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FORM 10-K

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

For the Fiscal Year ended December 31, 2002

Commission File Number 1-10403

TEPPCO Partners, L.P.

2929 Allen Parkway
P.O. Box 2521
Houston, Texas 77252-2521
(Address of principal executive offices, including zip code)

(713) 759-3636
(Registrant’s telephone number, including area code)

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

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 twelve 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  o

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

     Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes  x  Noo  

     At June 30, 2002, the aggregate market value of the registrant’s Limited Partner Units held by non-affiliates was $1,355,892,023, which was computed using the average of the high and low sales prices of the Limited Partner Units on June 30, 2002.

     Limited Partner Units outstanding as of March 14, 2003: 53,812,697.

Documents Incorporated by Reference: None

TABLE OF CONTENTS

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Items 1 and 2. Business and Properties

General

     TEPPCO Partners, L.P. (the “Partnership”), a Delaware limited partnership, is a master limited partnership formed in March 1990. We operate through TE Products Pipeline Company, Limited Partnership (“TE Products”), TCTM, L.P. (“TCTM”) and TEPPCO Midstream Companies, L.P. (“TEPPCO Midstream”). Collectively, TE Products, TCTM and TEPPCO Midstream are referred to as the “Operating Partnerships.” Texas Eastern Products Pipeline Company, LLC (the “Company” or “General Partner”), a Delaware limited liability company, serves as our general partner and owns a 2% general partner interest in us. The General Partner is a wholly owned subsidiary of Duke Energy Field Services, LLC (“DEFS”), a joint venture between Duke Energy Corporation (“Duke Energy”) and ConocoPhillips. Duke Energy holds an approximate 70% interest in DEFS, and ConocoPhillips holds the remaining 30%. The Company, as general partner, performs all management and operating functions required for us, except for the management and operations of certain of the TEPPCO Midstream assets that are managed by DEFS on our behalf. We reimburse the General Partner for all reasonable direct and indirect expenses incurred in managing us. TEPPCO GP, Inc. (“TEPPCO GP”), our subsidiary, is the general partner of our Operating Partnerships. We hold a 99.999% limited partner interest in the Operating Partnerships and TEPPCO GP holds a 0.001% general partner interest.

     As used in this Report, “we,” “us,” “our,” and the “Partnership” means TEPPCO Partners, L.P. and, where the context requires, includes our subsidiaries.

     We operate and report in three business segments: transportation and storage of refined products, liquefied petroleum gases (“LPGs”) and petrochemicals (“Downstream Segment”); gathering, transportation, marketing and storage of crude oil; and distribution of lubrication oils and specialty chemicals (“Upstream Segment”); and gathering of natural gas, fractionation of natural gas liquids (“NGLs”) and transportation of NGLs (“Midstream Segment”). Our reportable segments offer different products and services and are managed separately because each requires different business strategies.

     Effective January 1, 2002, we realigned our three business segments to reflect our entry into the natural gas gathering business and the expanded scope of NGLs operations. We transferred the fractionation of NGLs, which was previously reflected as part of the Downstream Segment, to the Midstream Segment. The operation of NGL pipelines, which was previously reflected as part of the Upstream Segment, was also transferred to the Midstream Segment. We have adjusted our period-to-period comparisons to conform with the current presentation.

     Our interstate transportation operations, including rates charged to customers, are subject to regulations prescribed by the Federal Energy Regulatory Commission (“FERC”). Refined products, LPGs, petrochemicals, crude oil, NGLs and natural gas are referred to in this Report, collectively, as “petroleum products” or “products.”

     At December 31, 2002 and 2001, we had outstanding 53,809,597 and 40,450,000 Limited Partner Units and 3,916,547 and 3,916,547 Class B Limited Partner Units (“Class B Units”), respectively. All of the Class B Units were issued to Duke Energy in connection with an acquisition of assets initially acquired in the Upstream Segment in 1998. The Class B Units share in income and distributions on the same basis as the Limited Partner Units, but they are not listed on the New York Stock Exchange. The Class B Units may be converted into Limited Partner Units upon approval by the unitholders. We have the option to seek approval for the conversion of the Class B Units into Limited Partner Units; however, if the conversion is denied, Duke Energy, as holder of the Class B Units, will have the right to sell them to us at 95.5% of the 20-day average market closing price of the Limited Partner Units, as determined under our Partnership Agreement. As a result of this option, we have not included the Class B Units in partners’ capital at December 31, 2002 and 2001. Collectively, the Limited Partner Units and Class B Units are referred to as “Units.”

     Our strategy is to expand and improve service in our current markets, maintain the integrity of our pipeline systems and pursue growth initiatives that are balanced between internal projects and acquisitions. We intend to leverage the advantages inherent in our pipeline systems to maintain our status as a preferred provider in our

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market areas. We also intend to grow by acquiring assets, from both third parties and affiliates, which complement existing businesses or to establish new core businesses. We routinely evaluate opportunities to acquire assets and businesses that will complement existing operations with a view to increasing earnings and cash available for distribution to our unitholders. We may fund additional acquisitions with cash flow from operations, borrowings under existing credit facilities, the issuance of debt in the capital markets, the sale of additional Units, or any combination thereof.

Downstream Segment – Transportation and Storage of Refined Products, LPGs and Petrochemicals

   Operations

     We conduct business in our Downstream Segment through TE Products. TE Products owns and operates properties located in 13 states. These operations consist of interstate transportation, storage and terminaling of petroleum products; short-haul shuttle transportation of LPGs at the Mont Belvieu, Texas complex; intrastate transportation of petrochemicals and other ancillary services.

     As an interstate common carrier, our TE Products pipeline offers interstate transportation services, pursuant to tariffs filed with the FERC, to any shipper of refined petroleum products and LPGs who requests such services, provided that the products tendered for transportation satisfy the conditions and specifications contained in the applicable tariff. In addition to the revenues received by our pipeline system from our interstate tariffs, we also receive revenues from the shuttling of LPGs between refinery and petrochemical facilities on the upper Texas Gulf Coast and ancillary transportation, storage and marketing services at key points along the pipeline system. Substantially all of the petroleum products transported and stored in the pipeline system are owned by TE Products’ customers. Petroleum products are received at terminals located principally on the southern end of the pipeline system, stored, scheduled into the pipeline in accordance with customer nominations and shipped to delivery terminals for ultimate delivery to the final distributor (including gas stations and retail propane distribution centers) or to other pipelines. Pipelines are generally the lowest cost method for intermediate and long-haul overland transportation of petroleum products. The TE Products pipeline system is the only pipeline that transports LPGs from the upper Texas Gulf Coast to the Northeast.

     Our Downstream Segment depends in large part on the level of demand for refined petroleum products and LPGs in the geographic locations that we serve and the ability and willingness of customers having access to the pipeline system to supply such demand. We cannot predict the impact of future fuel conservation measures, alternate fuel requirements, governmental regulation or technological advances in fuel economy and energy-generation devices, all of which could reduce the demand for refined petroleum products and LPGs in the areas we serve.

     The following table lists the material properties and investments of and ownership percentages in the Downstream Segment assets as of December 31, 2002:

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   Centennial Pipeline Equity Investment

     In August 2000, TE Products entered into agreements with Panhandle Eastern Pipeline Company (“PEPL”), a subsidiary of CMS Energy Corporation, and Marathon Ashland Petroleum LLC (“Marathon”) to form Centennial Pipeline LLC (“Centennial”). Centennial owns an interstate refined petroleum products pipeline extending from the upper Texas Gulf Coast to Illinois. Centennial commenced operations in April 2002. Each participant originally owned a one-third interest in Centennial. Centennial constructed a 74-mile, 24-inch diameter pipeline connecting TE Products’ facility in Beaumont with an existing 720-mile, 26-inch diameter pipeline extending from Longville, Louisiana, to Bourbon, Illinois. The Centennial pipeline intersects TE Products’ existing mainline pipeline near Creal Springs, Illinois, where Centennial constructed a new two million barrel refined petroleum products storage terminal. Marathon operates the mainline Centennial pipeline and TE Products operates the Beaumont origination point and the Creal Springs terminal.

     TE Products’ interest in Centennial is not subject to any encumbrances from mortgages or other secured debt. Centennial has unsecured debt, one third of which, up to $50.0 million in principal, was originally guaranteed by each owner, including TE Products. During the third quarter of 2002, PEPL, one of the participants in Centennial, was downgraded by Moody’s and Standard & Poors to below investment grade, which resulted in PEPL being in default under its portion of the Centennial guaranty. Effective September 27, 2002, TE Products and Marathon increased their guaranteed amounts to one-half of the debt of Centennial, up to a maximum amount of $75.0 million each, to avoid a default on the Centennial debt. As compensation to TE Products and Marathon for providing their additional guarantees, PEPL was required to pay interest at a rate of 4% per annum to each of TE Products and Marathon on the portion of the additional guaranty that each had provided for PEPL. On February 10, 2003, TE Products and Marathon each acquired an additional interest in Centennial from PEPL for $20.0 million each, increasing their percentage ownerships in Centennial to 50% each. In connection with the acquisition of the additional interest in Centennial, the guaranty agreement between TE Products, Marathon and PEPL was terminated. TE Products’ guaranty of up to a maximum of $75.0 million of Centennial’s debt remains in effect.

     Through December 31, 2002, TE Products has contributed approximately $80.9 million for its one-third interest in Centennial. Excluding TE Products’ purchase of its additional ownership interest of 16.7% on February 10, 2003, we expect to contribute an additional $10.0 million to Centennial in 2003.

   Refined Products, LPGs and Petrochemical Pipeline Systems

     TE Products is one of the largest pipeline common carriers of refined petroleum products and LPGs in the United States. TE Products owns and operates an approximate 4,500-mile pipeline system (together with the receiving, storage and terminaling facilities mentioned below, the “Products Pipeline System”) extending from southeast Texas through the central and midwestern United States to the northeastern United States. The Products Pipeline System includes delivery terminals for outloading product to other pipelines, tank trucks, rail cars or barges, as well as substantial storage capacity at Mont Belvieu, the largest LPGs storage complex in the United States, and at other locations. TE Products also owns two marine receiving terminals, one near Beaumont and the other at Providence, Rhode Island. The Providence terminal is not physically connected to the Products Pipeline System. The Products Pipeline System also includes three parallel 12-inch diameter petrochemical pipelines between Mont Belvieu and Port Arthur, each approximately 70 miles in length.

     All properties comprising the Products Pipeline System are wholly owned by our subsidiaries and none are mortgaged or encumbered to secure funded debt. TE Products has guaranteed up to $75.0 million of Centennial’s unsecured debt (see above) and has also guaranteed our unsecured debt (see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Financial Condition and Liquidity).

     Products are transported in liquid form from the upper Texas Gulf Coast through two parallel underground pipelines that extend to Seymour, Indiana. From Seymour, segments of the Products Pipeline System extend to the Chicago, Illinois; Lima, Ohio; Selkirk, New York; and Philadelphia, Pennsylvania, areas. The Products Pipeline System east of Todhunter, Ohio, is dedicated solely to LPGs transportation and storage services.

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     The Products Pipeline System includes 29 storage facilities with an aggregate storage capacity of 17 million barrels of refined petroleum products and 37 million barrels of LPGs, including storage capacity leased to outside parties. The Products Pipeline System makes deliveries to customers at 53 locations including 18 company owned truck racks, rail car facilities and marine facilities. Deliveries to other pipelines occur at various facilities owned by TE Products or by third parties.

     The Products Pipeline System is comprised of a 20-inch diameter line extending in a generally northeasterly direction from Baytown, Texas (located approximately 30 miles east of Houston), to a point in southwest Ohio near Lebanon and Todhunter. A second line, which also originates at Baytown, is 16 inches in diameter until it reaches Beaumont, at which point it reduces to a 14-inch diameter line. This second line extends along the same path as the 20-inch diameter line to the Products Pipeline System’s terminal in El Dorado, Arkansas, before continuing as a 16-inch diameter line to Seymour. The Products Pipeline System also has smaller diameter lines that extend laterally from El Dorado to Helena, Arkansas, from Tyler, Texas, to El Dorado and from McRae, Arkansas, to West Memphis, Arkansas. The line from El Dorado to Helena has a 10-inch diameter. The line from Tyler to El Dorado varies in diameter from 8 inches to 10 inches. The line from McRae to West Memphis has a 12-inch diameter. The Products Pipeline System also includes a 14-inch diameter line from Seymour to Chicago, Illinois, and a 10-inch diameter line running from Lebanon to Lima, Ohio. This 10-inch diameter pipeline connects to the Buckeye Pipe Line Company system that serves, among others, markets in Michigan and eastern Ohio. The Products Pipeline System also has a 6-inch diameter pipeline connection to the Greater Cincinnati/Northern Kentucky International Airport and an 8-inch diameter pipeline connection to the George Bush Intercontinental Airport in Houston. In addition, there are numerous smaller diameter lines associated with the gathering and distribution system.

     The Products Pipeline System continues eastward from Todhunter, Ohio, to Greensburg, Pennsylvania, at which point it branches into two segments, one ending in Selkirk, New York (near Albany), and the other ending at Marcus Hook, Pennsylvania (near Philadelphia). The Products Pipeline System east of Todhunter and ending in Selkirk is an 8-inch diameter line, and the line starting at Greensburg and ending at Marcus Hook varies in diameter from 6 inches to 8 inches.

     In November 2002, we announced a project to expand our delivery capacity of LPGs. The expansion will increase delivery capability to the Northeast during the peak winter months by approximately one million barrels. The expansion, which is scheduled for completion during the third quarter of 2003, consists of the construction of three new pump stations located between Middletown, Ohio, and Greenburg, Pennsylvania. In addition to the Northeast expansion, we completed our Princeton, Indiana, LPGs truck rack upgrade in December 2002, and we will add an additional 3.2 million barrels of brine storage capability at Mont Belvieu by the summer of 2003.

     TE Products also owns three 12-inch diameter common carrier petrochemical pipelines between Mont Belvieu and Port Arthur, which were completed in the fourth quarter of 2000. Each of these pipelines is approximately 70 miles in length. The pipelines transport ethylene, propylene and natural gasoline. We entered into a 20-year agreement with a major petrochemical producer for guaranteed throughput commitments. During the years ended December 31, 2002 and 2001, and the two month period ended December 31, 2000, we recognized $11.9 million, $10.7 million and $1.8 million, respectively, of revenue under the throughput and deficiency contract. We began transporting product through these pipelines in September 2001.

     We believe that our Products Pipeline System is in compliance with applicable federal, state and local laws and regulations and accepted industry standards and practices. We perform regular maintenance on all the facilities of the Products Pipeline System and have an ongoing process of inspecting the Products Pipeline System and making repairs and replacements when necessary or appropriate. In addition, we conduct periodic air patrols of the Products Pipeline System to monitor pipeline integrity and third-party right of way encroachments.

   Major Business Sector Markets

     Our major operations in the Downstream Segment consist of the transportation, storage and terminaling of refined petroleum products and LPGs along our mainline system, and the storage and short-haul transportation of

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LPGs associated with our Mont Belvieu LPG operations. Product deliveries, in millions of barrels (MMBbls) on a regional basis, for the years ended December 31, 2002, 2001 and 2000 were as follows:

     The mix of products delivered varies seasonally. Gasoline demand is generally stronger in the spring and summer months and LPGs demand is generally stronger in the fall and winter months. Weather and economic conditions in the geographic areas served by our Products Pipeline System also affect the demand for, and the mix of, the products delivered.

     Refined products and LPGs deliveries for the years ended December 31, 2002, 2001 and 2000 were as follows:

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(2)

Methyl tertiary butyl ether (“MTBE”). Effective April 22, 2001, we ceased transportation of MTBE through our Products Pipeline System.

   Refined Products Mainline Transportation

     Our Products Pipeline System transports refined petroleum products from the upper Texas Gulf Coast, eastern Texas and southern Arkansas to the Central and Midwest regions of the United States with deliveries in Texas, Louisiana, Arkansas, Missouri, Illinois, Kentucky, Indiana and Ohio. At these points, refined petroleum products are delivered to terminals owned by TE Products, connecting pipelines and customer-owned terminals.

     The volume of refined petroleum products transported by our Products Pipeline System is directly affected by the demand for such products in the geographic regions the system serves. This market demand varies based upon the different end uses to which the refined products deliveries are applied. Demand for gasoline, which accounted for approximately 59% of the volume of refined products transported through the Products Pipeline System during 2002, depends upon price, prevailing economic conditions and demographic changes in the markets that we serve. Demand for refined products used in agricultural operations is affected by weather conditions, government policy and crop prices. Demand for jet fuel depends upon prevailing economic conditions and military usage.

     Market prices for refined petroleum products affect the demand in the markets served by our Downstream Segment. Therefore, quantities and mix of products transported may vary. Transportation tariffs of refined petroleum products vary among specific product types. As a result, market price volatility may affect transportation volumes and revenues from period to period.

   LPGs Mainline Transportation

     Our Products Pipeline System transports LPGs from the upper Texas Gulf Coast to the Central, Midwest and Northeast regions of the United States. The Products Pipeline System east of Todhunter, Ohio, is devoted solely to the transportation of LPGs. Because propane demand is generally sensitive to weather in the winter months, year-to-year variations of propane deliveries have occurred and will likely continue to occur.

     Our ability in the Downstream Segment to serve propane markets in the Northeast is enhanced by our marine import terminal at Providence. This facility includes a 400,000-barrel refrigerated storage tank along with ship unloading and truck loading facilities. Effective May 2001, we entered into an agreement with DEFS to commit sole utilization of the Providence terminal to DEFS. We operate the terminal and provide propane loading services to DEFS. During the years ended December 31, 2002 and 2001, revenues of $2.3 million and $1.5 million from DEFS, respectively, were recognized pursuant to this agreement.

   Mont Belvieu LPGs Storage and Pipeline Shuttle

     A key aspect of the Products Pipeline System’s LPGs business is its storage and pipeline asset base in the Mont Belvieu complex serving the fractionation, refining and petrochemical industries. The complex is the largest of its kind in the United States and provides substantial capacity and flexibility in the transportation, terminaling and storage of NGLs, LPGs, petrochemicals and olefins.

     Our Downstream Segment has approximately 37 million barrels of LPGs storage capacity, including storage capacity leased to outside parties, at the Mont Belvieu complex. The Downstream Segment includes a Mont Belvieu short-haul transportation shuttle system, consisting of a complex system of pipelines and interconnects, that ties Mont Belvieu to virtually every refinery and petrochemical facility on the upper Texas Gulf Coast.

     In February 2000, we entered into a joint marketing and development alliance with Louis Dreyfus Plastics Corporation, now known as Louis Dreyfus Energy Services, L.P. (“Louis Dreyfus”), in which our Mont Belvieu LPGs storage and transportation shuttle system services were jointly marketed by Louis Dreyfus and TE Products.

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The purpose of the alliance was to expand services to the upper Texas Gulf Coast energy marketplace by increasing pipeline throughput and the mix of products handled through the existing system and establishing new receipt and delivery connections. The alliance was a service-oriented, fee-based venture with no commodity trading activity. TE Products operated the facilities for the alliance. Under the alliance, Louis Dreyfus invested $6.1 million for expansion projects at Mont Belvieu. The alliance also stipulated that if certain earnings thresholds were achieved, a partnership between TE Products and Louis Dreyfus was to be created effective January 1, 2003. All terms and earnings thresholds have been met; therefore, we will be contributing our Mont Belvieu assets to the newly formed partnership. The economic terms of the partnership are the same as those under the joint development and marketing alliance. TE Products will continue to operate the facilities for the partnership. The net book value of the Mont Belvieu assets and liabilities that we are contributing to the partnership is approximately $68.2 million. Our interest in the partnership will be accounted for as an equity investment.

   Other Operating Revenues

     Our Downstream Segment also earns revenue from terminaling activities and other ancillary services associated with the transportation and storage of refined petroleum products and LPGs. From time to time, we sell excess product inventory. Other operating revenues include revenues related to the intrastate transportation of petrochemicals under a throughput and deficiency contract.

   Customers

     Our customers for the transportation of refined petroleum products include major integrated oil companies, independent oil companies, the airline industry and wholesalers. End markets for these deliveries are primarily retail service stations, truck stops, agricultural enterprises, refineries, and military and commercial jet fuel users.

     Propane customers include wholesalers and retailers who, in turn, sell to commercial, industrial, agricultural and residential heating customers, as well as utilities who use propane as a back-up fuel source. Refineries constitute our major customers for butane and isobutane, which are used as a blend stock for gasolines and as a feed stock for alkylation units, respectively.

     At December 31, 2002, our Downstream Segment had approximately 150 customers. Transportation revenues (and percentage of total revenues) attributable to the top 10 customers were $101.6 million (51%), $115.0 million (44%) and $102.0 million (45%) for the years ended December 31, 2002, 2001 and 2000, respectively. During the year ended December 31, 2002, no single customer accounted for 10% or more of the Downstream Segment’s revenues.

     We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures. We utilize letters of credit and guarantees for certain of our receivables. However, these procedures and policies do not fully eliminate customer credit risk. During the year ended December 31, 2002, several customers of the Downstream Segment filed for bankruptcy protection. During the year ended December 31, 2002, we expensed approximately $0.7 million of uncollectible receivables of the Downstream Segment.

   Competition

     The Products Pipeline System conducts operations without the benefit of exclusive franchises from government entities. Interstate common carrier transportation services are provided through the system pursuant to tariffs filed with the FERC.

     Because pipelines are generally the lowest cost method for intermediate and long-haul overland movement of refined petroleum products and LPGs, the Products Pipeline System’s most significant competitors (other than indigenous production in its markets) are pipelines in the areas where the Products Pipeline System delivers products. Competition among common carrier pipelines is based primarily on transportation charges, quality of customer service and proximity to end users. We believe our Downstream Segment is competitive with other

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pipelines serving the same markets; however, comparison of different pipelines is difficult due to varying product mix and operations.

     Trucks, barges and railroads competitively deliver products in some of the areas served by the Products Pipeline System. Trucking costs, however, render that mode of transportation less competitive for longer hauls or larger volumes. Barge fees for the transportation of refined products are generally lower than TE Products’ tariffs. We face competition from rail movements of LPGs from Sarnia, Ontario, Canada, and waterborne imports into New Hampshire.

Upstream Segment – Gathering, Transportation, Marketing and Storage of Crude Oil

   Operations

     We conduct business in our Upstream Segment through TCTM and certain of its wholly owned subsidiaries, which gather, transport, market and store crude oil, and distribute lubrication oils and specialty chemicals, principally in Oklahoma, Texas and the Rocky Mountain region. We commenced our Upstream Segment business in connection with the acquisition of assets from DEFS in November 1998. Our Upstream Segment utilizes its asset base to aggregate crude oil and provide transportation and specialized services to its regional customers. Our Upstream Segment purchases crude oil from various producers and operators at the wellhead and makes bulk purchases of crude oil at pipeline and terminal facilities. The crude oil is then sold to refiners and other customers. The Upstream Segment transports crude oil through equity owned pipelines, its trucking operations and third party pipelines.

     Margins in the Upstream Segment are calculated as revenues generated from the sale of crude oil and lubrication oil, and transportation of crude oil, less the costs of purchases of crude oil and lubrication oil. Margins are a more meaningful measure of financial performance than operating revenues and operating expenses due to the significant fluctuations in revenues and expenses caused by variations in the level of marketing activity and prices for products marketed (see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Upstream Segment for margin and volume information).

     TCTM purchases crude oil and simultaneously establishes a margin by selling crude oil for physical delivery to third party users. We seek to maintain a balanced marketing position until we make physical delivery of the crude oil, thereby minimizing or eliminating our exposure to price fluctuations occurring after the initial purchase. However, certain basis risks, which are the risks that price relationships between delivery points, classes of products or delivery periods will change, cannot be completely hedged or eliminated. We make limited use of commodity derivative products for the purpose of hedging price changes. Risk management policies have been established by the Risk Management Committee to monitor and control market risks. The Risk Management Committee is comprised, in part, of senior executives of the Company. We had no commodity derivative contracts outstanding at December 31, 2002.

     Product deliveries on TCTM’s 100% owned pipeline systems and undivided joint interest pipelines for the years ended December 31, 2002, 2001 and 2000, were as follows (in millions):

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   Properties

     The major crude oil pipelines and pipeline systems of our Upstream Segment are set forth in the following table, which include several pipelines owned jointly with other industry participants or producers:

None of these pipelines or systems are mortgaged or encumbered to secure funded debt. TCTM has provided guarantees of our unsecured debt (see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations).

     The majority of the Red River System crude oil is delivered to Cushing, Oklahoma, via third party pipelines or to two local refineries. The majority of the crude oil on the South Texas System is delivered on a tariff basis to Houston area refineries. The West Texas Trunk System is a fee based system which connects gathering systems to TCTM’s Midland, Texas terminal. Other crude oil assets, located primarily in Texas and Oklahoma, consist of 310 miles of pipeline and 295,000 barrels of storage capacity.

     Under the terms of the Rancho System operating agreement, the operating agreement will expire during the first quarter of 2003. Upon expiration of the operating agreement, the Rancho System will cease operations in crude oil service from West Texas to Houston, Texas. The owners of the Rancho System are currently pursuing future opportunities for use of the system.

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   Our Interest in Seaway Crude Pipeline

     Seaway Crude Pipeline Company (“Seaway”) is a partnership between a subsidiary of TCTM, TEPPCO Seaway, L.P. (“TEPPCO Seaway”), and ConocoPhillips. TCTM acquired its 50% ownership interest in Seaway on July 20, 2000, as part of its purchase of ARCO Pipe Line Company (“ARCO”), a wholly owned subsidiary of Atlantic Richfield Company, and transferred the investment to TEPPCO Seaway. We assumed ARCO’s role as operator of this pipeline. The 30-inch diameter, 500-mile pipeline transports crude oil from the U.S. Gulf Coast to Cushing, a central crude distribution point for the central United States and a delivery point for the New York Mercantile Exchange (“NYMEX”). The Freeport, Texas, marine terminal is the origin point for the 30-inch diameter crude pipeline. Three large diameter lines carry crude oil from the Freeport marine terminal to the adjacent Jones Creek Tank Farm, which has six tanks capable of handling approximately 2.6 million barrels of crude oil. A crude oil marine terminal facility at Texas City, Texas, is used to supply refineries in the Houston area. Two pipelines connect the Texas City marine terminal to tank farms in Texas City and Galena Park, Texas, where there are seven tanks with a combined capacity of approximately 3 million barrels. Seaway has the capability to provide marine terminaling and crude oil storage services for all Houston area refineries.

     The Seaway partnership agreement provides for varying participation ratios throughout the life of Seaway. From July 20, 2000, through May 2002, we received 80% of revenue and expense of Seaway. From June 2002 until May 2006, we will receive 60% of revenue and expense of Seaway. Thereafter, we will receive 40% of revenue and expense of Seaway. For the year ended December 31, 2002, our portion of equity earnings on a pro-rated basis averaged approximately 67%.

   Line Transfers, Pumpovers and Other

     Our Upstream Segment provides trade documentation services to its customers, primarily at Cushing and Midland. TCTM documents the transfer of crude oil in its terminal facilities between contracting buyers and sellers. This line transfer documentation service is related to the trading activity by TCTM’s customers of NYMEX open-interest crude oil contracts and other physical trading activity. This service provides a documented record of receipts, deliveries and transactions to each customer, including confirmation of trade matches, inventory management and scheduled movements. Line transfer revenues are included as part of other operating revenues in our consolidated statements of income.

     The line transfer services also attract physical barrels to TCTM’s facilities for final delivery to the ultimate owner. A pumpover occurs when the last title transfer is executed and the physical barrels are delivered out of TCTM’s custody. TCTM owns and operates storage facilities primarily in Midland and Cushing with an operational capacity of approximately 1.1 million barrels to facilitate the pumpover business. Revenues from pumpover services are included as part of crude oil transportation revenues in our consolidated statements of income and represents the crude oil terminaling component of margin. The line transfer and pumpover operations were acquired as part of our purchase of ARCO in July 2000.

     Through its subsidiary, Lubrication Services, L.P. (“LSI”), TCTM distributes lubrication oils and specialty chemicals to natural gas pipelines, gas processors and industrial and commercial accounts. LSI’s distribution networks are located in Colorado, Wyoming, Oklahoma, Kansas, New Mexico, Texas, and Louisiana.

   Customers

     TCTM purchases crude oil primarily from major integrated oil companies and independent oil producers. Crude oil sales are primarily to major integrated oil companies and independent refiners. Gross sales revenue of the Upstream Segment attributable to the top 10 customers was $1.9 billion (66%) for the year ended December 31, 2002, of which Valero Energy Corp. (“Valero”) accounted for 18%. For the year ended December 31, 2001, gross sales revenue attributable to the top 10 customers was $2.0 billion (61%), of which Valero accounted for 16%. For the year ended December 31, 2000, gross sales revenue attributable to the top 10 customers was $1.6 billion (56%), of which Valero accounted for 13%.

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   Competition

     The most significant competitors in pipeline operations in our Upstream Segment are primarily common carrier and proprietary pipelines owned and operated by major oil companies, large independent pipeline companies and other companies in the areas where our pipeline systems deliver crude oil. Competition among common carrier pipelines is based primarily on posted tariffs, quality of customer service, knowledge of products and markets, and proximity to refineries and connecting pipelines. The crude oil gathering and marketing business is characterized by thin margins and intense competition for supplies of crude oil at the wellhead. Declines in domestic crude oil production have intensified competition among gatherers and marketers.

     A significant portion of the growth in our Upstream Segment has occurred through acquisitions of pipeline gathering systems. Our acquisitions in this Segment have provided increased efficiencies for the gathering and transportation of crude oil with our existing pipeline systems as well as expansion into new market areas. We experience competition from other gatherers and marketers in bidding for potential acquisitions. Within the past few years, the number of companies involved in the gathering of crude oil in the United States has decreased as a result of business consolidations and bankruptcies, which may decrease the number of potential acquisitions of crude gathering systems available to us.

   Credit Policies and Procedures

     As crude oil or lubrication oils are marketed, we must determine the amount, if any, of credit to be extended to any given customer, particularly in our Upstream Segment, where transported volumes are typically sold rather than transported for a fee. Due to the nature of individual sales transactions, risk of non-payment and non-performance by customers is a major consideration in our business. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures. We utilize letters of credit and guarantees for certain of our receivables. However, these procedures and policies do not fully eliminate customer credit risk. During the years ended December 31, 2001 and 2000, no reserves were necessary for uncollectible receivables of the Upstream Segment. During the year ended December 31, 2002, we expensed approximately $0.2 million of uncollectible receivables of the Upstream Segment.

Midstream Segment – Gathering of Natural Gas, Fractionation of NGLs and Transportation of NGLs

     We conduct business in our Midstream Segment through the following:

	•		TEPPCO Colorado, LLC (“TEPPCO Colorado”), which fractionates NGLs,
	•		TEPPCO Midstream Companies, LLC, and its wholly owned subsidiaries, Chaparral Pipeline Company, L.P. and Quanah Pipeline Company, L.P. (collectively referred to as “Chaparral” or “Chaparral NGL system”), Dean Pipeline Company, L.P., Panola Pipeline Company, L.P. and Wilcox Pipeline Company, L.P., which transport NGLs, and
	•		Jonah Gas Gathering Company (“Jonah”) and Val Verde Gas Gathering Company, L.P. (“Val Verde”), which gather natural gas.

     On December 31, 2000, we completed an acquisition of pipeline assets from DEFS for $91.7 million, which included $0.7 million of acquisition related costs. The purchase included two NGL pipelines in East Texas: the Panola Pipeline, a pipeline from Carthage, Texas, to Mont Belvieu and the San Jacinto Pipeline, a pipeline from Carthage to Longview, Texas. The pipelines originate at DEFS’ East Texas Plant Complex in Panola County, Texas. The acquisition of the assets was accounted for under the purchase method of accounting. Accordingly, the results of operations of the acquisition were included in our consolidated financial statements in the fourth quarter of 2000.

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     Our subsidiaries acquired all of the partnership interests of Jonah from Alberta Energy Company, effective September 30, 2001, for $359.8 million. We paid an additional $7.3 million on February 4, 2002, for final purchase price adjustments related primarily to construction projects in progress at the time of closing. The acquisition was accounted for under the purchase method of accounting. Accordingly, the results of operations of the acquisition were included in our consolidated financial statements in the fourth quarter of 2001. Under a contractual agreement, DEFS manages and operates the Jonah assets on our behalf.

     In connection with the acquisition of Jonah, we assumed responsibility for the completion of an ongoing expansion of the Jonah Gas Gathering System at a cost of approximately $25.0 million. The expansion, which was completed in March 2002, increased the capacity of the Jonah system by 62%, from approximately 450 million cubic feet per day (“MMcf/day”), to approximately 730 MMcf/day. In October 2002, additional expansion projects were completed, which increased the capacity of the Jonah system from 730 MMcf/day to approximately 880 MMcf/day. These projects were completed at a combined cost of approximately $45.0 million.

     In February 2002, a producer on the Jonah system sent a letter to Alberta Energy Company implying that as a result of our acquisition of the Jonah system, it may have a right to acquire all or a portion of the assets comprising the Jonah system pursuant to an alleged right of first refusal in a gas gathering agreement between the producer and Jonah. Subsidiaries of Alberta Energy Company have agreed to indemnify us against losses resulting from any breach of representations concerning the absence of third party rights in connection with our acquisition of the entity that owns the Jonah system. We believe that we have adequate legal defenses if the producer should assert a claim, and we also believe that no right of first refusal on any of the underlying Jonah system assets has been triggered.

     On March 1, 2002, we completed the purchase of the Chaparral NGL system for $132.4 million from Diamond-Koch II, L.P. and Diamond-Koch III, L.P., including acquisition related costs of approximately $0.4 million. The Chaparral NGL system extends from West Texas and New Mexico to Mont Belvieu. The pipeline delivers NGLs to fractionators and to our existing storage in Mont Belvieu. We accounted for the acquisition of the assets under the purchase method of accounting. Accordingly, the results of the acquisition have been included in our consolidated financial statements from March 1, 2002. Under a contractual agreement, DEFS manages and operates the Chaparral NGL system assets on our behalf.

     On June 30, 2002, we completed the purchase of the Val Verde Gathering System for $444.2 million from Burlington Resources Gathering Inc., a subsidiary of Burlington Resources Inc., including acquisition related costs of approximately $1.2 million. The Val Verde system gathers coal bed methane (“CBM”) from the Fruitland Coal Formation of the San Juan Basin in New Mexico and Colorado. The system is one of the largest CBM gathering and treating facilities in the United States. We accounted for the acquisition of the assets under the purchase method of accounting. Accordingly, the results of the acquisition have been included in our consolidated financial statements from June 30, 2002. Under a contractual agreement, DEFS manages and operates the Val Verde assets on our behalf.

     Revenues of our Midstream Segment are earned from fractionation of NGLs in Colorado, transportation of NGLs and gathering fees based on the volume and pressure of natural gas gathered, and from sales of condensate on the Jonah system. We do not take title to the natural gas gathered, NGLs transported or NGLs fractionated. Accordingly, the results of operations of the Midstream Segment are not directly affected by changes in the prices of natural gas or NGLs. TEPPCO Midstream has multiple long-term contracts with producers connected to the Jonah and Val Verde systems. We cannot influence or control the operation, development or production levels of the gas fields served by the Jonah and Val Verde systems, which may be affected by price and price volatility, market demand, depletion rates of existing wells and changes in laws and regulations.

     None of these pipelines or systems are mortgaged or encumbered to secure funded debt. TEPPCO Midstream, Jonah and Val Verde have each provided guarantees of our unsecured debt (see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations).

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     Volume information for the years ended December 31, 2002, 2001 and 2000, is presented below:

   The Jonah Gas Gathering System

     The Jonah system consists of over 400 miles of pipelines ranging in size from four inches to 24 inches in diameter, four compressor stations with an aggregate of approximately 40,000 horsepower and related metering facilities. Gas gathered on the Jonah system is collected from over 450 producing wells in the Green River Basin in southwestern Wyoming, which is one of the most prolific natural gas basins in the United States. A component of the system is a processing facility that extracts condensate prior to delivery of natural gas to DEFS’ Overland Trail Transmission system and Questar. Gas is also delivered to gas processing facilities owned by others. From these processing facilities, the natural gas is delivered to several interstate pipeline systems located in the region for transportation to end-use markets throughout the Midwest, the West Coast and the Rocky Mountain regions. Interstate pipelines in the region include Kern River, Northwest, Colorado Interstate Gas and Questar.

   The Val Verde Gas Gathering System

     The Val Verde Gas Gathering System consists of approximately 360 miles of pipeline ranging in size from four inches to 36 inches in diameter, 14 compressor stations operating over 93,000 horsepower of compression and a large amine treating facility for the removal of carbon dioxide. The system has a pipeline capacity of approximately one billion cubic feet of gas per day. The Val Verde Gas Gathering System gathers CBM from the Fruitland Coal Formation of the San Juan Basin in New Mexico and Colorado, a long-term source of natural gas supply in North America. The basin is one of the most prolific sources of CBM and also contains significant conventional gas reserves. The system is one of the largest CBM gathering and treating facilities in the United States, gathering CBM from more than 540 separate wells throughout northern New Mexico and southern Colorado, and provides gathering and treating services pursuant to 60 long-term contracts with approximately 40 different natural gas producers in the San Juan Basin. Gas transported on the Val Verde system is delivered to several interstate pipeline systems serving the western United States, as well as local New Mexico markets.

   NGL Transportation

     The NGL pipelines of the Midstream Segment are located along the Texas Gulf Coast and along southeastern New Mexico and West Texas to Mont Belvieu. They are all wholly owned and operated by either our subsidiaries or DEFS. Information concerning these NGL pipelines is set forth in the following table:

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None of these pipelines are mortgaged or encumbered to secure funded debt.

     The Wilcox NGL Pipeline transports NGLs for DEFS from two of their natural gas processing plants. The Wilcox NGL Pipeline is currently supported by a throughput agreement with DEFS through 2005. The fees paid to us by DEFS under the agreement totaled $1.2 million, $1.2 million and $1.1 million for the years ended December 31, 2002, 2001 and 2000, respectively. The Panola Pipeline and San Jacinto Pipeline were purchased on December 31, 2000, from DEFS for $91.7 million and originate at DEFS’ East Texas Plant Complex in Panola County, Texas. For the years ended December 31, 2002 and 2001, revenues recognized included $12.0 million and $13.9 million, respectively, from a subsidiary of DEFS for NGL transportation fees on the Panola and San Jacinto Pipelines.

   Customers

     The Midstream Segment’s customers for the gathering of natural gas include major integrated oil and gas companies and large to medium-sized independent producers. Natural gas from Jonah and Val Verde is delivered into major interstate gas pipelines for delivery primarily to markets along the West Coast. NGL sales are primarily to major integrated oil and gas companies and independent refiners.

     At December 31, 2002, the Midstream Segment had approximately 70 customers. Revenues attributable to the top 10 customers were $117.5 million (85%) for the year ended December 31, 2002, of which DEFS, EnCana Corporation (formerly Alberta Energy Company), and Burlington Resources Inc. accounted for approximately 21%, 19% and 15% of revenues of the Midstream Segment, respectively. At December 31, 2001, the Midstream Segment had 16 customers. Revenues attributable to the top 10 customers were $37.0 million (99%) for the year ended December 31, 2001, of which DEFS, Enron Corp. and Alberta Energy Company accounted for approximately 61%, 13% and 11% of revenues of the Midstream Segment, respectively. At December 31, 2000, the Midstream Segment had three customers. Revenues attributable to the three customers were $14.5 million, of which DEFS and Enron Corp. accounted for 60% and 39% of revenues of the Midstream Segment, respectively.

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     We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures. We utilize letters of credit and guarantees for certain of our receivables. However, these procedures and policies do not fully eliminate customer credit risk. In December 2001, we expensed approximately $4.3 million of uncollected transportation deficiency revenues due to the bankruptcy of Enron Corp. and certain of its subsidiaries in December 2001.

   Competition

     The most significant competition for the NGL pipeline operations of our Midstream Segment comes primarily from proprietary pipelines owned and operated by major oil and gas companies or other large independent pipeline companies with contiguous operations. The ability to compete in the NGL pipeline area is based primarily on the quality of customer service, knowledge of products and markets and market-responsive transportation rates.

     The majority of the recent growth in the Midstream Segment is due to the acquisition of Jonah in Wyoming and Val Verde in New Mexico and Colorado. Typically new supplies of natural gas are necessary to offset the natural declines in production from wells connected to any gathering system. The Jonah and Pinedale fields that are the focus of our Jonah system in Wyoming are both relatively young producing areas, characterized by long-lived production profiles and many years of significant growth potential ahead. We expect to aggressively market this system by obtaining contracts to gather additional natural gas supplies.

     Competition in the natural gas gathering operations of our Midstream Segment is based in large part on reputation, efficiency, system reliability, system capacity and market responsive pricing arrangements. Key competitors in the gathering and treating segment include independent gas gatherers as well as other major integrated energy companies. Alternate gathering facilities may be available to producers served by our Midstream Segment, and those producers could also elect to construct proprietary gas gathering systems. Success in the gas gathering and treating business segment is based primarily on a thorough understanding of the needs of the producers served, as well as a strong commitment to providing responsive, high-quality customer service.

     If the production ultimately delivered to one of our gathering systems declines, revenues from such operations would also be adversely affected. If such declines are sustained or substantial, then we could experience a material adverse effect on our financial position, results of operations or cash flows.

Title to Properties

     We believe we have satisfactory title to all of our assets. The properties are subject to liabilities in certain cases, such as customary interests generally contracted in connection with acquisition of the properties, liens for taxes not yet due, easements, restrictions, and other minor encumbrances. In February 2002, a producer on the Jonah system sent a letter to Alberta Energy Company implying that as a result of our acquisition of the Jonah system, it may have a right to acquire all or a portion of the assets comprising the Jonah system. See Items 1 and 2 Business and Properties, “Midstream Segment – Gathering of Natural Gas, Fractionation of NGLs and Transportation of NGLs” for a more detailed discussion of the matter. We believe none of these liabilities materially affect the value of our properties or our interest in the properties or will materially interfere with their use in the operation of our business.

Capital Expenditures

     Capital expenditures, excluding acquisitions, totaled $133.4 million for the year ended December 31, 2002. Revenue generating projects include those projects which expand service into new markets or expand capacity into current markets. Capital expenditures to sustain existing operations include projects required by regulatory agencies or required life-cycle replacements. System upgrade projects improve operational efficiencies or reduce cost. We capitalize interest costs incurred during the period that construction is in progress. The following table identifies capital expenditures by segment for the year ended December 31, 2002 (in millions):

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     Revenue generating capital spending by the Downstream Segment included $24.9 million used to expand our capacity to support Centennial’s throughput with additional tankage and system capacity improvements at our Beaumont terminal, and additional receipt connections and pumping capacity in the Houston Ship Channel area. An additional $3.2 million was used to construct connections and related facilities for our petrochemical pipeline system extending from Mont Belvieu to Port Arthur. We also spent approximately $3.7 million to expand capacity at truck loading facilities at Princeton, Indiana, and Lebanon, Ohio. Revenue generating capital spending by the Midstream Segment related primarily to a $45.0 million expansion of the Jonah system to increase its capacity. The remaining revenue generating capital spending of the Midstream Segment was used to construct well connections.

     We estimate that capital expenditures, excluding acquisitions, for 2003 will be approximately $55.0 million (which includes $3.6 million of capitalized interest). We expect to use approximately $18.4 million for revenue generating projects. Capital spending on revenue generating projects will include approximately $7.5 million for the expansion of our pumping capacity of LPGs into the Northeast markets, approximately $1.9 million for expansion of our Downstream Segment’s deliverability capacity, $4.0 million to expand Upstream Segment facilities and approximately $5.0 million for the expansion of Midstream assets. We expect to spend approximately $26.0 million to sustain existing operations, of which approximately $19.3 million will be for Downstream Segment pipeline projects, including the replacement of storage tanks, pipeline rehabilitation projects to comply with regulations enacted by the United States Department of Transportation Office of Pipeline Safety (“OPS”) and the installation of replacement electrical distribution facilities at our Mont Belvieu facilities, $4.8 million for upgrades of our Upstream Segment and $1.9 million of capital expenditures to sustain existing operations on the Midstream Segment. An additional $7.0 million will be expended on system upgrade projects among all of our business segments. We continually review and evaluate potential capital improvements and expansions that would be complementary to our present business segments. These expenditures can vary greatly depending on the magnitude of our transactions. We may finance capital expenditures through internally generated funds, debt or the issuance of additional equity.

Regulation

     Our interstate common carrier pipeline operations are subject to rate regulation by the FERC under the provisions of the Interstate Commerce Act (“ICA”), the Energy Policy Act of 1992 (“Act”) and rules and orders promulgated pursuant thereto. FERC regulation requires that interstate refined petroleum products and crude oil pipeline rates be posted publicly and that these rates be “just and reasonable” and nondiscriminatory.

     Rates of interstate refined petroleum products and crude oil pipeline companies, like us, are currently regulated by the FERC primarily through an index methodology, which allows a pipeline to change its rates based on the change from year to year in the Producer Price Index for finished goods (“PPI Index”). Effective as of February 24, 2003, FERC Order on Remand modified the PPI Index from PPI – 1% to PPI. In the alternative, interstate refined petroleum products and crude oil pipeline companies may elect to support rate filings by using a cost-of-service methodology, competitive market showings (“Market-Based Rates”) or agreements between shippers and refined petroleum products and crude oil pipeline companies that the rate is acceptable (“Settlement Rates”).

     On May 11, 1999, TE Products filed an application with the FERC requesting permission to charge Market-Based Rates for substantially all refined products transportation tariffs. On July 31, 2000, the FERC issued an order granting TE Products Market-Based Rates in certain markets and set for hearing TE Products’ application for Market-Based Rates in certain destination markets and origin markets. After the matter was set for hearing, TE Products and the protesting shippers entered into a settlement agreement resolving their respective differences. On

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April 25, 2001, the FERC issued an order approving the offer of settlement. As a result of the settlement, TE Products recognized approximately $1.7 million of previously deferred transportation revenue in the second quarter of 2001. As a part of the settlement, TE Products withdrew the application for Market-Based Rates to the Little Rock, Arkansas, and Arcadia and Shreveport-Arcadia, Louisiana, destination markets, which are currently subject to the PPI Index. As a result, we made refunds of approximately $1.0 million in the third quarter of 2001 for those destination markets.

     In a 1995 decision involving an unrelated pipeline limited partnership, the FERC partially disallowed the inclusion of income taxes in that partnership’s cost of service. In another FERC proceeding involving a different pipeline limited partnership, the FERC held that the pipeline limited partnership may not claim an income tax allowance for income attributable to non-corporate limited partners, both individuals and other entities. These FERC decisions do not affect our current rates and rate structure because we do not use the cost of service methodology to support our rates. However, the FERC decisions might become relevant to us should we (i) elect in the future to use the cost-of-service methodology or (ii) be required to use such methodology to defend initial rates or our indexed rates against a shipper protest alleging that an indexed rate increase substantially exceeds actual cost increases. Should these circumstances arise, there can be no assurance with respect to the effect of these precedents on our rates in view of the uncertainties involved in this issue.

     The natural gas gathering operations of the Jonah and Val Verde systems are exempt from FERC regulation under the Natural Gas Act of 1938 since they are intrastate gas gathering systems rather than interstate transmission pipelines. However, FERC regulation still significantly affects the Midstream Segment, directly or indirectly, by its influences on the parties that produce the natural gas gathered on the Jonah and Val Verde systems. In addition, in recent years, FERC has pursued pro-competition policies in its regulation of interstate natural gas pipelines. If the FERC does not continue the pro-competition policies as it considers pipeline rate case proposals, revisions to rules and policies that affect shipper rights of access to interstate natural gas transportation capacity or proposals by natural gas pipelines to allow natural gas pipelines to charge negotiated rates without rate ceiling limits, such policy changes could have an adverse effect on the gathering rates the Midstream Segment is able to charge in the future.

Environmental Matters

     Our operations are subject to federal, state and local laws and regulations governing the discharge of materials into the environment. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of injunctions delaying or prohibiting certain activities and the need to perform investigatory and remedial activities. Although we believe our operations are in material compliance with applicable environmental laws and regulations, risks of significant costs and liabilities are inherent in pipeline operations, and we cannot assure you that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly strict environmental laws and regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us. We believe that changes in environmental laws and regulations will not have a material adverse effect on our financial position, results of operations or cash flows in the near term.

   Water

     The Federal Water Pollution Control Act of 1972, as renamed and amended as the Clean Water Act (“CWA”), and analogous state laws impose strict controls against the discharge of oil and its derivatives into navigable waters. The CWA provides penalties for any discharges of petroleum products in reportable quantities and imposes substantial potential liability for the costs of removing petroleum or other hazardous substances. State laws for the control of water pollution also provide varying civil and criminal penalties and liabilities in the case of a release of petroleum or its derivatives in navigable waters or into groundwater. Spill prevention control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent a petroleum tank release from impacting navigable waters.

     Contamination resulting from spills or releases of petroleum products is an inherent risk within the petroleum pipeline industry. To the extent that groundwater contamination requiring remediation exists along our pipeline systems as a result of past operations, we believe any such contamination could be controlled or remedied

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without having a material adverse effect on our financial position, but such costs are site specific, and we cannot assure you that the effect will not be material in the aggregate.

     The primary federal law for oil spill liability is the Oil Pollution Act of 1990 (“OPA”), which addresses three principal areas of oil pollution — prevention, containment and cleanup, and liability. OPA applies to vessels, offshore platforms and onshore facilities, including terminals, pipelines and transfer facilities. In order to handle, store or transport oil, shore facilities are required to file oil spill response plans with the appropriate federal agency being either the United States Coast Guard, the OPS or the Environmental Protection Agency (“EPA”). Numerous states have enacted laws similar to OPA. Under OPA and similar state laws, responsible parties for a regulated facility from which oil is discharged may be liable for removal costs and natural resource damages.

     The EPA has adopted regulations that require us to have permits in order to discharge certain storm water run-off. Storm water discharge permits may also be required by certain states in which we operate. These permits may require us to monitor and sample the storm water run-off.

   Air Emissions

     Our operations are subject to the federal Clean Air Act (the “Clean Air Act”) and comparable state laws. Amendments to the Clean Air Act, as well as recent or soon to be adopted changes to state implementation plans for controlling air emissions in regional, non-attainment areas, may require our operations to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies. In addition, some of our facilities are included within the categories of hazardous air pollutant sources, which are subject to increasing regulation under the Clean Air Act. The Clean Air Act requires federal operating permits for major sources of air emissions. Under this program, a federal operating permit (a “Title V” permit) may be issued. The permit acts as an umbrella that includes other federal, state and local preconstruction and/or operating permit provisions, emission standards, grandfathered rates and record keeping, reporting and monitoring requirements in a single document. The federal operating permit is the tool that the public and regulatory agencies use to review and enforce a site’s compliance with all aspects of clean air regulation at the federal, state and local level. We have completed applications for the facilities for which these regulations apply.

   Risk Management Plans

     We are subject to the EPA’s Risk Management Plan (“RMP”) regulations at certain locations. This regulation is intended to work with the Occupational Safety and Health Act (“OSHA”) Process Safety Management regulation (see “Safety Regulation” below) to minimize the offsite consequences of catastrophic releases. The regulation requires a regulated source, in excess of threshold quantities, to develop and implement a risk management program that includes a five-year accident history, an offsite consequence analyses, a prevention program and an emergency response program. We believe the operating expenses of the RMP regulations will not have a material adverse effect on our financial position, results of operations or cash flows.

   Solid Waste

     We generate hazardous and non-hazardous solid wastes that are subject to requirements of the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. Amendments to RCRA required the EPA to promulgate regulations banning the land disposal of all hazardous wastes unless the wastes meet certain treatment standards or the land-disposal method meets certain waste containment criteria. From time to time, the EPA considers the adoption of stricter disposal standards for non-hazardous wastes, including crude oil and gas wastes. The adoption of such stricter standards for non-hazardous wastes, or any future re-designation of non-hazardous wastes as hazardous wastes will likely increase our operating expenses as well as the industry in general. We utilize waste minimization and recycling processes to reduce the volume of our waste. We currently have one permitted on-site waste water treatment facility. Operating expenses of this facility have not had a material adverse effect on our financial position, results of operations or cash flows.

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   Superfund

     The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as “Superfund,” imposes liability, without regard to fault or the legality of the original act, on certain classes of persons who contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of a facility where a release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at a facility. 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 take actions 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 our ordinary operations, our pipeline system generates wastes that may fall within CERCLA’s definition of a “hazardous substance.” In the event a disposal facility previously used by us requires clean up in the future, we may be responsible under CERCLA for all or part of the costs required to clean up sites at which such wastes have been disposed.

     In December 1999, we were notified by the EPA of potential liability for alleged waste disposal at Container Recycling, Inc., located in Kansas City, Kansas. We were also asked to respond to an EPA Information Request. Our response to the information request has been filed with the EPA Region VII office. Based on information we have received from the EPA, as well as through our internal investigations, we are pursuing dismissal from this matter.

     In November 2002, we were notified by the EPA of a potential liability for alleged waste disposal at Industrial Pollution Control located in Jackson, Mississippi. Based on the pro-rata share of waste disposed of at the facility, the potentially responsible parties were requested to file a tolling agreement. We filed this agreement with the EPA in December 2002. Our contribution of total waste disposed of at the facility was estimated to be less than 1% and potential liabilities are not expected to exceed $30,000.

   Other Environmental Proceedings

     In 1994, we entered into an Agreed Order with the Indiana Department of Environmental Management (“IDEM”) that resulted in the implementation of a remediation program for groundwater contamination attributable to our operations at the Seymour terminal. In 1999, the IDEM approved a Feasibility Study, which includes our proposed remediation program. In March 2003, the IDEM issued a Record of Decision formally approving the remediation program. As the Record of Decision has been issued, we will enter into an Agreed Order for the continued operation and maintenance of the remediation program. We have an accrued liability of $0.4 million at December 31, 2002, for future remediation costs at the Seymour terminal. We do not expect that the completion of the remediation program will have a future material adverse effect on our financial position, results of operations or cash flows.

     In 1994, the Louisiana Department of Environmental Quality (“LDEQ”) issued a compliance order for environmental contamination at our Arcadia, Louisiana, facility. This contamination may be attributable to our operations, as well as adjacent petroleum terminals operated by other companies. In 1999, our Arcadia facility and adjacent terminals were directed by the Remediation Services Division of the LDEQ to pursue remediation of this containment phase. At December 31, 2002, we have an accrued liability of $0.2 million for remediation costs at our Arcadia facility. We do not expect that the completion of the remediation program that we have proposed will have a future material adverse effect on our financial position, results of operations or cash flows.

     At December 31, 2002, we had an accrued liability of $5.6 million and a receivable of $4.2 million from DEFS related to various TCTM sites requiring environmental remediation activities. The receivable is based on a contractual indemnity obligation we received in connection with our acquisition of assets from a DEFS affiliate in November 1998. The indemnity relates to future environmental remediation activities attributable to operations of these assets prior to our acquisition. Under this indemnity obligation, we are responsible for the first $3.0 million in specified environmental liabilities, and DEFS is responsible for those environmental liabilities in excess of $3.0

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million, up to a maximum amount of $25.0 million. The majority of the receivable from DEFS relates to remediation activities at the Velma crude oil site in Stephens County, Oklahoma. The accrued liability balance at December 31, 2002, also includes an accrual of $2.3 million related to the Shelby crude oil site in Stephens County, Oklahoma. At December 31, 2002, it is uncertain if these costs related to Shelby are covered under the indemnity obligation from DEFS. We are currently in discussions with DEFS regarding these matters. We do not expect that the completion of remediation programs associated with TCTM activities will have a future material adverse effect on our financial position, results of operations or cash flows.

DOT Pipeline Compliance Matters

     We are subject to regulation by the United States Department of Transportation (“DOT”) under the Accountable Pipeline and Safety Partnership Act of 1996, sometimes referred to as the Hazardous Liquid Pipeline Safety Act (“HLPSA”), and comparable state statutes relating to the design, installation, testing, construction, operation, replacement and management of our pipeline facilities. The HLPSA covers petroleum and petroleum products and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to file certain reports and provide information as required by the Secretary of Transportation. The HLPSA was reauthorized in 2002.

     We are subject to the OPS regulation requiring qualification of pipeline personnel. The regulation requires pipeline operators to develop and maintain a written qualification program for individuals performing covered tasks on pipeline facilities. The intent of this regulation is to ensure a qualified work force and to reduce the probability and consequence of incidents caused by human error. The regulation establishes qualification requirements for individuals performing covered tasks, and amends certain training requirements in existing regulations. A written qualification program was completed in April 2001, and our employees performing a covered task were qualified by the October 2002 deadline.

     We are also subject to the OPS Integrity Management regulations which specify how companies with greater than 500 miles of pipeline should assess, evaluate, validate and maintain the integrity of pipeline segments that, in the event of a release, could impact High Consequence Areas (“HCA”). HCA are defined as highly populated areas, unusually sensitive environmental areas and commercially navigable waterways. The regulation requires an Integrity Management Program (“IMP”) be developed that utilizes internal pipeline inspection, pressure testing, or other equally effective means to assess the integrity of HCA pipeline segments. The regulation also requires periodic review of HCA pipeline segments to ensure adequate preventative and mitigative measures exist and that companies take prompt action to address integrity issues raised by the assessment and analysis. In compliance with these OPS regulations, we identified our HCA pipeline segments and developed an IMP by the March 31, 2002 deadline. The regulations require that initial HCA baseline integrity assessments are conducted within seven years, with all subsequent assessments conducted on a five-year cycle. We will evaluate each pipeline segment’s integrity by analyzing available information and develop a range of potential impacts resulting from a potential release to a HCA. We are currently developing cost estimates related to our baseline integrity assessments.

Safety Matters

     We are also subject to the requirements of the federal OSHA and comparable state statutes. We believe we are in material compliance with OSHA and state requirements, including general industry standards, record keeping requirements and monitoring of occupational exposures.

     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 us to organize and disclose information about the hazardous materials used in our operations. Certain parts of this information must be reported to employees, state and local governmental authorities, and local citizens upon request. We are subject to OSHA Process Safety Management (“PSM”) regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves a flammable liquid or gas, as defined in the regulations, stored on-site in one location, in a quantity of 10,000 pounds or more. We utilize certain covered processes and maintain storage of LPGs in pressurized tanks, caverns and wells, in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal

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boiling point without benefit of chilling or refrigeration are exempt. We believe we are in material compliance with the OSHA regulations.

     In general, we expect to increase our expenditures during the next decade to comply with stricter industry and regulatory safety standards such as those described above. While such expenditures cannot be accurately estimated at this time, we do not believe that they will have a future material adverse effect on our financial position, results of operations or cash flows.

Employees

     We do not have any employees, officers or directors. The General Partner is responsible for the management of us and our subsidiaries. As of December 31, 2002, the General Partner had 970 employees.

Available Information

     We file annual, quarterly and other reports and other information with the Securities and Exchange Commission (“SEC”) under the Securities Exchange Act of 1934 (the “Exchange Act”). You may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 450 Fifth Street, NW, Washington, DC 20549. You may obtain additional information about the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains an Internet site (http://www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, including us.

     We also make available free of charge on or through our Internet website (http://www.teppco.com) or through our Investor Relations Department (1-800-659-0059) our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and other information statements and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

Item 3. Legal Proceedings

Toxic Tort Litigation - Seymour, Indiana

     In the fall of 1999 and on December 1, 2000, the General Partner and the Partnership were named as defendants in two separate lawsuits in Jackson County Circuit Court, Jackson County, Indiana, styled Ryan E. McCleery and Marcia S. McCleery, et. al. v. Texas Eastern Corporation, et. al. (including the General Partner and Partnership) and Gilbert Richards and Jean Richards v. Texas Eastern Corporation, et. al. (including the General Partner and Partnership). In both cases, the plaintiffs contend, among other things, that we and other defendants stored and disposed of toxic and hazardous substances and hazardous wastes in a manner that caused the materials to be released into the air, soil and water. They further contend that the release caused damages to the plaintiffs. In their complaints, the plaintiffs allege strict liability for both personal injury and property damage together with gross negligence, continuing nuisance, trespass, criminal mischief and loss of consortium. The plaintiffs are seeking compensatory, punitive and treble damages. We have filed an answer to both complaints, denying the allegations, as well as various other motions. These cases are not covered by insurance. Discovery is ongoing, and we are defending ourselves vigorously against the lawsuits. The plaintiffs have not stipulated the amount of damages that they are seeking in the suit. We cannot estimate the loss, if any, associated with these pending lawsuits.

Other Litigation

     On December 21, 2001, TE Products was named as a defendant in a lawsuit in the 10th Judicial District, Natchitoches Parish, Louisiana, styled Rebecca L. Grisham et. al. v. TE Products Pipeline Company, Limited Partnership. In this case, the plaintiffs contend that our pipeline, which crosses the plaintiff’s property, leaked toxic products onto the plaintiff’s property. The plaintiffs further contend that this leak caused damages to the plaintiffs. We have filed an answer to the plaintiff’s petition denying the allegations. The plaintiffs have not stipulated the amount of damages they are seeking in the suit. We are defending ourselves vigorously against the lawsuit. We

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cannot estimate the damages, if any, associated with this pending lawsuit; however, this case is covered by insurance.

     On April 19, 2002, we, through our subsidiary TEPPCO Crude Oil, L.P., filed a declaratory judgment action in the U.S. District Court for the Western District of Oklahoma against D.R.D. Environmental Services, Inc. (“D.R.D.”) seeking resolution of billing and other contractual disputes regarding potential overcharges for environmental remediation services provided by D.R.D. On May 28, 2002, D.R.D. filed a counterclaim for alleged breach of contract in the amount of $2,243,525, and for unspecified damages for alleged tortious interference with D.R.D.’s contractual relations with DEFS. We have denied the counterclaims. Discovery is ongoing. If D.R.D. should be successful, management believes that a substantial portion of the $2,243,525 breach of contract claim will be covered under an indemnity from DEFS. We cannot predict the outcome of the litigation against us; however, we are defending ourselves vigorously against the counterclaim. We do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows.

     In addition to the litigation discussed above, we have been, in the ordinary course of business, a defendant in various lawsuits and a party to various other legal proceedings, some of which are covered in whole or in part by insurance. We believe that the outcome of these lawsuits and other proceedings will not individually or in the aggregate have a future material adverse effect on our consolidated financial position, results of operations or cash flows.

Item 4. Submission of Matters to a Vote of Security Holders

     None.

PART II

Item 5. Market for Registrant’s Units and Related Unitholder Matters

     Our Limited Partner Units are listed and traded on the New York Stock Exchange under the symbol TPP. The high and low trading prices of our Limited Partner Units in 2002 and 2001, respectively, as reported on The New York Times, were as follows:

     Based on the information received from our transfer agent and from brokers and nominees, we estimate the number of beneficial unitholders of our Limited Partner Units as of March 14, 2003, to be approximately 51,300.

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     The quarterly cash distributions for 2001 and 2002 were as follows:

     We make quarterly cash distributions of all of our Available Cash, generally defined as consolidated cash receipts less consolidated cash disbursements and cash reserves established by the General Partner in its sole discretion. Pursuant to the Partnership Agreement, the Company receives incremental incentive cash distributions when cash distributions exceed certain target thresholds (see Note 13. Quarterly Distributions of Available Cash).

     We are a publicly traded master limited partnership and are not subject to federal income tax. Instead, unitholders are required to report their allocated share of our income, gain, loss, deduction and credit, regardless of whether we make distributions. We have made quarterly distribution payments since May 1990.

     Distributions of cash by us to a unitholder will not result in taxable gain or income except to the extent the aggregate amount distributed exceeds the tax basis of the Units owned by the unitholder.

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Item 6. Selected Financial Data

     The following tables set forth, for the periods and at the dates indicated, our selected consolidated financial and operating data. The financial data was derived from our consolidated financial statements and should be read in conjunction with our audited consolidated financial statements included in the Index to Financial Statements on page F-1 of this Report. See also Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

     The following information is provided to facilitate increased understanding of our 2002, 2001 and 2000 consolidated financial statements and our accompanying notes listed in the Index to Financial Statements on page F-1 of this Report. Accounting policies that are among the most critical to the portrayal of our financial condition and results of operations are discussed under “Critical Accounting Policies.” Material period-to-period variances in the consolidated statements of income are discussed under “Results of Operations.” The “Financial Condition and Liquidity” section analyzes cash flows and financial position. Discussion included in “Other Considerations” addresses trends, future plans and contingencies that are reasonably likely to materially affect future liquidity or earnings.

     We operate and report in three business segments:

	•		Downstream Segment – transportation and storage of refined products, LPGs and petrochemicals;
	•		Upstream Segment – gathering, transportation, marketing and storage of crude oil; and distribution of lubrication oils and specialty chemicals; and
	•		Midstream Segment – gathering of natural gas, fractionation of NGLs and transportation of NGLs.

     Our reportable segments offer different products and services and are managed separately because each requires different business strategies. TEPPCO GP, our wholly owned subsidiary, acts as managing general partner of our Operating Partnerships with a 0.001% general partner interest and manages our subsidiaries.

     Effective January 1, 2002, we realigned our three business segments to reflect our entry into the natural gas gathering business and the expanded scope of NGLs operations. We transferred the fractionation of NGLs, which was previously reflected as part of the Downstream Segment, to the Midstream Segment. The operation of NGL pipelines, which was previously reflected as part of the Upstream Segment, was also transferred to the Midstream Segment. We have adjusted our period-to-period comparisons to conform with the current presentation.

     Our Downstream Segment revenues are earned from transportation and storage of refined products and LPGs, storage and short-haul shuttle transportation of LPGs at the Mont Belvieu complex, intrastate transportation

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of petrochemicals, sale of product inventory and other ancillary services. The two largest operating expense items of the Downstream Segment are labor and electric power. We generally realize higher revenues during the first and fourth quarters of each year since our operations are somewhat seasonal. Refined products volumes are generally higher during the second and third quarters because of greater demand for gasolines during the spring and summer driving seasons. LPGs volumes are generally higher from November through March due to higher demand in the Northeast for propane, a major fuel for residential heating. Our Downstream Segment also includes our equity investment in Centennial.

     Our Upstream Segment revenues are earned from gathering, transportation, marketing and storage of crude oil, and distribution of lubrication oils and specialty chemicals, principally in Oklahoma, Texas and the Rocky Mountain region. Marketing operations consist primarily of aggregating purchased crude oil along our pipeline systems, or from third party pipeline systems, and arranging the necessary logistics for the ultimate sale of the crude oil to local refineries, marketers or other end users. Our Upstream Segment also includes the equity earnings from our investment in Seaway. Seaway is a large diameter pipeline that transports crude oil from the U.S. Gulf Coast to Cushing, a central crude oil distribution point for the Central United States.

     Our Midstream Segment revenues are earned from the gathering of natural gas, fractionation of NGLs and transportation of NGLs. The Midstream Segment includes the operations from the acquisition of Jonah on September 30, 2001, from Alberta Energy Company for $359.8 million. We paid an additional $7.3 million on February 4, 2002, for final purchase adjustments related primarily to construction projects in progress at the time of closing. The results of operations of the acquisition are included in our consolidated financial statements beginning in the fourth quarter of 2001. The Jonah assets are managed and operated by DEFS under a contractual agreement.

     On March 1, 2002, we completed the purchase of the Chaparral NGL system for $132.4 million from Diamond-Koch II, L.P. and Diamond-Koch III, L.P., including acquisition related costs of approximately $0.4 million. The Chaparral NGL system has an 800-mile pipeline that extends from West Texas and New Mexico to Mont Belvieu. The pipeline delivers NGLs to fractionators and to our existing storage in Mont Belvieu. The Chaparral NGL system also has an approximately 170-mile NGL gathering system located in West Texas, which begins in Sutton County, Texas, and connects to the 800-mile pipeline near Midland. The pipelines are connected to 27 gas plants in West Texas and have approximately 28,000 horsepower of pumping capacity at 14 stations. The Chaparral NGL system is managed and operated by DEFS under a contractual agreement. These assets are included in the Midstream Segment.

     On June 30, 2002, we completed the purchase of the Val Verde Gathering System for $444.2 million from Burlington Resources Gathering Inc., a subsidiary of Burlington Resources Inc., including acquisition related costs of approximately $1.2 million. Val Verde gathers CBM from the Fruitland Coal Formation of the San Juan Basin in New Mexico and Colorado. The system is one of the largest CBM gathering and treating facilities in the United States, gathering CBM from more than 540 separate wells throughout New Mexico. The system provides gathering and treating services pursuant to approximately 60 long-term contracts with approximately 40 different gas producers in the San Juan Basin. Gas gathered on the Val Verde Gathering System is delivered to several interstate pipeline systems serving the western United States and to local New Mexico markets. The Val Verde Gathering System consists of 360 miles of pipeline ranging in size from 4 inches to 36 inches in diameter, 14 compressor stations operating over 93,000 horsepower of compression and a large amine treating facility for the removal of carbon dioxide. The system has a pipeline capacity of approximately one billion cubic feet per day. The Val Verde assets are managed and operated by DEFS under a contractual agreement. These assets are included in the Midstream Segment.

Critical Accounting Policies

     The preparation of financial statements in conformity with generally accepted accounting principles in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities in the accompanying financial statements. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Key estimates used by management include revenue and expense accruals, environmental costs, depreciation and amortization, asset impairment and fair values of assets acquired. Significant accounting policies that we employ are presented in the notes to the consolidated financial statements.

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     Critical accounting policies are those that are most important to the portrayal to our financial position and results of operations. These policies require management’s most difficult, subjective or complex judgments, often employing the use of estimates about the effect of matters that are inherently uncertain. Our most critical accounting policies pertain to revenue and expense accruals, environmental costs, property, plant and equipment, goodwill and intangible assets.

   Revenue and Expense Accruals

     We routinely make accruals for both revenues and expenses before we receive certain third party information and reconcile our records with those of third parties. The delayed information from third parties includes, among other things, actual volumes of crude oil purchased, transported or sold, adjustments to inventory and invoices for purchases and other operating expenses. We make accruals to reflect estimates for these items based on our internal records and information from third parties. The estimated accruals are reversed in the following month when actual information is received from third parties and our internal records have been reconciled.

   Environmental Costs

     At December 31, 2002, we have accrued a liability for our estimate of the future payments we expect to pay for environmental costs to remediate existing conditions attributable to past operations. We accrue for environmental costs that relate to existing conditions caused by past operations. Environmental costs include initial site surveys and environmental studies of potentially contaminated sites, costs for remediation and restoration of sites determined to be contaminated and ongoing monitoring costs, as well as fines, damages and other costs, when estimable. We monitor the balance of accrued undiscounted environmental liabilities on a regular basis. We record liabilities for environmental costs at a specific site when our liability for such costs, including direct internal and legal costs, is probable and a reasonable estimate of the associated costs can be made. Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information developed in subsequent periods. Estimates of our ultimate liabilities associated with environmental costs are particularly difficult to make with certainty due to the number of variables involved, including the early stage of investigation at certain sites, the lengthy time frames required to complete remediation alternatives available and the evolving nature of environmental laws and regulations. For information concerning environmental regulation and environmental costs and contingencies, see Item 1 and 2. Business and Properties – “Environmental Matters” in this Report.

   Property, Plant and Equipment

     We record property, plant and equipment at its acquisition cost. Additions to property, plant and equipment, including major replacements or betterments, are recorded at cost. We charge replacements and renewals of minor items of property that do not materially increase values or extend useful lives to maintenance expense. Depreciation expense is computed on the straight-line method using rates based upon expected useful lives of various classes of assets (ranging from 2% to 20% per annum).

     We evaluate impairment of long-lived assets in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 121, Accounting for the Impairment of Long-Lived Assets to Be Disposed Of, and effective January 1, 2002, SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of the carrying amount of assets to be held and used is measured by a comparison of the carrying amount of the asset to future net cash flows expected to be generated by the asset. Estimates of future net cash flows include anticipated future revenues, expected future operating costs and other estimates. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell.

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     During the second quarter of 2001, Pennzoil-Quaker State Company (“Pennzoil”) sold its Shreveport, Louisiana, refinery. Under its transportation agreement with TE Products, Pennzoil had a throughput commitment of 25,000 barrels per day. Pennzoil and TE Products negotiated a settlement of $18.9 million to terminate the long-term transportation agreement from the Shreveport origin point on the Products Pipeline System. The termination payment was recorded as refined products transportation revenue in 2001.

     We have evaluated the impact of the contract termination on the pipeline segment from Shreveport to El Dorado, Arkansas, in accordance with SFAS 144. The evaluation did not result in an impairment of the carrying value of the related transportation assets, which was $28.1 million at December 31, 2002. We are pursuing various alternatives including making system changes to allow for bi-directional product flow to make deliveries into the Shreveport market area. We have completed feasibility studies, and we are in discussions with potential customers regarding the transportation of volumes through this pipeline. If alternative revenue sources are not realized on this pipeline segment, an impairment may be recorded for the excess of the carrying value over discounted future net cash flows.

   Goodwill and Intangible Assets

     Goodwill and intangible assets represent the excess of consideration paid over the fair value of tangible net assets acquired. Certain assumptions and estimates are employed in determining the fair value of assets acquired including goodwill and other intangible assets as well as determining the allocation of goodwill to the appropriate reporting unit. In addition, we assess the recoverability of these intangibles by determining whether the amortization of these intangibles over their remaining useful lives can be recovered through undiscounted future net cash flows of the acquired operations. The amount of impairment, if any, is measured by the amount by which the carrying amounts exceed the projected discounted future operating cash flows. During 2002, we adopted SFAS No. 142, Goodwill and Other Intangible Assets, which discontinues the amortization of goodwill and indefinite life intangibles and requires an annual test of impairment based on a comparison of fair value to carrying values. The evaluation of impairment under SFAS 142 requires the use of projections, estimates and assumptions as to the future performance of the operations, including anticipated future revenues, expected future operating costs and the discount factor used. Actual results could differ from projections resulting in revisions to our assumptions and, if required, recognizing an impairment loss. Based on our assessment, we do not believe our goodwill is impaired and we have not recorded a charge from the adoption of SFAS 142.

     At December 31, 2002, we have $433.7 million of natural gas transportation contracts which were recorded as part of our acquisitions of Jonah on September 30, 2001, and Val Verde on June 30, 2002 (see Note 5. Acquisitions). The value assigned to the natural gas transportation contracts required management to make estimates regarding the fair value of the assets acquired. In connection with the acquisition of Jonah, we assumed contracts that dedicate future production from natural gas wells in the Green River Basin in Wyoming. We assigned $222.8 million of the purchase price to these production contracts based upon a fair value appraisal at the time of closing. In connection with the acquisition of Val Verde, we assumed fixed-term gas transportation contracts with customers in the San Juan Basin in New Mexico and Colorado. We assigned $239.6 million of the purchase price to these fixed term contracts based upon a fair value appraisal at the time of the closing. The value assigned to intangible assets is amortized on a unit of production basis, based upon the actual throughput of the system over the expected total throughput for the lives of the contracts. The amortization of the Jonah and Val Verde systems are expected to average approximately 16 years and 20 years, respectively. On a quarterly basis, we update production estimates of the natural gas wells and evaluate the remaining expected useful life of the contract assets. Changes in the estimated remaining production will impact the timing of amortization expense reported for future periods.

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Results of Operations

     The following table summarizes financial data by business segment (in thousands):