Form 10-K
Table of Contents

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, 2005

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.)

Mellon Bank Center

1735 Market Street, Suite LL, Philadelphia, PA

  19103-7583
(Address of principal executive offices)   (Zip Code)

 

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

 


 

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

 

Title of each class


 

Name of each exchange
on which registered


Common Units representing limited
partnership interests
  New York Stock Exchange
Senior Notes 7.25%, due February 15, 2012   New York Stock Exchange

 

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

 


 

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Exchange Act.    Yes    ¨    No    x

 

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act.    Yes    ¨     No     x

 

Indicate by check mark whether the Registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes    x    No    ¨

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment of this Form 10-K.    ¨

 

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

 

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

 

The aggregate value of the Common Units held by non-affiliates of the registrant (treating all executive officers and directors of the registrant and holders of 10 percent or more of the Common Units outstanding (including the General Partner of the registrant, Sunoco Partners LLC, as if they may be affiliates of the registrant)) was approximately $457.6 million as of June 30, 2005, based on $37.88 per unit, the closing price of the Common Units as reported on the New York Stock Exchange on that date.

 

At February 28, 2006, the number of the registrant’s Common Units outstanding was 20,164,051, and its Subordinated Units outstanding was 5,691,819.

 

DOCUMENTS INCORPORATED BY REFERENCE: NONE



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TABLE OF CONTENTS

 

PART I

   1
    ITEM 1.   

BUSINESS

   1
    ITEM 1A.   

RISK FACTORS

   20
    ITEM 1B.   

UNRESOLVED STAFF COMMENTS

   31
    ITEM 2.   

PROPERTIES

   31
    ITEM 3.   

LEGAL PROCEEDINGS

   31
    ITEM 4.   

SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS

   31

PART II

   32
    ITEM 5.   

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SECURITYHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

   32
    ITEM 6.   

SELECTED FINANCIAL DATA

   33
    ITEM 7.   

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

   37
    ITEM 7A.   

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

   60
    ITEM 8.   

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

   60
    ITEM 9.   

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

   99
    ITEM 9A.   

CONTROLS AND PROCEDURES

   99
    ITEM 9B.   

OTHER INFORMATION

   99

PART III

   100
   

ITEM 10.

  

DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

   100
   

ITEM 11.

  

EXECUTIVE COMPENSATION

   104
   

ITEM 12.

  

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

   111
   

ITEM 13.

  

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

   114
   

ITEM 14.

  

PRINCIPAL ACCOUNTING FEES AND SERVICES

   116

PART IV

   117
   

ITEM 15.

  

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

   117


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Forward-Looking Statements

 

Certain matters discussed in this report, excluding historical information, include “forward-looking” statements. Forward-looking statements discuss Sunoco Logistics Partners L.P.’s (the “Partnership”) goals, intentions and expectations as to future trends, plans, events, results of operations or financial condition, or state other information relating to it, based on the current beliefs of its management as well as assumptions made by, and information currently available to, management. Words such as “may,” “will,” “anticipate,” “believe,” “expect,” “estimate,” “intend,” “project,” and other similar phrases or expressions identify forward-looking statements. When considering forward-looking statements, investors should keep in mind the risk factors and other cautionary statements in this Annual Report.

 

Although management believes these forward-looking statements to be reasonable, they are based upon a number of assumptions, any or all of which ultimately may prove to be inaccurate. These statements are subject to numerous assumptions, uncertainties and risks that could cause actual results to differ materially from any results projected, forecasted, estimated or budgeted, including, but not limited to, the following:

 

    changes in demand for, or supply of, crude oil, refined petroleum products and natural gas liquids that impact demand for our pipeline, terminalling and storage services;

 

    changes in the demand for crude oil we both buy and sell;

 

    the loss of Sunoco R&M or another large customer or a significant reduction in its current level of throughput and storage with us;

 

    an increase in the competition encountered by our crude oil and refined products terminals, pipelines and crude oil acquisition and marketing operations;

 

    changes in the financial condition or operating results of joint ventures or other holdings in which we have an equity ownership interest;

 

    changes in the general economic conditions in the United States;

 

    changes in laws and regulations to which we are subject, including federal, state, and local tax, safety, environmental and employment laws;

 

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

 

    improvements in energy efficiency and technology resulting in reduced demand for crude oil and refined products;

 

    our ability to manage growth and control costs;

 

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

 

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

 

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

 

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

 

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

 

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

 

    delays related to construction of, or work on, new or existing facilities and issuance of applicable permits;

 

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


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    our ability to identify acquisitions under favorable terms, successfully consummate announced acquisitions or expansions and integrate them into existing business operations;

 

    risks related to labor relations and workplace safety;

 

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

 

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

 

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

 

    restrictive covenants in our or Sunoco, Inc.’s credit agreements;

 

    changes in our or Sunoco, Inc.’s credit ratings, as assigned by rating agencies;

 

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

 

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

 

    claims of our non-compliance with regulatory and statutory requirements; and

 

    the costs and effects of legal and administrative claims and proceedings against us or any entity in which we have an ownership interest, and changes in the status of, or the initiation of new litigation, claims or proceedings, to which we, or any entity in which we have an ownership interest, 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 publicly traded Delaware limited partnership formed by Sunoco, Inc. on October 15, 2001 to own, operate and acquire a geographically diverse portfolio of complementary pipeline, terminalling, and crude oil acquisition and marketing assets. The Partnership completed its initial public offering (“IPO”) on February 8, 2002. The principal executive offices of Sunoco Partners LLC, the Partnership’s general partner (the “General Partner”), are located at Mellon Bank Center, 1735 Market Street, Suite LL, Philadelphia, Pennsylvania 19103 (telephone (866) 248-4344). The Partnership’s website address is www.sunocologistics.com.

 

Sunoco, Inc., through its wholly-owned subsidiaries (collectively, “Sunoco”), owns approximately 47.9 percent of the partnership interests at December 31, 2005, including a 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 principally engaged in the transport, terminalling and storage of refined products and crude oil and the purchase and sale of crude oil in 12 states located in the Northeast, Midwest and Southwest United States. Sunoco, Inc. (R&M), a wholly-owned refining and marketing subsidiary of Sunoco (“Sunoco R&M”), accounted for approximately 44 percent of the Partnership’s total revenues for the year ended December 31, 2005. 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 1,647 miles of refined product pipelines, including a two-thirds undivided interest in the 80-mile refined product Harbor pipeline, and 58 miles of interrefinery pipelines between two of Sunoco R&M’s refineries; approximately 140 miles of crude oil pipelines; a 9.4 percent interest in Explorer Pipeline Company, a joint venture that owns a 1,413-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 655-mile refined product pipeline.

 

    The Terminal Facilities consist of 35 inland refined product terminals with an aggregate storage capacity of 5.9 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, which serve Sunoco R&M’s Philadelphia refinery; a ship and barge dock which serves Sunoco R&M’s Eagle Point refinery; and a 1.0 million barrel liquefied petroleum gas (“LPG”) terminal near Detroit, Michigan.

 

    The Western Pipeline System gathers, purchases, sells, and transports crude oil principally in Oklahoma and Texas and consists of approximately 2,197 miles of crude oil trunk pipelines, including a 37.0 percent undivided interest in the 80-mile Mesa Pipe Line system, and approximately 520 miles of crude oil gathering lines that supply the trunk pipelines; approximately 116 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.

 

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Revenues are generated by charging tariffs for transporting refined products, crude oil and other hydrocarbons through the pipelines and by charging fees for storing refined products, crude oil, and other hydrocarbons, and for providing other services at 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 commodity derivative contracts.

 

The Partnership’s primary business strategies are to generate stable cash flows, increase pipeline and terminal throughput, pursue strategic and accretive acquisitions that complement the Partnership’s existing asset base, improve operating efficiencies, and increase distributions to its unitholders.

 

For the year ended December 31, 2005, Sunoco R&M accounted for approximately 70 percent of the Eastern Pipeline segment’s total revenues, approximately 69 percent of the Terminal Facilities segment’s total revenues, and approximately 43 percent of the Western Pipeline System segment’s total revenues.

 

Eastern Pipeline System

 

Refined Product Pipelines

 

The Partnership owns and operates approximately 1,647 miles of refined product pipelines in the Northeast and Midwest United States. The refined product pipelines transport refined products from Sunoco R&M’s Philadelphia and Marcus Hook, Pennsylvania, Toledo, Ohio and Eagle Point, New Jersey refineries, as well as from third party locations, to markets in New York, New Jersey, Pennsylvania, Ohio, and Michigan. The refined products transported in these pipelines include multiple grades of gasoline, middle distillates (such as heating oil, diesel and jet fuel), liquefied petroleum gases (“LPGs”) (such as propane and butane), refining feedstocks, and other hydrocarbons. 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 Partnership also leases to Sunoco R&M three bi-directional, 18-mile interrefinery pipelines and a four-mile pipeline spur extending to the Philadelphia International Airport.

 

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 such as transfer pipelines transport large volumes over short distances and generate minimal revenues. The following excludes amounts attributable to the interrefinery pipelines and equity ownership interests in the corporate joint ventures:

 

     Year Ended December 31,

     2003

   2004

   2005

Total shipments (in thousands of barrel miles per day)

   44,657    46,284    46,144

 

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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Crude Oil Pipelines

 

The Eastern Pipeline system includes a 123-mile, 16-inch crude oil pipeline that runs from Marysville, Michigan to Toledo, Ohio. This pipeline receives crude oil from the Enbridge pipeline system for delivery to Sunoco R&M and BP refineries located in Toledo, Ohio and to Marathon’s Samaria, Michigan tank farm, which supplies its refinery in Detroit, Michigan. Marysville is also a truck injection point for local production. The Partnership is expanding the Marysville pipeline capacity by approximately 20% to 190,000 barrels per day, which it expects to complete in 2007.

 

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,

     2003

   2004

   2005(1)

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

   91,951    111,104    92,778

(1) During the first three quarters of 2005, production issues at two third-party Canadian synthetic crude oil plants resulted in lower shipments on the Marysville to Toledo crude oil pipeline as compared to 2004.

 

Explorer Pipeline

 

The Partnership owns a 9.4 percent interest in Explorer Pipeline Company (“Explorer”), a joint venture that owns a 1,413-mile common carrier refined product pipeline. Other owners of Explorer are Shell, Marathon, Chevron, 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. Explorer has received FERC approval to charge market-based rates for all its tariffs. The Partnership receives a quarterly cash dividend from Explorer that is proportionate 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

 

The Partnership owns 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, Marathon, and Shell. The system, which is operated by Wolverine employees, originates from Chicago, Illinois and extends to Detroit, Grand Haven, and Bay City, Michigan with delivery points along the way. Wolverine has received FERC approval to charge market-based rates for tariffs at the Detroit, Jackson, Niles, Hammond, and Lockport destinations. The Partnership receives a quarterly cash dividend from Wolverine that is proportionate with its ownership interest.

 

West Shore Pipe Line

 

The Partnership owns a 12.3 percent interest in West Shore Pipe Line Company (“West Shore”), a joint venture that owns a 652-mile common carrier refined product pipeline. On September 30, 2003, the Partnership acquired an additional 3.1 percent interest in West Shore increasing its overall ownership percentage from 9.2 percent 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. West Shore has received FERC approval to charge market-based tariff rates in the Chicago area. The Partnership receives a quarterly cash dividend from West Shore that is proportionate with its ownership interest.

 

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Yellowstone Pipe Line

 

The Partnership owns a 14.0 percent interest in Yellowstone Pipe Line Company (“Yellowstone”), a joint venture that owns a 655-mile common carrier refined product pipeline. Other owners of Yellowstone are ExxonMobil and ConocoPhillips. The system, which is operated by ConocoPhillips employees, originates from the Billings, Montana refining center and extends to Moses Lake, Washington with delivery points along the way. Tariff rates are regulated by the FERC for interstate shipments and the Montana Public Service Commission for intrastate shipments in Montana.

 

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. No dividends were received by the Partnership from Yellowstone during 2003 or 2004, however quarterly cash dividends from Yellowstone resumed in January 2005 after the debt was repaid.

 

Terminal Facilities

 

Refined Product Terminals

 

The Partnership’s 35 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 are facilities where refined products are transferred to or from storage or a transportation system, such as a pipeline, to another transportation system, such as trucks or another pipeline. The operation of these facilities is called “terminalling.” Terminals play a key role in moving product to the end-user market by providing the following services: storage; distribution; blending to achieve specified grades of gasoline; and other ancillary services that include the injection of additives and the filtering of jet fuel. Typically, 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. In 2005, the Partnership began the installation of ethanol blending facilities at 12 of its refined product terminals. The Partnership will have ethanol blending capabilities at all 30 of its refined product terminals that handle gasoline upon the completion of these installations in 2006.

 

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 generates revenues by charging customers fees for blending, including ethanol blending, injecting additives, and filtering jet fuel. Refined product terminals generate the balance of their revenues from the handling of other hydrocarbons for Sunoco R&M at 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,

     2003

   2004

   2005

Refined products throughput (bpd)

   283,071    340,675    389,523

 

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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

Maryland

   1    646,000

Michigan

   2    408,000

New Jersey

   4    751,200

New York(1)

   3    623,600

Ohio

   7    916,500

Pennsylvania

   16    2,043,700

Virginia

   1    277,000
    
  

Total

   35    5,873,000
    
  

(1) 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.

 

Nederland Terminal

 

The Nederland Terminal, which is located on the Sabine-Neches waterway between Beaumont and Port Arthur, Texas, is a large marine terminal that provides storage and distribution services for refiners and other large transporters of crude oil. The terminal receives, stores, and distributes crude oil, feedstocks, lubricants, petrochemicals, and bunker oils (used for fueling ships and other marine vessels). 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. During 2005, construction began on two new tanks, which will add approximately 1.0 million barrels of storage capacity to the terminal in 2006.

 

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 Cameron Highway pipeline, 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 is one of two facilities connected to the Cameron Highway pipeline, a new 390-mile, 24-inch to 30-inch pipeline that has the capacity to deliver up to 500,000 barrels per day of crude oil from off-shore production developments in the Gulf of Mexico. Crude oil deliveries through the Cameron Highway pipeline began in February 2005. In the first quarter of 2006 ExxonMobil reversed the flow of crude oil on its pipeline from Patoka, Illinois to the Nederland Terminal, which will result in the flow of Canadian crude oil to the Nederland Terminal beginning in the first or second quarter of 2006.

 

The Nederland Terminal can deliver crude oil and other petroleum products via pipeline, barge, ship, rail, or truck. In the aggregate, the terminal is capable of delivering over 1.0 million bpd of crude oil to 12 connecting pipelines. The connecting pipelines include the ExxonMobil pipeline to its Beaumont, Texas refinery; the DOE pipelines to the Big Hill and West Hackberry Strategic Petroleum Reserve caverns; the Valero pipeline to its Port Arthur, Texas refinery; the 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

 

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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,

     2003

   2004

   2005

Crude oil and refined products throughput (bpd)

   441,701    487,828    457,655

 

Revenues are generated at the Nederland Terminal primarily by providing term or spot storage services and throughput capability to a number of customers. Most of the terminal’s total revenues in 2005 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.

 

The Fort Mifflin Terminal consists of two ship docks with 38-foot freshwater drafts and nine tanks with a total storage capacity of 570,000 barrels. 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.

 

The Hog Island Wharf is located next to the Fort Mifflin Terminal on the Delaware River and receives crude oil via two ship docks, one of which can accommodate crude oil tankers and smaller crude oil vessels and the other of which can accommodate some smaller crude oil vessels.

 

The Darby Creek Tank Farm is a primary crude oil storage terminal for Sunoco 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,

     2003

   2004

   2005

Crude oil throughput (bpd)

   311,455    330,022    321,623

Refined products throughput (bpd)

   10,934    6,533    5,533
    
  
  

Total (bpd)

   322,389    336,555    327,156
    
  
  

 

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

 

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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,

     2003

   2004

   2005

Refined products throughput (bpd)

   157,233    144,724    149,934

 

Eagle Point Dock

 

On March 30, 2004, the Partnership acquired the Eagle Point logistics assets from Sunoco R&M, including a ship and barge dock connected to the Sunoco R&M Eagle Point refinery. This dock, located on the Delaware River, can accommodate three ships or barges and supplies the Eagle Point refinery with all of its crude oil. The dock can also receive and deliver intermediate products and refined products to outbound ships and barges.

 

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

 

       Year Ended December 31,

       2004(1)

     2005

Crude oil throughput (bpd)

     136,888      146,720

Refined products throughput (bpd)

     67,217      78,439
      
    

Total (bpd)

     204,105      225,159
      
    

(1) For the period from March 30, 2004, the date of acquisition, to December 31, 2004.

 

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

 

Crude Oil Pipelines

 

The Partnership owns and operates approximately 2,197 miles of crude oil trunk pipelines and approximately 520 miles of crude oil gathering pipelines in Texas and Oklahoma. The Partnership is the primary shipper on the Western Pipeline System. The Partnership also delivers crude oil and other feedstocks for Sunoco R&M and other third parties from points in Texas and 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.

 

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

 

     Year Ended December 31,

     2003

   2004

   2005(1)

Crude oil and other feedstocks throughput (bpd)

   304,471    298,797    356,129

(1) Includes results from the Partnership’s Texas crude oil pipeline system from the date of acquisition, August 1, 2005, through December 31, 2005.

 

Texas

 

The Partnership owns and operates approximately 1,397 miles of crude oil trunk pipelines and approximately 340 miles of crude oil gathering pipelines in Texas. The Texas system is connected to the West Texas Gulf pipeline which is 43.8 percent owned by the Partnership, the Mid-Valley pipeline in Longview, Texas which is 55.3 percent owned by Sunoco, other third-party pipelines, and the Partnership’s Nederland Terminal.

 

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’s Texas crude oil pipeline system also includes the following assets acquired since December 31, 2004:

 

    Corsicana to Wichita Falls Pipeline Acquisition. On August 1, 2005, the Partnership purchased, from an affiliate of Exxon Mobil Corporation, a crude oil pipeline system and storage facilities located in Texas for $100.0 million. The pipeline system consists primarily of a 187-mile, 16-inch pipeline with an operating capacity of 125,000 barrels per day. It originates at a crude oil terminal in Corsicana, Texas and terminates at Wichita Falls, Texas. The storage facilities include the Corsicana terminal, which has 2.9 million barrels of shell capacity for crude oil, and the Ringgold, Texas terminal, which consists of 0.5 million barrels of shell capacity for crude oil. In addition, the Partnership invested approximately $16.0 million to construct a new 20-mile pipeline to connect the Corsicana to Wichita Falls pipeline to the West Texas Gulf pipeline, in which the Partnership has a 43.8% ownership interest. Construction of the new 20-mile pipeline was completed in December 2005, and it is currently operational.

 

    Mesa Pipe Line Undivided Interest Acquisition. On December 5, 2005, the Partnership purchased a subsidiary of Sunoco which owned a 7.2 percent undivided interest in the Mesa Pipe Line system for approximately $1.3 million. The Mesa Pipe Line system consists of an 80-mile, 24-inch crude oil pipeline from Midland, Texas to Colorado City, Texas, with an operating capacity of 316,000 barrels per day, and approximately 800,000 barrels of tankage at Midland. The Mesa pipeline connects to the West Texas Gulf pipeline, which supplies crude oil to the Mid-Valley pipeline. On December 29, 2005, the Partnership purchased an additional 29.8 percent interest in Mesa from Chevron for $5.3 million, increasing the Partnership’s ownership to 37.0 percent. Other owners of the undivided interest in Mesa are Plains All American Pipeline and BP. On December 16, 2005, the owners of Mesa agreed to extend the operating agreement for the Mesa Pipe Line System until June 30, 2006. The operating agreement provides that upon expiration of the term, the pipeline is to be sold or salvaged. The owners are in discussions to extend the operating agreement beyond June 30, 2006 and are in disagreement as to the disposition of the pipeline if the agreement is not extended. Although the Partnership is in favor of extending the agreement, there can be no assurance that the agreement will be extended or that the pipeline system will remain operational.

 

   

Millenium and Kilgore Pipeline Acquisition. On March 1, 2006, the Partnership purchased a Texas crude oil pipeline system from affiliates of Black Hills Energy, Inc. for approximately $40.9 million. The system consists of (a) the Millennium Pipeline, a 200-mile, 12-inch crude oil pipeline with 65,000

 

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barrels per day operating capacity, originating near the Partnership’s Nederland Terminal, and terminating at Longview Texas; (b) the Kilgore Pipeline, a 190-mile, 10-inch crude oil pipeline with 35,000 barrel per day capacity originating in Kilgore, Texas and terminating at refineries in the Houston, Texas region; (c) approximately 340,000 shell barrels of active storage capacity at Kilgore, and Longview, Texas; (d) a lease acquisition marketing business; and (e) crude oil line fill and working inventory.

 

    Amdel and White Oil Pipeline Acquisition. On March 1, 2006, the Partnership acquired a Texas crude oil pipeline system from Alon USA Energy, Inc. for approximately $68.0 million. The system consists of (a) the Amdel Pipeline, a 503-mile, 10-inch common carrier crude oil pipeline with 27,000 barrels per day operating capacity, originating at the Nederland Terminal, and terminating at Midland, Texas, and (b) the White Oil Pipeline, a 25-mile, 10-inch crude oil pipeline with 40,000 barrels per day operating capacity, originating at the Amdel Pipeline and terminating at Alon’s Big Spring, Texas refinery. Alon has also agreed to ship a minimum of 15,000 barrels per day under a 10-year, throughput and deficiency agreement on the pipelines. These pipelines are currently idled and are scheduled to be returned to service on June 1, 2006. The Partnership also expects to complete a $12 million program to expand capacity on the Amdel Pipeline from 27,000 to 40,000 barrels per day, and to construct new tankage at the Nederland Terminal to service these new volumes by the end of 2006.

 

Oklahoma

 

The Partnership owns and operates a crude oil pipeline and gathering system in Oklahoma. This system contains approximately 800 miles of crude oil trunk pipelines and approximately 180 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 and other third-party refineries.

 

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 one of the largest purchasers of crude oil from producers in the state, and is the primary shipper on its Oklahoma system.

 

West Texas Gulf Pipe Line

 

The Partnership owns a 43.8 percent interest in, and operates the West Texas Gulf Pipe Line Company (“West Texas Gulf”), a joint venture that owns a 579-mile common carrier crude oil pipeline. Other owners of West Texas Gulf are Chevron, BP, and CITGO. The system originates from the West Texas oil fields at Colorado City and the Nederland crude oil import terminals and extends to Longview, Texas where deliveries are made to several pipelines, including the Mid-Valley pipeline. On January 1, 2005, the Partnership became the operator of this system. The Partnership receives a quarterly cash dividend from West Texas Gulf that is proportionate 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 activities. These activities are primarily in Oklahoma and Texas and include: purchasing crude oil at the wellhead from producers and in bulk from aggregators at major pipeline interconnections and trading locations; 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 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.

 

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The crude oil acquisition and marketing operations generate substantial revenue and cost of products sold because they reflect the sales price and cost of the significant volume of crude oil bought and sold. However, the absolute price levels for crude oil normally do not bear a relationship to gross margin, although these price levels significantly impact revenue and cost of products sold. As a result, period-to-period variations in revenue and cost of products sold are not generally meaningful in analyzing the variation in gross margin for the crude oil acquisition and marketing operations. The operating results of the crude oil acquisition and marketing operations are dependent on its ability to sell crude oil at a price in excess of the aggregate cost. 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 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 does not acquire and hold crude oil futures contracts or enter into other commodity derivative contracts.

 

Crude Oil Purchases and Exchanges

 

In a typical producer’s operation, crude oil flows from the wellhead to a separator where the petroleum gases are removed. After separation, the producer treats the crude oil to remove water, 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 directly or transported via truck to the Partnership’s pipeline or to a third party’s pipeline. The trucking services are performed either by the Partnership’s truck fleet or a third-party trucking operation.

 

Crude oil purchasers who buy from producers compete on the basis of competitive prices and highly responsive services. 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.

 

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 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, 2005, the Partnership purchased 186,224 bpd from approximately 3,400 producers and from approximately 34,000 leases, and undertook approximately 237,401 bpd of exchanges and bulk purchases during the same period.

 

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

 

       Year Ended December 31,

       2003

     2004

     2005

       (in thousands of bpd)

Lease purchases:

                    

Available for sale

     167      164      164

Exchanged

     26      23      22

Other exchanges and bulk purchases

     300      282      237
      
    
    

Total Purchases

     493      469      423
      
    
    

Sales:

                    

Sunoco R&M refineries:

                    

Toledo

     26      24      27

Tulsa

     80      80      62

Third parties

     79      85      96

Exchanges:

                    

Purchased at the lease

     26      23      22

Other

     282      257      216
      
    
    

Total Sales

     493      469      423
      
    
    

 

Market Conditions

 

Market conditions impact the Partnership’s sales and marketing strategies. The Partnership operates the crude oil acquisition and marketing activities differently as market conditions change. 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, the Partnership will use its tankage to improve margins by storing crude oil it has purchased at lower current prices for delivery in future months at higher prices. When there is a higher demand than supply of crude oil in the near term, the market is referred to as “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 generally has a positive impact on marketing margins because crude oil marketers can continue to purchase crude oil at fixed premiums to posted prices while selling crude oil at higher premiums to such prices. The Partnership’s storage capacity is less utilized in a backwardated market, however, the increased marketing margins normally reduce the impact of lower storage revenues.

 

The periods between a backwardated market and a contango market are referred to as transition periods. These transition periods may have either an adverse or beneficial impact on gross margins. A prolonged transition from a backwardated market to a contango market represents the most difficult environment for the Partnership’s sales and marketing activities. Management normally seeks to reduce the adverse impact during such transition periods by renegotiating its crude oil contracts.

 

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 116 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.

 

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Pipeline and Terminal Control Operations

 

Almost 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 through December 2005, Tulsa, Oklahoma. In January 2006, the Western area control center was moved from Tulsa to Sugar Land, Texas in connection with the Western Pipeline System headquarters move. The Montello control center primarily monitors and controls the Partnership’s Eastern Pipeline System, and the Sugar Land 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 and valves associated with the delivery of refined products and crude oil. The computer systems are designed to enhance leak-detection capabilities, sound automatic alarms if operational conditions outside of pre-established parameters occur, and provide for remote-controlled shutdown of pump stations on the 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

 

The Partnership completed the following acquisitions in the three years ended December 31, 2005:

 

Mesa Pipe Line Undivided Interest Acquisition. On December 5, 2005, the Partnership purchased a subsidiary of Sunoco which owned a 7.2 percent undivided interest in the Mesa Pipe Line system for approximately $1.3 million. On December 29, 2005, the Partnership purchased an additional 29.8 percent interest in Mesa from Chevron for $5.3 million, increasing its combined interest to 37.0 percent. For further information, see “Western Pipeline System” discussion above.

 

Corsicana to Wichita Falls Pipeline Acquisition. On August 1, 2005, the Partnership purchased, from an affiliate of Exxon Mobil Corporation, a crude oil pipeline system and storage facilities located in Texas for $100.0 million. For further information, see “Western Pipeline System” discussion above.

 

Columbus Terminal Acquisition. On November 30, 2004, the Partnership acquired a refined products terminal located in Columbus, Ohio for approximately $8.0 million. The terminal is connected to a third-party, refined product, common carrier pipeline and includes 6 refined product tanks with approximately 160,000 barrels of working storage capacity, located on 13 acres; two truck racks for shipping gasoline, distillate fuels, and ethanol via tanker truck; and rail siding access for 4 rail cars for ethanol handling.

 

Harbor Pipeline Interest Acquisition. On June 28, 2004, the Partnership purchased an additional 33.3 percent undivided interest in the Harbor pipeline for $7.3 million. The Harbor pipeline is an 80-mile, 180,000 bpd refined product, common carrier pipeline originating near Woodbury, New Jersey and terminating in Linden, New Jersey. As a result of this transaction, the Partnership increased its undivided ownership interest to 66.7 percent and continues to operate the pipeline.

 

Baltimore and Manassas Terminals Acquisition. On April 28, 2004, the Partnership purchased two refined product terminals located in Baltimore, Maryland and Manassas, Virginia for $12.0 million. The Baltimore terminal is connected to a third-party, refined product, common carrier pipeline and includes 13 refined product tanks with approximately 646,000 barrels of working storage capacity, located on 35 acres; one truck rack for shipping gasoline and distillate fuels via tanker truck; and one marine dock with two berths for receiving refined products. The Manassas terminal is connected to a third-party, refined product, common carrier pipeline and

 

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includes 7 refined product tanks with approximately 277,000 barrels of working storage capacity, located on 11 acres, and one truck rack for shipping gasoline and distillate fuels via tanker truck.

 

Eagle Point Logistics Assets Acquisition. On March 30, 2004, the Partnership acquired the Eagle Point refinery logistics assets from Sunoco R&M for $20 million. The Eagle Point logistics assets consist of a crude oil and refined product ship and barge dock, a refined product truck rack, and a 4.5 mile, refined product pipeline from the Eagle Point refinery to the origin of the Harbor pipeline. In connection with the acquisition, the Partnership entered into a throughput agreement with Sunoco R&M whereby they have agreed to minimum volumes on the truck rack upon completion of certain capital improvements, which were completed during the fourth quarter of 2004.

 

West Shore Pipe Line Company Interest Acquisition. 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.

 

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 discussed above, management of the Partnership may, in the future, consider and make acquisitions in other business areas.

 

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 agreements such as 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, Tulsa, and Eagle Point refineries, or refined products transported from the Philadelphia, Marcus Hook, Toledo, and Eagle Point 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, 2005, Sunoco R&M accounted for approximately 44 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 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.

 

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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 and other agreements, the Partnership will continue to receive a significant portion of the throughput at these facilities from Sunoco R&M.

 

The 35 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 the Beaumont, Texas area.

 

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

 

Western Pipeline System

 

The Western Pipeline System faces competition from a number of major oil companies and smaller entities. Competition among common carrier pipelines is based primarily on transportation charges and access to crude oil supply and demand. Management of the Partnership believes that high capital costs make it unlikely that other companies will build new competing crude oil pipeline systems in the pipeline corridors served by the Western Pipeline System, however changes in refiners’ supply sources may negatively impact existing throughput on the Western Pipeline System . Crude oil purchasing and marketing competitive factors include price and contract flexibility, quantity and quality of services, and accessibility to end markets.

 

Partnership’s Option to Purchase Pipelines from Sunoco

 

The Partnership owns most of the pipeline, terminalling, storage, and related assets that support Sunoco R&M’s refinery operations. Sunoco has retained the assets discussed below:

 

    Mid-Valley Pipeline. A subsidiary of Sunoco owns a 55.3 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.

 

    Inland Pipeline. A subsidiary of Sunoco owns a 10.0 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 either 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.

 

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.

 

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Both of the ten-year option agreements discussed 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 discussed 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 has completed the assessment of more than the minimum required 50 percent highest risk line segments as of December 31, 2005, and expects that it will complete the full assessment of the remaining segments by March 31, 2008, the timeframe prescribed by the regulations.

 

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, some of which are discussed below. Violations of environmental laws or regulations can result in the imposition of significant administrative, civil and criminal fines and penalties and, in some instances, injunctions banning or delaying certain activities. Management of the Partnership believes it is in substantial compliance with applicable environmental laws and regulations.

 

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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, 2005, all material environmental liabilities incurred by, and known to, the Partnership are either covered by the environmental indemnification or reserved for by the Partnership within its financial statements.

 

Air Emissions

 

The Partnership’s operations are subject to the Clean Air Act, as amended, and comparable state and local statutes. 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. As a result of these regulations, 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

 

In the course of ordinary operations, the Partnership may generate waste that falls within the Comprehensive Environmental Response, Compensation, and Liability Act’s, referred to as CERCLA and also known as Superfund, definition of a “hazardous substance” and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. Costs for any such remedial actions, as well as any related claims, could have a material adverse effect on 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”.

 

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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. 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. 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 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.

 

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.”

 

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The Partnership has experienced several petroleum releases for which it is not covered by an indemnity from Sunoco, Inc., and for which it is responsible for necessary assessment, remediation, and/or monitoring activities. 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 in relation to its financial position at December 31, 2005. 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.

 

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.

 

The Partnership has applied to FERC for permission to charge market-based rates in many of the refined products markets it serves. On January 19, 2006, the FERC ruled on the Partnership’s application for market-based rates on certain of its pipelines. Market-based rates were approved on the Detroit, MI, Pittsburgh, PA, Rochester, NY and Toledo, OH origin markets and the Detroit, MI, Philadelphia, PA and New York, NY destination markets. FERC ordered hearings on the application for the Philadelphia, PA origin market and the Cleveland, OH, Harrisburg, PA, Scranton, PA and Toledo, OH destination markets. In those markets where market-based rates were approved, the Partnership would be able to establish rates without regard to the index or our cost-of-service. As to the markets where hearings have been ordered, there can be no assurances that market-based rates will be approved, in which case, our rates would continue to be subject to current rate structures.

 

Intrastate Regulation. Some of the Partnership’s pipeline operations are subject to regulation by the Texas Railroad Commission, the Pennsylvania Public Utility Commission, the Ohio Public Utility Commission, and the Oklahoma Corporation Commission. The operations of the Partnership’s joint venture interests are also subject to regulation in the states in which they operate. The applicable state statutes require that pipeline rates be

 

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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.

 

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 acquired by the Partnership or transferred to it upon the closing of the February 2002 IPO require the consent of the grantor to transfer these rights, which in some instances is a governmental entity. 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. In management’s opinion, with respect to any consents, permits, or authorizations that have not been obtained, the failure to obtain them will not have a material adverse effect on the operation of 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 for environmental contamination, taxes and other burdens, easements, or other restrictions, management believes that none of these burdens materially detract from the value of the properties or will materially interfere with their use in the operation of the Partnership’s business.

 

Employees

 

To carry out the Partnership’s operations, the general partner and its affiliates employed approximately 1,125 people at December 31, 2005 who provide direct support to the operations. Labor unions or associations represent approximately 608 of these employees at December 31, 2005. The general partner considers its employee relations to be good. The Partnership has no employees.

 

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(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.

 

ITEM 1A. RISK FACTORS

 

The risks below may not be the only risks we face. Additional risks that we do not yet know of or that we currently think are immaterial also may impair our business operations. If any of the following risks actually occur, our business, results of operations, cash flows and financial condition could be affected materially and adversely.

 

We may not be able to generate sufficient cash from operations to allow us to make the required payments to our debt holders or to pay quarterly distributions.

 

The amount of cash we can distribute on our common units principally depends upon the cash we generate from our operations. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. Because the cash we generate from operations will fluctuate from quarter to quarter, we may not be able to pay all the applicable interest and principal obligations on our debt, or to pay quarterly distributions.

 

In the future, we may not be able to generate sufficient cash flow from operations, realize currently anticipated operating improvements or borrow amounts under our revolving credit facility sufficient to fund our liquidity needs. We may need to refinance all or a portion of our indebtedness on or before maturity. We may not be able to refinance any of our indebtedness on or before maturity on commercially reasonable terms, or at all.

 

Our ability to pay quarterly distributions depends primarily on cash flow, including cash flow from financial reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items. As a result, we may pay cash distributions during periods when we record net losses and may be unable to pay cash distributions during periods when we record net income.

 

Our general partner’s discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to our unitholders.

 

Our partnership agreement provides that our general partner may reduce operating surplus by establishing cash reserves to provide funds for our future operating expenditures. In addition, the partnership agreement provides that our general partner may reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to our unitholders in any one or more of the next four quarters. These cash reserves will affect the amount of cash available for current distribution to our unitholders.

 

Cost reimbursements, which will be determined by our general partner in good faith, and fees due our general partner and its affiliates will be substantial and could materially and adversely affect our financial condition, results of operations, or cash flows.

 

We currently pay Sunoco, Inc. an annual administrative fee for the provision by Sunoco, Inc. or its affiliates of various general and administrative services for our benefit. This fee is subject to periodic re-negotiation, and

 

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there can be no assurance that future administrative fees charged by Sunoco, Inc. will be at or below the current level. This fee may increase if an expansion of our operations requires an increased level of general and administrative services from Sunoco, Inc. or its affiliates. If we are unable to obtain such services from Sunoco, Inc. or third parties at or below the current cost, it could materially and adversely affect our financial condition, results of operations, or cash flows. In addition, our general partner is entitled to reimbursement for all other expenses it incurs on our behalf, including the salaries of, and the cost of employee benefits for, our general partner’s employees, including senior executives, who provide services to us. Our general partner will determine the amount of these expenses in good faith.

 

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

 

In some instances, our general partner may cause us to borrow funds from affiliates of Sunoco, Inc. or from third parties in order to permit the payment of cash distributions. These borrowings are permitted even if the purpose and effect of the borrowing is to enable us to make a distribution on the subordinated units, to make incentive distributions, or to hasten the expiration of the subordination period.

 

Our general partner has a limited call right that may require our unitholders to sell their common units at an undesirable time or price.

 

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their common units at an undesirable time or price, may not receive a return on the investment, and may incur a tax liability upon the sale.

 

Even if unitholders are dissatisfied, they cannot remove our general partner without its consent, which could lower the trading price of the common units.

 

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders did not elect our general partner or its board of directors and will have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is chosen by the members of our general partner, all of which are subsidiaries of Sunoco, Inc. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a control premium in the trading price.

 

The partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

 

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

 

The general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of the owner of the general partner from transferring its ownership interest in the general partner to a third party. The new owner of the general partner would then be in a position to replace the board of directors and officers of the general partner with its own choices and to control the decisions taken by the board of directors and officers.

 

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

 

Sunoco, Inc. indirectly owns and controls our general partner, which holds the 2 percent general partner interest and holds a 45.9 percent limited partner interest in us. Conflicts of interest may arise between Sunoco, Inc. and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, the general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:

 

    Sunoco R&M, as a shipper on our pipelines, and a customer at our terminals, could seek lower tariff rates or terminalling fees, once the terms of Sunoco R&M’s obligations under the pipelines and terminals storage and throughput agreements expire in 2007 through 2009.

 

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

 

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

 

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

 

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

 

    our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities, and reserves, each of which can affect the amount of cash that is distributed to our unitholders;

 

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

 

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

 

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

 

    our general partner decides whether to retain separate counsel, accountants, or others to perform services for us.

 

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

 

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

 

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We depend upon Sunoco R&M for a substantial portion of the crude oil and refined products transported on our pipelines and handled at our terminals, and our crude oil sales.

 

For the year ended December 31, 2005, Sunoco R&M accounted for approximately 70 percent of our Eastern Pipeline System total revenues, 69 percent of our Terminal Facilities total revenues, and 43 percent of our Western Pipeline System total revenues. The balance of our revenues was received from third parties, and we will continue to remain dependent on third parties for these additional revenues. Our pipelines and terminals storage and throughput agreements with Sunoco R&M provide for escalation of the fees charged to Sunoco R&M, but the increased fees may be inadequate to cover increased costs in the future. We expect to continue to derive a substantial portion of our revenues from Sunoco R&M for the foreseeable future. If for any reason, Sunoco R&M were to decrease the throughput transported on our pipelines, the volumes of crude oil or refined products handled at our terminals or the amounts of crude oil purchased from us, it could materially and adversely affect our financial condition, results of operations, or cash flows.

 

Sunoco R&M’s obligations to us under the pipelines and terminals storage and throughput agreements and other arrangements may be reduced or suspended in some circumstances.

 

Sunoco R&M’s obligations to us under the pipelines and terminals storage and throughput agreements may be permanently reduced in some circumstances. These events, some of which are within the exclusive control of Sunoco R&M, include:

 

    The inability of Sunoco R&M and us to agree on the amount of any surcharge required to be paid by Sunoco R&M to cover substantial and unanticipated costs that may be incurred in complying with new laws or governmental regulations applicable to our Terminal Facilities;

 

    A decision by Sunoco R&M to shut down or reconfigure one or more of its refineries if Sunoco R&M reasonably believes in good faith that such event will jeopardize its ability to satisfy its minimum revenue or throughput obligations; and

 

    Federal or state governmental action that prohibits Sunoco R&M from using MTBE in the gasoline it produces if Sunoco R&M reasonably believes in good faith that this action will jeopardize its ability to satisfy its minimum revenue or throughput obligations.

 

Depending on the ultimate cost of complying with existing and future environmental regulations or proceedings, Sunoco R&M may determine that it is more economical to reduce production at a refinery or shut down all or a portion of a refinery rather than make these capital expenditures. Sunoco R&M’s obligations to us under the pipelines and terminals storage and throughput agreements would be reduced in this event.

 

Furthermore, Sunoco R&M’s obligations to us would be temporarily suspended during the occurrence of an event that is outside the control of the parties, which renders performance impossible with respect to an asset for at least 30 days. The occurrence of any of these events could materially and adversely affect our financial condition, results of operations, or cash flows.

 

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

 

If Sunoco R&M satisfies only its minimum obligations to us under, or if we are unable to renew or extend the pipelines and terminals storage and throughput agreements, it could materially and adversely affect our financial condition, results of operations, or cash flows.

 

Sunoco R&M may reduce the volume it transports on our pipelines or delivers at our terminals to the minimum amounts it is obligated to transport or deliver under the pipelines and terminals storage and throughput agreements. In addition, the terms of Sunoco R&M’s obligations to us under the pipelines and terminals storage and throughput agreements entered into at the time of our initial public offering are of relatively brief duration,

 

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generally expiring in 2007 through 2009. If Sunoco R&M reduces its use of our facilities after expiration of this agreement or any other storage and throughput agreements between us and Sunoco R&M, or if the terms under a new agreement are materially changed in a way that reduces revenues, and we are unable to generate additional revenues from third parties, it could materially and adversely affect our financial condition, results of operations, or cash flows.

 

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

 

Factors that could lead to a sustained decrease in market demand for refined products include:

 

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

 

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

 

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

 

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

 

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

 

When the price of foreign crude oil delivered to the United States is greater than that of domestic crude oil, or the price for the future delivery of crude oil falls below current prices, customers are less likely to store crude oil, thereby reducing storage revenues at our Nederland Terminal.

 

Most of the crude oil stored at our Nederland Terminal is foreign crude oil. When the price of foreign crude oil delivered to the United States is greater than that of domestic crude oil, the demand for this storage capacity may decrease. If this market condition occurs, our storage revenues will be lower.

 

When the price of crude oil in a given month exceeds the price of crude oil for delivery in a subsequent month, the market is backwardated. When the crude oil market is backwardated, the demand for storage capacity at our Nederland Terminal may decrease because crude oil producers can capture a premium for prompt deliveries rather than storing it for sale later. Although a backwardated market generally has a favorable 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, we may be unable to completely offset the lower storage revenues in a backwardated market.

 

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

 

The volume of crude oil transported in our crude oil pipelines depends on the availability of attractively priced crude oil produced in the areas accessible to our crude oil pipelines and received from other common carrier pipelines. If we do not replace volume lost due to a material temporary or permanent decrease in supply, the volume of crude oil transported through our pipelines would decline. In addition, sustained low crude oil prices could lead to a decline in drilling activity and production levels or the shutting-in or abandonment of marginal wells. Similarly, a temporary or permanent material increase in the price of crude oil supplied from any of these sources, as compared to alternative sources of crude oil available to our customers, could cause the volume of crude oil transported in our pipelines to decline.

 

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Any reduction in the capability of, or the allocations to, our shippers in interconnecting, third-party pipelines would cause a reduction of volumes transported in our pipelines and through our terminals.

 

Sunoco R&M and the other users of our pipelines and terminals are dependent upon connections to third-party pipelines to receive and deliver crude oil and refined products. Any reduction of capabilities of these interconnecting pipelines due to testing, line repair, reduced operating pressures, or other causes would result in reduced volumes transported in our pipelines or through our terminals. Similarly, if additional shippers begin transporting volume over interconnecting pipelines, the allocations to our existing shippers could be reduced, which also would reduce volumes transported in our pipelines or through our terminals.

 

If we are unable to complete capital projects at their expected costs and/or in a timely manner, or if the market conditions assumed in our project economics deteriorate, our financial condition, results of operations, or cash flows could be affected materially and adversely.

 

Delays or cost increases related to capital spending programs involving construction of new facilities (or improvements and repairs to our existing facilities) could adversely affect our ability to achieve forecasted internal rates of return and operating results. Delays in making required changes or upgrades to our facilities could subject us to fines or penalties as well as affect our ability to supply certain products we make. Such delays or cost increases may arise as a result of unpredictable factors in the marketplace, many of which are beyond our control, including:

 

    denial or delay in issuing requisite regulatory approvals and/or permits;

 

    unplanned increases in the cost of construction materials or labor;

 

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

 

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

 

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

 

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

 

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

 

Our forecasted internal rates of return also are based upon our projections of future market fundamentals which are not within our control, including changes in general economic conditions, available alternative supply and customer demand.

 

Potential future acquisitions and expansions, if any, may increase substantially the level of our indebtedness and contingent liabilities, and we may be unable to integrate them effectively into our existing operations.

 

From time to time, we evaluate and acquire assets and businesses that we believe complement or diversify our existing assets and businesses. Acquisitions may require substantial capital or the incurrence of substantial indebtedness. If we consummate any future acquisitions, our capitalization and results of operations may change significantly.

 

Acquisitions and business expansions involve numerous risks, including difficulties in the assimilation of the assets and operations of the acquired businesses, inefficiencies and difficulties that arise because of unfamiliarity with new assets and the businesses associated with them and new geographic areas. Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined and we may experience unanticipated delays in realizing the benefits of an acquisition. In some cases, we have indemnified the previous owners and operators of acquired assets. Following an acquisition, we may discover previously unknown liabilities associated with the acquired business for which we have no recourse

 

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under applicable indemnification provisions. An acquisition may require us to assume certain prior known or unknown liabilities.

 

Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.

 

Our operations and those of our customers and suppliers may be subject to operational hazards and unforeseen interruptions such as natural disasters (including hurricanes), adverse weather, accidents, fires, explosions, hazardous materials releases, and other events beyond our control. These events might result in a loss of equipment or life, injury, or extensive property damage, as well as an interruption in our operations. We may not be able to maintain or obtain insurance of the type and amount desired at reasonable rates. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. If we were to incur a significant liability for which we were not fully insured, it could materially and adversely affect our financial condition, results of operations, or cash flows.

 

We are exposed to the credit and other counterparty risk of our customers in the ordinary course of our business.

 

There can be no assurance that we have adequately assessed the credit worthiness of our existing or future counterparties or that there will not be an unanticipated deterioration in their credit worthiness, which could have an adverse impact on us. In those cases in which we provide division order services for crude oil purchased at the wellhead, we may be responsible for distribution of proceeds to all parties. In other cases, we pay all of or a portion of the production proceeds to an operator who distributes these proceeds to the various interest owners. There can be no assurance that we will not experience material losses in dealings with other parties.

 

Competition with respect to our operating segments could ultimately lead to lower levels of profits and could materially and adversely affect our financial condition, results of operations, or cash flows.

 

We face competition from other pipelines, terminals and crude oil marketers, as well as from other means of transporting, storing and distributing petroleum products. Our customers demand delivery of products on tight time schedules and in a number of geographic markets. If our quality of service declines or we cannot meet the demands of our customers, they may utilize the services of our competitors. If a competing crude oil or refined product pipeline or other crude oil marketer charged lower rates than we do, we could be forced to reduce our rates to remain competitive.

 

Mergers among our customers and competitors could result in lower volumes being shipped on our pipelines or products stored in or distributed through our terminals, or reduced crude oil marketing margins or volumes.

 

Mergers between existing customers could provide strong economic incentives for the combined entities to utilize their existing systems instead of ours in those markets where the systems compete. As a result, we could lose some or all of the volumes and associated revenues from these customers and we could experience difficulty in replacing those lost volumes and revenues, which could materially and adversely affect our financial condition, results of operations, or cash flows.

 

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

 

The primary rate-making methodology of the Federal Energy Regulatory Commission, or FERC, is price indexing. We use this methodology in all of our interstate markets. In an order issued February 24, 2003, the FERC announced that, effective July 1, 2003, the index would equal the change in the producer price index for finished goods (previously, the index was equal to the change in the producer price index for finished goods

 

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minus 1%). If the index falls, we would be required to reduce rates that are based on the FERC’s price indexing methodology if they exceed the new maximum allowable rate. In addition, changes in the index might not be large enough to fully reflect actual increases in our costs. The FERC’s rate-making methodologies may limit our ability to set rates based on our true costs or may delay the use of rates that reflect increased costs.

 

Under the Energy Policy Act adopted in 1992, certain interstate pipeline rates were deemed just and reasonable or “grandfathered.” Most of our revenues are derived from grandfathered rates on our FERC-regulated refined products pipelines. A person challenging a grandfathered rate must, as a threshold matter, establish a substantial change since the date of enactment of the Act, in either the economic circumstances or the nature of the service that formed the basis for the rate. A complainant might assert that the creation of the partnership itself constitutes such a change, an argument that has not previously been specifically addressed by the FERC. If the FERC were to find a substantial change in circumstances, then the existing rates could be subject to detailed review. There is a risk that some rates could be found to be in excess of levels justified by our cost of service. In such event, the FERC would order us to reduce rates prospectively and could order us to pay reparations to complaining shippers. Reparations could be required for a period of up two years prior to the date of filing the complaint in the case of rates that are not grandfathered and for the period starting with the filing of the complaint in the case of grandfathered rates.

 

On July 20, 2004, the United States Court of Appeals for the District of Columbia Circuit, or the D.C. Circuit, issued its opinion in BP West Coast Products, LLC v. FERC, which upheld FERC’s determination that the rates of an interstate petroleum products pipeline, SFPP, L.P., or SFPP, were grandfathered rates under the Energy Policy Act of 1992 and that SFPP’s shippers had not demonstrated substantially changed circumstances that would justify modification of those rates. The court also vacated the portion of the FERC’s decision applying the Lakehead policy. In the Lakehead decision, the FERC allowed an oil pipeline master limited partnership to include in its cost-of-service an income tax allowance to the extent that its unitholders were corporations subject to income tax. The BP West Coast decision is likely to be appealed to the D.C. Circuit, and the new tax allowance policy is subject to rehearing and further action by the FERC. The ultimate outcome of this proceeding is not certain, and could result in changes to the FERC’s treatment of income tax allowances in cost-of-service. In May and June 2005, the FERC issued a statement of general policy, as well as an order on remand of BP West Coast, respectively, in which the FERC has stated it will permit pipelines to include in cost-of-service a tax allowance to reflect actual or potential tax liability on their public utility income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. Although the new policy is generally favorable for pipelines that are organized as pass-through entities, it still entails rate risk due to the case-by-case review requirement. However, on December 16, 2005, the FERC issued its first case-specific review of the income tax allowance issue in the SFPP, L.P. proceeding. The FERC ruled favorably to SFPP L.P. on all income tax issues and set forth guidelines regarding the evidence necessary for the pipeline to determine its income tax allowance.

 

In addition, a state commission could also investigate our intrastate rates or terms and conditions of service on its own initiative or at the urging of a shipper or other interested party. If a state commission found that our rates exceeded levels justified by our cost of service, the state commission could order us to reduce our rates.

 

Sunoco R&M has agreed not to challenge, or to cause others to challenge or assist others in challenging, our tariff rates in effect during the term of the pipelines and terminals storage and throughput agreement. This agreement does not prevent other current or future shippers from challenging our tariff rates. At the end of the term of the agreement, Sunoco R&M will be free to challenge, or to cause other parties to challenge or assist others in challenging, our tariff rates in effect at that time.

 

Potential changes to current rate-making methods and procedures may impact the federal and state regulations under which we will operate in the future. In addition, if the FERC’s petroleum pipeline ratemaking methodology changes, the new methodology could materially and adversely affect our financial condition, results of operations, or cash flows.

 

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Our operations are subject to federal, state, and local laws and regulations relating to environmental protection and operational safety that could require substantial expenditures.

 

Our pipelines, gathering systems, and terminal operations are subject to increasingly strict environmental and safety laws and regulations. The transportation and storage of refined products and crude oil result in a risk that refined products, crude oil, and other hydrocarbons may be suddenly or gradually released into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies for natural resources damages, personal injury, or property damages to private parties and significant business interruption. We own or lease a number of properties that have been used to store or distribute refined products and crude oil for many years. Many of these properties also have been previously owned or operated by third parties whose handling, disposal, or release of hydrocarbons and other wastes were not under our control, and for which, in some cases, we have indemnified the previous owners and operators.

 

Failure to comply with these laws and regulations may result in assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens and, to a lesser extent, issuance of injunctions to limit or cease operations. We may be unable to recover these costs through increased revenues.

 

Our business is subject to federal, state and local laws and regulations that govern the product quality specifications of the petroleum products that we store and transport.

 

Petroleum products that we store and transport are sold by our customers for consumption into the public market. Various federal, state and local agencies have the authority to prescribe specific product quality specifications to commodities sold into the public market. Changes in product quality specifications could reduce our throughput volume, require us to incur additional handling costs or require the expenditure of capital. In addition, different product specifications for different markets impact the fungibility of the system and could require the construction of additional storage. We may be unable to recover these costs through increased revenues.

 

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

 

As of December 31, 2005, our total outstanding long-term indebtedness was approximately $355.6 million, consisting of $248.9 million of senior notes, net of unamortized discount of $1.0 million and $106.6 million of borrowings under our credit facility. Our payment of principal and interest on the debt will reduce the cash available for distribution on our units, as will our obligation to repurchase the senior notes upon the occurrence of specified events involving a change in control of our general partner. In addition, we are prohibited by our credit facility and the senior notes from making cash distributions during an event of default, or if the payment of a distribution would cause an event of default, under any of our debt agreements. The termination of our pipelines and terminals storage and throughput agreements with Sunoco R&M would constitute an event of default under our credit facility. Failure to renew these agreements could lead to an event of default under our credit facility. Our leverage and various limitations in our credit facility and our senior notes may reduce our ability to incur additional debt, engage in some transactions, and capitalize on acquisition or other business opportunities. Since Sunoco, Inc. owns and controls our general partner, we are not permitted to incur additional debt if the effect would be to cause an event of default under Sunoco, Inc.’s revolving credit agreements. Any subsequent refinancing of Sunoco, Inc.’s or our current debt or any new debt could have similar or greater restrictions.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

    place us at a competitive disadvantage against less leveraged competitors.

 

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

 

As of December 31, 2005, we had $106.6 million of floating-rate debt. As a result, we have exposure to changes in short-term interest rates. Rising short-term rates could materially and adversely affect our financial condition, results of operations, or cash flows.

 

A down-grading in Sunoco, Inc.’s credit rating could result in a down-grading in our credit rating, which could adversely affect our ability to obtain financing.

 

Due to our relationship with Sunoco, Inc., our credit rating is partly dependent on Sunoco, Inc.’s credit rating. Any down-grading in Sunoco, Inc.’s credit rating could result in a down-grading in our credit rating, which could, among other things, limit our ability to obtain financing on the terms currently available to us, if at all.

 

Terrorist attacks aimed at our facilities could adversely affect our business.

 

Since the September 11, 2001 terrorist attacks, the U.S. government has issued warnings that energy assets, specifically the nation’s pipeline and terminal infrastructure, may be the future targets of terrorist organizations. Any future terrorist attack at our facilities, those of our customers and, in some cases, those of other pipelines, refineries, or terminals could materially and adversely affect our financial condition, results of operations, or cash flows.

 

Due to our lack of asset diversification, adverse developments in our businesses could materially and adversely affect our financial condition, results of operations, or cash flows.

 

We rely exclusively on the revenues generated from our businesses, and dividends from our equity investments. Due to our lack of asset diversification, an adverse development in one of these businesses could have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets.

 

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We may issue additional common units without unitholder approval, which would dilute our unitholders’ ownership interests.

 

During the subordination period, our general partner, without the approval of our unitholders, may cause us to issue up to 5,691,820 additional common units. Our general partner also may cause us to issue an unlimited number of additional common units or other equity securities of equal rank with the common units, without unitholder approval, in a number of circumstances. After the end of the subordination period, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Our partnership agreement does not give our unitholders the right to approve our issuance of equity securities ranking junior to the common units at any time. The issuance of additional common units, or other equity securities of equal or senior rank, will decrease the proportionate ownership interest of existing unitholders and may reduce the amount of cash available for distribution and/or the market price of our common units.

 

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

 

Sunoco, Inc. and its affiliates may engage in limited competition with us. Pursuant to the omnibus agreement, Sunoco, Inc. and its affiliates have agreed not to engage in the business of purchasing crude oil at the wellhead or operating refined product or crude oil pipelines or terminals or LPG terminals in the continental United States. The omnibus agreement, however, does not apply to:

 

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

 

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

 

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

 

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

 

Upon a change of control of Sunoco, Inc. or a sale of the general partner by Sunoco, Inc., the non-competition provisions of the omnibus agreement may terminate.

 

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

 

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

 

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

 

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

 

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

 

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

 

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Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity level taxation by individual states. If the Internal Revenue Service, or IRS, treats us as a corporation or we become subject to entity level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to unitholders.

 

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this matter. The IRS may adopt positions that differ from the ones we take. A successful IRS contest of the federal income tax positions we take may impact adversely the market for our common units, and the costs of any IRS contest will reduce our cash available for distribution to unitholders.

 

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax at the corporate tax rate, and likely would pay state income tax at varying rates. Distributions to unitholders generally would be taxed again as corporate distributions. Treatment of us as a corporation would result in a material reduction in anticipated cash flow and after-tax return to unitholders. Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or to otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise and other forms of taxation. If any of these states were to impose a tax on us, the cash available for distribution to unitholders would be reduced. The partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state, or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.

 

ITEM 1B. UNRESOLVED STAFF COMMENTS

 

None.

 

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 has 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.

 

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, 2005.

 

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS

 

No matters were submitted to a vote of the securityholders during fiscal 2005.

 

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PART II

 

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SECURITYHOLDER MATTERS AND PURCHASES OF EQUITY SECURITIES

 

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, 2006, there were 91 holders of record of the Partnership’s common units. These holders of record included the general partner with 6,371,915 common units registered in its name, and Cede & Co. with 13,702,630 common units registered to it.

 

The high and low closing sales price ranges (composite transactions) and distributions declared by quarter for 2004 and 2005 were as follows:

 

     2004

   2005

     Unit Price

   Declared
Distributions(1)


   Unit Price

   Declared
Distributions(1)


Quarter


   High

   Low

      High

   Low

  

1st

   $ 42.20    $ 34.48    $ 0.5700    $ 43.85    $ 40.30    $ 0.6250

2nd

   $ 39.75    $ 31.47    $ 0.5875    $ 42.85    $ 37.01    $ 0.6375

3rd

   $ 39.36    $ 36.00    $ 0.6125    $ 41.13    $ 38.05    $ 0.6750

4th

   $ 43.05    $ 38.75    $ 0.6250    $ 39.10    $ 37.66    $ 0.7125

(1) Distributions were declared and paid within 45 days following the close of each quarter.

 

Within 45 days after the end of each quarter, the Partnership distributes all cash on hand at the end of the quarter less reserves established by the general partner in its discretion. This is defined as “available cash” in the partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct the Partnership’s business. The Partnership will make 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.

 

The Partnership also had 8,537,729 subordinated units issued as of December 31, 2005, all of which were held by the general partner, and for which there is no established public trading market. The Partnership issued 11,383,639 subordinated units to its general partner in connection with the 2002 IPO. 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. In addition, one quarter of the subordinated units may convert to common units on a one-for-one basis after both December 31, 2004 and December 31, 2005, if the Partnership meets the required tests for the preceding three consecutive, non-overlapping four-quarter periods. When 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.

 

During the subordination period, the Partnership will generally 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 discussed below.

 

The Partnership has met the minimum quarterly distribution requirements on all outstanding units for each of the four-quarter periods ended December 31, 2003, 2004 and 2005. As a result, a total of 5,691,820 subordinated units have been converted into common units on a one-for-one basis, 2,845,910 each on February 15, 2005 and February 15, 2006. As a result, there are 5,691,819 subordinated units outstanding at February 28, 2006, all of which may be converted in February 2007 as long as the Partnership continues to meet the financial tests noted above for each of the four-quarter periods ending December 31, 2004, 2005 and 2006.

 

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

 

Quarterly Cash Distribution Amount per Unit


     Percentage of Distributions

 
     Unitholders

    General Partner

 

Up to minimum quarterly distribution ($0.45 per Unit)

     98 %   2 %

Above $0.45 per Unit up to $0.50 per Unit

     98 %   2 %

Above $0.50 per Unit up to $0.575 per Unit

     85 %   15 %

Above $0.575 per Unit up to $0.70 per Unit

     75 %   25 %

Above $0.70 per Unit

     50 %   50 %

 

If cash distributions exceed $0.50 per unit in a quarter, the general partner will receive increasing percentages, up to 50 percent, of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions”. The amounts shown in the table under “Percentage of Distributions” are the percentage interests of the general partner and the unitholders in any available cash from operating surplus that is distributed up to and including the corresponding amount in the column “Quarterly Cash Distribution Amount per Unit,” until the available cash that is distributed reaches the next target distribution level, if any. The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

 

There is no guarantee that the Partnership will pay the minimum quarterly distribution on the common units in any quarter, and the Partnership is 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 2. “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”), 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 2001, the Partnership and Predecessor for 2002, and the Partnership for 2003, 2004 and 2005.

 

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 the Predecessor for Sunoco R&M’s refining and marketing

 

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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 expense (“EBITDA”) for those assets was equal to their depreciation and amortization expense. Sunoco Logistics Partners L.P. began charging Sunoco R&M fees for these services that are 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 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 such as transfer pipelines, transport large volumes over short distances and generate minimal revenues.

 

The following table should be read together with, and is qualified in its entirety by reference to, the financial statements and the accompanying notes of Sunoco Logistics Partners L.P. included in Item 8. “Financial Statements and Supplementary Data”. The table also should be read together with Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations”.

 

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SUNOCO LOGISTICS PARTNERS L.P.

 

     Predecessor

    Partnership
and
Predecessor


    Partnership

 
     Year Ended December 31,

 
     2001

    2002(1)

    2003(2)

    2004(3)

    2005(4)

 
     (in thousands, except per unit and operating data)  

Income Statement Data:

                                        

Revenues:

                                        

Sales and other operating revenue:

                                        

Affiliates

   $ 1,067,182     $ 1,147,721     $ 1,383,090     $ 1,751,612     $ 1,986,019  

Unaffiliated customers

     545,822       676,307       1,274,383       1,699,673       2,496,593  

Other income(5)

     4,774       6,904       16,730       13,932       14,295  
    


 


 


 


 


Total revenues

     1,617,778       1,830,932       2,674,203       3,465,217       4,496,907  
    


 


 


 


 


Costs and expenses:

                                        

Cost of products sold and operating expenses

     1,503,156       1,690,896       2,519,160       3,307,480       4,326,713  

Depreciation and amortization

     25,325       31,334       27,157       31,933       33,838  

Selling, general and administrative expenses

     35,956       43,073       48,412       48,449       53,048  
    


 


 


 


 


Total costs and expenses

     1,564,437       1,765,303       2,594,729       3,387,862       4,413,599  
    


 


 


 


 


Operating income

     53,341       65,629       79,474       77,355       83,308  

Net interest cost and debt expense

     10,980       17,299       20,040       20,324       21,599  
    


 


 


 


 


Income before income tax expense

     42,361       48,330       59,434       57,031       61,709  

Income tax expense

     15,594       1,555       —         —         —    
    


 


 


 


 


Net Income

   $ 26,767     $ 46,775     $ 59,434     $ 57,031     $ 61,709  
    


 


 


 


 


Net Income per limited partner unit:

                                        

Basic

           $ 1.87 (6)   $ 2.55     $ 2.29     $ 2.37  
            


 


 


 


Diluted

           $ 1.86 (6)   $ 2.53     $ 2.27     $ 2.35  
            


 


 


 


Cash distributions per unit to limited partners:(7)

                                        

Paid

           $ 1.16     $ 1.9875     $ 2.32     $ 2.5625  
            


 


 


 


Declared

           $ 1.6475     $ 2.05     $ 2.395     $ 2.65  
            


 


 


 


Cash Flow Data:

                                        

Net cash provided by operating activities

   $ 27,238     $ 2,211     $ 97,212     $ 106,622     $ 90,835  

Net cash used in investing activities

   $ (73,079 )   $ (85,273 )   $ (39,008 )   $ (95,583 )   $ (180,654 )

Net cash provided by/(used in) financing activities

   $ 45,841     $ 116,902     $ (41,963 )   $ (8,460 )   $ 58,804  

Capital expenditures:

                                        

Maintenance

   $ 53,628     $ 27,934     $ 30,850     $ 30,829     $ 31,194  

Expansion

     19,055       77,439 (1)     10,226 (2)     64,754 (3)     149,460 (4)
    


 


 


 


 


Total capital expenditures

   $ 72,683     $ 105,373     $ 41,076     $ 95,583     $ 180,654  
    


 


 


 


 


EBITDA(8)

   $ 78,666     $ 96,963     $ 106,631     $ 109,288     $ 117,146  

Distributable Cash Flow(8)

   $ 14,058     $ 55,415     $ 61,055     $ 65,182     $ 72,378  

 

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     Predecessor

   Partnership
and
Predecessor


   Partnership

     Year Ended December 31,

     2001

   2002(1)

   2003(2)

   2004(3)

   2005(4)

     (in thousands, except per unit and operating data)

Balance Sheet Data (at period end):

                                  

Net properties, plants and equipment

   $ 566,359    $ 573,514    $ 583,164    $ 647,200    $ 814,836

Total assets

   $ 789,201    $ 1,093,880    $ 1,181,006    $ 1,368,786    $ 1,680,685

Total debt

   $ 144,781    $ 317,445    $ 313,136    $ 313,305    $ 355,573

Total Partners’ Capital/ Net parent investment

   $ 274,893    $ 383,033    $ 403,758    $ 460,594    $ 523,411

Operating Data (bpd):

                                  

Eastern Pipeline System total shipments (in thousands of barrel miles per day)(9)

     55,198      56,768      55,324      59,173      56,907

Terminal Facilities throughput (bpd)

     1,156,927      1,182,784      1,204,394      1,464,254      1,549,427

Western Pipeline System throughput(9) (bpd)

     287,237      286,912      304,471      298,797      356,129

Crude oil purchases at wellhead (bpd)

     174,182      189,277      193,176      186,827      186,224

(1) On November 15, 2002, the Partnership acquired a 31.5 percent interest in Wolverine Pipe Line Company, a 9.2 percent interest in West Shore Pipe Line Company, a 14.0 percent interest in Yellowstone Pipe Line Company, and a 43.8 percent equity interest in West Texas Gulf Pipe Line Company. The aggregate purchase price of $64.6 million for these acquisitions is included within the 2002 expansion capital expenditures.
(2) On September 30, 2003, the Partnership acquired an additional 3.1 percent ownership interest in West Shore for $3.7 million. The purchase price for this acquisition is included within the 2003 expansion capital expenditures.
(3) During the year ended December 31, 2004, the Partnership completed the following acquisitions: the Eagle Point logistics assets were purchased for $20.0 million on March 30, 2004; two refined product terminals located in Baltimore, Maryland and Manassas, Virginia were purchased for $12.0 million on April 28, 2004; an additional 33.3 percent undivided interest in the Harbor pipeline was acquired on June 28, 2004 for $7.3 million; and a refined product terminal located in Columbus, Ohio was purchased for $8.0 million on November 30, 2004. The aggregate purchase price for these acquisitions is included within the 2004 expansion capital expenditures.
(4) Expansion capital expenditures in 2005 includes $100.0 million related to the August 1, 2005 acquisition of the Corsicana to Wichita Falls, Texas crude oil pipeline system and storage facilities, and $5.5 million related to the December 2005 acquisition of an undivided joint interest in the Mesa Pipe Line. The total purchase price of the Mesa interest was $6.6 million, however since a portion of the interest was acquired from a related party, it was recorded by the Partnership at Sunoco’s historical cost and the $1.1 million difference between the purchase price and the cost basis of the assets was recorded by the Partnership as a capital distribution.
(5) Includes equity income from the investments in the following joint ventures: Explorer Pipeline Company, Wolverine Pipe Line Company, West Shore Pipe Line Company, Yellowstone Pipe Line Company, and West Texas Gulf Pipe Line Company. Equity income from these investments has been included based on the Partnership’s respective ownership percentages of each, and from the dates of acquisition forward.
(6) 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.
(7)

Cash distributions paid per unit to limited partners represent payments made per unit during the period stated. Cash distributions declared per unit to limited partners represent distributions declared per unit for

 

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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.

(8) EBITDA and distributable cash flow provides additional information for evaluating the Partnership’s ability to make distributions to its unitholders and the general partner. The following table reconciles the difference between operating income, as determined under United States generally accepted accounting principles, and EBITDA and distributable cash flow (in thousands):

 

     Year Ended December 31,

 
     2001

    2002

    2003

    2004

    2005

 

Operating income

   $ 53,341     $ 65,629     $ 79,474     $ 77,355     $ 83,308  

Depreciation and amortization

     25,325       31,334       27,157       31,933       33,838  
    


 


 


 


 


EBITDA

     78,666       96,963       106,631       109,288       117,146  

Interest expense, net

     (10,980 )     (17,299 )     (20,040 )     (20,324 )     (21,599 )

Maintenance capital expenditures

     (53,628 )     (27,934 )     (30,850 )     (30,829 )     (31,194 )

Sunoco reimbursements

     —         3,685       5,314       7,047       8,025  
    


 


 


 


 


Distributable cash flow

   $ 14,058     $ 55,415     $ 61,055     $ 65,182     $ 72,378  
    


 


 


 


 


 

Management of the Partnership believes EBITDA and distributable cash flow information enhances an investor’s understanding of a business’s ability to generate cash for payment of distributions and other purposes. In addition, EBITDA is also used as a measure in the Partnership’s $300 million revolving credit facility in determining its 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 and distributable cash flow do not represent and should not be considered alternatives to net income, operating income or cash flows from operating activities as determined under United States generally accepted accounting principles and may not be comparable to other similarly titled measures of other businesses.

 

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

 

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

 

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

 

Overview

 

The Partnership is a Delaware limited partnership formed on October 15, 2001 to acquire, own, and operate, a geographically diverse portfolio of complementary pipeline, terminalling, and crude oil acquisition and marketing assets.

 

The Partnership is engaged in the transport, terminalling, and storage of refined products and crude oil and in the purchase and sale of crude oil in 12 states located in the Northeast, Midwest and Southwest United States. Revenues are generated by charging tariffs for transporting refined products, crude oil and other hydrocarbons through the Partnership’s pipelines as well as by charging fees for storing refined products, crude oil and other hydrocarbons in, and for providing other services at, its terminals. Revenues are also generated by purchasing domestic crude oil and selling it to Sunoco R&M and other customers. Generally, as the Partnership purchases crude oil it simultaneously enters into corresponding sale transactions involving physical deliveries of crude oil, which enables it to secure a profit on the transaction at the time of purchase.

 

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Strategic Actions

 

The Partnership’s primary business strategies are to generate stable cash flows, increase pipeline and terminal throughput, pursue strategic and accretive acquisitions that complement the Partnership’s existing asset base, improve operating efficiencies, and increase its cash distributions to unitholders. As part of its strategy, the Partnership has undertaken several strategic initiatives, including:

 

2006 Acquisitions

 

    Millenium and Kilgore Pipeline Acquisition. On March 1, 2006, the Partnership purchased a Texas crude oil pipeline system from affiliates of Black Hills Energy, Inc. for approximately $40.9 million. The system consists of (a) the Millennium Pipeline, a 200-mile, 12-inch crude oil pipeline with 65,000 barrels per day operating capacity, originating near the Partnership’s Nederland Terminal, and terminating at Longview Texas; (b) the Kilgore Pipeline, a 190-mile, 10-inch crude oil pipeline with 35,000 barrel per day capacity originating in Kilgore, Texas and terminating at refineries in the Houston, Texas region; (c) approximately 340,000 shell barrels of active storage capacity at Kilgore, and Longview, Texas; (d) a lease acquisition marketing business; and (e) crude oil line fill and working inventory.

 

    Amdel and White Oil Pipeline Acquisition. On March 1, 2006, the Partnership acquired a Texas crude oil pipeline system from Alon USA Energy, Inc. for approximately $68.0 million. The system consists of (a) the Amdel Pipeline, a 503-mile, 10-inch common carrier crude oil pipeline with 27,000 barrels per day operating capacity, originating at the Nederland Terminal, and terminating at Midland, Texas, and (b) the White Oil Pipeline, a 25-mile, 10-inch crude oil pipeline with 40,000 barrels per day operating capacity, originating at the Amdel Pipeline and terminating at Alon’s Big Spring, Texas refinery. Alon has also agreed to ship a minimum of 15,000 barrels per day under a 10-year, throughput and deficiency agreement on the pipelines. These pipelines are currently idled and are scheduled to be returned to service on June 1, 2006. The Partnership also expects to complete a $12 million program to expand capacity on the Amdel Pipeline from 27,000 to 40,000 barrels per day, and to construct new tankage at the Nederland Terminal to service these new volumes by the end of 2006.

 

2005 Acquisitions

 

    Mesa Pipe Line System Interest Acquisition. On December 5, 2005, the Partnership purchased a subsidiary of Sunoco which owned a 7.2 percent undivided interest in the Mesa Pipe Line system for approximately $1.3 million. The Mesa Pipe Line system consists of an 80-mile, 24-inch crude oil pipeline from Midland, Texas to Colorado City, Texas, with an operating capacity of 316,000 barrels per day, and approximately 800,000 barrels of tankage at Midland. The Mesa pipeline connects to the West Texas Gulf pipeline, which supplies crude oil to the Mid-Valley pipeline. On December 29, 2005, the Partnership purchased an additional 29.8 percent interest in Mesa from Chevron for $5.3 million, increasing its combined interest to 37.0 percent.

 

    Corsicana to Wichita Falls Pipeline Acquisition. On August 1, 2005, the Partnership purchased, from an affiliate of Exxon Mobil Corporation, a crude oil pipeline system and storage facilities located in Texas for $100.0 million. The pipeline system consists primarily of a 187-mile, 16-inch pipeline with an operating capacity of 125,000 barrels per day. It originates at a crude oil terminal in Corsicana, Texas and terminates at Wichita Falls, Texas. The storage facilities include the Corsicana terminal, which has 2.9 million barrels of shell capacity for crude oil, and the Ringgold, Texas terminal, which consists of 0.5 million barrels of shell capacity for crude oil. In addition, the Partnership invested approximately $16.0 million to construct a new 20-mile pipeline to connect the Corsicana to Wichita Falls pipeline to the West Texas Gulf pipeline, in which the Partnership has a 43.8% ownership interest. Construction on the new 20-mile pipeline was completed in December 2005, and it is currently operational.

 

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2004 Acquisitions

 

    Columbus Terminal Acquisition. On November 30, 2004, the Partnership acquired a refined products terminal located in Columbus, Ohio for approximately $8.0 million. The terminal is connected to a third-party, refined product, common carrier pipeline and includes 6 refined product tanks with approximately 160,000 barrels of working storage capacity, located on 13 acres; two truck racks for shipping gasoline, distillate fuels, and ethanol via tanker truck; and rail siding access for 4 rail cars for ethanol handling.

 

    Harbor Pipeline Interest Acquisition. On June 28, 2004, the Partnership purchased an additional 33.3 percent undivided interest in the Harbor pipeline for $7.3 million. The Harbor pipeline is an 80-mile, 180,000 bpd refined product, common carrier pipeline originating near Woodbury, New Jersey and terminating in Linden, New Jersey. As a result of this transaction, the Partnership increased its undivided ownership interest to 66.7 percent and continues to operate the pipeline.

 

    Baltimore and Manassas Terminals Acquisition. On April 28, 2004, the Partnership purchased two refined product terminals located in Baltimore, Maryland and Manassas, Virginia for $12.0 million. The Baltimore terminal is connected to a third-party, refined product, common carrier pipeline and includes 13 refined product tanks with approximately 646,000 barrels of working storage capacity, located on 35 acres; one truck rack for shipping gasoline and distillate fuels via tanker truck; and one marine dock with two berths for receiving refined products. The Manassas terminal is connected to a third-party, refined product, common carrier pipeline and includes 7 refined product tanks with approximately 277,000 barrels of working storage capacity, located on 11 acres, and one truck rack for shipping gasoline and distillate fuels via tanker truck.

 

    Eagle Point Logistics Assets Acquisition. On March 30, 2004, the Partnership acquired the Eagle Point refinery logistics assets from Sunoco R&M for $20 million. The Eagle Point logistics assets consist of a crude oil and refined product ship and barge dock, a refined product truck rack, and a 4.5 mile, refined product pipeline from the Eagle Point refinery to the origin of the Harbor pipeline. In connection with the acquisition, the Partnership entered into a throughput agreement with Sunoco R&M whereby they have agreed to minimum volumes on the truck rack upon completion of certain capital improvements, which were completed during the fourth quarter of 2004.

 

2003 Acquisitions

 

    West Shore Pipe Line Company Interest Acquisition. 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.

 

Internal Expansion Program

 

In December 2005, the Partnership announced approximately $99.0 million in internal expansion capital projects planned for 2006 and 2007. This expansion program includes primarily the construction of new tanks and pipeline connections in the Eastern and Western Pipeline systems, new tankage at the Nederland Terminal, expansion of the Marysville crude oil pipeline, and installation of ethanol blending and ultra-low sulfur diesel infrastructure at certain refined product terminals. The internal expansion program is expected to provide approximately $28 million in incremental pre-financing cash flows by the end of 2007, consisting of approximately $37 million in revenues, less $9 million of direct operating expenses, and excluding indirect costs and costs of debt or equity financing.

 

Conservative Capital Structure

 

The Partnership maintained a conservative capital structure and substantial liquidity. In December 2005, the Partnership amended its Credit Facility, which expanded its size to $300 million and extended the maturity to

 

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2010. (See “Liquidity and Capital Resources” for further information.). The Partnership also completed a series of equity issuances during 2004 and 2005, through which it issued an aggregate of 7.8 million limited partner units, generating $288.4 million of net proceeds. Proceeds from these equity issues were used to redeem 5.0 million limited partner units owned by Sunoco and to repay a portion of the debt incurred to fund its acquisitions.

 

Cash Distribution Increases

 

As a result of the above initiatives, the general partner was able to increase the cash distributions to limited partners in all but one quarter during each of the three years ended December 31, 2005. The fourth quarter 2005 distribution of $0.7125 per common and subordinated partnership unit, ($2.85 annualized), paid in February 2006, represents a 14% increase over the fourth quarter 2004 distribution, and a 30% increase over the fourth quarter 2003 distribution.

 

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Results of Operations

 

     Year Ended December 31,

     2003

   2004

   2005

     (in thousands)

Statements of Income

      

Sales and other operating revenue:

                    

Affiliates

   $ 1,383,090    $ 1,751,612    $ 1,986,019

Unaffiliated customers

     1,274,383      1,699,673      2,496,593

Other income

     16,730      13,932      14,295
    

  

  

Total revenues

     2,674,203      3,465,217      4,496,907
    

  

  

Cost of products sold and operating expenses

     2,519,160      3,307,480      4,326,713

Depreciation and amortization

     27,157      31,933      33,838

Selling, general and administrative expenses

     48,412      48,449      53,048
    

  

  

Total costs and expenses

     2,594,729      3,387,862      4,413,599
    

  

  

Operating income

     79,474      77,355      83,308

Net interest expense

     20,040      20,324      21,599
    

  

  

Net income

   $ 59,434    $ 57,031    $ 61,709
    

  

  

Segment Operating Income:

                    

Eastern Pipeline System

                    

Sales and other operating revenue:

                    

Affiliate

   $ 72,533    $ 72,500    $ 75,570

Unaffiliated customers

     21,628      24,939      21,096

Other income

     12,147      11,701      11,773
    

  

  

Total revenues

     106,308      109,140      108,439
    

  

  

Operating expenses

     40,000      45,769      47,046

Depreciation and amortization

     10,630      11,005      10,509

Selling, general and administrative expenses

     18,560      18,077      18,560
    

  

  

Total costs and expenses

     69,190      74,851      76,115
    

  

  

Operating income

   $ 37,118    $ 34,289    $ 32,324
    

  

  

Terminal Facilities

                    

Sales and other operating revenue:

                    

Affiliates

   $ 60,060    $ 71,203    $ 78,885

Unaffiliated customers

     31,608      34,749      34,880

Other income

     1,146      16      79
    

  

  

Total revenues

     92,814      105,968      113,844
    

  

  

Operating expenses

     38,521      45,011      48,571

Depreciation and amortization

     10,925      15,115      15,054

Selling, general and administrative expenses

     12,913      13,036      14,429
    

  

  

Total costs and expenses

     62,359      73,162      78,054
    

  

  

Operating income

   $ 30,455    $ 32,806    $ 35,790
    

  

  

Western Pipeline System

                    

Sales and other operating revenue:

                    

Affiliates

   $ 1,250,497    $ 1,607,909    $ 1,831,564

Unaffiliated customers

     1,221,147      1,639,985      2,440,617

Other income

     3,437      2,215      2,443
    

  

  

Total revenues

     2,475,081      3,250,109      4,274,624
    

  

  

Cost of products sold and operating expenses

     2,440,639      3,216,700      4,231,096

Depreciation and amortization

     5,602      5,813      8,275

Selling, general and administrative expenses

     16,939      17,336      20,059
    

  

  

Total costs and expenses

     2,463,180      3,239,849      4,259,430
    

  

  

Operating income

   $ 11,901    $ 10,260    $ 15,194
    

  

  

 

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Operating Highlights

 

     Year Ended December 31,

     2003

   2004

   2005

Eastern Pipeline System(1):

              

Total shipments (barrel miles per day)(2)

   55,323,880    59,173,047    56,906,896

Revenue per barrel mile (cents)

   0.466    0.450    0.469

Terminal Facilities:

              

Terminal throughput (bpd):

              

Refined product terminals

   283,071    340,675    389,523

Nederland Terminal

   441,701    487,828    457,655

Fort Mifflin Terminal Complex

   322,389    336,555    327,156

Marcus Hook Tank Farm

   157,233    144,724    149,934

Eagle Point Dock(3)

   —      204,105    225,159

Western Pipeline System(1) (4):

              

Crude oil pipeline throughput (bpd)

   304,471    298,797    356,129

Crude oil purchases at wellhead (bpd)

   193,176    186,827    186,224

Gross margin per barrel of pipeline throughput (cents)(5)

   22.9    23.2    25.7

(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) Acquired on March 30, 2004. Amount for 2004 represents throughput for the period from the date of acquisition through December 31, 2004, divided by the number of days in that period.
(4) Includes results from the Corsicana to Wichita Falls, Texas crude oil pipeline system from the date of acquisition, August 1, 2005.
(5) Represents total segment sales and other operating revenue minus cost of products sold and operating expenses and depreciation and amortization divided by crude oil pipeline throughput.

 

Analysis of Consolidated Net Income

 

Net income was $59.4 million, $57.0 million and $61.7 million for the years ended December 31, 2003, 2004 and 2005, respectively.

 

The $4.7 million increase in net income from 2004 to 2005 was primarily the result of higher pipeline volumes in the Western Pipeline System and higher refined product terminal volumes. Partially offsetting these increases were $5.3 million in lost operating income and additional costs as a result of Hurricane Rita (see discussion below), higher insurance costs related to $2.5 million in special assessments by one of the Partnership’s insurers as a result of Hurricanes Rita and Katrina, and $2.0 million of costs related to the relocation of the Western area headquarters from Tulsa, Oklahoma to Sugar Land, Texas.

 

On September 24, 2005, Hurricane Rita damaged the Partnership’s Nederland Terminal facility and a portion of the Western Pipeline System, impacting several storage tanks, dock facilities, buildings and equipment. Although the Nederland Terminal resumed operations on October 3, 2005, the business was impacted for a few weeks as a result of interruptions in customer and supplier business activities related to the Hurricane. The estimated lost operating income and additional costs in 2005 attributed to the Hurricane totaled $5.3 million. The Partnership will incur additional costs in 2006 to repair its damaged facilities, and expects to negotiate a settlement with its insurance carrier for reimbursement of a portion of its costs during 2006.

 

The $2.4 million decrease in net income from 2003 to 2004 was primarily the result of higher Eastern Pipeline System and Terminal Facilities operating and maintenance expenses, lower volumes at the Eastern Pipeline System as a result of turnarounds at Sunoco, Inc.’s Toledo refinery in March 2004 and Marcus Hook

 

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refinery in September 2004, higher depreciation and amortization due to accelerating depreciation expense related to certain refined product terminal system assets, the absence in 2004 of a gain on settlement of a claim at the Nederland Terminal, lower equity income from the corporate joint venture interests, and costs related to complying with Sarbanes-Oxley. Partially offsetting these items were higher revenues from the Terminal Facilities and Eastern Pipeline System and the operating results from the acquisitions completed during 2004.

 

Net interest expense was $21.6 million for the year ended December 31, 2005, a $1.3 million increase from the prior year. Increased interest expense due to higher interest rates and a $42.1 million increase in the amount drawn under the Credit Facility was partially offset by $0.5 million in capitalized interest. The increased borrowings were used to partially fund the 2005 acquisitions of the Texas crude oil pipeline system and storage facilities and the interest in the Mesa Pipe Line system, as well as to fund construction of a new 20-mile pipeline to connect the newly acquired Corsicana to Wichita Falls, Texas crude oil pipeline system to the West Texas Gulf pipeline. Net interest expense was $20.3 million for the year ended December 31, 2004, a $0.3 million increase from the previous year due principally to a decrease in capitalized interest.

 

Analysis of Segment Operating Income

 

Year Ended December 31, 2005 versus Year Ended December 31, 2004

 

Eastern Pipeline System

 

Operating income for the Eastern Pipeline System was $32.3 million for the year ended December 31, 2005 compared with $34.3 million for the prior year. The $2.0 million decrease was the result of a $0.7 million decrease in total revenues and a $1.3 million increase in operating expenses. Total revenues decreased to $108.4 million for the year ended December 31, 2005 from $109.1 million for the prior year due mainly to lower shipments on the Marysville to Toledo crude oil pipeline caused by production issues at two third-party Canadian synthetic crude oil plants during the first three quarters of 2005, partially offset by a full year’s results in 2005 from the acquisition of an additional one-third interest in the Harbor pipeline in June 2004. Operating expenses increased from $45.8 million in 2004, to $47.0 million for 2005 due mainly to higher pipeline maintenance activity. The Partnership has completed most of the initial repairs required under the extensive pipeline integrity management program it implemented in 2002 as a result of Department of Transportation requirements, and therefore expects its repair costs associated with pipeline maintenance to decrease beginning in 2006. Selling, general and administrative expenses increased due mainly to the allocation of a portion of the special insurance assessments discussed above.

 

Terminal Facilities

 

The Terminal Facilities business segment experienced an increase in operating income to $35.8 million for the year ended December 31, 2005 compared with $32.8 million for the prior year. This increase was due mainly to a $7.8 million increase in sales and other operating revenue, partially offset by a $4.9 million increase in total costs and expenses. The increase in sales and other operating revenue to $113.8 million for 2005 compared with $106.0 million for the prior year was principally due to a full year’s results in 2005 from the acquisitions of the Eagle Point terminal assets located in Westville, New Jersey, and the three refined product terminals located in Baltimore, Maryland; Manassas, Virginia; and Columbus, Ohio during 2004, as well as an increase in the Nederland Terminal’s volumes despite the adverse impact of Hurricane Rita.

 

The increase in total costs and expenses was due mainly to a $3.6 million increase in operating expenses and a $1.4 million increase in selling, general and administrative expenses. Operating expenses increased in 2005 due principally to the assets acquired in 2004. Selling, general and administrative expenses increased due mainly to the allocation of a portion of the special insurance assessments discussed above.

 

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Western Pipeline System

 

Operating income for the Western Pipeline System was $15.2 million for the year ended December 31, 2005 compared with $10.3 million for the prior year. The $4.9 million increase was primarily the result of an increase in crude oil pipeline volumes, partially offset by lower crude oil sales and marketing results, a $2.5 million increase in depreciation and amortization and a $2.7 million increase in selling, general and administrative costs. The increase in pipeline volumes was due to volumes from the Corsicana to Wichita Falls, Texas crude oil pipeline acquisition and higher volumes on the Nederland to Longview, Texas pipeline. Sales and other operating revenue and cost of products sold and operating expenses increased for the year ended December 31, 2005 compared with the prior year due principally to an increase in crude oil prices. Depreciation and amortization increased by $2.5 million in 2005 due principally to the Corsicana to Wichita Falls crude oil pipeline acquisition. Selling, general and administrative expenses increased due to the allocation of a portion of the special insurance assessments discussed above and $2.0 million of costs related to the Western area headquarters’ relocation from Tulsa to Sugar Land.

 

Year Ended December 31, 2004 versus Year Ended December 31, 2003

 

Eastern Pipeline System

 

Operating income for the Eastern Pipeline System was $34.3 million for the year ended December 31, 2004 compared with $37.1 million for the prior year. The $2.8 million decrease was the result of a $5.7 million increase in total costs and expenses and a $0.4 million decrease in other income, partially offset by a $3.3 million increase in sales and other operating revenue. Sales and other operating revenue increased to $97.4 million for 2004 as a result of an increase in total shipments, partially offset by lower revenue per barrel mile. The increase in shipments was primarily the result of higher refined product throughput on the Harbor pipeline due to the acquisition of the additional one-third ownership interest and higher crude oil throughput on the Marysville to Toledo pipeline, partially offset by a decline in volumes as a result of planned turnarounds at Sunoco, Inc.’s Toledo refinery in March 2004 and Marcus Hook refinery in September 2004. The decrease in other income to $11.7 million for 2004 was due to lower equity income from the interests in corporate joint ventures. The increase in total costs and expenses to $74.9 million for 2004 from $69.2 million for the prior year was principally due to an increase in scheduled maintenance costs, the inclusion of an additional one-third ownership interest in the Harbor pipeline, and higher fuel and power costs associated with the increase in volumes.

 

Terminal Facilities

 

The Terminal Facilities business segment experienced a $2.3 million increase in operating income to $32.8 million for the year ended December 31, 2004 compared with $30.5 million for the prior year. This increase was due mainly to a $14.3 million increase in sales and other operating revenue, partially offset by a $10.8 million increase in total costs and expenses and a $1.1 million decrease in other income. The increase in sales and other operating revenue to $106.0 million for 2004 compared with $91.7 million for the prior year was principally due to the acquisitions completed during 2004, an increase in the Nederland Terminal’s volumes, and higher volumes at the refined product terminals and the Fort Mifflin Terminal Complex. The Nederland Terminal’s volumes increased from the prior year due to a full year’s utilization in 2004 of two new tanks constructed in 2003 and higher utilization of tankage caused by improved market conditions for crude oil imports. Other income decreased $1.1 million from the prior year due mainly to the prior year gain recognized on the settlement of a claim at the Nederland Terminal.

 

The increase in total costs and expenses was due mainly to a $6.5 million increase in operating expenses and a $4.2 million increase in depreciation and amortization. Operating expenses increased to $45.0 million for 2004 from $38.5 million for the prior year due principally to expenses associated with the acquired assets, non-routine dredging activity on the Delaware River at the Fort Mifflin Terminal docks, and an increase in scheduled tank maintenance costs at the Nederland Terminal and the refined product terminals. Depreciation and amortization increased to $15.1 million for 2004 due primarily to accelerating depreciation of certain refined product terminal assets mentioned previously and depreciation on the assets acquired.

 

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Western Pipeline System

 

Operating income for the Western Pipeline System was $10.3 million for the year ended December 31, 2004 compared with $11.9 million for the prior year. The $1.6 million decrease was primarily the result of a $1.2 million decrease in other income. Sales and other operating revenue and cost of products sold and operating expenses increased for the year ended December 31, 2004 compared with the prior year due principally to an increase in crude oil prices, partially offset by a decline in lease acquisition and bulk volumes mentioned previously. Other income decreased to $2.2 million for 2004 due mainly to lower equity income from the interest in West Texas Gulf Pipe Line due to a decline in demand for domestic crude oil transported on this pipeline from the prior year and the temporary shutdown of a significant connecting pipeline due to planned refinery turnarounds during the first half of 2004.

 

Liquidity and Capital Resources

 

Liquidity

 

Cash generated from operations and borrowings under the Credit Facility are the Partnership’s primary sources of liquidity. At December 31, 2005, the Partnership had a working capital deficit of $8.8 million and available borrowing capacity under the Credit Facility of $193.4 million. 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, the Partnership would have had working capital of $85.7 million at December 31, 2005.

 

Capital Resources

 

The Partnership periodically supplements its cash flows from operations with proceeds from debt and equity financing activities.

 

Credit Facility

 

On December 1, 2005, Sunoco Logistics Partners Operations L.P., a wholly-owned subsidiary of the Partnership (the “Operating Partnership”), amended the November 22, 2004, Credit Facility to increase the commitment amount from $250 million to $300 million, and extend the term by one year to November 22, 2010. At December 31, 2004, there was $64.5 million outstanding under the Credit Facility. On August 1, 2005, an additional $75.0 million was drawn against the Credit Facility which was used, along with $25.0 million of cash, to fund the acquisition of the Corsicana to Wichita Falls, Texas crude oil pipeline system and related storage facilities. The proceeds from the equity offering completed in September 2005 were used principally to repay $56.5 million of the additional indebtedness, reducing the total amount outstanding under the Credit Facility to $83.0 million. In December 2005, the Partnership drew an additional $23.6 million against the Credit Facility to fund the construction of a new 20-mile pipeline to connect the newly acquired Corsicana to Wichita Falls crude oil pipeline system to the West Texas Gulf pipeline, and the acquisitions of a 37.0 percent undivided interest in the Mesa Pipe Line system. The amount outstanding under the Credit Facility at December 31, 2005 totaled $106.6 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.

 

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.

 

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Indebtedness under the Credit Facility bears 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 Citibank prime rate (each plus the applicable margin). The interest rate on the borrowings outstanding under the Credit Facility as of December 31, 2005 was 4.74 percent. Additionally, certain fees are incurred in connection with the Credit Facility.

 

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 requiring the maintenance, on a rolling-four-quarter basis, of:

 

    a maximum ratio of 4.75 to 1 of consolidated total debt to consolidated EBITDA (each as defined in the credit agreement), which can be increased to 5.25 to 1 during an acquisition period (as defined in the credit agreement); and

 

    an interest coverage ratio (as defined in the credit agreement) of at least 3.0 to 1.

 

For the year ended December 31, 2005, the Partnership’s ratio of total debt to EBITDA was 2.9 to 1 and the interest coverage ratio was 5.2 to 1.

 

Equity Offerings

 

In August 2005, the Partnership sold 1.5 million common units in a public offering. In September 2005, the Partnership sold an additional 125,000 common units to cover over-allotments in connection with the August 2005 sale. The total sale of units resulted in total gross proceeds of $63.4 million, and net proceeds of $60.4 million, after the underwriters’ commission and legal, accounting and other transaction expenses. Net proceeds of the sale were used to repay $56.5 million of the debt incurred to finance the August 1, 2005 purchase of a Texas crude oil pipeline system and storage facilities, with the balance for general partnership purposes. As a result of this issuance of 1.625 million common units, the general partner contributed $1.3 million to the Partnership to maintain its 2.0 percent general partner interest.

 

In May 2005, the Partnership sold 2.5 million common units in a public offering. In June 2005, the Partnership sold an additional 275,000 common units to cover over-allotments in connection with the May 2005 sale. The purchase price for the over-allotment was equal to the offering price in the May 2005 sale. The sale of units resulted in total gross proceeds of $104.1 million, and net proceeds of $99.2 million, after underwriters’ commissions and legal, accounting and other transaction expenses. Net proceeds from the sale were used to redeem 2.775 million common units owned by Sunoco at a redemption price per unit equal to the public offering price per unit after the underwriters’ commissions.

 

On April 7, 2004, the Partnership sold 3.4 million common units in a public offering for total gross proceeds of $135.1 million. The sale of the units resulted in net proceeds of $128.7 million, after underwriters’ commissions and legal, accounting, and other transaction expenses. Net proceeds from the sale were used to (a) redeem approximately 2.2 million common units from Sunoco for $82.7 million, (b) replenish cash utilized to acquire the Eagle Point logistics assets for $20.0 million, (c) finance the acquisition of two refined product terminals for $12.0 million, (d) finance the acquisition of an additional 33.3 percent undivided interest in the Harbor pipeline for $7.3 million, and (e) for general partnership purposes, including to replenish cash used for past acquisitions and capital improvements, and for other expansion, capital improvements and acquisition projects. As a result of this net issuance of 1.2 million common units, the general partner contributed $1.0 million to the Partnership to maintain its 2.0 percent general partner interest.

 

Shelf Registration Statement

 

On December 21, 2005, the Partnership, the Operating Partnership, and the Operating Partnership’s wholly-owned subsidiaries, as co-registrants, filed a shelf registration statement with the Securities and Exchange

 

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Commission. This shelf registration, if and when declared effective by the SEC, will permit the periodic offering and sale of up to $500 million of equity securities by the Partnership or debt securities of the Operating Partnership (guaranteed by the Partnership). The shelf registration statement also covers the resale of up to five million common units by the Partnership’s general partner. This shelf registration statement, if and when effective, will replace the March 2003 shelf registration statement previously filed. As of December 31, 2005, $197.4 remains available for issuance under the March 2003 shelf registration statement. 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).

 

Cash Flows and Capital Expenditures

 

Net cash provided by operating activities for the years ended December 31, 2003, 2004 and 2005 was $97.2 million, $106.6 million and $90.8 million, respectively. Net cash provided by operating activities for 2005 consists primarily of net income of $61.7 million, depreciation and amortization of $33.8 million, and a decrease in working capital of $6.2 million. Net cash provided by operating activities for 2004 consists primarily of net income of $57.0 million, depreciation and amortization of $31.9 million, and a decrease in working capital of $13.5 million. Net cash provided by operating activities for 2003 consists primarily of net income of $59.4 million, depreciation and amortization of $27.2 million, and a decrease in working capital of $5.3 million. The decrease in net cash provided by operating activities from 2004 to 2005 and the increase in net cash provided by operating activities from 2003 to 2004 were primarily attributable to changes in working capital due to fluctuations in the price of crude oil and timing of operating cash receipts and disbursements.

 

Net cash used in investing activities for the years ended December 31, 2003, 2004, and 2005 was $39.0 million, $95.6 million and $180.7 million, respectively. The increases in cash used in investing activities from 2003 to 2004 and from 2004 to 2005 are due to acquisitions and organic growth projects. Capital expenditures (excluding acquisitions) were $37.4 million in 2003, $46.4 million in 2004, and $73.3 million in 2005 (see “Capital Requirements” below).

 

Net cash used for acquisitions was $3.7 million in 2003, $49.2 million in 2004, and $107.3 million in 2005. Acquisitions completed in 2005 include the Corsicana to Wichita Falls, Texas crude oil pipeline system and storage facilities for $100.0 million and a 37.0 percent undivided joint interest in the Mesa Pipe Line system for $6.6 million. During 2004, the Partnership completed the following acquisitions: the Eagle Point logistics assets, which were purchased for $20.0 million; two refined product terminals located in Baltimore, Maryland and Manassas, Virginia, which were purchased for $12.0 million; an additional 33.3 percent undivided interest in the Harbor pipeline, which was acquired for $7.3 million; and a refined product terminal located in Columbus, Ohio, which was purchased for approximately $8.0 million. During 2003, the Partnership acquired an additional 3.1 percent corporate joint venture interest in West Shore for $3.7 million.

 

Net cash provided by/ (used in) financing activities for the years ended December 31, 2003, 2004, and 2005 was ($42.0) million, ($8.5) million and $58.8 million, respectively.

 

For the year ended December 31, 2005, the Partnership received $60.4 million of net proceeds from the public offering completed in September 2005, net borrowings of $42.1 million drawn against the Credit Facility to fund the acquisitions of an undivided joint interest in the Mesa Pipe Line system and a portion of the Corsicana to Wichita Falls, Texas crude oil pipeline system and storage facilities, and the related pipeline construction. Additionally, the Partnership received $8.0 million of capital contributions for reimbursement of certain maintenance capital expenditures and operating expenses under agreements with Sunoco, and $18.1 million as a result of a reduction in advances to affiliates. The net proceeds from these sources were partially offset by $67.3 million in distributions paid to limited partners and the general partner in 2005.

 

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For the year ended December 31, 2004, the $8.5 million of net cash used in financing activities was due to the $82.7 million redemption of approximately 2.2 million common units from Sunoco, $57.5 million of cash distributions paid to the limited partners and general partner, and net advances to affiliate of $5.1 million, partially offset by $128.7 million of net proceeds from the sale of 3.4 million common units in April 2004, $7.0 million of capital contributions for reimbursement of certain maintenance capital expenditures and operating expenses under agreements with Sunoco, and a $1.0 million net contribution from the general partner to maintain its 2.0 percent ownership interest after the sale of common units.

 

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 limited partners 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.

 

Under a treasury services agreement with Sunoco, the Partnership participates in Sunoco’s centralized cash management program. Advances to affiliates in the Partnership’s balance sheets at December 31, 2004 represent amounts due from Sunoco under this agreement, and advances from affiliates in the balance sheet at December 31, 2005 represent amounts due to Sunoco under the agreement.

 

Capital Requirements

 

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

 

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

 

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

 

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

 

     Year Ended December 31,

 
     2003

    2004

    2005

 
     (in thousands of dollars)  

Maintenance

   $ 30,850     $ 30,829     $ 31,194  

Expansion

     10,226 (1)     64,754 (2)     149,460 (3)
    


 


 


Total

   $ 41,076     $ 95,583     $ 180,654  
    


 


 



(1) Includes the acquisition of an additional interest in one of its corporate joint venture pipeline interests for $3.7 million.
(2) Includes the following acquisitions: $20.0 million for the Eagle Point logistics assets; $12.0 million for two refined product terminals located in Baltimore, Maryland and Manassas, Virginia; $7.3 million for an additional 33.3 percent undivided interest in the Harbor pipeline; and $8.0 million for a refined product terminal located in Columbus, Ohio.
(3) Includes $100.0 million related to the acquisition of the Corsicana to Wichita Falls, Texas crude oil pipeline system and storage facilities and $5.5 million for the undivided joint interest in the Mesa Pipe Line system. The total purchase price of the Mesa interest was $6.6 million, however since a portion of the interest was acquired from a related party, it was recorded by the Partnership at Sunoco’s historical cost and the $1.1 million difference between the purchase price and the cost basis of the assets was recorded by the Partnership as a capital distribution.

 

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Maintenance capital expenditures primarily consist of recurring expenditures at each of the business segments such as pipeline integrity costs, pipeline relocations, repair and upgrade of field instrumentation, including measurement devices, repair and replacement of tank floors and roofs, upgrades of cathodic protection systems, crude trucks and related equipment, and the upgrade of pump stations. In addition to these recurring projects, maintenance capital includes certain expenditures for which the Partnership received reimbursement from Sunoco R&M under the terms of agreements between the parties (see “Agreements with Sunoco R&M and Sunoco, Inc.”). The year ended December 31, 2003 also includes $1.8 million of expenditures to replace assets at the Nederland Terminal as a result of 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. Management expects maintenance capital expenditures to be approximately $27.0 million in 2006, including approximately $2.0 million related to the Western area headquarters relocation from Tulsa to Sugar Land, and excluding reimbursements from Sunoco R&M in accordance with the terms of certain agreements.

 

Expansion capital expenditures include $3.7 million, $49.2 million, and $107.3 million in the years ended December 31, 2003, 2004 and 2005, respectively related to the acquisitions discussed above.

 

Expansion capital expenditures for the year ended December 31, 2005 also include construction of a new 20-mile pipeline to connect the newly acquired Corsicana to Wichita Falls, Texas crude oil pipeline system to the West Texas Gulf pipeline, completed in December 2005; construction at the Nederland Terminal of two new crude oil storage tanks with total capacity of approximately 1.0 million barrels, expected to be completed in 2006; and installation of ethanol blending facilities at a number of refined product terminals, also expected to be completed in 2006. Expansion capital expenditures for 2004 also include multiple pipeline connections and new truck stations, and expansion capital expenditures for 2003 also include 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.

 

Management expects to invest approximately $99.0 million in internal expansion capital projects in 2006 and 2007. This internal expansion program includes primarily the construction of new tanks and pipeline connections in the Eastern and Western Pipeline systems, new tankage at the Nederland Terminal, expansion of the Marysville crude oil pipeline, and installation of ethanol blending and ultra-low sulfur diesel infrastructure at certain refined product terminals.

 

Additionally, the $40.9 million acquisition of the Millennium and Kilgore pipeline system and the $68.0 million acquisition of the Amdel and White Oil pipeline system, each located in Texas, were completed in the first quarter of 2006. These acquisitions were funded with borrowings under the Partnership’s Credit Facility.

 

The Partnership expects to fund its capital expenditures, including any additional acquisitions, from cash provided by operations and, to the extent necessary, from the proceeds of borrowing under the Credit Facility, other borrowings and issuance of additional common units.

 

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Contractual Obligations

 

The following table sets forth the aggregate amount of long-term debt maturities (including interest commitments based upon the interest rate in effect at December 31, 2005), annual rentals applicable to noncancelable operating leases, and purchase commitments related to future periods at December 31, 2005 (in thousands of dollars):

 

     Year Ended December 31,

   Thereafter

   Total

     2006

   2007

   2008

   2009

   2010

     

Long-term debt:

                                                

Principal

   $ —      $ —      $ —      $ —      $ 106,600    $ 250,000    $ 356,600

Interest

     23,174      23,174      23,174      23,174      22,633      27,188      142,517

Operating leases

     3,157      3,020      2,669      2,204      1,980      7,359      20,389

Purchase obligations

     1,154,943      —        —        —        —        —        1,154,943
    

  

  

  

  

  

  

     $ 1,181,274    $ 26,194    $ 25,843    $ 25,378    $ 131,213    $ 284,547    $ 1,674,449
    

  

  

  

  

  

  

 

The Partnership’s operating leases reported above include leases of office space, third-party pipeline capacity, and other property and equipment, with initial or remaining noncancelable terms in excess of one year. On September 1, 2005, the Partnership executed an agreement to lease office space in Sugar Land, Texas for a term of approximately ten years. The lease terminates in November 2016.

 

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 noncancelable 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 2006. The remaining crude oil purchase obligation amounts are based on the quantities expected to be purchased for the remainder of the year, at December 31, 2005 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”.

 

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 10 to the financial statements included in Item 8. “Financial Statements and Supplementary Data.”

 

Under the terms of the Omnibus Agreement and in connection with the contribution of assets to the Partnership 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. See “Agreements with Sunoco R&M and Sunoco, Inc.”

 

For more information concerning environmental matters, please see Item 1. “Business—Environmental Regulation.”

 

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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.

 

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 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/Conflicts Committee of Sunoco Partners LLC’s Board of Directors.

 

The critical accounting policies identified by management of the Partnership are as follows:

 

Long-Lived Assets. The cost of properties, plants and equipment, less estimated salvage value, is generally depreciated on a straight-line basis over the estimated useful lives of the assets. Useful lives are based on historical experience and are adjusted when changes in planned use, technological advances or other factors indicate that a different life would be more appropriate. Changes in useful lives that do not result in the impairment of an asset are recognized prospectively. During 2004 and 2005, the Partnership accelerated the depreciation of assets related to equipment upgrade programs and the Western area headquarters’ move from Tulsa, Oklahoma to Sugar Land, Texas, based upon the estimated remaining useful lives of these assets until their replacement. The acceleration resulted in $1.8 million of additional depreciation expense recognized in 2004, $1.8 million in 2005, and will result in an additional $0.5 million of additional depreciation expense in 2006.

 

Long-lived assets are reviewed for impairment whenever events or circumstances indicate that the carrying amount of the assets may not be recoverable. Such events and circumstances include, among other factors: operating losses; unused capacity; market value declines; technological developments resulting in obsolescence; changes in demand for products manufactured by others utilizing 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 discussed under “Forward Looking Statements” in this document.

 

A long-lived asset is considered to be impaired when the undiscounted net cash flows expected to be generated by the asset are less than its carrying amount. Such estimated future cash flows are highly subjective and are based on numerous assumptions about future operations and market conditions. The impairment recognized is the amount by which the carrying amount exceeds the fair market value of the impaired asset. It is also difficult to precisely estimate fair market value because quoted market prices for the Partnership’s long-lived assets may not be readily available. Therefore, fair market value is generally based on the present values of

 

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estimated future cash flows using discount rates commensurate with the risks associated with the assets being reviewed for impairment.

 

There were no asset impairments for the years ended December 31, 2003, 2004 and 2005.

 

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, 2005, the Partnership’s accrual for environmental remediation activities was $0.6 million. This accrual is for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. The accrual is undiscounted and is based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. It is often extremely difficult to develop reasonable estimates of future site remediation costs due to changing regulations, changing technologies and their associated costs, and changes in the economic environment. In the above instances, if a range of probable environmental cleanup costs exists for an identified site, FASB Interpretation No. 14, “Reasonable Estimation of the Amount of a Loss” requires that the minimum of the range be accrued unless some other point or points in the range are more likely, in which case the most likely amount in the range is accrued. Engineering studies, historical experience and other factors are used to identify and evaluate remediation alternatives and their related costs in determining the estimated accruals for environmental remediation activities. Losses attributable to unasserted claims are also reflected in the accruals to the extent their occurrence is probable and reasonably estimable.

 

Management believes that none of the current remediation locations are material, individually or in the aggregate, to the Partnership’s financial position at December 31, 2005. 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 assets to the Partnership 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. 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. See “Agreements with Sunoco R&M and Sunoco, Inc.” for more information.

 

In summary, total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the technology available and needed to meet the various existing legal requirements, the nature and terms of cost sharing arrangements with other potentially responsible parties and the nature and extent of future environmental laws, inflation rates and the determination of the Partnership’s liability at the sites, if any, in the light of the number, participation level and financial viability of other parties.

 

New Accounting Pronouncements

 

For a discussion of recently issued accounting pronouncements requiring adoption subsequent to December 31, 2005, see Note 1 to the consolidated financial statements.

 

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Agreements with Sunoco R&M and Sunoco, Inc.

 

The Partnership has entered into several agreements with Sunoco, Inc., Sunoco R&M, and their affiliates as discussed below.

 

Pipelines and Terminals Storage and Throughput Agreement

 

Under this 2002 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 inland refined product terminals existing at the time of the agreement an amount of refined products that will produce at least $78.6 million of revenue for the contract year from March 1, 2005 to February 28, 2006, escalating at 1.67 percent each March 1 for the next two contract years. In addition, Sunoco R&M will pay the Partnership to transport on those refined product pipelines or throughput in those 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, 2005 and management of the Partnership expects Sunoco R&M to exceed the minimum amount under the agreement for the contract year from March 1, 2005 through February 28, 2006;

 

    receive and deliver at least 130,000 bpd of refined products per year at the Marcus Hook Tank Farm for five years ending February 28, 2007. 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, 2005, the Partnership received a fee of $0.1710 per barrel for the first 130,000 bpd and $0.0854 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, 2005 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, 2005 through February 28, 2006;

 

    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 ending March 31, 2009. For the calendar year ended December 31, 2005, the Partnership received a fee of $2.157 per barrel of committed storage, a fee of $0.216 per barrel for receipts greater than 975,734 barrels per contract year and a fee of $0.216 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, 2005 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, 2005 through March 31, 2006;

 

    receive and deliver at least 290,000 bpd of crude oil or refined products per contract year at the Fort Mifflin Terminal Complex for seven years ending February 28, 2009. This throughput is an annual amount for the contract period from March 1 to February 28 for the term of the agreement. For the year ended December 31, 2005, the Partnership received a fee of $0.1710 per barrel for the first 180,000 bpd and $0.0854 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, 2005 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, 2005 through February 28, 2006; and

 

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    transport or cause to be transported an aggregate of at least 140,000 bpd of crude oil per contract year on the Marysville to Toledo, Nederland to Longview, Cushing to Tulsa, Barnsdall to Tulsa, and Bad Creek to Tulsa crude oil pipelines at the published tariffs for a term of seven years ending February 28, 2009. This throughput is an annual amount for the contract period from March 1 to February 28 for the term of the agreement. Based upon the prorated minimum throughput amount noted, Sunoco R&M has exceeded the minimum throughput amount through December 31, 2005 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, 2005 through February 28, 2006.

 

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 certain states have already imposed MTBE bans, this has not had a material impact on Sunoco R&M’s obligations under the agreement to date.

 

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

 

There can be no assurance that Sunoco R&M will renew the pipelines and terminals storage and throughput agreement, or that, if renewed, the rates will be at or above the current rates. If 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, there can be no assurance that Sunoco R&M will continue to use the Partnership’s facilities or that additional revenues can be generated from third parties.

 

Sunoco R&M’s obligations under this agreement do not terminate if Sunoco, Inc. and its affiliates no longer own the general partner. This agreement may be assigned by Sunoco R&M only with the consent of the Audit/Conflicts Committee of the general partner’s board of directors.

 

Omnibus Agreement

 

In 2002, the Partnership entered into an Omnibus Agreement with Sunoco, Inc., Sunoco R&M, and the general partner that addresses the following matters:

 

    Sunoco R&M’s obligation to reimburse the Partnership for specified operating expenses and capital expenditures or otherwise to complete certain tank maintenance and inspection projects;

 

    the Partnership’s obligation to pay the general partner or Sunoco, Inc. an annual administrative fee for the provision by Sunoco, Inc. of certain general and administrative services;

 

    Sunoco, Inc.’s and its affiliates’ agreement not to compete with the Partnership under certain circumstances;

 

    the Partnership’s agreement to undertake to develop and construct or acquire an asset if requested by Sunoco, Inc.;

 

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

 

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    the Partnership’s obligation to indemnify Sunoco, Inc. and its affiliates for events and conditions associated with the operation of the assets that occur on or after the closing of the initial public offering and for environmental and toxic tort liabilities related to the assets to the extent Sunoco, Inc. is not required to indemnify the Partnership; and

 

    the Partnership’s option to purchase certain pipeline, terminalling, and storage assets retained by Sunoco, Inc. or its affiliates.

 

Reimbursement of Expenses and Completion of Certain Projects by Sunoco R&M. 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 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 required expenditures at the Marcus Hook Tank Farm and the Darby Creek Tank Farm to maintain compliance with existing industry standards and regulatory requirements, including: cathodic protection upgrades at these facilities; raising tank farm pipelines above ground level at these facilities; and repairing or demolishing two riveted tanks at the Marcus Hook Tank Farm.

 

The Partnership reports outlays for these programs as operating expenses or capital expenditures, as appropriate, in the financial statements. Capital expenditures are depreciated over their useful lives. Reimbursements by Sunoco R&M are reflected as capital contributions to Partners’ Capital within the Partnership’s balance sheets.

 

For the years ended December 31, 2003, 2004 and 2005, the Partnership was reimbursed $1.9 million, $2.1 million, and $7.0 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, 2005, the Partnership has received a cumulative reimbursement of $11.7 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 years ended December 31, 2003, 2004 and 2005, 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:

 

     Year Ended December 31,

     2003

   2004

   2005

     (in thousands of dollars)

Maintenance capital

   $ 2,982    $ 4,140    $ 885

Operating expenses

     467      540      —  
    

  

  

     $ 3,449    $ 4,680    $ 885
    

  

  

 

At December 31, 2005, the Partnership has received a cumulative reimbursement of $9.9 million relative to the $10.0 million maximum reimbursement for compliance expenditures at the Marcus Hook Tank Farm and the Darby Creek Tank Farm.

 

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General and Administrative Services Fee. Under the Omnibus Agreement, the Partnership pays Sunoco, Inc. or the general partner an annual administrative fee that includes expenses incurred by Sunoco, Inc. and its affiliates to perform centralized corporate functions, such as legal, accounting, treasury, engineering, information technology, insurance, and other corporate services, including the administration of employee benefit plans. This fee was $8.2 million, $8.4 million and $8.4 million for the years ended December 31, 2003, 2004 and 2005, respectively. This fee does not include the costs of shared insurance programs (which are allocated to the Partnership based upon its share of the cash premiums incurred), the salaries of pipeline and terminal personnel or other employees of the general partner (including senior executives), or the cost of their employee benefits. The Partnership has no employees, and reimburses Sunoco, Inc. and its affiliates for these costs and other direct expenses incurred on the Partnership’s behalf. In addition, the Partnership has incurred additional general and administrative costs which it pays directly.

 

The initial term of Section 4.1 of the Omnibus Agreement (which concerns the Partnership’s obligation to pay the annual fee for provision of certain general and administrative services) was through the end of 2004. The parties extended the term of Section 4.1 by one year each in January 2005 and January 2006. The 2006 annual fee decreased to $7.7 million, which reflects the Partnership directly incurring some of these general and administrative costs. These costs may be increased if the acquisition or construction of new assets or businesses require an increase in the level of general and administrative services received by the Partnership. There can be no assurance that Section 4.1 of the Omnibus Agreement will be extended beyond 2006, or that, if extended, the administrative fee charged by Sunoco will be at or below the current administrative fee. In the event that the Partnership is unable to obtain such services from Sunoco or other third parties at or below the current cost, the Partnership’s financial condition and results of operations may be adversely impacted.

 

In addition to the fees for the centralized corporate functions, selling, general and administrative expenses in the statements of income include the allocation of shared insurance costs of $2.7 million, $2.5 million and $5.1 million for the years ended December 31, 2003, 2004 and 2005, respectively. The insurance costs for the year ended December 31, 2005 include $2.5 million resulting from two special assessments by one of the Partnership’s insurers as a result of Hurricanes Rita and Katrina. The Partnership’s share of allocated Sunoco employee benefit plan expenses, including non-contributory defined benefit retirement plans, defined contribution 401(k) plans, employee and retiree medical, dental and life insurance plans, incentive compensation plans and other such benefits, was $20.6 million, $21.0 million, and $21.5 million for the years ended December 31, 2003, 2004 and 2005, respectively.

 

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

 

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

 

    any business currently operated by Sunoco, Inc. or any of its subsidiaries;

 

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

 

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

 

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    any business that Sunoco, Inc. or any of its subsidiaries acquires or constructs that has a fair market value of $5.0 million or more if the Partnership has been offered the opportunity to purchase the business for fair market value not later than six months after completion of such acquisition or construction, and the Partnership declines to do so with the concurrence of the Audit/Conflicts Committee.

 

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

 

Options to Purchase Assets Retained by Sunoco, Inc. The Omnibus Agreement also contains the terms under which the Partnership has the option to purchase Sunoco, Inc.’s direct or indirect interests in Mid-Valley Pipeline Company and Inland Corporation, as well as the Icedale pipeline, as discussed under “Business—Pipeline, Terminalling, and Storage Assets Retained by Sunoco, Inc.”

 

Indemnification. Under the terms of the Omnibus Agreement and in connection with the contribution of assets by affiliates of Sunoco, Sunoco has agreed to indemnify 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.

 

Sunoco, Inc. has also agreed to indemnify the Partnership for liabilities relating to:

 

    the assets contributed, other than environmental and toxic tort liabilities, that arise out of the operation of the assets prior to the closing of the February 2002 IPO and that are asserted within ten years after the closing of the IPO;

 

    certain defects in title to the assets contributed and failure to obtain certain consents and permits necessary to conduct the business that arise within ten years after the closing of the February 2002 IPO;

 

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

 

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

 

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, 2005 was $5.3 million. These fees are recorded as revenue within the Partnership’s statements of income.

 

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The lease agreement also requires Sunoco R&M to reimburse the Partnership for any non-routine maintenance expenditures, as defined, incurred during the term of the agreement. For the year ended December 31, 2005, the Partnership incurred maintenance capital expenditures of $0.1 million under this provision within the agreement and was reimbursed by Sunoco R&M. The reimbursement was recorded as a capital contribution to Partners’ Capital within the Partnership’s balance sheet.

 

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. Sunoco R&M cancelled one of these agreements during 2005 in accordance with the terms, but the cancellation did not have a material impact on the Partnership’s results of operations or cash flows. During each of the three years ended December 31, 2005, Sunoco R&M purchased all the barrels offered pursuant to these agreements and has not indicated that it intends to terminate any additional 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”).

 

Eagle Point Logistics Assets Purchase and Throughput Agreements

 

On March 30, 2004, the Partnership entered into a purchase agreement with Sunoco R&M to acquire the Eagle Point refinery logistics assets for $20 million. The purchase agreement requires Sunoco R&M to reimburse the Partnership for certain maintenance capital and expense expenditures incurred regarding the assets acquired, as defined, up to $5.0 million within the first 10 years of the closing of the transaction. For the year ended December 31, 2005, the Partnership incurred maintenance capital expenditures of $0.3 million under this provision within the agreement, but did not meet the threshold for reimbursement by Sunoco R&M.

 

In connection with the acquisition, the Partnership also entered into a throughput agreement with Sunoco R&M under which the Partnership is charging Sunoco R&M fees for services provided under this agreement that are comparable to those charged in arm’s length, third-party transactions to:

 

   

receive or deliver all crude oil to and from the Eagle Point refinery, other than those received or shipped via rail car, tanker truck or pipeline for twelve years ending March 31, 2016. This throughput is an

 

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annual amount for the contract period from April 1 to March 31 for the term of the agreement. For the calendar year ended December 31, 2005, the Partnership received a fee of $0.0813 per barrel for the first 130,000 bpd of crude oil and $0.0407 per barrel for volumes 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, 2005 and management of the Partnership expects Sunoco R&M to exceed the minimum throughput amount under the agreement for the contract year from April 1, 2005 through March 31, 2006;

 

    receive and deliver at least 41,800 bpd of refined and intermediate products per year at the Eagle Point dock for twelve years ending March 31, 2016. This throughput is an annual amount for the contract period from April 1 to March 31 for the term of the agreement. For the calendar year ended December 31, 2005, the Partnership received a fee of $0.0813 per barrel for the first 14,200 bpd of refined and intermediate products and $0.0407 per barrel for volume in excess of 14,200 bpd and also received a fee of $0.0712 per barrel for each shipment that required vapor combustion services. 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, 2005 and management of the Partnership expects Sunoco R&M to exceed the minimum throughput amount under the agreement for the contract year from April 1, 2005 through March 31, 2006; and

 

    receive and deliver at least 32,000 bpd of refined and intermediate products per year at the Eagle Point Refined Products Terminal for twelve years ending March 31, 2016. This throughput is an annual amount for the contract period from April 1 to March 31 for the term of the agreement. For the year ended December 31, 2005, the Partnership received per barrel fees as set forth in the contract by refined and intermediate product shipped. These fees will escalate at the rate of 1.67 percent each January 1 for the term of the agreement. Sunoco R&M has not met the minimum throughput amount through December 31, 2005. Under the agreement, Sunoco R&M will pay the Partnership any shortfall if it does not exceed the minimum throughput amount under the agreement for the contract year from April 1, 2005 through March 31, 2006.

 

Unit Redemptions and Equity Offering Cost-Sharing Agreements

 

In May and June 2005, the Partnership sold 2.775 million common units in a public offering for net proceeds of $99.2 million. The net proceeds were used to redeem 2.775 million common units owned by Sunoco. Also in connection with the equity offering, Sunoco reimbursed the Partnership for $0.4 million in transaction costs incurred by the Partnership. The reimbursement was accounted for in the third quarter of 2005 as an increase to Partners’ Capital within the Partnership’s consolidated balance sheet.

 

In April 2004, the Partnership sold 3.4 million common units in a public offering. In connection with this common unit offering, the Partnership utilized a portion of the offering proceeds to redeem 2.2 million common units held by Sunoco at a price per unit equal to the public offering price per unit after the underwriters’ commissions, or an aggregate of $82.7 million. Sunoco reimbursed the Partnership for $0.4 million in transaction costs it incurred based upon the percentage that Sunoco’s net redemption proceeds received represented of the total gross proceeds of the Partnership’s offering (64.2 percent). The reimbursement was accounted for in the fourth quarter of 2004 as an increase to Partners’ Capital within the Partnership’s consolidated balance sheet.

 

Other Agreements

 

The Partnership has also entered into various other agreements with Sunoco, Inc., Sunoco R&M and their affiliates, including throughput agreements regarding certain acquired assets or improvements or expansions at existing assets which are not covered within the pipelines and terminals storage and throughput agreement. Although these agreements did not result from arm’s-length negotiations, management of the Partnership believes the terms of these agreements to be comparable to those that could be negotiated with an unrelated third party.

 

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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 $300 million Credit Facility, with outstanding borrowings at December 31, 2005 of $106.6 million, exposes the Partnership to interest rate risk, since it bears interest at a variable rate (4.74 percent at December 31, 2005). A one percent change in interest rates changes annual interest expense by approximately $1.1 million.

 

I TEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

 

Management of Sunoco Logistics Partners L.P. (the “Partnership”) is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. The Partnership’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles.

 

The Partnership’s management assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2005. In making this assessment, the Partnership’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control—Integrated Framework.

 

Based on this assessment, management believes that, as of December 31, 2005, the Partnership’s internal control over financial reporting is effective based on those criteria. Ernst & Young LLP, an independent registered public accounting firm, has issued an attestation report on management’s assessment of the Partnership’s internal control over financial reporting, which appears in this section.

 

Deborah M. Fretz

President and Chief Executive Officer

 

Colin A. Oerton

Vice President and Chief Financial Officer

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

ON INTERNAL CONTROL OVER FINANCIAL REPORTING

 

To the Board of Directors of

Sunoco Partners LLC:

 

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that Sunoco Logistics Partners L.P. (the “Partnership”) maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Partnership’s internal control over financial reporting based on our audit.

 

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

 

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

 

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

 

In our opinion, management’s assessment that the Partnership maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the COSO criteria.

 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2005 financial statements of the Partnership and our report dated February 23, 2006 expressed an unqualified opinion thereon.

 

ERNST & YOUNG LLP

 

Philadelphia, Pennsylvania

February 23, 2006

 

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REPORT OF INDEPENDENT REGISTERED

PUBLIC ACCOUNTING FIRM ON FINANCIAL STATEMENTS

 

To the Board of Directors of

Sunoco Partners LLC:

 

We have audited the accompanying balance sheets of Sunoco Logistics Partners L.P. (the “Partnership”) as of December 31, 2004 and 2005 and the related statements of income, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Sunoco Logistics Partners L.P. at December 31, 2004 and 2005 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.

 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2006 expressed an unqualified opinion thereon.

 

ERNST & YOUNG LLP

 

Philadelphia, Pennsylvania

February 23, 2006

 

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SUNOCO LOGISTICS PARTNERS L.P.

 

STATEMENTS OF INCOME

(in thousands, except units and per unit amounts)

 

     Year Ended December 31,

 
     2003

    2004

    2005

 

Revenues

                        

Sales and other operating revenue:

                        

Affiliates (Note 3)

   $ 1,383,090     $ 1,751,612     $ 1,986,019  

Unaffiliated customers

     1,274,383       1,699,673       2,496,593  

Other income

     16,730       13,932       14,295  
    


 


 


Total Revenues

     2,674,203       3,465,217       4,496,907  
    


 


 


Costs and Expenses

                        

Cost of products sold and operating expenses

     2,519,160       3,307,480       4,326,713  

Depreciation and amortization

     27,157       31,933       33,838  

Selling, general and administrative expenses

     48,412       48,449       53,048  
    


 


 


Total Costs and Expenses

     2,594,729       3,387,862       4,413,599  
    


 


 


Operating Income

     79,474       77,355       83,308  

Net interest cost paid to affiliates (Note 3)

     15       439       468  

Other interest cost and debt expense, net

     20,518       19,885       21,611  

Capitalized interest

     (493 )     —         (480 )
    


 


 


Net Income

   $ 59,434     $ 57,031     $ 61,709  
    


 


 


Calculation of Limited Partners’ interest in Net Income:

                        

Net Income

   $ 59,434     $ 57,031     $ 61,709  

Less: General Partner’s interest in Net Income

     (1,423 )     (2,828 )     (3,054 )
    


 


 


Limited Partners’ interest in Net Income

   $ 58,011     $ 54,203     $ 58,655  
    


 


 


Net Income per Limited Partner unit:

                        

Basic

   $ 2.55     $ 2.29     $ 2.37  
    


 


 


Diluted

   $ 2.53     $ 2.27     $ 2.35  
    


 


 


Weighted average Limited Partners’ units outstanding (Note 5):

                        

Basic

     22,771,793       23,666,211       24,783,852  
    


 


 


Diluted

     22,894,520       23,907,151       24,953,713  
    


 


 


 

(See Accompanying Notes)

 

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SUNOCO LOGISTICS PARTNERS L.P.

 

BALANCE SHEETS

(in thousands)

 

     December 31,

     2004

   2005

Assets

             

Current Assets

             

Cash and cash equivalents

   $ 52,660    $ 21,645

Advances to affiliates (Note 3)

     12,349      —  

Accounts receivable, affiliated companies (Note 3)

     140,328      136,536

Accounts receivable, net

     396,479      584,509

Inventories (Note 6)

     27,128      28,261
    

  

Total Current Assets

     628,944      770,951

Properties, plants and equipment, net (Note 7)

     647,200      814,836

Investment in affiliates (Note 8)

     69,745      69,097

Deferred charges and other assets

     22,897      25,801
    

  

Total Assets

   $ 1,368,786    $ 1,680,685
    

  

Liabilities and Partners’ Capital

             

Current Liabilities

             

Accounts payable

   $ 553,629    $ 720,127

Accrued liabilities

     25,284      32,884

Accrued taxes other than income

     15,162      20,986

Advances from affiliates (Note 3)

     —        5,750
    

  

Total Current Liabilities

     594,075      779,747

Long-term debt (Note 9)

     313,305      355,573

Other deferred credits and liabilities

     812      21,954

Commitments and contingent liabilities (Note 10)

             
    

  

Total Liabilities

     908,192      1,157,274
    

  

Partners’ Capital:

             

Limited partners’ interest

     452,856      515,512

General partner’s interest

     7,738      7,899
    

  

Total Partners’ Capital

     460,594      523,411
    

  

Total Liabilities and Partners’ Capital

   $ 1,368,786    $ 1,680,685
    

  

 

(See Accompanying Notes)

 

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STATEMENTS OF CASH FLOWS

(in thousands)

 

     Year Ended December 31,

 
     2003

    2004

    2005

 

Cash Flows from Operating Activities:

                        

Net Income

   $ 59,434     $ 57,031     $ 61,709  

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

                        

Depreciation and amortization

     27,157       31,933       33,838  

Gain on claim settlement

     (1,175 )     —         —    

Restricted unit incentive plan expense

     2,204       3,204       3,221  

Changes in working capital pertaining to operating activities:

                        

Accounts receivable, affiliated companies

     (11,470 )     (23,392 )     3,792  

Accounts receivable, net

     (51,164 )     (94,244 )     (188,030 )

Inventories

     (1,524 )     140       (1,133 )

Accounts payable and accrued liabilities

     69,408       127,113       173,380  

Accrued taxes other than income

     39       3,850       5,824  

Other

     4,303       987       (1,766 )
    


 


 


Net cash provided by operating activities

     97,212       106,622       90,835  
    


 


 


Cash Flows from Investing Activities:

                        

Capital expenditures

     (37,377 )     (46,418 )     (73,345 )

Acquisitions

     (3,699 )     (49,165 )     (107,309 )

Net proceeds from claim settlement

     2,068       —         —    
    


 


 


Net cash used in investing activities

     (39,008 )     (95,583 )     (180,654 )
    


 


 


Cash Flows from Financing Activities:

                        

Distributions paid to Limited Partners and General Partner

     (46,227 )     (57,483 )     (67,331 )

Net proceeds from issuance of Limited Partner units

     —         128,738       159,641  

Redemption of Limited Partner units from Sunoco

     —         (82,690 )     (99,203 )

Net contribution from General Partner for Limited Partner unit transactions

     —         989       336  

Advances to affiliates, net

     3,428       (5,061 )     18,099  

Borrowings under credit facility

     —         64,500       98,600  

Repayments under credit facility

     —         (64,500 )     (56,500 )

Repayments of long-term debt

     (4,478 )     —         —    

Payments of statutory withholding on net issuance of Limited Partner units under restricted unit incentive plan

     —         —         (2,863 )

Contributions from affiliate

     5,314       7,047       8,025  
    


 


 


Net cash provided by/(used in) financing activities

     (41,963 )     (8,460 )     58,804  
    


 


 


Net change in cash and cash equivalents

     16,241       2,579       (31,015 )

Cash and cash equivalents at beginning of year

     33,840       50,081       52,660  
    


 


 


Cash and cash equivalents at end of year

   $ 50,081     $ 52,660     $ 21,645  
    


 


 


 

(See Accompanying Notes)

 

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STATEMENTS OF PARTNERS’ CAPITAL

(in thousands)

 

     Limited Partners

    General
Partner


    Total
Partners’
Capital


 
     Common

    Subordinated

     
     Units

    $

    Units

    $

    $

    $

 

Balance at January 1, 2003

   11,388     $ 192,688     11,384     $ 184,627     $ 5,718     $ 383,033  

Contribution from affiliate

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

Unissued units under incentive plans

   —         2,204     —         —         —         2,204  

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     $ 202,995     11,384     $ 194,484     $ 6,279     $ 403,758  
    

 


 

 


 


 


Issuance of Limited Partner units to the public (Note 2)

   3,400       128,738     —         —         2,759       131,497  

Redemption of Limited Partner units from affiliate (Note 2)

   (2,183 )     (82,690 )   —         —         (1,770 )     (84,460 )

Contribution from affiliate

   —         1,608     —         5,298       141       7,047  

Unissued units under incentive plans

   —         3,204     —         —         —         3,204  

Net income

   —         28,149     —         26,054       2,828       57,031  

Cash distributions

   —         (28,574 )   —         (26,410 )     (2,499 )     (57,483 )
    

 


 

 


 


 


Balance at December 31, 2004

   12,605     $ 253,430     11,384     $ 199,426     $ 7,738     $ 460,594  
    

 


 

 


 


 


Issuance of Limited Partner units to the public (Note 2)

   4,400       159,641     —         —         3,417       163,058  

Redemption of Limited Partner units from affiliate (Note 2)

   (2,775 )     (99,203 )   —         —         (2,124 )     (101,327 )

Conversion of Subordinated units to Common units held by affiliate (Note 3)

   2,846       49,857     (2,846 )     (49,857 )     —         —    

Contribution from affiliate

   —         2,345     —         5,519       161       8,025  

Distribution to affiliate

   —         (313 )   —         (759 )     (22 )     (1,094 )

Unissued units under incentive plans

   —         2,503     —         —         —         2,503  

Units issued under incentive plans

   155       (2,863 )   —         —         137       (2,726 )

Net income

   —         38,532     —         20,123       3,054       61,709  

Cash distributions

   —         (44,975 )   —         (17,894 )     (4,462 )     (67,331 )
    

 


 

 


 


 


Balance at December 31, 2005

   17,231     $ 358,954     8,538     $ 156,558     $ 7,899     $ 523,411  
    

 


 

 


 


 


 

(See Accompanying Notes)

 

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NOTES TO FINANCIAL STATEMENTS

 

1. Summary of Significant Accounting Policies

 

Principles of Consolidation

 

Sunoco Logistics Partners L.P. (the “Partnership”) is a Delaware limited partnership formed by Sunoco, Inc. (“Sunoco”) in October 2001 to acquire, own and operate a substantial portion of Sunoco, 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. The financial statements of the Partnership contain the accounts of the Partnership and its subsidiaries. Equity ownership interests in corporate joint ventures, which are not consolidated, are accounted for under the equity method.

 

Use of Estimates

 

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

 

Revenue Recognition

 

Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil gathering and marketing revenues are recognized when title to the crude oil is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to the Partnership’s end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of income based upon the concepts set forth in APB Opinion No. 29, “Accounting for Nonmonetary Transactions.” In September 2005, the Emerging Issues Task Force (the “EITF”) completed its deliberations on the accounting for exchange transactions in Issue 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty”. The consensus reached in EITF 04-13 supports the Partnership’s accounting treatment of its exchange transactions.

 

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. In 2002, 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. In 2004, in connection with the Partnership’s acquisition of the Eagle Point logistics assets, Sunoco R&M also agreed to minimum throughputs of refined products and crude oil at the Eagle Point truck rack, docks and pipeline assets (see Note 3).

 

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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NOTES TO FINANCIAL STATEMENTS—(Continued)

 

Accounts Receivable, net

 

Accounts receivable represent valid claims against non-affiliated customers (see Note 3 for affiliated receivables) for products sold or services rendered. The Partnership extends credit terms to certain customers after review of various credit indicators, including the customer’s credit rating. Outstanding customer receivable balances are regularly reviewed for possible non-payment indicators and reserves are recorded for doubtful accounts based upon management’s estimate of collectibility at the time of review. Actual balances are charged against the reserve when all collection efforts have been exhausted. The following table provides the activity in the allowance for doubtful accounts for the three-year period ended December 31, 2005:

 

     2003

   2004

    2005

Balance at January 1

   $ 500    $ 500     $ —  

Amounts charged to expense

     —        —         —  

Deductions

     —        (500 )     —  
    

  


 

Balance at December 31

   $ 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. The cost of materials, supplies and other inventories is principally determined using 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 properties, plants and equipment are retired or otherwise disposed of, the cost less net proceeds is charged to accumulated depreciation and amortization, except that gains and losses for unusual disposals for those groups are reflected in other income in the statements of income. Gains and losses on the disposal of non-FERC properties, plants and equipment are reflected in other income in the statements of income.

 

During 2004 and 2005, the Partnership accelerated the depreciation of assets related to equipment upgrade programs and the Western area headquarters’ move from Tulsa, Oklahoma to Sugar Land, Texas, based upon the estimated remaining useful lives of these assets until their replacement. The acceleration resulted in $1.8 million of additional depreciation expense recognized in 2004, $1.8 million in 2005, and will result in an additional $0.5 million of additional depreciation expense in 2006.

 

Capitalized Interest

 

The Partnership capitalizes interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. During the years ended December 31, 2003 and 2005, the amount of interest capitalized was $0.5 million and $0.5 million, respectively. There were no amounts capitalized in 2004. The weighted average rate used to capitalize interest on borrowed funds was 7.3 percent for 2003 and 6.5 percent for 2005.

 

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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 estimated fair value of the impaired asset. Long-lived assets held for sale are recorded at the lower of their carrying amount or estimated fair value less cost to sell the assets.

 

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, 2004 and 2005, the Partnership had $16.2 million of goodwill and accumulated amortization of $1.3 million related to goodwill. In accordance with Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets,” goodwill and indefinite-lived intangible assets are tested for impairment at least annually. The Partnership determined during 2003, 2004 and 2005 that such assets were not impaired.

 

Deferred financing fees of $2.6 million, net of accumulated amortization of $0.8 million, as of December 31, 2004, and $2.4 million, net of accumulated amortization of $1.2 million, as of December 31, 2005, have been included within deferred charges and other assets on the balance sheets. The Partnership deferred total fees of $0.6 million paid in 2004 and $0.2 million paid in 2005 related to the renewal and amendment of the Credit Facility during those periods. Amortization expense of $0.6 million, $0.7 million and $0.4 million for the years ended December 31, 2003, 2004 and 2005, respectively, has been included within other interest cost and debt expense on the statements of income. The Partnership amortizes deferred financing fees over the life of the respective debt agreement.

 

Investment in Affiliates

 

Investments in affiliates, which consist of corporate joint ventures, are accounted for under the equity method of accounting as required by Accounting Principles Board Opinion 18, “The Equity Method of Accounting for Investments in Common Stock” (“APB 18”). Under this method, an investment is carried at acquisition cost, increased for the equity in income or decreased for the equity in loss from the date of acquisition, and reduced for dividends received. The Partnership had $0.7 million of undistributed earnings from its investments in corporate joint ventures within Partners’ Capital on its December 31, 2005 balance sheet. During the years ended December 31, 2003, 2004 and 2005, the Partnership received dividends of $12.9 million, $13.3 million, and $13.2 million, respectively, from its investments in corporate joint ventures.

 

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

 

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,

 

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NOTES TO FINANCIAL STATEMENTS—(Continued)

 

existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point or points in the range are more likely, in which case the most likely amount in this range is accrued.

 

Income Taxes

 

No provision for U.S. federal income taxes is included in the accompanying financial statements, because as a partnership we are not subject to federal or state income tax and the tax effect of our activities accrues to the unitholders.

 

Long-Term Incentive Plan

 

In December 2004, Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (“SFAS No. 123R”) was issued, which revised Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”). Among other things, SFAS No. 123R requires a fair-value-based method of accounting for share-based payment transactions. SFAS No. 123R also requires the use of a non-substantive vesting period approach for new share-based payment transactions that vest when an employee becomes retirement eligible as is the case under the Partnership’s Long-Term Incentive Plan (i.e., the vesting period cannot exceed the date an employee becomes retirement eligible). The effect will be to accelerate expense recognition for units awarded to retirement-eligible participants compared to the vesting period approach the Partnership currently uses, which reflects the stated vesting period. The future impact of the non-substantive vesting period will be dependent upon the value of future awards granted to employees who are eligible to retire prior to the stated vesting periods of those awards. The Partnership intends to adopt SFAS No. 123R effective January 1, 2006. As the Partnership follows the fair value method of accounting prescribed by SFAS No. 123, the other provisions of SFAS No. 123R are not expected to have an impact on the Partnership’s financial statements.

 

Asset Retirement Obligations

 

In March 2005, the Financial Accounting Standards Board issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FASB Interpretation No. 47”). FASB Interpretation No. 47 clarifies that the term “conditional asset retirement obligation” as used in Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. FASB Interpretation No. 47 provides that a liability for the fair value of a conditional asset retirement obligation should be recognized if that fair value can be reasonably estimated. FASB Interpretation No. 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. In conjunction with the implementation of FASB Interpretation No. 47 in the fourth quarter of 2005, the Partnership recorded an increase in the liability for asset retirement obligations of $20.6 million (included as a component of other deferred credits and liabilities on the balance sheet) and additional properties, plants and equipment of $20.6 million, primarily attributed to pipelines and crude oil and refined product storage tanks at the Partnership’s facilities. This amount approximates the amount that would have been included in the balance sheets at the beginning of 2004 and as of December 31, 2004 if FASB Interpretation No. 47 had been applied to that period. This change did not have a significant impact on the Partnership’s statement of income for the year ended December 31, 2005. The Partnership believes it may have additional asset retirement obligations related to its pipeline assets and storage tanks, for which it is not possible to estimate when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time.

 

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SUNOCO LOGISTICS PARTNERS L.P.

 

NOTES TO FINANCIAL STATEMENTS—(Continued)

 

Lease Accounting

 

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 continually analyzing its agreements that were in existence prior to July 1, 2003 to determine if the accounting for these agreements would be impacted upon renewal or amendment. The provisions of EITF 01-8 had no impact on the Partnership’s financial statements for the years ended December 31, 2003, 2004 and 2005.

 

Hurricane Rita Losses

 

On September 24, 2005, Hurricane Rita damaged the Partnership’s Nederland Terminal facility and a portion of the Western Pipeline System, impacting several storage tanks, dock facilities, buildings and equipment. Although the Nederland Terminal resumed operations on October 3, 2005, the business was impacted for a few weeks as a result of interruptions in customer and supplier business activities related to the Hurricane. The estimated lost operating income and additional operating expenses incurred in 2005 attributed to the Hurricane totaled $5.3 million. The Partnership will incur additional costs in 2006 to repair its damaged facilities, and expects to negotiate a settlement with its insurance carrier for reimbursement of a portion of its costs during 2006.

 

2. Equity Offerings

 

On April 7, 2004, the Partnership sold 3.4 million common units in a public offering for total gross proceeds of $135.1 million. The units were issued under the Partnership’s previously filed Form S-3 shelf registration statement. The sale of the units resulted in net proceeds of $128.7 million, after underwriters’ commissions and legal, accounting, and other transaction expenses. Net proceeds from the sale were used to (a) redeem approximately 2.2 million common units from Sunoco for $82.7 million, (b) replenish cash utilized to acquire the Eagle Point logistics assets for $20.0 million, (c) finance the acquisition of two refined product terminals for $12.0 million, (d) finance the acquisition of an additional 33.3 percent undivided interest in the Harbor pipeline for $7.3 million, and (e) for general partnership purposes, including to replenish cash used for past acquisitions and capital improvements, and for other expansion, capital improvements or acquisition projects. As a result of this net issuance of 1.2 million common units, the general partner contributed $1.0 million to the Partnership to maintain its 2.0 percent general partner interest.

 

In May 2005, the Partnership sold 2.5 million common units in a public offering. In June 2005, the Partnership sold an additional 275,000 common units to cover over-allotments in connection with the May 2005 sale. The purchase price for the over-allotment was equal to the offering price in the May 2005 sale. The units were issued under the Partnership’s previously filed Form S-3 shelf registration statement. The sale of units resulted in total gross proceeds of $104.1 million, and net proceeds of $99.2 million, after underwriters’ commissions and legal, accounting and other transaction expenses. Net proceeds from the sale were used to redeem 2.775 million common units owned by Sunoco. The redemption price per unit was equal to the public offering price per unit after the underwriters’ commissions.

 

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SUNOCO LOGISTICS PARTNERS L.P.

 

NOTES TO FINANCIAL STATEMENTS—(Continued)

 

In August 2005, the Partnership sold 1.5 million common units in a public offering. In September 2005, the Partnership sold an additional 125,000 common units to cover over-allotments in connection with the August 2005 sale. The purchase price for the over allotment was equal to the offering price in the August 2005 sale. The units were issued under the Partnership’s previously filed Form S-3 shelf registration statement. The total sale of units resulted in total gross proceeds of $63.4 million, and net proceeds of $60.4 million, after the underwriters’ commission and legal, accounting and other transaction expenses. Net proceeds of the sale were used to repay $56.5 million of the debt incurred to finance the August 1, 2005 purchase of a Texas crude oil pipeline system and storage facilities with the balance for general partnership purposes. As a result of this issuance of 1.625 million common units, the general partner contributed $1.3 million to the Partnership to maintain its 2.0 percent general partner interest. At December 31, 2005, Sunoco’s ownership in the Partnership, including its 2.0 percent general partner interest, was 47.9 percent.

 

3. Related Party Transactions

 

Advances to/from Affiliate

 

The Partnership has a treasury services agreement with Sunoco pursuant to which it, among other things, participates in Sunoco’s centralized cash management program. Under this program, all of the Partnership’s cash receipts and cash disbursements are processed, together with those of Sunoco and its other subsidiaries, through Sunoco’s cash accounts with a corresponding credit or charge to an intercompany account. The intercompany balances are settled periodically, but no less frequently than monthly. Amounts due from Sunoco earn interest at a rate equal to the average rate of the Partnership’s third-party money market investments, while amounts due to Sunoco bear interest at a rate equal to the interest rate provided in the Partnership’s revolving credit facility (see Note 9).

 

Administrative Services

 

Under the Omnibus Agreement, the Partnership pays Sunoco, Inc. or the general partner an annual administrative fee that includes expenses incurred by Sunoco, Inc. and its affiliates to perform centralized corporate functions, such as legal, accounting, treasury, engineering, information technology, insurance, and other corporate services, including the administration of employee benefit plans. This fee was $8.2 million, $8.4 million and $8.4 million for the years ended December 31, 2003, 2004 and 2005, respectively. This fee does not include the costs of shared insurance programs (which are allocated to the Partnership based upon its share of the cash premiums incurred), the salaries of pipeline and terminal personnel or other employees of the general partner (including senior executives), or the cost of their employee benefits. The Partnership has no employees, and reimburses Sunoco, Inc. and its affiliates for these costs and other direct expenses incurred on the Partnership’s behalf. In addition, the Partnership has incurred additional general and administrative costs which it pays directly.

 

The initial term of Section 4.1 of the Omnibus Agreement (which concerns the Partnership’s obligation to pay the annual fee for provision of certain general and administrative services) was through the end of 2004. The parties extended the term of Section 4.1 by one year each in January 2005 and January 2006. The 2006 annual fee will decrease to $7.7 million, which reflects the Partnership directly incurring some of these general and administrative costs. These costs may be increased if the acquisition or construction of new assets or businesses require an increase in the level of general and administrative services received by the Partnership. There can be no assurance that Section 4.1 of the Omnibus Agreement will be extended beyond 2006, or that, if extended, the administrative fee charged by Sunoco will be at or below the current administrative fee. In the event that the Partnership is unable to obtain such services from Sunoco or other third parties at or below the current cost, the Partnership’s financial condition and results of operations may be adversely impacted

 

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SUNOCO LOGISTICS PARTNERS L.P.

 

NOTES TO FINANCIAL STATEMENTS—(Continued)

 

In addition to the fees for the centralized corporate functions, selling, general and administrative expenses in the statements of income include the allocation of shared insurance costs of $2.7 million, $2.5 million and $5.1 million for the years ended December 31, 2003, 2004 and 2005, respectively. The insurance costs for the year ended December 31, 2005 include $2.5 million resulting from two special assessments by one of the Partnership’s insurers as a result of Hurricanes Rita and Katrina. The Partnership’s share of allocated Sunoco employee benefit plan expenses, including non-contributory defined benefit retirement plans, defined contribution 401(k) plans, employee and retiree medical, dental and life insurance plans, incentive compensation plans and other such benefits, was $20.6 million, $21.0 million, and $21.5 million for the years ended December 31, 2003, 2004 and 2005, respectively. These expenses are reflected in cost of products sold and operating expenses and selling, general and administrative expenses in the statements of income.

 

Affiliated Revenues and Accounts Receivable, Affiliated Companies

 

Affiliated revenues in the statements of income consist of sales of crude oil as well as the provision of crude oil and refined product pipeline transportation, terminalling and storage services to Sunoco 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. In 2002, 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 that, in management’s opinion, are comparable to those charged in arm’s-length, third-party transactions. Under the pipelines and terminals storage and throughput agreement, Sunoco 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. Under various other agreements entered into in 2002, 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. During the year ended December 31, 2005 one of these agreements was terminated by Sunoco R&M, however the cancellation has not had a material impact on the Partnership’s results of operations. 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.

 

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 through 2006 that are made to comply with the U.S. Department of Transportation’s (“DOT”) pipeline integrity management rule, subject to a maximum aggregate reimbursement of $15.0 million over the five-year period ending December 31, 2006; complete, at its expense, certain tank maintenance and inspection projects at the Darby Creek Tank Farm; and reimburse the Partnership for up to $10.0 million of expenditures required at the Marcus Hook Tank Farm and the Darby Creek Tank Farm to maintain compliance with existing industry standards and regulatory requirements.

 

For the years ended December 31, 2003, 2004 and 2005, the Partnership was reimbursed $1.9 million, $2.1 million and $7.0 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, 2005, the Partnership has received a cumulative reimbursement of $11.7 million in regard to the

 

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$15.0 million maximum reimbursement over the five-year period for compliance expenditures relative to the DOT’s pipeline integrity management rule.

 

For the years ended December 31, 2003, 2004 and 2005, 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:

 

     Year Ended December 31,

     2003

   2004

   2005

     (amounts in thousands)

Maintenance capital

   $ 2,982    $ 4,140    $ 885

Operating expenses

     467      540      —  
    

  

  

     $ 3,449    $ 4,680    $ 885
    

  

  

 

At December 31, 2005, the Partnership has received a cumulative reimbursement of $9.9 million relative to the $10.0 million maximum reimbursement for compliance expenditures at the Marcus Hook Tank Farm and the Darby Creek Tank Farm.

 

The aggregate amounts reimbursed related to these provisions of the Omnibus Agreement of $5.3 million, $6.8 million and $7.9 million for the years ended December 31, 2003, 2004 and 2005, respectively, by Sunoco R&M related to these projects were recorded as capital contributions to Partners’ Capital within the Partnership’s balance sheets.

 

Under the terms of the Interrefinery Lease Agreement, Sunoco R&M is required to reimburse the Partnership for any non-routine maintenance expenditures, as defined, incurred during the term of the agreement. The Eagle Point purchase agreement requires Sunoco R&M to reimburse the Partnership for certain maintenance capital and expense expenditures incurred regarding the assets acquired, as defined, up to $5.0 million within the first 10 years of closing of the transaction. For the years ended December 31, 2004 and 2005, the Partnership incurred maintenance capital expenditures of $0.2 million and $0.1 million, respectively, under the provisions within these agreements and was reimbursed by Sunoco R&M. The reimbursements were recorded as capital contributions to Partners’ Capital within the Partnership’s balance sheet.

 

Asset Acquisitions

 

On December 5, 2005, the Partnership acquired a subsidiary of Sunoco which owned a 7.2 percent undivided interest in the Mesa Pipe Line system for approximately $1.3 million (see Note 4). Since the acquisition was from a related party, the interest in the entity was recorded by the Partnership at Sunoco’s historical cost of $0.2 million, and the $1.1 million difference between the purchase price and the cost basis of the assets was recorded by the Partnership as a capital distribution.

 

On March 30, 2004, the Partnership acquired the Eagle Point refinery logistics assets from Sunoco R&M for $20 million (see Note 4).

 

Redemption of Common Units

 

In April 2004, the Partnership sold 3.4 million common units in a public offering (see Note 2). The proceeds of this offering were partially utilized to redeem approximately 2.2 million common units from Sunoco for $82.7

 

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million. As a result of this net issuance of 1.2 million common units, the general partner contributed $1.0 million to the Partnership to maintain its 2.0 percent ownership interest. The Partnership recorded this amount as a capital contribution to Partners’ Capital within its balance sheet. In connection with the equity offering, Sunoco agreed to reimburse the Partnership for transaction costs incurred by the Partnership based upon the percentage that Sunoco’s net redemption proceeds received represented of the total gross proceeds of the Partnership’s offering (approximately 64.2 percent). Reimbursement of these costs of $0.4 million occurred during the fourth quarter of 2004 when the transaction costs were finalized and was accounted for as an increase to Partners’ Capital within the Partnership’s balance sheet.

 

In May 2005, the Partnership sold 2.5 million common units in a public offering. In June 2005, the Partnership sold an additional 275,000 common units to cover over-allotments in connection with the May 2005 sale (see Note 2). Net proceeds from the sale were used to redeem 2.775 million common units owned by Sunoco for $99.6 million. Also in connection with the equity offering, Sunoco agreed to reimburse the Partnership for transaction costs incurred by the Partnership. Reimbursement of these costs of $0.4 million occurred during the third quarter of 2005 when the transaction costs were finalized and was accounted for as an increase to Partners’ Capital within the Partnership’s balance sheet.

 

4. Acquisitions

 

On December 5, 2005, the Partnership purchased a subsidiary of Sunoco that owned a 7.2 percent undivided interest in the Mesa Pipe Line system for approximately $1.3 million. The Mesa Pipe Line system consists of an 80-mile, 24-inch crude oil pipeline from Midland, Texas to Colorado City, Texas, with an operating capacity of 316,000 barrels per day, and approximately 800,000 barrels of tankage at Midland. Mesa Pipeline connects to West Texas Gulf’s pipeline, which supplies crude oil to Mid-Valley. On December 29, 2005, the Partnership purchased an additional 29.8 interest in the Mesa Pipe Line system from Chevron for $5.3 million. The purchase prices of the acquisitions were funded with $6.6 million of net borrowings under the Partnership’s Credit Facility, and were allocated on a preliminary basis to property, plant and equipment within the Western Pipeline System business segment.

 

On August 1, 2005, the Partnership purchased, from an affiliate of Exxon Mobil Corporation, a crude oil pipeline system and storage facilities located in Texas for $100.0 million. The pipeline system consists primarily of a 187-mile, 16-inch pipeline with an operating capacity of 125,000 barrels per day. It originates at a crude oil terminal in Corsicana, Texas and terminates at Wichita Falls, Texas. The storage facilities include the Corsicana terminal, which has 2.9 million barrels of shell capacity for crude oil, and the Ringgold, Texas terminal, which consists of 0.5 million barrels of shell capacity for crude oil. In addition, the Partnership invested approximately $16.0 million to construct a new 20-mile pipeline to connect the Corsicana to Wichita Falls pipeline to the West Texas Gulf pipeline, in which the Partnership has a 43.8% ownership interest. The Partnership funded the purchase price of the Corsicana to Wichita Falls pipeline and storage facilities with a $75.0 million borrowing under the Credit Facility and $25.0 million of cash. The Partnership repaid $56.5 million of the additional indebtedness with proceeds from the August 2005 units offering (see Note 2), reducing the net borrowings used to fund the acquisition to $18.5 million. The pipeline construction and the acquisition of the related right-of-way were also funded with borrowings under the Partnership’s Credit Facility. The purchase price was allocated to property, plant and equipment within the Western Pipeline System business segment

 

On November 30, 2004, the Partnership acquired a refined products terminal located in Columbus, Ohio for approximately $8.0 million. The terminal is connected to a third-party, refined product, common carrier pipeline and includes 6 refined product tanks with approximately 160,000 barrels of working storage capacity. The purchase price was funded through cash on hand, and was allocated to property, plant and equipment within the Terminal Facilities business segment.

 

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On June 28, 2004, the Partnership purchased an additional 33.3 percent undivided interest in the Harbor pipeline for $7.3 million. The Harbor pipeline is an 80-mile, 180,000 bpd refined product, common carrier pipeline originating near Woodbury, New Jersey and terminating in Linden, New Jersey. As a result of this transaction, the Partnership increased its ownership to 66.7 percent and will continue to be the operator of the pipeline. The purchase price was funded through the proceeds of the April 7, 2004 sale of common units (see Note 2). The purchase price was allocated to property, plant and equipment within the Eastern Pipeline System business segment.

 

On April 28, 2004, the Partnership purchased two refined product terminals located in Baltimore, Maryland and Manassas, Virginia for $12.0 million. The Baltimore terminal is connected to a third-party, refined product, common carrier pipeline and includes 13 refined product tanks with approximately 646,000 barrels of working storage capacity. The Manassas terminal is connected to a third-party, refined product, common carrier pipeline and includes 7 refined product tanks with approximately 277,000 barrels of working storage capacity. The purchase price was funded through the proceeds of the April 7, 2004 sale of common units (see Note 2). The purchase price was allocated to property, plant and equipment within the Terminal Facilities business segment.

 

On March 30, 2004, the Partnership acquired the Eagle Point refinery logistics assets from Sunoco R&M for $20.0 million. The Eagle Point logistics assets consist of crude and refined product ship and barge docks, a refined product truck rack, and a 4.5-mile, refined product pipeline from the Eagle Point refinery to the origin of the Harbor pipeline. In connection with the acquisition, the Partnership entered into a throughput agreement with Sunoco R&M whereby they have agreed to maintain minimum volumes on the truck rack upon completion of certain capital improvements which were completed during the fourth quarter of 2004. The purchase price was funded initially through cash on hand. A portion of the proceeds of the April 7, 2004 sale of common units was subsequently utilized to replenish cash used to fund this acquisition (see Note 2). The purchase price was allocated to property, plant and equipment. The ship and barge docks and the truck rack have been included within the Terminal Facilities business segment, while the pipeline has been included within the Eastern Pipeline System.

 

5. Net Income Per Unit Data

 

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

 

Emerging Issues Task Force Issue No. 03-06 (“EITF 03-06”) “Participating Securities and the Two-Class Method under FASB Statement No. 128” addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity. EITF 03-06 provides that the general partner’s interest in net income is to be calculated based on the amount that would be allocated to the general partner if all the net income for the period were distributed, and not on the basis of actual cash distributions for the period. The Partnership applied EITF 03-06 prospectively beginning with the third quarter of 2005. The application of EITF 03-06 may have an impact on earnings per limited partner unit in future periods if there are material differences between net income and actual cash distributions or if other participating securities are issued. The effect of applying EITF 03-06 to prior periods, however, would not have been material.

 

The general partner’s interest in net income consists of its 2.0 percent general partner interest and “incentive distributions”, which are increasing percentages, up to 50 percent of quarterly distributions in excess of $0.50 per limited partner unit (see Note 12). The general partner was allocated net income of $1.4 million (representing

 

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2.4 percent of total net income for the period) for the year ended December 31, 2003, $2.8 million (representing 5.0 percent of total net income for the period) for the year ended December 31, 2004, and $3.1 million (representing 4.9 percent of total net income for the period) for the year ended December 31, 2005. Diluted net income per limited partner unit is calculated by dividing net income applicable to limited partners’ by the sum of the weighted-average number of common and subordinated units outstanding and the dilutive effect of incentive unit awards (see Note 11), as calculated by the treasury stock method.

 

The following table sets forth the reconciliation of the weighted average number of limited partner units used to compute basic net income per limited partner unit to those used to compute diluted net income per limited partner unit for the years ended December 31, 2003, 2004 and 2005:

 

     2003

   2004

   2005

Weighted average number of limited partner units outstanding—basic

   22,771,793    23,666,211    24,783,852

Add effect of dilutive unit incentive awards

   122,727    240,940    169,861
    
  
  

Weighted average number of limited partner units—diluted

   22,894,520    23,907,151    24,953,713
    
  
  

 

6. Inventories

 

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

 

     December 31,

     2004

   2005

Crude oil

   $ 26,428    $ 27,561

Materials, supplies and other

     700      700
    

  

     $ 27,128    $ 28,261
    

  

 

The current replacement cost of crude oil inventory exceeded its carrying value by $59.7 million and $94.5 million at December 31, 2004 and 2005, respectively. During 2004, 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 2004 net income by $0.5 million.

 

7. Properties, Plants and Equipment

 

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

 

     Estimated
Useful Lives


   December 31,

 
        2004

    2005

 

Land and land improvements (including rights of way)

   —      $ 56,678     $ 65,709  

Pipeline and related assets

   38 - 60      536,502       642,111  

Terminals and storage facilities

   5 - 44      383,809       436,628  

Other

   5 - 48      77,656       78,958  

Construction-in-progress

   —        41,283       64,136  
         


 


            1,095,928       1,287,542  

Less: Accumulated depreciation and amortization

          (448,728 )     (472,706 )
         


 


          $ 647,200     $ 814,836  
         


 


 

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8. Investment in Affiliates

 

The Partnership’s ownership percentages in corporate joint ventures as of December 31, 2004 and 2005 are as follows:

 

     Partnership
Ownership
Percentage


Explorer Pipeline Company

   9.4%

Wolverine Pipe Line Company

   31.5%

West Shore Pipe Line Company

   12.3%

Yellowstone Pipe Line Company

   14.0%

West Texas Gulf Pipe Line Company

   43.8%

 

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

 

     2003

   2004

   2005

Income Statement Data:

                    

Total revenues

   $ 345,741    $ 375,740    $ 375,435

Income before income taxes

   $ 155,577    $ 158,529    $ 147,204

Net income

   $ 94,437    $ 100,876    $ 92,657

Balance Sheet Data (as of year-end):

                    

Current assets

   $ 93,479    $ 100,971    $ 100,241

Non-current assets

   $ 472,444    $ 473,183    $ 468,994

Current liabilities

   $ 67,834    $ 69,836    $ 80,054

Non-current liabilities

   $ 444,845    $ 446,482    $ 437,004

Net equity

   $ 53,244    $ 57,836    $ 52,177

 

The Partnership’s investments in Wolverine, West Shore, Yellowstone, and West Texas Gulf at December 31, 2005 include an excess investment amount of approximately $55.6 million, net of accumulated amortization of $2.0 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, are 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.

 

9. Long-Term Debt

 

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

 

     December 31,

 
     2004

    2005

 

Credit Facility

   $ 64,500     $ 106,600  

Senior Notes

     250,000       250,000  

Less unamortized bond discount

     (1,195 )     (1,027 )
    


 


     $ 313,305     $ 355,573  
    


 


 

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Credit Facility

 

On December 1, 2005, Sunoco Logistics Partners Operations L.P., a wholly-owned entity of the Partnership (the “Operating Partnership”), amended the November 22, 2004, Credit Facility to increase the commitment amount from $250 million to $300 million, and extend the term by one year to November 22, 2010.

 

The Credit Facility 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 Citibank prime rate (each plus the applicable margin). The interest rate on the outstanding borrowings at December 31, 2004 and 2005 was 2.94 and 4.74 percent, respectively. 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 (each as defined in the credit agreement) requiring the Operating Partnership to maintain, on a rolling four-quarter basis, a maximum total debt to EBITDA ratio of 4.75 to 1, which can generally be increased to 5.25 to 1 during an acquisition period; and an interest coverage ratio of at least 3.0 to 1. The Operating Partnership is in compliance with these covenants as of December 31, 2005. The Partnership’s ratio of total debt to EBITDA was 2.9 to 1 and the interest coverage ratio was 5.2 to 1 for the year ended December 31, 2005.

 

Senior Notes

 

The Senior Notes were issued in connection with the February 2002 IPO by the Operating Partnership at a discount of 99.325 percent of the principal amount, are due February 15, 2012, and bear interest at 7.25 percent. The discount is amortized on a straight-line basis over the term of the Senior Notes and is included within interest expense in the statements of income. 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, 2005. 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 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 partnerships, deferred charges, and cash and cash equivalents of $21.6 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 partnerships. See Note 18 for supplemental condensed consolidating financial information.

 

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

 

Year Ended December 31:


    

2010

   $ 106,600

2012

     250,000
    

     $ 356,600
    

 

Cash payments for interest related to long-term debt, net of capitalized interest (see Note 1), were $19.3 million, $19.4 million and $20.6 million in 2003, 2004 and 2005, respectively.

 

10. Commitments and Contingent Liabilities

 

Total rental expense for 2003, 2004 and 2005 amounted to $4.5 million, $4.5 million and $4.7 million, respectively. The Partnership, as lessee, has noncancelable operating leases for land, office space and equipment for which the aggregate amount of future minimum annual rentals as of December 31, 2005 is as follows (in thousands of dollars):

 

Year Ended December 31:


    

2006

   $ 3,157

2007

     3,020

2008

     2,669

2009

     2,204

2010

     1,980

Thereafter

     7,359
    

Total

   $ 20,389
    

 

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, 2004 and 2005, there were accrued liabilities for environmental remediation in the balance sheets of $0.8 million and $0.6 million, respectively. The accrued liabilities for environmental remediation do not include any amounts attributable to unasserted claims, nor have any recoveries from insurance been assumed. Charges against income for environmental remediation totaled $1.2 million, $1.4 million and $1.6 million for the years ended December 31, 2003, 2004 and 2005, 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 Partnership is a party to certain pending and threatened claims. Although the ultimate outcome of these claims cannot be ascertained at this time, it is reasonably possible that some portion of them could be resolved unfavorably to the 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

 

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the Partnership at December 31, 2005. 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, 2005. There are certain other pending legal proceedings related to matters arising after the February 2002 IPO that are not indemnified by Sunoco. Management believes that any liabilities that may arise from these legal proceedings will not be material in relation to the financial position of the Partnership at December 31, 2005.

 

11. Management Incentive Plan

 

Sunoco Partners LLC, the general partner of the Partnership, has adopted the Sunoco Partners LLC Long-Term Incentive Plan (“LTIP”) for employees and directors of the general partner who perform services for the Partnership. The LTIP is administered by the independent directors of the Compensation Committee of the general partner’s board of directors. 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 foregoing. The general partner will be entitled to reimbursement by the Partnership for the cost incurred in

 

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acquiring common units. If the Partnership issues new common units upon vesting of the restricted units, the total number of common units outstanding will increase. The Compensation Committee, in its discretion, may grant tandem distribution equivalent rights (“DERs”) with respect to the restricted units. 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.

 

The following table provides the LTIP restricted unit activity for the three-year period ended December 31, 2005:

 

     2003

    2004

   2005

 

Outstanding at January 1

   185,625     264,247    341,821  

Granted(1)

   66,714     52,045    55,787  

Performance factor adjustment(2)

   19,508     25,529    53,180  

Matured

   —       —      (219,042 )

Cancelled

   (7,600 )   —      (3,114 )
    

 
  

Outstanding at December 31

   264,247     341,821    228,632  
    

 
  


(1) The weighted average price for restricted unit awards on the date of grant was $24.94, $37.15 and $41.93 for awards granted in 2003, 2004 and 2005, respectively.
(2) Consists of adjustments to performance-based awards to reflect actual performance. The adjustments are required since the original grants of these awards were at 100 percent of the targeted amounts.

 

The Partnership recognized non-cash compensation expense of $2.2 million, $3.2 million and $3.2 million for the years ended December 31, 2003, 2004 and 2005, respectively, related to the unit grants and performance factor adjustments noted in the table above. Each of the restricted unit grants also have tandem DERs which are recognized as a reduction of Partners’ Capital when earned.

 

Unit Options

 

A unit option entitles the grantee to purchase a common unit at a price determined at the date of grant by the Compensation Committee. There have been no grants of unit options for the years ended December 31, 2003, 2004 and 2005, and there are no unit options outstanding as of December 31, 2005. 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.

 

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

 

12. Cash Distributions

 

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

 

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The Partnership had 8,537,729 subordinated units issued as of December 31, 2005, all of which were held by the general partner and for which there is no established public trading market. The Partnership issued 11,383,639 subordinated units to its general partner in connection with the 2002 IPO. 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. In addition, one quarter of the subordinated units may convert to common units on a one-for-one basis after both December 31, 2004 and December 31, 2005, if the Partnership meets the required tests for the preceding three consecutive, non-overlapping four-quarter periods. When 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.

 

During the subordination period, the Partnership will generally 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 discussed below.

 

The Partnership has met the minimum quarterly distribution requirements on all outstanding units for each of the four-quarter periods ended December 31, 2003, 2004 and 2005. As a result, a total of 5,691,820 subordinated units have been converted into common units on a one-for-one basis, 2,845,910 each on February 15, 2005 and February 15, 2006. As a result, there are 5,691,819 subordinated units outstanding at February 28, 2006, all of which may be converted in February 2007 as long as the Partnership continues to meet the financial tests noted above for each of the four-quarter periods ending December 31, 2004, 2005 and 2006.

 

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

 

Quarterly Cash Distribution Amount per Unit


   Percentage of Distributions

 
   Unitholders

    General Partner

 

Up to minimum quarterly distribution ($0.45 per Unit)

   98 %   2 %

Above $0.45 per Unit up to $0.50 per Unit

   98 %   2 %

Above $0.50 per Unit up to $0.575 per Unit

   85 %   15 %

Above $0.575 per Unit up to $0.70 per Unit

   75 %   25 %

Above $0.70 per Unit

   50 %   50 %

 

If cash distributions exceed $0.50 per unit in a quarter, the general partner will receive increasing percentages, up to 50 percent, of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions”. The amounts shown in the table under “Percentage of Distributions” are the percentage interests of the general partner and the unitholders in any available cash from operating surplus that is distributed up to and including the corresponding amount in the column “Quarterly Cash Distribution Amount per Unit,” until the available cash that is distributed reaches the next target distribution level, if any. The

 

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percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

 

Distributions paid by the Partnership during the years ended December 31, 2003, 2004 and 2005 were as follows:

 

Date Cash
Distribution Paid


   Cash
Distribution
per Limited
Partner Unit