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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

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, 2001

Commission File Number 1-10403

TEPPCO Partners, L.P.
(Exact name of Registrant as specified in its charter)

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    No

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

     At March 7, 2002, the aggregate market value of the registrant’s Limited Partner Units held by non-affiliates was $1,240,803,750, which was computed using the average of the high and low sales prices of the Limited Partner Units on March 7, 2002.

     Limited Partner Units outstanding as of March 7, 2002: 40,450,000.

Documents Incorporated by Reference: None

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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 and was formed in March 1990. The Partnership operates 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 the general partner of the Partnership. The General Partner is a wholly-owned subsidiary of Duke Energy Field Services (“DEFS”), a joint venture between Duke Energy Corporation (“Duke Energy”) and Phillips Petroleum Company (“Phillips”). Duke Energy holds an approximate 70% interest in DEFS and Phillips holds the remaining 30%. The Company, as general partner, performs all management and operating functions required for the Partnership and the Operating Partnerships, except for the management and operations of the TEPPCO Midstream assets, which is performed by DEFS under an agreement with the Partnership. The General Partner is reimbursed by the Partnership for all reasonable direct and indirect expenses incurred in managing the Partnership.

     On July 26, 2001, the Company restructured its general partner ownership of the Operating Partnerships to cause them to be indirectly wholly-owned by the Partnership. TEPPCO GP, Inc. (“TEPPCO GP”), a subsidiary of the Partnership, succeeded the Company as general partner of the Operating Partnerships. All remaining partner interests in the Operating Partnerships not already owned by the Partnership were transferred to the Partnership. In exchange for this contribution, the Company’s interest as general partner of the Partnership was increased to 2%. The increased percentage is the economic equivalent of the aggregate interest that the Company had prior to the restructuring through its combined interests in the Partnership and the Operating Partnerships. As a result, the Partnership holds a 99.999% limited partner interest in the Operating Partnerships and TEPPCO GP holds a 0.001% general partner interest. This reorganization was undertaken to simplify required financial reporting by the Operating Partnerships when guarantees of Partnership debt are issued by the Operating Partnerships.

     The Partnership operates and reports in three business segments: transportation of refined products, liquefied petroleum gases (“LPGs”) and petrochemicals (“Downstream Segment”); transportation and marketing of crude oil and natural gas liquids (“NGLs”) (“Upstream Segment”); and gathering of natural gas (“Midstream Segment”). The Partnership’s reportable segments offer different products and services and are managed separately because each requires different business strategies. The Upstream Segment of the Partnership’s business was initially acquired in November 1998. The Midstream Segment of the Partnership’s business was initially acquired on September 30, 2001. The assets of the Midstream Segment are managed and operated by DEFS under an agreement with the Partnership.

     The Partnership’s 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, 2001, the Partnership had outstanding 40,450,000 Limited Partner Units and 3,916,547 Class B Limited Partner Units (“Class B Units”). 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. The Company has 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 the Partnership at 95.5% of the then current market price of the Limited Partner Units. As a result of this option, the Class B Units were not included in partners’ capital at December 31, 2001. Collectively, the Limited Partner Units and Class B Units are referred to as “Units.”

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     The Partnership’s strategy is to expand and improve service in its current markets, maintain the integrity of its pipeline systems and pursue a growth strategy that is balanced between internal projects and targeted acquisitions. The Partnership intends to leverage the advantages inherent in its pipeline systems to maintain its status as the incremental provider of choice in its market area. The Partnership also intends to grow by acquiring assets, from both third parties and affiliates, which complement existing businesses or to establish new core businesses. The Company routinely evaluates opportunities to acquire assets and businesses that will complement existing operations with a view to increasing earnings and cash available for distribution to unitholders. Additional acquisitions may be funded with cash flow from operations, borrowings under existing credit facilities, the issuance of debt in the capital markets and the sale of additional units.

Downstream Segment — Transportation of Refined Products, Petrochemicals and LPGs

   Operations

     The Partnership conducts business in its Downstream Segment through TE Products and its subsidiary. 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; fractionation of natural gas liquids and other ancillary services.

     As an interstate common carrier, the 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 the pipeline system from its interstate tariffs, it also receives 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 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 to the Northeast.

     The Partnership’s Downstream Segment depends in large part on the level of demand for refined petroleum products and LPGs in the geographic locations served by it and the ability and willingness of customers having access to the pipeline system to supply such demand. The Partnership cannot predict the impact of future fuel conservation measures, alternate fuel requirements, governmental regulation, 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 served by the Partnership.

     The following table lists the material properties and investments of and ownership percentages in the Downstream Segment assets as of December 31, 2001:

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   Centennial Pipeline Joint Venture

     In August 2000, TE Products entered into agreements with CMS Energy Corporation and Marathon Ashland Petroleum LLC to form a pipeline joint venture, Centennial Pipeline, LLC (“Centennial”). Centennial owns and operates an interstate refined petroleum products pipeline extending from the upper Texas Gulf Coast to Illinois. Each participant owns a one-third interest in Centennial. Centennial constructed a 74-mile, 24-inch diameter pipeline connecting TE Products’ facility in Beaumont, Texas, 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 has constructed a new two million barrel refined petroleum products storage terminal. TE Products’ interest is not subject to any encumbrances from mortgages or other secured debt. Centennial has unsecured debt, one third of which, up to $50 million in principal, is guaranteed by each owner, including TE Products. As of December 31, 2001, TE Products has contributed approximately $70 million for its one-third interest in Centennial. The Partnership expects to contribute an additional $4.9 million to Centennial in 2002. Centennial commenced operations in the first quarter of 2002.

   Refined Products and LPGs Pipeline System

     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, Texas, the largest LPGs storage complex in the United States, and at other locations. TE Products also owns two marine receiving terminals, one near Beaumont, Texas, 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 12-inch diameter common-carrier petrochemical pipelines between Mont Belvieu and Port Arthur, Texas, each approximately 70 miles in length.

     All properties comprising the Products Pipeline System are wholly-owned by subsidiaries of the Partnership and none are subject to any encumbrances from mortgages or other secured debt.

     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.

     The Products Pipeline System includes 30 storage facilities with an aggregate storage capacity of 13 million barrels of refined petroleum products and 38 million barrels of LPGs, including storage capacity leased to outside parties. The Products Pipeline System makes deliveries to customers at 53 locations including 18 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, Texas, 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, Indiana. 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. Also, the Products Pipeline System has a 6-inch diameter pipeline connection to the

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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, whereas the line starting at Greensburg and ending at Marcus Hook varies in diameter from 6 inches to 8 inches.

     TE Products also owns three 12-inch diameter common-carrier petrochemical pipelines between Mont Belvieu and Port Arthur, Texas, 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. The Partnership entered into a 20-year agreement with a major petrochemical producer for guaranteed throughput commitments. During the year ended December 31, 2001, and the two month period ended December 31, 2000, the Partnership recognized $10.7 million and $1.8 million, respectively, of revenue under the throughput and deficiency contract. The Partnership began transporting product through these pipelines in September 2001.

     The Partnership believes that the Products Pipeline System is in compliance with applicable federal, state and local laws and regulations, and accepted industry standards and practices. The Partnership performs regular maintenance on all the facilities of the Products Pipeline System and has an ongoing process of inspecting segments of the Products Pipeline System and making repairs and replacements when necessary or appropriate. In addition, the Partnership conducts periodic air patrols of the Products Pipeline System to monitor pipeline integrity and third-party right of way encroachments.

   Major Business Sector Markets

     The Partnership’s major operations in the Downstream Segment consist of the transportation, storage and terminaling of refined petroleum products and LPGs along its mainline system, and the storage and short-haul transportation of LPGs associated with its Mont Belvieu LPG operations. Product deliveries, in millions of barrels (MMBbls) on a regional basis, over the last three years were as follows:

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     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 the Products Pipeline System also affect the demand for, and the mix of, the products delivered.

     Refined products and LPGs deliveries over the last three years were as follows:

   Refined Products Mainline Transportation

     The 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. TE Products canceled its tariff for deliveries of MTBE into the Chicago market area on July 1, 1999, and canceled contract deliveries of MTBE at its marine terminal near Beaumont, Texas, effective April 22, 2001. The Partnership no longer transports MTBE through the Products Pipeline System.

     The volume of refined petroleum products transported by the 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 accounts for a substantial portion of the volume of refined products transported through the Products Pipeline System, depends upon price, prevailing economic conditions and demographic changes in the markets served. 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 the Partnership’s 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 revenues from period to period.

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   LPGs Mainline Transportation

     The 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. Since LPGs demand is generally stronger in the winter months, the Products Pipeline System often operates at or near capacity during such time. Propane deliveries are generally sensitive to the weather and meaningful year-to-year variations have occurred and will likely continue to occur.

     The Partnership’s ability in its Downstream Segment to serve markets in the Northeast is enhanced by its propane import terminal at Providence, Rhode Island. This facility includes a 400,000-barrel refrigerated storage tank along with ship unloading and truck loading facilities. Effective May 2001, the Company entered into an agreement with DEFS to commit sole utilization of the Providence terminal to DEFS. The terminal is operated by the Partnership. During the year ended December 31, 2001, DEFS paid the Partnership $1.5 million 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.

     The Partnership’s Downstream Segment has approximately 36 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, the Partnership and Louis Dreyfus Plastics Corporation (“Louis Dreyfus”) announced a joint marketing and development alliance. The Partnership’s Mont Belvieu LPGs storage and transportation shuttle system services are jointly marketed by Louis Dreyfus and the Partnership. The purpose of the alliance is 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. TE Products operates the facilities for the alliance. The alliance is a service-oriented, fee-based venture with no commodity trading activity. Under the alliance, Louis Dreyfus has invested $4.4 million for expansion projects at Mont Belvieu. The Partnership is required to reimburse this amount to Louis Dreyfus if the alliance is terminated by either Louis Dreyfus or the Partnership.

   Other Operating Revenues

     The Partnership’s Downstream Segment also derives revenue from terminaling activities, other ancillary services associated with the transportation and storage of refined petroleum products and LPGs, and the fractionation of NGLs. From time to time, the Partnership sells excess product inventory.

   Customers

     The Downstream Segment’s 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.

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     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 fuel source. Refineries constitute the Partnership’s 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, 2001, the Downstream Segment had approximately 140 customers. Transportation revenues (and percentage of total revenues) attributable to the top 10 customers were $109 million (40)%, $102 million (43)% and $105 million (46)%, for the years ended December 31, 2001, 2000 and 1999, respectively. During 2001, no single customer accounted for 10% or more of the Downstream Segment’s revenues.

   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. The Partnership believes the Downstream Segment is competitive with other 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. The Partnership faces competition from rail movements of LPGs from Sarnia, Ontario, Canada, and waterborne imports into New Hampshire.

Upstream Segment — Transportation and Marketing of Crude Oil and NGL

   Operations

     The Partnership conducts business in its Upstream Segment through TCTM and its wholly-owned subsidiaries, which gather, store, transport and market crude oil, NGLs, lube oils and specialty chemicals, principally in Oklahoma, Texas and the Rocky Mountain region. The Partnership commenced its Upstream Segment business in connection with the acquisition of certain assets from DEFS in November 1998. The Partnership’s Upstream Segment utilizes its asset base to aggregate crude oil and provide transportation and specialized services to its regional customers. The Partnership’s Upstream Segment purchases crude oil at prevailing prices from producers at the wellhead, aggregates such crude oil into its equity owned pipelines or third party owned pipelines utilizing its truck fleet and transports the crude oil for ultimate sale to or exchange with its customers.

     Margins in the Upstream Segment are calculated as revenues generated from the sale of crude oil and lubrication oil, and transportation of crude oil and NGLs, 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.

     TCTM purchases crude oil and simultaneously establishes a margin by selling crude oil for physical delivery to third party users. The Partnership seeks to maintain a balanced marketing position until it makes physical delivery of the crude oil, thereby minimizing or eliminating exposure to price fluctuations occurring after

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the initial purchase. However, certain basis risks, the risk that price relationships between delivery points, classes of products or delivery periods will change, cannot be completely hedged or eliminated. The Partnership makes limited use of commodity derivative products for the purpose of speculating on price changes. Risk management policies have been established for the Partnership by the Company’s Risk Management Committee to monitor and control market risks. The Risk Management Committee is comprised, in part, of senior executives of the Company. The Partnership had no commodity derivative contracts outstanding at December 31, 2001.

     Volume information of TCTM’s 100% owned pipeline systems and undivided joint interest pipelines for the years ended December 31, 2001, 2000 and 1999, is presented below (in thousands):

   Properties

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

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None of these pipelines or systems is subject to any encumbrance from a mortgage or other secured debt.

     The majority of the Red River System crude oil is delivered to Cushing, Oklahoma via connecting 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 connects gathering systems to TCTM’s Midland, Texas terminal. Other crude oil assets, located primarily in Texas and Louisiana, consist of 344 miles of pipeline and 295,000 barrels of storage capacity.

     The NGL pipelines of the Upstream Segment are located along the Texas Gulf Coast. They are all wholly-owned and operated by subsidiaries of the Partnership. Information concerning these NGL pipelines is set forth in the following table:

None of these pipelines is subject to any encumbrance from a mortgage or other secured 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 Panola Pipeline and San Jacinto Pipeline were purchased on December 31, 2000, from DEFS and originate at DEFS’ East Texas Plant Complex in Panola County, Texas.

   Partnership Interest in Seaway Crude Pipeline

     Seaway Crude Pipeline Company (“Seaway”) is a partnership between TCTM and Phillips. In July 2000, the Partnership acquired its 50-percent ownership interest in Seaway from ARCO Pipe Line Company (“ARCO”), a wholly-owned subsidiary of Atlantic Richfield Company. The Partnership 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. Two 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. 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 storage services for all Houston area refineries.

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     The Seaway partnership agreement provides for varying participation ratios throughout the life of Seaway. From July 20, 2000, through May 2002, the Partnership will receive 80% of revenue and expense of Seaway. From June 2002 until May 2006, the Partnership will receive 60% of revenue and expense of Seaway. Thereafter, the Partnership will receive 40% of revenue and expense of Seaway.

   Line Transfers, Pumpovers and Other

     The Partnership’s 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. 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 the Partnership’s 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 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 the Partnership’s consolidated statements of income and represents the crude oil terminaling component of margin. The line transfer and pumpover operations were acquired from ARCO in July 2000.

     Through its subsidiary, Lubrication Services, L.P. (“LSI”), TCTM distributes lube oils and specialty chemicals to natural gas pipelines, gas processors, and industrial and commercial accounts. LSI’s distribution networks are located in Colorado, 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. During 2001, no single customer accounted for 10% or more of the margin of the Partnership’s Upstream Segment. The Company does not believe the loss of any single customer would have a material adverse effect on the consolidated financial position, results of operations or cash flows of the Partnership.

   Competition

     The most significant competitors in pipeline operations in the Partnership’s 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 its pipeline systems deliver crude oil and NGLs. 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 has intensified competition among gatherers and marketers.

     A significant portion of the growth in the Partnership’s Upstream Segment has occurred through acquisitions of pipeline gathering systems. The Partnership’s acquisitions in this segment have provided increased efficiencies for the gathering and transportation of crude oil and NGLs with its existing pipeline systems as well as expansion into new market areas. The Partnership experiences competition from other gatherers and marketers in the 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, which may decrease the amount of potential acquisitions of crude gathering systems available to the Partnership.

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   Credit Policies and Procedures

     As crude oil or lube oils are marketed, the Partnership must determine the amount, if any, of credit to be extended to any given customer, particularly in the Partnership’s 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 the Partnership’s business. The Partnership manages its exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures. The Partnership utilizes letters of credit and guarantees for certain of its receivables. However, these procedures and policies may not fully eliminate customer credit risk. The bankruptcy of Enron Corp. and certain of its subsidiaries in December 2001 has made doubtful the collection of approximately $4.3 million of transportation deficiency payments by the Partnership. During the years ended 1999 and 2000, no reserves were necessary to write-off uncollectible receivables of the Upstream Segment.

Midstream Segment — Natural Gas Gathering

     The operations of the Partnership’s Midstream Segment commenced upon the acquisition of all of the partnership interests of Jonah Gas Gathering Company (“Jonah”) from Alberta Energy Company, effective September 30, 2001, by subsidiaries of the Partnership. The original purchase price totaled $359.8 million. An additional $7.2 million was accrued at December 31, 2001, for final purchase 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 are included in the Partnership’s consolidated financial statements in the fourth quarter of 2001. The assets of Jonah are managed and operated by DEFS under a contract arrangement. Jonah and its assets are not subject to any encumbrances from mortgages or other secured debt.

     In connection with the acquisition of Jonah, the Partnership assumed responsibility for the completion of an ongoing expansion of the Jonah Gas Gathering System (“Jonah System”) at a cost of approximately $25.0 million. The expansion, which is expected to be completed by the end of March 2002, will increase the capacity of the Jonah System by 62%, from approximately 450 million cubic feet per day (“MMcf/day”), to approximately 730 MMcf/day.

     In February 2002, a producer on the Jonah System notified Alberta Energy Company that it has a right to acquire all or a portion of the assets comprising the Jonah System. This claim is based upon an alleged right of first refusal contained in a gas gathering agreement between the producer and Jonah. Subsidiaries of Alberta Energy Company have agreed to indemnify the Partnership against losses resulting from the breach of representations concerning the absence of third party rights in connection with the acquisition of Jonah, the owner of the Jonah System. The Partnership believes that it has adequate legal defenses to the producer’s claim and that no right of first refusal on any of the underlying Jonah System assets has been triggered.

     Revenues of the Partnership’s Midstream Segment are earned primarily from gathering fees based on the volume and pressure of natural gas gathered, and also from sales of condensate on the Jonah System. TEPPCO Midstream has multiple long-term contracts with producers connected to the Jonah System. The Partnership cannot influence or control the operation or development of the gas fields served by the Jonah System. Production levels may be affected by price and price volatility, market demand, depletion rates of existing wells and changes in laws and regulations. The Partnership does not take title to the natural gas gathered on the Jonah System. Accordingly, the results of operations of the Midstream Segment are not directly affected by changes in the prices of natural gas or other commodities. It is expected that Midstream Segment revenues and cash flows will increase from historical levels as the system capacity expansion becomes operational.

     Volume information for the three month period ended December 31, 2001, is presented below:

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   The Jonah Gas Gathering System

     The Jonah System consists of approximately 350 miles of pipelines ranging in size from four to 20 inches in diameter, four compressor stations with an aggregate of approximately 21,200 horsepower and related metering facilities. Gas gathered on the Jonah System is collected from approximately 375 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 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 the Overland Trail Transmission system, Kern River, Northwest, Colorado Interstate Gas and Questar.

   Customers

     At December 31, 2001, the Midstream Segment had approximately 10 customers. During the fourth quarter of 2001, the first quarterly period that the Partnership owned Jonah, billings to Alberta Energy Company, BP p.l.c., and The Williams Companies, Inc. accounted for approximately 46%, 25% and 17%, respectively, of the revenues of the Partnership’s Midstream Segment.

   Competition

     New supplies of natural gas are necessary to offset natural declines in production from wells connected to the Jonah System and to increase throughput volume. Competition is encountered in obtaining contracts to gather natural gas supplies. Competition in natural gas gathering is based in large part on reputation, efficiency, reliability, gathering system capacity and price arrangements. Key competitors in the gas gathering segment include independent gas gatherers and major integrated energy companies. Alternate gathering facilities are available to producers served by the Partnership’s Midstream Segment, and those producers may also elect to construct proprietary gas gathering systems. If the production delivered to the Jonah System declines, revenues from such operations will decline.

     Declines in the volumes of natural gas delivered for gathering on the system will adversely affect revenues and could, if such declines are sustained or substantial, have a material adverse effect on the financial position, results of operations or cash flows.

Title to Properties

     The Partnership believes it has satisfactory title to all of its 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 notified Alberta Energy Company that it has a right to acquire all or a portion of the assets comprising Jonah. See Items 1 and 2. Business and Properties, “Midstream Segment — Natural Gas Gathering” for a more detailed discussion of the matter. The Partnership believes none of these liabilities materially affects the value of its properties or the Partnership’s interest therein or will materially interfere with their use in the operation of the Partnership’s business.

Capital Expenditures

     Capital expenditures, excluding acquisitions, by the Partnership totaled $107.6 million for the year ended December 31, 2001. Revenue generating projects include those projects which expand service into new markets or expand capacity into current markets. Maintenance capital spending includes projects required by regulatory agencies or required life-cycle replacements. System upgrade projects improve operational efficiencies or reduce

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cost. The Partnership capitalizes interest costs incurred during the period that construction is in progress. The following table identifies capital expenditures by segment for the year ended 2001 (in millions):

     Revenue generating capital spending by the Downstream Segment included $35.5 million used to expand the Partnership’s capacity to support the receipt connection point at Beaumont, Texas, and delivery location at Creal Springs, Illinois, with Centennial and $17.4 million used to construct connections and related facilities for the petrochemical pipelines at Mont Belvieu. Revenue generating capital spending of the Midstream Segment related to the ongoing expansion of the Jonah System that was assumed by the Partnership upon the purchase on September 30, 2001.

     The Partnership estimates that capital expenditures, excluding acquisitions, for 2002 will be approximately $74 million (which includes $4 million of capitalized interest). Approximately $31 million is expected to be used for revenue generating projects. Approximately $27 million is expected to be used for maintenance capital spending and approximately $12 million for system upgrade projects. Revenue generating projects will include the completion of facilities to support the receipt and delivery locations with Centennial, the completion of the Jonah System expansion, additional well connections to the Jonah System and other projects to expand service capabilities of the Partnership. Approximately $4.9 million of maintenance capital spending is expected to be used for pipeline rehabilitation projects to comply with regulations enacted by the United States Department of Transportation Office of Pipeline Safety (“OPS”). The Partnership continually reviews and evaluates potential capital improvements and expansions that would be complementary to its present business segments. These expenditures can vary greatly depending on the magnitude of these transactions by the Partnership. Capital expenditures may be financed through internally generated funds, debt or the issuance of additional Limited Partner Units.

Regulation

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

     Rates of interstate oil pipeline companies, like the Partnership, are currently regulated by the FERC primarily through an index methodology, whereby a pipeline is allowed to change its rates based on the change from year to year in the Producer Price Index for finished goods less 1% (“PPI Index”). In the alternative, interstate 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 the oil pipeline company 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 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, Arcadia and Shreveport-Arcadia, Louisiana, destination markets, which are currently subject to the

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PPI Index. As a result, the Partnership made refunds of approximately $1.0 million in the third quarter of 2001 for those destination markets.

     Effective July 1, 1999, TE Products established Settlement Rates with certain shippers of LPGs under which the rates in effect on June 30, 1999, would not be adjusted for a period of either two or three years. Other LPGs transportation tariff rates were reduced pursuant to the PPI Index (approximately 1.83)%, effective July 1, 1999.

     In a 1995 decision involving an unrelated oil 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 oil pipeline limited partnership, the FERC held that the oil 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 the Partnership’s current rates and rate structure because the Partnership does not use the cost of service methodology to support its rates. However, the FERC decisions might become relevant to the Partnership should it (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 its indexed rates against a shipper protest alleging that an indexed rate increase substantially exceeds actual cost increases. Should such circumstances arise, there can be no assurance with respect to the effect of such precedents on the Partnership’s rates in view of the uncertainties involved in this issue.

     While the FERC does not directly regulate the natural gas gathering operations of the Jonah System, federal regulation, directly or indirectly, influences the parties that gather natural gas on the Jonah System. The Jonah System is exempt from FERC regulation under the Natural Gas Act of 1938 since it is an intrastate gas gathering system rather than an interstate transmission pipeline. However, FERC regulation still significantly affects the Midstream Segment. 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 policy 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

     The operations of the Partnership are subject to federal, state and local laws and regulations governing the discharge of materials into the environment otherwise relating to environmental protection. 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 the Partnership believes its operations are in material compliance with applicable environmental laws and regulations, risks of significant costs and liabilities are inherent in pipeline operations, and there can be no assurance 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 its operations, could result in substantial costs and liabilities to the Partnership. The Company does not anticipate that changes in environmental laws and regulations will have a material adverse effect on the Partnership’s 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.

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     Contamination resulting from spills or releases of refined petroleum products is an inherent risk within the petroleum pipeline industry. To the extent that groundwater contamination requiring remediation exists along its pipeline systems as a result of past operations, the Partnership believes any such contamination could be controlled or remedied without having a material adverse effect on the financial condition of the Partnership, but such costs are site specific, and there can be no assurance 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 United States Department of Transportation Office of Pipeline Safety 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 the Partnership 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 the Partnership operates. Such permits may require the Partnership to monitor and sample the storm water run-off.

   Air Emissions

     The operations of the Partnership 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 operations of the Partnership to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies. In addition, some of the Partnership’s 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, one federal operating permit (a “Title V” permit) is 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. The Partnership has completed applications for the facilities for which these regulations apply.

   Risk Management Plans

     The Partnership is 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” following) to minimize the offsite consequences of catastrophic releases. The regulation requires a regulated source, in excess of threshold quantities, 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. The Company believes the operating expenses of the RMP regulations will not have a material adverse effect on the Partnership’s financial position, results of operations or cash flows.

   Solid Waste

     The Partnership generates 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,

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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 the operating expenses of the Partnership as well as the industry in general. The Partnership utilizes waste minimization and recycling processes to reduce the volume of its waste. The Partnership currently has one permitted on-site waste water treatment facility. Operating expenses of this facility has not had a material adverse effect on the financial position, results of operations or cash flows of the Partnership.

   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 its ordinary operations, the Partnership’s pipeline system generates wastes that may fall within CERCLA’s definition of a “hazardous substance.” In the event a disposal facility previously used by the Partnership requires clean up in the future, the Partnership 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, the Company was notified by the EPA of potential liability for alleged waste disposal at Container Recycling, Inc., located in Kansas City, Kansas. The Company was also asked to respond to an EPA Information Request. The Company’s response to the information request has been filed with the EPA Region VII office. Based on information the Company has received from the EPA, as well as through its internal investigations, the Company is pursuing dismissal from this matter.

   Other Environmental Proceedings

     In 1994, the Partnership and the Indiana Department of Environmental Management (“IDEM”) entered into an Agreed Order that resulted in the implementation of a remediation program for groundwater contamination attributable to the Partnership’s operations at the Seymour, Indiana, terminal. A Feasibility Study, which includes the Partnership’s proposed remediation program, was approved by IDEM in 1999. IDEM is expected to issue a Record of Decision formally approving the remediation program. After the Record of Decision is issued, the Partnership will enter into a subsequent Agreed Order for the continued operation and maintenance of the remediation program. The Partnership has an accrued liability of $0.6 million at December 31, 2001, for future remediation costs at the Seymour terminal. In the opinion of the Company, the completion of the remediation program will not have a future material adverse effect on the Partnership’s financial condition, results of operations or cash flows.

     In 1994, the Partnership was issued a compliance order from the Louisiana Department of Environmental Quality (“LDEQ”) relative to environmental contamination at the Partnership’s Arcadia, Louisiana, facility. This contamination may be attributable to the operations of the Partnership, as well as adjacent petroleum terminals operated by other companies. In 1999, the Partnership’s Arcadia facility and the adjacent terminals were directed by the Remediation Services Division of the LDEQ to pursue remediation of this containment phase. In the opinion of the Company, the completion of the remediation program that is proposed by the Partnership will not have a future material adverse effect on the Partnership’s financial condition, results of operations or cash flows.

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     During 2001, the Partnership accrued $8.6 million to complete environmental remediation activities at certain of the sites owned by TCTM and its subsidiaries. In establishing this accrual, the Partnership expensed $4.4 million for these environmental remediation costs and recorded a receivable of $4.2 million for the remainder. The receivable is based on a contractual indemnity obligation for specified environmental liabilities owed by DEFS to the Partnership in connection with the Partnership’s acquisition of the Upstream Segment from DEFS in November 1998. Under this indemnity obligation, the Partnership is responsible for the first $3.0 million in specified environmental liabilities, with DEFS becoming responsible for those environmental liabilities in excess of $3.0 million, up to a maximum amount of $25.0 million. At December 31, 2001, an accrual of $6.4 million remains outstanding related to TCTM environmental remediation activities. The majority of the indemnified costs relate to remediation activities at the Velma crude oil site in Stephens County, Oklahoma, attributable to operations prior to the Partnership’s acquisition of the Upstream Segment. Remediation activities at the Velma crude oil site are being conducted according to a work plan approved by the Oklahoma Corporation Commission. In the opinion of the Company, the completion of remediation programs associated with this release will not have a future material adverse effect on the Partnership’s financial condition, results of operations or cash flows.

Safety Regulation

     The Partnership is 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 its 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 make certain reports and provide information as required by the Secretary of Transportation. It is anticipated that the HLPSA will be reauthorized in 2002.

     The Partnership is 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 individuals performing a covered task must be qualified by October 2002.

     The Partnership is also subject to the OPS Integrity Management regulations which specifies 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, the Partnership has identified its HCA pipeline segments and will develop an IMP by March 31, 2002. The regulations require that initial HCA baseline integrity assessments are conducted within seven years, with all subsequent assessments conducted on a five-year cycle. The Partnership will evaluate each pipeline segment’s integrity by analyzing available information and develop a range of potential impacts resulting from a release to a HCA. The Partnership is currently developing cost estimates related to its baseline integrity assessments.

     The Partnership is also subject to the requirements of the federal OSHA and comparable state statutes. The Partnership believes it is 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 the Partnership to organize and disclose information about the hazardous materials used in its operations. Certain parts of this

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information must be reported to employees, state and local governmental authorities, and local citizens upon request. The Partnership is 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. The Partnership utilizes certain covered processes and maintains 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 boiling point without benefit of chilling or refrigeration are exempt. The Partnership believes it is in material compliance with the PSM regulations.

     In general, the General Partner expects to increase the expenditures of the Partnership 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, the Company does not believe that they will have a future material adverse effect on the Partnership’s financial condition, results of operations or cash flows.

Employees

     The Partnership does not have any employees, officers or directors. The General Partner is responsible for the management of the Partnership and Operating Partnerships. As of December 31, 2001, the General Partner had 919 employees.

Item 3. Legal Proceedings

Toxic Tort Litigation — Seymour, Indiana

     In the fall of 1999 and on December 1, 2000, the Company and the Partnership were named as defendants in two separate lawsuits in Jackson County Circuit Court, Jackson County, Indiana, in Ryan E. McCleery and Marcia S. McCleery, et. al. v. Texas Eastern Corporation, et. al. (including the Company and Partnership) and Gilbert Richards and Jean Richards v. Texas Eastern Corporation, et. al. (including the Company and Partnership). In both cases, the plaintiffs contend, among other things, that the Company 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. The Company has filed an answer to both complaints, denying the allegations, as well as various other motions. These cases are in the early stages of discovery and are not covered by insurance. The Company is defending itself vigorously against the lawsuits. The plaintiffs have not stipulated the amount of damages they are seeking in the suit. The Partnership cannot estimate the loss, if any, associated with these pending lawsuits.

Other Litigation

     On December 21, 2001, the Partnership was named as a defendant in a lawsuit in the 10th Judicial District, Natchitoches Parish, Louisiana in Rebecca L. Grisham et. al. v. TE Products Pipeline Company, Limited Partnership. In this case, the plaintiffs contend that the defendant’s 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. The Partnership has 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. The Partnership is defending itself vigorously against the lawsuit. The Partnership cannot estimate the damages, if any, associated with this pending lawsuit, however, this case is covered by insurance.

     In addition to the litigation discussed above, the Partnership has 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. The Company believes that the outcome of such lawsuits and other proceedings will not

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individually or in the aggregate have a future material adverse effect on the Partnership’s consolidated financial condition, 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

     The Limited Partner Units of the Partnership are listed and traded on the New York Stock Exchange under the symbol TPP. The high and low trading prices of the Limited Partner Units in 2001 and 2000, respectively, as reported in The Wall Street Journal, were as follows:

     Based on the information received from its transfer agent and from brokers and nominees, the Company estimates the number of beneficial unitholders of Limited Partner Units of the Partnership as of March 7, 2002, to be approximately 31,000.

     The quarterly cash distributions applicable to 2000 and 2001 were as follows:

     The Partnership makes quarterly cash distributions of its Available Cash, as defined by the Partnership Agreement. Available Cash generally consists of all cash receipts less cash disbursements and cash reserves necessary for working capital, anticipated capital expenditures and contingencies the General Partner deems appropriate and necessary.

     The Partnership is a publicly traded master limited partnership that is not subject to federal income tax. Instead, unitholders are required to report their allocated share of the Partnership’s income, gain, loss, deduction and credit, regardless of whether the Partnership makes distributions.

     Distributions of cash by the Partnership 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 held 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, selected consolidated financial and operating data for the Partnership. The financial data was derived from the consolidated financial statements of the Partnership and should be read in conjunction with the Partnership’s 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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(5)

Per Unit calculation for all periods reflects the two-for-one split on August 10, 1998. Per Unit calculation includes 3,916,547 Class B Units issued on November 1, 1998; 3,700,000 Limited Partner Units issued in 2000; and 7,750,000 Limited Partner Units issued in 2001.

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 the 2001, 2000 and 1999 consolidated financial statements and accompanying notes of the Partnership 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 the Partnership’s 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.

     The Partnership operates and reports in three business segments:

	•		Downstream Segment — interstate transportation, storage and terminaling of petroleum products and LPGs, intrastate transportation of petrochemicals and the fractionation of NGLs — conducted primarily through TE Products and its subsidiary;
	•		Upstream Segment — transportation, aggregation and marketing of crude oil and NGLs and the distribution of lube oils and specialty chemicals — conducted primarily through TCTM and its subsidiaries; and
	•		Midstream Segment — gathering of natural gas in the Green River Basin in southwestern Wyoming — conducted primarily through TEPPCO Midstream and its interest in Jonah.

     The Partnership’s reportable segments offer different products and services and are managed separately because each requires different business strategies. Each of the subsidiaries of the Partnership that are limited partnerships is managed by TEPPCO GP, a wholly-owned subsidiary of the Partnership that acts as managing general partner with a 0.001% general partner interest.

     The Downstream Segment revenues are derived from the transportation of refined products and LPGs, the storage and short-haul shuttle transportation of LPGs at the Mont Belvieu complex, intrastate transportation of petrochemicals, fractionation of NGLs, sale of product inventory and other ancillary services. Labor and electric power costs comprise the two largest operating expense items of the Downstream Segment. Operations are somewhat seasonal with higher revenues generally realized during the first and fourth quarters of each year. 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.

     The Upstream Segment revenues are earned from the gathering, storage, transportation and marketing of crude oil and NGLs and the distribution of lube oils and specialty chemicals, principally in Oklahoma, Texas and the Rocky Mountain region. Marketing operations consist primarily of aggregating purchased crude oil along its 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.

     On July 20, 2000, the Partnership completed an acquisition of assets from ARCO for $322.6 million, which included $4.1 million of acquisition-related costs other than the purchase price. An additional $11.0 million was paid in October 2001, for final post-closing adjustments. The purchased assets included ARCO’s 50-percent voting interest in Seaway. The Partnership assumed ARCO’s role as operator of this pipeline. The Company also acquired ARCO’s crude oil terminal facilities in Cushing and Midland, including the line transfer and pumpover business at

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each location, an undivided ownership interest in both the Rancho Pipeline and the Basin Pipeline, both of which are operated by another joint owner, and the receipt and delivery pipelines known as the West Texas Trunk System, located around the Midland terminal. The transaction was accounted for under the purchase method of accounting. The results of operations of the assets acquired have been included in the Upstream Segment since the purchase on July 20, 2000.

     The Midstream Segment commenced operations on September 30, 2001, when the Partnership acquired Jonah from Alberta Energy Company for $359.8 million. An additional $7.2 million was accrued December 31, 2001, for final purchase 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 are included in the Partnership’s consolidated financial statements in the fourth quarter of 2001. The Jonah assets are managed and operated by DEFS under a contract arrangement.

Critical Accounting Policies

   Estimates

     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 and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. Changes in these estimates could materially affect the financial condition, results of operations or cash flows.

   Environmental Costs

     The Partnership accrues 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. The balance of accrued undiscounted environmental liabilities are monitored on a regular basis by management. Liabilities for environmental costs at a specific site are initially recorded when the Partnership’s 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 the Partnership’s 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

     Statement of Financial Accounting Standards (“SFAS”) No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of requires that an entity review long-lived assets, including property, plant and equipment, whenever events occur that indicate that the book value of an asset may not be recoverable in the future. In August 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS 144 supercedes SFAS 121, but retains its fundamental provisions for reorganizing and measuring impairment losses on long-lived assets held for use and long-lived assets to be disposed of by sale. During the second quarter of 2001, Pennzoil-Quaker State Company (“Pennzoil”) sold its Shreveport, Louisiana, refinery and canceled refined products production. Pennzoil and TE Products negotiated a settlement of $18.9 million to terminate a long-term transportation agreement from the Shreveport origin point on the Products Pipeline System. Under the transportation agreement, Pennzoil had a throughput commitment of 25,000 barrels per day. The Partnership is pursuing various alternatives related to the reduced receipt volumes including making system changes to allow for bi-directional product flow to make

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deliveries into the Shreveport market area. The Partnership has 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. The termination payment was recorded as refined products transportation revenue in 2001. However, if alternative revenue sources are not realized on this pipeline segment, an impairment may be recorded, which could have a material adverse effect on the Partnership’s financial condition, results of operations or cash flows.

   Intangible Assets

     On September 30, 2001, the Partnership completed the purchase of all of the partnership interests of Jonah from Alberta Energy Company for $359.8 million. An additional $7.2 million was accrued at December 31, 2001, for final purchase adjustments related primarily to construction projects in progress at the time of closing. In connection with this acquisition, the Partnership assumed contracts that dedicate future production from natural gas wells in the Green River Basin in the State of Wyoming. The Partnership assigned $222.8 million of the purchase price to these production contracts based upon a fair value appraisal at the time of closing. The value assigned to intangible assets are amortized over the expected lives of the contracts (approximately 16 years) in proportion to the timing of the expected contractual volumes. On an annual basis, the Partnership will update production estimates of the natural gas wells and reassess the remaining useful life of the contract assets. Changes in the estimated remaining production could negatively impact the timing of amortization expense reported for future periods.

Results of Operations

     Summarized below is financial data by business segment (in thousands):

     The results for the year ended 2001, reflect the addition of the Midstream Segment for the fourth quarter of 2001, as a result of the acquisition of Jonah on September 30, 2001. The results for the year ended 2000, reflect the increased operations in the Upstream Segment resulting from the acquisition of the ARCO assets in July 2000, which results were impacted in 2001 as a result of having a full year of operations attributed to the former ARCO assets.

     Following is a detailed analysis of the results of operations, discussing the reasons for changes in results, by each operating segment of the Partnership.

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Downstream Segment

     Volume and average tariff information for 2001, 2000 and 1999 is presented below:

   2001 Compared to 2000

     For the year ended 2001, the Downstream Segment reported net income of $92.1 million, compared with net income of $60.7 million for the year ended 2000. The $31.4 million increase in net income was primarily due to a $34.9 million increase in operating revenues and a $1.7 million decrease in interest expense, partially offset by a $2.8 million increase in costs and expenses, $1.1 million in losses from equity investments, a $1.0 million decrease in capitalized interest and a $0.3 million decrease in other income — net. Factors influencing these variances are described below.

     Refined products transportation revenues increased $20.0 million for the year ended 2001, compared with 2000, primarily due to $18.9 million of revenue recognized on the canceled transportation agreement with Pennzoil and the recognition of $1.7 million of previously deferred revenue related to the approval of Market-Based Rates during the second quarter of 2001. See further discussion regarding these factors included in “Other Considerations.” These increases were partially offset by a 4% decrease in refined products volumes delivered. Deliveries of MTBE decreased 4.3 million barrels as a result of the expiration of contract deliveries to the Partnership’s marine terminal near Beaumont, Texas, in April 2001. As a result of the contract expiration, the Partnership no longer transports MTBE through its Products Pipeline System. Jet fuel volumes decreased 2.7 million barrels, or 10%, due to reduced air travel demand in the Midwest market areas. The total refined products volume decrease was partially offset by increased distillate demand in the South-Central market areas and increased distillate deliveries at a third-party terminal in Houston, Texas. The refined products average rate per barrel increased 5% from the prior-year period primarily due to an increased percentage of long-haul volumes delivered in 2001.

     LPGs transportation revenues increased $3.9 million for the year ended 2001, compared with 2000, primarily due to increased propane deliveries in the Midwest that resulted from favorable price differentials of Gulf Coast propane compared with competing Midwest supply sources. Additionally, increased feedstock demand resulted in higher deliveries of isobutane in the Chicago market area. Short-haul deliveries of propane along the upper Texas Gulf Coast decreased 29% from the prior year due to lower petrochemical feedstock demand and operational problems at a petrochemical facility served by the Partnership. The LPGs average rate per barrel

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increased 5% from the prior year as a result of an increased percentage of long-haul deliveries to the upper Midwest market areas.

     Revenues generated from Mont Belvieu operations increased $0.8 million during the year ended 2001, compared with 2000, as a result of increased loading fees, brine service revenue and butane segregation charges, partially offset by lower contract storage revenue. Mont Belvieu shuttle deliveries decreased 15% during the year ended 2001, compared with 2000, due to reduced propane and butane demand for petrochemical feedstock along the upper Texas Gulf Coast. The Mont Belvieu average rate per barrel increased in 2001 as a result of increased non-contract deliveries, which generally carry higher rates.

     Other operating revenues increased $10.2 million during the year ended 2001, compared with 2000, primarily due to an $8.9 million increase in contract petrochemical delivery revenue, which started during the fourth quarter of 2000, increased refined products loading fees, increased propane deliveries at the Providence, Rhode Island, import facility and increased gains on product sales. These increases were partially offset by losses incurred as a result of exchanging products at different geographic points of delivery to position product in the Midwest market area.

     Costs and expenses increased $2.8 million for the year ended 2001, compared with 2000, comprised of a $2.1 million increase in operating, general and administrative expenses, a $1.2 million increase in operating fuel and power expense and a $1.0 million increase in depreciation and amortization expense, partially offset by a $1.5 million decrease in taxes — other than income taxes. The increase in operating, general and administrative expenses was primarily due to increased employee benefit costs, increased supplies and services and environmental remediation expenses, partially offset by the March 2000 write-off of project evaluation costs related to the proposed pipeline construction from Beaumont, Texas, to Little Rock, Arkansas, and decreased product measurement losses. Operating fuel and power expense increased as a result of higher rates charged by electric utilities and increased long-haul volumes delivered. The increase in depreciation expense from the prior year period resulted from assets placed in service during the fourth quarter of 2000. The decrease in taxes — other than income taxes resulted from actual property taxes being lower than previously estimated.

     Interest expense attributable to the Downstream Segment decreased $1.7 million during the year ended 2001, compared with 2000, as a result of lower interest rates on borrowings under the variable-rate credit facilities and the favorable impact of the fixed-to-floating interest rate swap on the TE Products Senior Notes, effective October 4, 2001. Interest capitalized decreased $1.0 million during the year ended 2001, compared with 2000, as a result of the completion of the petrochemical pipelines from Mont Belvieu to Port Arthur, Texas, during the fourth quarter of 2000.

     Net loss from equity investments totaled $1.1 million during the year ended 2001 due primarily to pre-operating expenses of Centennial. Other income — net decreased $0.3 million during the year ended 2001, compared with 2000, due primarily to lower interest income earned on cash investments.

     The Downstream Segment is dependent in large part on the demand for refined petroleum products in the markets served by its pipelines. Reductions in that demand adversely affect the pipeline business of the Downstream Segment. Market demand varies based upon the different end uses of the refined products shipped in the Downstream Segment. Demand for gasoline, which has in recent years accounted for approximately one-half of the Downstream Segment’s refined products transportation revenues, depends upon price, prevailing economic conditions and demographic changes in the markets served in the Downstream Segment. Weather conditions, governmental policy and crop prices affect the demand for refined products used in agricultural operations. Demand for jet fuel, which has in recent years accounted for almost one-quarter of the Downstream Segment’s refined products revenues, depends on prevailing economic conditions and military usage. Propane deliveries are generally sensitive to the weather and meaningful year-to-year variances have occurred and will likely continue to occur.

   2000 Compared to 1999

     For the year ended 2000, net income of the Downstream Segment decreased $0.5 million compared with 1999 primarily due to a $5.8 million increase in costs and expenses and a $3.8 million increase in interest expense,

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partially offset by a $6.4 million increase in operating revenues and a $2.4 million increase in capitalized interest. Factors influencing these variances are described below.

     Refined products transportation revenues decreased $3.7 million for the year ended 2000, compared with 1999, as a result of a 3% decrease in total refined products volumes delivered. Motor fuel volumes delivered decreased by 2.5 million barrels and distillate volumes delivered decreased by 1.8 million barrels due primarily to a local refinery expansion in the West Memphis market and unfavorable price differentials in the Midwest market area. Natural gasoline volumes delivered declined 1.3 million barrels due primarily to the expiration of a contract in late 1999 for deliveries to the Chicago area, along with unfavorable processing and blending economics in the Chicago market area. These decreases were primarily offset by a 1.2 million barrel increase in jet fuel volumes delivered due to continued strong demand in the Chicago market area and at the Cincinnati airport that is supplied by the Partnership. The Partnership deferred recognition of approximately $1.5 million of revenue during the year ended 2000, with respect to potential refund obligations for rates charged in excess of the PPI Index while its application for Market-Based Rates was under review by the FERC.

     LPGs transportation revenues increased $6.2 million for the year ended 2000, compared with 1999, due to a 5% increase in volumes delivered and a 3% increase in the average LPGs tariff per barrel. Colder winter weather during the first and fourth quarters of 2000, coupled with lower customer storage levels contributed to a 1.2 million barrel increase in propane volumes delivered in the Northeast market area and a 0.9 million barrel increase in propane volumes delivered in the Midwest market area. Increased refinery demand in the Northeast market area resulted in a 0.2 million barrel increase in butane volumes delivered. The larger percentage of long-haul deliveries during 2000 resulted in a 3% increase in the average LPGs tariff per barrel.

     Revenues generated from Mont Belvieu operations increased $0.5 million for the year 2000, compared with 1999, primarily due to increased brine handling fees and higher storage revenue.

     Other operating revenues increased $3.4 million during the year ended 2000, compared with 1999, primarily due to $1.8 million of deficiency revenue recognized in the fourth quarter of 2000 related to the beginning of a 20-year contract for petrochemical deliveries at Port Arthur, and a $0.5 million increase in gains on the sale of product inventory attributable to higher market prices in 2000. The additional increases resulted from increased refined products terminaling revenue and increased custody transfer services at Mont Belvieu facilities.

     Costs and expenses of the Downstream Segment increased $5.8 million during the year ended 2000, compared with 1999, due to a $2.9 million increase in operating, general and administrative expenses, a $2.3 million increase in operating fuel and power expense and a $0.6 million increase in depreciation and amortization charges. The increase in operating, general and administrative expenses was primarily attributable to $0.9 million of expense recognized in the first quarter of 2000 to write-off project evaluation costs, a $2.3 million increase in general and administrative supplies and services, a $1.5 million increase in legal services, a $1.0 million increase in pipeline operations and maintenance expenses, a $0.7 million increase in labor related expenses and a $0.3 million increase in product measurement losses. The write-off of project evaluation costs resulted from the announcement in March 2000 of the Partnership’s abandonment of its plan to construct a pipeline from Beaumont to Little Rock in favor of participation in the Centennial joint venture. These increases in operating, general and administrative expenses were partially offset by a $3.9 million decrease in expenses associated with Year 2000 activities incurred in 1999. The increase in operating fuel and power expense from the prior year resulted primarily from higher fuel prices charged by electric utilities in 2000. Depreciation and amortization expense increased as a result of $0.3 million in depreciation expense related to the completion of the petrochemical pipelines and other capital additions placed in service throughout 2000.

     Interest expense attributable to the Downstream Segment increased $3.8 million during the year ended 2000, compared with 1999, as a result of borrowings under a term loan to finance construction of the petrochemical pipelines between Mont Belvieu and Port Arthur. Additionally, amortization of debt issue costs increased $0.8 million during the year ended 2000. The increase in interest expense was offset by increased interest capitalized of $2.4 million during the year ended 2000, as a result of higher balances associated with construction of the petrochemical pipelines.

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     Other income — net increased $0.2 million during the year ended 2000, compared with 1999, as a result of gains on the sale of right-of-way easements during the second quarter of 2000, coupled with increased interest income earned on cash investments in 2000.

Upstream Segment

     Margin of the Upstream Segment is calculated as revenues generated from the sale of crude oil and lubrication oil, and transportation of crude oil and NGLs, less the costs of purchases of crude oil and lubrication oil. Margin is 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. Margin and volume information for the years ended 2001, 2000 and 1999 is presented below (in thousands, except per barrel and per gallon amounts):