.0 percent of total net income for the period) for the period from February 8, 2002 to December 31, 2002. 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 13), as calculated by the treasury stock method.

 

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Prior to the closing of the Partnership’s IPO on February 8, 2002, there were no limited partner units outstanding. As such, net income per limited partner unit is not presented for the year ended December 31, 2001 and for the 38-day period from January 1, 2002 to February 7, 2002. 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 period from February 8, 2002 to December 31, 2002 and the year ended December 31, 2003:

 

     Partnership

     December 31,

     2002

   2003

Weighted average number of limited partner units outstanding—basic

   22,767,899    22,771,793

Add effect of dilutive unit incentive awards

   17,508    122,727
    
  

Weighted average number of limited partner units—diluted

   22,785,407    22,894,520
    
  

 

7. Inventories

 

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

 

     Partnership

     December 31,

     2002

   2003

Crude oil

   $ 24,641    $ 26,543

Materials, supplies and other

     1,103      725
    

  

     $ 25,744    $ 27,268
    

  

 

The current replacement cost of crude oil inventory exceeded its carrying value by $33.5 million and $38.1 million at December 31, 2002 and 2003, respectively. During 2002, the Partnership reduced crude oil inventory quantities, which were valued at lower LIFO costs prevailing in prior years. The effect of this reduction in inventory was to increase 2002 net income by $1.5 million.

 

8. Properties, Plants and Equipment

 

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

 

    

Estimated
Useful
Lives


   Partnership

 
        December 31,

 
        2002

    2003

 

Land and land improvements (including rights of way)

   —      $ 48,310     $ 49,425  

Pipeline and related assets

   38 - 60      493,887       510,670  

Terminals and storage facilities

   5 - 44      324,506       345,950  

Other

   5 - 48      73,512       75,674  

Construction-in-progress

   —        32,284       24,026  
         


 


            972,499       1,005,745  

Less: Accumulated depreciation and amortization

          (398,985 )     (422,581 )
         


 


          $ 573,514     $ 583,164  
         


 


 

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9. Investment in Affiliates

 

The Partnership’s ownership percentages in joint ventures are as follows:

 

     Partnership

 
     December 31,

 
       2002  

      2003  

 

Explorer Pipeline Company

   9.4 %   9.4 %

Wolverine Pipe Line Company

   31.5 %   31.5 %

West Shore Pipe Line Company

   9.2 %   12.3 %

Yellowstone Pipe Line Company

   14.0 %   14.0 %

West Texas Gulf Pipe Line Company

   43.8 %   43.8 %

 

The following table provides summarized financial information on a 100 percent basis for the Partnership’s equity ownership interests. The results of Wolverine, West Shore, Yellowstone and West Texas Gulf have been included from their dates of acquisition (see Note 14) (in thousands of dollars):

 

     Predecessor

   Predecessor
and
Partnership


   Partnership

     2001

   2002

   2003

Income Statement Data:

                    

Total revenues

   $ 178,082    $ 213,609    $ 345,840

Income before income taxes

   $ 80,047    $ 106,234    $ 156,788

Net income

   $ 50,610    $ 70,447    $ 96,712

Balance Sheet Data (as of year-end):

                    

Current assets

   $ 44,075    $ 100,132    $ 90,291

Non-current assets

   $ 132,327    $ 441,720    $ 477,467

Current liabilities

   $ 20,976    $ 70,404    $ 87,199

Non-current liabilities

   $ 149,407    $ 419,563    $ 423,763

Net equity

   $ 6,019    $ 51,885    $ 56,796

 

The Partnership’s investments in Wolverine, West Shore, Yellowstone, and West Texas Gulf at December 31, 2003 include an excess investment amount of approximately $56.7 million, net of accumulated amortization of $0.7 million. The excess investment is the difference between the investment balance and the Partnership’s proportionate share of the net assets of the entities. The excess investment was allocated to the underlying tangible and intangible assets. Other than land and indefinite-lived intangible assets, all amounts allocated, principally to pipeline and related assets, were amortized using the straight-line method over their estimated useful life of 40 years and included within depreciation and amortization in the statements of income.

 

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10. Long-Term Debt

 

The components of long-term debt (including current portion) are as follows (in thousands of dollars):

 

     Partnership

 
     December 31,

 
     2002

    2003

 

Credit Facility

   $ 64,500     $ 64,500  

Senior Notes

     250,000       250,000  

Less unamortized bond discount

     (1,533 )     (1,364 )

Other (including current portion)

     4,478       —    
    


 


       317,445       313,136  

Less current portion

     (303 )     —    
    


 


     $ 317,142     $ 313,136  
    


 


 

In conjunction with the IPO, the Operating Partnership issued $250.0 million of ten-year, 7.25 percent Senior Notes at 99.325 percent of the principal amount and established a revolving credit facility that matures January 2005 (the “Credit Facility”). The Senior Notes are redeemable, at a make-whole premium, and are not subject to sinking fund provisions. The 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, 2003. In addition, the 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. The Operating Partnership distributed the net proceeds of $244.8 million after offering commissions and issuance expenses from the sale of the outstanding Senior Notes to the Partnership for distribution to Sunoco.

 

On April 11, 2002, the Operating Partnership filed an exchange offer registration statement on SEC Form S-4, in connection with the registration of the exchange of the Senior Notes and the guarantees covering the Senior Notes. This registration statement was declared effective on June 28, 2002. The exchange offer was completed on August 2, 2002, with all $250 million aggregate principal amount of the Senior Notes being exchanged for a like principal amount of new publicly tradable notes having substantially identical terms issued pursuant to the exchange offer registration statement filed under the Securities Act of 1933, as amended.

 

The Credit Facility, which currently has an aggregate committed sum of $250 million, is available to fund the Operating Partnership’s working capital requirements, to finance future acquisitions and for general partnership purposes. It may also be used to fund the quarterly distribution to a maximum of $20.0 million. Borrowing under this distribution sublimit must be reduced to zero each year for a 15-day period. The Credit Facility bears interest at the Operating Partnership’s option, at either (i) LIBOR plus an applicable margin or (ii) the higher of the federal funds rate plus 0.50 percent or the Bank of America prime rate (each plus the applicable margin). The interest rate on the outstanding borrowings at December 31, 2003 was 1.85 percent. The Credit Facility may be prepaid at any time. The 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 Credit Facility also contains covenants requiring the Operating Partnership to maintain, on a rolling four-quarter basis, a maximum total debt to EBITDA ratio (each as defined in the credit agreement) of 4.0 to 1; and an interest

 

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coverage ratio (as defined in the credit agreement) of at least 3.5 to 1. The Operating Partnership is in compliance with these covenants as of December 31, 2003. The Partnership’s ratio of total debt to EBITDA was 3.0 to 1 and the interest coverage ratio was 5.1 to 1 for the year ended December 31, 2003.

 

The Partnership and the operating subsidiaries of the Operating Partnership serve as joint and several guarantors of the Senior Notes and of any obligations under the Credit Facility. The guarantees are full and unconditional.

 

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 subsidiaries, deferred charges, and cash and cash equivalents of $50.1 million. Except for amounts associated with the Senior Notes, the Credit Facility, 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 subsidiaries.

 

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

 

Year Ended December 31:


    

2005

   $ 64,500

2012

     250,000
    

     $    314,500
    

 

Cash payments for interest related to long-term debt, net of capitalized interest (see Note 1), were $0.4 million, $8.6 million and $19.3 million in 2001, 2002 and 2003, respectively.

 

11. Commitments and Contingent Liabilities

 

The Partnership, as lessee, has noncancelable operating leases for land, office space and equipment. Total rental expense for 2001, 2002 and 2003 amounted to $3.7 million, $3.1 million and $4.5 million, respectively.

 

The aggregate amount of future minimum annual rentals as of December 31, 2003 applicable to noncancelable operating leases is as follows (in thousands of dollars):

 

Year Ended December 31:


    

2004

   $ 2,785

2005

     2,152

2006

     1,772

2007

     1,437

2008

     1,318

Thereafter

     6,573
    

Total

   $      16,037
    

 

As part of the agreement to purchase Wolverine in November 2002 (see Note 14), the Partnership agreed to assume participation in an agreement along with the other owners of Wolverine to guarantee certain outstanding debt instruments of Wolverine based upon ownership percentage. Based upon outstanding indebtedness of these instruments of approximately $6.4 million at December 31, 2003, the approximate value of the guarantee is $2.0 million.

 

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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, 2002 and 2003, there were accrued liabilities for environmental remediation in the balance sheets of $0.5 million for each period. The accrued liabilities for environmental remediation does not include any amounts attributable to unasserted claims, nor have any recoveries from insurance been assumed. Pretax charges against income for environmental remediation totaled $6.2 million, $1.2 million and $1.2 million for the years ended December 31, 2001, 2002 and 2003, 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 impacted by an indemnification from Sunoco.

 

The Predecessor 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 Predecessor. Management does not believe that any liabilities which may arise from such claims and the environmental matters discussed above would be material in relation to the financial position of the Partnership at December 31, 2003. 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, 2003.

 

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12. Net Parent Investment

 

The Predecessor’s net parent investment account represented a net balance resulting from the settlement of intercompany transactions (including federal income taxes) between the Predecessor and Sunoco as well as Sunoco’s ownership interest in the net assets of the Predecessor. It also reflects the Predecessor’s participation in Sunoco’s central cash management program, wherein all of the Predecessor’s cash receipts were remitted to Sunoco and all cash disbursements were funded by Sunoco. There were no terms of settlement or interest charges attributable to this balance. The Predecessor’s net parent investment account excludes amounts loaned to/borrowed from Sunoco evidenced by interest-bearing notes.

 

In connection with the contribution of the Predecessor to the Partnership on February 8, 2002, Sunoco retained certain assets and liabilities. The following table summarizes the carrying amount of the assets and liabilities which were not contributed by Sunoco (in thousands of dollars):

 

Account receivable

   $ 2,446

Inventories

     6,989

Deferred income taxes

     2,821

Properties, plants and equipment, net

     1,482

Other deferred charges

     1,464
    

       15,202
    

Accounts payable

     4,152

Accrued liabilities

     10,714

Taxes payable

     14,072

Long-term debt due affiliate

     90,000

Deferred income taxes

     78,815

Other deferred credits and liabilities

     8,336
    

       206,089
    

Net liabilities retained by Sunoco

   $    190,887
    

 

13. 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. LTIP awards may consist of either restricted units or unit options. 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

 

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NOTES TO FINANCIAL STATEMENTS—(Continued)

 

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 (“DER”) with respect to the restricted units. 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.

 

For the years ended December 31, 2002 and 2003, 185,625 and 62,200 restricted units, respectively, along with tandem distribution equivalent rights were granted to employees of the general partner and will vest at the end of three-year periods based upon attainment of certain predetermined performance targets. The weighted average price for the restricted unit awards at the dates of grant was $19.87 for the 2002 grants and $24.94 for the 2003 grants. The Partnership recognized non-cash compensation expense of $0.7 million and $2.2 million for the years ended December 31, 2002 and 2003, respectively, related to these grants.

 

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, 2002 and 2003, and there are no unit options outstanding as of December 31, 2003. 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. Upon exercise of a unit option, the general partner will deliver common units acquired by it in the open market, purchased directly from the Partnership or any other person, use common units already owned by the general partner, or any combination of the foregoing. The general partner will be entitled to reimbursement by the Partnership for the difference between the cost incurred by the general partner in acquiring such common units and the proceeds received by the general partner from an optionee at the time of exercise. Thus, the cost of the unit options will be born by the Partnership. If the Partnership issues new common units upon exercise of the unit options, the total number of common units outstanding will increase, and the general partner will remit to the Partnership the proceeds received by it from the optionee upon exercise of the unit option.

 

The Partnership follows SFAS 123 (as discussed in Note 1) and has recognized compensation expense related to the restricted units granted based on the fair value method.

 

14. Acquisitions

 

On September 30, 2003, the Partnership acquired an additional 3.1 percent interest in West Shore, a Midwestern United States products pipeline company, for $3.7 million. The acquisition of this additional interest raised the Partnership’s overall ownership percentage in West Shore from 9.2 percent to 12.3 percent.

 

On November 15, 2002, the Partnership acquired a company whose assets included equity ownership interests in three Midwestern and Western United States products pipeline companies, consisting of a 31.5 percent interest in Wolverine, a 9.2 percent interest in West Shore, and a 14.0 percent interest in Yellowstone, for an aggregate purchase price of $54.0 million. The purchase price for this acquisition was funded through borrowings under the Partnership’s Credit Facility (see Note 10). The Partnership’s share of income from these joint ventures has been included in other income in the statements of income from the acquisition date. This investment was included within investment in affiliates in the balance sheets.

 

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On November 15, 2002, the Partnership acquired a 43.8 percent equity ownership interest in West Texas Gulf, a Texas crude oil pipeline, for an aggregate purchase price of $10.6 million from Sunoco. Consideration paid to Sunoco for the acquisition included $10.5 million in cash and 4,515 Partnership common units with a value of $0.1 million at the date of the transaction. Since the acquisition was from a related party, the interest in West Texas Gulf was recorded by the Partnership at Sunoco’s historical cost of $11.7 million. The additional $1.1 million was reflected as a capital contribution in the balance sheet. The cash component of the consideration for this acquisition was principally financed through borrowings under the Partnership’s Credit Facility. The Partnership’s share of income from this joint venture has been included in other income in the statements of income from the acquisition date. The investment was included within investment in affiliates in the balance sheets.

 

The following unaudited pro forma data is presented to show pro forma revenues, net income and basic and diluted net income per limited partner unit for the Partnership as if the acquisitions had occurred on January 1, 2001 (in thousands except per unit amounts):

 

     Predecessor

   Partnership
And
Predecessor


   Partnership

     Year Ended December 31,

     2001

   2002

   2003

Total revenues

   $ 1,623,005    $ 1,838,210    $ 2,674,525

Net income

   $ 28,795    $ 52,111    $ 59,655

Net income per Limited Partner unit (2002 is for the period from February 8 through December 31, 2002):

                    

Basic

          $ 2.06    $ 2.56

Diluted

          $ 2.05    $ 2.54

 

Pro forma net income utilized for pro forma net income per limited partner unit calculation purposes for the period from February 8, 2002 to December 31, 2002 and the year ended December 31, 2003 was $46.8 million and $58.2 million, respectively, after reduction for the general partner’s interest in net income. Prior to the closing of the Partnership’s IPO on February 8, 2002, there were no limited partner units outstanding and, as such, net income per limited partner unit is not presented for the year ended December 31, 2001 and for the 38 day period from January 1, 2002 to February 7, 2002.

 

15. Cash Distributions

 

The Partnership distributes all cash on hand within 45 days after the end of each 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 has 11,383,639 subordinated units issued, all of which are held by the general partner and for which there is no established public trading market. During the subordination period the Partnership will, in general, pay cash distributions each quarter in the following manner:

 

  First, 98 percent to the holders of common units and 2 percent to the general partner, until each common unit has received a minimum quarterly distribution of $0.45, plus any arrearages from prior quarters;

 

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  Second, 98 percent to the holders of subordinated units and 2 percent to the general partner, until each subordinated unit has received a minimum quarterly distribution of $0.45; and

 

  Thereafter, in the manner described in the table below.

 

The subordination period is generally defined as the period that ends on the first day of any quarter beginning after December 31, 2006 if (1) the Partnership has distributed at least the minimum quarterly distribution on all outstanding units with respect to each of the immediately preceding three consecutive, non-overlapping four quarter periods; and (2) the adjusted operating surplus, as defined in the partnership agreement, during such periods equals or exceeds the amount that would have been sufficient to enable the Partnership to distribute the minimum quarterly distribution on all outstanding units on a fully diluted basis and the related distribution on the 2 percent general partner interest during those periods. The Partnership has met the minimum quarterly distribution requirements on all outstanding units for each of the four quarter periods in 2002 and 2003. In addition, one-quarter of the subordinated units may convert to common units on a one-for-one basis after December 31, 2004, and one-quarter of the subordinated units may convert to common units on a one-for-one basis after December 31, 2005, if the Partnership meets the tests set forth in the partnership agreement. If the subordination period ends, the rights of the holders of subordinated units will no longer be subordinated to the rights of the holders of common units and the subordinated units may be converted into common units.

 

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

 

  First, 98 percent to all unitholders, pro rata, and 2 percent to the general partner, until the Partnership distributes for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

 

  Thereafter, as described in the paragraph and table below.

 

As presented in the table below, 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 below 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 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.

 

Quarterly Cash Distribution 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%

 

There is no guarantee that the Partnership will pay the minimum quarterly distribution on the common units in any quarter, and the Partnership will be prohibited from making any distributions to unitholders if it would cause an event of default, or if an event of default is existing, under the Credit Facility or the Senior Notes.

 

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Distributions paid by the Partnership for the period from February 8, 2002, the closing date of the IPO, through December 31, 2003 were as follows:

 

Date Cash

Distribution Paid


   Per Unit Cash
Distribution
Amount


   Annualized
Per Unit Cash
Distribution
Amount


   Total Cash
Distribution
to the Limited
Partners


   Total Cash
Distribution
To the General
Partner


               ($ in millions)    ($ in millions)

May 15, 2002

   $ 0.26    $     1.80    $ 5.9    $       0.1

August 14, 2002

   $ 0.45    $ 1.80    $     10.3    $ 0.2

November 14, 2002

   $ 0.45    $ 1.80    $ 10.3    $ 0.2

February 14, 2003

   $ 0.4875    $ 1.95    $