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, 2002

 

OR

 

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

 

For the transition period from            to            

Commission file number 1-31219

 


 

SUNOCO LOGISTICS PARTNERS L.P.

(Exact name of registrant as specified in its charter)

 


 

Delaware

 

23-3096839

(State or other jurisdiction of incorporation or organization)

 

(I.R.S. Employer Identification No.)

Ten Penn Center
1801 Market Street, Philadelphia, PA

 

19103-1699

(Address of principal executive offices)

 

(Zip Code)

 

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

 


 

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

 

 

Title of each class


 

Name of each exchange on which registered


Common Units representing limited partnership interests

 

New York Stock Exchange

Senior Notes 7.25%, due February 15, 2012

 

New York Stock Exchange

 

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

 


 

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

 

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

 

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

 

The aggregate value of the Common Units held by non-affiliates of the registrant (treating all executive officers and directors of the registrant and holders of 10% 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 $124.5 million on June 28, 2002, based on $21.82 per unit, the closing price of the Common Units as reported on the New York Stock Exchange on that date.

 

At February 28, 2003, the number of the registrant’s Common Units outstanding were 11,388,154, and its Subordinated Units outstanding were 11,383,639.

 

DOCUMENTS INCORPORATED BY REFERENCE: NONE

 



Table of Contents

TABLE OF CONTENTS

 

PART I

  

1

        ITEM 1.

 

BUSINESS

  

1

        ITEM 2.

 

PROPERTIES

  

33

        ITEM 3.

 

LEGAL PROCEEDINGS

  

34

        ITEM 4.

 

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

  

34

PART II

  

35

        ITEM 5.

 

MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED SECURITYHOLDER MATTERS

  

35

        ITEM 6.

 

SELECTED FINANCIAL DATA

  

37

        ITEM 7.

 

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

  

40

        ITEM 7A.

 

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

  

62

        ITEM 8.

 

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

  

63

        ITEM 9.

 

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

  

92

PART III

  

93

        ITEM 10.

 

DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

  

93

        ITEM 11.

 

EXECUTIVE COMPENSATION

  

96

        ITEM 12.

 

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

  

101

        ITEM 13.

 

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

  

103

        ITEM 14.

 

CONTROLS AND PROCEDURES

  

108

PART IV

  

109

        ITEM 15.

 

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

  

109

SIGNATURES

  

112

CERTIFICATIONS

  

113


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Forward-Looking Statements

 

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

 

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

 

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

 

    Changes in demand for crude oil and refined petroleum products that are stored and distributed;

 

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

 

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

 

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

 

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

 

    Changes in the general economic conditions in the United States;

 

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

 

    Changes to existing or future state or federal government regulations banning or restricting the use of MTBE in gasoline;

 

    Improvements in energy efficiency and technology resulting in reduced demand;

 

    The Partnership’s ability to manage rapid growth;

 

    The Partnership’s ability to control costs;

 

    The effect of changes in accounting principles;

 

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

 

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

 

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

 

    Changes in the expected level of environmental remediation spending;

 

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

 

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


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

 

    Risks related to labor relations;

 

    Non-performance by a major customer or supplier;

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

    The costs and effects of legal and administrative claims and proceedings against the Partnership or its subsidiaries, and changes in the status of litigation to which the Partnership is a party.

 

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of the Partnership’s forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on future results. The Partnership undertakes no obligation to update publicly any forward-looking statement whether as a result of new information or future events.


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PART I

 

ITEM 1.    BUSINESS

 

(a)  General Development of Business

 

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

 

On October 22, 2001, a Registration Statement on Form S-1 related to an initial public offering (the “IPO”) of the Partnership’s common units was filed with the Securities and Exchange Commission. In February 2002, 5,750,000 common units, representing approximately 24.7% of the partnership interests, were sold to the public. Sunoco, Inc., through its wholly-owned subsidiaries (collectively, “Sunoco”), currently owns approximately 75.3% of the partnership interests, including the 2% general partner interest.

 

(b)  Financial Information about Segments

 

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

 

(c)  Narrative Description of Business

 

The Partnership is a limited partnership formed by Sunoco, Inc. to own, operate and acquire a geographically diversified portfolio of complementary energy assets. The Partnership is principally engaged in the transport, terminalling and storage of refined products and crude oil and the purchase and sale of crude oil. Sunoco, Inc. (R&M), a wholly-owned refining and marketing subsidiary of Sunoco (“Sunoco R&M”), accounted for approximately 63% of the Partnership’s revenues for the year ended December 31, 2002. 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 1,900 miles of refined product pipelines, including a one-third interest in an 80-mile refined product pipeline, and 58 miles of interrefinery pipelines between two of Sunoco R&M’s refineries; a 123-mile wholly-owned crude oil pipeline; a 9.4% interest in Explorer Pipeline Company, a joint venture that owns a 1,413-mile refined product pipeline; a 31.5% interest in Wolverine Pipe Line Company, a joint venture that owns a 719-mile refined product pipeline; a 9.2% interest in West Shore Pipe Line Company, a joint venture that owns a 596-mile refined product pipeline; and a 14.0% interest in Yellowstone Pipe Line Company, a joint venture that owns a 746-mile refined product pipeline.

 

    The Terminal Facilities consist of 32 inland refined product terminals with an aggregate storage capacity of 4.8 million barrels, primarily serving the Partnership’s Eastern Pipeline System; a 2.0 million barrel refined product terminal serving Sunoco R&M’s Marcus Hook refinery near Philadelphia, Pennsylvania; an 11.2 million barrel marine crude oil terminal on the Texas Gulf Coast, the Nederland Terminal; one inland and two marine crude oil terminals, with a combined capacity of 3.4 million barrels, and related pipelines, all of which serve Sunoco R&M’s Philadelphia refinery; and a 1.0 million barrel liquefied petroleum gas (“LPG”) terminal near Detroit, Michigan.

 

    The Western Pipeline System gathers, purchases, sells, and transports crude oil principally in Oklahoma and Texas and consists of approximately 1,868 miles of crude oil trunk pipelines and approximately 840 miles of crude oil gathering lines that supply the trunk pipelines; approximately 120 crude oil transport trucks; approximately 130 crude oil truck unloading facilities; and a 43.8% interest in West Texas Gulf Pipe Line Company, a joint venture that owns a 580-mile crude oil pipeline.

 

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The Partnership and its equity interests are principally engaged in the transport, terminalling, and storage of refined products and crude oil and in the purchase and sale of crude oil in 17 states. Revenues are generated by charging tariffs for transporting refined products and crude oil through the pipelines and by charging fees for storing refined products, crude oil, and other hydrocarbons in, and for providing other services at the Partnership’s terminals. The Partnership also generates revenue by purchasing domestic crude oil and selling it to Sunoco R&M and other customers. Generally, as crude oil is purchased, corresponding sale transactions are simultaneously entered into involving physical deliveries of crude oil, which enables the Partnership to secure a profit on the transaction at the time of purchase and establish a substantially balanced position, thereby minimizing exposure to price volatility after the initial purchase. The Partnership’s practice is to not enter into futures contracts.

 

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

 

Eastern Pipeline System

 

Sunoco R&M accounted for approximately 71% of the Eastern Pipeline segment’s total revenues for the year ended December 31, 2002.

 

Refined Product Pipelines

 

The refined product pipelines transport refined products from Sunoco R&M’s Philadelphia, Pennsylvania, Marcus Hook, Pennsylvania and Toledo, Ohio refineries, as well as from third parties, to markets in New York, New Jersey, Pennsylvania, Ohio, and Michigan. The refined products transported in these pipelines include multiple grades of gasoline, low-octane gasoline for ethanol blending, middle distillates (such as heating oil, diesel and jet fuel), LPGs (such as propane, butane, isobutane, and a butane/butylene mixture), refining feedstocks, and other hydrocarbons (such as toluene and xylene). The refined product pipelines were originally constructed between 1931 and 1967. The pipelines are regularly maintained, and management of the Partnership believes they are in good repair. The Federal Energy Regulatory Commission (“FERC”) regulates the rates for interstate shipments on the Eastern Pipeline System and the Pennsylvania Public Utility Commission (“PA PUC”) regulates the rates for intrastate shipments in Pennsylvania.

 

The following table details the average aggregate daily number of barrels of refined products transported on the refined product pipelines in each of the years presented. The information in the following table does not include interrefinery pipelines and transfer pipelines that transport large volume over short distances and generate minimal revenues:

 

    

Year Ended December 31,


    

1998


  

1999


  

2000


  

2001


  

2002


Refined products transported (in barrels per day (“bpd”))

  

431,989

  

461,379

  

444,046

  

446,648

  

489,235

 

The mix of refined petroleum products delivered varies seasonally, with gasoline demand peaking during the summer months, and demand for heating oil and other distillate fuels being higher in the winter. In addition, weather conditions in the areas served by the Eastern Pipeline System affect both the demand for, and the mix of, the refined petroleum products delivered through the Eastern Pipeline System, although historically any overall impact on the total volume shipped has been short term.

 

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

 

 

Origin and Destination


  

Miles of Pipeline


  

Diameter


         

(inches)

Philadelphia, PA to Montello, PA

  

210

  

12,8

Montello, PA to Buffalo, NY

  

300

  

14,8

Montello, PA to Kingston, PA(1)

  

84

  

6

Montello, PA to Syracuse, NY(2)

  

230

  

8,6

Montello, PA to Pittsburgh, PA

  

221

  

8

Toledo, OH to Blawnox, PA

  

260

  

10,8

Toledo, OH to Sarnia, Canada

  

241

  

8,6

Twin Oaks, PA to Newark, NJ

  

118

  

14

Philadelphia, PA to Linden, NJ(3)

  

88

  

16,12

    
    

Subtotal

  

1,752

  

N.M.

Interrefinery Pipelines(4)

  

58

  

8,6,4

Transfer Pipelines(5)

  

85

  

N.M.

    
    

Total

  

1,895

  

N.M.

    
    

N.M. Not meaningful.

 

(1)   The Partnership is seeking permission from the PA PUC to idle 74 miles of this pipeline.

 

(2)   The Partnership idled the northern-most 160 miles of this pipeline in January 2003. These assets were idled as a result of a long-term agreement entered into by the Partnership in December 2002 to lease throughput capacity on a refined product pipeline which allowed it to provide the same service as existed on the idled pipeline while reducing operating expenses.

 

(3)   The Partnership owns a one-third interest in 80 miles of this pipeline.

 

(4)   The Partnership leases these pipelines to Sunoco R&M.

 

(5)   Consist of the Toledo, Twin Oaks, and Linden transfer pipelines.

 

The following text provides additional information about each of the refined product pipelines.

 

Philadelphia, Pennsylvania to Montello, Pennsylvania.    The Philadelphia to Montello refined product pipeline system is the principal means by which Sunoco R&M moves its refined products from its Philadelphia and Marcus Hook refineries into the Partnership’s Montello terminal for further transportation on the Eastern Pipeline System. The Philadelphia to Montello pipeline system consists of four segments:

 

    a 12-inch, 60-mile segment from the Point Breeze pump station at Sunoco R&M’s Philadelphia refinery to Montello;

 

    an 8-inch, 60-mile segment from the Point Breeze pump station to Montello;

 

    an 8-inch, 39-mile segment from the Partnership’s Twin Oaks pump station, which is adjacent to the Marcus Hook Tank Farm near Sunoco R&M’s Marcus Hook refinery, to the 8-inch Point Breeze to Montello pipeline segment;

 

    an 8-inch, 51-mile segment from Boot, Pennsylvania to Fullerton, Pennsylvania.

 

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The 12-inch Point Breeze pump station to Montello segment also serves the Partnership’s Exton, Pennsylvania terminal. The 8-inch Point Breeze pump station to Montello segment connects with the 8-inch Boot to Fullerton segment at the Boot pump station and continues to Montello, with connections to a ConocoPhillips pipeline in Swarthmore, Pennsylvania and the Partnership’s terminal in Exton along its route. The 8-inch segment from the Twin Oaks pump station to the Point Breeze to Montello pipeline segment serves the Partnership’s terminal at Malvern, Pennsylvania and the Partnership’s storage facility at Icedale, Pennsylvania. The 8-inch Boot to Fullerton segment originates at the Boot pump station and terminates at the Partnership’s Fullerton terminal and Gulf Oil’s Fullerton terminal. This segment also serves terminals operated by Pipeline Petroleum Corp. and Farm & Home and delivers to a third-party pipeline in Macungie, Pennsylvania.

 

Sunoco R&M accounted for approximately three-quarters of the volume transported on this pipeline system for 2002. Other shippers on this system include ExxonMobil, BP, Gulf Oil, Major Oil, Delphi Petroleum, CITGO, Pipeline Petroleum, Farm & Home, Petroleum Products, United Refining, Griffith Oil, NOCO Energy, Pickelner, and TransMontaigne. ConocoPhillips’ Trainer, Pennsylvania refinery and Motiva’s Delaware City, Delaware refinery can access the system at the Twin Oaks pump station. Products can also enter the system from ST Services’ terminal in Philadelphia and from Valero’s Paulsboro, New Jersey refinery via ExxonMobil’s Malvern terminal. Refined products from Buckeye’s Laurel pipeline can enter this system at Montello.

 

Montello, Pennsylvania to Buffalo, New York.    The Montello to Buffalo refined product pipeline system consists of the following segments:

 

    a 14-inch, 80-mile segment and an 8-inch, 3-mile segment from Montello to Williamsport, Pennsylvania; and

 

    an 8-inch, 217-mile segment from Williamsport to Buffalo, including an 8-inch, 19-mile spur from Caledonia Junction, New York to the Rochester, New York terminals.

 

The Montello to Williamsport segment makes deliveries to Petroleum Products Corp., the Partnership’s Northumberland, Pennsylvania terminal, and to the Sunoco R&M, Farm & Home, Pickelner, and Gulf Oil terminals in the Williamsport area. The Williamsport to Buffalo segment makes deliveries to the Energy East terminal in Big Flats, New York. At Caledonia Junction, the spur runs to the Partnership’s Rochester terminal, as well as to terminals operated by ExxonMobil, Buckeye, Alaskan Oil, and Energy East. In the Buffalo area, the pipeline serves the Partnership’s terminal and those of United Refining and NOCO Energy.

 

Sunoco R&M accounted for approximately one-half of the volumes transported on this pipeline system for 2002. In addition to Sunoco R&M and the other companies who are served by this pipeline system, the Partnership also transports refined products for Agway, CITGO, BP, ConocoPhillips, El Paso, ExxonMobil, Farm & Home, Griffith Oil, Gulf Oil, Duke, Petroleum Products, Pickelner, United Refining, NOCO Energy, and Motiva. The Partnership also receives refined products for shipment into the Buffalo market through its interconnection with Buckeye’s Buckeye pipeline at Caledonia Junction.

 

Montello, Pennsylvania to Kingston, Pennsylvania.    The Montello to Kingston refined product pipeline system consists of an 84-mile, 6-inch pipeline serving the Partnership’s terminal in Kingston, the Lehigh Oil & Gas terminal in Barnesville, Pennsylvania, and the Tri-State Oil terminal in Beach Haven, Pennsylvania. In addition to Sunoco R&M, which accounted for most of the volume transported on this system for 2002, product was also transported for Griffith Oil and TransMontaigne. In early 2003, the Partnership filed a request with the PA PUC to idle 74 miles of this pipeline segment due to expected higher costs. The Partnership plans to supply its terminal in Kingston by connecting it to the Partnership’s Montello to Syracuse pipeline.

 

Montello, Pennsylvania to Syracuse, New York.    The Montello to Syracuse refined product pipeline system consists of 15 miles of 8-inch pipeline and 215 miles of 6-inch pipeline. This pipeline system serves the Partnership’s terminals in Tamaqua, Pennsylvania and Binghamton, New York, and terminates at a

 

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Hess/ExxonMobil terminal in Syracuse, New York. Sunoco R&M is the only shipper on this pipeline system. In early 2003, the Partnership idled the northern most 160 miles of this pipeline segment. This segment now ends at Kingston. Movements to Binghamton and Syracuse will now be made via the Partnership’s pipeline to Macungie and via a long-term, third-party capacity lease from Macungie to Syracuse.

 

The request to the PA PUC to idle 74 miles of the Montello to Kingston, PA pipeline segment and the idling of the northern-most 160 miles of the Montello, PA to Syracuse, NY pipeline segment were undertaken as a result of a long-term agreement entered into by the Partnership in December 2002 to lease throughput capacity on a third-party refined product pipeline which allowed it to provide substantially the same service as existed on the idled pipeline while reducing operating expenses.

 

Montello, Pennsylvania to Pittsburgh, Pennsylvania.    The Montello to Pittsburgh refined product pipeline system consists of a 221-mile, 8-inch pipeline supplied by the Partnership’s Philadelphia to Montello pipeline system and Buckeye’s Laurel pipeline at Delmont, Pennsylvania. The pipeline system serves the Partnership’s terminals located in Mechanicsburg, Altoona, Delmont, Blawnox, and Pittsburgh, Pennsylvania. This pipeline system is connected to the Partnership’s Toledo, Ohio to Blawnox pipeline system, through which the Partnership’s Pittsburgh, Blawnox, Delmont, and Altoona terminals can be supplied with refined product from Sunoco R&M’s Toledo refinery. Sunoco R&M is the only shipper on this pipeline system.

 

Toledo, Ohio to Blawnox, Pennsylvania.    The Toledo to Blawnox refined product pipeline system consists of 115 miles of 10-inch pipeline and 145 miles of 8-inch pipeline. This pipeline system transports refined products and petrochemicals from Sunoco R&M’s Toledo refinery, as well as petrochemicals from Sarnia, Canada, to the Partnership’s terminals in Akron and Youngstown, Ohio and Vanport and Blawnox, Pennsylvania. The pipeline system also makes deliveries to the Kinder Morgan Indianola, Pennsylvania facility and accesses the Inland Pipeline system owned by a subsidiary of Sunoco, Inc., BP, Citgo, and Shell. Sunoco R&M accounted for most of the volume transported on this pipeline system for 2002.

 

Toledo, Ohio to Sarnia, Canada.    The Toledo to Sarnia refined product pipeline system consists of three segments totaling 241 miles of 6-inch and 8-inch pipelines originating at Sunoco R&M’s Toledo refinery and terminating at three separate points. The system includes one 6-inch and two 8-inch pipelines running approximately 50 miles between Toledo and the Partnership’s Inkster Terminal near Detroit, Michigan. At Inkster, the 6-inch pipeline continues 11 miles to River Rouge, Michigan, and one of the 8-inch pipelines continues 80 miles to Sarnia.

 

Deliveries into and out of Toledo originate from Sunoco R&M’s Toledo refinery, BP’s Toledo refinery, Buckeye’s Buckeye pipeline, and Marathon Ashland Petroleum’s (“MAP”) Toledo terminal. The Toledo to River Rouge segment serves the Atlas, Buckeye, and MAP terminals in Taylor, Michigan and the Partnership’s Inkster Terminal and River Rouge Terminal. Product terminals in the Detroit area served by the Toledo to Sarnia segment include those of BP, MAP, and RKA. The Toledo to Sarnia segment serves the Inkster Terminal and the Consumers Power Marysville, Michigan underground storage facilities and has delivery and origin capabilities at Sarnia that include the Suncor, BP, Royal Dutch/Shell, and Novacor refineries. Each section of this system is bi-directional and can ship refined products or LPG.

 

Sunoco R&M accounted for approximately half of the volume on this system for 2002. Other shippers on this system include Suncor, CITGO, Imperial Oil, Inergy Services, Northwest Airlines, BP and Kinetic Resources.

 

Twin Oaks, Pennsylvania to Newark, New Jersey.    The Twin Oaks to Newark refined product pipeline system consists of an 111-mile, 14-inch pipeline originating at the Twin Oaks pump station, adjacent to the Partnership’s Marcus Hook Tank Farm, and terminating in Newark and Linden, New Jersey. Motiva’s Delaware City refinery, ConocoPhillips’ Trainer refinery, and Sunoco R&M’s Marcus Hook refinery can access this pipeline system at its origin. Deliveries are made to the Partnership’s Willow Grove, Pennsylvania and

 

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Piscataway and Newark, New Jersey terminals, as well as into the Linden area via a 7-mile, 12-inch spur that serves terminals owned by Kaneb, Kinder Morgan, ExxonMobil, ConocoPhillips, and Buckeye. The Partnership’s Linden transfer facility allows transfers between these third-party terminals while the Partnership’s main-line deliveries are made. In Newark, the pipeline system serves terminals owned by Lukoil and Motiva. The Partnership interconnects with Buckeye’s Laurel pipeline at the Twin Oaks pump station using a 2-mile, 16-inch transfer pipeline. Shippers on this pipeline include Sunoco R&M, which accounted for most of the volume transported in 2002, Motiva, ConocoPhillips, and Kaneb.

 

Philadelphia, Pennsylvania to Linden, New Jersey.    The Philadelphia to Linden refined product pipeline system consists of an 80-mile, 16-inch segment called the Harbor pipeline, and an 8-mile, 12-inch segment. The Partnership owns 100% of the 12-inch segment and operates the 16-inch segment, which is owned jointly, in equal percentages, by El Paso, ConocoPhillips, and the Partnership. Each owner of the 16-inch segment has a right to 60,000 bpd of capacity. The pipeline system is connected at its origin to the El Paso refinery in Eagle Point, New Jersey, the ConocoPhillips tank farm in Woodbury, New Jersey, the Gulf Oil terminal in Woodbury, and Sunoco R&M’s Philadelphia refinery. Sunoco R&M can also deliver product to the Gulf Oil terminal while other parties are shipping product to New York. Deliveries at Linden are made to a ConocoPhillips terminal, a Gulf Oil terminal, CITGO terminals, and Buckeye’s and El Paso’s pipelines. This pipeline system is also connected and makes deliveries into the Partnership’s Twin Oaks, Pennsylvania to Newark pipeline, allowing the Partnership to transport refined product to its Newark, New Jersey terminal. Sunoco R&M accounted for all of the Partnership’s allocated share of the volume transported on the 16-inch segment for 2002 and for all of the volume transported on the 12-inch segment for the same period.

 

Interrefinery Pipelines

 

The Partnership leases to Sunoco R&M, for a fixed amount, three bi-directional 18-mile pipelines and a four-mile pipeline spur extending to the Philadelphia International Airport. One pipeline and the spur transfer jet fuel from Sunoco R&M’s Philadelphia and Marcus Hook refineries to the Philadelphia International Airport. A second pipeline transfers LPG to and from Sunoco R&M’s Philadelphia refinery and Marcus Hook storage facility. The third pipeline transfers gasoline blending components and intermediate feedstocks between Sunoco R&M’s Marcus Hook and Philadelphia refineries. The third pipeline is used to optimize refinery operations, such as gasoline blending and unit turnaround scheduling.

 

Crude Oil Pipeline

 

This 123-mile, 16-inch crude oil pipeline runs from Marysville, Michigan to Toledo, Ohio. This pipeline receives crude oil from the Lakehead pipeline system for delivery to Sunoco R&M and BP refineries located in Toledo, Ohio and to MAP’s Samaria, Michigan tank farm, which supplies its refinery in Detroit, Michigan. Marysville is also a truck injection point for local production. Sunoco R&M is the major shipper on the pipeline. The pipeline was built in 1967 and its tariffs are regulated by the FERC. This pipeline is regularly maintained and management of the Partnership believes that it is in good repair.

 

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,


    

1998


  

1999


  

2000


  

2001


  

2002


Crude oil transported (bpd)

  

88,638

  

81,464

  

91,464

  

98,226

  

95,311

 

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Explorer Pipeline

 

The Partnership owns a 9.4% interest in Explorer Pipeline Company (“Explorer”), a joint venture that owns and operates an 1,413-mile common carrier refined product pipeline. Other owners of Explorer are Shell, MAP, ChevronTexaco, CITGO, and ConocoPhillips. The system 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. The pipeline was built in 1972. Refined products transported on this system primarily include gasoline, jet fuel, diesel fuel, and heating oil. Shippers on the pipeline include most of the affiliates of the owners and many non-affiliated customers. The Partnership and its affiliates do not ship on the pipeline. In 2000, the FERC approved Explorer’s application for market-based rates for all its tariffs. The Partnership receives a quarterly cash dividend from Explorer that is commensurate with the ownership interest.

 

Volume transported on this system has increased as the refining centers in the Gulf Coast region have increased shipments to meet higher demand. Explorer is currently completing an expansion of the system’s capacity by 130,000 bpd from Port Arthur to Tulsa and by 100,000 bpd from Tulsa to Chicago. The expansions, planned to be completed in the second quarter of 2003, are currently projected to cost more than $100 million. The Partnership will not be required to make an equity contribution to finance these capital expenditures. A member of the Partnership’s management team serves on Explorer’s board of directors.

 

Wolverine Pipe Line

 

On November 15, 2002, the Partnership acquired a 31.5% interest in Wolverine Pipe Line Company (“Wolverine”), a joint venture that owns and operates a 719-mile common carrier refined product pipeline. Other owners of Wolverine are Citgo, ExxonMobil, MAP, and Shell. The system originates from the Chicago, Illinois refining center and extends to Detroit, Grand Haven, and Bay City, Michigan and Toledo, Ohio with delivery points along the way. Refined products transported on this system include gasoline, jet fuel, diesel fuel, and heating oil. Shippers on the pipeline include affiliates of most of the owners and several non-affiliated customers. The Partnership and its affiliates do not ship on the pipeline. In 2002, the FERC approved Wolverine’s application for market-based rates for the Detroit, Jackson, Niles, Hammond, and Lockport destinations. The Partnership receives a quarterly cash dividend from Wolverine that is commensurate with its ownership interest.

 

In 1999, Wolverine purchased the pipeline assets belonging to Total in Michigan that supported the Alma refinery. Wolverine has used these assets to make deliveries to Lansing and Bay City. Since the purchase, Wolverine has been expanding the capacity to those cities and expects to complete the expansion in 2003.

 

West Shore Pipe Line

 

On November 15, 2002, the Partnership acquired a 9.2% interest in West Shore Pipe Line Company (“West Shore”), a joint venture that owns and operates a 596-mile common carrier refined product pipeline. Other owners of West Shore are Citgo, ExxonMobil, MAP, Buckeye, and Shell. The system originates from the Chicago, Illinois refining center and extends to Madison and Green Bay, Wisconsin with delivery points along the way. Refined products transported on this system include gasoline, jet fuel, diesel fuel, and heating oil. Shippers on the pipeline include affiliates of most of the owners and several non-affiliated customers. The Partnership and its affiliates do not ship on the pipeline. In 2002, the FERC approved West Shore’s application for market-based rates for the Chicago area. The Partnership receives a quarterly cash dividend from West Shore that is commensurate with its ownership interest.

 

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Yellowstone Pipe Line

 

On November 15, 2002, the Partnership acquired a 14.0% interest in Yellowstone Pipe Line Company (“Yellowstone”), a joint venture that owns and operates a 746-mile common carrier refined product pipeline. Other owners of Yellowstone are ExxonMobil and ConocoPhillips. The system originates from the Billings, Montana refining center and extends to Spokane, Washington with delivery points along the way. Refined products transported on this system include gasoline, jet fuel, diesel fuel, and heating oil. Shippers on the pipeline include affiliates of the owners and some non-affiliated customers. The Partnership and its affiliates do not ship on the pipeline.

 

Since 1996, Yellowstone has not paid a dividend due to restrictions under existing credit facility covenants due to additional debt incurred as a result of a multi-year pipeline upgrade program.

 

Terminal Facilities

 

Sunoco R&M accounted for approximately 64% of the Terminal Facilities segment’s total revenues for the year ended December 31, 2002.

 

Refined Product Terminals

 

The Partnership’s 32 inland refined product terminals receive refined products from pipelines and distribute them to Sunoco R&M and to third parties, who in turn deliver them to end-users and retail outlets. Terminals play a key role in moving to the end-user market by providing the following services: storage and inventory management; distribution; blending to achieve specified grades of gasoline; and other ancillary services that include the injection of additives and the filtering of jet fuel.

 

Typically, the Partnership’s terminal facilities consist of multiple storage tanks and are equipped with automated truck loading equipment that is available 24 hours a day. This automated system provides for control of allocations, credit and carrier certification by remote input of data by the Partnership’s customers. In addition, all of the Partnership’s terminals are equipped with truck loading racks capable of providing automated blending to individual customer specifications.

 

The Partnership’s refined product terminals derive most of their revenues from terminalling fees paid by customers. A fee is charged for transferring refined products from the terminal to trucks, barges, or pipelines. In addition to terminalling fees, the Partnership’s revenues are generated by charging customers fees for blending, injecting additives, and filtering jet fuel. The Partnership generates the balance of its revenues from other hydrocarbons handled for Sunoco R&M in Vanport, Pennsylvania and Toledo, Ohio and for lubricants handled for Sunoco R&M in 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 inland refined product terminals. Third-party pipelines supply the remainder of the inland refined product terminals.

 

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

 

    

Year Ended December 31,


    

1998


  

1999


  

2000


  

2001


  

2002


Refined products terminalled (bpd)

  

234,058

  

251,627

  

266,212

  

272,698

  

272,788

 

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The following table outlines the locations of the inland refined product terminals and their storage capacities, supply source and mode of delivery:

 

Location


  

Storage
Capacity


  

Supply Source


  

Mode of
Delivery


    

(bbls)

         

Akron, OH

  

98,200

  

Pipeline

  

Truck

Altoona, PA

  

103,400

  

Pipeline

  

Truck

Belmont, PA(1)

  

0

  

Refinery

  

Truck

Binghamton, NY(2)

  

60,000

  

Pipeline

  

Truck

Blawnox, PA

  

72,100

  

Pipeline

  

Truck

Buffalo, NY

  

358,500

  

Pipeline

  

Truck

Cleveland, OH

  

255,000

  

Pipeline/Rail

  

Truck

Columbus, OH

  

78,900

  

Pipeline

  

Truck

Dayton, OH

  

248,700

  

Pipeline

  

Truck

Delmont, PA

  

233,900

  

Pipeline

  

Truck

Exton, PA

  

132,200

  

Pipeline

  

Truck

Fullerton, PA

  

161,700

  

Pipeline

  

Truck

Huntington, IN

  

207,000

  

Pipeline

  

Truck

Inwood, NY(3)

  

54,200

  

Pipeline

  

Truck

Kingston, PA

  

148,800

  

Pipeline

  

Truck

Malvern, PA

  

62,900

  

Pipeline

  

Truck

Mechanicsburg, PA

  

166,200

  

Pipeline

  

Truck

Montello, PA

  

67,900

  

Pipeline

  

Truck

Newark, NJ

  

581,100

  

Pipeline/Marine

  

Truck/Marine

Northumberland, PA

  

170,300

  

Pipeline

  

Truck

Owosso, MI

  

233,300

  

Pipeline

  

Truck

Paulsboro, NJ

  

81,000

  

Pipeline

  

Truck/Pipeline

Piscataway, NJ

  

95,000

  

Pipeline

  

Truck

Pittsburgh, PA

  

205,500

  

Pipeline/Rail

  

Truck

River Rouge, MI

  

178,400

  

Pipeline

  

Truck

Rochester, NY

  

173,000

  

Pipeline

  

Truck

Tamaqua, PA

  

113,600

  

Pipeline

  

Truck

Toledo, OH

  

102,400

  

Refinery/Rail

  

Truck

Twin Oaks, PA

  

90,000

  

Refinery

  

Truck

Vanport, PA

  

179,300

  

Pipeline/Marine

  

Truck/Marine

Willow Grove, PA

  

85,000

  

Pipeline

  

Truck

Youngstown, OH

  

22,700

  

Pipeline

  

Truck

    
         

Total

  

4,820,200

         
    
         

(1)   This terminal receives product from Sunoco R&M’s Philadelphia refinery and does not have any tankage. This terminal is part of the Philadelphia refinery and is owned by an affiliate of Sunoco, Inc. That affiliate has leased the terminal to the Partnership until the terminal can be platted as a separate lot. If the terminal is platted as a separate lot, the terminal will be conveyed to the Partnership for nominal consideration.

 

(2)   This terminal was idled in early 2003.

 

(3)   The Partnership has a 45% ownership interest in this terminal. The capacity represents the proportionate share of capacity attributable to the Partnership’s ownership interest.

 

The Nederland Terminal

 

The Texas Gulf Coast region is the major hub for petroleum refining in the United States. Growth in refining capacity in this region, including new heavy oil conversion projects, and increased product flow from the

 

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Gulf Coast region to other regions has created a need for additional transportation, storage, and distribution facilities on the Gulf Coast. Management of the Partnership believes that demand for imported crude oil and for petroleum products refined in the Gulf Coast region will continue to increase.

 

The Nederland Terminal, which is located on the Sabine-Neches waterway between Beaumont and Port Arthur, Texas, is a large marine terminal that provides inventory management, storage, and distribution services for refiners and other large end-users of crude oil. The Nederland Terminal receives, stores, and distributes crude oil, feedstocks, lubricants, petrochemicals, and bunker oils (used for fueling ships and other marine vessels). In addition, the Nederland Terminal also blends and packages lubricants and is equipped with petroleum laboratory facilities.

 

The Nederland Terminal currently has a total storage capacity of approximately 11.2 million barrels in 126 aboveground storage tanks with individual capacities of up to 660,000 barrels. The terminal currently uses its aggregate storage capacity as follows:

 

    9.7 million barrels for crude oil;

 

    1.0 million barrels for feedstocks;

 

    272,000 barrels for lubricants;

 

    150,000 barrels for bunker oils; and

 

    80,000 barrels for petrochemicals.

 

In May 2002, the Partnership announced the construction of 2 new storage tanks, which will add 1.3 million barrels of capacity. Construction is expected to be completed in the second quarter of 2003.

 

The 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 a total of 1.0 million bpd of crude oil. The terminal can also receive crude oil through a number of pipelines, including the Shell pipeline from Louisiana, the Department of Energy (“DOE”) Big Hill pipeline, the DOE West Hackberry pipeline, the EOTT Louisiana pipeline system, and the Partnership’s Western Pipeline System. The DOE pipelines connect the Nederland Terminal to the United States Strategic Petroleum Reserve’s West Hackberry caverns at Hackberry, Louisiana and Big Hill caverns near Winnie, Texas, which have an aggregate storage capacity of 370 million barrels. The Nederland Terminal’s pipeline connections to major markets in the Lake Charles, Beaumont, Port Arthur, Houston, and Midwest areas provide customers with maximum flexibility.

 

The Nederland Terminal can deliver crude oil and other petroleum products via pipeline, barge, ship, rail, or truck. In the aggregate, the Nederland Terminal is capable of delivering over 1.0 million bpd of crude oil to 12 connecting pipelines.

 

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

 

   

Year Ended December 31,


   

1998


 

1999


 

2000


 

2001


 

2002


Crude oil and refined products terminalled (bpd)

 

475,796

 

544,624

 

566,941

 

427,194

 

405,686

 

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The following table describes the Nederland Terminal’s pipeline delivery connections, including the destination of the pipelines to which the Partnership can deliver, the diameter of each pipeline, the rate which the Partnership can make deliveries, and the key delivery points along each pipeline’s route:

 

Pipeline


 

Destination


  

Diameter


 

Delivery
Rate


  

Key Delivery Points


        

(inches)

 

(bpd)

    

ExxonMobil

 

Beaumont, Texas

  

24

 

300,000

  

ExxonMobil’s Beaumont refinery

ExxonMobil

 

Wichita Falls, Texas

and Patoka, Illinois

  

20

 

225,000

  

Basin’s pipeline to Cushing, Oklahoma
Valero L.P.’s pipeline to Valero Energy
Corporation’s McKee, Texas and Ardmore,
Oklahoma refineries
ConocoPhillips’ pipeline to its Ponca City,
Oklahoma refinery
Pipelines supplying Midwest refineries

Shell

 

Houston, Texas

  

20

 

200,000

  

Houston area refineries

Premcor

 

Port Arthur, Texas

  

32

 

250,000

  

Premcor’s Port Arthur refinery

West Texas Gulf

 

Longview, Texas

  

26

 

250,000

  

Mid-Valley pipeline to Midwest
refineries
CITGO’s pipeline to its Lake Charles,
Louisiana refinery
BP’s pipeline to Cushing
McMurrey’s pipeline to Crown Central’s
Tyler, Texas refinery

Alon

 

Big Springs, Texas

  

10

 

25,000

  

Alon’s Big Springs refinery

TotalFinaElf

 

Port Arthur, Texas

  

10

 

50,000

  

Atofina Port Arthur

TotalFinaElf

 

Port Arthur, Texas

  

8

 

35,000

  

Atofina Port Arthur refinery

DOE

 

Big Hill caverns

  

36

 

250,000

  

DOE’s Strategic Petroleum Reserve

DOE

 

West Hackberry caverns

  

42

 

250,000

  

DOE’s Strategic Petroleum Reserve

The Partnership

 

Longview, Texas

  

10

 

50,000

  

Mid-Valley pipeline to Midwest
refineries
CITGO’s pipeline to its Lake Charles
refinery
BP’s pipeline to Cushing
McMurrey’s pipeline to Crown Central’s
Tyler refinery

The Partnership

 

Seabreeze, Texas

  

10

 

35,000

  

TEPPCO’s pipeline to BASF/Fina’s Port

Arthur steam cracker

 

Revenues are generated at the Nederland Terminal primarily by providing long-term and short-term, or spot, storage services and throughput capability to a broad spectrum of customers. Approximately 89% of the terminal’s total revenues in 2002 came from unaffiliated third parties. A significant portion of the Nederland Terminal’s revenues are derived from multi-year contracts, which enhance the stability and predictability of its revenue stream.

 

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 Sunoco R&M and others a storage fee based on tank capacity and

 

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throughput. Substantially all of the revenues from the Fort Mifflin Terminal Complex are derived from Sunoco R&M.

 

Fort Mifflin Terminal.    The Fort Mifflin Terminal consists of two ship docks with 40-foot freshwater drafts and nine tanks with a total storage capacity of 570,000 barrels. Six 80,000-barrel tanks are used to store crude oil, and three 30,000-barrel tanks are used to provide fuel to ships. Two of the 80,000-barrel tanks can be used to store refined products. This terminal also has a connection with the Colonial Pipeline System.

 

Crude oil and some refined products enter the Fort Mifflin Terminal primarily from marine vessels on the Delaware River. One Fort Mifflin dock is designed to handle crude oil from very large crude carrier-class tankers and smaller crude oil vessels. The other dock can accommodate only smaller crude oil vessels.

 

Hog Island Wharf.    The Hog Island Wharf is located next to the Fort Mifflin Terminal on the Delaware River. The Hog Island Wharf receives crude oil via two ship docks, one of which can accommodate crude oil tankers and smaller crude oil vessels and the other of which can accommodate some smaller crude oil vessels. Hog Island Wharf supplies the Partnership’s Darby Creek Tank Farm and Fort Mifflin Terminal with crude oil. Crude oil from the Hog Island Wharf is delivered to Sunoco R&M’s Philadelphia refinery via the Darby Creek Tank Farm.

 

Darby Creek Tank Farm.    The Darby Creek Tank Farm is a primary crude oil storage terminal for Sunoco R&M’s Philadelphia refinery. This facility has 26 tanks with a total storage capacity of 2.9 million barrels. Darby Creek receives crude oil from the Fort Mifflin Terminal and Hog Island Wharf via the Partnership’s 24-inch pipelines. The tank farm then stores the crude oil and pumps it to the Philadelphia refinery via the Partnership’s 16-inch pipeline. The multiple tanks in this storage facility provide added flexibility in blending crude oil to achieve the optimal crude oil slate for the Philadelphia refinery.

 

Crude Oil and Refined Product Delivery.    The Fort Mifflin Terminal Complex includes a number of crude oil pipelines:

 

    one 30-inch pipeline and one 16-inch pipeline that deliver crude oil from the Fort Mifflin Terminal to Sunoco R&M’s Philadelphia refinery;

 

    two 24-inch pipelines that deliver crude oil from the Hog Island Wharf to the Darby Creek Tank Farm;

 

    one 16-inch pipeline that delivers crude oil from the Darby Creek Tank Farm to Sunoco R&M’s Philadelphia refinery; and

 

    one 30-inch bi-directional pipeline that delivers crude oil between the Hog Island Wharf and the Fort Mifflin Terminal.

 

The Fort Mifflin Terminal Complex also includes several pipelines that deliver refined products to Sunoco R&M’s Philadelphia refinery:

 

    one 30-inch pipeline and one 16-inch pipeline that deliver refined products from the Fort Mifflin Terminal to Sunoco R&M’s Philadelphia refinery for transportation on the Eastern Pipeline System; and

 

    one dual diameter, 24- and 26-inch pipeline that delivers refined products from the Hog Island Wharf to Sunoco R&M’s Philadelphia refinery.

 

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The Partnership charges Sunoco R&M a fee for each barrel delivered to its Philadelphia refinery via the Fort Mifflin Terminal or the Darby Creek Tank Farm. 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,


    

1998


  

1999


  

2000


  

2001


  

2002


Crude oil transported (bpd)

  

306,181

  

297,271

  

306,121

  

309,435

  

310,981

Refined products transported (bpd)

  

9,316

  

9,263

  

8,502

  

9,110

  

11,323

    
  
  
  
  

Total (bpd)

  

315,497

  

306,534

  

314,623

  

318,545

  

322,304

    
  
  
  
  

 

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 17 tanks with a total storage capacity of approximately 2.0 million barrels. After receipt of refined products from the Marcus Hook refinery, the tank farm either stores them 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 throughput for the Marcus Hook Tank Farm in each of the years presented:

 

    

Year Ended December 31,


    

1998


  

1999


  

2000


  

2001


  

2002


Refined products terminalled (bpd)

  

138,556

  

142,404

  

133,455

  

138,490

  

149,982

 

The Inkster Terminal

 

The Inkster Terminal, located near Detroit, Michigan, consists of eight salt caverns with a total storage capacity of 975,000 barrels. The Partnership uses the Inkster Terminal’s storage in connection with its Toledo, Ohio to Sarnia, Canada pipeline system and for the storage of LPGs from Sunoco R&M’s Toledo refinery and from Canada. The terminal can receive and ship LPGs in both directions at the same time and has a propane truck loading rack. For the last five years, Sunoco R&M has used the full capacity of the Inkster Terminal. Buckeye has access to the terminal through the Partnership’s spur line to Joan Junction in Taylor, Michigan.

 

Western Pipeline System

 

Sunoco R&M accounted for approximately 62% of the Western Pipeline System segment’s total revenues for the year ended December 31, 2002.

 

Crude Oil Pipelines

 

The Partnership owns and operates approximately 1,870 miles of crude oil trunk pipelines and approximately 840 miles of crude oil gathering lines in three primary geographic regions—Oklahoma, West Texas, and the Texas Gulf Coast and East Texas region. The Partnership is the primary shipper on the Western Pipeline System. The Partnership also delivers crude oil for Sunoco R&M and for various third parties from points in Texas and Oklahoma. Delivery points on the Western Pipeline System include Sunoco R&M’s and Sinclair’s Tulsa, Oklahoma refineries and the Gary-Williams refinery in Wynnewood, Oklahoma.

 

The Partnership’s pipelines also access several trading hubs, including the largest and most significant trading hub for crude oil in the United States located in Cushing, Oklahoma, as well as other trading hubs located in Colorado City and Longview, Texas. The Partnership’s crude oil pipelines also connect with other pipelines

 

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that deliver crude oil to a number of third-party refineries. The majority of the pipelines in the Western Pipeline System were constructed between 1925 and 1967. The Partnership’s pipelines are subject to ongoing maintenance, and management of the Partnership believes they are in good repair.

 

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

 

    

Year Ended December 31,


    

1998


  

1999


  

2000


  

2001


  

2002


Crude oil transported (bpd)(1)

  

253,124

  

252,098

  

295,991

  

287,237

  

286,912


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

 

In each geographic region, the Partnership has major crude oil trunk line systems that ship crude oil across a number of different-sized trunk pipeline segments. The following table details the mileage and diameter for the pipelines in each major crude oil trunk line system. The Partnership transported most of the crude oil to and lube extracted feedstock from Sunoco R&M’s Tulsa, Oklahoma refinery for the year ended December 31, 2002.

 

Major System


  

Miles of
Pipeline


  

Diameter


         

(inches)

Oklahoma

         

Enid to Tulsa

  

304

  

4,6,8,10,12

Velma to Tulsa

  

248

  

4,6,8,10

Other

  

129

  

4,6,8,12

West Texas

         

Jameson and Salt Creek to Colorado City

  

93

  

6,8

Hearne to Hawley

  

453

  

6,8,12,16

Hawley to Dixon

  

242

  

8,10

Other

  

29

  

8

Texas Gulf Coast and East Texas

         

Seabreeze and Orange to Nederland

  

39

  

6,10

Nederland to Longview

  

199

  

10,12

Baytown to Nederland

  

124

  

6,8

Thomas to Longview

  

3

  

8

Other

  

5

  

8

 

Oklahoma

 

The Partnership owns and operates a large crude oil pipeline and gathering system in Oklahoma. This system contains 681 miles of crude oil trunk pipelines and 443 miles of crude oil gathering lines. The Partnership has the ability to deliver all of the crude oil gathered on its Oklahoma system to Cushing. Additionally, deliveries are made on the Oklahoma system to:

 

    Sunoco R&M’s Tulsa refinery;

 

    Sinclair’s Tulsa refinery;

 

    Gary-Williams’ Wynnewood refinery; and

 

    ConocoPhillips’ pipeline to its Ponca City refinery.

 

Revenues are generated on the Partnership’s Oklahoma system from tariffs paid by shippers utilizing the Partnership’s transportation services. The Partnership files these tariffs with the Oklahoma Corporation

 

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Commission and the FERC. The Partnership is the largest purchaser of crude oil from producers in the state, and is the primary shipper on its Oklahoma system. Other significant shippers are Sunoco R&M and Sinclair, which ship primarily on the Cushing to Tulsa segment.

 

The Partnership’s Oklahoma crude oil pipelines consist of two major systems, the Enid to Tulsa system and the Velma to Tulsa system, and several smaller pipelines.

 

Enid, Oklahoma to Tulsa, Oklahoma.    The Enid to Tulsa crude oil pipeline system originates in Northwestern Oklahoma, connects to the Cushing, Oklahoma trading hub, and terminates in Tulsa at the Sunoco R&M and Sinclair refineries. This system has three segments which deliver crude oil received from trucks and gathering systems to Enid for further delivery on this system. Enid is a hub from which Partnership crude oil is transported on its two east-bound pipelines to third-party pipelines and refineries, and to the Cushing trading hub. The two east-bound pipelines from Enid include the Partnership’s Enid to Morris pipeline, which connects to ConocoPhillips’ pipeline, which delivers to its Ponca City refinery, and the Partnership’s Enid to Cushing pipeline, which receives crude oil from the Partnership’s Oklahoma City to Douglas segment and delivers crude oil to the Partnership’s storage tanks at the Cushing trading hub.

 

Shippers utilizing the Partnership’s pipeline may also access the BP, Shell, Plains All American, and TEPPCO storage terminals in Cushing. The Partnership’s Cushing to Tulsa pipeline provides transportation services, under tariffs filed with the FERC, from third-party terminals and the Partnership’s tanks in Cushing to the Sunoco R&M and Sinclair refineries in Tulsa.

 

Velma, Oklahoma to Tulsa, Oklahoma.    The Velma to Tulsa crude oil pipeline system originates in Southwestern Oklahoma, moves eastward to the Gary-Williams refinery at Wynnewood, and terminates at the Sunoco R&M and Sinclair refineries in Tulsa. This system consists of seven major segments.

 

The Velma to Eola, Eola to Maysville, and Eola to Wynnewood segments are used to transport crude oil from trucks and gathering systems owned by the Partnership and third parties to Gary-Williams’ Wynnewood refinery and to the Partnership’s pipeline that delivers to Cushing and Sunoco R&M’s Tulsa refinery. The Maysville to Seminole, Seminole to Bad Creek, Fitts to Bad Creek, and Bad Creek to Tulsa pipelines are primarily used to transport crude oil to the Sunoco R&M and Sinclair refineries in Tulsa. These pipelines are supplied by the Partnership’s gathering systems and trucks, as well as EOTT’s and Seminole Trading and Gathering’s (“STG”) gathering lines. The Partnership ships substantially all of the volumes on these pipelines.

 

Other Oklahoma Pipelines.    The Partnership’s other Oklahoma pipelines include the Tulsa to Cushing segment that transports lube extracted feedstock from Sunoco R&M’s Tulsa refinery to Cushing for ultimate delivery by third-party pipelines to other refineries for further processing. The Partnership’s Barnsdall to Tulsa segment receives crude oil gathered by the Partnership’s and a third-party’s trucks for shipment to Sunoco R&M’s Tulsa refinery.

 

West Texas

 

The Partnership owns and operates approximately 817 miles of crude oil trunk pipelines and 247 miles of crude oil gathering lines in West and North Central Texas. Deliveries are made on the West Texas system to:

 

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

 

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

 

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

 

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

 

    other third-party pipelines at Colorado City that deliver crude oil to Sunoco R&M’s Tulsa and Toledo refineries, among others.

 

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

 

The West Texas pipelines include the three following systems:

 

Jameson and Salt Creek, Texas to Colorado City, Texas.    The Jameson and Salt Creek to Colorado City crude oil pipeline system consists of two pipeline segments. Crude oil is pipeline gathered or trucked into this system and transported from Jameson to Colorado City, or from Salt Creek to Colorado City, where it can be delivered into BP, Basin, ChevronTexaco, EOTT, or West Texas Gulf pipelines. These connections allow the Partnership to deliver crude oil to Sunoco R&M’s Tulsa and Toledo refineries and other unaffiliated third-party destinations.

 

Hearne, Texas to Hawley, Texas.    The Hearne to Hawley system is comprised of the two segments delivering into Comyn, Texas, and is supplied with crude oil from the Partnership’s trucks, third-party trucks, and third-party pipelines, including the Genesis, Koch, and Plains All American pipelines located in Hearne. From Comyn, crude oil can be shipped to:

 

    the West Texas Gulf pipeline at Tye;

 

    the ConocoPhillips and TEPPCO pipelines at South Bend; or

 

    the Partnership’s pipeline at Hawley.

 

At Tye, the Partnership has tankage and a bi-directional connection with the West Texas Gulf pipeline that allows it to receive and deliver crude oil.

 

Hawley, Texas to Dixon, Texas.    On the Hawley to Dixon system, crude oil is received from the following sources:

 

    the Partnership’s Hearne to Hawley system, including West Texas Gulf’s system through Tye, Texas;

 

    Plains All American pipeline interconnections; and

 

    truck injection locations and pipeline-connected lease gathering sites.

 

The Partnership delivers this crude oil to Dixon, where it connects with the Valero L.P. pipeline that delivers crude oil to the Valero Energy Corporation refinery at McKee. Crude oil received from the Partnership’s Hearne to Hawley system accounts for approximately 40% of the volume transported on this system.

 

Texas Gulf Coast and East Texas

 

The Partnership’s Texas Gulf Coast and East Texas pipeline system includes 370 miles of crude oil trunk pipelines and 150 miles of crude oil gathering lines that extend between the Texas Gulf Coast region near Beaumont and Baytown, Texas and the East Texas field near Longview, Texas. The Partnership transports multiple grades of crude oil, including foreign imports, and other refinery and petrochemical feedstocks, such as condensate and naphtha, on these pipelines. Crude oil is received for these systems from other pipelines, the Nederland Terminal, the Partnership’s trucks, third-party trucks, and the Partnership’s pipeline gathering

 

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systems. This system provides access to major delivery points with interconnecting pipelines in Texas at Longview, Sour Lake, and Nederland.

 

Revenues are generated from tariffs paid by shippers utilizing the Partnership’s transportation services. These tariffs are filed with the Texas Railroad Commission and the FERC. The Partnership is the primary shipper on the Texas Gulf Coast and East Texas system. Sunoco R&M ships on the Nederland to Longview segment, which connects with the Mid-Valley pipeline for deliveries to Sunoco R&M’s Toledo refinery.

 

The Partnership’s Texas Gulf Coast and East Texas system consists of the following pipelines:

 

Seabreeze and Orange, Texas to Nederland, Texas.    The Seabreeze and Orange to Nederland crude oil pipeline system consists of two pipelines:

 

    a bi-directional 28-mile pipeline from Seabreeze to Nederland; and

 

    an 11-mile pipeline from Orange to Nederland.

 

The Seabreeze pipeline transports condensate received from TransTexas’ Winnie, Texas plant and by truck to the Nederland Terminal. The Seabreeze pipeline also transports naphtha for BASF/Fina from the Nederland Terminal to the TEPPCO pipeline for delivery to BASF/Fina’s new steam cracker in Port Arthur. Crude oil gathered or trucked to the Orange pipeline is transported to the Nederland Terminal for delivery to a number of destinations.

 

Nederland, Texas to Longview, Texas.    The Nederland to Longview pipeline transports primarily foreign crude oil from the Nederland Terminal to the 240,000 bpd Mid-Valley pipeline in Longview, Texas. Other connections in the Longview area include BP’s pipeline from Longview to Cushing, Oklahoma, McMurrey’s pipeline that supplies Crown Central’s Tyler, Texas refinery, and ExxonMobil’s pipeline that delivers to Wichita Falls, Texas and Patoka, Illinois.

 

Baytown, Texas to Nederland, Texas.    The Baytown to Nederland crude oil pipeline passes through Sour Lake, Texas where it makes deliveries to the Nederland to Longview pipeline and the CITGO tank farm and pipeline that supplies CITGO’s Lake Charles, Louisiana refinery. The system also delivers to the ExxonMobil Baytown, Texas refinery.

 

Thomas, Texas to Longview, Texas.    The Thomas to Longview crude oil pipeline originates in Thomas, Texas and makes deliveries to all of the connections in Longview, Texas described above. The pipeline receives crude oil from the Partnership’s pipeline gathering system in the East Texas field.

 

West Texas Gulf Pipe Line

 

On November 15, 2002, the Partnership acquired a 43.8% interest in the West Texas Gulf Pipe Line Company (“West Texas Gulf”), a joint venture that owns and operates a 580-mile common carrier crude oil pipeline. Other owners of West Texas Gulf are ChevronTexaco, 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 Mid-Valley pipeline. The pipeline was built in 1953. Shippers on the pipeline are the Partnership, Sunoco, an affiliate of one other owner and several unaffiliated customers. The Partnership receives a quarterly cash dividend from West Texas Gulf that is commensurate with its ownership interest.

 

Crude Oil Acquisition and Marketing

 

In addition to receiving tariff revenues for transporting crude oil on the Western Pipeline System, the Partnership generates most of its revenues through its crude oil acquisition and marketing operations, primarily in

 

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Oklahoma and Texas. These activities include: purchasing crude oil at the wellhead from producers and in bulk from aggregators at major pipeline interconnections and trading locations; transporting crude oil on the Partnership’s pipelines and trucks or, when necessary or cost effective, pipelines or trucks owned and operated by third parties; and marketing crude oil to refiners or resellers.

 

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

 

The Partnership mitigates most of its pricing risk on purchased contracts by selling crude oil for an equal term on a similar pricing basis. The Partnership also mitigates most of its volume risk by entering into sales agreements, generally at the same time that purchase agreements are executed, at similar volumes. As a result, volumes sold are generally equal to volumes purchased.

 

The Partnership enters into contracts with producers at market prices generally for a term of one year or less, with a majority of the transactions on a 30-day renewable basis. For the year ended December 31, 2002, the Partnership purchased approximately 189,300 bpd from approximately 3,400 producers from approximately 36,000 leases and undertook approximately 214,800 bpd of exchanges and bulk purchases during the same period.

 

Crude Oil Lease Purchases and Exchanges

 

In a typical producer’s operation, crude oil flows from the wellhead to a separator where the petroleum gases are removed. After separation, the producer treats the crude oil to remove water, sand, and other contaminants and then moves it to an on-site storage tank. When the tank is full, the producer contacts the Partnership’s field personnel to purchase and transport the crude oil to market. The crude oil in producers’ tanks is then either delivered to the Partnership’s pipeline or transported via truck to the Partnership’s pipeline or a third party’s pipeline. The trucking services are performed either by the Partnership’s truck fleet or third party trucking operations.

 

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

 

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

 

    

Year Ended December 31,


    

1998


  

1999


  

2000


  

2001


  

2002


    

(in thousands of bpd)

Lease purchases:

                        

Available for sale

  

95

  

103

  

137

  

141

  

157

Exchanged

  

58

  

38

  

36

  

33

  

32

Other exchanges and bulk purchases

  

147

  

145

  

234

  

218

  

215

    
  
  
  
  

Total

  

300

  

286

  

407

  

392

  

404

    
  
  
  
  

 

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

 

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

 

    

Year Ended December 31,


    

1998


  

1999


  

2000


  

2001


  

2002


    

(in thousands of bpd)

Sunoco R&M refineries:

                        

Toledo

  

30

  

26

  

29

  

28

  

35

Tulsa

  

57

  

63

  

73

  

71

  

73

Third parties

  

14

  

20

  

41

  

52

  

63

Exchanges:

                        

Purchased at the lease

  

58

  

38

  

36

  

33

  

32

Other

  

141

  

139

  

227

  

208

  

202

    
  
  
  
  

Total

  

300

  

286

  

406

  

392

  

405

    
  
  
  
  

 

Market Conditions

 

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

 

Producer Services

 

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

 

Credit with Customers

 

When crude oil is marketed, the Partnership must determine the amount of any line of credit to be extended to a customer. Since typical sales transactions can involve tens of thousands of barrels of crude oil, the risk of nonpayment and nonperformance by customers is a major consideration in this business. Management of the

 

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Partnership believes that its sales are made to creditworthy entities or entities with adequate credit support. Credit review and analysis are also integral to the Partnership’s lease purchases. Payment for substantially all of the monthly lease production is sometimes made to the operator of the lease. The operator, in turn, is responsible for the correct payment and distribution of such production proceeds to the proper parties. In these situations, it must be determined by the Partnership whether the operator has sufficient financial resources to make such payments and distributions and to indemnify and defend the Partnership in the event a third party brings a protest, action, or complaint in connection with the ultimate distribution of production proceeds by the operator.

 

Crude Oil Trucking

 

The Partnership owns approximately 130 crude oil truck unloading facilities in Oklahoma, Texas, and New Mexico, of which approximately 90 are located on the Partnership’s pipeline system and approximately 40 are located on third-party pipeline systems. The Partnership also owns and operates a one-mile crude oil gathering line in New Mexico, which is associated with its crude oil trucking operations there. Approximately 270 crude oil truck drivers are employed by the Partnership and approximately 120 crude oil transport trucks are owned. The crude oil truck drivers pick up crude oil at production lease sites and transport it to various truck unloading facilities on the Partnership’s pipelines and third-party pipelines. Third-party trucking firms are also retained to transport crude oil to certain facilities.

 

Pipeline and Terminal Control Operations

 

All of the Partnership’s refined products and crude oil pipelines are operated via satellite, microwave, and frame relay communication systems from central control rooms located in Montello, Pennsylvania and Tulsa, Oklahoma. The Montello control center, which was moved from Philadelphia during 2002, primarily monitors and controls the Partnership’s Eastern Pipeline System, and the Tulsa control center primarily monitors and controls the Western Pipeline System. The Montello control center, which is located at a pipeline facility located approximately 50 miles from Philadelphia, has a backup control center in Philadelphia. The Nederland Terminal has its own control center.

 

The control centers operate with modern, state-of-the-art System Control and Data Acquisition, or SCADA, systems. The control centers are equipped with computer systems designed to continuously monitor real time operational data, including refined product and crude oil throughput, flow rates, and pressures. In addition, the control centers monitor alarms and throughput balances. The control centers operate remote pumps, motors, engines, and valves associated with the delivery of refined products and crude oil. 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

 

GulfMark Acquisition.    On November 1, 2001, the Partnership acquired a 54-mile, 8-inch bi-directional crude oil pipeline and a related crude oil acquisition business from GulfMark Energy, Inc. for $5.0 million in cash. The pipeline extends from Sour Lake, Texas to Baytown, Texas and complements the existing Texas Gulf Coast and East Texas pipeline system.

 

Wolverine, West Shore and Yellowstone Pipe Line Interest Acquisition.    On November 15, 2002, the Partnership acquired an affiliate of Union Oil Company of California, whose assets include a 31.5% interest in Wolverine, a joint venture that owns a 719-mile refined product pipeline; a 9.2% interest in West Shore, a joint venture that owns a 596-mile refined product pipeline; and a 14.0% interest in Yellowstone, a joint venture that owns a 746-mile refined product pipeline, for $54 million in cash.

 

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West Texas Gulf Pipe Line Interest Acquisition.    On November 15, 2002, the Partnership acquired a 43.8% interest in West Texas Gulf, a joint venture that owns a 580-mile crude oil pipeline, from an affiliate of Sunoco, Inc. for $10.6 million, including the issuance of 4,515 Partnership common units with a fair value at the date of issuance of $0.1 million.

 

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

 

Competition

 

As a result of the physical integration with Sunoco R&M’s refineries and the contractual relationship with Sunoco pursuant to the Omnibus Agreement and Sunoco R&M pursuant to the pipelines and terminals storage and throughput agreement, management of the Partnership believes that it will not face significant competition for crude oil transported to the Philadelphia, Toledo, and Tulsa refineries, or refined products transported from the Philadelphia, Marcus Hook, and Toledo refineries, particularly during the term of the pipelines and terminals storage and throughput agreement with Sunoco R&M. For further information on this agreement, please 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, 2002, Sunoco R&M accounted for approximately 63% 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 hard 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, such as those operated by Colonial, Buckeye, ExxonMobil, and Inland) could be built to effectively compete with it in particular locations.

 

In addition, the Partnership faces competition from trucks that deliver product in a number of areas that are served. 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.

 

Explorer’s primary competition is the TEPPCO pipeline, which transports petroleum products from the Beaumont, Port Arthur and Houston, Texas refining centers to Little Rock, Indianapolis, Chicago, and other markets along its route; the Seaway pipeline, a large diameter pipeline from Houston to Cushing, Oklahoma; and Centennial Pipeline, a natural gas pipeline that was converted in 2002 into a refined products pipeline and which originates near Beaumont, Texas and terminates in southern Illinois.

 

Wolverine’s primary competition is the Buckeye pipeline from Chicago, Illinois to Toledo, Ohio and Toledo to Bay City, Michigan; the MAP pipeline from Chicago to Grand Haven, Michigan; the BP pipeline from Chicago to Detroit, Michigan; and the MAP refinery in Detroit.

 

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West Shore’s primary competition is the Koch pipeline from Minneapolis, Minnesota to the Milwaukee, Wisconsin area; the BP, ExxonMobil, and CITGO Chicago area refineries.

 

Yellowstone’s primary competition is the Chevron pipeline from Salt Lake City, Utah to Spokane, Washington; other modes of transportation; and the supply from Seattle, Washington.

 

Terminal Facilities

 

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

 

The 32 inland refined product terminals compete with other independent terminals for 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 arms.

 

The primary competitors for the Nederland Terminal are its refinery customers’ docks and terminal facilities, and the Unocal terminal and the Oil Tanking terminal, both located in Beaumont. Management of the Partnership believes the Nederland Terminal has superior docking capabilities and tankage facilities, and is better connected supply and distribution pipelines than these competing terminals.

 

The Inkster Terminal’s primary competition comes from the Marysville Underground Storage Terminal, MAP’s LPG storage facility in Trenton, Michigan and BP’s facilities in St. Clair, Michigan and Windsor, Canada. The Inkster Terminal enjoys a competitive advantage with respect to volume from Sunoco R&M’s Toledo refinery due to the relatively short distance between Toledo and the Inkster Terminal. The Partnership owns three pipelines running between Toledo and the Inkster Terminal, which provide Sunoco R&M with additional flexibility.

 

Western Pipeline System

 

The Western Pipeline System faces competition from a number of major oil companies and smaller entities. Pipeline competition among common carrier pipelines is based primarily on transportation charges, access to producing areas, and demand for the crude oil by end users. Management of the Partnership believes that high capital costs make it unlikely for other companies to build competing crude oil pipeline systems in areas served by the Western Pipeline System. Crude oil purchasing and marketing competitive factors includes price and contract flexibility, quantity and quality of services, and accessibility to end markets. The principal competitors of the Western Pipeline System are EOTT, Plains All American, ConocoPhillips, Seminole Trading and Gathering, and TEPPCO.

 

West Texas Gulf’s primary competition is numerous pipelines originating from West Texas and numerous pipelines from Nederland, Texas to Longview, Texas.

 

Inactive Assets

 

The Partnership owns approximately 381 miles of inactive trunk lines. Of those inactive trunk lines, approximately 229 miles are located in the Oklahoma pipeline system, approximately 120 miles are located in the West Texas pipeline system and approximately 32 miles are located in the Texas Gulf Coast and East Texas pipeline system. Management of the Partnership is evaluating placing some of these pipelines back in service in the future either for the transportation of crude oil or as alternative service pipelines.

 

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In January 2003, the Partnership idled the northern most 160 miles of the Montello, PA to Syracuse, NY pipeline in the Eastern Pipeline System. In addition, the Partnership is seeking permission from the PA PUC to idle 74 miles of the Montello to Kingston, PA pipeline. These assets were idled or are expected to be idled as a result of a long-term agreement entered into by the Partnership to lease throughput capacity on a third-party refined product pipeline which allowed it to provide the same service as existed on the idled pipeline while reducing operating expenses.

 

Pipeline, Terminalling, and Storage Assets Retained by Sunoco

 

Sunoco has transferred to the Partnership most of its pipeline, terminalling, storage, and related assets that support Sunoco R&M’s refinery operations. Sunoco has retained the assets described below because they are either interests in crude oil pipelines that may not provide consistent revenues and cash flows or are inactive.

 

Assets That May Not Provide Consistent Revenues and Cash Flows

 

    Mid-Valley Pipeline.    A subsidiary of Sunoco owns a 55% interest in the Mid-Valley Pipeline Company (a 50% voting interest), which owns and operates a 994-mile crude oil pipeline from Longview, Texas to Samaria, Michigan. The Mid-Valley pipeline serves a number of refineries in the Midwest United States. Because of concern that the closure of one or more of these refineries could result in a material decline in the revenues and cash flows of Mid-Valley, management of the Partnership has elected not to acquire Sunoco’s interest in Mid-Valley. Management believes that Mid-Valley could be converted to a refined product pipeline and will continue to evaluate its future prospects.

 

    Mesa Pipeline.    A subsidiary of Sunoco owns an undivided 6% interest in the Mesa pipeline, an 80-mile crude oil pipeline from Midland, Texas to Colorado City. Mesa Pipeline connects to West Texas Gulf’s pipeline, which supplies crude oil to Mid-Valley. Management of the Partnership has elected not to acquire Sunoco interest in this pipeline for the reasons discussed above.

 

    Inland Pipeline.    A subsidiary of Sunoco owns a 10% 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. The Inland pipeline is a private intrastate pipeline that is operated at cost by the shipper-owners and does not generate profits to its owners. As a result, it was not included in the assets transferred to the Partnership.

 

Sunoco has granted the Partnership a ten-year option to purchase its interest in any of the preceding assets for fair market value at the date of purchase. Sunoco’s interests in these assets are subject to agreements with the other interest owners that include, among other things, consent requirements and rights of first refusal that may be triggered upon certain transfers. The exercise of the option with respect to any of these assets is subject to the terms and conditions of those agreements, which may or may not require consents or trigger rights of first refusal, depending on the facts and circumstances existing at the time of the option exercise. On November 15, 2002, the Partnership acquired Sunoco’s 43.8% interest in West Texas Gulf pipeline. This interest included Sunoco’s 17.3% interest and a 26.5% interest Sunoco acquired from an affiliate of Union Oil Company of California in November 2002. The Partnership has no current intention to purchase the retained assets noted above.

 

Assets That Are Inactive

 

    A subsidiary of Sunoco owns an idled 370-mile, 6-inch refined product pipeline from Icedale, Pennsylvania to Cleveland, Ohio.

 

    A subsidiary of Sunoco owns various crude oil pipelines and gathering systems in Louisiana, Oklahoma, and Texas that are no longer used because of a lack of crude oil supply.

 

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    A subsidiary of Sunoco owns various refined product pipelines in the Northeast and Midwest that are no longer used because they are no longer economical to operate. Most of these lines have been idle for several years.

 

    A subsidiary of Sunoco owns two inactive refined product terminals in Maryland and Pennsylvania. Sunoco idled these terminals because they were not economical to operate.

 

Sunoco has granted the Partnership a ten-year option to purchase the pipeline from Icedale, Pennsylvania to Cleveland, Ohio for fair market value at the date of purchase. The Partnership has no current intention to purchase this pipeline.

 

Both of the ten-year option agreements described above, which expire in 2012, are contained in the Omnibus Agreement that was entered into with Sunoco, Sunoco R&M and the general partner. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Agreements with Sunoco R&M and Sunoco, Inc.” In accordance with this agreement, if the Partnership decides to exercise the option to purchase any of the assets described above, written notice must be provided to Sunoco setting forth the fair market value the Partnership proposes to pay for the asset. If Sunoco does not agree with the proposed fair market value, the Partnership and Sunoco will appoint a mutually agreed-upon, nationally recognized investment banking firm to determine the fair market value of the asset. Once the investment bank submits its valuation of the asset, the Partnership will have the right, but not the obligation, to purchase the asset at the price determined by the investment banking firm.

 

Safety Regulation

 

A majority of the Partnership’s pipelines are subject to regulation by the United States Department of Transportation (“DOT”) under the Hazardous Liquid Pipeline Safety Act of 1979 (“HLPSA”) relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities or comparable state statutes and regulations. The HLPSA covers petroleum and petroleum products pipelines and requires any entity that owns or operates pipeline facilities to comply with such safety regulations and to permit access to and copying of records and to make certain reports and provide information as required by the Secretary of Transportation.

 

Effective in August 1999, the DOT issued its Operator Qualification Rule, which required a written program by April 27, 2001 to ensure that operators were qualified to perform tasks covered by the pipeline safety rules. The Partnership identified the tasks that must be performed to comply with this rule and has developed a written program as required. All persons performing covered tasks were qualified under the program by October 28, 2002.

 

On December 1, 2000, the DOT issued new regulations intended by the DOT to assess the integrity of hazardous liquid pipeline segments that, in the event of a leak or failure, could adversely affect highly populated areas, areas unusually sensitive to environmental impact and commercially navigable waterways. Under the regulations, an operator is required, among other things, to conduct baseline integrity assessment tests (such as internal inspections) within seven years, conduct future integrity tests at typically five year intervals and develop and follow a written risk-based integrity management program covering the designated high consequence areas. Under the rule, pipeline operators were required to identify line segments which could impact high consequence areas by December 31, 2001, develop “Baseline Assessment Plans” for evaluating the integrity of each pipeline segment by March 31, 2002 and complete an assessment of the highest risk 50 percent of line segments by September 30, 2004, with full assessment of the remaining 50 percent by March 31, 2008. 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.

 

The Pipeline Safety Improvement Act of 2002, which was signed into law on December 17, 2002, includes numerous provisions that tighten federal inspection and safety requirements for natural gas and hazardous liquids pipeline facilities. Many of the statute’s provisions build on existing statutory requirements and strengthen

 

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existing regulations of the Research and Special Programs Administration (“RSPA”) and the Office of Pipeline Safety (“OPS”), in particular, with respect to operator qualifications programs, public education programs, national mapping system, and safe excavation practices/one-call programs. Management of the Partnership believes that compliance with the Pipeline Safety Improvement Act of 2002 will not have a material effect on its operation.

 

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 the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that certain information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local authorities and citizens. Management believes that the Partnership is in general compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to benzene.

 

The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the Federal Superfund Amendment and Reauthorization Act, and comparable state statutes require the organization of information about the hazardous materials used in the Partnership’s operations. Certain parts of this information must be reported to employees, state and local governmental authorities, and local citizens upon request.

 

Environmental Regulation

 

General

 

The operation of pipelines, terminals, and associated facilities in connection with the storage and transportation of refined products, crude oil, and other liquid hydrocarbons 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 the protection of the environment. These laws and regulations apply to all participants in the industry, including the Partnership and its equity interests. To the extent the following discussion summarizes these laws and regulations, it is applicable to all those participants. Otherwise, the following discussion is limited to the effects of the laws and regulations on the Partnership. As with the industry generally, compliance with existing and anticipated laws and regulations increases the overall cost of business, including the capital costs to construct, maintain, and upgrade equipment and facilities. While these laws and regulations affect maintenance capital expenditures and net income, management believes that they do not affect the Partnership’s competitive position in that the operations of competitors are similarly affected. Management believes that the Partnership’s operations are in substantial compliance with applicable environmental laws and regulations. However, these laws and regulations are subject to frequent change by regulatory authorities, and the Partnership is unable to predict the ongoing cost of complying with these laws and regulations or the future impact of these laws and regulations on operations. Violation of environmental laws, regulations, and permits can result in the imposition of significant administrative, civil and criminal penalties, injunctions, and construction bans or delays. A discharge of hydrocarbons or hazardous substances into the environment could, to the extent the event is not insured, subject the Partnership to substantial expense, including both the cost to comply with applicable laws and regulations and claims made by neighboring landowners and other third parties for personal injury and property damage.

 

Under the terms of the Omnibus Agreement with Sunoco, Inc., and in connection with the contribution of assets by affiliates of Sunoco, Inc., Sunoco, Inc. agreed to indemnify the Partnership for 30 years from environmental and toxic tort liabilities related to the assets transferred to the Partnership that arise from the operation of such assets prior to the closing of the IPO on February 8, 2002. Sunoco, Inc. is obligated to indemnify the Partnership for 100% of all such losses asserted within the first 21 years of closing. Sunoco, Inc.’s

 

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share of liability for claims asserted thereafter will decrease by 10% a year. For example, for a claim asserted during the twenty-third year after closing, Sunoco, Inc. would be required to indemnify the Partnership for 80% of the loss. There is no monetary cap on the amount of indemnity coverage provided by Sunoco, Inc. Any remediation 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 Partnership’s liability at multi-party sites, if any, in light of the number, participation levels, and financial viability of other parties. The Partnership has agreed 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 IPO and for environmental and toxic tort liabilities related to these assets to the extent Sunoco, Inc. is not required to indemnify the Partnership.

 

Air Emissions

 

The Partnership’s operations are subject to the Clean Air Act and comparable state and local statutes. Amendments to the Clean Air Act enacted in late 1990 as well as recent or soon to be adopted changes to state implementation plans for controlling air emissions in regional, non-attainment areas require or will require most industrial operations in the United States to incur capital expenditures in order to meet air emission control standards developed by the Environmental Protection Agency and state environmental agencies. As a result of these amendments, the Partnership’s facilities that emit volatile organic compounds or nitrogen oxides are subject to increasingly stringent regulations, including requirements that some sources install maximum or reasonably available control technology. In addition, the 1990 Clean Air Act Amendments established a new operating permit for major sources, which applies to some of the Partnership’s facilities. The Partnership will be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing air emission related issues. Although no assurances can be given, management believes implementation of the 1990 Clean Air Act Amendments will not have a material adverse effect on the Partnership’s financial condition or results of operations.

 

The Partnership’s customers, including Sunoco R&M, are also subject to, and affected by, environmental regulations. Since the late 1990s, the EPA has undertaken significant enforcement initiatives under authority of the Clean Air Act. These enforcement initiatives have been targeted at industries that have large manufacturing facilities and that are significant sources of emissions, such as the refining, paper and pulp, and electric power generating industries. The basic premise of the enforcement initiative is the EPA’s assertion that many of these industrial establishments have modified or expanded their operations over time without complying with New Source Review regulations that require permits and new emission controls in connection with any significant facility modifications or expansions that can result in emission increases above certain thresholds, and have violated various other provisions of the Clean Air Act, including New Source Review and Prevention of Significant Deterioration (“NSR/PSD”) Programs, Benzene Waste Organic National Emissions Standards for Hazardous Air Pollutants (“NESHAP”), Leak Detection and Repair (“LDAR”) and flaring requirements. As part of this enforcement initiative, the EPA has entered into consent agreements with several refiners that require them to pay civil fines and penalties and make significant capital expenditures to install emissions control equipment at selected facilities. For some of these refineries, the cost of the required emissions control equipment is significant, depending on the size, age and configuration of the refinery. Sunoco R&M received information requests in 2000, 2001 and 2002 in connection with the enforcement initiative pertaining to its four current refineries, the Puerto Rico refinery divested by Sunoco R&M in 2001 and its phenol facility in Philadelphia, PA. Sunoco R&M has completed its responses to the EPA, which focus solely on the refineries at this time.

 

Sunoco R&M has received Notices of Violation and Findings of Violation from the EPA relating to its Marcus Hook, Philadelphia and Toledo refineries. The Notices and Findings of Violation allege failure to comply with certain requirements relating to benzene waste-water emissions at its Marcus Hook, Toledo and Philadelphia refineries and failure to comply with certain requirements relating to leak detection and repair at the Toledo refinery. In addition, the EPA has alleged that: at Sunoco R&M’s Philadelphia refinery, certain

 

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modifications were made to one of the fluid catalytic cracking units in 1992 and 1998 without obtaining requisite permits; at Sunoco R&M’s Marcus Hook refinery, certain modifications were made to the fluid catalytic cracking unit in 1990 and 1996 without obtaining requisite permits; and at its Toledo refinery, certain physical and operational changes were made to the fluid catalytic cracking unit in 1985 without obtaining requisite permits. The EPA has also alleged that at Sunoco R&M’s Toledo refinery, certain physical and operational changes were made to the sulfur plant in 1995, 1998 and 1999 without obtaining requisite permits; certain physical and operational changes were made to a flare system without obtaining requisite permits; and that the flare system was not being operated in compliance with the Clean Air Act. Sunoco R&M has met with representatives of the EPA on these Notices and Findings of Violation and is currently evaluating its position. Although Sunoco R&M does not believe that it has violated any Clean Air Act requirements, as part of this initiative, Sunoco R&M could be required to make significant capital expenditures, operate these refineries at reduced levels and pay significant penalties.

 

During the 2001-2002 session, the U.S. Congress was considering energy policy legislation. Congress failed to approve the legislation during the session. The Senate and House both approved bills, which included provisions concerning ethanol and MTBE; however, a conference committee was unable to resolve differences between the two pieces of legislation. Provisions concerning MTBE, ethanol, and fuels standards were among the disputed issues. It is expected that these issues will be on the Congressional agendas in 2003. Sunoco R&M uses MTBE and ethanol as an oxygenate in different geographic areas of its refining and marketing system. While federal action to ban or phase down MTBE or to require increased usage of ethanol is uncertain, some states are scheduled to begin enforcing MTBE bans within the next year. Sunoco R&M is currently evaluating its options to produce MTBE-free gasoline when the additive is banned in states where it markets, including Connecticut (October 2003) and New York (January 2004). While Sunoco R&M does not market in California, that state’s ban on MTBE (January 2004) could have an impact on market conditions. Numerous other states are expected to consider legislation to ban MTBE during their 2003 legislative sessions. If MTBE is banned throughout the United States or on a state-by-state basis, the effect on Sunoco R&M and the industry in general could be significant. It will depend on the specific regulations, the impact on gasoline supplies, the cost and availability of alternative oxygenates if the minimum oxygenate requirements remain in effect, and the ability of Sunoco R&M and the industry in general to recover their costs in the marketplace.

 

During 2001, the EPA issued its final rule addressing emissions of toxic air pollutants from mobile sources (the Mobile Source Air Toxics (“MSAT”) Rule). The rule is currently being challenged by certain environmental organizations and a number of states, and by a member of the petroleum industry. It requires refiners to produce gasoline which maintains their average 1998-2000 gasoline toxic emission performance level. If the rule survives the challenges and if MTBE is banned, it could result in significant additional expenditures or significant reductions in reformulated gasoline production levels for Sunoco R&M as well as the industry.

 

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 the pipelines, cash flow, and ability to make distributions or satisfy its debt obligations.

 

Hazardous Substances and Waste

 

To a large extent, the environmental laws and regulations affecting the Partnership’s operations relate to the release of hazardous substances or solid wastes into soils, groundwater, and surface water, and include measures to control pollution of the environment. These laws generally regulate the generation, storage, treatment, transportation, and disposal of solid and hazardous waste. They also require corrective action, including the investigation and remediation, of certain units at a facility where such waste may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act, referred to as CERCLA and also known as Superfund, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release

 

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occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In the course of ordinary operations, the Partnership may generate waste that falls within CERCLA’s definition of a “hazardous substance” and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. Costs for any such remedial actions, as well as any related claims, could have a material adverse effect on maintenance capital expenditures and operating expenses to the extent not all are covered by an indemnity from Sunoco. For more information, please see “Environmental Remediation”.

 

The Partnership also generates solid wastes, including hazardous wastes, that are subject to the requirements of the federal Resource Conservation and Recovery Act, referred to as RCRA, and comparable state statutes. From time to time, the EPA considers the adoption of stricter disposal standards for non-hazardous wastes, including crude oil and gas wastes. The Partnership is not currently required to comply with a substantial portion of the RCRA requirements because the operations generate minimal quantities of hazardous wastes. However, it is possible that additional wastes, which could include wastes currently generated during operations, 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 maintenance capital expenditures and operating expenses.

 

The Partnership currently owns or leases, and the Partnership’s predecessor has in the past owned or leased, properties where hydrocarbons are being or have been handled for many years. Although operating and disposal practices have been utilized that were standard in the industry at the time, hydrocarbons or other waste may have been disposed of or released on or under the properties owned or leased by the Partnership or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under the Partnership’s control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under these laws, the Partnership could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater), or to perform remedial operations to prevent future contamination.

 

The Partnership has not been identified by any state or federal agency as a PRP 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 pollutants, including crude oil. The Oil Pollution Act was enacted in 1990 and amends provisions of the Water Pollution Control Act of 1972 and other statutes as they pertain to prevention and response to oil spills. The Oil Pollution Act subjects owners of covered facilities to strict, joint, and potentially unlimited liability for removal costs and other consequences of an oil spill, where the spill is into navigable waters, along shorelines or in the exclusive economic zone of the United States. In the event of an oil spill into navigable waters, substantial liabilities could be imposed upon the Partnership. States in which the Partnership operates have also enacted similar laws. Regulations are currently being developed under the Oil Pollution Act and state laws that may also impose additional regulatory burdens on the Partnership’s operations. Spill prevention control and countermeasure requirements of federal laws and some state laws require diking and similar structures to help prevent contamination of navigable waters in the event of an oil overflow, rupture, or leak. The Partnership is in substantial compliance with these laws. Additionally, the Office of Pipeline Safety of the DOT has approved the Partnership’s oil spill emergency response plans.

 

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The Water Pollution Control Act of 1972 imposes restrictions and strict controls regarding the discharge of pollutants into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters. The Water Pollution Control Act of 1972 imposes substantial potential liability for the costs of removal, remediation, and damages. In addition, some states maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Management believes that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on the Partnership’s financial condition or results of operations.

 

Endangered Species Act

 

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

 

Environmental Remediation

 

Contamination resulting from spills of refined products and crude oil is not unusual within the petroleum pipeline industry. Historic spills along the Partnership’s pipelines, gathering systems, and terminals as a result of past operations have resulted in contamination of 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 IPO and are asserted within 30 years after the closing of the IPO. This indemnity will cover the costs associated with performance of the assessment, monitoring, and remediation programs, as well as any related claims and penalties. See “Environmental Regulation—General.”

 

The Partnership has experienced several petroleum releases for which it is not covered by an indemnity from Sunoco, Inc., and is therefore the responsible party and needs to perform the necessary assessment, remediation, and/or monitoring activities. Remediation programs may be mandated at two sites, one in Texas and one in Pennsylvania. Management estimates that the total aggregate cost of performing the currently anticipated assessment, monitoring, and remediation activities at these two sites is not material to the Partnership at December 31, 2002.

 

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 Interstate Commerce Act requires that tariff rates for oil pipelines, a category that includes crude oil, petroleum products, and petrochemical pipelines (crude oil, petroleum product, and petrochemical pipelines are referred to collectively as “petroleum pipelines”), be just and reasonable and not unduly discriminatory. The Interstate Commerce Act permits challenges to proposed new or changed rates by protest, and challenges to rates that are already on file and in effect by complaint. Upon the appropriate showing, a successful complainant may obtain damages or reparations for generally up to two years prior to the filing of a complaint.

 

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The FERC is authorized to suspend the effectiveness of a new or changed tariff rate for a period of up to seven months and to investigate the rate. If upon the completion of an investigation the FERC finds that the rate is unlawful, it may require the pipeline operator to refund to shippers, with interest, any difference between the rates the FERC determines to be lawful and the rates under investigation. The FERC will order the pipeline to change its rates prospectively to the lawful level.

 

Index-Based Rates and Other Subsequent Developments.    In October 1992, Congress passed the Energy Policy Act of 1992. The Energy Policy Act deemed interstate petroleum pipeline rates in effect for the 365-day period ending on the date of enactment of the Energy Policy Act, or that were in effect on the 365th day preceding enactment and had not been subject to complaint, protest, or investigation during the 365-day period, to be just and reasonable under the Interstate Commerce Act. These rates are commonly referred to as “grandfathered rates.” All of the Partnership’s interstate pipeline rates were deemed just and reasonable and therefore are grandfathered under the Energy Policy Act. The Energy Policy Act provides that the FERC may change grandfathered rates upon complaints only under the following limited circumstances:

 

    a substantial change has occurred since enactment in either the economic circumstances or the nature of the services that were a basis for the rate;

 

    the complainant was contractually barred from challenging the rate prior to enactment of the Energy Policy Act and filed the complaint within 30 days of the expiration of the contractual bar; or

 

    a provision of the tariff is unduly discriminatory or preferential.

 

The Energy Policy Act further required the FERC to issue rules establishing a simplified and generally applicable ratemaking methodology for interstate petroleum pipelines and to streamline procedures in petroleum pipeline proceedings. On October 22, 1993, the FERC responded to the Energy Policy Act directive by issuing Order No. 561, which adopted a new indexed rate methodology for interstate petroleum pipelines. Under the resulting regulations, effective January 1, 1995, petroleum pipelines were able to change their rates within prescribed ceiling levels that were tied to changes in the Producer Price Index for Finished Goods, minus one percent (“PPI-1”). Rate increases made under the index are subject to protest, but the scope of the protest proceeding will be limited to an inquiry into whether the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs. The indexing methodology is applicable to any existing rate, whether grandfathered or whether established after enactment of the Energy Policy Act.

 

In December 2000, the FERC concluded that the PPI-1 index should be continued for another five-year period. However, the U.S. Court of Appeals for the District of Columbia found the decision to be flawed in certain respects and remanded the matter to the FERC for further consideration. On February 24, 2003, the FERC issued its Order on Remand. The Commission concluded that the appropriate index for the current five-year period should be the PPI without the minus one percent adjustment. It further ruled that pipelines may calculate the current ceiling rate using the PPI as though it had been the index in effect since July 1, 2001.

 

In Order No. 561, the FERC said that as a general rule pipelines must utilize the indexing methodology to change their rates. Indexing includes the requirement that, in any year in which the index is negative, pipelines must file to lower their rates if they would otherwise be above the reduced ceiling. However, the pipeline is not required to reduce its rates below the level deemed just and reasonable under the Energy Policy Act. The FERC further indicated in Order No. 561, however, that it is retaining cost-of-service ratemaking, market-based rates, and settlement rates as alternatives to the indexing approach. A pipeline can follow a cost-of-service approach when seeking to increase its rates above index levels (or when seeking to avoid lowering rates to index levels) provided that the pipeline can establish that there is a substantial divergence between the actual cost increases (or decreases) experienced by the pipeline and the rate resulting from application of the index. A pipeline can charge market-based rates if it establishes that it lacks significant market power in the affected markets. In addition, a pipeline can establish rates under settlement if agreed upon by all current shippers. As specified in Order 561 and subsequent decisions, a pipeline can seek to establish initial rates for new services through a cost-of-service showing, by establishing in advance that it lacks significant market power in the affected markets, or through an

 

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agreement between the pipeline and at least one shipper not affiliated with the pipeline who intends to use the new service.

 

Another development affecting petroleum pipeline ratemaking arose in Opinion No. 397, involving a partnership operating a crude oil pipeline. In Opinion No. 397, the FERC concluded that there should not be a corporate income tax allowance built into a petroleum pipeline’s rates for income attributable to noncorporate partners because those partners, unlike corporate partners, do not pay a corporate income tax on partnership distributions. Opinion No. 397 was affirmed by the FERC on rehearing in May 1996. The parties subsequently settled the case, so no judicial review of the tax ruling took place.

 

A current proceeding, however, is pending at the FERC that could result in changes to the FERC’s income tax method announced in Opinion No. 397 as well as to other elements of the FERC’s rate methods for petroleum pipelines. This proceeding involves another publicly traded limited partnership engaged in petroleum products pipeline transportation. In January, 1999, the FERC issued Opinion No. 435 in this proceeding, which, among other things, affirmed Opinion No. 397’s determination that there should not be a corporate income tax allowance built into a petroleum pipeline’s rates for income attributable to noncorporate partners. In subsequent decisions on rehearing, the FERC further defined the scope of the income tax allowance for publicly traded limited partnerships, and resolved a number of other cost of service issues as well.

 

Market-Based Rates.    In a proceeding involving Buckeye Pipeline Company, L.P., the FERC found that a petroleum pipeline able to demonstrate a lack of market power may be allowed a lighter standard of regulation than that imposed by the trended original cost methodology. In such a case, the pipeline company has the opportunity to establish that it faces sufficient competition to justify relief from the strict application of the cost-based principles. In Buckeye, the FERC determined, based on the existing level of market concentration in the pipeline’s market areas, that Buckeye exercised significant market power in only five of its 21 market areas and therefore was entitled to charge market-based rates in the other 16 market areas. The opportunity to charge market-based rates means that the pipeline may charge what the market will bear. Order No. 572, a companion order to Order No. 561, was issued by the FERC on October 25, 1994 and established procedural rules governing petroleum pipelines’ applications for a finding that the pipeline lacks significant market power in the relevant market.

 

Settlement Rates.    In Order No. 561, the FERC specifically held that it would also permit changes in rates that are the product of unanimous agreement between the pipeline and all the shippers using the service to which the rate applies. The rationale behind allowing this type of rate change is to further the FERC’s policy of favoring settlements among parties and to lessen the regulatory burdens on all concerned. The FERC, however, will also entertain a challenge to settlement rates, in response to a protest or a complaint that alleges the same circumstances required to challenge an indexed rate. An example of this type of challenge is that there is a discrepancy between the rate and the pipeline’s cost of service that is so substantial as to render the settlement (or indexed) rate unjust and unreasonable.

 

Intrastate Regulation.     Some of the Partnership’s pipeline operations are subject to regulation by the Texas Railroad Commission, the PA PUC, the Ohio Public Utility Commission, and the Oklahoma Corporation Commission. The applicable state statutes require that pipeline rates be nondiscriminatory and provide no more than a fair return on the aggregate value of the pipeline property used to render services. State commissions have generally not been aggressive in regulating common carrier pipelines and have generally not investigated the 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 would ultimately be upheld if challenged, management 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.

 

The Partnership’s Pipelines.    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. In

 

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addition, as discussed above, intrastate pipelines generally are subject to “light-handed” regulation by state commissions and management of the Partnership does not believe the intrastate tariffs now in effect are likely to be challenged. However, the FERC or a state regulatory commission could investigate the Partnership’s rates at the urging of a third party if the third party is either a current shipper or is able to show that it has a substantial economic interest in the tariff rate level. If an intrastate rate were challenged, the Partnership would defend it on a cost of service basis. If an interstate rate were challenged, that rate would be defended as grandfathered under the Energy Policy Act. As that Act applies to the Partnership’s rates, 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 and to which management believes there are valid defenses. If the FERC were to find a substantial change in circumstances, then the existing rates could be subject to detailed review. Management believes that most such rates can be supported on a cost of service basis, even recognizing the reduction in the income tax allowance that is likely to result from the conversion from a corporation to a partnership. Although there are some rates that might not be defensible on that basis, management believes that all of those rates involve movements as to which (1) Sunoco R&M is the only shipper, (2) the Partnership has a reasonable basis to assert the lack of significant market power and therefore are entitled to market based rates, or (3) the revenue amounts involved do not materially affect the Partnership’s performance.

 

If the FERC investigated the Partnership’s rate levels, it could inquire into the costs, including:

 

    the overall cost of service, including operating costs and overhead;

 

    the allocation of overhead and other administrative and general expenses to the rate;

 

    the appropriate capital structure to be utilized in calculating rates;

 

    the appropriate rate of return on equity;

 

    the rate base, including the proper starting rate base;

 

    the throughput underlying the rate; and

 

    the proper allowance for federal and state income taxes.

 

Management of the Partnership does not believe that it is likely that there will be a rate challenge by a current shipper that would materially affect revenues or cash flows. Sunoco R&M and its subsidiaries are the only current shippers in many of the pipelines. Sunoco R&M has agreed not to challenge, or to cause others to challenge or assist others in challenging, the tariff rates for the term of the pipelines and terminals storage and throughput agreement.

 

Because most of the pipelines are common carrier pipelines, the Partnership may be required to accept new shippers who wish to transport in 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, the cash available for distribution could be materially reduced.

 

Title to Properties

 

Substantially all of the 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

 

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cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election. In some cases, property for pipeline purposes was purchased in fee. In some states and under some circumstances, the Partnership has the right of eminent domain to acquire rights-of-way and lands necessary for the common carrier pipelines. The previous owners of the applicable pipelines may not have commenced or concluded eminent domain proceedings for some rights-of-way.

 

Some of the leases, easements, rights-of-way, permits, and licenses transferred to the Partnership upon the completion of the IPO in February 2002 required the consent of the grantor to transfer these rights, which in some instances is a governmental entity. The Partnership has obtained or is in the process of obtaining third-party consents, permits, and authorizations sufficient for the transfer of the assets necessary to operate the business in all material respects. With respect to any consents, permits, or authorizations that have not been obtained, the failure to obtain these consents, permits, or authorizations will have no material adverse effect on the operation of the business.

 

The Partnership has satisfactory title to all of the assets, or is entitled to indemnification from Sunoco, Inc. under the Omnibus Agreement for title defects to the assets contributed to the Partnership and for failures to obtain certain consents and permits necessary to conduct the business that arise within ten years after the closing of the 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 IPO. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with acquisition of real property, liens that can be imposed in some jurisdictions for government-initiated action to clean up environmental contamination, liens for current taxes and other burdens, and easements, restrictions, and other encumbrances to which the underlying properties were subject at the time of acquisition by the predecessor or the Partnership, none of these burdens should materially detract from the value of these properties or from the Partnership’s interest in these properties or should materially interfere with their use in the operation of the business.

 

Employees

 

To carry out the Partnership’s operations, the general partner and its affiliates employ approximately 1,200 people who provide direct support to the operations. Labor unions or associations represent approximately 680 of these employees. The general partner considers its employee relations to be good. The Partnership has no employees.

 

(d) Financial Information about Geographical Areas

 

The Partnership has no significant amounts of revenue or segment profit or loss attributable to international activities. As a result, management does not consider those proceedings material to the Partnership.

 

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 2.    PROPERTIES

 

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

 

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ITEM 3.    LEGAL PROCEEDINGS

 

With respect to a pipeline release of crude oil in February 2000 in the John Heinz National Wildlife Refuge in Philadelphia, the Partnership has conducted remedial activities at the release area and has initiated restoration efforts in the area. Management of the Partnership expects the Environmental Protection Agency (“EPA”) to assess a penalty with respect to this release that could exceed $100,000. Sunoco has agreed to indemnify the Partnership, among other things, for any penalty that may be assessed. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Agreements with Sunoco R&M and Sunoco, Inc.”

 

There are certain legal and administrative proceedings 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 any losses it may suffer as a result of these pending legal actions.

 

There are certain other pending legal proceedings related to matters arising after the IPO that are not indemnified by Sunoco. Management believes that any liabilities that may arise from these legal proceedings will not be material to the Partnership.

 

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

 

No matters were submitted to a vote of the security holders, through solicitation of proxies or otherwise, during fiscal 2002.

 

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PART II

 

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

 

The Partnership’s common units were listed on the New York Stock Exchange under the symbol “SXL” beginning on February 5, 2002. Prior to February 5, 2002, the Partnership’s equity securities were not traded on any public trading market. At the close of business on February 28, 2002, there were 52 holders of record of the Partnership’s common units. These holders of record included the general partner with 5,638,154 common units registered in its name, and Cede & Co. with 5,695,632 common units (representing approximately 5,700 beneficial owners) registered to it.

 

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

 

    

2002


Quarter


  

Unit Price High


  

Unit Price Low


    

Declared Distributions(1)


1st 

  

$

23.44

  

$

20.49

    

$

0.26    

2nd

  

$

24.00

  

$

20.95

    

$

0.45    

3rd

  

$

23.25

  

$

18.85

    

$

0.45    

4th

  

$

24.07

  

$

21.10

    

$

0.4875


(1)   Distributions were declared and paid within 45 days following the close of each quarter. The distribution for the first quarter of 2002 was pro-rated for the period from February 8, 2002 through March 31, 2002.

 

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

 

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

 

The Partnership will make minimum quarterly distributions of $0.45 per common unit, to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner.

 

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

 

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

 

    Thereafter, in the manner described in the table below.

 

The subordination period is generally defined as the period that ends on the first day of any quarter beginning after December 31, 2006 if (1) the Partnership has distributed at least the minimum quarterly distribution on all outstanding units with respect to each of the immediately preceding three consecutive, non-overlapping four quarter periods; and (2) the adjusted operating surplus, as defined in the partnership agreement, during such periods equals or exceeds the amount that would have been sufficient to enable the Partnership to distribute the minimum quarterly distribution on all outstanding units on a fully diluted basis and the related distribution on the 2% general partner interest during those periods. In addition, one-quarter of the

 

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subordinated units may convert to common units on a one-for-one basis after December 31, 2004, and one-quarter of the subordinated units may convert to common units on a one-for-one basis after December 31, 2005, if the Partnership meets the tests set forth in the partnership agreement. If the subordination period ends, the rights of the holders of subordinated units will no longer be subordinated to the rights of the holders of common units and the subordinated units may be converted into common units.

 

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

 

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

 

    Thereafter, as described in the paragraph and table below.

 

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

 

Quarterly Distribution Amount per Unit


    

Percentage of Distribution


    

Unitholders


    

General Partner


Up to Minimum Quarterly Distribution ($0.450)

    

98%

    

2%

Up to $0.500

    

98%

    

2%

Above $0.500 up to $0.575

    

85%

    

15%

Above $0.575 up to $0.700

    

75%

    

25%

Above $0.700

    

50%

    

50%

 

There is no guarantee that the Partnership will pay the minimum quarterly distribution on the common units in any quarter, and the Partnership will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default is existing, under the credit facility or the senior notes (Please see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources”).

 

Use of Proceeds

 

On February 4, 2002, the Partnership’s Registration Statement on Form S-1 (Registration No. 333-71968), filed with the Securities and Exchange Commission, became effective. Pursuant to the Registration Statement, on February 4, 2002, 5,000,000 common units were sold to the public at a price of $20.25 per unit for aggregate gross proceeds of $101.3 million. Subsequent to the IPO, the underwriters exercised their over-allotment option for 750,000 additional common units at a price of $20.25 per unit for aggregate gross proceeds of $15.1 million. Underwriting fees paid in connection with these transactions were $6.7 million and $1.0 million, respectively. On February 8, 2002, the closing date of the IPO, the Partnership received net proceeds of $108.7 million (including proceeds of the over-allotment option). The aggregate offering price of 5,750,000 common units was $116.4 million, and the aggregate underwriting fees were $7.7 million. Approximately $12.2 million of the net proceeds were used to pay expenses associated with the IPO and related formation transactions, which consisted primarily of legal, accounting and other professional services costs. The remaining $96.5 million of net proceeds was used to increase working capital to the level necessary for the operation of the business, thereby establishing working capital that was not contributed to the Partnership by Sunoco, Inc. in connection with the Partnership’s formation. The underwriters of the IPO were Lehman Brothers, Salomon Smith Barney, UBS Warburg, Banc of America Securities, Wachovia Securities and Credit Suisse First Boston.

 

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In addition, concurrent with the closing of the IPO, Sunoco Logistics Partners Operations L.P. (the “Operating Partnership”), a wholly-owned operating subsidiary, issued $250.0 million of 7.25% Senior Notes due 2012 (the “Senior Notes”) in an offering exempt from registration under the Securities Act of 1933. The Senior Notes were issued at a price of 99.325% of their principal amount. Gross proceeds from this offering were $248.3 million and aggregate underwriting discounts and commissions were $1.6 million. Net proceeds were $246.7 million. Expenses incurred in connection with the issuance of the Senior Notes were approximately $1.9 million, which consisted primarily of legal, accounting and other professional services costs. The initial purchasers of the Notes were Lehman Brothers, Credit Suisse First Boston, Salomon Smith Barney, UBS Warburg, Banc of America Securities and Wachovia Securities.

 

The $244.8 million of net proceeds from the sale of the Senior Notes were distributed to Sunoco, Inc. and its affiliates.

 

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

 

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 for Sunoco Logistics Partners L.P. for 1998, 1999, 2000 and 2001 are derived from the audited financial statements of Sunoco Logistics Partners L.P., which reflect the historical cost basis amounts of Sunoco Logistics (Predecessor), the predecessor. The selected financial and operating data for Sunoco Logistics Partners L.P. for 2002 are derived from the audited financial statements for Sunoco Logistics Partners L.P. and Sunoco Logistics (Predecessor).

 

The Partnership defines EBITDA as operating income plus depreciation and amortization. EBITDA provides additional information for evaluating the Partnership’s ability to service debt obligations and make the minimum quarterly distribution and is presented solely as a supplemental measure. You should not consider EBITDA as an alternative to net income, income before income taxes, cash flows from operations, or any other measure of financial performance presented in accordance with accounting principles generally accepted in the United States. The Partnership’s EBITDA may not be comparable to EBITDA or similarly titled measures of other entities as other entities may not calculate EBITDA in the same manner.

 

For the periods presented, Sunoco R&M was the primary or exclusive user of the refined product terminals, the Fort Mifflin Terminal Complex, and the Marcus Hook Tank Farm. Prior to January 1, 2002, most of the terminalling and throughput services provided by Sunoco Logistics (Predecessor) for Sunoco R&M’s refining and marketing operations were at fees that enabled the recovery of costs, but not to generate any operating income. Accordingly, historical EBITDA for those assets was equal to their depreciation and amortization. Sunoco Logistics Partners L.P. began charging Sunoco R&M fees for these services comparable to those charged in arm’s length, third-party transactions, generally effective January 1, 2002, using the terms included in a pipelines and terminals storage and throughput agreement entered into at the closing of the 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. The maintenance capital expenditures for the periods presented include several one-time projects to upgrade technology, increase reliability, and lower the Partnership’s cost structure.

 

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Throughput is the total number of barrels per day transported on a pipeline system or through a terminal and includes barrels ultimately transported to a delivery point on another pipeline system.

 

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

 

SUNOCO LOGISTICS PARTNERS L.P.

 

    

Sunoco Logistics (Predecessor)


    

Sunoco Logistics Partners L.P. and

Predecessor


 
    

Year Ended December 31,


 
    

1998


    

1999(1)


    

2000


    

2001


    

2002(2)


 
    

(in thousands, except per unit and operating data)

 

Income Statement Data:

                                            

Revenues:

                                            

Sales and other operating revenue:

                                            

Affiliates

  

$

570,332

 

  

$

764,133

 

  

$

1,301,079

 

  

$

1,067,182

 

  

$

1,147,721

 

Unaffiliated customers

  

 

124,869

 

  

 

210,069

 

  

 

507,532

 

  

 

545,822

 

  

 

676,307

 

Other income(3)

  

 

5,022

 

  

 

6,133

 

  

 

5,574

 

  

 

4,774

 

  

 

6,904

 

    


  


  


  


  


Total revenues

  

 

700,223

 

  

 

980,335

 

  

 

1,814,185

 

  

 

1,617,778

 

  

 

1,830,932

 

    


  


  


  


  


Costs and expenses:

                                            

Cost of products sold and operating expenses

  

 

583,587

 

  

 

866,610

 

  

 

1,699,541

 

  

 

1,503,156

 

  

 

1,690,896

 

Depreciation and amortization

  

 

18,622

 

  

 

19,911

 

  

 

20,654

 

  

 

25,325

 

  

 

31,334

 

Selling, general and administrative expenses

  

 

29,890

 

  

 

27,461

 

  

 

34,683

 

  

 

35,956

 

  

 

43,073

 

    


  


  


  


  


Total costs and expenses

  

 

632,099

 

  

 

913,982

 

  

 

1,754,878

 

  

 

1,564,437

 

  

 

1,765,303

 

    


  


  


  


  


Operating income

  

 

68,124

 

  

 

66,353

 

  

 

59,307

 

  

 

53,341

 

  

 

65,629

 

Net interest cost and debt expense

  

 

7,117

 

  

 

6,487

 

  

 

10,304

 

  

 

10,980

 

  

 

17,299

 

    


  


  


  


  


Income before income tax expense

  

 

61,007

 

  

 

59,866

 

  

 

49,003

 

  

 

42,361

 

  

 

48,330

 

Income tax expense

  

 

23,116

 

  

 

22,488

 

  

 

18,483

 

  

 

15,594

 

  

 

1,555

 

    


  


  


  


  


Net Income

  

$

37,891

 

  

$

37,378

 

  

$

30,520

 

  

$

26,767

 

  

$

46,775

 

    


  


  


  


  


Net Income per unit:

                                            

Basic

                                      

$

1.87

(4)

                                        


Diluted

                                      

$

1.86

(4)

                                        


Cash distributions per unit(5)

                                      

$

1.16

 

                                        


Cash Flow Data:

                                            

Net cash provided by operating activities

  

$

44,950

 

  

$

125,165

 

  

$

79,116

 

  

$

27,238

 

  

$

2,211

 

Net cash used in investing activities

  

$

(36,933

)

  

$

(75,120

)

  

$

(77,292

)

  

$

(73,079

)

  

$

(85,273

)

Net cash provided by/(used in) financing activities

  

$

(8,017

)

  

$

(50,045

)

  

$

(1,824

)

  

$

45,841

 

  

$

116,902

 

Capital expenditures:

                                            

Maintenance

  

$

28,420

 

  

$

32,312

 

  

$

39,067

 

  

$

53,628

 

  

$

27,934

 

Expansion

  

 

8,527

 

  

 

49,556

(1)

  

 

18,854

 

  

 

19,055

 

  

 

77,439

(2)

    


  


  


  


  


Total capital expenditures

  

$

36,947

 

  

$

81,868

(1)

  

$

57,921

 

  

$

72,683

 

  

$

105,373

(2)

    


  


  


  


  


EBITDA(6)

  

$

86,746

 

  

$

86,264

 

  

$

79,961

 

  

$

78,666

 

  

$

96,963

 

Balance Sheet Data (at period end):

                                            

Net properties, plants and equipment

  

$

430,848

 

  

$

481,967

 

  

$

518,605

 

  

$

566,359

 

  

$

573,514

 

Total assets

  

$

528,279

 

  

$

712,149

 

  

$

845,956

 

  

$

789,201

 

  

$

1,093,880

 

Total debt(7)

  

$

90,225

 

  

$

95,287

 

  

$

190,043

 

  

$

144,781

 

  

$

317,445

 

Total Partners’ Capital/Net parent investment

  

$

235,478

 

  

$

223,083

 

  

$

157,023

 

  

$

274,893

 

  

$

382,350

 

Operating Data (bpd):

                                            

Eastern Pipeline System throughput(8)

  

 

520,627

 

  

 

542,843

 

  

 

535,510

 

  

 

544,874

 

  

 

584,546

 

Terminal Facilities throughput

  

 

1,163,907

 

  

 

1,245,189

 

  

 

1,281,231

 

  

 

1,156,927

 

  

 

1,150,760

 

Western Pipeline System throughput(9)

  

 

253,124

 

  

 

252,098

 

  

 

295,991

 

  

 

287,237

 

  

 

286,912

 

Crude oil purchases at wellhead

  

 

152,503

 

  

 

140,779

 

  

 

172,839

 

  

 

174,182

 

  

 

189,277

 

 

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(1)   On October 1, 1999, the Partnership acquired the crude oil transportation and marketing operations of Pride Companies, L.P. (“Pride”) for $29.6 million in cash and the assumption of $5.3 million of debt. The purchase price of this acquisition has been included in expansion capital expenditures.
(2)   On November 15, 2002, the Partnership acquired a company whose assets included equity interests in three products pipeline companies, consisting of a 31.5% interest in Wolverine Pipe Line Company, a 9.2% interest in West Shore Pipe Line Company, and a 14.0% interest in Yellowstone Pipe Line Company for $54.0 million. On November 15, 2002, the Partnership also acquired a 43.8% equity interest in West Texas Gulf Pipe Line Company for $10.6 million. The aggregate purchase price for these acquisitions have been included within the 2002 expansion capital expenditures. The equity income from these acquisitions has been included in the Partnership’s statements of income from the dates of their acquisition.
(3)   Includes equity income from the investments in the following joint ventures: 9.4% in Explorer Pipeline Company and, for the period beginning November 15, 2002, 31.5% in Wolverine Pipe Line Company, 9.2% in West Shore Pipe Line Company, 14.0% in Yellowstone Pipe Line Company, and 43.8% in West Texas Gulf Pipe Line Company.
(4)   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 2% interest. Net income for the period from January 1, 2002 to February 7, 2002 totalled $3.4 million.
(5)   The cash distributions for the year ended December 31, 2002 include the pro-rata portion of the $0.45 per unit minimum quarterly distribution to unitholders for the 52-day period from the date of the IPO, February 8, 2002, through March 31, 2002.
(6)   EBITDA is defined in the Partnership’s three-year $150 million revolving credit facility (“Credit Facility”) as net income before interest expense, income taxes, depreciation and amortization. The following table reconciles the difference between net income, as determined under United States generally accepted accounting principles, and EBITDA (in thousands):

 

    

Year Ended December 31,


    

1998


  

1999


  

2000


  

2001


  

2002


Net income

  

$

37,891

  

$

37,378

  

$

30,520

  

$

26,767

  

$

46,775

Interest expense, net

  

 

7,117

  

 

6,487

  

 

10,304

  

 

10,980

  

 

17,299

Provision for income taxes

  

 

23,116

  

 

22,488

  

 

18,483

  

 

15,594

  

 

1,555

Depreciation and amortization

  

 

18,622

  

 

19,911

  

 

20,654

  

 

25,325

  

 

31,334

    

  

  

  

  

EBITDA

  

$

86,746

  

$

86,264

  

$

79,961

  

$

78,666

  

$

96,963

    

  

  

  

  

 

  Management   of the Partnership believes EBITDA information enhances an investor’s understanding of a business’s ability to satisfy principal and interest obligations with respect to its indebtedness and to utilize cash for other purposes including the payment of distributions. In addition, EBITDA is used as a measure in the Credit Facility in determining the Partnership’s compliance with certain covenants. However, there may be contractual, legal, economic or other reasons which may prevent the Partnership from satisfying principal and interest obligations with respect to indebtedness and may require the Partnership to allocate funds for other purposes. EBITDA does not represent and should not be considered as an alternative to net income, income from operations or cash flows from operating activities as determined under United States generally accepted accounting principles and may not be comparable to other similarly titled measures of other businesses.
(7)   The year ended December 31, 2002 includes the net amount outstanding of the $250.0 million, ten-year 7.25% Senior Notes at 99.325% of the principal amount, $64.5 million outstanding on the Credit Facility, both established in conjunction with the IPO, and other debt. All amounts prior to the IPO included debt due an affiliate or other debt.
(8)   Excludes amounts attributable to the 9.4% ownership interest in Explorer Pipeline Company, the 31.5% interest in Wolverine Pipe Line Company, the 9.2% interest in West Shore Pipe Line Company, the 14.0% interest in Yellowstone Pipe Line Company, and the interrefinery pipelines. Also excludes amounts attributable to the Toledo, Twin Oaks, and Linden transfer pipelines, which transport large volumes over short distances and generate minimal revenues.
(9)   Excludes amounts attributable to the 43.8% interest in West Texas Gulf Pipe Line Company.

 

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

 

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

 

Introduction

 

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

 

General

 

The Partnership conducts its business through three segments: the Eastern Pipeline System, the Terminal Facilities, and the Western Pipeline System. The Eastern Pipeline System primarily transports refined products in the Northeast and Midwest United States largely for three of Sunoco R&M’s refineries and transports crude oil in Ohio and Michigan. This system also includes the interrefinery pipeline between Sunoco R&M’s Marcus Hook and Philadelphia refineries and ownership interests in four refined product pipeline joint ventures located in the West and Midwest United States: 9.4% in Explorer Pipeline Company (“Explorer”), 31.5% in Wolverine Pipe Line Company (“Wolverine”), 9.2% in West Shore Pipe Line Company (“West Shore”), and 14.0% in Yellowstone Pipe Line Company (“Yellowstone”). The interests in Wolverine, West Shore, and Yellowstone were acquired on November 15, 2002 for a purchase price of $54.0 million. The Terminal Facilities business includes a network of 32 refined product terminals in the Northeast and Midwest United States that distribute products primarily to Sunoco R&M’s retail outlets, the Nederland marine crude oil terminal on the Texas Gulf Coast, and a liquefied petroleum gas (“LPG”) storage facility in the Midwest. The Terminal Facilities business also owns and operates refinery related assets, including one inland and two marine crude oil terminals and related pipelines that supply all of the crude oil processed by Sunoco R&M’s Philadelphia refinery and a refined product storage terminal used by Sunoco R&M’s Marcus Hook refinery. The Western Pipeline System owns and operates crude oil trunk and gathering pipelines and purchases and markets crude oil primarily in Oklahoma and Texas for Sunoco R&M’s Tulsa, Oklahoma and Toledo, Ohio refineries and for other customers. The Western Pipeline System also has a 43.8% equity ownership interest in West Texas Gulf Pipe Line Company (“West Texas Gulf”), a joint venture that owns a crude oil pipeline in Texas. The interest in West Texas Gulf was acquired on November 15, 2002 for $10.6 million.

 

Eastern Pipeline System

 

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

 

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The tariffs for the Partnership’s interstate common carrier pipelines are regulated by the Federal Energy Regulatory Commission (“FERC”). The rate making methodology for these pipelines is price indexing. This methodology provides for increases in tariff rates based upon changes in the producer price index. Competition, however, may constrain the tariffs charged. The Partnership also leases to Sunoco R&M, for a fixed amount escalating annually at 1.67%, three pipelines between Sunoco R&M’s Marcus Hook and Philadelphia refineries, as well as a pipeline from the Paulsboro terminal to the Philadelphia International Airport for the delivery of jet fuel.

 

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

 

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

 

Terminal Facilities

 

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

 

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

 

Western Pipeline System

 

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

 

The factors affecting the operating results of the crude oil pipelines and gathering systems are substantially similar to the factors affecting the operating results of the pipelines in the Eastern Pipeline System described

 

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above. 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 crude oil acquisition and marketing operations generate substantial revenue and cost of products sold because they reflect the sales price and cost of the significant volume of crude oil bought and sold. However, the absolute price levels for crude oil normally do not bear a relationship to gross margin, although these price levels significantly impact revenue and cost of products sold. As a result, period-to-period variations in revenue and cost of products sold are not generally meaningful in analyzing the variation in gross margin for the crude oil acquisition and marketing operations.

 

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

 

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

 

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

 

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Agreements with Sunoco R&M and Sunoco, Inc.

 

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

 

Pipelines and Terminals Storage and Throughput Agreement

 

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

 

    transport on the refined product pipelines or throughput in the 32 inland refined product terminals an amount of refined products that will produce at least $75.0 million of revenue in the first year, escalating at 1.67% each January 1 for the next four years. In addition, Sunoco R&M will pay the Partnership to transport on the refined product pipelines an amount of refined products that will produce at least $54.3 million of revenue in the sixth year and at least $55.2 million of revenue in the seventh year. These revenues are annual amounts for the contract period from March 1 to February 28 of each year under the agreement. 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, 2002 and management of the Partnership expects Sunoco R&M to exceed the minimum amount under the agreement for the contract year from March 1, 2002 through February 28, 2003;

 

    receive and deliver at least 130,000 bpd of refined products per year at the Marcus Hook Tank Farm for five years. This throughput is an annual amount for the contract period from March 1 to February 28 of each year under the agreement. For the contract year ended February 28, 2003, the Partnership received a fee of $0.1627 per barrel for the first 130,000 bpd and $0.0813 per barrel for volume in excess of 130,000 bpd. These fees escalate at the rate of 1.67% 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, 2002 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, 2002 through February 28, 2003;

 

    store 975,734 barrels of LPG per 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 of each year under the agreement. In the first year of this seven-year agreement, the Partnership received a fee of $2.04 per barrel of committed storage, a fee of $0.204 per barrel for receipts greater than 975,734 barrels per year and a fee of $0.204 per barrel for deliveries greater than 975,734 barrels per year. These fees will escalate at the rate of 1.875% 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, 2002 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, 2002 through March 31, 2003;

 

    receive and deliver at least 290,000 bpd of crude oil or refined products per year at the Fort Mifflin Terminal Complex for seven years. This throughput is an annual amount for the contract period from March 1 to February 28 of each year under the agreement. In the first year, the Partnership received a fee of $0.1627 per barrel for the first 180,000 bpd and $0.0813 per barrel for volume in excess of 180,000 bpd. These fees will escalate at the rate of 1.67% 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, 2002 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, 2002 through February 28, 2003; and

 

   

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

 

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throughput amount through December 31, 2002 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, 2002 through February 28, 2003.

 

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 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.

 

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

 

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

 

Omnibus Agreement

 

Historically, Sunoco, Inc. has allocated a portion of its general and administrative expenses to its pipeline, terminalling, and storage operations to cover costs of centralized corporate functions such as legal, accounting, treasury, engineering, information technology, and insurance. Prior to the IPO, such expenses were based on amounts negotiated between the parties, which approximated Sunoco, Inc.’s cost of providing such services.

 

Under the Omnibus Agreement entered into with Sunoco, Inc. concurrent with the IPO, the Partnership is paying Sunoco, Inc. or the general partner an annual administrative fee, initially in the amount of $8.0 million, for the provision by Sunoco, Inc. or its affiliates of various general and administrative services for the Partnership’s benefit for three years following the IPO. This fee 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 does not include the costs of shared insurance programs, which are allocated to the Partnership based upon its share of the premiums incurred. This fee also does not include salaries of pipeline and terminal personnel or other employees of the general partner, including senior executives, or the cost of their employee benefits. The Partnership has no employees. Selling, general and administrative expenses in the

 

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statements of income include expenses related to the provision of these services and allocation of shared insurance costs of $10.1 million, $10.8 million and $10.2 million for the years ended December 31, 2000, 2001 and 2002, respectively. The Partnership will also reimburse Sunoco, Inc. and its affiliates for direct expenses they incur on the Partnership’s behalf, including salaries and benefits of employees of the general partner and its subsidiaries. The Partnership’s and Predecessor’s share of allocated Sunoco employee benefit plan expenses, including non-contributory defined benefit retirement plans, defined contribution 401(k) plans, employee and retiree medical, dental and life insurance plans, incentive compensation plans and other such benefits, was $18.7 million, $19.6 million and $19.6 million for the years ended December 31, 2000, 2001 and 2002, respectively. The Partnership began incurring additional general and administrative costs from the date of the IPO, including costs for tax return preparation, annual and quarterly reports to unitholders, investor relations, registrar and transfer agent fees, and other costs related to operating as a separate publicly held entity.

 

The Omnibus Agreement also requires Sunoco R&M to: reimburse the Partnership for any operating expenses and capital expenditures in excess of $8.0 million per year in each year from 2002 to 2006 that are made to comply with the DOT’s pipeline integrity management rule, commencing on the close of the IPO, subject to a maximum aggregate reimbursement of $15.0 million over the five-year period; complete, at its expense, certain tank maintenance and inspection projects currently in progress or expected to be completed at the Darby Creek Tank Farm within one year; 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 year ended December 31, 2002, the Partnership received $0.7 million from 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. For the year ended December 31, 2002, the Partnership also received $2.1 million from Sunoco R&M for maintenance capital expenditures for certain tank maintenance and inspection projects completed at the Darby Creek Tank Farm. For the year ended December 31, 2002, the Partnership also received $0.9 million from Sunoco R&M, consisting of $0.5 million for maintenance capital expenditures and $0.4 million for operating expenses, for expenditures at the Marcus Hook Tank Farm and the Darby Creek Tank Farm to maintain compliance with existing industry standards and regulatory requirements. The aggregate amounts received of $3.7 million from Sunoco R&M related to these projects were recorded by the Partnership as capital contributions.

 

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

 

Interrefinery Lease Agreement

 

Under a 20-year lease agreement, Sunoco R&M will pay the Partnership $5.1 million in the first contract year from February 8, 2002 to February 7, 2003 to lease the 58 miles of interrefinery pipelines between Sunoco R&M’s Philadelphia and Marcus Hook refineries, escalating at 1.67% each January 1 for the next 19 years. For the period from February 8, 2002, the date of the IPO, to December 31, 2002, the Partnership recorded the pro-rata portion of $4.6 million of this annual fee under this agreement.

 

Crude Oil Purchase Agreement

 

Sunoco R&M will purchase from the Partnership, at market-based rates, particular grades of crude oil that the crude oil acquisition and marketing business purchases for delivery to pipelines in: Longview, Trent, Tye, and Colorado City, Texas; Haynesville, Louisiana; Marysville and Lewiston, Michigan; and Tulsa, Oklahoma. At Marysville and Lewiston, Michigan, Michigan sweet and Michigan sour crude oil is exchanged for domestic sweet crude oil supplied by Sunoco R&M at market-based rates. These agreements, which will have an initial

 

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term of two months, will automatically renew on a monthly basis unless terminated by either party on 30 days’ written notice. For the year ended December 31, 2002, Sunoco R&M has purchased all the barrels noted above and has indicated that it has no current intention to terminate these agreements.

 

License Agreement

 

The Partnership has granted to Sunoco, Inc. and certain of its affiliates, including the general partner, a license to its intellectual property so that the general partner can manage its operations and create intellectual property using the 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, Inc. in the conduct of its business.

 

Treasury Services Agreement

 

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

 

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Results of Operations

 

    

Predecessor


    

Partnership
and
Predecessor


 
    

Year Ended December 31,


 
    

2000


  

2001


    

2002


 
    

(in thousands)

 

Statements of Income

                        

Sales and other operating revenue:

                        

Affiliates

  

$

1,301,079

  

$

1,067,182

 

  

$

1,147,721

 

Unaffiliated customers

  

 

507,532

  

 

545,822

 

  

 

676,307

 

Other income

  

 

5,574

  

 

4,774

 

  

 

6,904

 

    

  


  


Total revenues

  

 

1,814,185

  

 

1,617,778

 

  

 

1,830,932

 

    

  


  


Cost of products sold and operating expenses

  

 

1,699,541

  

 

1,503,156

 

  

 

1,690,896

 

Depreciation and amortization

  

 

20,654

  

 

25,325

 

  

 

31,334

 

Selling, general and administrative expenses

  

 

34,683

  

 

35,956

 

  

 

43,073

 

    

  


  


Total costs and expenses

  

 

1,754,878

  

 

1,564,437

 

  

 

1,765,303

 

    

  


  


Operating income

  

 

59,307

  

 

53,341

 

  

 

65,629

 

Net interest expense

  

 

10,304

  

 

10,980

 

  

 

17,299

 

    

  


  


Income before income tax expense

  

 

49,003

  

 

42,361

 

  

 

48,330

 

Income tax expense

  

 

18,483

  

 

15,594

 

  

 

1,555

 

    

  


  


Net income

  

$

30,520

  

$

26,767

 

  

$

46,775

 

    

  


  


Segment Operating Income:

                        

Eastern Pipeline System

                        

Sales and other operating revenue:

                        

Affiliate

  

$

69,027

  

$

69,631

 

  

$

72,173

 

Unaffiliated customers

  

 

19,323

  

 

21,059

 

  

 

22,865

 

Other income

  

 

4,592

  

 

4,749

 

  

 

6,925

 

    

  


  


Total revenues

  

 

92,942

  

 

95,439

 

  

 

101,963

 

    

  


  


Operating expenses

  

 

41,174

  

 

42,784

 

  

 

42,982

 

Depreciation and amortization

  

 

8,272

  

 

9,778

 

  

 

15,051

 

Selling, general and administrative expenses

  

 

12,432

  

 

12,984

 

  

 

16,772

 

    

  


  


Total costs and expenses

  

 

61,878

  

 

65,546

 

  

 

74,805

 

    

  


  


Operating income

  

$

31,064

  

$

29,893

 

  

$

27,158

 

    

  


  


Terminal Facilities

                        

Sales and other operating revenue:

                        

Affiliates

  

$

44,356

  

$

43,628

 

  

$

55,971

 

Unaffiliated customers

  

 

31,042

  

 

30,273

 

  

 

31,914

 

Other income/(loss)

  

 

430

  

 

(85

)

  

 

2

 

    

  


  


Total revenues

  

 

75,828

  

 

73,816

 

  

 

87,887

 

    

  


  


Operating expenses

  

 

39,390

  

 

36,488

 

  

 

35,568

 

Depreciation and amortization

  

 

8,616

  

 

11,094

 

  

 

11,113

 

Selling, general and administrative expenses

  

 

10,666

  

 

10,158

 

  

 

12,367

 

    

  


  


Total costs and expenses

  

 

58,672

  

 

57,740

 

  

 

59,048

 

    

  


  


Operating income

  

$

17,156

  

$

16,076

 

  

$

28,839

 

    

  


  


Western Pipeline System

                        

Sales and other operating revenue:

                        

Affiliates

  

$

1,187,696

  

$

953,923

 

  

$

1,019,577

 

Unaffiliated customers

  

 

457,167

  

 

494,490

 

  

 

621,528

 

Other income/(loss)

  

 

552

  

 

110

 

  

 

(23

)

    

  


  


Total revenues

  

 

1,645,415

  

 

1,448,523

 

  

 

1,641,082

 

    

  


  


Cost of products sold and operating expenses

  

 

1,618,977

  

 

1,423,884

 

  

 

1,612,346

 

Depreciation and amortization

  

 

3,766

  

 

4,453

 

  

 

5,170

 

Selling, general and administrative expenses

  

 

11,585

  

 

12,814

 

  

 

13,934

 

    

  


  


Total costs and expenses

  

 

1,634,328

  

 

1,441,151

 

  

 

1,631,450

 

    

  


  


Operating income

  

$

11,087

  

$

7,372

 

  

$

9,632

 

    

  


  


 

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Operating Highlights

 

    

Predecessor


  

Partnership
and
Predecessor


    

Year Ended December 31,


    

2000


  

2001


  

2002


Eastern Pipeline System(1):

              

Pipeline throughput (bpd):

              

Refined products (2)

  

444,046

  

446,648

  

489,235

Crude oil

  

91,464

  

98,226

  

95,311

Total shipments (barrel miles per day)(3)

  

54,910,640

  

55,198,189

  

56,768,267

Revenue per barrel mile (cents)

  

0.440

  

0.450

  

0.459

Terminal Facilities:

              

Terminal throughput (bpd):

              

Refined product terminals

  

266,212

  

272,698

  

272,788

Nederland Terminal

  

566,941

  

427,194

  

405,686

Fort Mifflin Terminal Complex

  

314,623

  

318,545

  

322,304

Marcus Hook Tank Farm

  

133,455

  

138,490

  

149,982

Western Pipeline System(1):

              

Crude oil pipeline throughput (bpd)

  

295,991

  

287,237

  

286,912

Crude oil purchases at wellhead (bpd)

  

172,839

  

174,182

  

189,277

Gross margin per barrel of pipeline throughput (cents)(4)

  

20.4

  

19.1

  

22.5


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

 

(2)   Excludes Toledo, Twin Oaks, and Linden transfer pipelines, which transport large volumes over short distances and generate minimal revenue.

 

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

 

(4)   Represents total segment sales and other operating revenue minus cost of products sold and operating expenses and depreciation and amortization divided by crude oil pipeline throughput.

 

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

 

Analysis of Statements of Income

 

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

 

Sales and other operating revenue totaled $1,824.0 million for the year ended December 31, 2002 as compared with $1,613.0 million for the corresponding 2001 period, an increase of $211.0 million. The increase was largely attributable to higher lease acquisition volume and an increase in crude oil prices. The average price of West Texas Intermediate crude oil at Cushing, Oklahoma, the benchmark crude oil in the United States,

 

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increased to an average price of $26.11 per barrel for the year ended December 31, 2002 from $25.95 for the prior year. Other income increased $2.1 million from the prior year to $6.9 million for the year ended December 31, 2002 due principally to increased equity income from the Explorer Pipeline Company (“Explorer”) caused by higher volume and revenue per barrel. Other income also increased due to equity income from the acquisitions of a 31.5% ownership interest in Wolverine, a 9.2% interest in West Shore, a 14.0% interest in Yellowstone, and a 43.8% interest in West Texas Gulf. Wolverine, West Shore, and Yellowstone were acquired for $54.0 million, and West Texas Gulf was acquired for $10.6 million. Results have been included within the statements of income from November 15, 2002, their date of acquisition.

 

Total cost of products sold and operating expenses increased $187.7 million to $1,690.9 million for the year ended December 31, 2002 from $1,503.2 million for the prior year due primarily to an increase in lease acquisition volume and an increase in crude oil prices described earlier. Depreciation and amortization increased $6.0 million from $25.3 million for the year ended December 31, 2001 to $31.3 million for the year ended December 31, 2002. This is primarily due to a $6.3 million write-down of an idled refined product pipeline in the Eastern Pipeline System and a related terminal in 2002. During 2002, the Partnership entered into a long-term agreement to lease throughput capacity on a third-party refined product pipeline which allowed it to provide substantially the same service as existed on the idled pipeline while reducing operating expenses.

 

Selling, general and administrative expenses increased $7.1 million to $43.1 million for the year ended December 31, 2002 from $36.0 million for the prior year primarily due to public company costs, increased insurance premiums and higher administrative expenses.

 

Net interest expense increased $6.3 million to $17.3 million for the year ended December 31, 2002 from $11.0 million for the prior year due to interest expense on the $250.0 million, ten year, 7.25% Senior Notes being at a higher interest rate than the debt due to Sunoco in the prior year, which was primarily at a floating rate, and a higher debt level in 2002 compared with the prior year. The debt due to Sunoco in the prior year was either repaid prior to the IPO or not assumed by the Partnership.

 

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

 

Analysis of Segment Operating Income

 

Eastern Pipeline System

 

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

 

The $9.3 million increase in total costs and expenses from the prior year was due to increases in depreciation and amortization of $5.3 million, selling, general and administrative expenses of $3.8 million, and operating expenses of $0.2 million. The increase in depreciation and amortization was due to the write-down of the idled refined product pipeline. The increase in selling, general and administrative expenses was due to allocated public company costs, increased insurance premiums and higher administrative expenses. The increase in operating expenses was due to slightly higher pipeline maintenance expenses.

 

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Terminal Facilities

 

Operating income for the Terminal Facilities was $28.8 million for the year ended December 31, 2002 compared with $16.1 million for the prior year. The $12.7 million increase was due to a $14.1 million increase in total revenues and a $0.9 million decrease in operating expenses, partially offset by a $2.2 million increase in selling, general and administrative expenses.

 

The $14.1 million increase in total revenues was principally due to the change in the fee arrangement for terminalling and throughput services provided to Sunoco as discussed earlier. Total revenues at the Nederland Terminal also increased due to higher tank rental revenues including additional revenues from the new tank that was brought into service at the beginning of the second quarter of 2002, partially offset by lower throughput volumes.

 

The $0.9 million decrease in operating expenses was primarily due to lower maintenance expenses at the refined product terminals, the Fort Mifflin Terminal Complex, the Marcus Hook Tank Farm and the Inkster Terminal. The $2.2 million increase in selling, general and administrative expenses was attributable to allocated public company costs, increased insurance premiums and higher administrative expenses.

 

Western Pipeline System

 

Operating income for the Western Pipeline System was $9.6 million for the year ended December 31, 2002, a $2.3 million increase from the prior year. This increase was primarily the result of a $3.4 million increase in gross margin, partially offset by a $1.1 million increase in selling, general and administrative expenses.

 

Sales and other operating revenue and cost of products sold and operating expenses increased in 2002 compared with the prior year due to higher lease acquisition volume and an increase in the price of crude oil as discussed earlier. The lease acquisition volume increase was partially due to the acquisition of GulfMark Energy, Inc.’s crude oil pipeline in Texas and its crude oil acquisition business in November 2001 (the “GulfMark Assets”). The $3.4 million increase in gross margin was due to an increase in lease acquisition volume and margins, partially offset by a higher proportion of lower revenue per barrel throughput on the Western Pipeline trunk system. Depreciation and amortization increased $0.7 million to $5.2 million for 2002 compared with the prior year due to higher capital expenditures at the end of 2001 including the acquisition of the GulfMark Assets.

 

Selling, general and administrative expenses increased $1.1 million due to allocated public company costs, increased insurance premiums and higher administrative expenses.

 

Year Ended December 31, 2001 versus Year Ended December 31, 2000

 

Analysis of Statements of Income

 

Net income was $26.8 million for the year ended December 31, 2001 as compared with $30.5 million for the same period in the prior year, a decrease of $3.7 million. This decrease was primarily the result of a $6.0 million decrease in operating income and a $0.7 million increase in net interest expense, partially offset by a $2.9 million decrease in corporate income taxes. Operating income declined $6.0 million to $53.3 million for the year ended December 31, 2001 in comparison with 2000 due principally to lower gross margins for the Western Pipeline System, higher operating expenses at the Eastern Pipeline System primarily due to additional environmental remediation costs associated with a prior-period pipeline leak, and a decline in volume and revenue at the Nederland Terminal.

 

Sales and other operating revenue totaled $1,613.0 million for the year ended December 31, 2001 as compared with $1,808.6 million for the corresponding 2000 period, a decrease of $195.6 million. This decrease was primarily attributable to lower lease acquisition revenue due to a decline in crude oil prices. The average price of West Texas Intermediate crude oil at Cushing, Oklahoma, dropped to an average price of $25.92 per

 

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barrel for the year ended December 31, 2001 from $30.20 per barrel for the prior year. Other income decreased $0.8 million from the prior year to $4.8 million for the year ended December 31, 2001 due to lower dividend income from an insurance consortium in which Sunoco participates and the absence of the allocated portion of a gain recognized in 2000 attributable to the receipt of stock by Sunoco in connection with an insurance company demutualization. These insurance-related gains were allocated to each of the business segments. Partially offsetting these lower insurance gains was a $0.5 million increase in Explorer equity income to $4.3 million for the year ended December 31, 2001. Cash dividends paid by Explorer approximate the equity income earned from that investment. The increase in Explorer equity income was due to the absence of the adverse impact of a refined product spill that occurred in March 2000.

 

Total cost of products sold and operating expenses decreased $196.3 million to $1,503.2 million for the year ended December 31, 2001 from $1,699.5 million for the prior year due primarily to the decline in crude oil prices described above. Depreciation and amortization increased $4.6 million from $20.7 million for the year ended December 31, 2000 to $25.3 million for the year ended December 31, 2001 primarily due to higher capital expenditures in 2001 than in 2000 and a $1.4 million write-off of refined product terminal equipment in the fourth quarter of 2001.

 

Selling, general and administrative expenses increased $1.3 million to $36.0 million for the year ended December 31, 2001 from $34.7 million for the prior year. This increase was primarily attributable to an increase in the amounts allocated by Sunoco, Inc. to cover the costs of centralized corporate functions incurred on the Predecessor’s behalf. These allocations of costs of centralized corporate functions are now covered under an omnibus agreement (the “Omnibus Agreement”) entered into between the Partnership and Sunoco, Inc. concurrent with the IPO on February 8, 2002 (see “Agreements with Sunoco R&M and Sunoco, Inc.”).

 

Net interest expense increased $0.7 million to $11.0 million for the year ended December 31, 2001 from $10.3 million for the prior year primarily due to lower capitalized interest amounts on capital projects.

 

Income tax expense for the year ended December 31, 2001 of $15.6 million represents a $2.9 million decrease from $18.5 million for the prior year due principally to the decrease in pretax earnings. The effective tax rate decreased to 37% in 2001 from 38% in 2000.

 

Analysis of Segment Operating Income

 

Eastern Pipeline System

 

Operating income for the Eastern Pipeline System was $29.9 million for the year ended December 31, 2001 compared with $31.1 million for the prior year. The $1.2 million decrease was primarily the result of a $3.7 million increase in total costs and expenses, partially offset by a $2.4 million increase in sales and other operating revenue and a $0.1 million increase in other income. Sales and other operating revenue increased compared with the prior year due to higher volumes and revenue per barrel mile. Other income increased primarily due to a $0.5 million increase in equity income from Explorer, partially offset by lower allocated insurance-related gains in 2001 compared with 2000.

 

The $3.7 million increase in total costs and expenses was due to an increase in operating expenses of $1.6 million due to additional environmental remediation costs associated with a prior-period pipeline leak, an increase in depreciation and amortization of $1.5 million due to higher capital expenditures in 2001 than in 2000, and an increase in selling, general and administrative expense of $0.6 million due to a higher allocation of centralized corporate function costs from Sunoco, Inc. in 2001 than in 2000.

 

Terminal Facilities

 

Operating income for the Terminal Facilities was $16.1 million for the year ended December 31, 2001 compared with $17.2 million for the prior year. The $1.1 million decrease was due to a $2.5 million increase in depreciation and amortization and a $2.0 million decline in total revenues, partially offset by a $2.9 million decrease in operating expenses and a $0.5 million decrease in selling, general and administrative expenses.

 

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The $2.0 million decrease in total revenues was due principally to a decline in volume at the Nederland Terminal resulting from the absence of Department of Energy sales of crude oil from the Strategic Petroleum Reserve, which occurred primarily during the fourth quarter of 2000. Partially offsetting this decline was an increase in tank rental revenue attributable to a new tank that was placed into service in the third quarter of 2000 at the Nederland Terminal.

 

The $2.9 million decrease in operating expenses was attributable to the absence of $6.0 million in charges recognized in 2000 in connection with remediation activities related to a February 2000 crude oil spill at one of the crude oil transfer lines to the Darby Creek Tank Farm, partially offset by higher terminal maintenance expenses and other environmental expenses in 2001. The $2.5 million increase in depreciation and amortization was primarily due to a $1.4 million write-off of refined product terminal equipment in 2001 and higher capital expenditures in 2001 than in 2000.

 

Western Pipeline System

 

Operating income for the Western Pipeline System was $7.4 million for the year ended December 31, 2001, a $3.7 million decrease from the prior year. This decrease was primarily the result of a $2.1 million decrease in gross margin, a $1.2 million increase in selling, general and administrative expenses, and a $0.4 million decrease in other income.

 

Sales and other operating revenue and cost of products sold and operating expenses decreased in 2001 compared with the prior year primarily due to a decline in the price of crude oil discussed earlier and lower revenue per barrel pipeline throughput, partially offset by higher lease acquisition volumes. The $2.1 million decrease in gross margin was primarily due to a decrease in crude oil pipeline gathering revenues. Depreciation and amortization increased $0.7 million to $4.5 million for 2001 compared with the prior year due to higher capital expenditures in 2001 compared with 2000.

 

The $1.2 million increase in selling, general and administrative expenses relates primarily to higher allocated costs from Sunoco for centralized corporate functions incurred on the Predecessor’s behalf as well as other general expenditures. Other income decreased $0.4 million due primarily to lower allocated insurance-related gains.

 

Liquidity and Capital Resources

 

General

 

Cash generated from operations and the Credit Facility are the Partnership’s primary sources of liquidity. At December 31, 2002, the Partnership had working capital of $33.2 million and $85.5 million available under the Credit Facility. In February 2003, the Credit Facility was amended to increase the aggregate committed sum to $200 million, increasing the amount available under the facility to $135.5 million. The Partnership’s working capital position is stronger than indicated because of the relatively low historical costs assigned under the LIFO method of accounting for crude oil inventories reflected in the balance sheets. The current replacement cost of all such inventories exceeded their carrying value at December 31, 2002 by $33.5 million. Management believes that the Partnership has sufficient liquid assets, cash from operations and borrowing capacity under its credit agreements to meet its financial commitments, debt service obligations, unitholder distributions, contingencies and anticipated capital expenditures. However, the Partnership is subject to business and operations risks that could adversely effect its cash flow. The Partnership may supplement its cash generation with proceeds from financing activities, including borrowings under the Credit Facility and other borrowings and the issuance of additional common units.

 

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Cash Flows and Capital Expenditures

 

Net cash provided by operating activities for 2002 was $2.2 million compared with $27.2 million in 2001 and $79.1 million in 2000. The decline in net cash provided by operating activities of $25.0 million from 2002 to 2001 is primarily attributable to a $73.4 million increase in working capital for the year ended December 31, 2002 in comparison to a $33.6 million increase in working capital in 2001. The increase in working capital in 2002 is due to the replacement of working capital that was not contributed by Sunoco to the Partnership upon formation. The net proceeds of the IPO were used to replenish the working capital shortfall. The working capital not contributed consisted primarily of $81.0 million of affiliated company accounts receivable and $13.5 million of crude oil inventory. In addition to the working capital change between periods, there was also an increase in net income of $20.0 million to $46.8 million in 2002 and an increase in depreciation and amortization of $6.0 million to $31.3 million in 2002, partially offset by a decline of $8.1 million in deferred income tax expense.

 

Net cash provided by operating activities of $27.2 million for the year ended December 31, 2001 represents a $51.9 million decrease from 2000. The decline between periods is due to an increase in working capital in 2001 of $33.6 million in comparison to an decrease in working capital in 2000 of $24.3 million. The increase in working capital in 2001 was primarily the result of a decline in crude oil prices and its effect on receivables and payables from the purchase and sale of crude oil in the Western Pipeline System. During 2000, crude oil prices increased, which caused working capital to decline.

 

The inverse relationship between crude oil prices and the level of working capital exists because there are more crude oil payables than receivables and because of the use of the last-in, first-out method of accounting for crude oil inventories in the crude oil acquisition and marketing activities. Prior to the IPO in February 2002, crude oil payables exceeded crude oil receivables largely due to the absence of a crude oil receivable from Sunoco R&M. Receivables from Sunoco R&M were settled immediately through the net parent investment account. Upon completion of the IPO, payment terms in the crude oil supply contracts with Sunoco R&M resulted in crude oil receivables, lowering the net crude oil payable and reducing the impact of changes in crude oil prices on net cash provided by operating activities.

 

Net cash used in investing activities for the years ended December 31, 2000, 2001, and 2002 was $77.3 million, $73.1 million and $85.3 million, respectively. Capital expenditures were $57.9 million in 2000, $72.7 million in 2001, and $40.8 million in 2002. During 2002, the Partnership acquired equity ownership interests in four corporate joint venture pipeline companies for an aggregate purchase price of $64.5 million in cash and $0.1 million in Partnership common units, consisting of $54.0 million for a 31.5% equity ownership interest in Wolverine, a 9.2% interest in West Shore, and a 14.0% interest in Yellowstone and $10.6 million for a 43.8% interest in West Texas Gulf. The only other significant investing transaction in the three-year period was a loan to The Claymont Investment Company, a wholly-owned subsidiary of Sunoco, of $20.0 million in 2000, which was subsequently repaid in 2002.

 

Net cash provided by/(used in) financing activities for the years ended December 31, 2000, 2001, and 2002 was $(1.8) million, $45.8 million, and $116.9 million, respectively. In 2002, the Partnership received net proceeds of $96.5 million from the IPO, $64.5 million of borrowings under the Credit Facility to fund the acquisitions noted earlier, and $43.9 million of capital contributions from Sunoco, partially offset by a $50.0 million repayment of long-term debt due an affiliate, $26.9 million of distributions paid to unitholders and the general partner and net advances to affiliates of $10.7 million. In addition, net proceeds of $244.8 million from the issuance of the Senior Notes in conjunction with the IPO were distributed to Sunoco. For a more detailed discussion of the IPO and related transactions, see “Initial Public Offering” and “Senior Notes” in this section. The other significant transactions during 2000 and 2001 were contributions from/(distributions to) Sunoco and its affiliates of $(96.6) million and $91.1 million in 2000 and 2001, respectively, and net proceeds from/(repayments of) borrowings to The Claymont Investment Company of $95.0 million and $(45.0) million in 2000 and 2001, respectively.

 

Under the treasury services agreement entered into with Sunoco upon the closing of the IPO, the Partnership, among other things, participates in Sunoco’s centralized cash management program. Advances to an

 

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

 

Capital Requirements

 

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

 

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

 

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

 

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

 

    

Predecessor


  

Partnership

and

Predecessor


 
    

Year Ended December 31,


 
    

2000


  

2001


  

2002


 
    

(in thousands)

 

Maintenance

  

$

39,067

  

$

53,628

  

$

27,934

 

Expansion

  

 

18,854

  

 

19,055

  

 

77,439

(1)

    

  

  


Total

  

$

57,921

  

$

72,683

  

$

105,373

 

    

  

  



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

 

Total capital expenditures for the year ended December 31, 2002 were $105.4 million, an increase of approximately $40.1 million from the average annual outlays for the years ended December 31, 2000 and 2001. This increase was due to the acquisition of equity interests in Wolverine, West Shore and Yellowstone for $54.0 million and West Texas Gulf for $10.6 million, including issuance of Partnership common units for $0.1 million, in November 2002, partially offset by the absence of several one-time projects undertaken in 2000 and 2001. The projects were undertaken primarily to upgrade the Partnership’s technology, increase reliability, and lower its cost structure. These expenditures were not incurred in 2002 and are not expected to be incurred in the near future by the Partnership’s management. Management expects maintenance capital expenditures to be approximately $25.5 million in 2003.

 

In 2002, capital expenditures consisted of $27.9 million of maintenance capital, a $25.7 million decrease from 2001 expenditures of $53.6 million, and $77.4 million of expansion capital, a $58.3 million increase from 2001 expenditures of $19.1 million. Maintenance capital spending in 2002 primarily consisted of recurring expenditures such as pipeline integrity enhancements, pipeline relocations, renewal and replacement of terminal tank floors and roofs, repair or upgrade of field instrumentation, upgrade to cathodic protection systems, repair and upgrade to pump stations and the purchase of new crude oil transport trucks. In addition to these recurring projects, maintenance capital includes $2.6 million of expenditures at the Darby Creek Tank Farm and the

 

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Marcus Hook Tank Farm for which the Partnership received reimbursement from Sunoco R&M under the terms of the Omnibus Agreement. In addition to the interests in the pipeline system acquisitions, expansion capital spending primarily consisted of the construction of two new tanks at the Nederland Terminal, which will add 1.3 million barrels of storage capacity and is expected to be operational by the second quarter of 2003, the construction of multiple vapor combustion units at the Nederland Terminal, and pipeline meter modifications in the Eastern Pipeline System to improve throughput efficiency.

 

Under the terms of the Omnibus Agreement, Sunoco R&M is required, among other things, to: reimburse the Partnership for any operating expenses and capital expenditures in excess of $8.0 million per year in each 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 from the closing of the IPO; complete, at its expense, certain tank maintenance and inspection projects currently in progress or expected to be completed at the Darby Creek Tank Farm within one year; 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 year ended December 31, 2002, the Partnership received $0.7 million from 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. For the year ended December 31, 2002, the Partnership also received $2.1 million from Sunoco R&M for maintenance capital expenditures for certain tank maintenance and inspection projects completed at the Darby Creek Tank Farm. For the year ended December 31, 2002, the Partnership also received $0.9 million from Sunoco R&M, consisting of $0.5 million for maintenance capital expenditures and $0.4 million for operating expenses, for expenditures at the Marcus Hook Tank Farm and the Darby Creek Tank Farm to maintain compliance with existing industry standards and regulatory requirements. The aggregate amounts received of $3.7 million from Sunoco R&M related to these projects were recorded by the Partnership as capital contributions.

 

In 2000 and 2001, capital expenditures consisted of $46.3 million of average annual spending for maintenance capital, $18.4 million above 2002 amounts, and $19.0 million of average annual spending for expansion capital, $58.4 million below 2002 amounts. Maintenance capital expenditures in 2000 and 2001 consisted of several one-time projects to upgrade the Partnership’s technology, increase reliability, and lower its cost structure. These types of expenditures were not incurred in 2002 and are not expected to be incurred in the near future. These expenditures consisted of technology projects such as numerous automation projects, upgrades to metering systems, replacement of pipeline control systems, and enhancements to various software packages. One-time maintenance capital expenditures during these periods also consisted of asset upgrade projects such as relocating pipelines at the Philadelphia International Airport due to runway and terminal reconfigurations, rebuilds on three pump stations, replacement and upgrade of vapor recovery units at the product terminals and repair and upgrades on the crude oil transfer lines between Hog Island Wharf and the Darby Creek Tank Farm. The crude oil transfer lines, which were historically a part of Sunoco R&M’s refining business, did not meet pipeline standards and could not be internally inspected or maintained by conventional leak detection devices prior to completion of this project. Expansion capital expenditures in 2000 and 2001 consisted of several projects to create new tankage, increase throughput on existing pipelines, and build new connections for deliveries to customers. Management of the Partnership anticipates pursuing similar growth projects in the future.

 

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

 

    borrowing under the Credit Facility discussed below and other borrowings; and

 

    issuance of additional common units.

 

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Contractual Obligations

 

The following table sets forth the aggregate amount of long-term debt maturities and future annual rentals applicable to noncancellable operating leases at December 31, 2002 (in thousands):

 

    

Year Ended December 31,


    
    

2003


  

2004


  

2005


  

2006


  

2007


  

Thereafter


  

Total


Long-term debt

  

$

303

  

$

303

  

$

64,803

  

$

303

  

$

303

  

$

252,963

  

$

318,978

Operating leases

  

 

3,112

  

 

2,526

  

 

1,884

  

 

1,485

  

 

1,314

  

 

6,577

  

 

16,898

    

  

  

  

  

  

  

    

$

3,415

  

$

2,829

  

$

66,687

  

$

1,788

  

$

1,617

  

$

259,540

  

$

335,876

    

  

  

  

  

  

  

 

Initial Public Offering

 

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

 

Credit Facility

 

In conjunction with the IPO, Sunoco Logistics Partners Operations L.P., a wholly-owned subsidiary of the Partnership (the “Operating Partnership”), entered into a three-year $150.0 million Credit Facility. In February 2003, the Credit Facility was amended to add new lenders, and to increase the aggregate committed sum to $200 million. The Credit Facility is available to fund working capital requirements, to finance future acquisitions, and for general partnership purposes. It also includes a $20.0 million distribution sublimit that is available for distributions, and may be used to fund the quarterly distributions provided the total outstanding borrowings for distributions do not at any time exceed $20.0 million. The Partnership will be required to reduce to zero all borrowings under the distribution sublimit under the Credit Facility each year for 15 days. At December 31, 2002, there was $64.5 million drawn under the Credit Facility.

 

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

 

Indebtedness under the Credit Facility will bear interest, at the Partnership’s option, at either (i) LIBOR plus an applicable margin or (ii) the higher of the federal funds rate plus 0.50% or the Bank of America prime rate (each plus the applicable margin). The interest rate on the borrowings outstanding under the Credit Facility as of December 31, 2002 was 2.12%. Fees will be incurred in connection with the Credit Facility. The Credit Facility will mature in January 2005. At that time, the facility will terminate and all outstanding amounts will be due and payable.

 

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

 

    incur indebtedness;

 

    grant certain liens;

 

    make certain loans, acquisitions, and investments;

 

    make any material change to the nature of the business;

 

    acquire another company; or

 

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

 

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

 

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

 

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

 

For the year ended December 31, 2002, the Partnership’s ratio of total debt to EBITDA was 3.0 to 1 and the interest coverage ratio was 5.0 to 1.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

Senior Notes

 

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

 

In addition, the Senior Notes contain various covenants limiting the Operating Partnership’s ability to:

 

    incur certain liens;

 

    engage in sale/leaseback transactions; or

 

    merge, consolidate, or sell substantially all of its assets.

 

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

 

    failure to pay interest on any note for 30 days;

 

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

 

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

 

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

 

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

 

Upon the occurrence of a change of control to a non-investment grade entity, the Operating Partnership must offer to purchase the Senior Notes at a price equal to 100% of their principal amount plus accrued and unpaid interest, if any, to the date of purchase. The initial offering of the Senior Notes was not registered under the Securities Act. However, the Operating Partnership filed an exchange offer registration statement on SEC Form S-4 on April 11, 2002 and a first amendment on May 8, 2002 in connection with the registration of the exchange of the Senior Notes and the guarantees covering the Senior Notes. This registration statement was declared effective on June 28, 2002. The exchange offer was completed on August 2, 2002, with all $250 million aggregate principal amount of the Senior Notes being exchanged for a like principal amount of new publicly tradable notes having substantially identical terms issued pursuant to the exchange offer registration statement filed under the Securities Act of 1933, as amended.

 

Environmental Matters

 

Operation of the pipelines, terminals, and associated facilities are subject to stringent and complex federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment. As a result of compliance with these laws and regulations, liabilities have been accrued for estimated site restoration costs to be incurred in the future at the facilities and properties, including liabilities for environmental remediation obligations. Under the Partnership’s accounting policies, liabilities are recorded when site restoration and environmental remediation and cleanup obligations are either known or considered probable and can be reasonably estimated. For a discussion of the accrued liabilities and charges against income related to these activities, see Note 11 to the financial statements included in Item 8. “Financial Statements and Supplementary Data.”

 

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 IPO. Sunoco is obligated to indemnify the Partnership for 100% of all losses asserted within the first 21 years of closing. Sunoco’s share of liability for claims asserted thereafter will decrease by 10% a year. For example, for a claim asserted during the twenty-third year after closing, Sunoco would be required to indemnify the Partnership for 80% 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 IPO and for environmental and toxic tort liabilities to the extent Sunoco is not required to indemnify the Partnership.

 

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The use of MTBE continues to be the focus of federal and state government attention due to public health and environmental issues that have been raised by the use of MTBE in gasoline, and specifically the discovery of MTBE in water supplies. MTBE is the primary oxygenate used by Sunoco R&M and other petroleum refiners to meet reformulated gasoline requirements under the Clean Air Act. Many states, including New York and Connecticut, have banned or restricted the use of MTBE in gasoline commencing as early as 2003 in response to concerns about MTBE’s adverse impact on ground or surface water. Other states are considering bans or restrictions on MTBE or opting out of the EPA’s reformulated gasoline program, either of which events would reduce the use of MTBE. Any ban or restriction on the use of MTBE may lead to the greater use of ethanol.

 

Another significant environmental uncertainty relates to Sunoco R&M’s potential capital expenditures to comply with new fuel specifications required under the Clean Air Act, and to respond to the EPA’s enforcement initiative under the authority of the Clean Air Act, including the notices of violation and findings of violations recently received by Sunoco R&M. It is uncertain what Sunoco or Sunoco R&M’s responses to these emerging issues will be. The Partnership cannot assure you that those responses will not reduce Sunoco R&M’s obligations under the pipelines and terminals storage and throughput agreement, thereby reducing the throughput in the pipelines and the cash flow. Unlike MTBE, which can be blended in gasoline at the refinery, ethanol is blended at the terminal and is not transported by the pipelines. While many of the inland-refined product terminals currently blend ethanol, any revenues the Partnership would receive for blending ethanol might not offset the loss of revenues that would be suffered from the reduced volume transported on the Eastern refined product pipelines.

 

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

 

Impact of Inflation

 

Although the impact of inflation has slowed in recent years, it is still a factor in the United States economy and may increase the cost to acquire or replace property, plant, and equipment and may increase the costs of labor and supplies. To the extent permitted by competition, regulation, and existing agreements, the Partnership has and will continue to pass along increased costs to customers in the form of higher fees.

 

Critical Accounting Policies

 

A summary of the Partnership’s significant accounting policies is included in Note 1 to the financial statements included in Item 8 “Financial Statements and Supplementary Data.” Management believes that the application of these policies on a consistent basis enables it to provide the users of the financial statements with useful and reliable information about the Partnership’s operating results and financial condition. The preparation of the Partnership’s financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Significant items that are subject to such estimates and assumptions include long-lived assets and environmental remediation activities. Although management bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, actual results may differ to some extent from the estimates on which the Partnership’s financial statements are prepared at any given point in time. Despite these inherent limitations, management believes the Partnership’s Management’s Discussion and Analysis and financial statements provide a meaningful and fair perspective of the Partnership. Management has reviewed the estimates affecting its critical accounting policies with the Audit Committee of Sunoco Partners LLC’s Board of Directors.

 

Long-Lived Assets.    The cost of property, plants and equipment, less estimated salvage value, is generally depreciated on a straight-line basis over the estimated useful lives of the assets. Useful lives are based on historical experience and are adjusted when changes in planned use, technological advances or other factors show that a different life would be more appropriate. Changes in useful lives that do not result in the impairment of an asset are recognized prospectively. There have been no significant changes in the useful lives of the Partnership’s plants and equipment to be recognized prospectively during the 2000-2002 period.

 

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Long-lived assets, other than those held for sale, are reviewed for impairment whenever events or circumstances indicate that the carrying amount of the assets may not be recoverable. Such events and circumstances include, among other factors: operating losses; unused capacity; market value declines; technological developments resulting in obsolescence; changes in demand for products manufactured by others utilizing the Partnership’s services or for the Partnership’s products; changes in competition and competitive practices; uncertainties associated with the United States and world economies; changes in the expected level of environmental capital, operating or remediation expenditures; and changes in governmental regulations or actions. Additional factors impacting the economic viability of long-lived assets are described under “Forward Looking Statements”, which can be found after the Table of Contents at the front of the document.

 

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

 

The Partnership had asset impairments of $1.4 million and $6.3 million for the years ended December 31, 2001 and 2002. There were no asset impairments for the year ended December 31, 2000. During 2002, the Partnership recorded a $6.3 million provision to write-down an idled refined product pipeline in the Eastern Pipeline System and a related terminal. These assets were idled as a result of a long-term agreement entered into by the Partnership in December 2002 to lease throughput capacity on a third-party refined product pipeline which allowed it to provide substantially the same service as existed on the idled pipeline while reducing operating expenses. During 2001, the Predecessor recorded a $1.4 million charge to write-off obsolete refined product terminal equipment due to the purchase of technologically advanced units. These provisions were recorded within depreciation and amortization in the statements of income in the financial statements. For further discussion of these asset impairments, see Note 4 to the financial statements included in Item 8 “Financial Statements and Supplementary Data.”

 

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

 

At December 31, 2002, the Partnership’s accrual for environmental remediation activities was $0.5 million. This accrual is for work at identified sites where an assessment has indicated that cleanup costs are probably 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.

 

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Management believes that none of the current remediation locations are material, individually or in the aggregate, to the Partnership at December 31, 2002. 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.

 

At December 31, 2001, the Predecessor’s accrual for environmental remediation activities was $16.3 million. Under the terms of the Omnibus Agreement and in connection with the contribution of the Predecessor to the Partnership by affiliates of Sunoco, Sunoco has retained those liabilities in connection with its agreement to indemnify the Partnership for 30 years from environmental and toxic tort liabilities related to the assets contributed that arise from the operation of such assets prior to closing of the IPO. Sunoco is obligated to indemnify the Partnership for 100% of all losses asserted within the first 21 years of closing. Sunoco’s share of liability for claims asserted thereafter will decrease by 10% a year. For example, for a claim asserted during the twenty-third year after closing, Sunoco would be required to indemnify the Partnership for 80% of the loss. There is no monetary cap on the amount of indemnity coverage provided by Sunoco. Any environmental and toxic tort liabilities not covered by this indemnity will be the Partnership’s responsibility. The Partnership has agreed to indemnify Sunoco and its affiliates for events and conditions associated with the operation of the assets that occur on or after the closing of the IPO and for environmental and toxic tort liabilities to the extent Sunoco is not required to indemnify the Partnership.

 

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

 

New Accounting Pronouncements

 

In August 2001, Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”), was issued. This statement significantly changes the method of accruing for costs associated with the retirement of fixed assets that an entity is legally obligated to incur associated with the retirement of fixed assets. Under SFAS No. 143, the fair value of a liability for an asset retirement obligation will be recognized in the period in which it is incurred if a reasonable estimate of the fair value of the liability can be made. The associated asset retirement costs will be capitalized as part of the carrying amount of the fixed asset and depreciated over its estimated useful life. Under existing accounting principles, a liability for an asset retirement obligation is recognized using a cost-accumulation measurement approach. The Partnership is adopting SFAS No. 143 effective January 1, 2003 when adoption is mandatory. Adoption of SFAS No. 143 is not expected to have a significant impact on the Partnership’s financial statements.

 

In July 2002, Statement of Financial Accounting Standards No. 146, “Accounting for Costs Associated with Exit or Disposal Activities” (“SFAS No. 146”), was issued. SFAS No. 146 supersedes Emerging Issues Task Force (“EITF”) Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred. Under SFAS No. 146, an entity’s commitment to a plan, by itself, does not create an obligation that meets the definition of a liability. SFAS No. 146 also establishes fair value as the objective for initial measurement of the liability. Severance pay would be recognized over time rather than at the plan commitment date if the benefit arrangement requires employees to render future service beyond a “minimum retention period.” The provisions of SFAS No. 146 are effective for exit or disposal activities that are initiated after December 31, 2002. Adoption of SFAS No. 146 could result in the deferral of recognition of costs associated with restructuring plans initiated in

 

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periods subsequent to December 31, 2002 from the date the Partnership commits to the plan to the date that it incurs a liability for the costs. As SFAS No. 146 only applies to prospective items, the Partnership is unable to determine the impact, if any, that adoption of SFAS No. 146 would have on its future financial position or results of operations.

 

In November 2002, FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (“FASB Interpretation No. 45”), was issued. The accounting recognition provisions of FASB Interpretation No. 45 are effective January 1, 2003 on a prospective basis. They require that a guarantor recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. Under prior accounting principles, a guarantee would not have been recognized as a liability until a loss was probable and reasonably estimable. As FASB Interpretation No. 45 only applies to prospective transactions, the Partnership is unable to determine the impact, if any, that adoption of the accounting recognition provisions of FASB Interpretation No. 45 would have on its future financial position or results of operations.

 

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 $150 million Credit Facility, with outstanding borrowings at December 31, 2002 of $64.5 million, would expose the Partnership to interest rate risk, since it bears interest at a variable rate (2.12% at December 31, 2002). A one percent change in interest rates changes annual interest expense by approximately $645,000. In February 2002, the Credit Facility was amended to increase the aggregate committed sum to $200 million.

 

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ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

REPORT OF INDEPENDENT AUDITORS

 

To the Board of Directors of  

Sunoco Partners LLC:

 

We have audited the accompanying balance sheets of Sunoco Logistics Partners L.P. (the “Partnership”) as of December 31, 2002 and 2001 and the related statements of income and partners’ capital/net parent investment and cash flows for each of the three years in the period ended December 31, 2002. These financial statements, which reflect the cost-basis accounts of Sunoco Logistics (Predecessor), the predecessor to the Partnership, are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

 

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

 

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Sunoco Logistics Partners L.P. at December 31, 2002 and 2001 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States.

 

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

 

ERNST & YOUNG LLP

 

Philadelphia, Pennsylvania

February 14, 2003

 

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SUNOCO LOGISTICS PARTNERS L.P.

 

STATEMENTS OF INCOME

(in thousands, except units and per unit amounts)

 

    

Predecessor


    

Partnership
and
Predecessor


 
    

Year Ended December 31,


 
    

2000


    

2001


    

2002


 

Revenues

                          

Sales and other operating revenue:

                          

Affiliates (Note 3)

  

$

1,301,079

 

  

$

1,067,182

 

  

$

1,147,721

 

Unaffiliated customers

  

 

507,532

 

  

 

545,822

 

  

 

676,307

 

Other income

  

 

5,574

 

  

 

4,774

 

  

 

6,904

 

    


  


  


Total Revenues

  

 

1,814,185

 

  

 

1,617,778

 

  

 

1,830,932

 

Costs and Expenses

                          

Cost of products sold and operating expenses

  

 

1,699,541

 

  

 

1,503,156

 

  

 

1,690,896

 

Depreciation and amortization (Note 4)

  

 

20,654

 

  

 

25,325

 

  

 

31,334

 

Selling, general and administrative expenses

  

 

34,683

 

  

 

35,956

 

  

 

43,073

 

    


  


  


Total Costs and Expenses

  

 

1,754,878

 

  

 

1,564,437

 

  

 

1,765,303

 

    


  


  


Operating Income

  

 

59,307

 

  

 

53,341

 

  

 

65,629

 

Net interest cost paid to affiliates (Note 3)

  

 

11,537

 

  

 

11,727

 

  

 

1,205

 

Other interest cost and debt expense, net

  

 

426

 

  

 

393

 

  

 

17,390

 

Capitalized interest

  

 

(1,659

)

  

 

(1,140

)

  

 

(1,296

)

    


  


  


Income before income tax expense

  

 

49,003

 

  

 

42,361

 

  

 

48,330

 

Income tax expense (Note 5)

  

 

18,483

 

  

 

15,594

 

  

 

1,555

 

    


  


  


Net Income

  

$

30,520

 

  

$

26,767

 

  

$

46,775

 

    


  


  


Allocation of 2002 Net Income:

                          

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

                    

$

3,421

 

Portion applicable to February 8 through December 31, 2002

                    

 

43,354

 

                      


Net Income

                    

$

46,775

 

                      


Calculation of Limited Partners’ interest in Net Income:

                          

Net Income

                    

$

43,354

 

Less: General Partners’ interest in Net Income

                    

 

867

 

                      


Limited Partners’ interest in Net Income

                    

$

42,487

 

                      


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

                          

Basic

                    

$

1.87

 

                      


Diluted

                    

$

1.86

 

                      


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

                          

Basic

                    

 

22,767,899

 

                      


Diluted

                    

 

22,785,407

 

                      


 

(See Accompanying Notes)

 

 

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SUNOCO LOGISTICS PARTNERS L.P.

 

BALANCE SHEETS

(in thousands)

 

    

Predecessor


  

Partnership


    

December 31,


    

2001


  

2002


Assets

             

Current Assets

             

Cash and cash equivalents

  

$

   —  

  

$

33,840

Advances to affiliates (Note 3)

  

 

—  

  

 

10,716

Accounts receivable, affiliated companies (Note 3)

  

 

6,245

  

 

105,466

Accounts receivable, net

  

 

151,264

  

 

251,071

Note receivable from affiliate (Note 3)

  

 

20,000

  

 

—  

Inventories (Note 7)

  

 

20,606

  

 

25,744

Deferred income taxes (Note 5)

  

 

2,821

  

 

—  

    

  

Total Current Assets

  

 

200,936

  

 

426,837

Properties, plants and equipment, net (Note 8)

  

 

566,359

  

 

573,514

Investment in affiliates (Note 9)

  

 

27

  

 

65,733

Deferred charges and other assets

  

 

21,879

  

 

27,796

    

  

Total Assets

  

$

789,201

  

$

1,093,880

    

  

Liabilities and Partners’ Capital / Net Parent Investment

             

Current Liabilities

             

Accounts payable

  

$

   235,061

  

$

356,977

Accrued liabilities

  

 

26,628

  

 

25,090

Current portion of long-term debt due affiliate (Note 3)

  

 

75,000

  

 

—  

Current portion of long-term debt (Note 10)

  

 

228

  

 

303

Taxes payable

  

 

20,373

  

 

11,273

    

  

Total Current Liabilities

  

 

357,290

  

 

393,643

Long-term debt due affiliate (Note 3)

  

 

65,000

  

 

—  

Long-term debt (Note 10)

  

 

4,553

  

 

317,142

Deferred income taxes (Note 5)

  

 

78,140

  

 

—  

Other deferred credits and liabilities

  

 

9,325

  

 

745

Commitments and contingent liabilities (Note 11)

             

Partners’ Capital:

             

Limited partners’ interest

  

 

—  

  

 

376,632

General partner’s interest

  

 

—  

  

 

5,718

Net parent investment (Note 12)

  

 

274,893

  

 

—  

    

  

Total Liabilities and Partners’ Capital / Net Parent Investment

  

$

789,201

  

$

1,093,880

    

  

 

(See Accompanying Notes)

 

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SUNOCO LOGISTICS PARTNERS L.P.

 

STATEMENTS OF CASH FLOWS

(in thousands)

 

    

Predecessor


    

Partnership
and Predecessor


 
    

Year Ended December 31,


 
    

2000


    

2001


    

2002


 

Cash Flows from Operating Activities:

                          

Net Income

  

$

30,520

 

  

$

26,767

 

  

$

46,775

 

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

                          

Depreciation and amortization

  

 

20,654

 

  

 

25,325

 

  

 

31,334

 

Deferred income tax expense

  

 

5,340

 

  

 

8,813

 

  

 

675

 

Changes in working capital pertaining to operating activities:

                          

Accounts receivable, affiliated companies

  

 

2,253

 

  

 

508

 

  

 

(99,221

)

Accounts receivable, net

  

 

(70,052

)

  

 

106,780

 

  

 

(102,253

)

Inventories

  

 

(6,014

)

  

 

(1,923

)

  

 

(12,127

)

Accounts payable and accrued liabilities

  

 

96,408

 

  

 

(140,340

)

  

 

135,244

 

Taxes payable

  

 

1,668

 

  

 

1,415

 

  

 

4,972

 

Other

  

 

(1,661

)

  

 

(107

)

  

 

(3,188

)

    


  


  


Net cash provided by operating activities

  

 

79,116

 

  

 

27,238

 

  

 

2,211

 

    


  


  


Cash Flows from Investing Activities:

                          

Capital expenditures

  

 

(57,921

)

  

 

(72,683

)

  

 

(40,782

)

Net cash paid for acquisitions

  

 

—  

 

  

 

—  

 

  

 

(64,491

)

Collection of/(loan to) affiliate

  

 

(20,000

)

  

 

—  

 

  

 

20,000

 

Other

  

 

629

 

  

 

(396

)

  

 

—  

 

    


  


  


Net cash used in investing activities

  

 

(77,292

)

  

 

(73,079

)

  

 

(85,273

)

    


  


  


Cash Flows from Financing Activities:

                          

Distributions paid to unitholders and general partner

  

 

—  

 

  

 

—  

 

  

 

(26,949

)

Net proceeds from issuance of common units to the public

  

 

—  

 

  

 

—  

 

  

 

96,468

 

Advances to affiliates, net

  

 

—  

 

  

 

—  

 

  

 

(10,716

)

Net borrowings under credit facility

  

 

—  

 

  

 

—  

 

  

 

64,500

 

Repayments of long-term debt

  

 

(244

)

  

 

(262

)

  

 

(303

)

Proceeds / (repayments) from issuance of long-term debt to affiliate

  

 

50,000

 

  

 

—  

 

  

 

(50,000

)

Net proceeds from issuance of long-term debt

  

 

—  

 

  

 

—  

 

  

 

244,788

 

Special distribution to Sunoco

  

 

—  

 

  

 

—  

 

  

 

(244,788

)

Contributions from / (distributions to) Su