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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

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

For the Fiscal Year ended December 31, 2002

Commission File Number 1-13603

TE Products Pipeline Company, Limited Partnership

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

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

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

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

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

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

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

Documents Incorporated by Reference: None

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Items 1 and 2. Business and Properties

General

     TE Products Pipeline Company, Limited Partnership (the “Partnership”), a Delaware limited partnership, was formed in March 1990. TEPPCO Partners, L.P. (the “Parent Partnership”) owns a 99.999% interest in us as the sole limited partner. TEPPCO GP, Inc. (“TEPPCO GP” or “General Partner”), a subsidiary of the Parent Partnership, holds a 0.001% General Partner interest in us. Texas Eastern Products Pipeline Company, LLC (the “Company”), a Delaware limited liability company, serves as the general partner of our Parent Partnership. The Company is a wholly owned subsidiary of Duke Energy Field Services, LLC (“DEFS”), a joint venture between Duke Energy Corporation (“Duke Energy”) and ConocoPhillips. Duke Energy holds an approximate 70% interest in DEFS and ConocoPhillips holds the remaining 30%. TEPPCO GP, as general partner, performs all of our management and operating functions required according to the Agreement of Limited Partnership of TE Products Pipeline Company, Limited Partnership (the “Partnership Agreement”). We reimburse our General Partner and the Company for all reasonable direct and indirect expenses that they incur in managing us.

     As used in this Report, “we,” “us,” and “our” means TE Products Pipeline Company, Limited Partnership.

     We operate and report in one business segment: transportation and storage of refined products, liquefied petroleum gases (“LPGs”) and petrochemicals. Our interstate transportation operations, including rates charged to customers, are subject to regulations prescribed by the Federal Energy Regulatory Commission (“FERC”). Refined products, LPGs and petrochemicals are referred to in this Report, collectively, as “petroleum products” or “products.”

     Effective January 1, 2002, our Parent Partnership realigned its business segments to reflect its entry into the natural gas gathering business and the expanded scope of its natural gas liquids (“NGLs”) operations. As part of this realignment, on May 31, 2002, we transferred our investment in TEPPCO Colorado, LLC (“TEPPCO Colorado”), which fractionates NGLs, to TEPPCO Midstream Companies, L.P. (“TEPPCO Midstream”) for the book value of TEPPCO Colorado’s net assets, which was $4.1 million. In connection with the transfer, we received $4.1 million in cash from TEPPCO Midstream. As a result of the transfer, the results of operations of TEPPCO Colorado for the periods presented are reflected as discontinued operations (see Note 18. Discontinued Operations in the Notes to Consolidated Financial Statements). We have reclassified prior periods presented to reflect the current presentation.

     Our strategy is to expand and improve service in our current markets, maintain the integrity of our pipeline systems and pursue growth initiatives that are balanced between internal projects and acquisitions. We intend to leverage the advantages inherent in our pipeline systems to maintain our status as a preferred provider in our market areas. We also intend to grow by acquiring assets, from both third parties and affiliates, which complement existing businesses or to establish new core businesses. We routinely evaluate opportunities to acquire assets and businesses that will complement existing operations with a view to increasing earnings and cash available for distribution. We may fund additional acquisitions with cash flow from operations, borrowings and capital contributions from the Parent Partnership, the issuance of debt in the capital markets or any combination thereof.

Operations

     We conduct business, own and operate properties located in 13 states. These operations consist of interstate transportation, storage and terminaling of petroleum products; short-haul shuttle transportation of LPGs at the Mont Belvieu, Texas complex; intrastate transportation of petrochemicals and other ancillary services.

     As an interstate common carrier, our pipeline offers interstate transportation services, pursuant to tariffs filed with the FERC, to any shipper of refined petroleum products and LPGs who requests such services, provided that the products tendered for transportation satisfy the conditions and specifications contained in the applicable tariff. In addition to the revenues received by our pipeline system from our interstate tariffs, we also receive

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revenues from the shuttling of LPGs between refinery and petrochemical facilities on the upper Texas Gulf Coast and ancillary transportation, storage and marketing services at key points along the pipeline system. Substantially all of the petroleum products transported and stored in the pipeline system are owned by our 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. Our pipeline system is the only pipeline that transports LPGs from the upper Texas Gulf Coast to the Northeast.

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

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

Centennial Pipeline Equity Investment

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

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

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additional interest in Centennial from PEPL for $20.0 million each, increasing our percentage ownerships in Centennial to 50% each. In connection with the acquisition of the additional interest in Centennial, the guaranty agreement between us, Marathon and PEPL was terminated. Our guaranty of up to a maximum of $75.0 million of Centennial’s debt remains in effect.

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

Refined Products, LPGs and Petrochemical Pipeline Systems

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

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

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

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

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

     Our 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

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Hook, Pennsylvania (near Philadelphia). The Pipeline System east of Todhunter and ending in Selkirk is an 8-inch diameter line, and the line starting at Greensburg and ending at Marcus Hook varies in diameter from 6 inches to 8 inches.

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

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

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

Major Business Sector Markets

     Our major operations are the transportation, storage and terminaling of refined petroleum products and LPGs along our mainline system, and the storage and short-haul transportation of LPGs associated with our Mont Belvieu LPG operations. Product deliveries, in millions of barrels (MMBbls) on a regional basis, for the years ended December 31, 2002, 2001 and 2000 were as follows:

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

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

     Refined Products Mainline Transportation

     Our 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 that we own, connecting pipelines and customer-owned terminals.

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

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

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     LPGs Mainline Transportation

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

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

     Mont Belvieu LPGs Storage and Pipeline Shuttle

     A key aspect of our Pipeline System’s LPGs business is our 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.

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

     In February 2000, we entered into a joint marketing and development alliance with Louis Dreyfus Plastics Corporation, now known as Louis Dreyfus Energy Services, L.P. (“Louis Dreyfus”), in which our Mont Belvieu LPGs storage and transportation shuttle system services were jointly marketed by Louis Dreyfus and us. The purpose of the alliance was to expand services to the upper Texas Gulf Coast energy marketplace by increasing pipeline throughput and the mix of products handled through the existing system and establishing new receipt and delivery connections. The alliance was a service-oriented, fee-based venture with no commodity trading activity. We operated the facilities for the alliance. Under the alliance, Louis Dreyfus invested $6.1 million for expansion projects at Mont Belvieu. The alliance also stipulated that if certain earnings thresholds were achieved, a partnership between us and Louis Dreyfus was to be created effective January 1, 2003. All terms and earnings thresholds have been met; therefore, we will be contributing our Mont Belvieu assets to the newly formed partnership. The economic terms of the partnership are the same as those under the joint development and marketing alliance. We will continue to operate the facilities for the partnership. The net book value of the Mont Belvieu assets and liabilities that we are contributing to the partnership is approximately $68.2 million. Our interest in the partnership will be accounted for as an equity investment.

     Other Operating Revenues

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

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Customers

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

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

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

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

Competition

     Our 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, our Pipeline System’s most significant competitors (other than indigenous production in our markets) are pipelines in the areas where the Pipeline System delivers products. Competition among common carrier pipelines is based primarily on transportation charges, quality of customer service and proximity to end users. We believe the Pipeline System 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 our 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 our tariffs. We face competition from rail movements of LPGs from Sarnia, Ontario, Canada, and waterborne imports into New Hampshire.

Title to Properties

     We believe we have satisfactory title to all of our assets. The properties are subject to liabilities in certain cases, such as customary interests generally contracted in connection with acquisition of the properties, liens for taxes not yet due, easements, restrictions, and other minor encumbrances. We believe none of these liabilities materially affect the value of our properties or our interest in the properties or will materially interfere with their use in the operation of our business.

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Capital Expenditures

     Capital expenditures, excluding acquisitions, totaled $60.9 million for the year ended December 31, 2002. Revenue generating projects include those projects which expand service into new markets or expand capacity into current markets. Capital expenditures to sustain existing operations include projects required by regulatory agencies or required life-cycle replacements. System upgrade projects improve operational efficiencies or reduce cost. We capitalize interest costs incurred during the period that construction is in progress. The following table identifies capital expenditures for the year ended December 31, 2002 (in millions):

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

     We estimate that capital expenditures, excluding acquisitions, for 2003 will be approximately $34.6 million (which includes $1.9 million of capitalized interest). We expect to use approximately $9.4 million for revenue generating projects which will include approximately $7.5 million for the expansion of our pumping capacity for LPGs into the Northeast markets and approximately $1.9 million for expansion of deliverability capacity at various locations throughout the system. We expect to spend approximately $17.5 million to sustain existing operations, including the replacement of storage tanks and pipeline rehabilitation projects to comply with regulations enacted by the United States Department of Transportation Office of Pipeline Safety (“OPS”) and the installation of replacement electrical distribution facilities at our Mont Belvieu facilities. An additional $5.8 million will be expended on other replacements and system upgrade projects. We continually review and evaluate potential capital improvements and expansions that would be complementary to our present system. These expenditures can vary greatly depending on the magnitude of our transactions. We may finance capital expenditures through internally generated funds, debt or capital contributions from our Parent Partnership or any combination thereof.

Regulation

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

     Rates of interstate refined petroleum products pipeline companies, like us, are currently regulated by the FERC primarily through an index methodology, which allows a pipeline to change its rates based on the change from year to year in the Producer Price Index for finished goods (“PPI Index”). Effective as of February 24, 2003, FERC Order on Remand modified the PPI Index from PPI — 1% to PPI. In the alternative, interstate refined petroleum products 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 refined petroleum products pipeline company that the rate is acceptable (“Settlement Rates”).

     On May 11, 1999, we 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

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granting us Market-Based Rates in certain markets and set for hearing our application for Market-Based Rates in certain destination markets and origin markets. After the matter was set for hearing, we entered into a settlement agreement with the protesting shippers resolving our respective differences. On April 25, 2001, the FERC issued an order approving the offer of settlement. As a result of the settlement, we recognized approximately $1.7 million of previously deferred transportation revenue in the second quarter of 2001. As a part of the settlement, we withdrew our application for Market-Based Rates to the Little Rock, Arkansas, and Arcadia and Shreveport-Arcadia, Louisiana, destination markets, which are currently subject to the PPI Index. As a result, we made refunds of approximately $1.0 million in the third quarter of 2001 for those destination markets.

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

Environmental Matters

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

     Water

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

     Contamination resulting from spills or releases of petroleum products is an inherent risk within the petroleum pipeline industry. To the extent that groundwater contamination requiring remediation exists along our pipeline systems as a result of past operations, we believe any such contamination could be controlled or remedied without having a material adverse effect on our financial position, but such costs are site specific, and we cannot assure you that the effect will not be material in the aggregate.

     The primary federal law for oil spill liability is the Oil Pollution Act of 1990 (“OPA”), which addresses three principal areas of oil pollution — prevention, containment and cleanup, and liability. OPA applies to vessels, offshore platforms and onshore facilities, including terminals, pipelines and transfer facilities. In order to handle, store or transport oil, shore facilities are required to file oil spill response plans with the appropriate federal agency

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being either the United States Coast Guard, the OPS or the Environmental Protection Agency (“EPA”). Numerous states have enacted laws similar to OPA. Under OPA and similar state laws, responsible parties for a regulated facility from which oil is discharged may be liable for removal costs and natural resource damages.

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

     Air Emissions

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

     Risk Management Plans

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

     Solid Waste

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

     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

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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, our pipeline system generates wastes that may fall within CERCLA’s definition of a “hazardous substance.” In the event a disposal facility previously used by us requires clean up in the future, we may be responsible under CERCLA for all or part of the costs required to clean up sites at which such wastes have been disposed.

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

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

     Other Environmental Proceedings

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

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

DOT Pipeline Compliance Matters

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

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

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

Safety Matters

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

     The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require us to organize and disclose information about the hazardous materials used in our operations. Certain parts of this information must be reported to employees, state and local governmental authorities, and local citizens upon request. We are subject to OSHA Process Safety Management (“PSM”) regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves a flammable liquid or gas, as defined in the regulations, stored on-site in one location, in a quantity of 10,000 pounds or more. We utilize certain covered processes and maintain storage of LPGs in pressurized tanks, caverns and wells, in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling point without benefit of chilling or refrigeration are exempt. We believe we are in material compliance with the OSHA regulations.

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

Employees

     We do not have any employees, officers or directors. The General Partner is responsible for our management. The Company is responsible for the management of our Parent Partnership. As of December 31, 2002, the Company had 970 employees. Certain employees of the Company may devote all or a portion of their time to us.

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Available Information

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

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

Item 3. Legal Proceedings

Toxic Tort Litigation — Seymour, Indiana

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

Other Litigation

     On December 21, 2001, we were named as a defendant in a lawsuit in the 10th Judicial District, Natchitoches Parish, Louisiana, styled Rebecca L. Grisham et. al. v. TE Products Pipeline Company, Limited Partnership. In this case, the plaintiffs contend that our pipeline, which crosses the plaintiff’s property, leaked toxic products onto the plaintiff’s property. The plaintiffs further contend that this leak caused damages to the plaintiffs. We have filed an answer to the plaintiff’s petition denying the allegations. The plaintiffs have not stipulated the amount of damages they are seeking in the suit. We are defending ourself vigorously against the lawsuit. We 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, we have been, in the ordinary course of business, a defendant in various lawsuits and a party to various other legal proceedings, some of which are covered in whole or in part by insurance. We believe that the outcome of these lawsuits and other proceedings will not individually or in the aggregate have a future material adverse effect on our consolidated financial position, results of operations or cash flows.

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

     None.

PART II

Item 5. Market for Registrant’s Common Equity and Related Partnership Interest Matters

     TEPPCO Partners, L.P. owns a 99.999% interest as the sole limited partner interest and TEPPCO GP, Inc. owns a 0.001% general partner interest in us. There is no established public trading market for our ownership interests.

     We make periodic distributions of our available cash to our partners. Available cash consists generally of all cash receipts less cash disbursements and cash reserves necessary for working capital, anticipated capital expenditures and contingencies we deem appropriate and necessary.

     We are a limited partnership, and we are not subject to federal income tax. Instead, the partners are required to report their allocable share of our income, gain, loss, deduction and credit, regardless of whether we make distributions.

Item 6. Selected Financial Data

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

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

General

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

     We operate and report in one business segment: transportation and storage of refined products, LPGs, and petrochemicals. Revenues are earned from the transportation of refined products and LPGs, storage and short-haul shuttle transportation of LPGs at the Mont Belvieu complex, intrastate transportation of petrochemicals, sale of product inventory and other ancillary services. The two largest operating expense items are labor and electric power. We generally realize higher revenues during the first and fourth quarters of each year since our operations are somewhat seasonal. Refined products volumes are generally higher during the second and third quarters because of greater demand for gasolines during the spring and summer driving seasons. LPGs volumes are generally higher from November through March due to higher demand in the Northeast for propane, a major fuel for residential heating. Our results also include our equity investment in Centennial.

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Critical Accounting Policies

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

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

     Revenue and Expense Accruals

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

     Environmental Costs

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

     Property, Plant and Equipment

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

     We evaluate impairment of long-lived assets in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 121, Accounting for the Impairment of Long-Lived Assets to Be Disposed Of, and effective

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

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

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

Results of Operations

     The following table presents volume and average tariff information for the years ended December 31, 2002, 2001 and 2000:

     Year Ended December 31, 2002 Compared to Year Ended December 31, 2001

     We reported net income of $55.3 million for the year ended December 31, 2002, compared with net income of $92.7 million for the year ended December 31, 2001. Net income decreased $37.4 million primarily due to a decrease of $20.7 million in operating revenues, an increase of $13.9 million in costs and expenses, additional losses

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of $5.7 million from equity investments, a decrease of $0.6 million in other income — net, a decrease of $0.3 million in interest capitalized and a decrease of $0.8 million in income from discontinued operations. The decreases to net income were partially offset by a decrease of $4.6 million in interest expense. We discuss the factors influencing these variances below.

     Revenues from refined products transportation decreased $15.8 million for the year ended December 31, 2002, compared with the year ended December 31, 2001, primarily due to $18.9 million of revenue recognized in 2001 from a cash settlement received from a 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 decreases were partially offset by a 12% increase in refined products volumes delivered during the year ended December 31, 2002, primarily due to barrels received into our pipeline from Centennial at Creal Springs, Illinois. Centennial commenced refined products deliveries to us beginning in April 2002. The overall increase in refined products deliveries was partially offset by a 1.3 million barrel decrease in MTBE deliveries as a result of the expiration of contract deliveries to our marine terminal near Beaumont effective April 2001. As a result of the contract expiration, we no longer transport MTBE through our Pipeline System. The refined products average rate per barrel decreased 9% from the prior year due to the impact of the Midwest origin point for volumes received from Centennial, which was partially offset by decreased short-haul MTBE volumes delivered, and higher market-based tariff rates, which went into effect in July 2001.

     Revenues from LPGs transportation decreased $3.2 million for the year ended December 31, 2002, compared with the year ended December 31, 2001, primarily due to decreased deliveries of propane in the upper Midwest and Northeast market areas attributable to warmer than normal weather in the first quarter of 2002. The decrease was also due to lower prices from competing Canadian and mid-continent propane supply as compared to propane originating from the Gulf Coast. Total LPGs volumes delivered increased 1% as a result of increased short-haul deliveries to a petrochemical facility on the upper Texas Gulf Coast. The LPGs average rate per barrel decreased 6% from the prior year as a result of a decreased percentage of long-haul deliveries during the year ended December 31, 2002.

     Revenues generated from Mont Belvieu operations increased $1.1 million during the year ended December 31, 2002, compared with the year ended December 31, 2001, as a result of increased storage revenue and receipt revenue. Mont Belvieu shuttle volumes delivered increased 25% during the year ended December 31, 2002, compared with the year ended December 31, 2001, due to increased petrochemical demand. The Mont Belvieu average rate per barrel decreased 17% during the year ended December 31, 2002, as a result of increased contract shuttle deliveries, which generally carry lower rates.

     Other operating revenues decreased $2.8 million during the year ended December 31, 2002, compared with the year ended December 31, 2001, primarily due to lower propane deliveries at our Providence import facility, lower refined products storage revenue, lower margins on product inventory sales and lower revenues from product location exchanges which are used to position product in the Midwest market area. These decreases were partially offset by increased refined products and LPGs loading fees.

     Costs and expenses increased $13.9 million for the year ended December 31, 2002, compared with the year ended December 31, 2001. The increase was comprised of an increase of $11.8 million in operating, general and administrative expenses, an increase of $3.4 million in depreciation and amortization expense and an increase of $3.1 million in taxes — other than income taxes. These increases were partially offset by a decrease of $4.4 million in operating fuel and power expense. Operating, general and administrative expenses increased primarily due to higher pipeline maintenance expenses, increased consulting and contract services, increased labor costs and increased general and administrative supplies expense. Depreciation expense increased from the prior year because of assets placed in service during 2002. Taxes — other than income taxes increased as a result of a higher property base in 2002. Operating fuel and power expense decreased as a result of decreased long-haul volumes delivered related to Midwest volumes received from Centennial and lower power costs.

     Interest expense decreased $4.6 million during the year ended December 31, 2002, compared with the year ended December 31, 2001, due to lower interest rates on the Note Payable, Parent Partnership. Interest capitalized decreased $0.3 million during the year ended December 31, 2002, compared with the year ended December 31,

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2001, due to decreased balances during 2002 on construction work-in-progress partially offset by interest capitalized on our investment in Centennial during its construction.

     Net losses from equity investments totaled $6.8 million during the year ended December 31, 2002, due to pre-operating expenses and start-up costs of Centennial, which commenced operations in early April 2002.

     Other income — net decreased $0.8 million for the year ended December 31, 2002, compared with the year ended December 31, 2001. The decrease was primarily due to lower interest income earned on cash investments.

     We are dependent in large part on the demand for refined petroleum products in the markets that we serve. Reductions in that demand adversely affect our pipeline business. Market demand varies based upon the different end uses of the refined products that we ship. Demand for gasoline, which in recent years has accounted for approximately one-half of our refined products transportation revenues, depends upon price, prevailing economic conditions and demographic changes in the markets that we serve. Weather conditions and governmental policy 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 our 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.

     Year Ended December 31, 2001 Compared to Year Ended December 31, 2000

     For the year ended December 31, 2001, we reported net income of $92.7 million, compared with net income of $61.3 million for the year ended December 31, 2000. Net income increased $31.4 million primarily due to an increase of $35.0 million in operating revenues and a decrease of $1.5 million in interest expense, partially offset by an increase of $2.8 million in costs and expenses, additional losses of $1.1 million from equity investments, a decrease of $1.0 million in capitalized interest, a decrease of $0.1 million in other income — net and a decrease of $0.1 million in income from discontinued operations. We discuss the factors influencing these variances below.

     Revenues from refined products transportation increased $20.0 million for the year ended December 31, 2001, compared with the year ended December 31, 2000, primarily due to $18.9 million of revenue recognized on the canceled transportation agreement with Pennzoil in 2001 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. 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 our marine terminal near Beaumont in April 2001. 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.

     Revenues from LPGs transportation increased $3.9 million for the year ended December 31, 2001, compared with the year ended December 31, 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 that we serve. The LPGs average rate per barrel 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 December 31, 2001, compared with the year ended December 31, 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 December 31, 2001, compared with the year ended December 31, 2000, due to reduced propane and butane demand for petrochemical feedstock along the upper Texas Gulf Coast.

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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 $10.3 million during the year ended December 31, 2001, compared with the year ended December 31, 2000, primarily due to an increase of $8.9 million in contract petrochemical delivery revenue, which began during the fourth quarter of 2000, increased refined products loading fees, increased propane deliveries from the Providence import facility and increased gains on product sales. These increases were partially offset by lower revenues from product location exchanges which are used to position product in the Midwest market area.

     Costs and expenses increased $2.8 million for the year ended December 31, 2001, compared with the year ended December 31, 2000, and were comprised of an increase of $2.1 million in operating, general and administrative expenses, an increase of $1.2 million in operating fuel and power expense and an increase of $1.0 million in depreciation and amortization expense, partially offset by a decrease of $1.5 million 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 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 decreased $1.5 million during the year ended December 31, 2001, compared with the year ended December 31, 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 Senior Notes, effective October 4, 2001. Interest capitalized decreased $1.0 million during the year ended December 31, 2001, compared with the year ended December 31, 2000, as a result of the completion of the petrochemical pipelines from Mont Belvieu to Port Arthur during the fourth quarter of 2000.

     Net losses from equity investments totaled $1.1 million during the year ended December 31, 2001, due primarily to pre-operating expenses of Centennial.

     Other income — net decreased $0.1 million during the year ended December 31, 2001, compared with the year ended December 31, 2000, due primarily to lower interest income earned on cash investments.

     Discontinued Operations

     Effective January 1, 2002, our Parent Partnership realigned its business segments to reflect its entry into the natural gas gathering business and the expanded scope of its NGLs operations. As part of this realignment, on May 31, 2002, we entered into an Assignment and Assumption Agreement with TEPPCO Midstream to transfer our investment in TEPPCO Colorado, which fractionates NGLs, to TEPPCO Midstream at the book value of TEPPCO Colorado’s net assets (see Note 18. Discontinued Operations). SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, requires that long-lived assets to be disposed of should be recorded at the lower of their carrying amount or fair value less costs to sell. As a result, in the quarter ended June 30, 2002, we compared the fair value of TEPPCO Colorado to its carrying value and noted no indication of impairment.

     As a result of the transfer, our financial position and results of operations have been reclassified to reflect revenue, expenses, assets and liabilities of TEPPCO Colorado as discontinued operations. Condensed statements of income are shown below for TEPPCO Colorado for the years ended December 31, 2002, 2001 and 2000 (in thousands):

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     The following table presents volume and average rate information for TEPPCO Colorado for the years ended December 31, 2002, 2001 and 2000:

Financial Condition and Liquidity

     Net cash from operations totaled $107.6 million for the year ended December 31, 2002. This cash was made up of $84.5 million of income before charges for depreciation and amortization, $21.9 million of cash provided by working capital changes, and $1.2 million of cash from discontinued operations. Net cash from operations totaled $123.1 million for the year ended December 31, 2001, comprised of $117.7 million of income before charges for depreciation and amortization, $6.5 million of cash from discontinued operations partially offset by $1.1 million of cash used for working capital changes. Net cash from operations totaled $87.5 million for the year ended December 31, 2000, comprised of $85.3 million of income before charges for depreciation and amortization, $0.5 million of cash provided by working capital changes and $1.7 million of cash from discontinued operations. Net cash from operations for the years ended December 31, 2002, 2001 and 2000 included interest payments of $25.0 million, $31.0 million, and $29.0 million, respectively.

     Cash flows used in investing activities totaled $64.3 million during the year ended December 31, 2002, and were comprised of $60.9 million of capital expenditures and $10.9 million of cash contributions for our ownership interest in Centennial, partially offset by $3.4 million of cash proceeds from the sale of assets and $4.1 million of cash proceeds from the sale of TEPPCO Colorado. Cash flows used in investing activities totaled $142.1 million during the year ended December 31, 2001, and were comprised of $81.4 million of capital expenditures and $64.9 million of cash contributions for our ownership interest in Centennial, partially offset by $4.2 million of net proceeds received from cash investments. Cash flows used in investing activities totaled $60.1 million during the year ended December 31, 2000, and were comprised of $56.5 million of capital expenditures and $5.0 million of cash contributions for our ownership interest in Centennial, partially offset by $1.4 million of net proceeds received from cash investments.

     Cash flows used in financing activities totaled $46.5 million during the year ended December 31, 2002, and were comprised of $94.9 million of distributions paid to our Parent Partnership and $150.0 million of repayments on our term loan, partially offset by $186.1 million of proceeds from our term loan and $12.3 million of equity

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contributions received from our Parent Partnership. Cash flows provided by financing activities totaled $13.5 million during the year ended December 31, 2001, and were comprised of $166.1 million of proceeds from our term loan, $1.2 million of advances from our Parent Partnership and $24.0 million of equity contributions from our Parent Partnership, partially offset by $96.9 million of repayments on our term loan and $80.9 million of distributions paid to our Parent Partnership. Cash flows used in financing activities totaled $34.5 million during the year ended December 31, 2000, and were comprised of $92.6 million of repayments on our term loan, $2.8 million of advances to our Parent Partnership and $70.8 million of distributions paid to our Parent Partnership, partially offset by $115.4 million of proceeds from our term loan and $16.3 million of equity contributions from our previous general partner and Parent Partnership.

     In August 2000, we entered into agreements with PEPL and Marathon to form Centennial. Centennial owns an interstate refined petroleum products pipeline extending from the upper Texas Gulf Coast to Illinois. During the years ended December 31, 2002 and 2001, we contributed approximately $10.9 million and $70.0 million, respectively, for our investment in Centennial. These amounts are included in the equity investment balance at December 31, 2002 and 2001. Through February 9, 2003, each original participant owned a one-third interest in Centennial. On February 10, 2002, we and Marathon each acquired an additional 16.7% interest in Centennial, bringing our ownership interest to 50% each. Excluding our purchase of the additional ownership interest of 16.7% on February 10, 2003, we expect to contribute an additional $10.0 million to Centennial in 2003.

     Centennial entered into credit facilities totaling $150.0 million, and as of December 31, 2002, $150.0 million was outstanding under those credit facilities. The proceeds were used to fund construction and conversion costs of its pipeline system. Each of the participants in Centennial, including us, originally guaranteed one-third of Centennial’s debt, up to a maximum amount of $50.0 million. During the third quarter of 2002, PEPL, one of the participants in Centennial, was downgraded by Moody’s and Standard & Poors to below investment grade, which resulted in PEPL being in default under its portion of the Centennial guaranty. Effective September 27, 2002, we and Marathon increased our guaranteed amounts to one-half of the debt of Centennial, up to a maximum amount of $75.0 million each, to avoid a default on the Centennial debt. As compensation to us and Marathon for providing our additional guarantees, PEPL was required to pay interest at a rate of 4% per annum to each of us and Marathon on the portion of the additional guaranty that we had provided for PEPL. In connection with the acquisition of the additional interest in Centennial on February 10, 2003, the guaranty agreement between Marathon, PEPL and us was terminated. Our guaranty of up to a maximum of $75.0 million of Centennial’s debt remains in effect.

     In February 2000, we entered into a joint marketing and development alliance with Louis Dreyfus in which our Mont Belvieu LPGs storage and transportation shuttle system services were jointly marketed by Louis Dreyfus and us. The purpose of the alliance was to expand services to the upper Texas Gulf Coast energy marketplace by increasing pipeline throughput and the mix of products handled through the existing system and establishing new receipt and delivery connections. The alliance was a service-oriented, fee-based venture with no commodity trading activity. We operated the facilities for the alliance. Under the alliance, Louis Dreyfus invested $6.1 million for expansion projects at Mont Belvieu. The alliance also stipulated that if certain earnings thresholds were achieved, a partnership between us and Louis Dreyfus was to be created effective January 1, 2003. All terms and earnings thresholds have been met; therefore, we will be contributing our Mont Belvieu assets to the newly formed partnership. The economic terms of the partnership are the same as those under the joint development and marketing alliance. We will continue to operate the facilities for the partnership. The net book value of the Mont Belvieu assets and liabilities that we are contributing to the partnership is approximately $68.2 million. Our interest in the partnership will be accounted for as an equity investment.

     On February 20, 2002, the Parent Partnership issued $500.0 million principal amount of 7.625% Senior Notes due 2012. We and the Parent Partnership’s other significant operating subsidiaries, which include TCTM, L.P., TEPPCO Midstream and Jonah Gas Gathering Company, issued guarantees of this debt. On June 30, 2002, the Parent Partnership acquired the Val Verde Gathering System (“Val Verde”) through its subsidiary, Val Verde Gas Gathering Company, L.P., which also issued an unconditional guarantee of the Parent Partnership’s debt securities. The guarantees are full, unconditional and joint and several. The proceeds from the offering of the $500.0 million principal amount of 7.625% Senior Notes were used to reduce the outstanding balances of the Parent Partnership’s credit facilities.

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      On January 30, 2003, the Parent Partnership issued $200.0 million principal amount of 6.125% Senior Notes due 2013. We and the Parent Partnership’s other significant operating subsidiaries issued guarantees of this debt. The guarantees are full, unconditional and joint and several. The proceeds from the offering of the $200.0 million principal amount of 6.125% Senior Notes were used to reduce the outstanding principal of the Parent Partnership’s revolving credit facilities.

     Parent Partnership Credit Facilities

     We currently utilize debt financing available from our Parent Partnership through intercompany notes. The terms of the intercompany notes generally match the principal and interest payment dates under the Parent Partnership’s credit agreements. The interest rates charged by the Parent Partnership include the stated interest rate of the Parent Partnership, plus a premium to cover debt issuance costs. The interest rate is also decreased or increased to cover gains and losses, respectively, on any interest rate swaps that the Parent Partnership may have in place on its respective credit agreements. These credit facilities of the Parent Partnership are described below.

     On July 14, 2000, our Parent Partnership entered into a $75.0 million term loan and a $475.0 million revolving credit facility (“Three Year Facility”) and borrowed $75.0 million and $340.0 million, respectively, to finance the acquisition of assets from ARCO Pipe Line Company, a wholly owned subsidiary of Atlantic Richfield Company for $322.6 million. The acquired assets are held through TCTM, L.P., a 99.999% owned entity of the Parent Partnership. On April 6, 2001, the Three Year Facility was amended to provide for revolving borrowings of up to $500.0 million for a period of three years including the issuance of letters of credit of up to $20.0 million. The interest rate is based, at the Parent Partnership’s option, on either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement for the Three Year Facility contains restrictive financial covenants that require the Parent Partnership to maintain a minimum level of partners’ capital as well as maximum debt-to-EBITDA (earnings before interest expense, income tax expense and depreciation and amortization expense) and minimum fixed charge coverage ratios. On June 27, 2002, the Three Year Facility was amended to increase the maximum debt-to-EBITDA ratio covenant to allow the Parent Partnership to incur additional indebtedness to finance a portion of the purchase price of the acquisition of Val Verde from Burlington Resources Gathering Inc., a subsidiary of Burlington Resources Inc. On June 27, 2002, the Parent Partnership drew down the existing capacity of the Three Year Facility. During the fourth quarter of 2002, the Parent Partnership repaid $68.0 million of the outstanding balance of the Three Year Facility with proceeds from its November and December 2002 equity offerings. At December 31, 2002, $432.0 million was outstanding under the Three Year Facility.

     On April 6, 2001, the Parent Partnership entered into a 364-day, $200.0 million revolving credit agreement (“Short-term Revolver”). The interest rate is based, at the Parent Partnership’s option, on either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement contains restrictive financial covenants that require the Parent Partnership to maintain a minimum level of partners’ capital as well as maximum debt-to-EBITDA and minimum fixed charge coverage ratios. On March 28, 2002, the Short-term Revolver was extended for an additional period of 364 days, ending in March 2003. On June 27, 2002, the Short-term Revolver was amended to increase the maximum debt-to-EBITDA ratio covenant to allow the Parent Partnership to incur additional indebtedness to finance a portion of the Val Verde acquisition. On June 27, 2002, the Parent Partnership drew down $72.0 million under the Short-term Revolver to finance a portion of the Val Verde acquisition. In the fourth quarter of 2002, the Parent Partnership repaid the existing amounts outstanding under the Short-term Revolver with proceeds it received from the issuance of Limited Partner Units in November and December 2002. At December 31, 2002, no amounts were outstanding under this facility. In February 2003, our Parent Partnership gave notice that it will not renew the Short-term Revolver. As a result, the facility will expire on March 27, 2003.

     As of December 31, 2002 and 2001, we had intercompany notes payable to our Parent Partnership of $154.1 million and $117.9 million, respectively. At December 31, 2001, $72.5 million, included in current liabilities, related to our borrowings under the Parent Partnership’s Short-term Revolver described above. Our long-term portion at December 31, 2001, totaled $45.4 million and represented borrowings under the Parent Partnership’s Three Year Facility. During the year ended December 31, 2002, the Parent Partnership issued $500.0 million principal amount of 7.625% Senior Notes due 2012. The Parent Partnership used a portion of the proceeds to repay

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the Short-term Revolver. Thus, at December 31, 2002, no amounts were included in current liabilities as our portion of the Short-term Revolver had been repaid. Our long-term portion at December 31, 2002, totaled $154.1 million and represents borrowings by us under the Parent Partnership’s Three Year Facility and Senior Notes described above. The interest rate on the note payable, Parent Partnership at December 31, 2002, was 5.3%. At December 31, 2002, accrued interest includes $4.1 million due to the Parent Partnership. For the year ended December 31, 2002, interest costs incurred on the note payable, Parent Partnership totaled $7.2 million.

     Senior Notes

     On January 27, 1998, we completed the issuance of $180.0 million principal amount of 6.45% Senior Notes due 2008, and $210.0 million principal amount of 7.51% Senior Notes due 2028 (collectively the “Senior Notes”). The 6.45% Senior Notes were issued at a discount of $0.3 million and are being accreted to their face value over the term of the notes. The 6.45% Senior Notes due 2008 are not subject to redemption prior to January 15, 2008. The 7.51% Senior Notes due 2028, issued at par, may be redeemed at any time after January 15, 2008, at our option, in whole or in part, at a premium.

     The Senior Notes do not have sinking fund requirements. Interest on the Senior Notes is payable semiannually in arrears on January 15 and July 15 of each year. The Senior Notes are unsecured obligations and rank on a parity with all of our other unsecured and unsubordinated indebtedness. The indenture governing the Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit our ability to incur additional indebtedness. As of December 31, 2002, we were in compliance with the covenants of the Senior Notes.

     We have entered into an interest rate swap agreement to hedge our exposure to changes in the fair value on a portion of the Senior Notes, as more fully described in Item 7A. “Quantitative and Qualitative Disclosures About Market Risk.”

     Cash Distributions

     For the years ended December 31, 2002, 2001 and 2000, cash distributions totaled $94.9 million, $80.9 million and $70.8 million, respectively. The distribution increases reflect our success in improving cash flow levels. On February 7, 2003, we paid a cash distribution of $24.5 million for the quarter ended December 31, 2002.

     Future Capital Needs and Commitments

     We estimate that capital expenditures, excluding acquisitions, for 2003 will be approximately $34.6 million (which includes $1.9 million of capitalized interest). We expect to use approximately $9.4 million for revenue generating projects which will include approximately $7.5 million for the expansion of our pumping capacity for LPGs into the Northeast markets and approximately $1.9 million for expansion of deliverability capacity at various locations throughout the system. We expect to spend approximately $17.5 million to sustain existing operations, including the replacement of storage tanks and pipeline rehabilitation projects to comply with regulations enacted by the OPS and the installation of replacement electrical distribution facilities at our Mont Belvieu facilities. An additional $5.8 million will be expended on other replacements and system upgrade projects. We continually review and evaluate potential capital improvements and expansions that would be complementary to our present system. These expenditures can vary greatly depending on the magnitude of our transactions. We may finance capital expenditures through internally generated funds, debt or capital contributions from our Parent Partnership or any combination thereof.

     Our debt repayment obligations consist of payments for principal and interest on (i) Senior Notes, $180.0 million principal amount due January 15, 2008, and $210.0 million principal amount due January 15, 2028, and (ii) $154.1 million principal amount due to the Parent Partnership related to our share of the Parent Partnership’s Three Year Facility and Senior Notes, due in April 2004 and February 2012, respectively. We expect to repay the long-

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term, senior unsecured obligations through the issuance of additional long-term senior unsecured debt at the time the 2008 and 2028 debt matures, proceeds from dispositions of assets, or any combination of the above items.

     We are also contingently liable as guarantor for the lesser of one-half or $75.0 million principal amount (plus interest) of the borrowings of Centennial. We expect to contribute an additional $10.0 million to Centennial in 2003 to provide for its working capital needs. In January 2003, we entered into a pipeline capacity lease agreement with Centennial for a period of five years. On February 10, 2003, we acquired an additional 16.7% interest in Centennial, bringing our ownership percentage to 50%. We are also contingently liable as guarantor for $500.0 million principal amount of 7.625% Senior Notes due 2012 issued in February 2002 and for $200.0 million principal amount of 6.125% Senior Notes due 2013 issued in January 2003 by our Parent Partnership. We do not rely on off-balance sheet borrowings to fund our acquisitions. We have no off-balance sheet commitments for indebtedness other than the limited guaranty of the Centennial debt, the Parent Partnership debt and leases covering assets utilized in several areas of our operations.

     The following table summarizes our debt repayment obligations and material contractual commitments as of December 31, 2002 (in millions):

     Sources of Future Capital

     We expect that our cash flow from operating activities will be adequate to fund cash distributions and capital additions necessary to sustain existing operations. However, expansionary capital projects and acquisitions may require additional capital contributions from our Parent Partnership. The Parent Partnership has funded its capital commitments from operating cash flow, borrowings under bank credit facilities, the issuance of long term debt in capital markets and the public offering of Limited Partner Units. We expect future capital needs would be similarly funded.

     On May 29, 2002, Moody’s Investors Service downgraded our Parent Partnership’s senior unsecured debt rating to Baa3 from Baa2. We were also included in this downgrade. These ratings were given with stable outlooks and followed our Parent Partnership’s announcement of the acquisition of Val Verde. The downgrades reflect Moody’s concern that the Parent Partnership has a high level of debt relative to many of its peers and that its debt may be continually higher than its long-term targets if the Parent Partnership continues to make a series of acquisitions of increasingly larger size. Because of its high distribution rate, the Parent Partnership is particularly reliant on external financing to finance its acquisitions. Moody’s indicated that the Parent Partnership’s cash flows

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are becoming less predictable as a result of its acquisitions and expansion into the crude oil and natural gas gathering businesses. Further reductions in the Parent Partnership’s and our credit ratings could increase the debt financing costs or possibly reduce the availability of financing. Generally, a subsidiary’s credit rating will not be higher than its parent. A rating reflects only the view of a rating agency and is not a recommendation to buy, sell or hold any indebtedness. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant such a change. On January 27, 2003, Moody’s reaffirmed the Baa3 ratings on us and our Parent Partnership.

Other Considerations

     Credit Risks

     Risks of nonpayment and nonperformance by customers are a major consideration in our businesses. Our credit procedures and policies do not fully eliminate customer credit risk. During 2002, several of our customers filed for bankruptcy protection. During the year ended December 31, 2002, we expensed approximately $0.7 million of uncollectible receivables.

     Terrorist Threats

     On September 11, 2001, the United States was the target of terrorist attacks of unprecedented scale. Since the September 11 attacks, the United States government has issued warnings that energy assets, specifically the nation’s pipeline infrastructure, could be a future target of terrorist organizations. These developments have subjected our operations to increased risks. Any terrorist attack on our facilities, customers’ facilities and, in some cases, those of other pipelines, could have a material adverse effect on our business. We have increased security initiatives and are working with various governmental agencies to minimize risks associated with additional terrorist attacks.

     Environmental

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

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

     In 1994, the LDEQ issued a compliance order for environmental contamination at our Arcadia, Louisiana, facility. This contamination may be attributable to our operations, as well as adjacent petroleum terminals operated by other companies. In 1999, our Arcadia facility and adjacent terminals were directed by the Remediation Services

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Division of the LDEQ to pursue remediation of this containment phase. At December 31, 2002, we have an accrued liability of $0.2 million for remediation costs at our Arcadia facility. We do not expect that the completion of the remediation program that we have proposed will have a future material adverse effect on our financial position, results of operations or cash flows.

     Market-Based Rates

     On May 11, 1999, we 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 us Market-Based Rates in certain markets and set for hearing our application for Market-Based Rates in certain destination markets and origin markets. After the matter was set for hearing, we entered into a settlement agreement with the protesting shippers resolving our respective differences. On April 25, 2001, the FERC issued an order approving the offer of settlement. As a result of the settlement, we recognized approximately $1.7 million of previously deferred transportation revenue in the second quarter of 2001. As a part of the settlement, we withdrew the application for Market-Based Rates to the Little Rock, Arkansas, and Arcadia and Shreveport-Arcadia, Louisiana, destination markets, which are currently subject to the PPI Index. As a result, we made refunds of approximately $1.0 million in the third quarter of 2001 for those destination markets.

     New Accounting Pronouncements

     In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS 143 requires us to record the fair value of an asset retirement obligation as a liability in the period in which we incur a legal obligation for the retirement of tangible long-lived assets. A corresponding asset is also recorded and depreciated over the life of the asset. After the initial measurement of the asset retirement obligation, the liability will be adjusted at the end of each reporting period to reflect changes in the estimated future cash flows underlying the obligation. We will adopt SFAS 143 effective January 1, 2003. Determination of any amounts to be recognized upon adoption is based upon numerous estimates and assumptions, including future retirement costs, future inflation rates and the credit-adjusted risk-free interest rates.

     Our assets consist of a pipeline system and a series of storage facilities that originate along the upper Texas Gulf Coast and extend through the Midwest and northeastern United States. We transport refined products, LPGs and petrochemicals through the pipeline system. These products are primarily received in the south end of the system and stored and/or transported to various points along the system per customer nominations. The fair value of the asset retirement obligations for our trunk and interstate pipelines and our surface facilities cannot be reasonably estimated, as future dismantlement and removal dates are indeterminate. We will record such asset retirement obligations in the period in which we determine the settlement dates of the retirement obligations. We are continuing to evaluate the effect of SFAS 143, but we do not currently anticipate that the adoption of SFAS 143 will have a material impact on our financial position, results of operations or cash flows.

     In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS 144 supercedes SFAS No. 121, Accounting for Long-Lived Assets and For Long-Lived Assets to be Disposed Of, 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. We adopted SFAS 144 effective January 1, 2002. The adoption of SFAS 144 resulted in the classification of the transfer of TEPPCO Colorado as discontinued operations. Under previously existing literature, the classification of the transfer of TEPPCO Colorado as discontinued operations would not have been required.

     In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections. SFAS 145 eliminates the requirement to classify gains and losses from the extinguishment of indebtedness as extraordinary, requires certain lease modifications to be treated the same as a sale-leaseback transaction, and makes other non-substantive technical corrections to existing pronouncements. SFAS 145 is effective for fiscal years beginning after May 15, 2002, with earlier adoption encouraged. We are required to adopt SFAS 145 effective January 1, 2003. We do not believe that the adoption of SFAS 145 will have a material effect on our financial position, results of operations or cash flows.

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     In July 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force (“EITF”) Issue No. 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). SFAS 146 requires recognition of a liability for a cost associated with an exit or disposal activity when the liability is incurred, as opposed to when the entity commits to an exit plan under EITF No. 94-3. SFAS 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002. We do not believe that the adoption of SFAS 146 will have a material effect on our financial position, results of operations or cash flows.

     In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based Compensation — Transition and Disclosure. SFAS 148 amends SFAS No. 123, Accounting for Stock-Based Compensation, to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS 148 amends the disclosure requirements of SFAS 123 to require prominent disclosure in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. The provisions of SFAS 148 are effective for financial statements for fiscal years ending after December 15, 2002. The adoption of SFAS 148 did not affect our financial position, results of operations or cash flows.

     In November 2002, the FASB issued Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (“FIN 45”), which addresses the disclosure to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees. FIN 45 also requires the recognition of a liability by a guarantor at the inception of certain guarantees. FIN 45 requires the guarantor to recognize a liability for the non-contingent component of the guarantee, which is the obligation to stand ready to perform in the event that specified triggering events or conditions occur. The initial measurement of this liability is the fair value of the guarantee at inception. The recognition of the liability is required even it is not probable that payments will be required under the guarantee or if the guarantee was issued with a premium payment or as part of a transaction with multiple elements. We have adopted the disclosure requirements of FIN 45 (see Note 17. Commitments and Contingencies) and will apply the recognition and measurement provisions for all guarantees entered into or modified after December 31, 2002. To date, we have not entered into or modified guarantees pursuant to the provisions of FIN 45.

     In January 2003, the FASB issued FASB Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51 (“FIN 46”). FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. We are required to apply FIN 46 to all new variable interest entities created or acquired after January 31, 2003. For variable interest entities created or acquired prior to February 1, 2003, we are required to apply FIN 46 on July 1, 2003. We do not believe FIN 46 will have a significant impact on our financial position, results of operations or cash flows.

     Disclosures About Effects of Transactions with Related Parties

     We have no employees and are managed by TEPPCO GP, a wholly owned subsidiary of our Parent Partnership. The Parent Partnership is managed by the Company, which is a wholly owned subsidiary of DEFS. Duke Energy holds an approximate 70% interest in DEFS and ConocoPhillips holds the remaining 30%. See Item 10, Directors and Executive Officers of the Registrant and Item 13, Certain Relationships and Related Transactions for discussion regarding transactions between us, our Parent Partnership, DEFS, Duke Energy and ConocoPhillips.

Forward-Looking Statements

     The matters discussed in this Report include “forward-looking statements” within the meaning of various provisions of the Securities Act of 1933 and the Securities Exchange Act of 1934. All statements, other than

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statements of historical facts, included in this document that address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as estimated future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, competitive strengths, goals, expansion and growth of our business and operations, plans, references to future success, references to intentions as to future matters and other such matters are forward-looking statements. These statements are based on certain assumptions and analyses based on our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, including general economic, market or business conditions, the opportunities (or lack thereof) that may be presented to and pursued by us, competitive actions by other pipeline companies, changes in laws or regulations and other factors, many of which are beyond our control. Consequently, all of the forward-looking statements made in this document are qualified by these cautionary statements and we cannot assure you that actual results or developments that we anticipate will be realized or, even if substantially realized, will have the expected consequences to or effect on us or our business or operations.

Item 7A. Quantitative and Qualitative Disclosures About Market Risks

     We may be exposed to market risk through changes in commodity prices and interest rates. We do not have foreign exchange risks. Our Risk Management Committee has established policies to monitor and control these market risks. The Risk Management Committee is comprised, in part, of senior executives of the Company.

     We have utilized and expect to continue to utilize interest rate swap agreements to hedge a portion of our fair value risks. Interest rate swap agreements are used to manage the fixed interest rate mix of our debt portfolio and overall cost of borrowing. The interest rate swaps related to our fair value risks are intended to reduce our exposure to changes in the fair value of our fixed rate Senior Notes. The interest rate swap agreements involve the periodic exchange of payments without the exchange of the notional amount upon which the payments are based. The related amount payable to or receivable from counterparties is included as an adjustment to accrued interest.

     As of December 31, 2002 and 2001, we had intercompany notes payable to our Parent Partnership of $154.1 million and $117.9 million, respectively. At December 31, 2001, $72.5 million, included in current liabilities, related to our borrowings under the Parent Partnership’s Short-term Revolver. Our long-term portion at December 31, 2001, totaled $45.4 million and represented borrowings under the Parent Partnership’s Three Year Facility. During the year ended December 31, 2002, the Parent Partnership issued $500.0 million principal amount of 7.625% Senior Notes due 2012. The Parent Partnership used a portion of the proceeds to repay the Short-term Revolver. Thus, at December 31, 2002, no amounts were included in current liabilities as our portion of the Short-term Revolver had been repaid. Our long-term portion at December 31, 2002, totaled $154.1 million and represents borrowings by us under the Parent Partnership’s Three Year Facility and Senior Notes. The interest rate on the note payable, Parent Partnership at December 31, 2002, was 5.3%. At December 31, 2002, accrued interest includes $4.1 million due to the Parent Partnership. For the year ended December 31, 2002, interest costs incurred on the note payable, Parent Partnership totaled $7.2 million.

     As of December 31, 2002, we had an interest rate swap agreement in place to hedge our exposure to changes in the fair value of our fixed rate 7.51% Senior Notes due 2028. We designated this swap agreement as a fair value hedge. The swap agreement has a notional amount of $210.0 million and matures in January 2028 to match the principal and maturity of the Senior Notes. Under the swap agreement, we pay a floating rate based on a three month U.S. Dollar LIBOR rate, plus a spread, and receive a fixed rate of interest of 7.51%. During the years ended December 31, 2002 and 2001, we recognized reductions in interest expense of $8.6 million and $1.8 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap. During the year ended December 31, 2002, we measured the hedge effectiveness of this interest rate swap and noted that no gain or loss from ineffectiveness was required to be recognized. The fair value of this interest rate swap agreement was a gain of approximately $13.6 million at December 31, 2002, and a loss of approximately $14.6 million at December 31, 2001. Utilizing the balance of the 7.51% Senior Notes outstanding at December 31, 2002, and including the effects of hedging activities, assuming market interest rates increase 100 basis points, the potential annual increase in interest expense is $2.1 million.

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     At December 31, 2002, we had outstanding $180.0 million principal amount of 6.45% Senior Notes due 2008 and $210.0 million principal amount of 7.51% Senior Notes due 2028. At December 31, 2002, the estimated fair value of the Senior Notes was approximately $385.8 million.

Item 8. Financial Statements and Supplementary Data

     Our consolidated financial statements, together with the independent auditors’ report of KPMG LLP, begin on page F-1 of this Report.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

     None.

PART III

Item 10. Directors and Executive Officers of the Registrant

     We do not have employees, officers or directors and we are managed by the General Partner, a wholly owned subsidiary of our Parent Partnership. The directors and officers of the General Partner are appointed annually by the Parent Partnership by action of the board of directors of the Company. The directors of the General Partner, TEPPCO GP, Inc., are Barry R. Pearl, James C. Ruth and Charles H. Leonard. The Executive Officers of the General Partner are also Executive Officers of the Company. Information concerning the Executive Officers of the General Partner and the Company is contained in Item 10 of the Parent Partnership’s Annual Report on Form 10-K for the Year Ended December 31, 2002 (the “Parent Partnership Form 10-K”), and is incorporated by reference in this Report.

Item 11. Executive Compensation

     We do not have any employees, officers or directors. The General Partner manages and operates our business. The Executive Officers of the General Partner are employees of the Company. Certain employees of the Company may devote all or a portion of their time to us. We reimburse the Company for the services of such persons. The information contained in Item 11 of the Parent Partnership Form 10-K is incorporated by reference in this Report.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

     The Parent Partnership owns a 99.999% interest as the sole limited partner interest and the General Partner owns a 0.001% general partner interest in us. Information identifying security ownership of the Parent Partnership is contained in Item 12 of the Parent Partnership Form 10-K and is incorporated by reference in this Report.

Item 13. Certain Relationships and Related Transactions

Our Management

     We have no employees and we are managed by TEPPCO GP, a wholly owned subsidiary of the Parent Partnership. The Parent Partnership is managed by the Company, which is a wholly owned subsidiary of DEFS. Duke Energy holds an approximate 70% interest in DEFS and ConocoPhillips holds the remaining 30%. According

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to the Partnership Agreement, the General Partner and the Company are entitled to reimbursement of all direct and indirect expenses related to our business activities.

     For the years ended December 31, 2002, 2001 and 2000, direct expenses incurred by the Company in the amount of $46.6 million, $41.3 million and $39.6 million, respectively, were charged to us by DEFS. Substantially all such costs were related to payroll and payroll related expenses. For the years ended December 31, 2002, 2001 and 2000, expenses for administrative service and overhead allocated to us by the Company (including Duke Energy and its affiliates) were $0.8 million, $0.5 million and $0.8 million, respectively.

Transactions with DEFS

     Effective with the purchase of the fractionation facilities on March 31, 1998, TEPPCO Colorado and DEFS entered into a 20-year Fractionation Agreement, under which TEPPCO Colorado received a variable fee for all fractionated volumes delivered to DEFS. Revenues recognized from the fractionation facilities totaled $3.1 million, $7.4 million and $7.5 million for the years ended December 31, 2002, 2001 and 2000, respectively. TEPPCO Colorado and DEFS also entered into an Operation and Maintenance Agreement, whereby DEFS operated and maintained the fractionation facilities. For these services, TEPPCO Colorado paid DEFS a set volumetric rate for all fractionated volumes delivered to DEFS. Expenses related to the Operation and Maintenance Agreement totaled $0.4 million, $0.9 million and $0.9 million for the years ended December 31, 2002, 2001 and 2000, respectively. On May 31, 2002, TEPPCO Colorado was transferred to TEPPCO Midstream.

     Effective May 2001, we entered into an agreement with DEFS to commit sole utilization of our Providence terminal to DEFS. We operate the terminal and provide propane loading services to DEFS. During the years ended December 31, 2002 and 2001, revenues of $2.3 million and $1.5 million from DEFS, respectively, were recognized pursuant to this agreement.

Interests of Duke Energy in the Parent Partnership

     In connection with our formation, the Company received 2,500,000 Deferred Participation Interests (“DPIs”). Effective April 1, 1994, the DPIs began participating in distributions of cash and allocations of profit and loss in a manner identical to the Parent Partnership’s Limited Partner Units and are treated as Limited Partner Units for purposes of this Report. These Limited Partner Units were assigned to Duke Energy when ownership of the Company was transferred from Duke Energy to DEFS in 2000. Pursuant to our Parent Partnership’s Partnership Agreement, we have registered the resale by Duke Energy of such Limited Partner Units with the Securities and Exchange Commission. As of December 31, 2002, no such Limited Partner Units had been sold by Duke Energy.

     At December 31, 2002, Duke Energy also held 3,916,547 Class B Units. The Class B Units share in income and distributions on the same basis as the Parent Partnership’s Limited Partner Units, but they are not listed on the New York Stock Exchange. The Class B Units may be converted into Limited Partner Units upon approval by the unitholders. We have the option to seek approval for the conversion of the Class B Units into Limited Partner Units; however, if the conversion is denied, Duke Energy, as holder of the Class B Units, will have the right to sell them to the Parent Partnership at 95.5% of the 20-day average market closing price of the Limited Partner Units, as determined under our Parent Partnership’s Partnership Agreement.

Item 14. Controls and Procedures

     Included in its recent Release No. 34-46427, effective August 29, 2002, the Securities and Exchange Commission adopted rules requiring reporting companies to maintain disclosure controls and procedures to provide reasonable assurance that a registrant is able to record, process, summarize and report the information required in the registrant’s quarterly and annual reports under the Securities Exchange Act of 1934 (the “Exchange Act”). While we believe that our existing disclosure controls and procedures have been effective to accomplish these objectives,

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we intend to continue to examine, refine and formalize our disclosure controls and procedures and to monitor ongoing developments in this area.

     The principal executive officer and principal financial officer of our General Partner, after evaluating the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-14(c) and Rule 15d-14(c)) as of a date within 90 days before the filing date of this Report, have concluded that, as of such date, our disclosure controls and procedures are adequate and effective to ensure that material information relating to us and our consolidated subsidiaries would be made known to them by others within those entities.

     There have been no changes in our internal controls or in other factors known to us that could significantly affect those internal controls subsequent to the date of the evaluation, nor were there any significant deficiencies or material weaknesses in our internal controls. As a result, no corrective actions were required or undertaken.

PART IV

Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K

(a)

The following documents are filed as a part of this Report:

	(1)		Financial Statements: See Index to Financial Statements and Supplemental Schedule on page F-1 of this Report for financial statements filed as part of this Report.
	(2)		Financial Statement Schedules: See Index to Financial Statements and Supplemental Schedule on page F-1 of this Report for financial statements schedules filed as part of this Report.
	(3)		Exhibits.

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(b)

Reports on Form 8-K filed during the quarter ended December 31, 2002:

     A Report on Form 8-K was filed on October 9, 2002.

SIGNATURES

     TE Products Pipeline Company, Limited Partnership, pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

Dated: March 27, 2003

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CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002

I, BARRY R. PEARL, certify that:

1.		I have reviewed this annual report on Form 10-K of TE Products Pipeline Company, Limited Partnership;
2.		Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3.		Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4.		The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

	a)		designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
	b)		evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and
	c)		presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.

The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

	a)		all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
	b)		any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and