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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

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

For the fiscal year ended December 31, 2003

OR

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

TEPPCO Partners, L.P.

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

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

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding twelve months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes  þ  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. Yes  o

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

At June 30, 2003, the aggregate market value of the registrant’s Limited Partner Units held by non-affiliates was $2,103,612,900, which was computed using the average of the high and low sales prices of the Limited Partner Units on June 30, 2003.

Limited Partner Units outstanding as of February 20, 2004: 62,998,554.

Documents Incorporated by Reference: None

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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 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 made by us in light of 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.

Items 1 and 2. Business and Properties

General

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

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

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

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

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

          At December 31, 2003 and 2002, we had outstanding 62,998,554 and 53,809,597 Limited Partner Units, respectively. At December 31, 2002, we had outstanding 3,916,547 Class B Limited Partner Units (“Class B Units”). All of the Class B Units were issued to Duke Energy Transport and Trading Company, LLC (“DETTCO”) in connection with an acquisition of assets initially acquired in the Upstream Segment in 1998. The Class B Units shared in income and distributions on the same basis as the Limited Partner Units, but they were not listed on the New York Stock Exchange. The Class B Units were not included in partners’ capital at December 31, 2002, as the Class B Units could have been converted into Limited Partner Units upon approval by the unitholders. We had the option to seek approval for the conversion of the Class B Units into Limited Partner Units; however, if the conversion was denied, DETTCO, as holder of the Class B Units, would have had the right to sell them to us at 95.5% of the 20-day average market closing price of the Limited Partner Units, as determined under our Partnership Agreement. On April 2, 2003, we repurchased and retired all of the 3,916,547 previously outstanding Class B Units with proceeds from the issuance of additional Limited Partner Units (see Note 12. Partners’ Capital and Distributions). Collectively, the Limited Partner Units and Class B Units are referred to as “Units.”

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

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

     Operations

          We conduct business in our Downstream Segment through the following:

	•		TE Products,
	•		a subsidiary which owns the northern portion of the Dean Pipeline (“Dean North”),
	•		our 50% owned equity investment in Centennial Pipeline LLC (“Centennial”), and
	•		our 50% owned equity investment in Mont Belvieu Storage Partners, L.P. (“MB Storage”).

          Our Downstream Segment owns, operates or has investments in properties located in 14 states. The operations of the Downstream Segment consist of interstate transportation, storage and terminaling of petroleum products; short-haul shuttle transportation of LPGs at the Mont Belvieu, Texas, complex through MB Storage; intrastate transportation of petrochemicals and other ancillary services.

          As an interstate common carrier, our TE Products pipeline offers interstate transportation services, pursuant to tariffs filed with the FERC, to any shipper of refined petroleum products and LPGs who requests these 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 provide storage and marketing services at key points along our pipeline systems. Substantially all of the petroleum products transported and stored in our pipeline systems 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

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generally the lowest cost method for intermediate and long-haul overland transportation of petroleum products. The TE Products pipeline system is the only pipeline that transports LPGs from the upper Texas Gulf Coast to the Northeast.

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

          The following table lists the material properties and investments of and ownership percentages in the Downstream Segment assets as of December 31, 2003:

     Centennial Pipeline Equity Investment

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

          TE Products’ interest in Centennial is not subject to any encumbrances from mortgages or other secured debt. Centennial has unsecured debt, one third of which, up to $50.0 million in principal, was originally guaranteed by each owner, including TE Products. On February 10, 2003, TE Products and Marathon each acquired an additional interest in Centennial from PEPL for $20.0 million each, increasing their percentage ownerships in Centennial to 50% each. TE Products and Marathon have each guaranteed one-half of Centennial’s debt, up to a maximum of $75.0 million each. Through December 31, 2003, including the amount paid for the acquisition of the additional ownership interest in February 2003, TE Products has invested $104.9 million in Centennial.

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     Mont Belvieu Storage Equity Investment

          In February 2000, we entered into a joint marketing and development alliance with Louis Dreyfus in which our Mont Belvieu LPGs storage and shuttle transportation system was jointly marketed by Louis Dreyfus and TE Products. The purpose of the alliance was to expand services to the upper Texas Gulf Coast energy marketplace by increasing pipeline throughput and the mix of products handled through the existing system and establishing new receipt and delivery connections. The alliance was a service-oriented, fee-based venture with no commodity trading activity. TE Products operated the facilities for the alliance. The alliance stipulated that if certain earnings thresholds were achieved, a partnership between TE Products and Louis Dreyfus was to be created effective January 1, 2003. All terms and earnings thresholds were met; therefore, as of January 1, 2003, TE Products and Louis Dreyfus formed MB Storage.

          The economic terms of the MB Storage partnership are the same as those under the joint marketing and development alliance. TE Products contributed property, plant and equipment with a net book value of $67.4 million to MB Storage. TE Products continues to operate the facilities for MB Storage. Louis Dreyfus had invested $6.1 million for expansion projects for MB Storage that TE Products was required to reimburse if the original joint development and marketing agreement was terminated by either party. This deferred liability was also contributed and converted to the capital account of Louis Dreyfus in MB Storage. TE Products and Louis Dreyfus each own a 50% ownership interest in MB Storage. Through December 31, 2003, excluding the contribution of property, plant and equipment upon formation of the partnership, TE Products has contributed $2.5 million to MB Storage. In December 2003, we received a distribution of $5.3 million from MB Storage.

          TE Products’ interest in MB Storage is not subject to any encumbrances from mortgages or other secured debt. TE Products receives the first $1.8 million per quarter (or $7.15 million on an annual basis) of MB Storage’s gross income less mandatory capital expenditures plus capital contributions, as defined in the operating agreement. Any amount of MB Storage’s gross income in excess of the $7.15 million is allocated evenly between TE Products and Louis Dreyfus, except for depreciation expense. Each partner is allocated depreciation expense based upon assets each originally contributed to MB Storage. Depreciation expense on assets constructed or acquired by MB Storage is allocated evenly between TE Products and Louis Dreyfus. For the year ended December 31, 2003, TE Products’ sharing ratio in the earnings of MB Storage was approximately 70.4%.

          MB Storage’s asset base in the Mont Belvieu fractionation and storage complex, which is the largest complex of its kind in the United States, serving the fractionation, refining and petrochemical industries, provides substantial capacity and flexibility for the transportation, terminaling and storage of NGLs, LPGs and refined products. MB Storage receives revenue from the shuttling of product from refineries and fractionators to pipelines, refineries and petrochemical facilities on the upper Texas Gulf Coast. MB Storage has approximately 33 million barrels of LPGs storage capacity and approximately 5 million barrels of refined products storage capacity, including storage capacity leased to outside parties, at the Mont Belvieu fractionation and storage complex. MB Storage includes a 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. MB Storage also provides truck and rail car loading capability. Total shuttle volumes for the three years ended December 31, 2003, 2002 and 2001, were 33.1 million barrels, 28.9 million barrels and 23.1 million barrels, respectively.

     Refined Products, LPGs and Petrochemical Pipeline Systems

          TE Products is one of the largest pipeline common carriers of refined petroleum products and LPGs in the United States. TE Products owns and operates an approximately 4,600-mile pipeline system (together with the receiving, storage and terminaling facilities mentioned below, the “Products Pipeline System”) extending from southeast Texas through the central and midwestern United States to the northeastern United States. The Products Pipeline System includes delivery terminals for outloading product to other pipelines, tank trucks, rail cars or barges, and substantial storage facilities at numerous locations. TE Products also owns two marine receiving terminals, one near Beaumont and the other at Providence, Rhode Island. The Providence terminal is not physically connected to the Products Pipeline System. The Products Pipeline System also includes three parallel 12-inch diameter petrochemical pipelines between Mont Belvieu and Port Arthur, each approximately 70 miles in length, and 138 miles of pipeline from Mont Belvieu to Point Comfort (the northern portion of the Dean Pipeline).

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

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

          Excluding the storage facilities of Centennial and MB Storage, the Products Pipeline System includes 27 storage facilities with an aggregate storage capacity of 16 million barrels of refined petroleum products and 6 million barrels of LPG storage, including storage capacity leased to outside parties. The Products Pipeline System makes deliveries to customers at 56 locations including 19 truck racks, rail car facilities and marine facilities that we own. Deliveries to other pipelines occur at various facilities owned by TE Products or by third parties.

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

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

          In December 2002, we completed an upgrade of our Princeton, Indiana, LPG truck rack to increase its capacity. During the fourth quarter of 2003, we completed a Phase I project to expand our delivery capacity of LPGs in the Northeast. The Phase I expansion increased delivery capability to the Northeast during the peak winter months by approximately one million barrels. The expansion consisted of the construction of three new pump stations located between Middletown, Ohio, and Coshocton, Ohio. During the fourth quarter of 2003, we began projects to increase our truck rack capacity in the Northeast at locations in New York and Pennsylvania in order to improve customer service to those areas. These projects are scheduled to be completed in early 2004. Additionally, in 2004, we have begun a Phase II project to further expand our delivery capability to the Northeast by constructing three new pump stations located between Coshocton and Greensburg, Pennsylvania, and two new pump stations located between Greensburg and Watkins Glen, New York. The Phase II projects are anticipated to be completed during the fourth quarter of 2004. We have also approved a project for construction of a new truck loading terminal in Bossier City, Louisiana, which is scheduled to be completed by the end of 2004.

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          TE Products also owns three 12-inch diameter common carrier petrochemical pipelines between Mont Belvieu and Port Arthur. 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 in 2002 with a major petrochemical producer for guaranteed throughput commitments. During the years ended December 31, 2003, 2002, and 2001, we recognized $11.9 million, $11.9 million and $10.7 million, respectively, of revenue under the throughput and deficiency contract. We began transporting product through these pipelines in September 2001.

          Our Downstream Segment also includes the operations of the northern portion of the Dean Pipeline. Beginning in January 2003, the northern portion of the Dean Pipeline was converted to transport RGP from Mont Belvieu to Point Comfort. The northern portion of the Dean Pipeline consists of 138 miles of pipeline from Mont Belvieu to Point Comfort.

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

     Major Business Sector Markets

          Our major operations in the Downstream Segment consist of the transportation, storage and terminaling of refined petroleum products and LPGs along our mainline system. Product deliveries, in millions of barrels (MMBbls) on a regional basis, for the years ended December 31, 2003, 2002 and 2001, were as follows:

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

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          Refined products and LPGs deliveries for the years ended December 31, 2003, 2002 and 2001, were as follows:

     Refined Products Mainline Transportation

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

          The volume of refined petroleum products transported by our Products Pipeline System is directly affected by the demand for refined products in the geographic regions the system serves. This market demand varies based upon the different end uses to which the refined products deliveries are applied. Demand for gasoline, which accounted for approximately 58% of the volume of refined products transported through the Products Pipeline System during 2003, depends upon price, prevailing economic conditions and demographic changes in the markets that we serve. Demand for distillates is affected by truck and railroad freight, the price of natural gas used by utilities, which use distillates as a substitute for natural gas when the price of natural gas is high, and usage for agricultural operations, which is affected by weather conditions, government policy and crop prices. Demand for jet fuel depends upon prevailing economic conditions and military usage.

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

     LPGs Mainline Transportation

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

          Our ability in the Downstream Segment to serve propane markets in the Northeast is enhanced by our marine import terminal at Providence. This facility includes a 400,000-barrel refrigerated storage tank along with

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ship unloading and truck loading facilities. Effective May 2001, we entered into an agreement with an affiliate of DEFS to commit sole utilization of the Providence terminal to an affiliate of DEFS. We operate the terminal and provide propane loading services to an affiliate of DEFS. The agreement, with an affiliate of DEFS, terminates in May 2004, and we are currently renegotiating the agreement. During the years ended December 31, 2003, 2002 and 2001, revenues of $3.2 million, $2.3 million and $1.5 million from an affiliate of DEFS, respectively, were recognized pursuant to this agreement.

     Other Operating Revenues

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

     Customers

          Our customers for the transportation of refined petroleum products include major integrated oil companies, independent oil companies, the airline industry and wholesalers. End markets for these deliveries are primarily retail service stations, truck stops, railroads, 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, 2003, our Downstream Segment had approximately 130 customers. During the year ended December 31, 2003, total revenues (and percentage of total revenues) attributable to the top 10 customers were $149.5 million (56%), of which Marathon Ashland Petroleum LLC accounted for approximately 18% of total Downstream Segment revenues. During the years ended December 31, 2002 and 2001, total revenues (and percentage of total revenues) attributable to the top 10 customers were $101.6 million (51%) and $115.0 million (44%), respectively. During the years ended December 31, 2002 and 2001, no single customer accounted for 10% or more of the Downstream Segment’s revenues.

     Credit Policies and Procedures

          We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures. We utilize letters of credit and guarantees for certain of our receivables. However, these procedures and policies do not fully eliminate customer credit risk. During the years ended December 31, 2003 and 2002, a few small to medium-sized customers of the Downstream Segment filed for bankruptcy protection. During the years ended December 31, 2003 and 2002, we expensed approximately $0.8 million and $0.7 million, respectively, of uncollectible receivables of the Downstream Segment related to customer bankruptcies or other non-payments.

     Competition

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

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

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

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

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

     Operations

          We conduct business in our Upstream Segment through the following:

	•		TCTM and certain of its wholly owned subsidiaries, and
	•		our 50% owned equity investment in Seaway Crude Pipeline Company (“Seaway”).

          Our Upstream Segment gathers, transports, markets and stores crude oil, and distributes lubrication oils and specialty chemicals, principally in Oklahoma, Texas, New Mexico and the Rocky Mountain region. We commenced our Upstream Segment business in connection with the acquisition of assets from an affiliate of DEFS in November 1998. Our Upstream Segment uses its asset base to aggregate crude oil and provide transportation and specialized services to its regional customers. Our Upstream Segment purchases crude oil from various producers and operators at the wellhead and makes bulk purchases of crude oil at pipeline and terminal facilities. The crude oil is then sold to refiners and other customers. The Upstream Segment transports crude oil through equity owned pipelines, its trucking operations and third party pipelines.

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

          TCTM purchases crude oil and simultaneously establishes a margin by selling crude oil for physical delivery to third party users. We seek to maintain a balanced marketing position until we make physical delivery of the crude oil, thereby minimizing or eliminating our exposure to price fluctuations occurring after the initial purchase. However, certain basis risks, which are the risks that price relationships between delivery points, classes of products or delivery periods will change, cannot be completely hedged or eliminated. Risk management policies have been established by the Risk Management Committee to monitor and control market risks. The Risk Management Committee is comprised, in part, of certain senior executives of the Company.

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          Product deliveries on TCTM’s 100% owned pipeline systems, undivided joint interest pipelines and Seaway for the years ended December 31, 2003, 2002 and 2001, were as follows (in millions):

     Properties

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

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

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

          In connection with our acquisition of ARCO Pipe Line Company (“ARCO”), a wholly owned subsidiary of Atlantic Richfield Company, in 2000, we acquired an approximate 23.5% undivided joint interest in the Rancho Pipeline, which was a crude oil pipeline system from West Texas to Houston. In March 2003, the Rancho Pipeline ceased operations, and segments of the pipeline were sold to certain of the owners which previously held undivided interests in the pipeline. We acquired approximately 230 miles of the pipeline in exchange for cash of $5.5 million and our interests in other portions of the Rancho Pipeline. We sold part of the segment we acquired to other entities for cash and assets valued at approximately $8.5 million. We recorded a net gain of $3.9 million on the transactions, which is included in the gain on sale of assets in our consolidated statements of income.

          On November 1, 2003, we completed the purchase of crude supply and transportation assets along the upper Texas Gulf Coast for $21.0 million from Genesis Crude Oil, L.P. and Genesis Pipeline Texas, L.P. (“Genesis”). The transaction was funded with proceeds from our August 2003 equity offering (see Note 12. Partners’ Capital and Distributions). We allocated the purchase price, net of liabilities assumed, primarily to property, plant and equipment and intangible assets (see Note 6. Acquisitions and Dispositions). The assets acquired included approximately 150 miles of small diameter trunk lines, 26,000 barrels per day of throughput and 12,000 barrels per day of lease marketing and supply business. We have integrated these assets into our South Texas pipeline system which has allowed us to consolidate gathering and marketing assets in key operating areas in a cost effective manner and will provide future growth opportunities. Accordingly, the results of the acquisition are included in the consolidated financial statements from November 1, 2003.

     Seaway Crude Pipeline Equity Investment

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

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

     Line Transfers, Pumpovers and Other

          Our Upstream Segment provides trade documentation services to its customers, primarily at Cushing and Midland. TCTM documents the transfer of crude oil in its terminal facilities between contracting buyers and sellers. This line transfer documentation service is related to the trading activity by TCTM’s customers of NYMEX open-

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interest crude oil contracts and other physical trading activity. This service provides a documented record of receipts, deliveries and transactions to each customer, including confirmation of trade matches, inventory management and scheduled movements. Line transfer revenues are included as part of other operating revenues in our consolidated statements of income.

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

          Lubrication Services, L.P. (“LSI”), a subsidiary of TCTM, distributes lubrication oils and specialty chemicals to natural gas pipelines, gas processors and industrial and commercial accounts. LSI’s distribution networks are located in Colorado, Wyoming, Oklahoma, Kansas, New Mexico, Texas and Louisiana. LSI also sells lubrication oils and specialty chemicals to DEFS. For the years ended December 31, 2003, 2002, and 2001, revenues recognized by LSI included $15.2 million, $14.6 million, and $12.3 million, respectively, for the sale of lubrication oils and specialty chemicals to DEFS.

     Customers

          TCTM purchases crude oil primarily from major integrated oil companies and independent oil producers. Crude oil sales are primarily to major integrated oil companies and independent refiners. Gross sales revenue of the Upstream Segment attributable to the top 10 customers was $2.6 billion (67%) for the year ended December 31, 2003, of which Valero Energy Corp. (“Valero”) accounted for 18%. For the year ended December 31, 2002, gross sales revenue attributable to the top 10 customers was $1.9 billion (66%), of which Valero accounted for 18%. For the year ended December 31, 2001, gross sales revenue attributable to the top 10 customers was $2.0 billion (61%), of which Valero accounted for 16%.

     Competition

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

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

     Credit Policies and Procedures

          As crude oil or lubrication oils are marketed or transported, we must determine the amount, if any, of credit to be extended to any given customer. Due to the nature of individual sales transactions, risk of non-payment and non-performance by customers is a major consideration in our business. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures. We utilize letters of credit and guarantees for certain of our receivables. However, these procedures and policies do not fully eliminate customer credit risk. During the year ended December 31, 2002, we expensed approximately $0.2 million of uncollectible

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receivables of the Upstream Segment. During the years ended December 31, 2003 and 2001, no additional reserves were necessary for uncollectible receivables of the Upstream Segment.

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

     Operations

          We conduct business in our Midstream Segment through the following:

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

          Revenues of our Midstream Segment are earned from gathering fees based on the volume and pressure of natural gas gathered, transportation of NGLs and fractionation of NGLs in Colorado. Gathering and transportation revenues are recognized as natural gas or NGLs are delivered to customers. Revenues are also earned from the sale of condensate liquid extracted from the natural gas stream to an Upstream Segment marketing affiliate. Fractionation revenues are recognized ratably over the contract year as products are delivered to DEFS. We generally do not take title to the natural gas gathered, NGLs transported or NGLs fractionated, therefore, the results of operations of our Midstream Segment are not directly affected by changes in the prices of natural gas or NGLs. Our Midstream Segment has multiple long-term contracts with producers connected to the Jonah and Val Verde systems. We cannot influence or control the operation, development or production levels of the gas fields served by the Jonah and Val Verde systems, which may be affected by price and price volatility, market demand, depletion rates of existing wells and changes in laws and regulations.

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

          Volume information for the years ended December 31, 2003, 2002 and 2001, is presented below:

     The Jonah Gas Gathering System

          On September 30, 2001, we completed the purchase of Jonah from Alberta Energy Company for $359.8 million, with an additional payment of $7.3 million made on February 4, 2002, for final purchase adjustments related primarily to construction projects in progress at the time of closing. The acquisition served as our entry into the natural gas gathering industry. We funded the acquisition through a borrowing under a $400.0 million credit facility with SunTrust Bank (see Note 11. Debt). We allocated the purchase price, net of liabilities assumed, primarily to property, plant and equipment and intangible assets for gas gathering contracts. We also recognized goodwill on the purchase of approximately $2.8 million (see Note 6. Acquisitions and Dispositions). We accounted for the acquisition under the purchase method of accounting. Accordingly, the results of operations of the

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acquisition have been included in our consolidated financial statements from September 30, 2001. Under a contractual agreement, DEFS manages and operates Jonah on our behalf.

          Since the acquisition, we have expanded both the pipeline capacity and processing capacity of the Jonah system. In 2002, we completed the Phase I and Phase II expansions of Jonah, which nearly doubled the capacity of the Jonah system. The first expansion was completed in May 2002 at a cost of approximately $25.0 million and increased system capacity by 62%, from approximately 450 million cubic feet per day (“MMcf/day”) to approximately 730 MMcf/day. In October 2002, an additional expansion project was completed at a cost of approximately $45.0 million, which increased the capacity of the Jonah system from 730 MMcf/day to approximately 880 MMcf/day. In 2003, the Jonah system was again expanded to include an 80-mile expansion on the system and the building of a new 250 MMcf/day gas processing plant near Opal, Wyoming. Phase III was substantially completed during the fourth quarter of 2003, and the system was operational, with system capacity increasing to 1,180 MMcf/day. The cost of the Phase III expansion through December 31, 2003, was approximately $44.6 million. The total cost of the Phase III expansion will be approximately $59.0 million, with the remaining work to be completed in 2004.

          The Jonah system consists of approximately 500 miles of pipelines ranging in size from three inches to 24 inches in diameter, three compressor stations with an aggregate of approximately 44,000 horsepower and related metering facilities. Gas gathered on the Jonah system is collected from approximately 500 producing wells in southwestern Wyoming’s Green River Basin, which is one of the most prolific natural gas basins in the United States. The system also includes two processing facilities that extract condensate prior to delivery of natural gas to DEFS, Northwest, Kern River and Questar. Gas is also delivered to gas processing facilities owned by others. From these processing facilities, the natural gas is delivered to several interstate pipeline systems located in the region for transportation to end-use markets throughout the Midwest, the West Coast and the Rocky Mountain regions. Interstate pipelines in the region include Kern River, Northwest, Colorado Interstate Gas and Questar.

     The Val Verde Gas Gathering System

          On June 30, 2002, we completed the purchase of Val Verde for $444.2 million from Burlington Resources Gathering Inc., a subsidiary of Burlington Resources Inc., including acquisition related costs of approximately $1.2 million. We funded the purchase through borrowings of $168.0 million under our $500.0 million revolving credit facility, $72.0 million under our 364-day revolving credit facility and $200.0 million under a six-month term loan with SunTrust Bank (see Note 11. Debt). The remaining purchase price was funded through working capital sources of cash. We allocated the purchase price, net of liabilities assumed, primarily to property, plant and equipment and intangible assets for gas gathering contracts (see Note 6. Acquisitions and Dispositions). We accounted for the acquisition of these assets under the purchase method of accounting. Accordingly, the results of the acquisition have been included in our consolidated financial statements from June 30, 2002. Under a contractual agreement, DEFS manages and operates Val Verde on our behalf.

          The Val Verde system consists of approximately 400 miles of pipeline ranging in size from four inches to 36 inches in diameter, 14 compressor stations operating over 93,000 horsepower of compression and a large amine treating facility for the removal of carbon dioxide. The system has a pipeline capacity of approximately one billion cubic feet of gas per day. The Val Verde system gathers coal bed methane (“CBM”) from the Fruitland Coal Formation of the San Juan Basin in New Mexico and Colorado, a long-term source of natural gas supply in North America. The basin is one of the most prolific sources of CBM and also contains significant conventional gas reserves. The system is one of the largest CBM gathering and treating facilities in the United States, gathering CBM from more than 500 separate wells throughout northern New Mexico and southern Colorado, and provides gathering and treating services pursuant to 60 long-term contracts with approximately 40 different natural gas producers in the San Juan Basin. Gas transported on the Val Verde system is delivered to several interstate pipeline systems serving the western United States, as well as local New Mexico markets.

          In July 2003, the New Mexico Oil Conservation Division approved an application for infill drilling to allow two wells per standard 320-acre gas spacing unit in the Fruitland Coal Formation of the San Juan Basin. This approval of infill drilling will provide potential opportunities for long-term growth and increased throughput on the Val Verde system.

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          On February 6, 2004, a lawsuit styled San Juan Citizens Alliance et al. v. Norton et al. was filed against the United States Department of Interior and the Bureau of Land Management (“BLM”) in the U.S. District Court, District of Columbia, challenging a recent decision by the BLM. In that decision, the BLM adopted a Resource Management Plan, which authorized the development of additional gas wells on public lands in northwestern New Mexico. A substantial portion of the development activity in the area that is the subject of the suit involves the infill drilling in the Basin-Fruitland Coal Gas Pool which covers most of the San Juan Basin. We believe the BLM followed the requirements of the law and reached a balanced decision in adopting the Resource Management Plan. However, an adverse decision could impact infill drilling activities in the San Juan Basin.

     NGL Transportation and Fractionation

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

          On March 1, 2002, we completed the purchase of the Chaparral NGL system for $132.4 million from Diamond-Koch II, L.P. and Diamond-Koch III, L.P., including acquisition related costs of approximately $0.4 million. The Chaparral NGL system extends from West Texas and New Mexico to Mont Belvieu. The pipeline delivers NGLs to fractionators and to MB Storage’s existing storage facilities in Mont Belvieu. We funded the purchase through borrowings under our $500.0 million revolving credit facility (see Note 11. Debt). We allocated the purchase price to property, plant and equipment, and we accounted for the acquisition of these assets under the purchase method of accounting. Accordingly, the results of the acquisition have been included in our consolidated financial statements from March 1, 2002. Under a contractual agreement, DEFS manages and operates Chaparral on our behalf. An affiliate of DEFS transports NGLs on the Chaparral NGL system. The fees paid to us by an affiliate of DEFS for NGL transportation on the Chaparral NGL system totaled $5.5 million and $4.5 million for the years ended December 31, 2003 and 2002, respectively.

          The Panola Pipeline and San Jacinto Pipeline originate at DEFS’ East Texas Plant Complex in Panola County, Texas, and transport NGLs for DEFS and other major integrated oil and gas companies. Revenues recognized from an affiliate of DEFS for NGL transportation totaled $9.2 million, $12.0 million and $13.9 million for the years ended December 31, 2003, 2002 and 2001, respectively.

          The southern portion of the Dean Pipeline originates in South Texas and transports NGLs for DEFS into its pipeline in Point Comfort, Texas. Revenues recognized from DEFS for NGL transportation totaled $1.0 million, $2.9 million and $0.1 million for the years ended December 31, 2003, 2002 and 2001, respectively.

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          The Wilcox Pipeline transports NGLs for DEFS from two of its natural gas processing plants. The Wilcox Pipeline is currently supported by a throughput agreement with DEFS through 2005. The fees paid to us by DEFS under the agreement were $1.5 million, $1.2 million and $1.2 million for the years ended December 31, 2003, 2002 and 2001, respectively.

          TEPPCO Colorado has two NGL fractionation facilities which separate NGLs into individual components. TEPPCO Colorado is currently supported by a fractionation agreement with DEFS through 2018, under which TEPPCO Colorado receives a variable fee for all fractionated volumes delivered to DEFS. Revenues recognized from the fractionation facilities totaled $7.4 million for each of the years ended December 31, 2003, 2002 and 2001. Under an operation and maintenance agreement, DEFS also operates and maintains the fractionation facilities on behalf of TEPPCO Colorado. For these services, TEPPCO Colorado pays DEFS a set volumetric rate for all fractionated volumes delivered to DEFS. Expenses related to the Operation and Maintenance Agreement totaled $0.9 million for each of the years ended December 31, 2003, 2002 and 2001.

     Customers

          The Midstream Segment’s customers for the gathering of natural gas include major integrated oil and gas companies and large to medium-sized independent producers. Natural gas from Jonah and Val Verde is delivered into major interstate gas pipelines for delivery primarily to markets in the western United States. The Midstream Segment’s customers for the transporting of NGLs include DEFS and its affiliates and other major integrated oil and gas companies. Condensate sales from the Jonah system are primarily to an Upstream Segment marketing affiliate.

          At December 31, 2003, the Midstream Segment had approximately 70 customers. Revenue attributable to the top 10 customers was $155.9 million (84%) for the year ended December 31, 2003, of which EnCana Corporation (formerly Alberta Energy Company), Burlington Resources Inc. and DEFS and affiliates accounted for approximately 21%, 18% and 14% of revenues of the Midstream Segment, respectively. At December 31, 2002, the Midstream Segment had approximately 70 customers. Revenue attributable to the top 10 customers was $117.5 million (85%) for the year ended December 31, 2002, of which DEFS and affiliates, EnCana Corporation and Burlington Resources Inc. accounted for approximately 21%, 19% and 15% of revenues of the Midstream Segment, respectively. At December 31, 2001, the Midstream Segment had approximately 20 customers. Revenue attributable to the 10 customers was $37.0 million (99%) for the year ended December 31, 2001, of which DEFS and affiliates, Enron Corp. and Alberta Energy Company accounted for approximately 61%, 13% and 11% of revenues of the Midstream Segment, respectively.

     Credit Policies and Procedures

          We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures. We utilize letters of credit and guarantees for certain of our receivables. However, these procedures and policies do not fully eliminate customer credit risk. In December 2001, we expensed approximately $4.3 million of uncollected transportation deficiency revenues due to the bankruptcy of Enron Corp. and certain of its subsidiaries in December 2001. During the years ended December 31, 2003 and 2002, no additional reserves were necessary for uncollectible receivables of the Midstream Segment.

     Competition

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

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

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

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

Title to Properties

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

Capital Expenditures

          Capital expenditures, excluding acquisitions, totaled $140.6 million for the year ended December 31, 2003. Revenue generating projects include those projects which expand service into new markets or expand capacity into current markets. Capital expenditures to sustain existing operations include projects required by regulatory agencies or required life-cycle replacements. System upgrade projects improve operational efficiencies or reduce cost. We capitalize interest costs incurred during the period that construction is in progress. The following table identifies capital expenditures by segment for the year ended December 31, 2003 (in millions):

          Revenue generating capital spending by the Downstream Segment totaled $26.6 million and was used primarily for the expansion of our pumping capacity of LPGs into the Northeast markets, expansion of our North Houston terminal facility, increased storage capacity at the Princeton, Indiana, terminal and expansion of delivery capacity at various other locations. Revenue generating capital spending by the Midstream Segment totaled $55.5 million and was used primarily for the upgrade of the Jonah system and additional well connections on both the Jonah and Val Verde systems. Revenue generating capital spending by the Upstream Segment totaled $5.3 million and was used primarily for the expansion of our South Texas system and connections to various other production facilities and pipelines. In order to sustain existing operations, we spent $18.3 million for various Downstream Segment pipeline projects, $7.8 million for the Midstream Segment and $6.6 million for Upstream Segment facilities. An additional $15.0 million was spent on system upgrade projects among all of our business segments.

          We estimate that capital expenditures, excluding acquisitions, for 2004 will be approximately $144.0 million (which includes $4.0 million of capitalized interest). We expect to spend approximately $112.0 million for revenue generating projects and facility improvements. Capital spending on revenue generating projects and facility improvements will include approximately $49.0 million for the expansion of our Downstream Segment facilities including pipelines extending from Seymour to Indianapolis, Indiana, further expansions of our Northeast pipeline

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system and construction of a new truck loading terminal in Bossier City, Louisiana. We expect to spend $21.2 million to expand our Upstream Segment pipelines and facilities in South Texas and Oklahoma and approximately $41.8 million to expand our Midstream Segment assets. We expect to spend approximately $28.0 million to sustain existing operations, including life-cycle replacements for equipment at various facilities and pipeline and tank replacements among all of our business segments. We continually review and evaluate potential capital improvements and expansions that would be complementary to our present business segments. These expenditures can vary greatly depending on the magnitude of our transactions. We may finance capital expenditures through internally generated funds, debt or the issuance of additional equity.

Regulation

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

          Rates of interstate petroleum products and crude oil pipeline companies, like us, are currently regulated by the FERC primarily through an index methodology, which allows a pipeline to change its rates based on the change from year to year in the Producer Price Index for finished goods (“PPI Index”). Effective as of February 24, 2003, FERC Order on Remand modified the PPI Index from PPI – 1% to PPI. On April 22, 2003, several shippers filed a petition in the United States Court of Appeals for the District of Columbia Circuit, Flying J. Inc., Lion Oil Company, Sinclair Oil Corporation and Tesoro Refining and Marketing Company vs. Federal Energy Regulatory Commission, Docket No. 03-1107, seeking a review of whether the FERC’s adoption of the PPI Index was reasonable and supported by the evidence. Oral arguments are scheduled for early 2004.

          As an alternative to using the PPI Index, interstate petroleum products and crude oil pipeline companies may elect to support rate filings by using a cost-of-service methodology, competitive market showings (“Market-Based Rates”) or agreements between shippers and petroleum products and crude oil pipeline companies that the rate is acceptable.

          TE Products has been granted permission by the FERC to utilize Market-Based Rates for all of its refined products movements other than the Little Rock, Arkansas, Arcadia and Shreveport-Arcadia, Louisiana destination markets, which are currently subject to the PPI Index. With respect to LPG movements, TE Products uses the PPI Index. All interstate transportation movements of crude oil by TCTM are subject to the PPI Index as is the NGL interstate transportation movements on the Chaparral NGL system.

          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. These FERC decisions do not affect our current rates and rate structure because we do not use the cost-of-service methodology to support our rates. However, the FERC decisions might become relevant to us should we (i) elect in the future to use the cost-of-service methodology or (ii) be required to use such methodology to defend initial rates or our indexed rates against a shipper protest alleging that an indexed rate increase substantially exceeds actual cost increases. Should these circumstances arise, there can be no assurance with respect to the effect of these precedents on our rates in view of the uncertainties involved in this issue.

          The natural gas gathering operations of the Jonah and Val Verde systems are exempt from FERC regulation under the Natural Gas Act of 1938 since they are intrastate gas gathering systems rather than interstate transmission pipelines. However, FERC regulation still significantly affects the Midstream Segment, directly or indirectly, by its influences on the parties that produce the natural gas gathered on the Jonah and Val Verde systems. In addition, in recent years, FERC has pursued pro-competition policies in its regulation of interstate natural gas pipelines. If the FERC does not continue the pro-competition policies as it considers pipeline rate case proposals, revisions to rules and policies that affect shipper rights of access to interstate natural gas transportation capacity or proposals by

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natural gas pipelines to allow natural gas pipelines to charge negotiated rates without rate ceiling limits, such policy changes could have an adverse effect on the gathering rates the Midstream Segment is able to charge in the future.

Environmental Matters

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

     Water

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

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

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

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

     Air Emissions

          Our operations are subject to the federal Clean Air Act (the “Clean Air Act”) and comparable state laws. Amendments to the Clean Air Act, as well as recent or soon to be adopted changes to state implementation plans for controlling air emissions in regional, non-attainment areas, may require our operations to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies. In addition, some of our facilities are included within the categories of hazardous air pollutant sources, which are subject to increasing regulation under the Clean Air Act. The Clean Air Act requires federal operating permits for major sources of air emissions. Under this program, a federal operating permit (a “Title V” permit) may

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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 Matters” 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 analysis, 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. We also utilize waste minimization and recycling processes to reduce the volumes of our waste. Amendments to RCRA required the EPA to promulgate regulations banning the land disposal of all hazardous wastes unless the wastes meet certain treatment standards or the land-disposal method meets certain waste containment criteria. From time to time, the EPA considers the adoption of stricter disposal standards for non-hazardous wastes, including crude oil and gas wastes. The adoption of such stricter standards for non-hazardous wastes, or any future re-designation of non-hazardous wastes as hazardous wastes will likely increase our operating expenses as well as for the industry in general.

     Superfund

          The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as “Superfund,” imposes liability, without regard to fault or the legality of the original act, on certain classes of persons who contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of a facility where a release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at a facility. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In the course of our ordinary operations, our pipeline systems generate 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.

     Other Environmental Proceedings

          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 to 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 contamination. At December 31, 2003, we have an accrued liability of $0.3 million for remediation costs at our Arcadia facility. We do not expect that the completion of the remediation program proposed to the LDEQ will have a future material adverse effect on our financial position, results of operations or cash flows.

          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

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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 we agreed in August 2003 to pay our pro-rata share of the remediation costs which amounted to $12,000. This matter has been fully resolved with the EPA, and no further action is expected.

          On March 17, 2003, we experienced a release of 511 barrels of jet fuel from a storage tank at our Blue Island terminal located in Cook County, Illinois. As a result of the release, we have entered into an Agreed Order with the State of Illinois. The Agreed Order requires us, in part, to complete a site investigation plan to delineate the scope of any potential contamination resulting from the release and to remediate any contamination present above regulatory standards. This site investigation plan has been completed and submitted to the State of Illinois. The Agreed Order does not contain any provision for any fines or penalties; however, it does not preclude the State of Illinois from assessing these at a later date. 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.

          At December 31, 2003, we have an accrued liability of $5.9 million related to various TCTM sites requiring environmental remediation activities. Under the terms of a 1998 agreement through which we acquired various crude oil assets from DETTCO, we received a five year contractual indemnity obligation for environmental liabilities not otherwise assumed by us that were attributable to the operations of the assets prior to our acquisition. The indemnity expired on November 30, 2003. Under the agreement, we were responsible for the first $3.0 million in environmental liabilities covered by DETTCO’s indemnification obligation, and DETTCO was responsible for specified environmental liabilities in excess of $3.0 million, up to a maximum amount of $25.0 million. At December 31, 2002, we had a receivable balance from DETTCO of $4.2 million, the majority of which related to remediation activities at the Velma, Oklahoma crude oil site. On March 31, 2003, we received a $2.4 million payment from DETTCO for environmental liabilities we incurred that were covered under the indemnity obligation with DETTCO. The remaining $1.8 million due was determined as not attributable to DETTCO’s indemnity obligation as a result of settlement discussions with DETTCO on this matter and was written off. On December 1, 2003, concurrent with the expiration of the five year contractual indemnity obligation, we entered into a Settlement Agreement and Release with DETTCO regarding future obligations pertaining to various environmental liabilities associated with the assets purchased from DETTCO in 1998. The agreement provided for a net payment of $1.3 million to us from DETTCO, which consisted of a settlement of $2.0 million for remaining crude oil sites, partially offset by the sharing of expenses of $1.0 million which were incurred by DETTCO in remediation of a crude oil site in Stephens County, Oklahoma. The agreement also provided for $0.3 million toward the purchase of an environmental insurance policy for gathering systems located in Texas and Oklahoma and the assumption of responsibility by DETTCO for environmental liabilities associated with three sites located in Texas and Oklahoma. We do not expect that the completion of remediation programs associated with TCTM activities will have a future material adverse effect on our financial position, results of operations or cash flows.

DOT Pipeline Compliance Matters

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

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          We are subject to the DOT 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 believe that we are in material compliance with these DOT regulations.

          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 the development and implementation of an Integrity Management Program (“IMP”) 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 must be conducted within seven years, with all subsequent assessments conducted on a five-year cycle. During 2003, we continued with the baseline evaluation efforts initiated in 2002 and completed the evaluation and associated repair of approximately 1,300 miles of our pipeline system.

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

          The Partnership does not have any employees. However, for organizational purposes, TEPPCO GP, TEPPCO NGL Pipelines, LLC and TEPPCO Crude GP, LLC have officers and directors, who are employees of the General Partner. The General Partner is responsible for the management of us and our subsidiaries. As of December 31, 2003, the General Partner had 1,061 employees.

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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

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

          On December 21, 2001, TE Products was named as a defendant in a lawsuit in the 10th Judicial District, Natchitoches Parish, Louisiana, styled Rebecca L. Grisham et al. v. TE Products Pipeline Company, Limited Partnership. In this case, the plaintiffs contend that our pipeline, which crosses the plaintiffs’ property, leaked toxic products onto their property and, consequently caused damages to them. We have filed an answer to the plaintiffs’ petition denying the allegations, and we are defending ourselves vigorously against the lawsuit. The plaintiffs have not stipulated the amount of damages they are seeking in the suit; however, this case is covered by insurance. We do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows.

          On April 19, 2002, we, through our subsidiary TEPPCO Crude Oil, L.P., filed a declaratory judgment action in the U.S. District Court for the Western District of Oklahoma against D.R.D. Environmental Services, Inc. (“D.R.D.”) seeking resolution of billing and other contractual disputes regarding potential overcharges for environmental remediation services provided by D.R.D. On May 28, 2002, D.R.D. filed a counterclaim for alleged breach of contract in the amount of $2,243,525, and for unspecified damages for alleged tortious interference with D.R.D.’s contractual relations with DEFS. On July 16, 2003, the parties entered into a Settlement Agreement and Mutual Release, dismissing all claims and counterclaims against each other. The terms of the Settlement Agreement and Mutual Release did not have a material adverse effect on our financial position, results of operations or cash flows.

          In May 2003, the General Partner was named as a defendant in a lawsuit styled John R. James, et al. v. J Graves Insulation Company, et al. as filed in the first Judicial District Court, Caddo Parish, Louisiana. There are numerous plaintiffs identified in the action that are alleged to have suffered damages as the result of alleged exposure to asbestos-containing products and materials. According to the petition and as a result of a preliminary investigation, the General Partner believes that the only claim asserted against it results from one individual for the

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period from July 1971 through June 1972, who is alleged to have worked on a facility owned by the General Partner’s predecessor. This period represents a small portion of the total alleged exposure period from January 1964 through December 2001 for this individual. The individual’s claims involve numerous employers and alleged job sites. Currently, the General Partner has been unable to confirm involvement by the General Partner or its predecessors with the alleged location, and it is currently uncertain whether this case is covered by insurance. Discovery is planned, and the General Partner intends to defend itself vigorously against this lawsuit. The plaintiffs have not stipulated the amount of damages that they are seeking in this suit. We are obligated to reimburse the General Partner for any costs it incurs related to this lawsuit. We cannot estimate the loss, if any, associated with this pending lawsuit. We do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows.

          On April 2, 2003, Centennial was served with a petition in a matter styled Adams, et al. v. Centennial Pipeline Company LLC, et al. This matter involves approximately 2,000 plaintiffs who allege that over 200 defendants, including Centennial, generated, transported, and/or disposed of hazardous and toxic waste at two sites in Bayou Sorrell, Louisiana, an underground injection well and a landfill. The plaintiffs allege personal injuries, allergies, birth defects, cancer and death. The underground injection well has been in operation since May 1976. Based upon current information, Centennial appears to be a de minimis contributor, having used the disposal site during the two month time period of December 2001 to January 2002. Marathon has been handling this matter for Centennial under its operating agreement with Centennial. TE Products has a 50% ownership interest in Centennial. Based upon Centennial's limited involvement with the disposal site, we do not believe that the outcome of this matter will have a material adverse effect on our financial position, results of operations or cash flows.

          On December 16, 2003, Centennial, the General Partner, the Partnership and other Partnership entities were named as defendants in a lawsuit in the 128th District Court of Orange County, Texas, styled Elwood Karr et al. v. Centennial Pipeline, LLC et al. In this case, the plaintiffs contend that our pipeline leaked toxic substances on their property, causing them property damage. We have filed an answer to the plaintiffs’ petition, denying the allegations, and we are defending ourselves vigorously against this lawsuit. This case is covered by insurance. We do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows.

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

          On February 6, 2004, a lawsuit styled San Juan Citizens Alliance et al. v. Norton et al. was filed against the United States Department of Interior and the BLM in the U.S. District Court, District of Columbia, challenging a recent decision by the BLM. In that decision, the BLM adopted a Resource Management Plan, which authorized the development of additional gas wells on public lands in northwestern New Mexico. A substantial portion of the development activity in the area that is the subject of the suit involves the infill drilling in the Basin-Fruitland Coal Gas Pool which covers most of the San Juan Basin. We believe the BLM followed the requirements of the law and reached a balanced decision in adopting the Resource Management Plan. However, an adverse decision could impact infill drilling activities in the San Juan Basin.

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

          None.

PART II

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

          Our Limited Partner Units are listed and traded on the New York Stock Exchange under the symbol TPP. The high and low trading prices of our Units in 2003 and 2002, respectively, as reported in The New York Times, were as follows:

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          Based on the information received from our transfer agent and from brokers and nominees, we estimate the number of beneficial holders of our Units as of February 20, 2004, to be approximately 70,000.

          The quarterly cash distributions for the years ended December 31, 2003 and 2002 were as follows:

          We make quarterly cash distributions of all of our Available Cash, generally defined as consolidated cash receipts less consolidated cash disbursements and cash reserves established by the General Partner in its sole discretion. Pursuant to the Partnership Agreement, the Company receives incremental incentive cash distributions when cash distributions exceed certain target thresholds (see Note 12. Partner’s Capital and Distributions).

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

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

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Item 6. Selected Financial Data

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

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(1)		Data reflects the operations of the Chaparral and Val Verde assets acquired on March 1, 2002 and June 30, 2002, respectively.
(2)		Data reflects the operations of the Jonah assets acquired on September 30, 2001.
(3)		Data reflects the operations of the ARCO assets acquired on July 20, 2000.
(4)		Per Unit calculation includes 3,700,000 Units issued in 2000, 7,750,000 Units issued in 2001, 13,359,597 Units issued in 2002 and 9,188,957 Units issued in 2003, net of retirement of Class B Units of 3,916,547.

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

          The following information is provided to facilitate increased understanding of our 2003, 2002 and 2001 consolidated financial statements and our accompanying notes listed in the Index to Financial Statements on page F-1 of this Report. Accounting policies that are among the most critical to the portrayal of our financial condition and results of operations are discussed under “-Critical Accounting Policies.” Material period-to-period variances in the consolidated statements of income are discussed under “-Results of Operations.” The “-Financial Condition and Liquidity” section analyzes cash flows and financial position. Discussion included in “-Other Considerations” addresses trends, future plans and contingencies that are reasonably likely to materially affect future liquidity or earnings.

Overview

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

          We operate and report in three business segments. Our Upstream Segment gathers, transports, markets and stores crude oil and distributes lubrication oils and specialty chemicals in Oklahoma, Texas, New Mexico and in the Rocky Mountain region. Our Midstream Segment gathers natural gas in the Green River Basin in southwestern Wyoming and in the San Juan Basin in northwestern New Mexico and southwestern Colorado; transports NGLs from southeastern New Mexico, East Texas and West Texas to Mont Belvieu, Texas, and fractionates NGLs at two facilities in Colorado. Our Downstream Segment owns, operates or has investments in properties located in 14 states and transports, stores and provides terminal facilities for petroleum products; transports LPGs in the Mont Belvieu area; transports petrochemicals in southeast Texas; and provides other ancillary services.

          We earn revenues and income and generate cash by charging our customers a fee for the transportation, storage, gathering, terminaling, fractionation and other services we provide. In our Upstream Segment, we seek to maintain a balanced marketing position until we make physical delivery of the crude oil, thereby minimizing or eliminating our exposure to price fluctuations occurring after the initial purchase.

          We are subject to economic and other factors that affect our industry. The demand for crude oil and petroleum products is dependent on the price of crude oil and the products produced from the refining of crude oil; the price of natural gas and locations in which natural gas is drilled; and the demand for petrochemicals, which is dependent on prices for products produced from petrochemicals. We are also subject to regulatory factors such as the amounts we are allowed to charge our customers for the services we provide on our regulated pipeline systems.

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          We are focused on opportunities, challenges and risks that are inherent in our business segments as discussed in this Report. These include the safe, reliable and efficient operation of the pipelines and facilities that we own or operate while meeting increased regulations that govern the operation of our assets and the costs associated with such regulations. We are also focused on our continued growth through expansion of the assets that we own and through acquisition of assets that compliment the segments in which we operate.

          In 2003, excellent operating performance across all of our business segments contributed to a record year for volumes, net income and earnings before interest, taxes, depreciation and amortization. Our 2003 results illustrate the strength and diversity of our asset portfolio. Our net income for the year ended December 31, 2003, was $125.8 million. We raised our distribution to our unitholders by $0.20 per Unit to an annualized rate of $2.60 per Unit at year end, continuing our eleven year track record of distribution increases. Distributions have increased 35% over the past five years.

          Our Upstream Segment had strong gathering, marketing and transportation results, including the benefits of a one-time gain of $3.9 million related to the sale of certain portions of the Rancho Pipeline. Additionally, Seaway’s performance was noticeably stronger, with record volumes in the second half of the year. We also had higher throughput on our crude systems and a record year for gallons delivered by LSI. The Downstream Segment had an excellent year, as well, with record refined product and propane deliveries, made possible by the additional capacity provided by our lease agreement with Centennial. We have utilized Centennial capacity in a manner that has provided additional delivery capability for our customers. The Midstream Segment continued its strong performance, with continued volume growth on the Jonah system and full year contribution of the Val Verde system, acquired in June 2002, providing a positive impact on our overall profitability. Additional revenue generating capital growth prospects make the outlook favorable for continued strong performance in this segment.

          Our operating costs were higher than expected, largely as a result of pipeline integrity expenses in our Downstream Segment. The goal of our on-going pipeline integrity program has always been to maintain the long-term reliability and safety of our pipeline systems, while minimizing the impact to our customers. We ended 2003 in a solid financial position. During the year, we spent $162.0 million on acquisitions and revenue generating capital projects, which we believe will provide earnings, cash flow and growth opportunities. We raised approximately $171.0 million in equity capital during the year to fund these revenue generating capital projects, reduce debt and for general partnership purposes.

          We continued building a base for long-term growth by enhancing existing systems and pursuing new business opportunities. We increased throughput on our pipeline systems, constructed new pipeline and gathering systems, and expanded and upgraded our existing infrastructure. Among the highlights of 2003:

	•		We acquired an additional interest in Centennial for $20.0 million, bringing our ownership interest to 50%. Additionally, Centennial has provided additional capacity through our lease agreement that has enabled us to transport record refined product volumes in 2003.
	•		In November, we purchased 150 miles of crude supply and transportation assets along the upper Texas Gulf Coast from Genesis Crude Oil, L.P. and Genesis Pipeline Texas, L.P. The $21.0 million acquisition strengthened our existing South Texas market position and improved our physical asset base.
	•		During the fourth quarter of 2003, we completed a $12.0 million expansion project that was part of a system-wide effort to increase our deliverability of LPGs to the Northeast markets.
	•		In the fourth quarter of 2003, the Phase III expansion of the Jonah system became operational. During 2003, we spent approximately $44.6 million on the project with an additional $14.4 million expected to be spent in 2004. The Phase III project expands both pipeline and processing capacity on the Jonah system. The Phase III expansion provides additional investment opportunities from the ongoing development of the Jonah and Pinedale reserves in Wyoming.
	•		We spent an additional $64.4 million on other revenue generating projects, including the expansion of Downstream Segment terminal storage and delivery capacity, additional well connections in the Midstream Segment and expansions on the Upstream Segment’s South Texas system.

          We remain confident that our current strategy and focus will provide continued growth in earnings and cash distributions. With respect to 2004, these opportunities include:

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	•		Construction of a new truck loading facility in Bossier City, Louisiana.
	•		Integration of the Genesis crude oil assets and increased utilization of Seaway.
	•		Continued development of refined products and propane market opportunities.
	•		Continued development of the Jonah and Pinedale fields.
	•		Infill drilling of CBM and conventional gas in the San Juan Basin, where our Val Verde system is located.

Acquisitions

          We completed several acquisitions in 2003, 2002 and 2001 that have impacted the results of operations and liquidity discussed in this Report. The following acquisitions were accounted for, and the purchase price was allocated, in accordance with the purchase method of accounting. We adopted Statement of Financial Accounting Standards (“SFAS”) No. 141, Business Combinations, in 2001 and followed the provisions of that statement for all business combinations initiated after June 30, 2001.

     Jonah Gas Gathering Company

          On September 30, 2001, we completed the purchase of Jonah from Alberta Energy Company for $359.8 million, with an additional payment of $7.3 million made on February 4, 2002, for final purchase adjustments related primarily to construction projects in progress at the time of closing. The acquisition served as our entry into the natural gas gathering industry. We funded the acquisition through a borrowing under a $400.0 million credit facility with SunTrust Bank (see Note 11. Debt). We allocated the purchase price, net of liabilities assumed, primarily to property, plant and equipment and intangible assets for gas gathering contracts. We also recognized goodwill on the purchase of approximately $2.8 million (see Note 6. Acquisitions and Dispositions). Accordingly, the results of operations of the acquisition have been included in our consolidated financial statements from September 30, 2001. Under a contractual agreement, DEFS manages and operates Jonah on our behalf.

          The value assigned to intangible assets relates to contracts with customers that are for either a fixed term or which dedicate total future lease production. We are amortizing the value assigned to intangible assets on a unit-of-production basis, based upon the actual throughput of the system over the expected total throughput for the contracts (averaging approximately 25 years).

          Since the acquisition, we have expanded both the pipeline capacity and processing capacity of the Jonah system. In 2002, we completed the Phase I and Phase II expansions of Jonah, which nearly doubled the capacity of the Jonah system. The first expansion was completed in May 2002 at a cost of approximately $25.0 million and increased system capacity by 62%, from approximately 450 MMcf/day to approximately 730 MMcf/day. In October 2002, an additional expansion project was completed at a cost of approximately $45.0 million, which increased the capacity of the Jonah system from 730 MMcf/day to approximately 880 MMcf/day. In 2003, the Jonah system was again expanded to include an 80-mile expansion on the system and the building of a new 250 MMcf/day gas processing plant near Opal, Wyoming. Phase III was substantially completed during the fourth quarter of 2003, and the system was operational, with system capacity increasing to 1,180 MMcf/day. The cost of the Phase III expansion through December 31, 2003, was approximately $44.6 million. The total cost of the Phase III expansion will be approximately $59.0 million, with the remaining work to be completed in 2004.

     Chaparral NGL System

          On March 1, 2002, we completed the purchase of the Chaparral NGL system for $132.4 million from Diamond-Koch II, L.P. and Diamond-Koch III, L.P., including acquisition related costs of approximately $0.4 million. The Chaparral NGL system extends from West Texas and New Mexico to Mont Belvieu. The pipeline delivers NGLs to fractionators and to MB Storage’s existing storage facilities in Mont Belvieu. We funded the purchase through borrowings under our $500.0 million revolving credit facility (see Note 11. Debt). We allocated the purchase price to property, plant and equipment. Accordingly, the results of the acquisition have been included in our consolidated financial statements from March 1, 2002. Under a contractual agreement, DEFS manages and operates Chaparral on our behalf.

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     Val Verde Gas Gathering Company

          On June 30, 2002, we completed the purchase of Val Verde for $444.2 million from Burlington Resources Gathering Inc., a subsidiary of Burlington Resources Inc., including acquisition related costs of approximately $1.2 million. The Val Verde system gathers CBM from the Fruitland Coal Formation of the San Juan Basin in New Mexico and Colorado. The system is one of the largest CBM gathering and treating facilities in the United States. We funded the purchase through borrowings of $168.0 million under our $500.0 million revolving credit facility, $72.0 million under our 364-day revolving credit facility and $200.0 million under a six-month term loan with SunTrust Bank (see Note 11. Debt). The remaining purchase price was funded through working capital sources of cash. We allocated the purchase price, net of liabilities assumed, primarily to property, plant and equipment and intangible assets for gas gathering contracts (see Note 6. Acquisitions and Dispositions). Accordingly, the results of the acquisition have been included in our consolidated financial statements from June 30, 2002. Under a contractual agreement, DEFS manages and operates Val Verde on our behalf.

          The value assigned to intangible assets relates to fixed-term contracts with customers. We are amortizing the value assigned to intangible assets on a unit-of-production basis, based upon the actual throughput of the system over the expected total throughput for the contracts (averaging approximately 20 years).

     Rancho Pipeline

          In connection with our acquisition of crude oil assets in 2000, we acquired an approximate 23.5% undivided joint interest in the Rancho Pipeline, which was a crude oil pipeline system from West Texas to Houston. In March 2003, the Rancho Pipeline ceased operations, and segments of the pipeline were sold to certain of the owners which previously held undivided interests in the pipeline. We acquired approximately 230 miles of the pipeline in exchange for cash of $5.5 million and our interests in other portions of the Rancho Pipeline. We sold part of the segment we acquired to other entities for cash and assets valued at approximately $8.5 million. We recorded a net gain of $3.9 million on the transactions, which is included in the gain on sale of assets in our consolidated statements of income.

     Genesis Pipeline

          On November 1, 2003, we completed the purchase of crude supply and transportation assets along the upper Texas Gulf Coast for $21.0 million from Genesis Crude Oil, L.P. and Genesis Pipeline Texas, L.P. The transaction was funded with proceeds from our August 2003 equity offering (see Note 12. Partners’ Capital and Distributions). We allocated the purchase price, net of liabilities assumed, primarily to property, plant and equipment and intangible assets (see Note 6. Acquisitions and Dispositions). The assets acquired included approximately 150 miles of small diameter trunk lines, 26,000 barrels per day of throughput and 12,000 barrels per day of lease marketing and supply business. We have integrated these assets into our South Texas pipeline system which has allowed us to consolidate gathering and marketing assets in key operating areas in a cost effective manner and will provide future growth opportunities. Accordingly, the results of the acquisition are included in the consolidated financial statements from November 1, 2003.

General

          We operate and report in three business segments:

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

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

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

          Our Downstream Segment revenues are earned from transportation and storage of refined products and LPGs, intrastate transportation of petrochemicals, sale of product inventory and other ancillary services. The two largest operating expense items of the Downstream Segment are labor and electric power. We generally realize higher revenues during the first and fourth quarters of each year since our operations are somewhat seasonal. Refined products volumes are generally higher during the second and third quarters because of greater demand for gasolines during the spring and summer driving seasons. LPGs volumes are generally higher from November through March due to higher demand in the Northeast for propane, a major fuel for residential heating. Our Downstream Segment also includes the results of operations of the northern portion of the Dean Pipeline. Beginning in January 2003, the northern portion of the Dean Pipeline was converted to transport RGP from Mont Belvieu to Point Comfort, Texas. As a result, the revenues and expenses of the northern portion of the Dean Pipeline are included in the Downstream Segment. Our Downstream Segment also includes our equity investments in Centennial and MB Storage (see Note 7. Equity Investments).

          Our Upstream Segment revenues are earned from gathering, transportation, marketing and storage of crude oil and distribution of lubrication oils and specialty chemicals, principally in Oklahoma, Texas, New Mexico and the Rocky Mountain region. Marketing operations consist primarily of aggregating purchased crude oil along our pipeline systems, or from third party pipeline systems, and arranging the necessary transportation logistics for the ultimate sale of the crude oil to local refineries, marketers or other end users. Our Upstream Segment also includes our equity investment in Seaway (see Note 7. Equity Investments).

          Our Midstream Segment revenues are earned from the fractionation of NGLs in Colorado, transportation of NGLs from two trunkline NGL pipelines in South Texas, two NGL pipelines in East Texas and a pipeline system (Chaparral) from West Texas and New Mexico to Mont Belvieu; the gathering of natural gas in the Green River Basin in southwestern Wyoming, through Jonah, and the gathering of CBM in the San Juan Basin in New Mexico and Colorado, through Val Verde. DEFS manages and operates the Val Verde, Jonah and Chaparral assets for us under contractual agreements. The results of operations of the acquisitions are included in our consolidated financial statements in periods subsequent to their respective acquisition dates (see Note 6. Acquisitions and Dispositions).

Critical Accounting Policies

          The preparation of financial statements in accordance with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities as well as the disclosure of contingent assets and liabilities at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenues and expenses during the reporting period. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Although we believe that these estimates are reasonable, actual results could differ from these estimates. Key estimates used by our management include estimates used to record revenue and expense accruals, environmental costs, depreciation and amortization, asset impairment and fair values of assets acquired. Significant accounting policies that we employ are presented in the notes to the consolidated financial statements (see Note 2. Summary of Significant Accounting Policies).

          Critical accounting policies are those that are most important to the portrayal of 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

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policies pertain to revenue and expense accruals, environmental costs, property, plant and equipment and goodwill and intangible assets.

     Revenue and Expense Accruals

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

          The most difficult accruals to estimate are power costs, property taxes and crude oil margins. Power cost accruals generally involve a two to three month estimate, and the amount varies primarily for actual power usage. Power costs are dependent upon the actual volumes transported through our pipeline systems and the various power rates charged by numerous power companies along the pipeline system. Peak demand rates, which are difficult to predict, drive the variability of the power costs. Property tax accruals involve significant tax rate estimates among numerous jurisdictions. Actual property taxes are often not known until the tax bill is settled in subsequent periods, and the tax amount can vary for tax rate changes and changes in tax methods or elections. Crude oil margin estimates are based upon an average of the past twelve months of crude oil marketing volumes, factoring in current market events, and prices of crude oil. We use an average of prices that were in effect during the applicable month to determine the expected revenue amount, and we determine the margin by evaluating the actual margins of the prior twelve months. Each of these accruals requires management’s subjective judgments, requiring estimates regarding the effects of items that are inherently uncertain.

     Environmental Costs

          At December 31, 2003, we have accrued a liability for our estimate of the future payments we expect to pay for environmental costs to remediate existing conditions attributable to past operations. 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 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 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 Items 1 and 2. Business and Properties – Environmental Matters.

     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. The cost of property, plant and equipment, less estimated salvage value, is generally depreciated on a straight-line basis using rates based upon expected useful lives of various classes of assets (ranging from 2% to 20% per year). Useful lives are based on historical experience and are adjusted when changes in planned use, technological advances or other factors show that a different life would be more appropriate. Changes in useful lives that do not result in the impairment of an asset are recognized prospectively.

          We review long-lived assets for impairment in accordance with 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

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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 TE Products, Pennzoil had a throughput commitment of 25,000 barrels per day. Pennzoil and TE Products negotiated a settlement of $18.9 million to terminate the long-term transportation agreement from the Shreveport origin point on the Products Pipeline System. The termination payment was recorded as refined products transportation revenue in 2001. In connection with the termination of the transportation agreement, we evaluated its impact 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, 2003. We are pursuing a plan to make system changes to allow for bi-directional product flow and 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. We have approved a project for construction of a new truck loading terminal in Bossier City, Louisiana, and the reversal of the pipeline. Engineering design work and property acquisition for the terminal site are currently under way, and the project is scheduled to be completed by the end of 2004. If the successful completion of the plan is not realized on this pipeline segment, an impairment may be recorded for the excess of the carrying value over discounted future net cash flows.

     Goodwill and Intangible Assets

          Goodwill and intangible assets represent the excess of consideration paid over the fair value of tangible net assets acquired. Certain assumptions and estimates are employed in determining the fair value of assets acquired including goodwill and other intangible assets as well as determining the allocation of goodwill to the appropriate reporting unit. In addition, we assess the recoverability of these intangibles by determining whether the amortization of these intangibles over their remaining useful lives can be recovered through undiscounted future net cash flows of the acquired operations. The amount of impairment, if any, is measured by the amount by which the carrying amounts exceed the projected discounted future operating cash flows. During 2002, we adopted SFAS No. 142, Goodwill and Other Intangible Assets, which discontinues the amortization of goodwill and indefinite life intangibles and requires an annual test of impairment based on a comparison of fair value to carrying values. The evaluation of impairment under SFAS 142 requires the use of projections, estimates and assumptions as to the future performance of the operations, including anticipated future revenues, expected future operating costs and the discount factor used. Actual results could differ from projections resulting in revisions to our assumptions and, if required, recognizing an impairment loss. Based on our assessment, we do not believe our goodwill is impaired and we have not recorded a charge from the adoption of SFAS 142 (see Note 3. Goodwill and Other Intangible Assets). At December 31, 2003, the recorded value of goodwill was $16.9 million.

          At December 31, 2003, we have $400.3 million of intangible assets related to natural gas transportation contracts which were recorded as part of our acquisitions of Jonah on September 30, 2001, and Val Verde on June 30, 2002 (see Note 6. Acquisitions and Dispositions). The value assigned to the natural gas transportation contracts required management to make estimates regarding the fair value of the assets acquired. In connection with the acquisition of Jonah, we assumed contracts that dedicate future production from natural gas wells in the Green River Basin in Wyoming. We assigned $222.8 million of the purchase price to these production contracts based upon a fair value appraisal at the time of closing. In connection with the acquisition of Val Verde, we assumed fixed-term gas transportation contracts with customers in the San Juan Basin in New Mexico and Colorado. We assigned $239.6 million of the purchase price to these fixed term contracts based upon a fair value appraisal at the time of the closing. The value assigned to intangible assets is amortized on a unit-of-production basis, based upon the actual throughput of the system over the expected total throughput for the lives of the contracts. The amortization of the Jonah and Val Verde systems are expected to average approximately 25 years and 20 years, respectively. On a quarterly basis, we update throughput estimates and evaluate the remaining expected useful life of the contract assets based upon the best available information. Changes in the estimated remaining production will impact the timing of amortization expense reported for future periods.

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Results of Operations

          The following table summarizes financial data by business segment for the years ended December 31, 2003, 2002 and 2001 (in thousands):