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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

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

Commission File Number 1-10403

TEPPCO Partners, L.P.

(Exact name of Registrant as specified in its charter)


Delaware		76-0291058
(State of Incorporation or Organization)		(I.R.S. Employer Identification Number)

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:


		Name of each exchange on
Title of each class		which registered

Limited Partner Units representing Limited Partner Interests		New York Stock Exchange

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 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

TABLE OF CONTENTS


	Items 1 and 2. Business and Properties
	Item 3. Legal Proceedings
	Item 4. Submission of Matters to a Vote of Security Holders
PART II
	Item 5. Market for Registrant’s Units and Related Unitholder Matters
	Item 6. Selected Financial Data
	Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Item 7A. Quantitative and Qualitative Disclosures About Market Risk
	Item 8. Financial Statements and Supplementary Data
	Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
	Item 9A. Controls and Procedures
PART III
	Item 10. Directors and Executive Officers of the Registrant
	Item 11. Executive Compensation
	Item 12. Security Ownership of Certain Beneficial Owners and Management
	Item 13. Certain Relationships and Related Transactions
	Item 14. Principal Accounting Fees and Services
PART IV
	Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K
SIGNATURES
INDEX TO EXHIBIT
Statement of Computation of Ratio of Earnings
Consent of KPMG LLP
Powers of Attorney
Certification of CEO pursuant to Section 302
Certification of CFO pursuant to Section 302
Certification of CEO pursuant to Section 906
Certification of CFO pursuant to Section 906
Charter of the Audit Committee of the Board

TABLE OF CONTENTS


	PART I
ITEMS 1. AND 2.	Business and Properties	1
ITEM 3.	Legal Proceedings	23
ITEM 4.	Submission of Matters to a Vote of Security Holders	24
	PART II
ITEM 5.	Market for Registrant’s Units and Related Unitholder Matters	24
ITEM 6.	Selected Financial Data	26
ITEM 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk	53
ITEM 8.	Financial Statements and Supplementary Data	54
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	54
ITEM 9A.	Controls and Procedures	54
	PART III
ITEM 10.	Directors and Executive Officers of the Registrant	55
ITEM 11.	Executive Compensation	59
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management	65
ITEM 13.	Certain Relationships and Related Transactions	66
ITEM 14.	Principal Accounting Fees and Services	69
	PART IV
ITEM 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K	69

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.

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

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:


	Our
	Ownership

Refined products and LPGs pipelines		100	%
Mont Belvieu, Texas, to Port Arthur, Texas, petrochemical pipelines		100	%
Northern portion of Dean Pipeline (1)		100	%
Centennial Pipeline LLC (2)		50	%
Mont Belvieu Storage Partners, L.P. (3)		50	%

(1)		Effective January 1, 2003, the northern portion of the Dean Pipeline was converted to transport refinery grade propylene (“RGP”) from Mont Belvieu, Texas, to Point Comfort, Texas.

(2)		Accounted for as an equity investment. Effective February 10, 2003, TE Products acquired an additional 16.7% interest in Centennial, bringing its ownership percentage to 50%.

(3)		Accounted for as an equity investment. Effective January 1, 2003, TE Products contributed substantially all of its Mont Belvieu LPG assets to MB Storage, a newly formed partnership with Louis Dreyfus Energy Services L.P. (“Louis Dreyfus”).

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.

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).

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.

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:


			Product Deliveries (MMBbls)
			Years Ended December 31,

			2003		2002		2001

Refined Products Mainline Transportation:
	Central (1)			67.0		62.9		62.0
	Midwest (2)			57.7		49.6		37.4
	Ohio and Kentucky			29.4		25.7		23.5

		Subtotal		154.1		138.2		122.9

LPGs Mainline Transportation:
	Central, Midwest and Kentucky (1)(2)			23.4		25.4		23.8
	Ohio and Northeast (3)			19.1		15.1		16.2

		Subtotal		42.5		40.5		40.0

		Total Mainline Transportation		196.6		178.7		162.9

Petrochemical Transportation (4)				3.4		—		—

		Total Product Deliveries		200.0		178.7		162.9

(1)		Arkansas, Louisiana, Missouri and Texas.

(2)		Illinois and Indiana.

(3)		New York and Pennsylvania.

(4)		Includes Dean North RGP volumes. Petrochemical transportation between Mont Belvieu and Port Arthur, Texas, has not been included as those volumes are with one customer.

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

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


			Product Deliveries (MMBbls)
			Years Ended December 31,

			2003		2002		2001

Refined Products Mainline Transportation:
	Gasoline			89.8		81.9		69.4
	Jet Fuels			26.4		25.3		25.4
	Distillates (1)			37.9		31.0		28.1

		Subtotal		154.1		138.2		122.9

LPGs Mainline Transportation:
	Propane			34.5		32.9		32.8
	Butanes			8.0		7.6		7.2

		Subtotal		42.5		40.5		40.0

		Total Mainline Transportation		196.6		178.7		162.9

Petrochemical Transportation				3.4		—		—

		Total Product Deliveries		200.0		178.7		162.9

(1)

Primarily diesel fuel, heating oil and other middle distillates.

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

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

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.

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):


		Years Ended December 31,

		2003		2002		2001

Barrels Delivered:
	Crude oil transportation		95.5		82.8		78.7
	Crude oil marketing		159.7		139.2		159.5
	Crude oil terminaling		115.1		127.4		121.9
Lubricants and chemicals (total gallons)			10.4		9.6		8.8
Seaway:
	Long-haul		71.0		62.6		69.9
	Short-haul		179.8		183.8		175.7

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:


	Our
Crude Oil Pipeline	Ownership		Operator	Description

Red River System		100%	TEPPCO Crude Pipeline (“TCPL”) (1)	1,690 miles of pipeline; 1,484,000 barrels of storage – North Texas to South Oklahoma

South Texas System (2)		100%	TCPL	900 miles of pipeline; 780,000 barrels of storage – South Central Texas to Houston, Texas area

West Texas Trunk System		100%	TCPL	250 miles of smaller diameter pipeline – connecting West Texas and Southeast New Mexico to TCTM’s Midland, Texas terminal

Seaway (3)		50% general partnership interest	TCPL	500-mile, 30-inch diameter pipeline; 6,320,000 barrels of storage – Texas Gulf Coast to Cushing, Oklahoma

Basin		13% joint ownership	Plains All American Pipeline, L.P.	416-mile pipeline – Permian Basin (New Mexico and Texas) to Cushing, Oklahoma

(1)		TCPL is a wholly owned subsidiary of TCTM.

(2)		Includes our remaining interest in the Rancho Pipeline and our acquisition of the Genesis assets.

(3)		TCPL’s participation in revenues and expenses of Seaway vary as described below in “Seaway Crude Pipeline Equity Investment.”

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-

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

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:


	Years Ended December 31,

	2003		2002		2001

Gathering – Natural Gas (billion cubic feet (“Bcf”))		461.2		340.7		45.5
Transportation – NGLs (million barrels)		57.9		54.0		21.5
Fractionation – NGLs (million barrels)		4.1		4.1		4.1

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

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.

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:


	Capacity
NGL Pipeline	(barrels/day)		Description

Chaparral		135,000	845 miles of pipeline – West Texas and New Mexico to Mont Belvieu, Texas

Quanah		22,000	180 miles of pipeline – Sutton County, Texas to the Chaparral Pipeline near Midland, Texas

Panola		43,000	189 miles of pipeline – Carthage, Texas to Mont Belvieu, Texas

San Jacinto		12,000	34 miles of pipeline – Carthage, Texas to Longview, Texas

The southern portion of the Dean Pipeline		10,000	155 miles of pipeline – South Texas to Point Comfort, Texas

Wilcox		7,500	103 miles of pipeline – Southeast Texas

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.

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.

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):


				Sustaining
		Revenue		Existing		System		Capitalized
		Generating		Operations		Upgrades		Interest		Total

Downstream Segment		$	26.6	$	18.3	$	11.4	$	2.8	$	59.1
Midstream Segment			55.5		7.8		2.6		2.0		67.9
Upstream Segment			5.3		6.6		1.0		0.5		13.4
Other			—		0.2		—		—		0.2

	Total	$	87.4	$	32.9	$	15.0	$	5.3	$	140.6

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.

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

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

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

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.

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.

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.

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:


	2003				2002

Quarter	High		Low		High		Low

First	$	31.64	$	28.05	$	33.25	$	27.30
Second		37.00		30.35		33.20		29.35
Third		37.69		34.00		32.19		23.90
Fourth		41.15		35.22		29.98		26.00

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:


		Amount
Record Date	Payment Date	Per Unit

April 30, 2002	May 8, 2002	$	0.575
July 31, 2002	August 8, 2002		0.600
October 31, 2002	November 8, 2002		0.600
January 31, 2003	February 7, 2003		0.600
April 30, 2003	May 9, 2003	$	0.625
July 31, 2003	August 8, 2003		0.625
October 31, 2003	November 7, 2003		0.650
January 30, 2004	February 6, 2004		0.650

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.

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.


					Years Ended December 31,

					2003			2002 (1)			2001 (2)			2000 (3)			1999

					(in thousands, except per Unit amounts)
Income Statement Data:
	Operating revenues:
		Sales of petroleum products			$	3,766,651		$	2,823,800		$	3,219,816		$	2,821,943		$	1,692,767
		Transportation – Refined products				138,926			123,476			139,315			119,331			123,004
		Transportation – LPGs				91,787			74,577			77,823			73,896			67,701
		Transportation – Crude oil				29,057			27,414			24,223			17,524			11,846
		Transportation – NGLs				39,837			38,870			20,702			7,009			—
		Gathering – Natural gas				135,144			90,053			8,824			—			—
		Mont Belvieu operations				—			15,238			14,116			13,334			12,849
		Other revenues				54,430			48,735			51,594			34,904			26,716

			Total operating revenues			4,255,832			3,242,163			3,556,413			3,087,941			1,934,883
	Purchases of petroleum products					3,711,207			2,772,328			3,172,805			2,793,643			1,666,042
	Operating expenses					255,437			213,556			185,918			150,149			136,095
	Depreciation and amortization					100,728			86,032			45,899			35,163			32,656
	Gain on sale of assets					(3,948	)		—			—			—			—

		Operating income				192,408			170,247			151,791			108,986			100,090
	Interest expense – net					(84,250	)		(66,192	)		(62,057	)		(44,423	)		(29,430	)
	Equity earnings					16,863			11,980			17,398			12,214			—
	Other income – net					748			1,827			1,999			599			1,460

		Net income (as reported)				125,769			117,862			109,131			77,376			72,120
	Amortization of goodwill and excess investment					—			—			2,396			767			—

		Adjusted net income			$	125,769		$	117,862		$	111,527		$	78,143		$	72,120

	Basic and diluted income per Unit: (4)
	As reported				$	1.52		$	1.79		$	2.18		$	1.89		$	1.91
		Amortization of goodwill and excess investment				—			—			0.05			0.02			—

				Adjusted net income per Unit	$	1.52		$	1.79		$	2.23		$	1.91		$	1.91


		December 31,

		2003		2002 (1)		2001(2)		2000 (3)		1999

		(in thousands)
Balance Sheet Data:
	Property, plant and equipment – net	$	1,619,163	$	1,587,824	$	1,180,461	$	949,705	$	720,919
	Total assets		2,940,992		2,768,422		2,065,348		1,622,810		1,041,373
	Long-term debt (net of current maturities)		1,339,650		1,377,692		715,842		835,784		455,753
	Total debt		1,339,650		1,377,692		1,075,842		835,784		455,753
	Class B Units held by related party		—		103,363		105,630		105,411		105,859
	Partners’ capital		1,109,321		891,842		543,181		315,057		229,767


		Years Ended December 31,

		2003			2002 (1)			2001(2)			2000 (3)			1999

		(in thousands, except per Unit amounts)
Cash Flow Data:
	Net cash provided by operating activities	$	239,354		$	234,917		$	169,148		$	108,045		$	103,070
	Capital expenditures to sustain existing operations		(32,864	)		(21,978	)		(18,578	)		(21,859	)		(24,890	)
	Distributions paid		(202,498	)		(151,853	)		(104,412	)		(82,231	)		(69,259	)
	Distributions paid per Unit (4)	$	2.50		$	2.35		$	2.15		$	2.00		$	1.85

(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.

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:

	•		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

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.

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

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

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.

Results of Operations

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


			Years Ended December 31,

			2003			2002			2001

Operating revenues:
	Downstream Segment		$	266,427		$	243,538		$	264,233
	Upstream Segment			3,806,215			2,861,700			3,255,260
	Midstream Segment			185,105			138,922			37,242
	Intercompany eliminations			(1,915	)		(1,997	)		(322	)

		Total operating revenues		4,255,832			3,242,163			3,556,413

Operating income:
	Downstream Segment			83,704			83,098			117,676
	Upstream Segment			28,416			26,408			18,292
	Midstream Segment			80,288			60,741			15,823

		Total operating income		192,408			170,247			151,791

Earnings before interest:
	Downstream Segment			79,844			77,115			118,064
	Upstream Segment			49,671			46,735			38,027
	Midstream Segment			80,577			61,010			15,897
	Intercompany eliminations			(73	)		(806	)		—

		Total earnings before interest		210,019			184,054			171,988

Interest expense				(89,540	)		(70,537	)		(66,057	)
Interest capitalized				5,290			4,345			4,000
Minority interest				—			—			(800	)

		Net income	$	125,769		$	117,862		$	109,131

Below is a detailed analysis of the results of operations, including reasons for changes in results, by each of our operating segments.

Downstream Segment

The following table presents volumes delivered in barrels and average tariff per barrel for the years ended December 31, 2003, 2002 and 2001:


										Percentage
			Years Ended December 31,							Increase (Decrease)

			2003		2002		2001			2003			2002

			(in thousands, except tariff information)
Volumes Delivered:
	Refined products			154,061		138,164		122,947			12	%		12	%
	LPGs			42,543		40,490		39,957			5	%		1	%

		Total		196,604		178,654		162,904			10	%		10	%

Average Tariff per Barrel:
	Refined products		$	0.90	$	0.89	$	0.98	(1)		1	%		(9	%)
	LPGs			2.16		1.84		1.95			17	%		(6	%)
		Average system tariff per barrel	$	1.17	$	1.11	$	1.22			5	%		(9	%)

(1)

Excludes $18.9 million received from Pennzoil in 2001 for canceled transportation agreement discussed below.

Year Ended December 31, 2003 Compared with Year Ended December 31, 2002

Our Downstream Segment reported earnings before interest of $79.8 million for the year ended December 31, 2003, compared with earnings before interest of $77.1 million for the year ended December 31, 2002. Earnings before interest increased $2.7 million primarily due to an increase of $22.9 million in operating revenues and increased income of $2.7 million from equity investments, partially offset by an increase of $22.3 million in costs and expenses and a decrease of $0.6 million in other income – net. We discuss factors influencing our operating performance below.

Revenues from refined products transportation increased $15.5 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, due to an overall increase of 12% in the refined products volumes delivered. This increase was primarily due to deliveries of products received into our pipeline from Centennial at Creal Springs, Illinois. Centennial, which began operations in April 2002, has provided our system with additional pipeline capacity for products originating in the U.S. Gulf Coast area. In February 2003, we entered into a lease agreement with Centennial that increased our capacity to deliver refined products to our market areas. Prior to the lease agreement with Centennial, deliveries on our pipeline system were based upon a proration policy, which limited customer transportation. During 2003, with the expanded capacity through our lease agreement with Centennial, our pipeline system was not prorated during portions of 2003 and was better able to serve markets which increased transportation on our system. In addition, in December 2002, we raised the operating pressure of our Chicago lateral pipeline which resulted in an increase in capacity for deliveries into the Indianapolis and Chicago markets. With this incremental pipeline capacity, our previously constrained system has expanded deliveries in markets both south and north of Creal Springs. Volume increases were due to increased demand and market share for products supplied from the U.S. Gulf Coast into Midwest markets. The refined products average rate per barrel increased 1% from the prior year period primarily due higher market-based tariff rates which went into effect in July 2003, partially offset by the impact of the Midwest origin point for barrels received from Centennial, which resulted in an increase in short-haul barrels transported on our system.

Revenues from LPGs transportation increased $17.2 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, primarily due to increased deliveries of propane in the upper Midwest and Northeast market areas attributable to colder than normal weather during the first quarter of 2003 and due to low inventories at competing supply locations during the second and third quarters of 2003. The U.S. Gulf Coast had higher propane inventory during 2003 as compared to the previous year because of higher than normal foreign propane imports at Mont Belvieu, which resulted in a lower propane price in this market area. This lower price contributed to increased transportation deliveries to the mid-continent market areas. Additional pipeline capacity for expanded propane movements was available due to a shift of refined product volumes to Centennial. Butane deliveries also increased due to the increased demand by refineries for normal butane for use in gasoline blending and increased isobutane deliveries to Chicago area refineries. The LPGs average rate per barrel increased 17% from the prior year period as a result of an increased percentage of long-haul deliveries during the year ended December 31, 2003, and an increase in LPG tariff rates, which went into effect in July 2003.

Effective January 1, 2003, TE Products’ 50% ownership interest in MB Storage is accounted for as an equity investment. Revenues generated from Mont Belvieu operations totaled $15.2 million for the year ended December 31, 2002. As a result of the formation of MB Storage, revenues and expenses related to Mont Belvieu operations are now recorded within equity earnings. See discussion regarding changes in equity earnings/losses below.

Other operating revenues increased $5.4 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, primarily due to the addition of the northern portion of the Dean Pipeline to the Downstream Segment in January 2003, which increased other operating revenues by $4.5 million as the pipeline began transporting RGP in January 2003. The increase was also due to higher propane deliveries at our Providence, Rhode Island import facility and higher refined product loading fees. These increases were partially offset by lower

revenues from product location exchanges which are used to position product in the Midwest market area and lower volume of product inventory sales.

Costs and expenses increased $22.3 million for the year ended December 31, 2003, compared with the year ended December 31, 2002. The increase was made up of a $23.4 million increase in operating, general and administrative expenses and a $1.5 million increase in depreciation and amortization expense, partially offset by a $2.4 million decrease in taxes – other than income taxes and a $0.2 million decrease in operating fuel and power. Operating, general and administrative expenses increased primarily due to higher pipeline maintenance expenses, due in part to pipeline rehabilitation expenses associated with our integrity management program, increased consulting and contract services, increased labor costs primarily due to an increase in the number of employees between years, increased insurance expense, expense from the Centennial pipeline capacity lease agreement that we entered into in 2003 and the write-off of receivables of $0.8 million related to customer bankruptcies or other customer non-payments. The addition of the northern portion of the Dean Pipeline to the Downstream Segment increased operating, general and administrative expense by $0.7 million. Depreciation and amortization expense increased from the prior year period because of assets placed in service during the year, which resulted in increased depreciation expense. In addition, we wrote off assets taken out of service during the period to depreciation expense, which also increased depreciation expense. These increases in depreciation expense were partially offset by lower depreciation expense from assets retired during the year, which reduced the asset base, and due to the transfer of assets to MB Storage. Taxes – other than income taxes decreased as a result of actual property taxes being lower than previously estimated and due to the transfer of assets to MB Storage. Operating fuel and power expense decreased as a result of lower power costs due to a slight decrease in the price of natural gas, partially offset by increased mainline throughput.

Net losses from equity investments decreased $2.7 million for the year ended December 31, 2003, compared with the year ended December 31, 2002. On February 10, 2003, TE Products acquired an additional 16.7% interest in Centennial, bringing its ownership interest to 50%. Centennial, which commenced operations in April 2002, accounted for $11.4 million of the equity losses for the year ended December 31, 2003, resulting in an increase of $4.7 million in equity losses as compared with the year ended December 31, 2002. During the year ended December 31, 2003, we recognized increased equity losses from our investment in Centennial due to the acquisition of the additional 16.7% ownership interest in February 2003. In April 2003, we entered into a pipeline capacity lease with Centennial for a period of five years in order to expand our capacity to deliver refined products to our market areas. The losses from Centennial are partially offset by equity earnings of $7.4 million from our equity ownership interest in MB Storage, which was formed effective January 1, 2003. Amounts in the prior year period related to Mont Belvieu operations which were recorded to revenues and costs and expenses are now being recorded within equity earnings based upon our 50% ownership interest in MB Storage, effective with its formation on January 1, 2003. If the 2002 revenues and costs and expenses from the Mont Belvieu operations had been accounted for under the same method as in 2003, equity earnings from MB Storage would have increased $0.2 million in 2003, compared with the prior year, due to increased shuttle deliveries and increased storage revenue, partially offset by increases in depreciation expense and rehabilitation expenses on MB Storage assets.

Other income – net decreased $0.6 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, primarily due to lower interest income earned on cash investments.

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

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

Our Downstream Segment reported earnings before interest of $77.1 million for the year ended December 31, 2002, compared with earnings before interest of $118.1 million for the year ended December 31, 2001. Earnings before interest decreased $41.0 million primarily due to a decrease of $20.7 million in operating revenues, an increase of $13.9 million in costs and expenses, additional losses of $5.7 million from equity investments and a decrease of $0.7 million in other income – net. We discuss factors influencing our operating performance below.

Revenues from refined products transportation decreased $15.8 million for the year ended December 31, 2002, compared with the year ended December 31, 2001, primarily due to $18.9 million of revenue recognized in 2001 from a cash settlement received from a canceled transportation agreement with Pennzoil and the recognition of $1.7 million of previously deferred revenue related to the approval of market-based rates during the second quarter of 2001. See further discussion regarding these factors included in “Other Considerations.” These decreases were partially offset by a 12% increase in refined products volumes delivered during the year ended December 31, 2002, primarily due to barrels received into our pipeline from Centennial at Creal Springs, Illinois. Centennial commenced refined products deliveries to us beginning in April 2002. The overall increase in refined products deliveries was partially offset by a 1.3 million barrel decrease in methyl tertiary butyl ether (“MTBE”) deliveries as a result of the expiration of contract deliveries to our marine terminal near Beaumont effective April 2001. As a result of the contract expiration, we no longer transport MTBE through our Products Pipeline System. The refined products average rate per barrel decreased 9% from the prior year due to the impact of the Midwest origin point for volumes received from Centennial, which was partially offset by decreased short-haul MTBE volumes delivered and higher market-based tariff rates, which went into effect in July 2001.

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

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

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

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

Net losses from equity investments increased $5.7 million for the year ended December 31, 2002, compared with the year ended December 31, 2001. The increase is primarily due to pre-operating expenses and start-up costs of Centennial, which commenced operations in early April 2002.

Other income – net decreased $0.7 million for the year ended December 31, 2002, compared with the year ended December 31, 2001. The decrease was primarily due to lower interest income earned on cash investments.

Upstream Segment

Information presented in the following table includes the margin of the Upstream Segment, which may be viewed as a non-GAAP (Generally Accepted Accounting Principles) financial measure under the rules of the Securities and Exchange Commission. We calculate the margin of the Upstream Segment 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. We believe that margin is a more meaningful measure of financial performance than operating revenues and operating expenses due to the significant fluctuations in revenues and expenses caused by variations in the level of marketing activity and prices for products marketed. Margin and volume information for the years ended December 31, 2003, 2002 and 2001 is presented below (in thousands, except per barrel and per gallon amounts):


									Percentage
			Years Ended December 31,						Increase (Decrease)

			2003		2002		2001		2003			2002

Margins:
	Crude oil transportation		$	45,794	$	39,025	$	34,121		17	%		14	%
	Crude oil marketing			22,017		22,914		22,502		(4	%)		2	%
	Crude oil terminaling			9,403		10,124		10,163		(7	%)		—
	Lubrication oil sales			5,372		4,826		4,126		11	%		17	%

		Total margin	$	82,586	$	76,889	$	70,912		7	%		8	%

Total barrels:
	Crude oil transportation			95,541		82,813		78,714		15	%		5	%
	Crude oil marketing			159,710		139,182		159,477		15	%		(13	%)
	Crude oil terminaling			115,076		127,376		121,932		(10	%)		5	%
Lubrication oil volume (total gallons)				10,449		9,648		8,769		8	%		10	%
Margin per barrel:
	Crude oil transportation		$	0.479	$	0.471	$	0.434		2	%		9	%
	Crude oil marketing			0.138		0.165		0.141		(16	%)		17	%
	Crude oil terminaling			0.082		0.080		0.083		3	%		(4	%)
Lubrication oil margin (per gallon):			$	0.514	$	0.500	$	0.471		3	%		6	%

The following table reconciles the Upstream Segment margin to the consolidated statements of income using the information presented in the consolidated statements of income and the statements of income in Note 18. Segment Information (in thousands):


		Years Ended December 31,

		2003			2002			2001

Sales of petroleum products		$	3,766,651		$	2,823,800		$	3,219,816
Transportation – Crude oil			29,057			27,414			24,223
Less: Purchases of petroleum products			(3,713,122	)		(2,774,325	)		(3,173,127	)

	Total margin	$	82,586		$	76,889		$	70,912

Year Ended December 31, 2003 Compared with Year Ended December 31, 2002

Our Upstream Segment reported earnings before interest of $49.7 million for the year ended December 31, 2003, compared with earnings before interest of $46.7 million for the year ended December 31, 2002. Earnings before interest increased $3.0 million primarily due to an increase of $5.7 million in margin, an increase of $2.2 million in equity earnings of Seaway and a gain of $3.9 million from the sale of assets, partially offset by an increase of $7.6 million in costs and expenses (excluding purchases of crude oil and lubrication oil) and a decrease of $1.2 million in other income – net. We discuss factors influencing our operating performance below.

Our margin increased $5.7 million for the year ended December 31, 2003, compared with the year ended December 31, 2002. Crude oil transportation margin increased $6.8 million primarily due to increased revenues on our Red River, Basin, South Texas and West Texas systems resulting from a 15% increase in transportation volumes on these systems partially due to the acquisition of the Genesis assets. During the fourth quarter of 2003, we completed the purchase of crude supply and transportation assets (Genesis), which was integrated into our South Texas system. The acquisition of the Genesis assets increased our transportation and marketing margins by approximately $1.2 million and the barrels transported and marketed by approximately 1.6 million barrels during 2003. Lubrication oil sales margin increased $0.5 million due to increased sales of chemical volumes, higher margins on lubrication sales and increased volumes related to the acquisition of a lubrication oil distributor in Abilene, Texas, in December 2003. Crude oil marketing margin decreased $0.9 million primarily due to an invoicing settlement on a marketing contract in the first quarter of 2003, partially offset by increased volumes marketed, renegotiated supply contracts, lower trucking expenses and more favorable crude oil price differentials. Crude oil terminaling margin decreased $0.7 million as a result of a 10% decrease in volumes at Midland, Texas, and Cushing, Oklahoma.

Costs and expenses (excluding expenses associated with purchases of crude oil and lubrication oil) increased $7.6 million for the year ended December 31, 2003, compared with the year ended December 31, 2002. Operating, general and administrative expenses increased $7.1 million from the prior year period. The increase includes a $2.4 million increase in environmental assessment and remediation costs in 2003, higher legal costs related to the litigation and settlement with D.R.D. and other legal costs (see Note 17. Commitments and Contingencies), $1.7 million of expense from the net settlement of crude oil imbalances with customers, higher pipeline rehabilitation expenses associated with our integrity management program and increased labor costs due to an increase in the number of employees between periods, partially offset by lower general and administrative supplies expenses during the period. In addition, the acquisition of the Genesis assets and integration into our South Texas system during the fourth quarter increased operating, general and administrative expenses by approximately $0.5 million. Operating fuel and power increased $0.3 million due to higher power costs and higher volumes in 2003. Depreciation and amortization expense increased $0.1 million due to assets placed in service in 2002 and 2003 and due to asset retirements. Taxes - - other than income taxes increased $0.1 million due to slight increases in property tax accruals.

Equity earnings from our investment in Seaway increased $2.2 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, due to a favorable crude oil imbalance settlement, a gain on the sale of inventory, lower general and administrative expenses and higher long-haul transportation volumes, partially offset by our portion of equity earnings which decreased from 80% to 60% on a pro-rated basis in 2002 (averaging approximately 67% for the year ended December 31, 2002), to 60% in 2003.

In June 2003, we recorded a net gain of $3.9 million, included in the gain on sale of assets in our consolidated statements of income, on the sale of certain of the assets of the 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 current owners of the Rancho 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.

Other income – net decreased $1.2 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, primarily due to lower interest income received on intercompany borrowings.

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

Our Upstream Segment reported earnings before interest of $46.7 million for the year ended December 31, 2002, compared with earnings before interest of $38.0 million for the year ended December 31, 2001. Earnings before interest increased $8.7 million primarily due to an increase of $6.0 million in margin, a decrease of $2.9 million in costs and expenses (excluding purchases of crude oil and lubrication oil), an increase of $0.3 million in other income – net and an increase of $0.2 million in equity earnings of Seaway. These increases were partially offset by a decrease of $0.7 million in other operating revenues. We discuss factors influencing our operating performance below.

Our margin increased $6.0 million for the year ended December 31, 2002, compared with the year ended December 31, 2001. Crude oil transportation margin increased $4.9 million primarily due to volumes transported on the pipeline assets acquired from Valero in March 2001 and higher revenues on our Basin, Red River and West Texas systems. Crude oil terminaling margin remained constant between years as a result of higher volumes at Midland and our Red River system, offset by lower volumes at Cushing and on our Basin system. Lubrication oil sales margin increased $0.7 million due to increased volumes related to the acquisition of a lubrication oil distributor in Amarillo, Texas, in the fourth quarter of 2001. Crude oil marketing margin increased $0.4 million primarily due to increased volumes marketed, renegotiated supply contracts and lower trucking expenses.

Other operating revenues of the Upstream Segment decreased $0.7 million for the year ended December 31, 2002, compared with the year ended December 31, 2001, due to lower revenues from documentation and other services to support customers’ trading activity at Midland and Cushing.

Costs and expenses (excluding expenses associated with purchases of crude oil and lubrication oil) decreased $2.9 million for the year ended December 31, 2002, compared with the year ended December 31, 2001. Operating, general and administrative expenses decreased $3.8 million from the prior year due to $4.4 million of environmental costs recognized in 2001 and decreased labor related costs, partially offset by increased general and administrative supplies and services expense and environmental costs recognized in 2002 (see Note 17. Commitments and Contingencies). Depreciation and amortization expense increased $1.9 million due to increased depreciation expense on the assets acquired from Valero and from the acquisition of a lubrication oil distributor in Amarillo, Texas, partially offset by lower amortization costs from the adoption of SFAS 142 effective January 1, 2002, in which goodwill and excess investment are no longer being amortized. Taxes – other than income taxes decreased $1.6 million due to reductions in property tax accruals. These decreases were partially offset by an increase of $0.6 million in operating fuel and power costs attributed to higher transportation volumes.

Equity earnings from our investment in Seaway for the year ended December 31, 2002, increased $0.2 million from the year ended December 31, 2001, due to higher third party transportation volumes. This increase was partially offset by our portion of equity earnings being reduced from 80% to 60% on a pro rated basis in 2002 (averaging approximately 67% for the year ended December 31, 2002). Equity earnings from our investment in Seaway were affected in 2002 as a result of the reduction of the sharing percentages of TCTM under the Seaway partnership agreement. Beginning in June 2002, our participation in Seaway decreased from 80% of revenue and expense of Seaway to 60%. See Items 1 and 2. Business and Properties, “Upstream Segment – Gathering, Transportation, Marketing and Storage of Crude Oil” for a more detailed discussion.

Midstream Segment

The following table presents volume and average rate information for the years ended December 31, 2003, 2002 and 2001:


								Percentage
		Years Ended December 31,						Increase (Decrease)

		2003		2002		2001		2003			2002

Gathering – Natural Gas:
	Million cubic feet		461,238		340,697		45,496		35	%		649	%
	Million British thermal units (“MMBtu”)		469,127		353,663		50,650		33	%		598	%
	Average fee per MMBtu	$	0.288	$	0.255	$	0.174		13	%		47	%
Transportation – NGLs:
	Thousand barrels		57,902		53,980		21,538		7	%		151	%
	Average rate per barrel	$	0.688	$	0.720	$	0.961		(4	%)		(25	%)
Fractionation – NGLs:
	Thousand barrels		4,131		4,072		4,078		1	%		—
	Average rate per barrel	$	1.804	$	1.824	$	1.813		(1	%)		1	%
Sales – Condensate:
	Thousand barrels		63.3		80.0		16.2		(21	%)		394	%
	Average rate per barrel	$	30.25	$	25.39	$	19.91		19	%		28	%

Year Ended December 31, 2003 Compared with Year Ended December 31, 2002

Our Midstream Segment reported earnings before interest of $80.6 million for the year ended December 31, 2003, compared with earnings before interest of $61.0 million for the year ended December 31, 2002. Earnings before interest increased $19.6 million due to an increase of $46.2 million in operating revenues, partially offset by an increase of $26.6 million in costs and expenses. We discuss factors influencing our operating performance below.

Revenues from the gathering of natural gas increased $45.1 million for the year ended December 31, 2003, compared with the year ended December 31, 2002. Natural gas gathering revenues from the Jonah system increased $14.6 million and volumes delivered increased 54.6 Bcf for the year ended December 31, 2003, due to the expansions of the Jonah system during 2002. The first expansion, which was completed in May 2002, increased the capacity of the Jonah system by 62%, from approximately 450 MMcf/day to approximately 730 MMcf/day. In October 2002, additional expansion projects were completed, which increased the capacity of the Jonah system from 730 MMcf/day to approximately 880 MMcf/day. A Phase III expansion was substantially completed during the fourth quarter of 2003 and increased system capacity to 1,180 MMcf/day. The increase in Jonah’s revenues is also partially due to an increase in the average natural gas gathering rate due to certain volume thresholds being exceeded. Natural gas gathering revenues from the Val Verde system increased $30.5 million and volumes delivered increased 65.9 Bcf for the year ended December 31, 2003, primarily due to the acquisition of the Val Verde system on June 30, 2002. Volumes delivered for the first half of 2003 were approximately 82.0 Bcf. As Val Verde was acquired on June 30, 2002, there were no comparable volumes for the first half of 2002. Volumes delivered during the second half of 2003 as compared to the second half of 2002 declined approximately 16.0 Bcf. This decrease in volumes during the second half of 2003 was due to the natural decline of CBM production, which resulted in decreased revenues, partially offset by an increase in the average natural gas gathering rate due to annual fee escalations in gathering agreements and higher carbon dioxide treating fees as a result of increasing carbon dioxide content in the natural gas.

Revenues from the transportation of NGLs increased $1.0 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, primarily due to an increase of $4.4 million related to the acquisition of Chaparral on March 1, 2002, $0.7 million due to an increase in volumes transported on Chaparral and $0.2 million due to an increase in volumes transported on the Wilcox Pipeline. This increase was partially offset by a decrease of $2.4 million due to lower transportation volumes on the Panola Pipeline as a result of lower NGL volumes available from the connected NGL plants and a decrease of $1.9 million on the southern portion of the Dean Pipeline due to decreased transportation volumes. Lower transportation volumes on the southern portion of the Dean Pipeline resulted from the conversion of the northern portion of the pipeline to transport RGP and subsequent classification as a part of the Downstream Segment, effective January 1, 2003. The decrease in the NGL transportation average rate per barrel resulted from a lower average rate per barrel on volumes transported on Chaparral.

Other operating revenues increased $0.1 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, due to an increase in stabilizer overhead gas on the Jonah system, partially offset by a decrease in condensate sales on Jonah.

Costs and expenses increased $26.6 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, due to a $13.1 million increase in depreciation and amortization expense, a $12.1 million increase in operating, general and administrative expense and a $1.6 million increase in operating fuel and power, partially offset by a $0.2 million decrease in taxes - - other than income taxes. Depreciation and amortization expense increased $14.6 million due to the Chaparral and Val Verde assets acquired on March 1, 2002, and June 30, 2002, respectively, $0.3 million due to assets placed in service in 2002 related primarily to the expansions of the Jonah system and $2.0 million in amortization expense on Jonah’s intangible assets under the units-of-production method, as volumes gathered increased between periods. These increases were partially offset by a decrease of $1.8 million in amortization expense on Val Verde’s intangible assets under the units-of-production method as volumes gathered decreased between periods. In addition, amortization expense on Jonah decreased $2.0 million related to its intangible assets. In second quarter 2003, Jonah’s estimated total throughput of the system was adjusted, which resulted in an extension of the expected amortization period from 16 years to 25 years (see Note 3. Goodwill and Other Intangible Assets). Operating, general and administrative expense increased $11.0 million from the assets acquired, and $1.1 million primarily due to higher general and administrative labor and supplies expense and increased consulting and contracting services. Operating fuel and power costs increased $0.8 million due to the assets acquired and $0.8 million due to increased volumes transported on Chaparral. Taxes – other than income taxes decreased $0.2 million due to actual property taxes being lower than previously estimated on Val Verde, Panola Pipeline and the southern portion of the Dean Pipeline.

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

Our Midstream Segment reported earnings before interest of $61.0 million for the year ended December 31, 2002, compared with earnings before interest of $15.9 million for the year ended December 31, 2001. Earnings before interest increased $45.1 million due to an increase of $101.6 million in operating revenues and an increase of $0.3 million in other income – net, partially offset by an increase of $56.8 million in costs and expenses. We discuss factors influencing our operating performance below.

Revenues from the gathering of natural gas increased $81.2 million for the year ended December 31, 2002, compared with the year ended December 31, 2001. Natural gas gathering revenues from the Jonah system increased $41.3 million and volumes delivered increased 202.9 Bcf for the year ended December 31, 2002, due to a full year’s contribution to earnings from Jonah in 2002. The Jonah system was acquired on September 30, 2001. Natural gas gathering revenues from the Val Verde system, which was acquired on June 30, 2002, totaled $39.9 million and volumes delivered totaled 92.3 Bcf for the year ended December 31, 2002.

Revenues from the transportation of NGLs increased $18.2 million for the year ended December 31, 2002, compared with the year ended December 31, 2001. NGL transportation revenues increased $18.2 million, primarily due to the acquisition of the Chaparral NGL system on March 1, 2002, partially offset by lower revenues on a take-or-pay contract on the Dean Pipeline that was in effect until the bankruptcy of Enron Corp. in December 2001. The decrease in the NGL transportation average rate per barrel resulted from the cancellation of the Enron Corp. take-or-pay contract and a lower average rate per barrel on volumes transported on Chaparral.

Other operating revenues increased $2.2 million for the year ended December 31, 2002, compared with the year ended December 31, 2001, primarily due to an increase in sales of gas condensate from the Jonah system.

Costs and expenses increased $56.8 million for the year ended December 31, 2002, compared with the year ended December 31, 2001, due to a $34.8 million increase in depreciation and amortization expense, a $15.5 million increase in operating, general and administrative expense, a $4.1 million increase in operating fuel and power costs and a $2.4 million increase in taxes – other than income taxes. Depreciation and amortization expense increased $34.6 million due to the acquisition of the Jonah, Chaparral and Val Verde assets on September 30, 2001, March 1, 2002, and June 30, 2002, respectively. Operating, general and administrative expense increased $15.5 million due to an increase of $17.6 million from assets acquired and an increase of $2.2 million attributable to higher general and administrative labor and supplies expense, partially offset by decreased operating expenses. Operating, general and administrative expenses for the year ended December 31, 2001, included a $4.3 million reserve for a doubtful receivable balance under a transportation contract with an Enron Corp. subsidiary. Operating fuel and power costs and taxes – other than income taxes increased $4.1 million and $2.4 million, respectively, due to the assets acquired in 2001 and 2002.

Interest Expense and Capitalized Interest

Year Ended December 31, 2003 Compared with Year Ended December 31, 2002

Interest expense increased $19.0 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, primarily due to $12.3 million of additional expense related to changes in our fair value and cash flow hedging activities, $16.1 million of additional expense related to the issuance of our 6.125% Senior Notes in January 2003 and our 7.625% Senior Notes in February 2002 and $1.3 million of debt issuance costs written off in June 2003 related to the refinancing of our revolving credit facility. These increases were partially offset by a $10.7 million reduction in interest expense related to decreased borrowings under our revolving credit facility.

Capitalized interest increased $0.9 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, due to increased construction work-in-progress balances during 2003, partially offset by interest capitalized on our investment in Centennial during the first quarter of 2002.

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

Interest expense increased $4.5 million for the year ended December 31, 2002, compared with the year ended December 31, 2001, primarily due to higher outstanding debt balances used for capital expenditures and to finance the acquisition of assets acquired in the Midstream Segment, partially offset by lower LIBOR rates in effect during the year ended December 31, 2002.

Capitalized interest increased $0.3 million for the year ended December 31, 2002, compared with the year ended December 31, 2001, due to interest capitalized on the investment during the construction of the Jonah expansion and increased balances during 2002 on construction work-in-progress.

Financial Condition and Liquidity

Cash generated from operations, credit facilities and debt and equity offerings are our primary sources of liquidity. At December 31, 2003, and 2002, we had working capital deficits of $22.8 million and $6.2 million, respectively. At December 31, 2003, we had $340.0 million in available borrowing capacity under our revolving credit facility to cover any working capital shortfalls. Cash flows for the years ended December 31, 2003, 2002 and 2001 were as follows (in millions):


		Years Ended December 31,

		2003			2002			2001

Cash provided by (used in):
	Operating activities	$	239.4		$	234.9		$	169.2
	Investing activities		(185.3	)		(724.7	)		(557.9	)
	Financing activities		(55.6	)		495.3			387.1

Operating Activities

Net cash from operating activities for the years ended December 31, 2003, 2002 and 2001, were comprised of the following (in millions):


	Years Ended December 31,

	2003			2002			2001

Net income	$	125.8		$	117.9		$	109.1
Depreciation and amortization		100.7			86.0			45.9
Earnings in equity investments		(16.9	)		(12.0	)		(26.4	)
Distributions from equity investments		28.0			30.9			40.8
Gain on sale of assets		(3.9	)		—			—
Non-cash portion of interest expense		4.8			4.9			4.1
Cash provided by (used in) working capital and other		0.9			7.2			(4.3	)

Net cash from operating activities	$	239.4		$	234.9		$	169.2

For a discussion of changes in earnings before interest, depreciation and amortization, equity earnings and gain on sale of assets by segment and consolidated interest expense – net, see Results of Operations for the Downstream Segment, Upstream Segment and Midstream Segment in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. Cash provided by operating activities increased for the year ended December 31, 2003, compared with the years ended December 31, 2002, and 2001, primarily due to our 2002 and 2001 acquisitions and changes in working capital components resulting from the timing of cash receipts and cash disbursements. Distributions from equity method investments decreased between periods, primarily due to our sharing ratio in Seaway decreasing from 80% to 60% between years, partially offset by a distribution from MB Storage in 2003 of $5.3 million.

We believe that we will continue to have adequate liquidity to fund future recurring operating and investing activities. Our primary cash requirements consist of normal operating expenses, capital expenditures to sustain existing operations and revenue generating expenditures, interest payments on our Senior Notes and revolving credit facility, distributions to our General Partner and unitholders and acquisitions of new assets or businesses. Short-term cash requirements, such as operating expenses, capital expenditures to sustain existing operations and quarterly distributions to our General Partner and unitholders, are expected to be funded through operating cash flows. Long-term cash requirements for expansion projects and acquisitions are expected to be funded by several sources, including cash flows from operating activities, borrowings under credit facilities, and the issuance of additional equity and debt securities. Our ability to complete future debt and equity offerings and the timing of any such

offerings will depend on various factors, including prevailing market conditions, interest rates and our financial condition and our credit rating at the time.

Net cash from operating activities for the years ended December 31, 2003, 2002 and 2001, included interest payments, net of amounts capitalized, of $79.9 million, $48.9 million and $61.5 million, respectively. Excluding the effects of hedging activities and interest capitalized, during the year ended December 31, 2004, we expect interest payments on our fixed rate Senior Notes to be approximately $78.0 million. We expect to pay our interest payments with cash flows from operating activities.

Investing Activities

Cash flows used in investing activities totaled $185.3 million for the year ended December 31, 2003, and were comprised of $140.6 million of capital expenditures, $22.0 million for our acquisition of the Genesis assets and other assets, $20.0 million for TE Products’ acquisition of an additional 16.7% interest in Centennial, $4.0 million of cash contributions for TE Products’ ownership interest in Centennial and $2.5 million of cash contributions for TE Products’ ownership interest in MB Storage. These uses of cash were partially offset by $3.0 million in net cash proceeds from the Rancho Pipeline transactions and $0.8 million received on matured cash investments. Cash flows used in investing activities totaled $724.7 million for the year ended December 31, 2002, and were comprised of $7.3 million for the final purchase price adjustments on the acquisition of Jonah, $133.4 million of capital expenditures, $10.9 million of cash contributions for TE Products’ ownership interest in Centennial, $132.4 million for the purchase of the Chaparral NGL system on March 1, 2002, and $444.2 million for the purchase of Val Verde on June 30, 2002. These uses of cash were partially offset by $3.5 million in cash proceeds from the sale of assets. Cash flows used in investing activities totaled $557.9 million for the year ended December 31, 2001, and were comprised of $359.8 million for the purchase of Jonah on September 30, 2001, $107.6 million of capital expenditures, $65.0 million of cash contributions for TE Products’ ownership interest in Centennial, $20.0 million for the purchase of assets from Valero on March 1, 2001, and $11.0 million paid in October 2001, for the final purchase price settlement related to the previously acquired ARCO assets. These uses of cash were partially offset by $1.3 million of cash received from the sale of vehicles and $4.2 million received on matured cash investments.

Financing Activities

Cash flows used in financing activities totaled $55.6 million for the year ended December 31, 2003, and were comprised of $382.0 million in proceeds from revolving credit facilities; $198.6 million from the issuance in January 2003 of our 6.125% Senior Notes due 2013, partially offset by debt issuance costs of $3.4 million; and $287.5 million from the issuance of 9.2 million Units in April and August 2003. These sources of cash for the year ended December 31, 2003, were partially offset by $604.0 million of repayments on our revolving credit facilities, $113.8 million to repurchase and retire all of the 3.9 million outstanding Class B Units, and $202.5 million of distributions paid to unitholders. Cash flows provided by financing activities totaled $495.3 million for the year ended December 31, 2002, and were comprised of $675.0 million in proceeds from revolving credit facilities; $497.8 million from the issuance in February 2002 of our 7.625% Senior Notes due 2012, partially offset by debt issuance costs of $7.0 million; $372.5 million from the issuance of 13.4 million Units during the year ended December 31, 2002, and $7.6 million of General Partner contributions; and $44.9 million of proceeds from the termination of our interest rate swaps on our 7.625% Senior Notes due 2012. These sources of cash for the year ended December 31, 2002, were partially offset by $943.7 million of repayments on our revolving credit facilities and $151.8 million of distributions to unitholders. Cash flows provided by financing activities totaled $387.1 million for the year ended December 31, 2001, and were comprised of $546.1 million of proceeds from term and revolving credit facilities, partially offset by debt issuance costs of $2.6 million; and $234.7 million from the issuance of 7.8 million Units during the year ended December 31, 2001, and $4.8 million of General Partner contributions. These sources of cash for the year ended December 31, 2001 were partially offset by $291.5 million of repayments on our term and revolving credit facilities and $104.4 million of distributions to unitholders.

Centennial entered into credit facilities totaling $150.0 million, and as of December 31, 2003, $150.0 million was outstanding under those credit facilities. The proceeds were used to fund construction and conversion costs of its pipeline system. TE Products and Marathon have each guaranteed one-half of Centennial’s debt, up to a maximum of $75.0 million each.

Credit Facilities and Interest Rate Swap Agreements

On April 6, 2001, we entered into a $500.0 million revolving credit facility including the issuance of letters of credit of up to $20.0 million (“Three Year Facility”). The interest rate was based, at our option, on either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement for the Three Year Facility contained certain restrictive financial covenant ratios. During 2002, borrowings under the Three Year Facility were used to finance the acquisitions of Chaparral on March 1, 2002, and Val Verde on June 30, 2002, and for general partnership purposes. During 2002, repayments were made on the Three Year Facility with proceeds from the issuance of our 7.625% Senior Notes, proceeds from the issuance of additional Units and proceeds from the termination of interest rate swaps (see Note 4. Interest Rate Swaps). During the first quarter of 2003, we repaid $182.0 million of the outstanding balance of the Three Year Facility with proceeds from the issuance of our 6.125% Senior Notes on January 30, 2003. On June 27, 2003, we repaid the outstanding balance under the Three Year Facility with borrowings under a new credit facility, and canceled the Three Year Facility.

On June 27, 2003, we entered into a $550.0 million revolving credit facility with a three year term, including the issuance of letters of credit of up to $20.0 million (“Revolving Credit Facility”). The interest rate is based, at our option, on either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement for the Revolving Credit Facility contains certain restrictive financial covenant ratios. We borrowed $263.0 million under the Revolving Credit Facility and repaid the outstanding balance of the Three Year Facility. On December 31, 2003, $210.0 million was outstanding under the Revolving Credit Facility at a weighted average interest rate, before the effects of hedging activities, of 1.9%. At December 31, 2003, we were in compliance with the covenants in this credit agreement.

On April 6, 2001, we entered into a 364-day, $200.0 million revolving credit agreement (“Short-term Revolver”). The interest rate was based, at our option, on either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement contained certain restrictive financial covenant ratios. On March 28, 2002, the Short-term Revolver was extended for an additional period of 364 days, ending in March 2003. During 2002, borrowings under the Short-term Revolver were used to finance the acquisition of the Val Verde assets and for other purposes. During 2002, we repaid the existing amounts outstanding under the Short-term Revolver with proceeds we received from the issuance of Units in 2002. The Short-term Revolver expired on March 27, 2003.

On September 28, 2001, we entered into a $400.0 million credit facility with SunTrust Bank (“Bridge Facility”) payable in June 2002. We borrowed $360.0 million under the Bridge Facility to acquire the Jonah assets (see Note 6. Acquisitions and Dispositions). During the fourth quarter of 2001, we repaid $160.0 million of the outstanding principal from proceeds received from the issuance of Units in November 2001. On February 5, 2002, we borrowed an additional $15.0 million under the Bridge Facility. On February 20, 2002, we repaid the outstanding balance of the Bridge Facility of $215.0 million with proceeds from the issuance of the 7.625% Senior Notes and canceled the facility.

On February 20, 2002, we completed the issuance of $500.0 million principal amount of 7.625% Senior Notes due 2012. The 7.625% Senior Notes were issued at a discount of $2.2 million and are being accreted to their face value over the term of the notes. We used the proceeds from the offering to reduce a portion of the outstanding balances of our credit facilities, including those issued in connection with the acquisition of Jonah. The Senior Notes may be redeemed at any time at our option with the payment of accrued interest and a make-whole premium determined by discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of comparable remaining maturity plus 35 basis points. The indenture governing the 7.625% Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit our ability to incur additional indebtedness. As of December 31, 2003, we were in compliance with the covenants of these Senior Notes.

either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement contained certain restrictive financial covenant ratios. On July 11, 2002, we repaid $90.0 million of the outstanding principal from proceeds primarily received from the issuance of Units in July 2002. On September 10, 2002, we repaid the remaining outstanding balance of $110.0 million with proceeds received from the issuance of Units in September 2002, and canceled the facility.

On January 30, 2003, we completed the issuance of $200.0 million principal amount of 6.125% Senior Notes due 2013. The 6.125% Senior Notes were issued at a discount of $1.4 million and are being accreted to their face value over the term of the notes. We used $182.0 million of the proceeds from the offering to reduce the outstanding principal on the Three Year Facility to $250.0 million. The balance of the net proceeds received was used for general partnership purposes. The Senior Notes may be redeemed at any time at our option with the payment of accrued interest and a make-whole premium determined by discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of comparable remaining maturity plus 35 basis points. The indenture governing our 6.125% Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit our ability to incur additional indebtedness. As of December 31, 2003, we were in compliance with the covenants of these Senior Notes.

We have entered into interest rate swap agreements to hedge our exposure to cash flows and fair value changes. These agreements are more fully described in Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

The following table summarizes our credit facilities as of December 31, 2003 (in millions):


		As of December 31, 2003

				Available
		Outstanding		Borrowing		Maturity
Description:		Principal		Capacity		Date

Revolving Credit Facility		$	210.0	$	340.0	June 2006
6.45% Senior Notes (1)			180.0		—	January 2008
7.625% Senior Notes (1)			500.0		—	February 2012
6.125% Senior Notes (1)			200.0		—	February 2013
7.51% Senior Notes (1)			210.0		—	January 2028

	Total	$	1,300.0	$	340.0

(1)

Our TE Products subsidiary entered into an interest rate swap agreement to hedge its exposure to changes in the fair value of its 7.51% Senior Notes due 2028. At December 31, 2003, the 7.51% Senior Notes include an adjustment to increase the fair value of the debt by $2.3 million related to this interest rate swap agreement. We also entered into interest rate swap agreements to hedge our exposure to changes in the fair value of our 7.625% Senior Notes due 2012. At December 31, 2003, the 7.625% Senior Notes include a deferred gain, net of amortization, from previous interest rate swap terminations of $40.6 million. At December 31, 2003, our 6.45% Senior Notes, our 7.625% Senior Notes and our 6.125% Senior Notes include $3.2 million of unamortized debt discounts. The fair value adjustments, the deferred gain adjustment and the unamortized debt discounts are excluded from this table.

Distributions and Issuance of Additional Limited Partner Units

We paid cash distributions of $202.5 million ($2.50 per Unit), $151.9 million ($2.35 per Unit) and $104.4 million ($2.15 per Unit), during each of the years ended December 31, 2003, 2002 and 2001, respectively. Additionally, on January 16, 2004, we declared a cash distribution of $0.65 per Unit for the quarter ended December 31, 2003. The distribution of $57.1 million was paid on February 6, 2004, to unitholders of record on January 30, 2004.

repay $50.0 million of the outstanding balance on the Three Year Facility, with the remaining amount being used for general partnership purposes.

On July 11, 2002, we sold in an underwritten public offering 3.0 million Units at $30.15 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $86.6 million and were used to reduce borrowings under our Six-Month Term Loan. On August 14, 2002, 175,000 Units were sold upon exercise of the underwriters’ over-allotment option granted in connection with the offering on July 11, 2002. Proceeds from that sale totaled $5.1 million and were used for general partnership purposes.

On September 5, 2002, we sold in an underwritten public offering 3.8 million Units at $29.72 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $108.1 million and were used to reduce borrowings under our Six-Month Term Loan. On September 19, 2002, 570,000 Units were sold upon exercise of the underwriters’ over-allotment option granted in connection with the offering on September 5, 2002. Proceeds from that sale totaled $16.2 million and were used to reduce borrowings under our Short-term Revolver.

On November 7, 2002, we sold in an underwritten public offering 3.3 million Units at $26.83 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $84.8 million and were used to reduce borrowings under our Short-term Revolver and Three Year Facility. On December 4, 2002, 495,000 Units were sold upon exercise of the underwriters’ over-allotment option granted in connection with the offering on November 7, 2002. Proceeds from that sale totaled $12.7 million and were used to reduce borrowings under our Short-term Revolver and Three Year Facility.

On April 2, 2003, we sold in an underwritten public offering 3.9 million Units at $30.35 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $114.5 million, of which approximately $113.8 million was used to repurchase and retire all of the 3.9 million previously outstanding Class B Units held by DETTCO. We received approximately $0.7 million in proceeds from the offering in excess of the amount needed to repurchase and retire the Class B Units.

On August 7, 2003, we sold in an underwritten public offering 5.0 million Units at $34.68 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $166.0 million. On August 19, 2003, 162,900 Units were sold upon exercise of the underwriters’ over-allotment option granted in connection with the offering on August 7, 2003. Proceeds from the over-allotment sale, net of underwriting discount, totaled $5.4 million. Approximately $53.0 million of the proceeds were used to repay indebtedness under our revolving credit facility and $21.0 million was used to fund the acquisition of the Genesis assets (see Note 6. Acquisitions and Dispositions). The remaining amount was used primarily to fund revenue-generating and system upgrade capital expenditures and for general partnership purposes.

General Partner Interest

As of December 31, 2003, we had a deficit balance of $7.2 million in our General Partner’s equity account. This negative balance does not represent an asset to us and does not represent an obligation of the General Partner to contribute cash or other property to us. The General Partner’s equity account consists of its cumulative share of our net income and cash distributions that we made and capital contributions that it has made to us (see our Consolidated Statements of Partners’ Capital for a detail of the General Partner’s equity account). For the year ended December 31, 2003, the General Partner was allocated $34.8 million (representing 27.65%) of our net income and received $54.7 million in cash distributions.

Capital Accounts, as defined under our Partnership Agreement, are maintained for our General Partner and our limited partners. The Capital Account provisions of our Partnership Agreement incorporate principles established for U.S. Federal income tax purposes and are not comparable to the equity accounts reflected under accounting principles generally accepted in the United States in our financial statements. Under our Partnership Agreement, the General Partner is only required to make additional capital contributions to us upon the issuance of any additional limited partner units and only if necessary to maintain a Capital Account balance equal to 1.999999% of the total Capital Accounts of all partners. At December 31, 2003, the General Partner’s Capital Account balance substantially exceeded this requirement.

Net income is allocated between the General Partner and the limited partners in the same proportion as aggregate cash distributions made to the General Partner and the limited partners during the period. This is generally consistent with the manner of allocating net income under our Partnership Agreement. Net income determined under our Partnership Agreement, however, incorporates principles established for U.S. Federal income tax purposes and is not comparable to net income reflected under accounting principles generally accepted in the United States in our financial statements.

Cash distributions that we make during a period may exceed our net income for the period. 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 (see Note 12. Partners’ Capital and Distributions). Cash distributions in excess of net income allocations and capital contributions during the year ended December 31, 2003, resulted in a deficit in the General Partner’s equity account at December 31, 2003. Future cash distributions which exceed net income will result in an increase in the deficit balance in the General Partner’s equity account.

According to the Partnership Agreement, in the event of our dissolution, after satisfying our liabilities, our remaining assets would be divided among our limited partners and the General Partner generally in the same proportion as Available Cash but calculated on a cumulative basis over the life of the partnership. After all allocations are made between the partners, if a deficit balance in its equity account still remains for the General Partner, the General Partner would not be required to make whole any such deficit.

Future Capital Needs and Commitments

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 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.

Our debt repayment obligations consist of payments for principal and interest on (i) outstanding principal amounts under the Revolving Credit Facility due in June 2006 ($210.0 million outstanding at December 31, 2003), (ii) the TE Products $180.0 million 6.45% Senior Notes due January 15, 2008, (iii) our $500.0 million 7.625% Senior Notes due February 15, 2012, (iv) our $200.0 million 6.125% Senior Notes due February 1, 2013, and (v) the TE Products $210.0 million 7.51% Senior Notes due January 15, 2028.

TE Products is contingently liable as guarantor for the lesser of one-half or $75.0 million principal amount (plus interest) of the borrowings of Centennial. In January 2003, TE Products entered into a pipeline capacity lease agreement with Centennial for a period of five years that contains a minimum throughput requirement. During the year ended December 31, 2003, TE Products exceeded the minimum throughput requirements on the lease agreement. On February 10, 2003, TE Products acquired an additional 16.7% ownership interest in Centennial, bringing its ownership percentage to 50%.

During the years ended December 31, 2003, 2002 and 2001, we contributed $4.0 million, $10.9 million and $65.0 million, respectively, to Centennial to cover operating shortfalls and capital expenditures. During the year ended December 31, 2003, we contributed $2.5 million to MB Storage for capital expenditures. During 2004, we may be required to contribute cash to both Centennial and MB Storage to cover capital expenditures or other operating shortfalls.

We do not rely on off-balance sheet borrowings to fund our acquisitions. We have no off-balance sheet commitments for indebtedness other than the limited guaranty of Centennial debt and leases covering assets utilized in several areas of our operations.

The following table summarizes our debt repayment obligations and material contractual commitments as of December 31, 2003 (in millions):


		Amount of Commitment Expiration Per Period

										More than
		Total		Less than 1 Year		1-3 Years		3-5 Years		5 Years

Revolving Credit Facility		$	210.0	$	—	$	210.0	$	—	$	—
6.45% Senior Notes due 2008 (1) (2)			180.0		—		—		180.0		—
7.625% Senior Notes due 2012 (2)			500.0		—		—		—		500.0
6.125% Senior Notes due 2013 (2)			200.0		—		—		—		200.0
7.51% Senior Notes due 2028 (1) (2)			210.0		—		—		—		210.0

	Debt subtotal		1,300.0		—		210.0		180.0		910.0

Operating leases			71.6		16.5		27.9		15.3		11.9

	Total	$	1,371.6	$	16.5	$	237.9	$	195.3	$	921.9

(1)		Obligations of TE Products.

(2)		Our TE Products subsidiary entered into an interest rate swap agreement to hedge its exposure to changes in the fair value of its 7.51% Senior Notes due 2028. At December 31, 2003, the 7.51% Senior Notes include an adjustment to increase the fair value of the debt by $2.3 million related to this interest rate swap agreement. We also entered into interest rate swap agreements to hedge our exposure to changes in the fair value of our 7.625% Senior Notes due 2012. At December 31, 2003, the 7.625% Senior Notes include a deferred gain, net of amortization, from previous interest rate swap terminations of $40.6 million. At December 31, 2003, our 6.45% Senior Notes, our 7.625% Senior Notes and our 6.125% Senior Notes include $3.2 million of unamortized debt discounts. The fair value adjustments, the deferred gain adjustment and the unamortized debt discounts are excluded from this table.

We expect to repay the long-term, senior unsecured obligations and bank debt through the issuance of additional long-term senior unsecured debt at the time the 2008, 2012, 2013 and 2028 debt matures, issuance of additional equity, with proceeds from dispositions of assets, cash flow from operations or any combination of the above items.

Sources of Future Capital

Historically, we have funded our capital commitments from operating cash flow and borrowings under bank credit facilities or bridge loans. We repaid these loans in part by the issuance of long term debt in capital markets and the public offering of Units. We expect future capital needs would be similarly funded to the extent not otherwise available from cash flow from operations.

As of December 31, 2003, we had $340.0 million in available borrowing capacity under the Revolving Credit Facility. We expect that cash flows from operating activities will be adequate to fund cash distributions and capital additions necessary to sustain existing operations. However, future expansionary capital projects and acquisitions may require funding through proceeds from the sale of additional debt or equity offerings.

Our senior unsecured debt is rated BBB by Standard and Poors (“S&P”) and Baa3 by Moody’s Investors Service (“Moody’s”). Both ratings are stable. A rating reflects only the view of a rating agency and is not a recommendation to buy, sell or hold any indebtedness. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it determines that the circumstances warrant such a change. The senior unsecured debt of our subsidiary, TE Products, is also rated BBB by S&P and Baa3 by Moody’s.

Other Considerations

Credit Risks

Risks of non-payment and nonperformance by customers are a major consideration in our businesses. Our credit procedures and policies do not fully eliminate customer credit risk. During the years ended December 31, 2003, 2002 and 2001, some of our customers filed for bankruptcy protection. During the years ended December 31, 2003 and 2002, we expensed approximately $0.8 million and $0.9 million, respectively, of uncollectible receivables due to customer bankruptcies and other customer non-payments. During the year ended December 31, 2001, we expensed a receivable for transportation fees of approximately $4.3 million, or approximately $0.09 per Unit because of the bankruptcy of Enron Corp. and certain of its subsidiaries in December 2001.

Terrorist Threats

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

Environmental

In 1994, the LDEQ issued a compliance order for environmental contamination at our Arcadia, Louisiana, facility. This contamination may be attributable to our operations, as well as 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.

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.

Market-Based Rates

On May 11, 1999, TE Products filed an application with the FERC requesting permission to charge Market-Based Rates for substantially all refined products transportation tariffs. On July 31, 2000, the FERC issued an order granting TE Products Market-Based Rates in certain markets and set for hearing TE Products’ application for Market-Based Rates in certain destination markets and origin markets. After the matter was set for hearing, TE Products and the protesting shippers entered into a settlement agreement resolving their respective differences. On April 25, 2001, the FERC issued an order approving the offer of settlement. As a result of the settlement, TE Products recognized approximately $1.7 million of previously deferred transportation revenue in the second quarter of 2001. As a part of the settlement, TE Products withdrew the application for Market-Based Rates to the Little Rock, Arkansas, and Arcadia and Shreveport-Arcadia, Louisiana, destination markets, which are currently subject to the PPI Index. As a result, we made refunds of approximately $1.0 million in the third quarter of 2001 for those destination markets.

Recent Accounting Pronouncements

See discussion of new accounting pronouncements in Note 2. Summary of Significant Accounting Policies – New Accounting Pronouncements in the accompanying consolidated financial statements.

Disclosures About Effects of Transactions with Related Parties

The Partnership does not have any employees, and we are managed by the General Partner, a wholly owned subsidiary of DEFS. Duke Energy holds an interest of approximately 70% in DEFS, and ConocoPhillips holds the remaining 30%. See Item 10. Directors and Executive Officers of the Registrant and Item 13. Certain Relationships and Related Transactions for discussion regarding transactions between us and DEFS, Duke Energy and ConocoPhillips.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

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

At December 31, 2003, we had $210.0 million outstanding under our variable interest rate revolving credit agreement. The interest rate is based, at our option, on either the lender’s base rate plus a spread or LIBOR plus a spread in effect at the time of the borrowings and is adjusted monthly, bimonthly, quarterly or semiannually. Utilizing the balances of our variable interest rate debt outstanding at December 31, 2003, including the effects of hedging activities discussed below, and assuming market interest rates increase 100 basis points, the potential annual increase in interest expense would be less than $0.1 million.

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

At December 31, 2003, TE Products had outstanding $180.0 million principal amount of 6.45% Senior Notes due 2008, and $210.0 million principal amount of 7.51% Senior Notes due 2028 (collectively the “TE Products Senior Notes”). At December 31, 2003, the estimated fair value of the TE Products Senior Notes was approximately $432.8 million. At December 31, 2003, we had outstanding $500.0 million principal amount of 7.625% Senior Notes due 2012 and $200.0 million principal amount of 6.125% Senior Notes due 2013. At December 31, 2003, the estimated fair value of the $500.0 million 7.625% Senior Notes and the $200.0 million 6.125% Senior Notes was approximately $578.2 million and $206.7 million, respectively.

As of December 31, 2003, TE Products had an interest rate swap agreement in place to hedge its exposure to changes in the fair value of its fixed rate 7.51% TE Products Senior Notes due 2028. We designated this swap agreement as a fair value hedge. The swap agreement has a notional amount of $210.0 million and matures in January 2028 to match the principal and maturity of the TE Products Senior Notes. Under the swap agreement, TE Products pays a floating rate of interest based on a three-month U.S. Dollar LIBOR rate, plus a spread, and receives a fixed rate of interest of 7.51%. During the years ended December 31, 2003, and 2002, we recognized reductions in interest expense of $10.0 million and $8.6 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap. During the year ended December 31, 2003, we measured the hedge effectiveness of this interest rate swap and noted that no gain or loss from ineffectiveness was required to be recognized. The fair value of this interest rate swap agreement was a gain of approximately $2.3 million and $13.6 million at December 31, 2003, and 2002, respectively. Utilizing the balance of the 7.51% TE Products Senior Notes outstanding at December 31, 2003, and including the effects of hedging activities, assuming market interest rates increase 100 basis points, the potential annual increase in interest expense is $2.1 million.

We have entered into an interest rate swap agreement to hedge our exposure to increases in the benchmark interest rate underlying our variable rate revolving credit facility. This interest rate swap matures on April 6, 2004. We designated this swap agreement, which hedges exposure to variability in expected future cash flows attributed to changes in interest rates, as a cash flow hedge. The swap agreement is based on a notional amount of $250.0 million. Under the swap agreement, we pay a fixed rate of interest of 6.955% and receive a floating rate based on a three-month U.S. Dollar LIBOR rate. Since this swap is designated as a cash flow hedge, the changes in fair value, to the extent the swap is effective, are recognized in other comprehensive income until the hedged interest costs are recognized in earnings. On June 27, 2003, we repaid the amounts outstanding under the revolving credit facility with borrowings under a new three year revolving credit facility and canceled the old facility (see Note 11. Debt). We redesignated this interest rate swap as a hedge of our exposure to increases in the benchmark interest rate underlying the new variable rate revolving credit facility. During the years ended December 31, 2003, and 2002, we

recognized increases in interest expense of $14.4 million and $12.9 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap.

During the year ended December 31, 2003, we determined that we would repay a portion of the amount outstanding under the revolving credit facility, established June 27, 2003, with proceeds from our Unit offering in August 2003 (see Note 12. Partners’ Capital and Distributions) resulting in a reduction of probable future interest payments under the credit facility. As a result, we measured and reclassified amounts previously accumulated in other comprehensive income related to the discontinued portion of the hedge and recognized a loss of $1.0 million, which has been included in interest expense. The total fair value of the interest rate swap was a loss of approximately $3.9 million and $20.1 million at December 31, 2003, and 2002, respectively. Losses recognized in other comprehensive income of approximately $2.9 million related to the portion of the interest rate swap hedging probable future interest payments will be transferred into earnings over the remaining term of the interest rate swap. Changes in the fair value of the portion of the interest rate swap related to the discontinued hedge will be recorded in earnings over the remaining term of the interest rate swap.

On February 20, 2002, we entered into interest rate swap agreements, designated as fair value hedges, to hedge our exposure to changes in the fair value of our fixed rate 7.625% Senior Notes due 2012. The swap agreements had a combined notional amount of $500.0 million and matured in 2012 to match the principal and maturity of the Senior Notes. Under the swap agreements, we paid a floating rate of interest based on a U.S. Dollar LIBOR rate, plus a spread, and received a fixed rate of interest of 7.625%. On July 16, 2002, the swap agreements were terminated resulting in a gain of approximately $18.0 million. Concurrent with the swap terminations, we entered into new interest rate swap agreements, with identical terms as the previous swap agreements; however, the floating rate of interest was based upon a spread of an additional 50 basis points. In December 2002, the swap agreements entered into on July 16, 2002, were terminated, resulting in a gain of approximately $26.9 million. The gains realized from the July 2002 and December 2002 swap terminations have been deferred as adjustments to the carrying value of the Senior Notes and are being amortized using the effective interest method as reductions to future interest expense over the remaining term of the Senior Notes. At December 31, 2003, the unamortized balance of the deferred gains was $40.6 million. In the event of early extinguishment of the Senior Notes, any remaining unamortized gains would be recognized in the consolidated statement of income at the time of extinguishment.

Item 8. Financial Statements and Supplementary Data

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

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

None.

Item 9A. Controls and Procedures

The principal executive officer and principal financial officer of our General Partner, after evaluating the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of December 31, 2003, have concluded that, as of such date, our disclosure controls and procedures are adequate and effective to ensure that material information relating to us and our consolidated subsidiaries would be made known to them by others within those entities.

During the fourth quarter of 2003, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, those internal controls subsequent to the date of the evaluation. As a result, no corrective actions were required or undertaken.

PART III

Item 10. Directors and Executive Officers of the Registrant

Partnership Management

We do not directly have directors or officers, as is commonly the case with publicly traded partnerships. Our operations and activities are managed by the General Partner, which employs our management and operational personnel. The officers and directors of the General Partner are responsible for managing us. All directors of the General Partner are elected annually by DEFS. All officers serve at the discretion of the directors. None of the officers of the General Partner serve as officers or employees of DEFS or any other parent-affiliated company.

Because we are a limited partnership, the listing standards of the New York Stock Exchange do not require that we or our General Partner have a majority of independent directors or a nominating or compensation committee of the General Partner’s board of directors.

Committees of the Board of Directors

Audit Committee

Our General Partner has an audit committee (the “Audit Committee”) comprised of three board members who are “independent” as that term is defined in Rule 10A-3 of the Exchange Act and as that term is used in applicable listing standards of the New York Stock Exchange. The members of the Audit Committee are R. A. Walker (Chairman), John P. DesBarres and Milton Carroll. The members of the Audit Committee are non-employee directors of the General Partner and are not officers, directors or otherwise affiliated with DEFS or its parent companies, ConocoPhillips or Duke Energy. No member of the Audit Committee of our General Partner serves on the audit committees of more than three public companies. Our Board of Directors has also determined that no Audit Committee member has a material relationship with the Company. Our Board of Directors has also determined that Mr. Walker qualifies as an audit committee financial expert as defined in Item 401(h) of Regulation S-K.

The Audit Committee provides independent oversight with respect to our internal controls, accounting policies, financial reporting, internal audit function and the independent auditors. The Audit Committee also reviews the scope and quality, including the independence and objectivity of the independent and internal auditors. The Audit Committee has sole authority as to the retention, evaluation, compensation and oversight of the work of the independent auditors. The independent auditors report directly to the Audit Committee. The Audit Committee also has sole authority to approve all audit and non-audit services provided by the independent auditors and shall assure that the independent auditors are not engaged to perform specific non-audit services prohibited by law or regulation. The charter of the Audit Committee is filed as an exhibit to this Annual Report on Form 10-K and is available on our website at www.teppco.com.

Our Audit Committee has established procedures for the receipt, retention and treatment of complaints we receive regarding accounting, internal accounting controls or auditing matters and the confidential, anonymous submission by our employees of concerns regarding questionable accounting or auditing matters. Persons wishing to communicate with our Audit Committee may do so by calling 1-800-799-4607.

Special Committee

The Special Committee is a standing committee of the Board of Directors of the General Partner and is composed of three independent directors, John P. DesBarres (Chairman), Milton Carroll and R. A. Walker. The members of the Special Committee are non-employee directors of the General Partner and are not officers, directors or otherwise affiliated with DEFS or its parent companies, ConocoPhillips or Duke Energy. The Special Committee is responsible for the independent evaluation of the fairness and reasonableness of affiliate transactions and the approval or rejection of those transactions that would ordinarily require board approval involving the General

Partner, DEFS or an affiliate of either, and us. Such transactions include related party asset sales and operating agreements. The Special Committee is also responsible for the evaluation of the fairness and approval or rejection of the issuance and pricing of additional Units and debt.

Compensation Committee

The Compensation Committee is a standing committee of the Board of Directors of the General Partner and is composed of five directors, Jim W. Mogg (Chairman), Milton Carroll, Derrill Cody, John P. DesBarres and R. A. Walker. The Compensation Committee establishes and maintains competitive and equitable compensation and employment policies to retain the management required to carry out our business, to stimulate their useful and profitable efforts on our behalf and to attract necessary additions to management with appropriate qualifications. The Compensation Committee also recommends to the Board of Directors the election of officers and reviews the management succession plans for senior officer positions.

Code of Ethics, Corporate Governance Guidelines and Charter of the Audit Committee

We have adopted a Code of Ethics applicable to all employees, including the principal executive officer, principal financial officer and directors of the General Partner. A copy of the Code of Ethics is available on our website at www.teppco.com under Corporate Governance. We intend to post on our website any amendments to, or waivers from, our Code of Ethics applicable to our senior officers.

Corporate governance guidelines are currently under consideration by our Board of Directors, and will address director qualification standards; director access to management, and as necessary and appropriate, independent advisors; director compensation; director orientation and continuing education; management succession and annual performance evaluation of the board. The Charter of our Audit Committee is currently available on our website at www.teppco.com under Corporate Governance. Our Corporate Governance Guidelines will be available on our website when adopted, and will be in place before the date required by the listing standards of the New York Stock Exchange. Additionally, the Code of Ethics and the Charter of the Audit Committee are available in print to any person who requests the information. Persons wishing to obtain this printed material should submit a request in care of Secretary, TEPPCO Partners, L.P., 2929 Allen Parkway, P.O. Box 2521, Houston, Texas 77252-2521.

Executive Sessions of Non-Management Directors

Mark A. Borer, Michael J. Bradley, Milton Carroll, Derrill Cody, John P. DesBarres, Jim W. Mogg, William H. Easter III and R. A. Walker, who are non-management directors of our General Partner, meet at regularly scheduled executive sessions without management. Mr. Mogg serves as the presiding director at those executive sessions. Persons wishing to communicate with the Company’s non-management directors may do so by calling 1-800-799-4607.

Milton Carroll, John P. DesBarres and R. A. Walker, who are independent non-management directors of our General Partner, meet at regularly scheduled executive sessions without management and the other directors. The chairs of the Audit Committee and the Special Committee of the Board of Directors rotate on an annual basis as the chair of the independent non-management directors. The chair for 2004 is John P. DesBarres. Persons wishing to communicate with the Company’s independent non-management directors may do so by calling 1-800-799-4607.

Directors and Executive Officers

The following table sets forth certain information with respect to the directors and executive officers of the General Partner.


Name	Age		Position with Our General Partner

Jim W. Mogg		55	Chairman of the Board, Member of the Compensation* Committee and Director
Mark A. Borer		49	Director
Michael J. Bradley		49	Director
Milton Carroll		53	Director and Member of the Compensation, Special and Audit Committees
Derrill Cody		65	Director and Member of the Compensation Committee
John P. DesBarres		64	Director and Member of the Compensation, Special* and Audit Committees
William H. Easter III		54	Director
R. A. Walker		46	Director and Member of the Compensation, Special and Audit* Committees
Barry R. Pearl+		54	President, Chief Executive Officer and Director
Charles H. Leonard+		55	Senior Vice President and Chief Financial Officer
James C. Ruth+		56	Senior Vice President, General Counsel and Secretary
Thomas R. Harper+		63	Senior Vice President of Commercial Downstream
J. Michael Cockrell+		57	Senior Vice President of Commercial Upstream
Leonard W. Mallett+		47	Vice President of Operations
Stephen W. Russell+		52	Vice President of Support Services
David E. Owen+		54	Vice President of Human Resources
John N. Goodpasture+		55	Vice President of Corporate Development
Barbara A. Carroll+		49	Vice President of Environmental, Health and Safety

*		Indicates Chairman of committee

+		Indicates employment contract with the General Partner (see Executive Employment Contracts and Termination of Employment Arrangements)

Jim W. Mogg was elected a director of the General Partner in October 1997, Chairman of the Compensation Committee in April 2000 and Chairman of the Board in May 2002. Mr. Mogg succeeded William L. Thacker as Chairman of the Board in May 2002, when Mr. Thacker retired as Chairman. Prior to being elected Chairman of the Board in 2002, Mr. Mogg served as Vice Chairman of the Board from April 2000 to April 2002. Mr. Mogg was named group vice president and chief development officer of Duke Energy, effective January 1, 2004. He served as chairman, president and chief executive officer of DEFS from December 1999 to December 2003. Mr. Mogg was previously president of Centana Energy Corporation, a subsidiary of a predecessor of Duke Energy, from 1992 to 1999. He joined Duke Energy in 1973 in the gas supply department of Panhandle Eastern Pipe Line Company.

Mark A. Borer was elected a director of the General Partner in April 2000. Mr. Borer is executive vice president of marketing and corporate development of DEFS, having been elected in April 2002. He previously served as senior vice president, Southern Division, having been elected to that position in 1999 when Union Pacific Fuels, Inc. was acquired by DEFS. Before joining DEFS, he was vice president of natural gas marketing for Union Pacific Fuels, Inc. from 1992 until 1999.

Michael J. Bradley was elected a director of the General Partner in February 2003. Mr. Bradley is executive vice president, gathering and processing of DEFS, having been elected to that position in April 2002. He previously served as senior vice president, Northern Division, for DEFS, having been elected to that position in 1999. Mr. Bradley joined DEFS in 1979 and served in a variety of positions in marketing, business development and operations.

Milton Carroll was elected a director of the General Partner in November 1997 and is a member of the Compensation Committee, Special Committee and the Audit Committee. He served as Chairman of the Audit Committee from April 2000 until January 16, 2003. Mr. Carroll is the chairman of CenterPoint Energy, Inc., having

been elected in September 2002. Mr. Carroll is the founder and chairman of Instrument Products, Inc., a manufacturer of oil field equipment since 1977. Mr. Carroll is a director of Devon Energy Corporation, Eagle Global Logistics and Chairman of the Board of Health Care Service Corporation.

Derrill Cody was elected a director of the General Partner in 1989. He is a member of the Compensation Committee and was Chairman of the Audit Committee from April 1990 until April 2000. Mr. Cody is currently of counsel to McKinney and Stringer, P. C., which represents Duke Energy, DEFS and us in certain matters. He is also an advisor to DEFS pursuant to a personal contract. Mr. Cody served as chief executive officer of Texas Eastern Gas Pipeline Company from 1987 to 1990. Prior to that, he was executive vice president of Kerr McGee Corporation. Mr. Cody is a director of CenterPoint Energy, Inc.

John P. DesBarres was elected a director of the General Partner in May 1995. He is a member of the Compensation and Audit Committees and serves as Chairman of the Special Committee. Mr. DesBarres was formerly chairman, president and chief executive officer of Transco Energy Company from 1992 to 1995. He joined Transco in 1991 as president and chief executive officer. Prior to joining Transco, Mr. DesBarres served as chairman, president and chief executive officer for Santa Fe Pacific Pipelines, Inc. from 1988 to 1991. Mr. DesBarres is a director of American Electric Power and Penn Virginia G.P., LLC, an indirect wholly owned subsidiary of Penn Virginia Corporation, which is the general partner of Penn Virginia Resource Partners, L.P.

William H. Easter III was elected a director of the General Partner in February 2004. Mr. Easter is chairman, president and chief executive officer of DEFS, having been elected to that position in January 2004. He was previously vice president of state government affairs for ConocoPhillips from 2002 until December 2003. Mr. Easter joined ConocoPhillips (formerly Conoco Inc.) in 1971 and served in a variety of positions, most recently as general manager of Gulf Coast businesses unit in Lake Charles, Louisiana, from 1998 until 2002.

R. A. Walker was elected director of the General Partner in July 2002, and is a member of the Compensation, Audit and Special Committees. He was elected Chairman of the Audit Committee on January 16, 2003. Mr. Walker was president, chief financial officer and director of 3TEC Energy Corporation, a publicly held independent oil and gas company from 2000 to 2003. 3TEC Energy was acquired by Plains Exploration and Production Company in 2003. Prior to joining 3TEC Energy Corporation in 2000, Mr. Walker was senior managing director and co-head of Prudential Capital Group, an asset management firm of The Prudential Insurance Company of America from 1997 to 2000. Previously, he was managing director of Prudential Capital’s Dallas office from 1990 to 1997, where he was responsible for its worldwide energy investing.

Barry R. Pearl was elected President of the General Partner in February 2001 and Chief Executive Officer and director in May 2002. He succeeded William L. Thacker as Chief Executive Officer in May 2002, when Mr. Thacker retired as Chief Executive Officer. Mr. Pearl was previously Chief Operating Officer from February 2001 until May 2002. Prior to joining the Company, Mr. Pearl was vice president – finance and administration, treasurer, secretary and chief financial officer of Maverick Tube Corporation from June 1998. Mr. Pearl was senior vice president and chief financial officer of Santa Fe Pacific Pipeline Partners, L.P. from 1995 until 1998, and senior vice president, business development from 1992 to 1995.

Charles H. Leonard is Senior Vice President and Chief Financial Officer of the General Partner. Mr. Leonard joined the Company in 1988 as Vice President and Controller. In November 1989, he was elected Vice President and Chief Financial Officer. He was elected Senior Vice President in March 1990, and was Treasurer from October 1996 until May 2002.

James C. Ruth is Senior Vice President, General Counsel and Secretary of the General Partner, having been elected in February 2001. Mr. Ruth was previously Vice President and General Counsel and Secretary from 1998 until February 2001, and Vice President, General Counsel from 1991 until 1998. Mr. Ruth joined the Company in 1970.

Thomas R. Harper is Senior Vice President, Commercial Downstream of the General Partner, having been elected in February 2003. Mr. Harper was previously Vice President, Commercial Downstream from September 2000 until February 2003 and Vice President, Product Transportation and Refined Products Marketing from 1988 until September 2000. Mr. Harper joined the Company in 1987 as Director of Product Transportation.

J. Michael Cockrell is Senior Vice President, Commercial Upstream of the General Partner, having been elected in February 2003. Mr. Cockrell was previously Vice President, Commercial Upstream from September 2000 until February 2003. He was elected Vice President of the General Partner in January 1999 and also serves as President of TEPPCO Crude GP, LLC. He joined PanEnergy in 1987 and served in a variety of positions in supply and development, including president of DETTCO.

Leonard W. Mallett is Vice President, Operations of the General Partner, having been elected in September 2000. Mr. Mallett was previously Region Manager of the Southwest Region of the Company from 1994 until 1999 and Director of Engineering, from 1992 until 1994. Mr. Mallett joined the Company in 1979 as an engineer.

Stephen W. Russell is Vice President, Support Services of the General Partner, having been elected in September 2000. Mr. Russell was previously Region Manager of the Southwest Region from July 1999 until September 2000, and Technical Operations Superintendent of the Southwest Region from 1994 until 1999. Mr. Russell joined the Company in 1988 as Project Manager in Engineering.

David E. Owen is Vice President, Human Resources of the General Partner, having joined the Company in February 2001. He was previously Northern Division human resources manager of DEFS from May 2000 until he joined the Company. Prior to DEFS, Mr. Owen held various positions with ARCO International Oil and Gas Company from October 1996 until January 2000.

John N. Goodpasture is Vice President, Corporate Development of the General Partner, having joined the Company in November 2001. Mr. Goodpasture was previously Vice President of Business Development for Enron Transportation Services from June 1999 until he joined the Company. Prior to his employment at Enron Transportation Services, Mr. Goodpasture spent 19 years in various executive positions at Seagull Energy Corporation (now Devon Energy Corporation), a large independent oil and gas company. At Seagull Energy, Mr. Goodpasture had most recently served for over ten years as Senior Vice President, Pipelines and Marketing.

Barbara A. Carroll is Vice President, Environmental, Health and Safety, having been elected in February 2002. Ms. Carroll joined ExxonMobil in 1990 and served in a variety of management positions, including Procurement Services Manager, Materials and Service Manager and Baytown Area Public Affairs Manager until she joined the Company in February 2002. Prior to ExxonMobil, Ms. Carroll was General Manager, Corporate Environmental Protection and Compliance with Panhandle Eastern Corporation. Ms. Carroll is not related to Milton Carroll.

In addition to our Executive Officers, Mark G. Stockard serves as Treasurer, having been elected in May 2002. Mr. Stockard was Assistant Treasurer of the General Partner from July 2001 until May 2002. He was previously Controller from October 1996 until May 2002. Mr. Stockard joined the Company in October 1990.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires directors, officers and persons who beneficially own more than ten percent of a registered class of our equity securities to file with the SEC and the New York Stock Exchange initial reports of ownership and reports of changes in ownership of such equity securities. Based on information furnished to the Company and written representation that no other reports were required, to the Company’s knowledge, all applicable Section 16(a) filing requirements were complied with during the year ended December 31, 2003, except for reports covering certain transactions that were filed late by Mr. Mallett.

Item 11. Executive Compensation

Summary Compensation Table

The officers of the General Partner manage and operate our business. We do not directly employ any of the persons responsible for managing or operating our operations, but instead reimburse the General Partner for the

services of these persons (See Note 8. Related Party Transactions). The following table reflects cash compensation paid or accrued by the General Partner for the years ended December 31, 2003, 2002 and 2001, with respect to its Chief Executive Officer and the four other most highly compensated executive officers in 2003 (collectively, the “Named Executive Officers”).

SUMMARY COMPENSATION TABLE


			Annual Compensation						Other		Long Term
									Annual		Compensation		All Other
Name and							Bonus		Compensation		Payouts		Compensation
Principal Position			Year		Salary ($)		($) (2)		($) (3)		($)(4)		($) (5)

Barry R. Pearl (1)				2003		283,500		196,465		52,000		—		26,683
	President and Chief			2002		252,308		142,000		24,160		—		16,163
	Executive Officer			2001		190,385		131,900		7,800		—		78,423
J. Michael Cockrell				2003		202,846		114,364		7,250		108,225		18,716
		Senior Vice President,		2002		195,462		86,600		21,750		358,200		13,369
		Commercial Upstream		2001		189,504		100,500		32,250		—		10,722
Charles H. Leonard				2003		195,654		108,800		20,250		271,523		16,112
		Senior Vice President and		2002		182,342		88,200		18,095		32,062		11,241
		Chief Financial Officer		2001		170,404		106,700		11,395		46,581		8,347
James C. Ruth				2003		195,654		108,333		20,250		456,084		13,439
		Senior Vice President and		2002		182,342		86,300		18,095		55,368		11,346
		General Counsel		2001		169,942		103,300		11,395		23,411		6,156
John N. Goodpasture				2003		189,846		104,263		13,250		—		17,996
		Vice President,		2002		182,885		91,000		5,875		—		7,226
		Corporate Development		2001		27,692		—		—		—		—

(1)		Mr. Pearl was elected as President in February 2001, and Chief Executive Officer and director effective May 1, 2002.

(2)		Amounts represent bonuses accrued during the year under the Management Incentive Compensation Plan (“MICP”). Payments under the MICP are made in the subsequent year. Annual compensation does not include awards under long-term incentive plans, which are described in the 2000 LTIP awards table under “-Compensation Pursuant to General Partner Plans”.

(3)		Amounts represent quarterly distribution equivalents under the terms of the Company’s 2000 Long Term Incentive Plan (“2000 LTIP”) and Retention Incentive Compensation Plan (“RICP”).

(4)		Amounts represent credits earned to Performance Unit accounts and options exercised under the terms of 1994 LTIP, payouts under the RICP and payouts under the 2000 LTIP.

(5)		Includes (i) Company matching contributions under funded, qualified, defined contribution retirement plans; (ii) Company matching contribution credits under unfunded, non qualified plans; and (iii) the imputed value of premiums paid by the Company for insurance on the Named Executive Officers’ lives. Amount for Mr. Pearl in 2001 also includes $74,302 of relocation expenses.

Executive Employment Contracts and Termination of Employment Arrangements

On February 12, 2001, Barry R. Pearl and the Company entered into an employment agreement, which set a minimum base salary of $220,000 per year. The Company may terminate the employment agreement for cause, death or disability. In addition, the Company or Mr. Pearl may terminate the agreement upon written notice. Mr. Pearl participates in other Company sponsored benefit plans on the same basis as other senior executives of the Company. In the event Mr. Pearl is terminated due to death or disability or by the Company for cause, Mr. Pearl is entitled only to base salary earned through the date of termination. In the event of termination for any other reason, Mr. Pearl is entitled to base salary earned through the date of termination plus a lump sum severance payment equal to two times his base annual salary and two times the current target bonus approved under the MICP by the Compensation Committee. In the event Mr. Pearl is involuntarily terminated following a change in control, he is entitled to a lump sum severance payment equal to two times his base annual salary plus two times his current target bonus.

The Company has entered into employment agreements with its executive officers identified in Item 10. Directors and Executive Officers of the Registrant. The agreements may be terminated for death, disability or by the Company with or without cause. In the event one of the named executives’ employment is terminated due to death or disability or by the Company for cause, the executive is entitled only to base salary earned through the date of termination. In the event of termination for any other reason, the executive is entitled to base salary earned through the date of termination plus a lump sum severance payment equal to two times such executive’s base annual salary and two times the current target bonus approved under the MICP by the Compensation Committee. In the event that an executive is involuntarily terminated following a change in control, the executive is entitled to a lump sum severance payment equal to two times his base annual salary plus two times his current target bonus.

Compensation Committee Interlocks and Insider Participation

During 2003, Jim W. Mogg, a director of the General Partner and chairman, president and chief executive officer of DEFS, was chairman of the Compensation Committee of the General Partner and participated in deliberations concerning the General Partner’s executive officer compensation. The other four members of the Compensation Committee of the General Partner, Milton Carroll, R. A. Walker, Derrill Cody and John P. DesBarres, are non-employee directors of the General Partner and are not officers or directors of DEFS or its parent companies, ConocoPhillips or Duke Energy.

Compensation Pursuant to General Partner Plans

Management Incentive Compensation Plan

The General Partner has established the MICP, which provides for the payment of additional cash compensation to participants if certain Partnership performance objectives and personal objectives are met each year. The Compensation Committee of the Board of Directors of the General Partner determines at the beginning of each year which employees are eligible to become participants in the MICP. Additional participants may be added to the plan during the year by the Chief Executive Officer. Each participant is assigned a target award, determined as a percentage of total annual eligible earnings for the plan year less any incentive compensation payments during the plan year, by the Compensation Committee. Such target award determines the additional compensation to be paid if certain performance objectives and personal objectives are met. The amount of the target awards may range from 10% to 55% of a participant’s base salary. Maximum payout under the MICP is 144% of a participant’s target award. Awards are paid as soon as practicable following approval by the Compensation Committee after the close of a year.

1994 Long Term Incentive Plan

The 1994 LTIP authorized incentive awards to key employees whereby a participant was granted an option to purchase Units together with a stipulated number of Performance Units, which provided for cash credits to participants’ accounts when annual earnings exceeded specified levels. No awards have been made under the 1994 LTIP since 1999, and none are expected to be made in the future.

The following table provides information concerning the Unit options exercised under the 1994 LTIP by each of the Named Executive Officers during 2003. There were no unexercised outstanding Unit options under the 1994 LTIP to the Named Executive Officers as of December 31, 2003.

AGGREGATED OPTIONS EXERCISES IN YEAR ENDED DECEMBER 31, 2003

Value of

Unexercised

Shares

Number of Securities

In-the-Money

Acquired on

Value

Underlying Unexercised

Options

Name

Exercise

Realized

Options at FY-end (1)

at FY-end (1)

Mr. Leonard

17,328

196,123

—

Mr. Ruth

32,547

356,109

—

(1)

All remaining outstanding options were exercised during the year ended December 31, 2003.

2000 Long Term Incentive Plan

Effective January 1, 2000, the General Partner established the Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan (“2000 LTIP”) to provide key employees incentives to achieve improvements in our financial performance. Generally, upon the close of a three-year performance period, if the participant is then still an employee of the General Partner, the participant will receive a cash payment in an amount equal to (1) the applicable performance percentage specified in the award multiplied by (2) the number of phantom Units granted under the award multiplied by (3) the average of the closing prices of a Unit over the ten consecutive trading days immediately preceding the last day of the performance period. Generally, a participant’s performance percentage is based upon the improvement of our Economic Value Added (as defined below) during a three-year performance period over the Economic Value Added during the three-year period immediately preceding the performance period. If a participant incurs a separation from service during the performance period due to death, disability or retirement (as such terms are defined in the 2000 LTIP), the participant will be entitled to receive a cash payment in an amount equal to the amount computed as described above multiplied by a fraction, the numerator of which is the number of days that have elapsed during the performance period prior to the participant’s separation from service and the denominator of which is the number of days in the performance period.

The performance period applicable to awards granted in 2003 is the three-year period that commenced on January 1, 2003, and ends on December 31, 2005. Each participant’s performance percentage is the result of [(A) minus (B)] divided by [(C) minus (B)] where (A) is the actual Economic Value Added for the performance period, (B) is $60.1 million (which represents the actual Economic Value Added for the three-year period immediately preceding the performance period) and (C) is $82.0 million (which represents the Target Economic Value Added during the three-year performance period). No amounts will be payable under the awards granted in 2003 for the 2000 LTIP unless Economic Value Added for the three year performance period exceeds $60.1 million. The performance percentage may not exceed 150%.

Economic Value Added means our average annual EBITDA for the performance period minus the product of our average asset base and our cost of capital for the performance period. For purposes of the 2000 LTIP for plan years 2000 through 2002, EBITDA means our earnings before net interest expense, depreciation and amortization and our proportional interest in EBITDA of our joint ventures as presented in our consolidated financial statements prepared in accordance with generally accepted accounting principles, except that in its discretion the Compensation Committee of the General Partner may exclude gains or losses from extraordinary, unusual or non-recurring items. For the year ended December 31, 2003, EBITDA means, in addition to the above, earnings before other income – net. Average asset base means the quarterly average, during the performance period, of our gross value of property, plant and equipment, plus products and crude oil operating oil supply and the gross value of intangibles and equity investments. Our cost of capital is approved by the Compensation Committee at the date of award grant.

The following table provides information concerning awards under the 2000 LTIP to each of the Named Executive Officers during 2003.


	Number			Estimated Future Payouts (1)
	of
	Phantom		Performance	Threshold		Target		Maximum
Name	Units		Period	(#) (2)		(#) (3)		(#) (4)

Mr. Pearl		9,100	3 years		—		13,650		13,650
Mr. Leonard		2,900	3 years		—		4,350		4,350
Mr. Ruth		2,900	3 years		—		4,350		4,350
Mr. Goodpasture		2,800	3 years		—		4,200		4,200

(1)		Phantom units will be settled in cash based upon the then market price of the Units at the end of the performance period as described above.

(2)		No amounts will be payable for awards granted in 2003 unless Economic Value Added for the three year performance period exceeds $60.1 million.

(3)		In number of phantom units. Pursuant to Instruction 5 to Regulation 402(e) of the Securities and Exchange Commission, these amounts assume that the 37% increase in Economic Value Added for 2003 as compared with 2002 is maintained for each of the three years in the performance period. There can be no assurance that any specific amount of Economic Value Added will be attained for such period.

(4)		The maximum potential payout under the 2000 LTIP is 150% of phantom units awarded.

Pension Plan

Prior to the transfer of the General Partner interest from Duke Energy to DEFS on April 1, 2000, the Company’s employees participated in the Duke Energy Retirement Cash Balance Plan, which is a noncontributory, trustee-administered pension plan. Effective January 1, 1999, the benefit formula for all eligible employees was a cash balance formula. Under a cash balance formula, a plan participant accumulated a retirement benefit based upon pay credits and current interest credits. The pay credits were based on a participant’s salary, age, and service. In addition, the Named Executive Officers participated in the Duke Energy Executive Cash Balance Plan, which is a noncontributory, nonqualified, defined benefit retirement plan. The Duke Energy Executive Cash Balance Plan was established to restore benefit reductions caused by the maximum benefit limitations that apply to qualified plans.

Benefits under the Duke Energy Retirement Cash Balance Plan and the Duke Energy Executive Cash Balance Plan were based on eligible pay, generally consisting of base pay, short term incentive pay, and lump-sum merit increases. The Duke Energy Retirement Cash Balance Plan excludes deferred compensation, other than deferrals pursuant to Sections 401(k) and 125 of the Internal Revenue Code. As part of the change in ownership on March 31, 2000, the Company is no longer responsible for the funding of the liabilities associated with the Duke Energy Retirement Cash Balance Plan or the Duke Energy Executive Cash Balance Plan.

Effective April 1, 2000, the Company adopted the TEPPCO Retirement Cash Balance Plan (“TEPPCO RCBP”) and the TEPPCO Supplemental Benefit Plan (“TEPPCO SBP”). The benefits and provisions of these plans are substantially identical to the Duke Energy Retirement Cash Balance Plan and the Duke Energy Executive Cash Balance Plan previously in effect prior to April 1, 2000.

Under the cash balance benefit accrual formula that applies in determining benefits under the TEPPCO RCBP, an eligible employee’s plan account receives a pay credit at the end of each month in which the employee remains eligible and receives eligible pay for services. The monthly pay credit is equal to a percentage of the

employee’s monthly eligible pay. The percentage depends on age added to completed years of services at the beginning of the year, as shown below:


	Monthly Pay
	Credit
Age plus Service	Percentage

34 or less		4	%
35 to 49		5	%
50 to 64		6	%
65 or more		7	%

The above monthly pay credit is increased by an additional 4% of any portion of eligible pay above the Social Security taxable wage base ($87,000 for 2003). Employee accounts also receive monthly interest credits on their balances. The rate of the interest credit is adjusted quarterly and is derived from the average annual yield on 30-year U.S. Treasury Bonds during the third week of the last month of the previous quarter, subject to a minimum rate of 4% per year and a maximum rate of 9% per year.

Assuming that the Named Executive Officers continue in their present positions at their present salaries until retirement at age 65, their estimated annual pensions in a single life annuity form under the applicable pension plan(s) (including the Duke Energy Retirement Cash Balance Plan, the Duke Energy Executive Cash Balance Plan, the TEPPCO RCBP and the TEPPCO SBP) attributable to such salaries would be as follows: Barry R. Pearl, $66,977; J. Michael Cockrell, $43,259; Charles H. Leonard, $98,261; James C. Ruth, $165,721; and John N. Goodpasture, $34,545. Such estimates were calculated assuming interest credits at a rate of 6% per annum and using a future Social Security taxable wage base equal to $87,900.

Compensation of Directors

Directors of the General Partner who are neither officers nor employees of either the Company or DEFS receive a stipend, effective January 1, 2004, of $35,000 per annum, $1,000 for attendance at each meeting of the Board of Directors, $1,000 for attendance at each meeting of a committee of the Board of Directors, except for attendance of the Audit Committee, for which the amount is $2,000 for each meeting, and reimbursement of expenses incurred in connection with attendance at a meeting of the Board of Directors or a committee of the Board of Directors. Each non-employee director who serves as chairman of a committee of the Board of Directors receives an additional stipend of $5,000 per annum, except for the chairman of the Audit Committee, who receives an additional stipend of $20,000 per annum. Effective September 1, 1999, non-employee directors may elect to defer payment of retainer and attendance fees until termination of service on the Board of Directors. Such deferral may be either 50% or 100% in either a fixed income investment account that is credited with annual interest (currently 7%) or an investment account based upon the market value of Units.

Effective April 1, 2002, each quarter that a non-employee director continues to serve on the Board of Directors, such director will be credited with an amount equal to the then current market value of 100 Units and distribution equivalents on previously awarded amounts. In general, such amounts will not become distributable until the non-employee director terminates service on the Board of Directors. When a non-employee director terminates service on the Board of Directors, payment will be distributed in cash to the director according to the distribution schedule chosen by such director.

Messrs. Mogg, Pearl, Borer, Bradley and Easter are not compensated for their services as directors, and it is not anticipated that any compensation for service as a director will be paid in the future to directors who are either officers or full-time employees of Duke Energy, DEFS, the General Partner or any of their affiliates.

Item 12. Security Ownership of Certain Beneficial Owners and Management

Equity Compensation Plan Information

The following table provides information about our Equity Compensation Plans.

Number of

securities to be

Number of

issued upon

Weighted

securities

exercise of

average price

remaining

outstanding

of outstanding

available for

Plan Category

options

future issuance

Equity compensation plans approved by Security holders

—

Equity compensation plans not approved by Security holders

—

Total

—

During the year ended December 31, 2003, all of the remaining outstanding Unit options under the 1994 LTIP were exercised (see Compensation Pursuant to General Partner Plans). We have no other compensation plans that would result in the issuance of equity.

Security Ownership of Certain Beneficial Owners

As of February 20, 2004, Duke Energy, through its ownership of the Company and other subsidiaries, owns 2,500,000 Units, representing 4.0% of the 63.0 million Units outstanding. The following table sets forth information of each person other than Duke Energy known to us to be the beneficial owner of more than 5% of our voting shares as of February 20, 2004:


		Amount and Nature
		of Beneficial			Percentage
Name and Address of Beneficial Owner		Ownership			Owned

Goldman, Sachs & Co.			3,714,182	(1)		5.9	%
	85 Broad St. New York, NY 10004

(1)

Goldman, Sachs & Co. reported shared voting and dispositive power in its most recent report on Schedule 13G/A filed February 12, 2004. Goldman, Sachs & Co. is registered investment adviser whose clients have the right to receive distributions from, and the proceeds from the sale of, such shares.

No other person is known by us to own more than 5% of our outstanding Units.

Security Ownership of Management

The following table sets forth certain information, as of February 20, 2004, concerning the beneficial ownership of Units by each director and Named Executive Officer of the General Partner and by all directors and officers of the General Partner as a group. This information is based on data furnished by the persons named. Based on information furnished to the General Partner by these persons, no director or officer of the General Partner owned beneficially, as of February 20, 2004, more than 1% of the 63.0 million Units outstanding at that date.


	Number of
Name	Units (1)

Mark A. Borer		1,000
Michael J. Bradley		1,150
J. Michael Cockrell		5,000
Derrill Cody		13,000
John P. DesBarres		20,000
Charles H. Leonard		1,124
Jim W. Mogg (2)		4,427
Barry R. Pearl		10,000
James C. Ruth		5,000
All directors and officers (consisting of 18 people, including those named above)		72,438

(1)		Unless otherwise indicated, the persons named above have sole voting and investment power over the Units reported. Includes Units that the named person has the right to acquire within 60 days.

(2)		Includes 2,227 Units owned by daughters.

Item 13. Certain Relationships and Related Transactions

Our Management

We have no employees and are managed by the Company, a wholly owned subsidiary of DEFS. Duke Energy holds an interest of approximately 70% in DEFS, and ConocoPhillips holds the remaining 30%. According to the Partnership Agreements, the Company is entitled to reimbursement of all direct and indirect expenses related to our business activities (see Note 1. Partnership Organization).

For the years ended December 31, 2003, 2002, and 2001, we incurred direct expenses of $74.5 million, $66.7 million and $65.2 million, respectively, which were charged to us by DEFS. Substantially all of these costs were related to payroll and payroll related expenses. For the years ended December 31, 2003, 2002, and 2001, expenses for administrative services and overhead allocated to us by Duke Energy and its affiliates were $1.1 million, $0.8 million and $0.6 million, respectively.

Transactions with DEFS

LSI 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.

Effective with the purchase of the fractionation facilities on March 31, 1998, TEPPCO Colorado and DEFS entered into a 20-year Fractionation Agreement, under which TEPPCO Colorado 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. TEPPCO Colorado and DEFS also entered into an Operation and Maintenance Agreement, whereby DEFS operates and maintains the fractionation facilities. 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.

The Dean Pipeline and the Wilcox Pipeline were included with the crude oil assets purchased from DEFS effective November 1, 1998. 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. The Wilcox Pipeline, which is located along the Texas Gulf Coast, transports NGLs for DEFS from two of its processing plants and 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.

The Panola Pipeline and San Jacinto Pipeline were purchased on December 31, 2000, from DEFS for $91.7 million. These pipelines originate at DEFS’ East Texas Plant Complex in Panola County, Texas. For the years ended December 31, 2003, 2002 and 2001, revenues recognized included $9.2 million, $12.0 million and $13.9 million, respectively, from an affiliate of DEFS for NGL transportation fees on the Panola and San Jacinto Pipelines.

Effective May 2001, we entered into an agreement with an affiliate of DEFS to commit sole utilization of our Providence terminal to an affiliate of DEFS. We operate the terminal and provide propane loading services to an affiliate of DEFS. The agreement 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.

On September 30, 2001, we completed the acquisition of Jonah (see Note 6. Acquisitions and Dispositions). The Jonah assets are managed and operated by employees of DEFS under a contractual agreement under which DEFS is reimbursed for its actual costs. During the years ended December 31, 2003, 2002 and 2001, we recognized $3.7 million, $3.3 million and $0.6 million, respectively, of expense related to the operation and management of the Jonah assets by DEFS.

On March 1, 2002, we completed the acquisition of the Chaparral NGL system (see Note 6. Acquisitions and Dispositions). The Chaparral assets are managed and operated by employees of DEFS under a contractual agreement under which DEFS is reimbursed for its actual costs. During the years ended December 31, 2003, and 2002, we recognized $2.1 million and $1.7 million, respectively, of expenses related to the operation and management of the Chaparral assets by DEFS. 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 Chaparral totaled $5.5 million and $4.5 million for the years ended December 31, 2003 and 2002, respectively.

On June 30, 2002, we completed the acquisition of Val Verde (see Note 6. Acquisitions and Dispositions). The Val Verde assets are managed and operated by employees of DEFS under a contractual agreement under which DEFS is reimbursed for its actual costs. During the years ended December 31, 2003, and 2002, we recognized $3.0 million and $1.2 million, respectively, of expenses related to the operation and management of the Val Verde assets by DEFS.

At December 31, 2003 and 2002, we had a receivable from DEFS of $1.8 million and $6.9 million, respectively, related to sales and transportation services provided to DEFS. Included in the receivable balance at December 31, 2002, was an amount related to environmental remediation activities. At December 31, 2003 and 2002, we had a payable to DEFS of $9.7 million and $6.7 million, respectively, related to direct payroll, payroll related costs and management fees for Jonah, Chaparral, and Val Verde as described above. Included in this payable balance to DEFS at December 31, 2003 and 2002, is an imbalance payable to DEFS by TEPPCO Midstream of $1.5 million and $0.9 million, respectively.

On April 2, 2003, we sold in an underwritten public offering 3.9 million Units at $30.35 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $114.5 million, of which approximately $113.8 million was used to repurchase and retire all of the 3.9 million previously outstanding Class B Units held by DETTCO (see Note 12. Partners’ Capital and Distributions).

We contract with Bison Insurance Company Limited (“Bison”), a wholly owned subsidiary of Duke Energy, for a majority of our insurance coverage, including property, liability, auto and directors and officers insurance coverage. For the years ended December 31, 2003 and 2002, we paid insurance premiums to Bison of $6.4 million and $4.5 million, respectively. At December 31, 2003 and 2002, we had insurance reimbursement receivables due from Bison of $1.9 million and $1.3 million, respectively.

At December 31, 2003, we had a loan of propane outstanding to DEFS with a total value of $1.4 million. We will earn a nominal rental fee of $0.1 million on this transaction. This propane will be returned to us in February 2004. We regularly loan inventory for a fee to third parties and affiliates as part of our inventory management practice.

Interest of the General Partner in the Partnership

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. According to the Partnership Agreement, the Company receives incremental incentive cash distributions when cash distributions exceed certain target thresholds as follows:


					General
		Unitholders			Partner

Quarterly Cash Distribution per Unit:
	Up to Minimum Quarterly Distribution ($0.275 per Unit)		98	%		2	%
	First Target - $0.276 per Unit up to $0.325 per Unit		85	%		15	%
	Second Target - $0.326 per Unit up to $0.45 per Unit		75	%		25	%
	Over Second Target - Cash distributions greater than $0.45 per Unit		50	%		50	%

During the year ended December 31, 2003, distributions paid to the General Partner totaled $54.7 million, including incentive distributions of $51.7 million.

Interests of Duke Energy in the Partnership

In connection with our formation, the Company received 2,500,000 Deferred Participation Interests (“DPIs”). Effective April 1, 1994, the DPIs began participating in distributions of cash and allocations of profit and loss in a manner identical to Units and are treated as Units for purposes of this Report. These Units were assigned to Duke Energy when ownership of the Company was transferred from Duke Energy to DEFS in 2000. Pursuant to our Partnership Agreement, we have registered the resale by Duke Energy of these Units with the Securities and Exchange Commission. As of December 31, 2003, none of these Units had been sold by Duke Energy.

Item 14. Principal Accounting Fees and Services

The following table describes fees for professional audit services rendered by KPMG, our principal accountant, for the audit of our financial statements for the years ended December 31, 2003 and 2002, and for fees billed for other services rendered by KPMG during those periods.


		Years Ended December 31,

Type of Fee		2003		2002

		(in thousands)
Audit Fees		$	953	$	915
Audit Related Fees (1)			58		15
Tax Fees (2)			183		17
All Other Fees (3)			656		106

	Total	$	1,850	$	1,053

(1)		Audit related fees consist principally of fees for audits of financial statements of certain employee benefit plans and certain internal control documentation assistance.

(2)		Tax Fees consist of fees for sales and use tax consultation and tax compliance services.

(3)		All Other Fees include the aggregate fees we paid during the years ended December 31, 2003 and 2002, for products and services provided by KPMG, other than the services reported above. The majority of the other fees are fees for litigation support services related to the D.R.D. legal proceedings which were settled on July 16, 2003 (see Note 17. Commitments and Contingencies).

Procedures For Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Auditor

Pursuant to its charter, the Audit Committee of our Board of Directors is responsible for reviewing and approving, in advance, any audit and any permissible non-audit engagement or relationship between us and our independent auditors. KPMG’s engagement to conduct our audit was approved by the Audit Committee on April 28, 2003. Additionally, all permissible non-audit engagements with KPMG have been reviewed and approved by the Audit Committee, pursuant to pre-approval policies and procedures established by the Audit Committee.

PART IV

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

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

	(1)		Financial Statements: See Index to Financial Statements on page F-1 of this Report for financial statements filed as part of this Report.

	(2)		Financial Statement Schedules: None.

	(3)		Exhibits.


Exhibit
Number		Description

	3.1	Certificate of Limited Partnership of TEPPCO Partners, L.P. (Filed as Exhibit 3.2 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference).

	3.2	Third Amended and Restated Agreement of Limited Partnership of TEPPCO Partners, L.P., dated September 21, 2001 (Filed as Exhibit 3.7 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).

	4.1	Form of Certificate representing Limited Partner Units (Filed as Exhibit 4.1 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference).

	4.2	Form of Indenture between TE Products Pipeline Company, Limited Partnership and The Bank of New York, as Trustee, dated as of January 27, 1998 (Filed as Exhibit 4.3 to TE Products Pipeline Company, Limited Partnership’s Registration Statement on Form S-3 (Commission File No. 333-38473) and incorporated herein by reference).

	4.3	Form of Certificate representing Class B Units (Filed as Exhibit 4.3 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference).

	4.4	Form of Indenture between TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as subsidiary guarantors, and First Union National Bank, NA, as trustee, dated as of February 20, 2002 (Filed as Exhibit 99.2 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of February 20, 2002 and incorporated herein by reference).

	4.5	First Supplemental Indenture between TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as subsidiary guarantors, and First Union National Bank, NA, as trustee, dated as of February 20, 2002 (Filed as Exhibit 99.3 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of February 20, 2002 and incorporated herein by reference).

	4.6	Second Supplemental Indenture, dated as of June 27, 2002, among TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., and Jonah Gas Gathering Company, as Initial Subsidiary Guarantors, and Val Verde Gas Gathering Company, L.P., as New Subsidiary Guarantor, and Wachovia Bank, National Association, formerly known as First Union National Bank, as trustee (Filed as Exhibit 4.6 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by reference).

	4.7	Third Supplemental Indenture among TEPPCO Partners, L.P. as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Jonah Gas Gathering Company and Val Verde Gas Gathering Company, L.P. as Subsidiary Guarantors, and Wachovia Bank, National Association, as trustee, dated as of January 30, 2003 (Filed as Exhibit 4.7 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

	10.1+	Duke Energy Corporation Executive Savings Plan (Filed as Exhibit 10.7 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).

	10.2+	Duke Energy Corporation Executive Cash Balance Plan (Filed as Exhibit 10.8 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).

	10.3+	Duke Energy Corporation Retirement Benefit Equalization Plan (Filed as Exhibit 10.9 to Form 10-K for TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).


Exhibit
Number		Description

	10.4+	Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan executed on March 8, 1994 (Filed as Exhibit 10.1 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1994 and incorporated herein by reference).

	10.5+	Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan, Amendment 1, effective January 16, 1995 (Filed as Exhibit 10.12 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 1999 and incorporated herein by reference).

	10.6+	Form of Employment Agreement between the Company and Thomas R. Harper, Charles H. Leonard, James C. Ruth, John N. Goodpasture, Leonard W. Mallett, Stephen W. Russell, David E. Owen, and Barbara A. Carroll (Filed as Exhibit 10.20 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference).

	10.7	Services and Transportation Agreement between TE Products Pipeline Company, Limited Partnership and Fina Oil and Chemical Company, BASF Corporation and BASF Fina Petrochemical Limited Partnership, dated February 9, 1999 (Filed as Exhibit 10.22 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference).

	10.8	Call Option Agreement, dated February 9, 1999 (Filed as Exhibit 10.23 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference).

	10.9+	Texas Eastern Products Pipeline Company Retention Incentive Compensation Plan, effective January 1, 1999 (Filed as Exhibit 10.24 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference).

	10.10+	Form of Employment and Non-Compete Agreement between the Company and J. Michael Cockrell effective January 1, 1999 (Filed as Exhibit 10.29 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference).

	10.11+	Texas Eastern Products Pipeline Company Non-employee Directors Unit Accumulation Plan, effective April 1, 1999 (Filed as Exhibit 10.30 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference).

	10.12+	Texas Eastern Products Pipeline Company Non-employee Directors Deferred Compensation Plan, effective November 1, 1999 (Filed as Exhibit 10.31 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference).

	10.13+	Texas Eastern Products Pipeline Company Phantom Unit Retention Plan, effective August 25, 1999 (Filed as Exhibit 10.32 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference).

	10.14+	Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan, Amendment and Restatement, effective January 1, 2000 (Filed as Exhibit 10.28 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2000 and incorporated herein by reference).

	10.15+	TEPPCO Supplemental Benefit Plan, effective April 1, 2000 (Filed as Exhibit 10.29 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2000 and incorporated herein by reference).

	10.16+	Employment Agreement with Barry R. Pearl (Filed as Exhibit 10.30 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2001 and incorporated herein by reference).

	10.17	Amended and Restated Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent and LC Issuing Bank, and Certain Lenders, dated as of April 6, 2001 ($500,000,000 Revolving Facility) (Filed as Exhibit 10.31 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2001 and incorporated herein by reference).


Exhibit
Number		Description

	10.18	Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent, and Certain Lenders, dated as of April 6, 2001 ($200,000,000 Revolving Facility) (Filed as Exhibit 10.32 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2001 and incorporated herein by reference).

	10.19	Amendment 1, dated as of September 28, 2001, to the Amended and Restated Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent and LC Issuing Bank, and Certain Lenders, dated as of April 6, 2001 ($500,000,000 Revolving Facility) (Filed as Exhibit 10.33 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).

	10.20	Amendment 1, dated as of September 28, 2001, to the Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent, and Certain Lenders, dated as of April 6, 2001 ($200,000,000 Revolving Facility) (Filed as Exhibit 10.34 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).

	10.21	Amendment and Restatement, dated as of November 13, 2001, to the Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent, and Certain Lenders, dated as of April 6, 2001 ($200,000,000 Revolving Facility) (Filed as Exhibit 10.35 to Form 10-K of TEPPCO Partners, L.P (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).

	10.22	Second Amendment and Restatement, dated as of November 13, 2001, to the Amended and Restated Credit Agreement amount TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent and LC Issuing Bank, and Certain Lenders, dated as of April 6, 2001 ($500,000,000 Revolving Facility) (Filed as Exhibit 10.36 to Form 10-K of TEPPCO Partners, L.P (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).

	10.23	Second Amended and Restated Agreement of Limited Partnership of TE Products Pipeline Company, Limited Partnership, dated September 21, 2001 (Filed as Exhibit 3.8 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).

	10.24	Amended and Restated Agreement of Limited Partnership of TCTM, L.P., dated September 21, 2001 (Filed as Exhibit 3.9 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).

	10.25	Contribution, Assignment and Amendment Agreement among TEPPCO Partners, L.P., TE Products Pipeline Company, Limited Partnership, TCTM, L.P., Texas Eastern Products Pipeline Company, LLC, and TEPPCO GP, Inc., dated July 26, 2001 (Filed as Exhibit 3.6 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2001 and incorporated herein by reference).

	10.26	Certificate of Formation of TEPPCO Colorado, LLC (Filed as Exhibit 3.2 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1998 and incorporated herein by reference).

	10.27	Agreement of Limited Partnership of TEPPCO Midstream Companies, L.P., dated September 24, 2001 (Filed as Exhibit 3.10 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).

	10.28	Agreement of Partnership of Jonah Gas Gathering Company dated June 20, 1996 as amended by that certain Assignment of Partnership Interests dated September 28, 2001 (Filed as Exhibit 10.40 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).

	10.29	Unanimous Written Consent of the Board of Directors of TEPPCO GP, Inc. dated February 13, 2002 (Filed as Exhibit 10.41 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).


Exhibit
Number		Description

	10.30	Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent and Certain Lenders, as Lenders dated as of March 28, 2002 ($200,000,000 Revolving Credit Facility) (Filed as Exhibit 10.44 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the three months ended March 31, 2002 and incorporated herein by reference).

	10.31	Amended and Restated Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank, as Administrative Agent and LC Issuing Bank and Certain Lenders, as Lenders dated as of March 28, 2002 ($500,000,000 Revolving Facility) (Filed as Exhibit 10.45 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the three months ended March 31, 2002 and incorporated herein by reference).

	10.32	Purchase and Sale Agreement between Burlington Resources Gathering Inc. as Seller and TEPPCO Partners, L.P., as Buyer, dated May 24, 2002 (Filed as Exhibit 99.1 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).

	10.33	Credit Agreement among TEPPCO Partners, L.P., as Borrower, SunTrust Bank, as Administrative Agent and Certain Lenders, as Lenders dated as of June 27, 2002 ($200,000,000 Term Facility) (Filed as Exhibit 99.2 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).

	10.34	Amendment, dated as of June 27, 2002 to the Amended and Restated Credit Agreement among TEPPCO Partners, L.P., as Borrower, SunTrust Bank, as Administrative Agent, and Certain Lenders, dated as of March 28, 2002 ($500,000,000 Revolving Credit Facility) (Filed as Exhibit 99.3 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).

	10.35	Amendment 1, dated as of June 27, 2002 to the Credit Agreement among TEPPCO Partners, L.P., as Borrower, SunTrust Bank, as Administrative Agent and Certain Lenders, dated as of March 28, 2002 ($200,000,000 Revolving Credit Facility) (Filed as Exhibit 99.4 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).

	10.36	Agreement of Limited Partnership of Val Verde Gas Gathering Company, L.P., dated May 29, 2002 (Filed as Exhibit 10.48 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by reference).

	10.37+	Texas Eastern Products Pipeline Company, LLC 2002 Phantom Unit Retention Plan, effective June 1, 2002 (Filed as Exhibit 10.43 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by reference).

	10.38+	Amended and Restated TEPPCO Supplemental Benefit Plan, effective November 1, 2002 (Filed as Exhibit 10.44 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

	10.39+	Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan, Second Amendment and Restatement, effective January 1, 2003 (Filed as Exhibit 10.45 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

	10.40+	Amended and Restated Texas Eastern Products Pipeline Company, LLC Management Incentive Compensation Plan, effective January 1, 2003 (Filed as Exhibit 10.46 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

	10.41+	Amended and Restated TEPPCO Retirement Cash Balance Plan, effective January 1, 2002 (Filed as Exhibit 10.47 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

	10.42	Formation Agreement between Panhandle Eastern Pipe Line Company and Marathon Ashland Petroleum LLC and TE Products Pipeline Company, Limited Partnership, dated as of August 10, 2000 (Filed as Exhibit 10.48 to Form 10-K of TEPPCO Partners, L.P.


Exhibit
Number		Description

		(Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

	10.43	Amended and Restated Limited Liability Company Agreement of Centennial Pipeline LLC dated as of August 10, 2000 (Filed as Exhibit 10.49 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

	10.44	Guaranty Agreement, dated as of September 27, 2002, between TE Products Pipeline Company, Limited Partnership and Marathon Ashland Petroleum LLC for Note Agreements of Centennial Pipeline LLC (Filed as Exhibit 10.50 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

	10.45	LLC Membership Interest Purchase Agreement By and Between CMS Panhandle Holdings, LLC, As Seller and Marathon Ashland Petroleum LLC and TE Products Pipeline Company, Limited Partnership, Severally as Buyers, dated February 10, 2003 (Filed as Exhibit 10.51 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

	10.46	Joint Development Agreement between TE Products Pipeline Company, Limited Partnership and Louis Dreyfus Plastics Corporation dated February 10, 2000 (Filed as Exhibit 10.52 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2003 and incorporated herein by reference).

	10.47	Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent and LC Issuing Bank and The Lenders Party Hereto, as Lenders, dated as of June 27, 2003 ($550,000,000 Revolving Facility) (Filed as Exhibit 10.52 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2003 and incorporated herein by reference).

	10.48	Agreement of Limited Partnership of Mont Belvieu Storage Partners, L.P. dated effective January 21, 2003 (Filed as Exhibit 10.53 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2003 and incorporated herein by reference).

	10.49	Letter of Agreement Clarifying Rights and Obligations of the Parties Under the Mont Belvieu Storage Partners, L.P., Partnership Agreement and the Mont Belvieu Venture, LLC, LLC Agreement, dated October 13, 2003 (Filed as Exhibit 10.54 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2003 and incorporated herein by reference).

	12.1*	Statement of Computation of Ratio of Earnings to Fixed Charges.

	21	Subsidiaries of the Partnership (Filed as Exhibit 21 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by reference).

	23*	Consent of KPMG LLP.

	24*	Powers of Attorney.

	31.1*	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	31.2*	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	32.1**	Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

	32.2**	Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

	99.1*	Charter of the Audit Committee of the Board of Directors of the General Partner.

*		Filed herewith.

**		Furnished herewith pursuant to Item 601(b)-(32) of Regulation S-K.

+		A management contract or compensation plan or arrangement.

(b)

Reports on Form 8-K filed with or furnished to the Securities and Exchange Commission during the quarter ended December 31, 2003:

			A current report on Form 8-K was furnished on October 28, 2003, in connection with disclosure of third quarter estimates and earnings guidance.

			A current report on Form 8-K was filed on November 3, 2003, in connection with a presentation to analysts and investors.

			A current report on Form 8-K was filed on December 9, 2003, in connection with a presentation at an industry conference.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.


		TEPPCO Partners, L.P.

		(Registrant)
		(A Delaware Limited Partnership)

		By: Texas Eastern Products Pipeline
		Company, LLC, as General Partner

		By: /s/ BARRY R. PEARL

		Barry R. Pearl,
		President and Chief Executive Officer

		By: /s/ CHARLES H. LEONARD

		Charles H. Leonard,
		Senior Vice President and Chief Financial
		Officer

Dated: February 23, 2004

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.


Signature	Title	Date

BARRY R. PEARL* Barry R. Pearl	President and Chief Executive Officer of Texas Eastern Products Pipeline Company, LLC	February 23, 2004

CHARLES H. LEONARD Charles H. Leonard	Senior Vice President and Chief Financial Officer of Texas Eastern Products Pipeline Company, LLC (Principal Accounting and Financial Officer)	February 23, 2004

JIM W. MOGG* Jim W. Mogg	Chairman of the Board of Texas Eastern Products Pipeline Company, LLC	February 23, 2004

MARK A. BORER * Mark A. Borer	Director of Texas Eastern Products Pipeline Company, LLC	February 23, 2004

MILTON CARROLL* Milton Carroll	Director of Texas Eastern Products Pipeline Company, LLC	February 23, 2004

R.A. WALKER* R.A. Walker	Director of Texas Eastern Products Pipeline Company, LLC	February 23, 2004

DERRILL CODY* Derrill Cody	Director of Texas Eastern Products Pipeline Company, LLC	February 23, 2004

JOHN P. DESBARRES* John P. DesBarres	Director of Texas Eastern Products Pipeline Company, LLC	February 23, 2004

MICHAEL J. BRADLEY* Michael J. Bradley	Director of Texas Eastern Products Pipeline Company, LLC	February 23, 2004

WILLIAM H. EASTER III* William H. Easter III	Director of Texas Eastern Products Pipeline Company, LLC	February 23, 2004

* Signed on behalf of the Registrant and each of these persons:


By:		/s/ CHARLES H. LEONARD

		(Charles H. Leonard, Attorney-in-Fact)

CONSOLIDATED FINANCIAL STATEMENTS
OF TEPPCO PARTNERS, L.P.

INDEX TO FINANCIAL STATEMENTS


		Page

Financial Statements:
	Independent Auditors’ Report		F-2
	Consolidated Balance Sheets as of December 31, 2003 and 2002		F-3
	Consolidated Statements of Income for the years ended December 31, 2003, 2002 and 2001		F-4
	Consolidated Statements of Cash Flows for the years ended December 31, 2003, 2002 and 2001		F-5
	Consolidated Statements of Partners’ Capital for the years ended December 31, 2003, 2002 and 2001		F-6
	Notes to Consolidated Financial Statements		F-7

F-1

INDEPENDENT AUDITORS’ REPORT

To the Partners of
TEPPCO Partners, L.P.:

We have audited the accompanying consolidated balance sheets of TEPPCO Partners, L.P. as of December 31, 2003 and 2002, and the related consolidated statements of income, partners’ capital, and cash flows for each of the years in the three-year period ended December 31, 2003. These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of TEPPCO Partners, L.P. as of December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.

As described in Note 2 to the consolidated financial statements, as of January 1, 2001, the Partnership changed its method of accounting for derivative instruments and hedging activities and, effective January 1, 2002, adopted Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets.

KPMG LLP

Houston, Texas
February 12, 2004

F-2

TEPPCO PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS
(in thousands)


					December 31,

					2003			2002

				ASSETS
Current assets:
	Cash and cash equivalents				$	29,469		$	30,968
	Accounts receivable, trade (net of allowance for doubtful accounts of $4,700 and $4,608)					371,938			271,854
	Accounts receivable, related parties					3,143			8,751
	Inventories					16,060			15,104
	Other					32,208			31,670

		Total current assets				452,818			358,347

Property, plant and equipment, at cost (net of accumulated depreciation and amortization of $345,357 and $338,746)						1,619,163			1,587,824
Equity investments						365,286			284,705
Intangible assets						438,565			465,374
Goodwill						16,944			16,944
Other assets						48,216			55,228

		Total assets			$	2,940,992		$	2,768,422

			LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
	Accounts payable and accrued liabilities				$	359,660		$	265,844
	Accounts payable, related parties					16,269			8,888
	Accrued interest					35,111			29,726
	Other accrued taxes					9,941			11,260
	Other					54,610			48,845

		Total current liabilities				475,591			364,563

Senior Notes						1,129,650			945,692
Other long-term debt						210,000			432,000
Other liabilities and deferred credits						16,430			30,962
Redeemable Class B Units held by related party						—			103,363
Commitments and contingencies
Partners’ capital:
	Accumulated other comprehensive loss					(2,902	)		(20,055	)
	General partner’s interest					(7,181	)		12,770
	Limited partners’ interests					1,119,404			899,127

		Total partners’ capital				1,109,321			891,842

		Total liabilities and partners’ capital			$	2,940,992		$	2,768,422

See accompanying Notes to Consolidated Financial Statements.

F-3

TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME
(in thousands, except per Unit amounts)


			Years Ended December 31,

			2003			2002			2001

Operating revenues:
	Sales of petroleum products		$	3,766,651		$	2,823,800		$	3,219,816
	Transportation – Refined products			138,926			123,476			139,315
	Transportation – LPGs			91,787			74,577			77,823
	Transportation – Crude oil			29,057			27,414			24,223
	Transportation – NGLs			39,837			38,870			20,702
	Gathering – Natural gas			135,144			90,053			8,824
	Mont Belvieu operations			—			15,238			14,116
	Other			54,430			48,735			51,594

		Total operating revenues		4,255,832			3,242,163			3,556,413

Costs and expenses:
	Purchases of petroleum products			3,711,207			2,772,328			3,172,805
	Operating, general and administrative			201,329			158,753			135,253
	Operating fuel and power			38,511			36,814			36,575
	Depreciation and amortization			100,728			86,032			45,899
	Taxes – other than income taxes			15,597			17,989			14,090
	Gain on sale of assets			(3,948	)		—			—

		Total costs and expenses		4,063,424			3,071,916			3,404,622

		Operating income		192,408			170,247			151,791
Interest expense – net				(84,250	)		(66,192	)		(62,057	)
Equity earnings				16,863			11,980			17,398
Other income – net				748			1,827			2,799

		Income before minority interest		125,769			117,862			109,931
Minority interest				—			—			(800	)

		Net income	$	125,769		$	117,862		$	109,131

Net Income Allocation:
Limited Partner Unitholders			$	89,191		$	81,238		$	76,986
Class B Unitholder				1,806			6,943			8,642
General Partner				34,772			29,681			23,503

		Total net income allocated	$	125,769		$	117,862		$	109,131

Basic and diluted net income per Limited Partner and Class B Unit			$	1.52		$	1.79		$	2.18

Weighted average Limited Partner and Class B Units outstanding				59,765			49,202			39,258

See accompanying Notes to Consolidated Financial Statements.

F-4

TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)


				Years Ended December 31,

				2003			2002			2001

Cash flows from operating activities:
	Net income			$	125,769		$	117,862		$	109,131
	Adjustments to reconcile net income to cash provided by operating activities:
		Depreciation and amortization			100,728			86,032			45,899
		Earnings in equity investments, net of distributions			11,140			18,401			14,377
		Gain on sale of assets			(3,948	)		—			—
		Non-cash portion of interest expense			4,793			4,916			4,053
		Decrease (increase) in accounts receivable			(100,085	)		(50,313	)		81,190
		Decrease (increase) in inventories			(956	)		2,139			7,541
		Increase in other current assets			(953	)		(16,263	)		(8,082	)
		Increase (decrease) in accounts payable and accrued expenses			100,757			68,805			(71,757	)
		Other			2,109			3,338			(13,204	)

			Net cash provided by operating activities		239,354			234,917			169,148

Cash flows from investing activities:
	Proceeds from the sale of assets				8,531			3,380			1,300
	Proceeds from cash investments				750			—			4,236
	Purchase of crude oil assets				(27,469	)		—			(31,000	)
	Purchase of Val Verde Gathering System				—			(444,150	)		—
	Purchase of Jonah Gas Gathering Company				—			(7,319	)		(359,834	)
	Purchase of Chaparral NGL System				—			(132,372	)		—
	Investment in Mont Belvieu Storage Partners, L.P.				(2,533	)		—			—
	Investment in Centennial Pipeline LLC				(4,000	)		(10,882	)		(64,953	)
	Acquisition of additional interest in Centennial Pipeline LLC				(20,000	)		—			—
	Capital expenditures				(140,517	)		(133,372	)		(107,614	)

			Net cash used in investing activities		(185,238	)		(724,715	)		(557,865	)

Cash flows from financing activities:
	Proceeds from revolving credit facilities				382,000			675,000			546,148
	Issuance of Limited Partner Units, net				287,506			372,506			234,660
	Issuance of Senior Notes				198,570			497,805			—
	Proceeds from termination of interest rate swaps				—			44,896			—
	Repayments on revolving credit facilities				(604,000	)		(943,659	)		(291,490	)
	Repurchase and retirement of Class B Units				(113,814	)		—			—
	Debt issuance costs				(3,381	)		(7,025	)		(2,601	)
	General Partner’s contributions				2			7,617			4,795
	Distributions paid				(202,498	)		(151,853	)		(104,412	)

			Net cash (used in) provided by financing activities		(55,615	)		495,287			387,100

Net increase (decrease) in cash and cash equivalents					(1,499	)		5,489			(1,617	)
Cash and cash equivalents at beginning of period					30,968			25,479			27,096

Cash and cash equivalents at end of period				$	29,469		$	30,968		$	25,479

Non-cash investing activities:
	Net assets transferred to Mont Belvieu Storage Partners, L.P.			$	61,408		$	—		$	—

Supplemental disclosure of cash flows:
	Cash paid for interest (net of amounts capitalized)			$	79,930		$	48,908		$	61,458

See accompanying Notes to Consolidated Financial Statements.

F-5

TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(in thousands, except Unit amounts)


		Outstanding								Accumulated
		Limited		General			Limited			Other
		Partner		Partner’s			Partners’			Comprehensive
		Units		Interest			Interests			Loss			Total

Partners’ capital at December 31, 2000			32,700,000	$	1,824		$	313,233		$	—		$	315,057
	Capital contributions		—		4,795			—			—			4,795
	Issuance of Limited Partner Units, net		7,750,000		—			234,660			—			234,660
	Minority interest restructured		—		4,598			—			—			4,598
	Cumulative effect of accounting change		—		—			—			(10,103	)		(10,103	)
	Net loss on cash flow hedge		—		—			—			(10,221	)		(10,221	)
	2001 net income allocation		—		23,503			76,986			—			100,489
	2001 cash distributions		—		(21,530	)		(73,961	)		—			(95,491	)
	Option exercises, net of Unit repurchases		—		—			(603	)		—			(603	)

Partners’ capital at December 31, 2001			40,450,000		13,190			550,315			(20,324	)		543,181
	Capital contributions		—		7,568			—			—			7,568
	Issuance of Limited Partner Units, net		13,260,000		—			370,108			—			370,108
	Net gain on cash flow hedge		—		—			—			269			269
	2002 net income allocation		—		29,681			81,238			—			110,919
	2002 cash distributions		—		(37,718	)		(104,932	)		—			(142,650	)
	Issuance of Limited Partner Units upon exercise of options		99,597		49			2,398			—			2,447

Partners’ capital at December 31, 2002			53,809,597		12,770			899,127			(20,055	)		891,842
	Issuance of Limited Partner Units, net		9,101,650		—			285,461			—			285,461
	Retirement of Class B Units		—		—			(10,993	)		—			(10,993	)
	Net gain on cash flow hedge		—		—			—			16,164			16,164
	Reclassification due to discontinued portion of cash flow hedge		—		—			—			989			989
	2003 net income allocation		—		34,772			89,191			—			123,963
	2003 cash distributions		—		(54,725	)		(145,427	)		—			(200,152	)
	Issuance of Limited Partner Units upon exercise of options		87,307		2			2,045			—			2,047

Partners’ capital at December 31, 2003			62,998,554	$	(7,181	)	$	1,119,404		$	(2,902	)	$	1,109,321

See accompanying Notes to Consolidated Financial Statements.

F-6

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. PARTNERSHIP ORGANIZATION

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

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

At formation in 1990, we completed an initial public offering of 26,500,000 Units representing Limited Partner Interests (“Limited Partner Units”) at $10.00 per Unit. In connection with our formation, the Company received 2,500,000 Deferred Participation Interests (“DPIs”). Effective April 1, 1994, the DPIs began participating in distributions of cash and allocations of profit and loss in a manner identical to Limited Partner Units and are treated as Limited Partner Units for purposes of this Report. These Limited Partner Units were assigned to Duke Energy when ownership of the Company was transferred from Duke Energy to DEFS in 2000. Pursuant to our Partnership Agreement, we have registered the resale by Duke Energy of such Limited Partner Units with the Securities and Exchange Commission. As of December 31, 2003, none of these Limited Partner Units had been sold by Duke Energy.

F-7

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

We adhere to the following significant accounting policies in the preparation of our consolidated financial statements.

Basis of Presentation and Principles of Consolidation

The financial statements include our accounts on a consolidated basis. The Company’s 1% general partner interest in the Operating Partnerships, prior to July 26, 2001, is accounted for as a minority interest. We have eliminated all significant intercompany items in consolidation. We have reclassified certain amounts from prior periods to conform with the current presentation.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles in the United States requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

Business Segments

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.

Revenue Recognition

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. Transportation revenues are recognized as products are delivered to customers. Storage revenues are recognized upon receipt of products into storage and upon performance of storage services. Terminaling revenues are recognized as products are out-loaded. Revenues from the sale of product inventory are recognized when the products are sold.

F-8

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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. Revenues are also generated from trade documentation and pumpover services, primarily at Cushing, Oklahoma, and Midland, Texas. Revenues are accrued at the time title to the product sold transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser, and purchases are accrued at the time title to the product purchased transfers to our crude oil marketing company, TEPPCO Crude Oil, L.P., which typically occurs upon our receipt of the product. Revenues related to trade documentation and pumpover fees are recognized as services are completed.

Except for crude oil purchased from time to time as inventory, our policy is to purchase only crude oil for which we have a market to sell and to structure sales contracts so that crude oil price fluctuations do not materially affect the margin received. As we purchase crude oil, we establish a margin by selling crude oil for physical delivery to third party users or by entering into a future delivery obligation. Through these transactions, we seek to maintain a position that is balanced between crude oil purchases and sales and future delivery obligations. However, certain basis risks (the risk that price relationships between delivery points, classes of products or delivery periods will change) cannot be completely hedged.

Our Midstream Segment revenues are earned from the gathering of natural gas, fractionation of NGLs and transportation of NGLs. 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, with the exception of inventory imbalances discussed in “Natural Gas Imbalances.” Therefore, the results of our Midstream Segment are not directly affected by changes in the prices of natural gas or NGLs.

Cash and Cash Equivalents

Cash equivalents are defined as all highly marketable securities with maturities of three months or less when purchased. The carrying value of cash and cash equivalents approximate fair value because of the short term nature of these investments.

Allowance for Doubtful Accounts

We establish provisions for losses on accounts receivable if we determine that we will not collect all or part of the outstanding balance. Collectibility is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. The following table presents the activity of our allowance for doubtful accounts for the years ended December 31, 2003, 2002 and 2001 (in thousands):


		Years Ended December 31,

		2003			2002			2001

Balance at beginning of period		$	4,608		$	4,422		$	—
Charges to expense			793			325			4,422
Deductions and other			(701	)		(139	)		—

	Balance at end of period	$	4,700		$	4,608		$	4,422

F-9

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Inventories

Inventories consist primarily of petroleum products and crude oil which are valued at the lower of cost (weighted average cost method) or market. Our Downstream Segment acquires and disposes of various products under exchange agreements. Receivables and payables arising from these transactions are usually satisfied with products rather than cash. The net balances of exchange receivables and payables are valued at weighted average cost and included in inventories. Inventories of materials and supplies, used for ongoing replacements and expansions, are carried at the lower of fair value or cost.

Property, Plant and Equipment

We evaluate impairment of long-lived assets in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of the carrying amount of assets to be held and used is measured by a comparison of the carrying amount of the asset to future net cash flows expected to be generated by the asset. 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.

Capitalization of Interest

We capitalize interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average rate used to capitalize interest on borrowed funds was 4.84%, 5.11% and 6.46% for the years ended December 31, 2003, 2002 and 2001, respectively. During the years ended December 31, 2003, 2002 and 2001, the amount of interest capitalized was $5.3 million, $4.3 million and $4.0 million, respectively.

Intangible Assets

Intangible assets at December 31, 2003, consist primarily of gathering contracts assumed in the acquisition of Jonah Gas Gathering System (“Jonah”) on September 30, 2001, and the acquisition of Val Verde Gathering System (“Val Verde”) on June 30, 2002, the fractionation agreement with DEFS and other intangible assets (see Note 3. Goodwill and Other Intangible Assets).

In connection with the acquisitions of Jonah and Val Verde, we assumed contracts that dedicate future production from natural gas wells in the Green River Basin in Wyoming, and we assumed fixed-term contracts with customers that gather coal bed methane (“CBM”) from the San Juan Basin in New Mexico and Colorado, respectively (see Note 6. Acquisitions and Dispositions). The value assigned to our intangible assets relates to contracts with customers that are for either a fixed term or which dedicate total future lease production to the gathering system. 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. Due to our recent expansions on the gathering systems at Jonah and because of certain limited production forecasts obtained from producers on the Jonah system related to the expansions, in the second quarter of 2003, we increased our estimate of

F-10

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

future throughput on the Jonah system. This increase in the estimate of future throughput extends the expected amortization period of Jonah’s natural gas gathering contracts from 16 years to approximately 25 years. The amortization of the contracts related to the Val Verde system is expected to average approximately 20 years. Further revisions to these estimates may occur as additional production information is made available to us.

In connection with the purchase of the fractionation facilities in 1998, we entered into a fractionation agreement with DEFS. The fractionation agreement is being amortized over a period of 20 years, which is the term of the agreement with DEFS (see Note 8. Related Party Transactions).

In connection with the acquisition of crude supply and transportation assets in November 2003, we acquired intangible customer contracts for $8.5 million, which are amortized on a unit-of-production basis (see Note 6. Acquisitions and Dispositions).

Goodwill

Goodwill represents the excess of purchase price over fair value of net assets acquired and is presented on the consolidated balance sheets net of accumulated amortization. We account for goodwill under SFAS No. 142, Goodwill and Other Intangible Assets which was issued by the Financial Accounting Standards Board (“FASB”) in July 2001 (see Note 3. Goodwill and Other Intangible Assets). SFAS 142 prohibits amortization of goodwill and intangible assets with indefinite useful lives, but instead requires testing for impairment at least annually. SFAS 142 requires that intangible assets with definite useful lives be amortized over their respective estimated useful lives. Beginning January 1, 2002, effective with the adoption of SFAS 142, we no longer record amortization expense related to goodwill or amortization expense related to the excess investment on our equity investment (equity method goodwill).

Environmental Expenditures

We accrue for environmental costs that relate to existing conditions caused by past operations. Environmental costs include initial site surveys and environmental studies of potentially contaminated sites, costs for remediation and restoration of sites determined to be contaminated and ongoing monitoring costs, as well as 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.

The following table presents the activity of our environmental reserve for the years ended December 31, 2003, 2002 and 2001 (in thousands):


		Years Ended December 31,

		2003			2002			2001

Balance at beginning of period		$	7,693		$	6,434		$	3,648
Additions related to acquisitions			—			—			300
Charges to expense			6,824			5,785			8,691
Deductions and other			(6,878	)		(4,526	)		(6,205	)

	Balance at end of period	$	7,639		$	7,693		$	6,434

F-11

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Natural Gas Imbalances

Gas imbalances occur when gas producers (customers) deliver more or less actual natural gas gathering volumes to our gathering systems than they originally nominated. Actual deliveries are different from nominated volumes due to fluctuations in gas production at the wellhead. If the customers supply more natural gas gathering volumes than they nominated, Val Verde and Jonah record a payable for the amount due to customers and also record a receivable for the same amount due from connecting pipeline transporters or shippers. If the customers supply less natural gas gathering volumes than they nominated, the Val Verde and the Jonah systems record a receivable reflecting the amount due from customers and a payable for the same amount due to connecting pipeline transporters or shippers. We record natural gas imbalances using a mark-to-market approach.

Income Taxes

We are a limited partnership. As such, we are not a taxable entity for federal and state income tax purposes and do not directly pay federal and state income tax. Our taxable income or loss, which may vary substantially from the net income or net loss we report in our consolidated statements of income, is includable in the federal and state income tax returns of each unitholder. Accordingly, no recognition has been given to federal income taxes for our operations. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined as we do not have access to information about each unitholders’ tax attributes in the Partnership.

Use of Derivatives

We account for derivative financial instruments in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of FASB Statement No. 133. These statements establish accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet at fair value as either assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative.

We adopted SFAS 133 at January 1, 2001, which resulted in the recognition of approximately $10.1 million of derivative liabilities, $4.1 million of which were current liabilities and $6.0 million of which were noncurrent liabilities, and $10.1 million of hedging losses included in accumulated other comprehensive income, a component of partners’ capital, as the cumulative effect of the change in accounting. The hedging losses included in accumulated other comprehensive loss are transferred to earnings as the forecasted transactions actually occur. Amounts determined as of January 1, 2001, were based on the market quote of our interest swap agreement in place at the time of adoption.

Our derivative instruments consist primarily of interest rate swaps and contracts for the purchase and sale of petroleum products in connection with our crude oil marketing activities. Substantially all derivative instruments related to our crude oil marketing activities meet the normal purchases and sales criteria of SFAS 133, as amended, and as such, changes in the fair value of petroleum product purchase and sales agreements are reported on the accrual basis of accounting. SFAS 133 describes normal purchases and sales as contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business.

For all hedging relationships, we formally document at inception the hedging relationship and its risk-management objective and strategy for undertaking the hedge, the hedging instrument, the item, the nature of the risk being hedged, how the hedging instrument’s effectiveness in offsetting the hedged risk will be assessed and a

F-12

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

description of the method of measuring ineffectiveness. This process includes linking all derivatives that are designated as fair value or cash flow to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions. We also formally assess, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair values or cash flows of hedged items. If it is determined that a derivative is not highly effective as a hedge or that it has ceased to be a highly effective hedge, we discontinue hedge accounting prospectively.

For derivative instruments designated as fair value hedges, gains and losses on the derivative instrument are offset against related results on the hedged item in the statement of income. Changes in the fair value of a derivative that is highly effective and that is designated and qualifies as a fair value hedge, along with the loss or gain on the hedged asset or liability or unrecognized firm commitment of the hedged item that is attributable to the hedged risk, are recorded in earnings. Changes in the fair value of a derivative that is highly effective and that is designated and qualifies as a cash flow hedge are recorded in other comprehensive income to the extent that the derivative is effective as a hedge, until earnings are affected by the variability in cash flows of the designated hedged item. Hedge effectiveness is measured at least quarterly based on the relative cumulative changes in fair value between the derivative contract and the hedged item over time. The ineffective portion of the change in fair value of a derivative instrument that qualifies as either a fair value hedge or a cash flow hedge is reported immediately in earnings.

According to SFAS 133, as amended, we are required to discontinue hedge accounting prospectively when it is determined that the derivative is no longer effective in offsetting changes in the fair value or cash flows of the hedged item, the derivative expires or is sold, terminated, or exercised, the derivative is dedesignated as a hedging instrument, because it is unlikely that a forecasted transaction will occur, a hedged firm commitment no longer meets the definition of a firm commitment, or management determines that designation of the derivative as a hedging instrument is no longer appropriate.

When hedge accounting is discontinued because it is determined that the derivative no longer qualifies as an effective fair value hedge, we continue to carry the derivative on the balance sheet at its fair value and no longer adjust the hedged asset or liability for changes in fair value. The adjustment of the carrying amount of the hedged asset or liability is accounted for in the same manner as other components of the carrying amount of that asset or liability. When hedge accounting is discontinued because the hedged item no longer meets the definition of a firm commitment, we continue to carry the derivative on the balance sheet at its fair value, remove any asset or liability that was recorded pursuant to recognition of the firm commitment from the balance sheet, and recognize any gain or loss in earnings. When hedge accounting is discontinued because it is probable that a forecasted transaction will not occur, we continue to carry the derivative on the balance sheet at its fair value with subsequent changes in fair value included in earnings, and gains and losses that were accumulated in other comprehensive income are recognized immediately in earnings. In all other situations in which hedge accounting is discontinued, we continue to carry the derivative at its fair value on the balance sheet and recognize any subsequent changes in its fair value in earnings.

Net Income Per Unit

Basic net income per Unit is computed by dividing net income, after deduction of the General Partner’s interest, by the weighted average number of Limited Partner and Class B Units outstanding (a total of 59.8 million Units, 49.2 million Units and 39.3 million Units for the years ended December 31, 2003, 2002 and 2001, respectively). The General Partner’s percentage interest in our net income is based on its percentage of cash distributions from Available Cash for each year (see Note 12. Partner’s Capital and Distributions). The General Partner was allocated $34.8 million (representing 27.65%) of net income for the year ended December 31, 2003, $29.7 million (representing 25.18%) of net income for the year ended December 31, 2002, and $23.5 million (representing 21.54%) of net income for the year ended December 31, 2001. The General Partner’s percentage interest in our net income increases as cash distributions paid per Unit increase, according to our Partnership Agreement.

F-13

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Diluted net income per Unit is similar to the computation of basic net income per Unit, except that the denominator is increased to include the dilutive effect of outstanding Unit options by application of the treasury stock method. For the years ended December 31, 2003, 2002 and 2001, the denominator was increased by 11,878 Units, 32,053 Units and 41,864 Units, respectively. During the third quarter of 2003, all remaining outstanding Unit options were exercised (see Note 14. Unit-Based Compensation).

Unit Option Plan

We have not granted options for any periods presented. For options outstanding under the 1994 Long Term Incentive Plan (see Note 14. Unit-Based Compensation), we followed the intrinsic value method of accounting for recognizing stock-based compensation expense. Under this method, we record no compensation expense for Unit options granted when the exercise price of the options granted is equal to, or greater than, the market price of our Units on the date of the grant. During the year ended December 31, 2003, all remaining outstanding Unit options were exercised.

In December 2002, SFAS No. 148, Accounting for Stock-Based Compensation – Transition and Disclosure was issued. SFAS 148 amends SFAS No. 123, Accounting for Stock-Based Compensation, and provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS 148 amends the disclosure requirements of SFAS 123 to require prominent disclosure in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. Certain of the disclosure modifications are required for fiscal years ending after December 15, 2002, and are included in Note 14. Unit-Based Compensation.

Assuming we had used the fair value method of accounting for our Unit option plan, pro forma net income for the years ended December 31, 2002 and 2001, would be lower than reported net income by an immaterial amount. Pro forma net income would equal reported net income for the year ended December 31, 2003. Pro forma net income per Unit would equal reported net income per Unit for the periods presented. The adoption of SFAS 148 did not have an effect on our financial position, results of operations or cash flows.

New Accounting Pronouncements

In January 2003, the FASB issued FASB Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51 (“FIN 46”). FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. We are required to apply FIN 46 to all new variable interest entities created or acquired after January 31, 2003. For variable interest entities created or acquired prior to February 1, 2003, we were required to apply FIN 46 on July 1, 2003. In connection with the adoption of FIN 46, we evaluated our investments in Centennial Pipeline LLC, Seaway Crude Pipeline Company and Mont Belvieu Storage Partners, L.P. and determined that these entities are not variable interest entities as defined by FIN 46, and thus we have accounted for them as equity method investments (see Note 7. Equity Investments). The adoption of FIN 46 did not have an effect on our financial position, results of operations or cash flows.

In December 2003, the FASB revised FIN 46. The revised statement, FASB Interpretation No. 46(R), Consolidation of Variable Interest Entities, an interpretation of ARB No. 51 (“FIN 46(R)”) clarifies some of the requirements of FIN 46, eases some implementation problems that companies experienced implementing FIN 46, adds new scope exceptions and makes the probability more likely for many companies that potential variable interest entities will be identified and consolidated. We are required to apply the new requirements detailed in FIN 46(R) as of March 31, 2004. We are evaluating our investments in Centennial Pipeline LLC, Seaway Crude Pipeline Company and Mont Belvieu Storage Partners, L.P. to determine the impact, if any, of the adoption of FIN

F-14

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

46(R). We do not believe the adoption of FIN 46(R) will have a material effect on our financial position, results of operations or cash flows.

In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS 149 amends SFAS 133 to conform and incorporate derivative implementation issues and subsequently issued accounting guidance. SFAS 149 clarifies under what circumstances a contract with an initial net investment meets the characteristics of a derivative, clarifies when a derivative contains a financing component, amends the definition of an underlying to conform it to language used in FASB Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others and amends certain other existing pronouncements. SFAS 149 is effective for contracts entered into or modified after June 30, 2003, and should be applied prospectively. However, certain SFAS 133 implementation issues that were effective for all fiscal quarters prior to June 15, 2003, should continue to be applied in accordance with their respective effective dates. We adopted SFAS 149 effective July 1, 2003. The adoption of SFAS 149 did not have an effect on our financial position, results of operations or cash flows.

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. SFAS 150 establishes standards for how an issuer classifies and measures certain freestanding financial instruments with characteristics of both liabilities and equity. SFAS 150 requires that an issuer classify a financial instrument that is within its scope as a liability (or asset in some circumstances). We adopted SFAS 150 effective July 1, 2003. The adoption of SFAS 150 did not have an effect on our financial position, results of operations or cash flows.

In May 2003, the EITF reached consensus in EITF 01-08, Determining Whether an Arrangement Contains a Lease, to clarify the requirements of identifying whether an arrangement should be accounted for as a lease at its inception. The guidance in the consensus is designed to mandate reporting revenue as rental or leasing income that otherwise would be reported as part of product sales or service revenue. EITF 01-08 requires both parties in an arrangement to determine whether a service contract or similar arrangement is or includes a lease within the scope of SFAS No. 13, Accounting For Leases. We have historically leased storage capacity to outside parties and entered into pipeline capacity lease agreements both as the lessee and as the lessor. The accounting requirements under the consensus affect the timing of revenue and expense recognition, and revenues reported as transportation and storage services might have to be reported as rental or leasing income. Should capital-lease treatment be necessary, purchasers of transportation and storage services in the arrangements would have to recognize new assets on their balance sheets. The consensus is to be applied prospectively to arrangements agreed to, modified, or acquired in business combinations in fiscal periods beginning after May 28, 2003. Previous arrangements that would be leases or would contain a lease according to the consensus will continue to be accounted for as transportation and storage purchases or sales arrangements. As we enter into new arrangements, we will assess the impact of EITF 01-08 on the arrangement. The adoption of EITF 01-08 did not have a material effect on our financial position, results of operations or cash flows.

In July 2003, the EITF reached consensus in EITF 03-11, Reporting Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes. In a 2002 Issue, the EITF reached a consensus that all gains and losses (realized and unrealized) on derivative instruments within the scope of SFAS 133 should be shown net in the income statement, whether or not settled physically, if the derivative instruments are held for trading purposes. However, the EITF recognized that there may be contracts within the scope of SFAS 133 considered not held for trading purposes that warrant further consideration as to the appropriate income statement classification of the gains and losses. In EITF 03-11, the EITF clarified certain criteria to use in determining whether gains and losses related to non-trading derivative instruments should be shown net in the income statement. The adoption of EITF 03-11 did not have a material effect on our financial position, results of operations or cash flows.

F-15

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

On December 8, 2003, President Bush signed into a law a bill that expands Medicare, primarily adding a prescription drug benefit for Medicare-eligible retirees starting in 2006. We anticipate that the benefits we pay after 2006 could be lower as a result of the new Medicare provisions; however, at this time the retiree medical obligations and costs reported do not reflect any changes as a result of this legislation. Deferring the recognition of the new Medicare provisions’ impact is permitted by FASB Staff Position 106-1, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, due to open questions about some of the new Medicare provisions and a lack of authoritative accounting guidance about certain matters. The final accounting guidance could require changes to previously reported information. We do not believe that this regulation will have a material adverse effect on our financial position, results of operations or cash flows.

NOTE 3. GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill

Beginning January 1, 2002, effective with the adoption of SFAS 142, we no longer record amortization expense related to goodwill or amortization expense related to the excess investment on our equity investment in Seaway Crude Pipeline Company (see Note 7. Equity Investments). The following table presents our results on a comparable basis, as if we had not recorded amortization expense of goodwill or amortization expense of our excess investment in Seaway Crude Pipeline Company for the years ended December 31, 2003, 2002 and 2001 (in thousands, except per Unit amounts):


			Years Ended December 31,

			2003		2002		2001

Net income:
	Reported net income		$	125,769	$	117,862	$	109,131
	Amortization of goodwill and excess investment			—		—		2,396

		Adjusted net income	$	125,769	$	117,862	$	111,527

Net income allocation:
	Limited Partner Unitholders		$	89,191	$	81,238	$	78,676
	Class B Unitholder			1,806		6,943		8,832
	General Partner			34,772		29,681		24,019

		Total net income allocated	$	125,769	$	117,862	$	111,527

Basic and diluted net income per Limited Partner and Class B Unit:
	As reported		$	1.52	$	1.79	$	2.18
	Amortization of goodwill and excess investment			—		—		0.05

		Adjusted net income per Unit	$	1.52	$	1.79	$	2.23

In connection with the transitional goodwill impairment evaluation required by SFAS 142, we were required to perform an assessment of whether there was an indication that goodwill was impaired as of the date of adoption. We accomplished this by identifying our reporting units and determining the carrying value of each

F-16

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

reporting unit by assigning the assets and liabilities, including the existing goodwill and intangible assets, to those reporting units as of the date of adoption. We then determined the fair value of each reporting unit and compared it to the carrying value of the reporting unit. We completed this analysis during the second quarter of 2002, resulting in no transitional impairment loss. We will continue to compare the fair value of each reporting unit to the carrying value on an annual basis to determine if an impairment loss has occurred.

At December 31, 2003, we had $16.9 million of unamortized goodwill and $25.5 million of excess investment in our equity investment in Seaway Crude Pipeline Company (equity method goodwill). We completed an impairment analysis of the excess investment in our equity investment during the year ended December 31, 2003, and we noted no indication of impairment. The excess investment is included in our equity investments account at December 31, 2003. The following table presents the carrying amount of goodwill and equity method goodwill at December 31, 2003, by business segment (in thousands):


	Downstream		Midstream		Upstream		Segments
	Segment		Segment		Segment		Total

Goodwill	$	—	$	2,777	$	14,167	$	16,944
Equity method goodwill		—		—		25,502		25,502

Other Intangible Assets

The following table reflects the components of amortized intangible assets at December 31, 2003 and 2002 (in thousands):


			December 31, 2003					December 31, 2002

			Gross Carrying		Accumulated			Gross Carrying		Accumulated
			Amount		Amortization			Amount		Amortization

Amortized intangible assets:
	Gathering and transportation agreements		$	464,337	$	(62,436	)	$	463,449	$	(28,818	)
	Fractionation agreement			38,000		(10,925	)		38,000		(9,025	)
	Other			11,270		(1,681	)		2,745		(977	)

		Total	$	513,607	$	(75,042	)	$	504,194	$	(38,820	)

At December 31, 2003, we had $33.4 million of excess investment in our equity investment in Centennial Pipeline LLC, which was created upon formation of the company (see Note 7. Equity Investments). The excess investment is included in our equity investments account at December 31, 2003. This excess investment is accounted for as an intangible asset with an indefinite life. We completed an impairment analysis of the excess investment in Centennial Pipeline LLC during the year ended December 31, 2003, and we noted no indication of impairment. We will assess the intangible asset for impairment on an annual basis.

Upon the adoption of SFAS 142, we were required to reassess the useful lives and residual values of all intangible assets acquired, and make necessary amortization period adjustments by the end of the first interim period after adoption. We completed this analysis during the year ended December 31, 2002, resulting in no change to the amortization period for our intangible assets. We will continue to reassess the useful lives and residual values of all intangible assets on an annual basis.

SFAS 142 requires that intangible assets with finite useful lives be amortized over their respective estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset shall be amortized over the best estimate of its useful life. At a minimum, we will assess the useful lives and residual values of all intangible assets on an annual basis to determine if adjustments are required. With respect to our natural gas gathering contracts, we update throughput estimates and evaluate the remaining

F-17

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

expected useful life of the contract assets on a quarterly basis based on the best available information. Amortization expense on intangible assets was $36.2 million, $27.9 million and $5.5 million for the years ended December 31, 2003, 2002 and 2001, respectively.

The value assigned to our intangible assets for natural gas gathering contracts 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. Due to our recent expansions on the gathering systems at Jonah and because of certain limited production forecasts obtained from producers on the Jonah system related to the expansions, in the second quarter of 2003, we increased our best estimate of future throughput on the Jonah system. This increase in the estimate of future throughput extends the amortization period of Jonah’s natural gas gathering contracts by an estimated 9 years, increasing from approximately 16 years to 25 years. Further revisions to this estimate may occur as additional production information is made available to us.

The following table sets forth the estimated amortization expense on intangible assets for the years ending December 31 (in thousands):


2004	$	35,146
2005		40,614
2006		37,882
2007		35,005
2008		32,688

NOTE 4. INTEREST RATE SWAPS

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

By using interest rate swap agreements to hedge exposures to changes in interest rates and the fair value of fixed rate Senior Notes, we are exposed to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk for us. When the fair value of a derivative contract is negative, we owe the counterparty and, therefore, we do not possess credit risk. We minimize the credit risk in derivative instruments by entering into transactions with major financial institutions. Market risk is the adverse effect on the value of a financial instrument that results from a change in interest rates. We manage market risk associated with interest rate contracts by establishing and monitoring parameters that limit the type and degree of market risk that may be undertaken.

F-18

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

extent the swap is effective, are recognized in other comprehensive income until the hedged interest costs are recognized in earnings. On June 27, 2003, we repaid the amounts outstanding under the revolving credit facility with borrowings under a new three year revolving credit facility and canceled the old facility (see Note 11. Debt). We redesignated this interest rate swap as a hedge of our exposure to increases in the benchmark interest rate underlying the new variable rate revolving credit facility. During the years ended December 31, 2003, and 2002, we recognized increases in interest expense of $14.4 million and $12.9 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap.

During the year ended December 31, 2003, we determined that we would repay a portion of the amount outstanding under the revolving credit facility, established June 27, 2003, with proceeds from our Unit offering in August 2003 (see Note 12. Partners’ Capital and Distributions) resulting in a reduction of probable future interest payments under the credit facility. As a result, we measured and reclassified amounts previously accumulated in other comprehensive income related to the discontinued portion of the hedge and recognized a loss of $1.0 million, which has been included in interest expense. The total fair value of the interest rate swap was a loss of approximately $3.9 million and $20.1 million at December 31, 2003, and 2002, respectively. Losses recognized in other comprehensive income of approximately $2.9 million related to the portion of the interest rate swap hedging probable future interest payments will be transferred into earnings over the remaining term of the interest rate swap agreement. Changes in the fair value of the portion of the interest rate swap related to the discontinued hedge will be recorded in earnings over the remaining term of the interest rate swap.

On October 4, 2001, TE Products entered into an interest rate swap agreement to hedge its exposure to changes in the fair value of its fixed rate 7.51% Senior Notes due 2028. We designated this swap agreement as a fair value hedge. The swap agreement has a notional amount of $210.0 million and matures in January 2028 to match the principal and maturity of the TE Products Senior Notes. Under the swap agreement, TE Products pays a floating rate of interest based on a three-month U.S. Dollar LIBOR rate, plus a spread, and receives a fixed rate of interest of 7.51%. During the years ended December 31, 2003, and 2002, we recognized reductions in interest expense of $10.0 million and $8.6 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap. During the quarter ended December 31, 2003, we measured the hedge effectiveness of this interest rate swap and noted that no gain or loss from ineffectiveness was required to be recognized. The fair value of this interest rate swap was a gain of approximately $2.3 million and $13.6 million at December 31, 2003, and 2002, respectively.

F-19

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

NOTE 5. ASSET RETIREMENT OBLIGATIONS

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

The Downstream Segment assets consist primarily of an interstate trunk pipeline system and a series of storage facilities that originate along the upper Texas Gulf Coast and extend through the Midwest and northeastern United States. We transport refined products, LPGs and petrochemicals through the pipeline system. These products are primarily received in the south end of the system and stored and/or transported to various points along the system per customer nominations. The Upstream Segment’s operations include purchasing crude oil from producers at the wellhead and providing delivery, storage and other services to its customers. The properties in the Upstream Segment consist of interstate trunk pipelines, pump stations, trucking facilities, storage tanks and various gathering systems primarily in Texas and Oklahoma. The Midstream Segment gathers natural gas from wells owned by producers and transports natural gas and NGLs on its pipeline systems, primarily in Texas, Wyoming, New Mexico and Colorado. The Midstream Segment also owns and operates two NGL fractionator facilities in Colorado.

We have completed our assessment of SFAS 143, and we have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of our assets. However, we are not able to reasonably determine the fair value of the asset retirement obligations for our trunk, interstate and gathering pipelines and our surface facilities, since future dismantlement and removal dates are indeterminate.

In order to determine a removal date for our gathering lines and related surface assets, reserve information regarding the production life of the specific field is required. As a transporter and gatherer of crude oil and natural gas, we are not a producer of the field reserves, and we therefore do not have access to adequate forecasts that predict the timing of expected production for existing reserves on those fields in which we gather crude oil and natural gas. In the absence of such information, we are not able to make a reasonable estimate of when future dismantlement and removal dates of our gathering assets will occur. With regard to our trunk and interstate pipelines and their related surface assets, it is impossible to predict when demand for transportation of the related products will cease. Our right-of-way agreements allow us to maintain the right-of-way rather than remove the pipe. In addition, we can evaluate our trunk pipelines for alternative uses, which can be and have been found.

We will record such asset retirement obligations in the period in which more information becomes available for us to reasonably estimate the settlement dates of the retirement obligations. The adoption of SFAS 143 did not have an effect on our financial position, results of operations or cash flows.

NOTE 6. ACQUISITIONS AND DISPOSITIONS

Jonah Gas Gathering Company

F-20

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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. We accounted for the acquisition under the purchase method of accounting. 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 following table allocates the estimated fair value of Jonah assets acquired on September 30, 2001, and includes the additional purchase adjustment paid on February 4, 2002 (in thousands):


Property, plant and equipment		$	141,835
Intangible assets (primarily gas gathering contracts)			222,800
Goodwill			2,777
Other			147

	Total assets		367,559

Total liabilities assumed			(489	)

	Net assets acquired	$	367,070

Chaparral NGL System

On March 1, 2002, we completed the purchase of the Chaparral NGL system (“Chaparral”) for $132.4 million from Diamond-Koch II, L.P. and Diamond-Koch III, L.P., including acquisition related costs of approximately $0.4 million. The Chaparral NGL system extends from West Texas and New Mexico to Mont Belvieu. The pipeline delivers NGLs to fractionators and to our existing storage 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. 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.

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. 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

F-21

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

statements from June 30, 2002. Under a contractual agreement, DEFS manages and operates Val Verde on our behalf.

The following table allocates the estimated fair value of the Val Verde assets acquired on June 30, 2002 (in thousands):


Property, plant and equipment		$	205,146
Intangible assets (primarily gas gathering contracts)			239,649

	Total assets		444,795

Total liabilities assumed			(645	)

	Net assets acquired	$	444,150

The following table presents our unaudited pro forma results as though the acquisitions of Jonah and Val Verde occurred at the beginning of 2002 and 2001 (in thousands, except per Unit amounts). The unaudited pro forma results give effect to certain pro forma adjustments including depreciation and amortization expense adjustments of property, plant and equipment and intangible assets based upon the purchase price allocations, interest expense related to financing the acquisition, amortization expense of debt issue costs and the removal of income tax effects in historical results of operations. The pro forma results do not include operating efficiencies or revenue growth from historical results.


	Year Ended
	December 31,

	2002		2001

Revenues	$	3,279,948	$	3,659,496
Operating income		181,717		179,600
Net income		130,335		119,286
Basic and diluted net income per Unit	$	1.70	$	2.00

The summarized pro forma information has been prepared for comparative purposes only. It is not intended to be indicative of the actual operating results that would have occurred had the acquisitions been consummated at the beginning of 2002 or 2001, or the results which may be attained in the future.

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, Texas. 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.

F-22

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 (“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. 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.

The following table allocates the estimated fair value of the Genesis assets acquired on November 1, 2003 (in thousands):


Property, plant and equipment		$	13,053
Intangible assets			8,500
Other			144

	Total assets		21,697

Total liabilities assumed			(687	)

	Net assets acquired	$	21,010

NOTE 7. EQUITY INVESTMENTS

Through one of our indirect wholly owned subsidiaries, we own a 50% ownership interest in Seaway Crude Pipeline Company (“Seaway”). The remaining 50% interest is owned by ConocoPhillips. Seaway owns a pipeline that carries mostly imported crude oil from a marine terminal at Freeport, Texas, to Cushing, Oklahoma, and from a marine terminal at Texas City, Texas, to refineries in the Texas City and Houston, Texas, areas. The Seaway Crude Pipeline Company Partnership Agreement provides for varying participation ratios throughout the life of the Seaway partnership. From July 20, 2000, through May 2002, we received 80% of revenue and expense of Seaway. From June 2002 through May 2006, we receive 60% of revenue and expense of Seaway. Thereafter, the sharing ratio becomes 40% of revenue and expense to us. For the year ended December 31, 2002, our portion of equity earnings on a pro-rated basis averaged approximately 67%.

In August 2000, TE Products entered into agreements with Panhandle Eastern Pipeline Company (“PEPL”), a former subsidiary of CMS Energy Corporation, and Marathon Ashland Petroleum LLC (“Marathon”) to form Centennial Pipeline LLC (“Centennial”). Centennial owns an interstate refined petroleum products pipeline extending from the upper Texas Gulf Coast to central Illinois. Through February 9, 2003, each participant owned a one-third interest in Centennial. 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. During the year ended December 31, 2003, including the amount paid for the acquisition of the additional ownership interest, TE Products has invested $24.0 million in Centennial, which is included in the equity investment balance at December 31, 2003.

As of January 1, 2003, TE Products and Louis Dreyfus Energy Services, L.P. (“Louis Dreyfus”) formed Mont Belvieu Storage Partners, L.P. (“MB Storage”). TE Products and Louis Dreyfus each own a 50% ownership

F-23

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

interest in MB Storage. The purpose of MB Storage is to expand services to the upper Texas Gulf Coast energy marketplace by increasing pipeline throughput and the mix of products handled through the existing system and establishing new receipt and delivery connections. MB Storage is a service-oriented, fee-based venture with no commodity trading activity. TE Products continues to operate the facilities for MB Storage. Effective January 1, 2003, TE Products contributed property and equipment with a net book value of $67.4 million to MB Storage. Additionally, as of the contribution date, 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 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%. During the year ended December 21, 2003, excluding the contribution of property, plant and equipment, TE Products contributed $2.5 million to MB Storage. In December 2003, we received a distribution of $5.3 million from MB Storage.

We use the equity method of accounting to account for our investments in Seaway, Centennial and MB Storage. Summarized combined financial information for Seaway, Centennial and MB Storage for the year ended December 31, 2003, and for Seaway and Centennial for the year ended December 31, 2002, is presented below (in thousands):


	Years Ended
	December 31,

	2003		2002

Revenues	$	125,521	$	83,237
Net income		30,034		5,389

Summarized combined balance sheet data for Seaway, Centennial and MB Storage as of December 31, 2003, and for Seaway and Centennial as of December 31, 2002, is presented below (in thousands):


	December 31,

	2003		2002

Current assets	$	56,243	$	32,528
Noncurrent assets		609,215		551,324
Current liabilities		43,177		28,681
Long-term debt		140,000		140,000
Noncurrent liabilities		13,182		14,875
Partners’ capital		469,099		400,296

Our investments in Seaway and Centennial include excess net investment amounts of $25.5 million and $33.4 million, respectively. Excess investment is the amount by which our investment balance exceeds our proportionate share of the net assets of the investment. Prior to January 1, 2002, and the adoption of SFAS 142, we were amortizing the excess investment in Seaway using the straight-line method over 20 years.

F-24

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

NOTE 8. RELATED PARTY TRANSACTIONS

Duke Energy, DEFS and Affiliates

Lubrication Services, L.P. (“LSI”) 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.

Effective with the purchase of the fractionation facilities on March 31, 1998, TEPPCO Colorado, LLC (“TEPPCO Colorado”) and DEFS entered into a 20-year Fractionation Agreement, 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. TEPPCO Colorado and DEFS also entered into an Operation and Maintenance Agreement, whereby DEFS operates and maintains the fractionation facilities. 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.

Effective May 2001, we entered into an agreement with an affiliate of DEFS to commit sole utilization of our Providence terminal to an affiliate of DEFS. We operate the terminal and provide propane loading services to an affiliate of DEFS. 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.

F-25

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

On March 1, 2002, we completed the acquisition of the Chaparral NGL system (see Note 6. Acquisitions and Dispositions). The Chaparral assets are managed and operated by employees of DEFS under a contractual agreement under which DEFS is reimbursed for its actual costs. During the years ended December 31, 2003, and 2002, we recognized $2.1 million and $1.7 million, respectively, of expenses related to the operations and management of the Chaparral assets by DEFS. 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 Chaparral totaled $5.5 million and $4.5 million for the years ended December 31, 2003 and 2002, respectively.

On April 2, 2003, we sold in an underwritten public offering 3.9 million Units at $30.35 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $114.5 million, of which approximately $113.8 million was used to repurchase and retire all of the 3.9 million previously outstanding Class B Units held by DETTCO (see Note 12. Partners’ Capital and Distributions).

Seaway

On July 20, 2000, we acquired a 50% ownership interest in Seaway. ConocoPhillips owns the remaining 50% interest in Seaway. We are the operator of Seaway. During the years ended December 31, 2003, 2002 and 2001, we billed Seaway $7.2 million, $7.1 million and $7.0 million, respectively, for direct payroll and payroll related expenses for operating Seaway. Additionally, for each of the years ended December 31, 2003, 2002 and 2001, we billed Seaway $2.1 million for indirect management fees for operating Seaway. At December 31, 2003 and 2002, we had a payable balance to Seaway of $4.0 million and $1.1 million, respectively, for advances Seaway paid to us as operator for operating costs, including payroll and related expenses and management fees.

F-26

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Centennial

In August 2000, TE Products entered into agreements with PEPL and Marathon to form Centennial (see Note 7. Equity Investments). At December 31, 2003, TE Products had a 50% ownership interest in Centennial. TE Products has entered into a management agreement with Centennial to operate Centennial’s terminal at Creal Springs and pipeline connection in Beaumont, Texas. For each of the years ended December 31, 2003, and 2002, we recognized management fees of $0.2 million from Centennial, and actual operating expenses billed to Centennial were $4.4 million and $4.0 million, respectively.

TE Products also has a joint tariff with Centennial to deliver products at TE Products’ locations using Centennial’s pipeline as part of the delivery route to connecting carriers. TE Products, as the delivering pipeline, invoices the shippers for the entire delivery rate, records only the net rate attributable to it as transportation revenues and records a liability for the amounts due to Centennial for its share of the tariff. At December 31, 2003 and 2002, we had a payable balance of $2.3 million and $1.0 million, respectively, to Centennial for its share of the joint tariff deliveries. In addition, TE Products performs ongoing construction services for Centennial and bills Centennial for labor and other costs to perform the construction. At December 31, 2003 and 2002, TE Products had a receivable balance of $1.3 million and $1.9 million, respectively, due from Centennial for reimbursement of construction services provided to Centennial.

In January 2003, TE Products entered into a pipeline capacity lease agreement with Centennial for a period of five years that contains a minimum throughput requirement. For the year ended December 31, 2003, TE Products incurred $3.8 million of rental charges related to the lease of pipeline capacity on Centennial.

MB Storage

Effective January 1, 2003, TE Products entered into agreements with Louis Dreyfus to form MB Storage (see Note 7. Equity Investments). TE Products operates the facilities for MB Storage. TE Products and MB Storage have entered into a pipeline capacity lease agreement, and for the year ended December 31, 2003, TE Products recognized $0.1 million in rental revenue related to this lease agreement. TE Products also billed MB Storage $2.3 million for direct payroll and payroll related expenses for operating MB Storage during the year ended December 31, 2003. At December 31, 2003, TE Products had a payable balance to MB Storage of $0.2 million for advances MB Storage paid for operating costs, including payroll and related expenses.

NOTE 9. INVENTORIES

Inventories are valued at the lower of cost (based on weighted average cost method) or market. The costs of inventories did not exceed market values at December 31, 2003 and 2002. The major components of inventories were as follows (in thousands):


		December 31,

		2003		2002

Crude oil		$	1,303	$	—
Refined products			6,632		5,164
LPGs			517		1,991
Lubrication oils and specialty chemicals			3,080		3,836
Materials and supplies			4,528		4,113

	Total	$	16,060	$	15,104

F-27

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

NOTE 10. PROPERTY, PLANT AND EQUIPMENT

Major categories of property, plant and equipment were as follows (in thousands):


			December 31,

			2003		2002

Land and right of way			$	130,775	$	132,132
Line pipe and fittings				1,256,393		1,158,071
Storage tanks				135,938		147,650
Buildings and improvements				35,648		16,425
Machinery and equipment				292,949		370,046
Construction work in progress				112,817		102,246

	Total property, plant and equipment		$	1,964,520	$	1,926,570
	Less accumulated depreciation and amortization			345,357		338,746

		Net property, plant and equipment	$	1,619,163	$	1,587,824

Depreciation expense on property, plant and equipment was $64.5 million, $56.0 million and $39.5 million for the years ended December 31, 2003, 2002 and 2001, respectively.

NOTE 11. DEBT

Senior Notes

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

The TE Products Senior Notes do not have sinking fund requirements. Interest on the TE Products Senior Notes is payable semiannually in arrears on January 15 and July 15 of each year. The TE Products Senior Notes are unsecured obligations of TE Products and rank on a parity with all other unsecured and unsubordinated indebtedness of TE Products. The indenture governing the TE Products Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit our ability to incur additional indebtedness. As of December 31, 2003, TE Products was in compliance with the covenants of the TE Products Senior Notes.

On February 20, 2002, we completed the issuance of $500.0 million principal amount of 7.625% Senior Notes due 2012. The 7.625% Senior Notes were issued at a discount of $2.2 million and are being accreted to their face value over the term of the notes. We used the proceeds from the offering to reduce a portion of the outstanding balances of our credit facilities, including those issued in connection with the acquisition of Jonah. The Senior Notes may be redeemed at any time at our option with the payment of accrued interest and a make-whole premium determined by discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of comparable remaining maturity plus 35 basis points. The indenture governing our 7.625% Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit our ability to incur

F-28

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

additional indebtedness. As of December 31, 2003, we were in compliance with the covenants of these Senior Notes.

On January 30, 2003, we completed the issuance of $200.0 million principal amount of 6.125% Senior Notes due 2013. The 6.125% Senior Notes were issued at a discount of $1.4 million and are being accreted to their face value over the term of the notes. We used $182.0 million of the proceeds from the offering to reduce the outstanding principal on our $500.0 million revolving credit facility to $250.0 million. The balance of the net proceeds received was used for general partnership purposes. The Senior Notes may be redeemed at any time at our option with the payment of accrued interest and a make-whole premium determined by discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of comparable remaining maturity plus 35 basis points. The indenture governing our 6.125% Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit our ability to incur additional indebtedness. As of December 31, 2003, we were in compliance with the covenants of these Senior Notes.

The following table summarizes the estimated fair values of the Senior Notes as of December 31, 2003 and 2002 (in millions):


			December 31,
	Face
	Value		2003		2002

6.45% TE Products Senior Notes, due January 2008	$	180.0	$	204.8	$	184.6
7.625% Senior Notes, due February 2012		500.0		578.2		529.1
6.125% Senior Notes, due February 2013		200.0		206.7		—
7.51% TE Products Senior Notes, due January 2028		210.0		228.0		201.2

We have entered into interest rate swap agreements to hedge our exposure to changes in the fair value on a portion of the Senior Notes discussed above. See Note 4. Interest Rate Swaps.

Other Long Term Debt and Credit Facilities

F-29

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

We have entered into an interest rate swap agreement to hedge our exposure to increases in interest rates on a portion of the credit facilities discussed above. See Note 4. Interest Rate Swaps.

Short Term Credit Facilities

On June 27, 2002, we entered into a $200.0 million six-month term loan with SunTrust Bank (“Six-Month Term Loan”) payable in December 2002. We borrowed $200.0 million under the Six-Month Term Loan to acquire the Val Verde assets (see Note 6. Acquisitions and Dispositions). The interest rate was based, at our option, on either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement contained certain restrictive financial covenant ratios. On July 11, 2002, we repaid $90.0 million of the outstanding principal from proceeds primarily received from the issuance of Units in July 2002. On September 10, 2002, we repaid the remaining outstanding balance of $110.0 million with proceeds received from the issuance of Units in September 2002, and canceled the facility.

The following table summarizes the principal amounts outstanding under our credit facilities as of December 31, 2003 and 2002 (in thousands):


			December 31,

			2003		2002

Credit Facilities:
	Three Year Facility, due April 2004		$	—	$	432,000
	Revolving Credit Facility, due June 2006			210,000		—
	6.45% TE Products Senior Notes, due January 2008			179,876		179,845
	7.625% Senior Notes, due February 2012			498,216		497,995
	6.125% Senior Notes, due February 2013			198,702		—
	7.51% TE Products Senior Notes, due January 2028			210,000		210,000

		Total borrowings		1,296,794		1,319,840
	Adjustment to carrying value associated with hedges of fair value			42,856		57,852

		Total Credit Facilities	$	1,339,650	$	1,377,692

F-30

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

NOTE 12. PARTNERS’ CAPITAL AND DISTRIBUTIONS

Equity Offerings

On March 22, 2002, we sold in an underwritten public offering 1.92 million Units at $31.18 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $57.3 million and were used to repay $50.0 million of the outstanding balance on the Three Year Facility, with the remaining amount being used for general partnership purposes.

Quarterly Distributions of Available Cash

F-31

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


					General
		Unitholders			Partner

Quarterly Cash Distribution per Unit:
	Up to Minimum Quarterly Distribution ($0.275 per Unit)		98	%		2	%
	First Target - $0.276 per Unit up to $0.325 per Unit		85	%		15	%
	Second Target - $0.326 per Unit up to $0.45 per Unit		75	%		25	%
	Over Second Target - Cash distributions greater than $0.45 per Unit		50	%		50	%

The following table reflects the allocation of total distributions paid during the years ended December 31, 2003, 2002 and 2001 (in thousands, except per Unit amounts):


		Years Ended December 31,

		2003		2002		2001

Limited Partner Units		$	145,427	$	104,932	$	73,961
General Partner Ownership Interest			3,016		2,329		1,273
General Partner Incentive			51,709		35,389		20,257

	Total Partners’ Capital Cash Distributions		200,152		142,650		95,491
Class B Units			2,346		9,203		8,421
Minority Interest			—		—		500

	Total Cash Distributions Paid	$	202,498	$	151,853	$	104,412

Total Cash Distributions Paid Per Unit		$	2.50	$	2.35	$	2.15

On February 6, 2004, we paid a cash distribution of $0.65 per Unit for the quarter ended December 31, 2003. The fourth quarter 2003 cash distribution totaled $57.1 million.

General Partner Interest

F-32

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

NOTE 13. CONCENTRATIONS OF CREDIT RISK

Our primary market areas are located in the Northeast, Midwest and Southwest regions of the United States. We have a concentration of trade receivable balances due from major integrated oil companies, independent oil companies and other pipelines and wholesalers. These concentrations of customers may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors. We thoroughly analyze our customers’ historical and future credit positions prior to extending credit. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions may utilize letters of credit, prepayments and guarantees.

For the years ended December 31, 2003, 2002 and 2001, we had one customer from the Upstream Segment, Valero Energy Corp., which accounted for 16%, 16% and 14%, respectively, of our total consolidated revenues. No other single customer accounted for 10% or more of our total consolidated revenues for the years ended December 31, 2003, 2002 and 2001.

The carrying amount of cash and cash equivalents, accounts receivable, inventories, other current assets, accounts payable and accrued liabilities and other current liabilities approximates their fair value due to their short-term nature.

NOTE 14. UNIT-BASED COMPENSATION

1994 Long Term Incentive Plan

During 1994, the Company adopted the Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan (“1994 LTIP”). The 1994 LTIP provides certain key employees with an incentive award whereby a participant is granted an option to purchase Units. These same employees are also granted a stipulated number of Performance Units, the cash value of which may be used to pay for the exercise of the respective Unit options awarded. Under the provisions of the 1994 LTIP, no more than one million options and two million Performance Units may be granted.

When our calendar year earnings per unit (exclusive of certain special items) exceeds a stated threshold, each participant receives a credit to their respective Performance Unit account equal to the earnings per unit excess multiplied by the number of Performance Units awarded. The balance in the Performance Unit account may be used to offset the cost of exercising Unit options granted in connection with the Performance Units or may be withdrawn two years after the underlying options expire, usually 10 years from the date of grant. Any unused balance previously credited is forfeited upon termination. We accrue compensation expense for the Performance Units awarded annually based upon the terms of the plan discussed above.

Under the agreement for such Unit options, the options become exercisable in equal installments over periods of one, two, and three years from the date of the grant. At December 31, 2003, 42,000 Performance Units granted in 1995 with an earnings threshold of $1.25 remain outstanding. The Performance Units expire in 2005.

F-33

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

A summary of Unit options granted under the terms of the 1994 LTIP is presented below:


			Options			Options			Exercise
			Outstanding			Exercisable			Range

Unit Options:
	Outstanding at December 31, 2000			290,864			160,529		$	13.81-$25.69
		Forfeited		(2,800	)		—		$	25.25
		Became exercisable		—			81,669		$	25.25-$25.69
		Exercised		(98,376	)		(98,376	)	$	13.81-$25.69

	Outstanding at December 31, 2001			189,688			143,822		$	13.81-$25.69
		Became exercisable		—			45,866		$	25.25
		Exercised		(99,597	)		(99,597	)	$	13.81-$25.69

	Outstanding at December 31, 2002			90,091			90,091		$	13.81-$25.69
		Exercised		(90,091	)		(90,091	)	$	13.81-$25.69

	Outstanding at December 31, 2003			—			—

We have not granted options for any periods presented. During the year ended December 31, 2003, all remaining outstanding Unit options were exercised. For options previously outstanding, we followed the intrinsic value method for recognizing stock-based compensation expense. The exercise price of all options awarded under the 1994 LTIP equaled the market price of our Units on the date of grant. Accordingly, we recognized no compensation expense at the date of grant. Had compensation expense been determined consistent with SFAS No. 123, Accounting for Stock-Based Compensation, compensation expense related to option grants would have been immaterial for the years ended December 31, 2002 and 2001, and no compensation expense would have been recognized for the year ended December 31, 2003.

1999 and 2002 Phantom Unit Plans

Effective September 1, 1999, the Company adopted the Texas Eastern Products Pipeline Company, LLC 1999 Phantom Unit Retention Plan (“1999 PURP”). Effective June 1, 2002 the Company adopted the Texas Eastern Products Pipeline Company, LLC 2002 Phantom Unit Retention Plan (“2002 PURP”). The 1999 PURP and the 2002 PURP provide key employees with incentive awards whereby a participant is granted phantom units. These phantom units are automatically redeemed for cash based on the vested portion of the fair market value of the phantom units at stated redemption dates. The fair market value of each phantom unit is equal to the closing price of a Unit as reported on the New York Stock Exchange on the redemption date.

Under the agreement for the phantom units, each participant will vest 10% of the number of phantom units initially granted under his or her award at the end of each of the first four years and will vest the final 60% at the end of the fifth year. Each participant is required to redeem their units as they vest. They are also entitled to quarterly cash distributions equal to the product of the number of phantom units outstanding for the participant and the amount of the cash distribution that we paid per Unit to unitholders. A total of 26,040 phantom units granted under the 1999 PURP remain outstanding at December 31, 2003. A total of 67,230 phantom units granted under the 2002 PURP remain outstanding at December 31, 2003. We accrue compensation expense annually based upon the terms of the 1999 PURP and 2002 PURP discussed above. At December 31, 2003 and 2002, we had an accrued liability balance of $2.1 million and $1.0 million, respectively, for compensation related to the 1999 PURP and 2002 PURP.

2000 Long Term Incentive Plan

F-34

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

in our financial performance. Generally, upon the close of a three-year performance period, if the participant is then still an employee of the General Partner, the participant will receive a cash payment in an amount equal to (1) the applicable performance percentage specified in the award multiplied by (2) the number of phantom Units granted under the award multiplied by (3) the average of the closing prices of a Unit over the ten consecutive trading days immediately preceding the last day of the performance period. Generally, a participant’s performance percentage is based upon the improvement of our Economic Value Added during a three-year performance period over the Economic Value Added during the three-year period immediately preceding the performance period. If a participant incurs a separation from service during the performance period due to death, disability or retirement (as such terms are defined in the 2000 LTIP), the participant will be entitled to receive a cash payment in an amount equal to the amount computed as described above multiplied by a fraction, the numerator of which is the number of days that have elapsed during the performance period prior to the participant’s separation from service and the denominator of which is the number of days in the performance period. At December 31, 2003, phantom Units outstanding were 31,800, 22,300 and 24,013 for awards granted for the years ended December 31, 2003, 2002 and 2001, respectively.

In addition to the payment described above, during the performance period, the General Partner will pay to the participant the amount of cash distributions that we would have paid to our unitholders had the participant been the owner of the number of Units equal to the number of phantom Units granted to the participant under this award. We accrue compensation expense annually based upon the terms of the 2000 LTIP discussed above. At December 31, 2003 and 2002, we had an accrued liability balance of $2.9 million and $1.8 million, respectively, for compensation related to the 2000 LTIP.

NOTE 15. OPERATING LEASES

We use leased assets in several areas of our operations. Total rental expense for the years ended December 31, 2003, 2002 and 2001 was $21.9 million, $14.2 million and $10.8 million, respectively. The following table sets forth our minimum rental payments under our various operating leases for the years ending December 31 (in thousands):


2004	$	16,444
2005		15,307
2006		12,620
2007		9,556
2008		5,771
Thereafter		11,891

	$	71,589

F-35

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

NOTE 16. EMPLOYEE BENEFITS

Retirement Plans

We have adopted the TEPPCO Retirement Cash Balance Plan (“TEPPCO RCBP”), which is a noncontributory, trustee-administered pension plan. In addition, certain executive officers participate in the TEPPCO Supplemental Benefit Plan (“TEPPCO SBP”), which is a noncontributory, nonqualified, defined benefit retirement plan. The TEPPCO SBP was established to restore benefit reductions caused by the maximum benefit limitations that apply to qualified plans. The benefit formula for all eligible employees is a cash balance formula. Under a cash balance formula, a plan participant accumulates a retirement benefit based upon pay credits and current interest credits. The pay credits are based on a participant’s salary, age and service. We use a December 31 measurement date for these plans.

The components of net pension benefits costs for the TEPPCO RCBP and the TEPPCO SBP for the years ended December 31, 2003, 2002 and 2001, were as follows (in thousands):


		2003			2002			2001

Service cost benefit earned during the year		$	3,179		$	2,925		$	2,419
Interest cost on projected benefit obligation			504			315			129
Expected return on plan assets			(604	)		(390	)		(166	)
Amortization of prior service cost			7			7			8
Recognized net actuarial loss			24			12			—

	Net pension benefits costs	$	3,110		$	2,869		$	2,390

Other Postretirement Benefits

Effective January 1, 2001, we provide employees with certain health care and life insurance benefits for retired employees on a contributory and non-contributory basis (“TEPPCO OPB”). Employees become eligible for these benefits if they meet certain age and service requirements at retirement, as defined in the plans. We provide a fixed dollar contribution, which does not increase from year to year, towards retired employee medical costs. The retiree pays all health care cost increases due to medical inflation. We use a December 31 measurement date for this plan.

The components of net postretirement benefits cost for the TEPPCO OPB for the years ended December 31, 2003, 2002 and 2001, were as follows (in thousands):


		2003		2002		2001

Service cost benefit earned during the year		$	137	$	115	$	99
Interest cost on accumulated postretirement benefit obligation			137		119		113
Amortization of prior service cost			126		126		126

	Net postretirement benefits costs	$	400	$	360	$	338

We employ a building block approach in determining the long-term rate of return for plan assets. Historical markets are studied and long-term historical relationships between equities and fixed-income are preserved consistent with a widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current market factors such as inflation and interest rates are evaluated before long-term capital market assumptions are determined. The long-term portfolio return is established via a building block approach with proper consideration of diversification and rebalancing. Peer data and historical returns are reviewed to check for reasonability and appropriateness.

F-36

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The weighted average assumptions used to determine benefit obligations for the retirement plans and other postretirement benefit plans at December 31, 2003 and 2002, were as follows:


							Other Postretirement
	Pension Benefits						Benefits

	2003			2002			2003			2002

Discount rate		6.25	%		6.75	%		6.25	%		6.75	%
Increase in compensation levels		5.00	%		5.00	%		—			—
Expected long-term rate of return on plan assets		8.00	%		9.00	%		—			—

The weighted average assumptions used to determine net periodic benefit cost for the retirement plans and other postretirement benefit plans for the years ended December 31, 2003 and 2002, were as follows:


							Other Postretirement
	Pension Benefits						Benefits

	2003			2002			2003			2002

Discount rate		6.75	%		7.25	%		6.75	%		7.25	%
Increase in compensation levels		5.00	%		5.00	%		—			—
Expected long-term rate of return on plan assets		9.00	%		9.00	%		—			—

The following table sets forth our pension and other postretirement benefits changes in benefit obligation, fair value of plan assets and funded status as of December 31, 2003 and 2002 (in thousands):


								Other Postretirement
		Pension Benefits						Benefits

		2003			2002			2003			2002

Change in benefit obligation
	Benefit obligation at beginning of year	$	7,578		$	3,786		$	2,001		$	1,781
	Service cost		3,179			2,925			137			115
	Interest cost		504			315			137			118
	Actuarial (gain)/loss		236			711			209			1
	Retiree contributions		—			—			54			29
	Benefits paid		(241	)		(159	)		(71	)		(43	)

	Benefit obligation at end of year	$	11,256		$	7,578		$	2,467		$	2,001

Change in plan assets
	Fair value of plan assets at beginning of year	$	6,820		$	3,959		$	—		$	—
	Actual return on plan assets		650			(99	)		—			—
	Retiree contributions		—			—			54			29
	Employer contributions		3,692			3,119			17			14
	Benefits paid		(241	)		(159	)		(71	)		(43	)

	Fair value of plan assets at end of year	$	10,921		$	6,820		$	—		$	—

Reconciliation of funded status
	Funded status	$	(335	)	$	(758	)	$	(2,467	)	$	(2,001	)
	Unrecognized prior service cost		40			47			1,129			1,255
	Unrecognized actuarial loss		1,421			1,255			267			58

	Net amount recognized	$	1,126		$	544		$	(1,071	)	$	(688	)

F-37

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Plan Assets

We employ a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed-income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks, both growth and value equity style, and small, mid and large capitalizations. Investment risk and return parameters are reviewed and evaluated periodically to ensure compliance with stated investment objectives and guidelines. This comprehensive review incorporates investment portfolio performance, annual liability measurements and periodic asset/liability studies.

The following table sets forth the weighted average asset allocations for the retirement plans and other postretirement benefit plans as of December 31, 2003 and 2002, by asset category (in thousands):


		December 31,

Asset Category		2003			2002

Equity securities			47	%		21	%
Debt securities			30	%		56	%
Other (money market and cash)			23	%		23	%

	Total		100	%		100	%

We expect to contribute approximately $3.0 million to our retirement plans and other postretirement benefit plans in 2004.

Other Plans

DEFS also sponsors an employee savings plan, which covers substantially all employees. Plan contributions on behalf of the Company of $3.2 million, $2.8 million and $3.1 million were recognized during the years ended December 31, 2003, 2002 and 2001, respectively.

NOTE 17. COMMITMENTS AND CONTINGENCIES

F-38

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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.

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 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.

F-39

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 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. Nortan 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.

F-40

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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.

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.

Substantially all of the petroleum products that we transport and store are owned by our customers. At December 31, 2003, TCTM and TE Products had approximately 3.2 million barrels and 17.3 million barrels, respectively, of products in their custody that was owned by customers. We are obligated for the transportation, storage and delivery of such products on behalf of our customers. We maintain insurance adequate to cover product losses through circumstances beyond our control.

We carry insurance coverage consistent with companies engaged in similar operations with similar type properties. Our insurance coverage includes (1) commercial general public liability insurance for liabilities to third parties for bodily injury and property damage resulting from our operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage, and (4) property insurance covering the replacement value of all real and personal property damage, including damages arising from earthquake, flood damage and business interruption/extra expense. For select assets, we also carry pollution liability insurance that provides coverage for historical and gradual pollution events. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operations.

We also maintain excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Limits, terms, conditions and deductibles are comparable to those carried by other energy companies of similar size. The cost of our general insurance coverages continued to fluctuate over the past year reflecting the changing conditions of the insurance markets. These insurance policies, except for the pollution liability policies, are with Bison Insurance Company Limited, an insurance company that is wholly owned by Duke Energy (see Note 8. Related Parties).

F-41

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

NOTE 18. SEGMENT INFORMATION

We have three reporting segments: transportation and storage of refined products, LPGs and petrochemicals, which operates as the Downstream Segment; gathering, transportation, marketing and storage of crude oil and distribution of lubrication oils and specialty chemicals, which operates as the Upstream Segment; and gathering of natural gas, fractionation of NGLs and transportation of NGLs, which operates as the Midstream Segment. The amounts indicated below as “Partnership and Other” relate primarily to intersegment eliminations and assets that we hold that have not been allocated to any of our reporting segments.

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 refinery grade propylene (“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 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 Chaparral and Val Verde acquisitions are included in periods subsequent to their respective acquisition dates (see Note 6. Acquisitions and Dispositions).

F-42

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The tables below include financial information by reporting segment for the years ended December 31, 2003, 2002 and 2001 (in thousands):


		Year Ended December 31, 2003

		Downstream			Upstream			Midstream		Segments			Partnership
		Segment			Segment			Segment		Total			and Other			Consolidated

Revenues		$	266,427		$	3,806,215		$	185,105	$	4,257,747		$	(1,915	)	$	4,255,832
Purchases of petroleum products			—			3,713,122			—		3,713,122			(1,915	)		3,711,207
Operating expenses, including power			151,103			57,314			47,020		255,437			—			255,437
Depreciation and amortization expense			31,620			11,311			57,797		100,728			—			100,728
Gain on sale of assets			—			(3,948	)		—		(3,948	)		—			(3,948	)

	Operating income		83,704			28,416			80,288		192,408			—			192,408
Equity earnings (losses)			(4,086	)		20,949			—		16,863			—			16,863
Other income, net			226			306			289		821			(73	)		748

	Earnings before interest	$	79,844		$	49,671		$	80,577	$	210,092		$	(73	)	$	210,019


		Year Ended December 31, 2002

		Downstream			Upstream		Midstream		Segments		Partnership
		Segment			Segment		Segment		Total		and Other			Consolidated

Revenues		$	243,538		$	2,861,700	$	138,922	$	3,244,160	$	(1,997	)	$	3,242,163
Purchases of petroleum products			—			2,774,325		—		2,774,325		(1,997	)		2,772,328
Operating expenses, including power			130,324			49,781		33,451		213,556		—			213,556
Depreciation and amortization expense			30,116			11,186		44,730		86,032		—			86,032

	Operating income		83,098			26,408		60,741		170,247		—			170,247
Equity earnings (losses)			(6,815	)		18,795		—		11,980		—			11,980
Other income, net			832			1,532		269		2,633		(806	)		1,827

	Earnings before interest	$	77,115		$	46,735	$	61,010	$	184,860	$	(806	)	$	184,054


		Year Ended December 31, 2001

		Downstream			Upstream		Midstream		Segments		Partnership
		Segment			Segment		Segment		Total		and Other			Consolidated

Revenues		$	264,233		$	3,255,260	$	37,242	$	3,556,735	$	(322	)	$	3,556,413
Purchases of petroleum products			—			3,173,127		—		3,173,127		(322	)		3,172,805
Operating expenses, including power			119,858			54,578		11,482		185,918		—			185,918
Depreciation and amortization expense			26,699			9,263		9,937		45,899		—			45,899

	Operating income		117,676			18,292		15,823		151,791		—			151,791
Equity earnings (losses)			(1,149	)		18,547		—		17,398		—			17,398
Other income, net			1,537			1,188		74		2,799		—			2,799

	Earnings before interest	$	118,064		$	38,027	$	15,897	$	171,988	$	—		$	171,988

F-43

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table provides the total assets, capital expenditures and significant non-cash investing activities for each segment as of and for the years ended December 31, 2003, 2002 and 2001 (in thousands):


		Downstream		Upstream		Midstream		Segments		Partnership
		Segment		Segment		Segment		Total		and Other			Consolidated

December 31, 2003:
	Total assets	$	916,917	$	834,502	$	1,194,844	$	2,946,263	$	(5,271	)	$	2,940,992
	Capital expenditures		59,061		13,427		67,882		140,370		147			140,517
	Non-cash investing activities		61,408		—		—		61,408		—			61,408
December 31, 2002:
	Total assets	$	881,101	$	724,860	$	1,174,139	$	2,780,100	$	(11,678	)	$	2,768,422
	Capital expenditures		60,900		10,212		62,260		133,372		—			133,372
December 31, 2001:
	Total assets	$	844,036	$	694,934	$	541,195	$	2,080,165	$	(14,817	)	$	2,065,348
	Capital expenditures		81,410		13,987		12,217		107,614		—			107,614

The following table reconciles the segments total earnings before interest to consolidated net income for the three years ended December 31, 2003, 2003 and 2001 (in thousands):


		Years Ended December 31,

		2003			2002			2001

Earnings before interest		$	210,019		$	184,054		$	171,988
Interest expense – net			(84,250	)		(66,192	)		(62,057	)
Minority interest			—			—			(800	)

	Net income	$	125,769		$	117,862		$	109,131

NOTE 19. COMPREHENSIVE INCOME

SFAS No. 130, Reporting Comprehensive Income requires certain items such as foreign currency translation adjustments, minimum pension liability adjustments and unrealized gains and losses on certain investments to be reported in a financial statement. As of and for the years ended December 31, 2003, 2002 and 2001, the components of comprehensive income were due to the interest rate swap related to our variable rate revolving credit facility, which is designated as a cash flow hedge. Changes in the fair value of the cash flow hedge, to the extent the hedge is effective, are recognized in other comprehensive income until the hedge interest costs are recognized in earnings. The table below reconciles reported net income to total comprehensive income for the years ended December 31, 2003, 2002 and 2001 (in thousands).


		Years Ended December 31,

		2003		2002		2001

Net income		$	125,769	$	117,862	$	109,131
Cumulative effect attributable to adoption of SFAS 133			—		—		(10,103	)
Net income (loss) on cash flow hedge			16,164		269		(10,221	)

	Total comprehensive income	$	141,933	$	118,131	$	88,807

F-44

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The accumulated balance of other comprehensive loss related to our cash flow hedge is as follows (in thousands):


Balance at December 31, 2000		$	—
	Cumulative effect of accounting change		(10,103	)
	Transferred to earnings		6,790
	Change in fair value of cash flow hedge		(17,011	)

Balance at December 31, 2001		$	(20,324	)
	Transferred to earnings		12,883
	Change in fair value of cash flow hedge		(12,614	)

Balance at December 31, 2002		$	(20,055	)
	Reclassification due to discontinued portion of cash flow hedge		989
	Transferred to earnings		14,417
	Change in fair value of cash flow hedge		1,747

Balance at December 31, 2003		$	(2,902	)

NOTE 20. SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Our significant operating subsidiaries, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Jonah Gas Gathering Company and Val Verde Gas Gathering Company, L.P., have issued unconditional guarantees of our debt securities. The guarantees are full, unconditional, and joint and several. TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Jonah Gas Gathering Company and Val Verde Gas Gathering Company, L.P. are collectively referred to as the “Guarantor Subsidiaries.”

The following supplemental condensed consolidating financial information reflects our separate accounts, the combined accounts of the Guarantor Subsidiaries, the combined accounts of our other non-guarantor subsidiaries, the combined consolidating adjustments and eliminations and our consolidated accounts for the dates and periods indicated. For purposes of the following consolidating information, our investments in our subsidiaries and the Guarantor Subsidiaries’ investments in their subsidiaries are accounted for under the equity method of accounting.

F-45

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


			December 31, 2003

												TEPPCO
			TEPPCO		Guarantor		Non-Guarantor		Consolidating			Partners, L.P.
			Partners, L.P.		Subsidiaries		Subsidiaries		Adjustments			Consolidated

			(in thousands)
Assets
	Current assets		$	38,281	$	92,817	$	360,564	$	(38,844	)	$	452,818
	Property, plant and equipment – net			—		1,146,455		472,708		—			1,619,163
	Equity investments			1,112,252		404,886		209,438		(1,361,290	)		365,286
	Intercompany notes receivable			943,447		—		—		(943,447	)		—
	Intangible assets			—		401,404		37,161		—			438,565
	Other assets			6,157		21,444		37,559		—			65,160

		Total assets	$	2,100,137	$	2,067,006	$	1,117,430	$	(2,343,581	)	$	2,940,992

Liabilities and partners’ capital
	Current liabilities		$	41,895	$	105,285	$	367,260	$	(38,849	)	$	475,591
	Long-term debt			947,486		392,164		—		—			1,339,650
	Intercompany notes payable			—		557,842		385,604		(943,446	)		—
	Other long term liabilities			1,435		14,995		—		—			16,430
	Total partners’ capital			1,109,321		996,720		364,566		(1,361,286	)		1,109,321

		Total liabilities and partners’ capital	$	2,100,137	$	2,067,006	$	1,117,430	$	(2,343,581	)	$	2,940,992


			December 31, 2002

												TEPPCO
			TEPPCO		Guarantor		Non-Guarantor		Consolidating			Partners, L.P.
			Partners, L.P.		Subsidiaries		Subsidiaries		Adjustments			Consolidated

			(in thousands)
Assets
	Current assets		$	241	$	90,578	$	286,379	$	(18,851	)	$	358,347
	Property, plant and equipment – net			—		1,128,803		459,021		—			1,587,824
	Equity investments			1,011,935		846,991		211,229		(1,785,450	)		284,705
	Intercompany notes receivable			986,852		—		—		(986,852	)		—
	Intangible assets			—		434,941		30,433		—			465,374
	Other assets			6,200		31,135		34,837		—			72,172

		Total assets	$	2,005,228	$	2,532,448	$	1,021,899	$	(2,791,153	)	$	2,768,422

Liabilities and partners’ capital
	Current liabilities		$	30,715	$	120,949	$	272,538	$	(59,639	)	$	364,563
	Long-term debt			974,264		403,428		—		—			1,377,692
	Intercompany notes payable			—		508,652		437,411		(946,063	)		—
	Other long term liabilities			6,523		24,230		209		—			30,962
	Redeemable Class B Units held by related party			103,363		—		—		—			103,363
	Total partners’ capital			890,363		1,475,189		311,741		(1,785,451	)		891,842

		Total liabilities and partners’ capital	$	2,005,228	$	2,532,448	$	1,021,899	$	(2,791,153	)	$	2,768,422

F-46

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


		Year Ended December 31, 2003

														TEPPCO
		TEPPCO			Guarantor			Non-Guarantor			Consolidating			Partners, L.P.
		Partners, L.P.			Subsidiaries			Subsidiaries			Adjustments			Consolidated

		(in thousands)
Operating revenues		$	—		$	399,504		$	3,858,243		$	(1,915	)	$	4,255,832
Costs and expenses			—			262,971			3,806,316			(1,915	)		4,067,372
Gain on sale of assets			—			—			(3,948	)		—			(3,948	)

	Operating income		—			136,533			55,875			—			192,408

Interest expense – net			(36,416	)		(52,903	)		(31,420	)		36,489			(84,250	)
Equity earnings			125,769			41,678			20,949			(171,533	)		16,863
Other income – net			36,416			461			360			(36,489	)		748

	Net income	$	125,769		$	125,769		$	45,764		$	(171,533	)	$	125,769


		Year Ended December 31, 2002

														TEPPCO
		TEPPCO			Guarantor			Non-Guarantor			Consolidating			Partners, L.P.
		Partners, L.P.			Subsidiaries			Subsidiaries			Adjustments			Consolidated

		(in thousands)
Operating revenues		$	—		$	336,045		$	2,908,115		$	(1,997	)	$	3,242,163
Costs and expenses			—			216,552			2,857,361			(1,997	)		3,071,916

	Operating income		—			119,493			50,754			—			170,247

Interest expense – net			(51,947	)		(40,651	)		(26,347	)		52,753			(66,192	)
Equity earnings			117,862			38,053			18,795			(162,730	)		11,980
Other income – net			51,947			967			1,666			(52,753	)		1,827

	Net income	$	117,862		$	117,862		$	44,868		$	(162,730	)	$	117,862


		Year Ended December 31, 2001

														TEPPCO
		TEPPCO			Guarantor			Non-Guarantor			Consolidating			Partners, L.P.
		Partners, L.P.			Subsidiaries			Subsidiaries			Adjustments			Consolidated

		(in thousands)
Operating revenues		$	—		$	273,379		$	3,283,356		$	(322	)	$	3,556,413
Costs and expenses			—			152,558			3,252,386			(322	)		3,404,622

	Operating income		—			120,821			30,970			—			151,791

Interest expense – net			(40,143	)		(30,605	)		(31,452	)		40,143			(62,057	)
Equity earnings			109,131			18,178			18,547			(128,458	)		17,398
Other income – net			40,143			1,537			1,262			(40,143	)		2,799

	Income before minority interest		109,131			109,931			19,327			(128,458	)		109,931
Minority interest			—			—			—			(800	)		(800	)

	Net income	$	109,131		$	109,931		$	19,327		$	(129,258	)	$	109,131

F-47

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


				Year Ended December 31, 2003

																TEPPCO
				TEPPCO			Guarantor			Non-Guarantor			Consolidating			Partners, L .P.
				Partners, L .P.			Subsidiaries			Subsidiaries			Adjustments			Consolidated

				(in thousands)
Cash flows from operating activities
	Net income			$	125,769		$	125,769		$	45,764		$	(171,533	)	$	125,769
		Adjustments to reconcile net income to net cash provided by operating activities:
			Depreciation and amortization		—			80,114			20,614			—			100,728
			Earnings in equity investments, net of distributions		76,729			3,559			1,791			(70,939	)		11,140
			Changes in assets and liabilities and other		48,432			5,576			(5,943	)		(46,348	)		1,717

Net cash provided by operating activities					250,930			215,018			62,226			(288,820	)		239,354

Cash flows from investing activities					(175,568	)		(178,682	)		(34,519	)		203,531			(185,238	)
Cash flows from financing activities					(55,618	)		(25,340	)		(44,758	)		70,101			(55,615	)

Net increase (decrease) in cash and cash equivalents					19,744			10,996			(17,051	)		(15,188	)		(1,499	)
Cash and cash equivalents at beginning of period					—			8,247			22,721			—			30,968

Cash and cash equivalents at end of period				$	19,744		$	19,243		$	5,670		$	(15,188	)	$	29,469


			Year Ended December 31, 2002

															TEPPCO
			TEPPCO			Guarantor			Non-Guarantor			Consolidating			Partners, L .P.
			Partners, L .P.			Subsidiaries			Subsidiaries			Adjustments			Consolidated

			(in thousands)
Cash flows from operating activities
	Net income		$	117,862		$	117,862		$	44,868		$	(162,730	)	$	117,862
	Adjustments to reconcile net income to net cash provided by (used in) operating activities:
		Depreciation and amortization		—			66,175			19,857			—			86,032
		Earnings in equity investments, net of distributions		33,994			18,879			11,586			(46,058	)		18,401
		Changes in assets and liabilities and other		(269,102	)		48,638			40,254			192,832			12,622

Net cash provided by (used in) operating activities				(117,246	)		251,554			116,565			(15,956	)		234,917

Cash flows from investing activities				(378,039	)		(1,150,967	)		(253,879	)		1,058,170			(724,715	)
Cash flows from financing activities				495,285			904,006			138,210			(1,042,214	)		495,287

Net increase in cash and cash equivalents				—			4,593			896			—			5,489
Cash and cash equivalents at beginning of period				—			3,654			21,825			—			25,479

Cash and cash equivalents at end of period			$	—		$	8,247		$	22,721		$	—		$	30,968

F-48

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


			Year Ended December 31, 2001

															TEPPCO
			TEPPCO			Guarantor			Non-Guarantor			Consolidating			Partners, L .P.
			Partners, L .P.			Subsidiaries			Subsidiaries			Adjustments			Consolidated

			(in thousands)
Cash flows from operating activities
	Net income		$	109,131		$	109,931		$	19,327		$	(129,258	)	$	109,131
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization		—			31,226			14,673			—			45,899
		Earnings in equity investments, net of distributions		(5,219	)		10,131			13,417			(3,952	)		14,377
		Changes in assets and liabilities and other		2,874			16,850			(20,783	)		800			(259	)

Net cash provided by operating activities				106,786			168,138			26,634			(132,410	)		169,148

Cash flows from investing activities				(498,711	)		(514,178	)		(43,687	)		498,711			(557,865	)
Cash flows from financing activities				391,925			340,529			20,947			(366,301	)		387,100

Net increase (decrease) in cash and cash equivalents				—			(5,511	)		3,894			—			(1,617	)
Cash and cash equivalents at beginning of period				—			9,166			17,930			—			27,096

Cash and cash equivalents at end of period			$	—		$	3,655		$	21,824		$	—		$	25,479

NOTE 21. QUARTERLY FINANCIAL INFORMATION (UNAUDITED) (1)


	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter

	(in thousands, except per Unit amounts)
2003
Operating revenues	$	1,099,239	$	1,040,800	$	1,066,889	$	1,048,904
Operating income		51,342		47,986		45,265		47,815
Net income		33,925		33,944		30,491		27,409
Basic and diluted income per Limited Partner and Class B Unit (2) (3)	$	0.43	$	0.43	$	0.36	$	0.31
2002
Operating revenues	$	631,137	$	888,329	$	880,804	$	841,893
Operating income		37,586		37,356		47,087		48,218
Net income		26,808		24,377		32,093		34,584
Basic and diluted income per Limited Partner and Class B Unit (4)	$	0.46	$	0.39	$	0.48	$	0.46

(1)		Certain reclassifications have been made to the quarterly information to conform with the current presentation.

(2)		Per Unit calculation includes 3,938,750 Units issued in April 2003, 3,916,547 Units repurchased and retired in April 2003, 5,162,900 Units issued in August 2003, and 87,307 Units issued through the exercise of Unit options in 2003.

(3)		The sum of the four quarters does not equal the total year due to rounding.

F-49

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(4)

Per Unit calculation includes 1,920,000 Units issued in March 2002, 3,175,000 Units issued in July and August 2002, 4,370,000 Units issued in September 2002, 3,795,000 Units issued in November and December 2002, and 99,597 Units issued through the exercise of Unit options in 2002.

F-50

INDEX TO EXHIBIT


3.1		Certificate of Limited Partnership of TEPPCO Partners, L.P. (Filed as Exhibit 3.2 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference).

3.2		Third Amended and Restated Agreement of Limited Partnership of TEPPCO Partners, L.P., dated September 21, 2001 (Filed as Exhibit 3.7 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).

4.1		Form of Certificate representing Limited Partner Units (Filed as Exhibit 4.1 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference).

4.2		Form of Indenture between TE Products Pipeline Company, Limited Partnership and The Bank of New York, as Trustee, dated as of January 27, 1998 (Filed as Exhibit 4.3 to TE Products Pipeline Company, Limited Partnership’s Registration Statement on Form S-3 (Commission File No. 333-38473) and incorporated herein by reference).

4.3		Form of Certificate representing Class B Units (Filed as Exhibit 4.3 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference).

4.4		Form of Indenture between TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as subsidiary guarantors, and First Union National Bank, NA, as trustee, dated as of February 20, 2002 (Filed as Exhibit 99.2 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of February 20, 2002 and incorporated herein by reference).

4.5		First Supplemental Indenture between TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as subsidiary guarantors, and First Union National Bank, NA, as trustee, dated as of February 20, 2002 (Filed as Exhibit 99.3 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of February 20, 2002 and incorporated herein by reference).

4.6		Second Supplemental Indenture, dated as of June 27, 2002, among TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., and Jonah Gas Gathering Company, as Initial Subsidiary Guarantors, and Val Verde Gas Gathering Company, L.P., as New Subsidiary Guarantor, and Wachovia Bank, National Association, formerly known as First Union National Bank, as trustee (Filed as Exhibit 4.6 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by reference).

4.7		Third Supplemental Indenture among TEPPCO Partners, L.P. as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Jonah Gas Gathering Company and Val Verde Gas Gathering Company, L.P. as Subsidiary Guarantors, and Wachovia Bank, National Association, as trustee, dated as of January 30, 2003 (Filed as Exhibit 4.7 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.1+		Duke Energy Corporation Executive Savings Plan (Filed as Exhibit 10.7 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).

10.2+		Duke Energy Corporation Executive Cash Balance Plan (Filed as Exhibit 10.8 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).

10.3+		Duke Energy Corporation Retirement Benefit Equalization Plan (Filed as Exhibit 10.9 to Form 10-K for TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).


10.4+		Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan executed on March 8, 1994 (Filed as Exhibit 10.1 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1994 and incorporated herein by reference).

10.5+		Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan, Amendment 1, effective January 16, 1995 (Filed as Exhibit 10.12 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 1999 and incorporated herein by reference).

10.6+		Form of Employment Agreement between the Company and Thomas R. Harper, Charles H. Leonard, James C. Ruth, John N. Goodpasture, Leonard W. Mallett, Stephen W. Russell, David E. Owen, and Barbara A. Carroll (Filed as Exhibit 10.20 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference).

10.7		Services and Transportation Agreement between TE Products Pipeline Company, Limited Partnership and Fina Oil and Chemical Company, BASF Corporation and BASF Fina Petrochemical Limited Partnership, dated February 9, 1999 (Filed as Exhibit 10.22 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference).

10.8		Call Option Agreement, dated February 9, 1999 (Filed as Exhibit 10.23 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference).

10.9+		Texas Eastern Products Pipeline Company Retention Incentive Compensation Plan, effective January 1, 1999 (Filed as Exhibit 10.24 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference).

10.10+		Form of Employment and Non-Compete Agreement between the Company and J. Michael Cockrell effective January 1, 1999 (Filed as Exhibit 10.29 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference).

10.11+		Texas Eastern Products Pipeline Company Non-employee Directors Unit Accumulation Plan, effective April 1, 1999 (Filed as Exhibit 10.30 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference).

10.12+		Texas Eastern Products Pipeline Company Non-employee Directors Deferred Compensation Plan, effective November 1, 1999 (Filed as Exhibit 10.31 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference).

10.13+		Texas Eastern Products Pipeline Company Phantom Unit Retention Plan, effective August 25, 1999 (Filed as Exhibit 10.32 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference).

10.14+		Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan, Amendment and Restatement, effective January 1, 2000 (Filed as Exhibit 10.28 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2000 and incorporated herein by reference).

10.15+		TEPPCO Supplemental Benefit Plan, effective April 1, 2000 (Filed as Exhibit 10.29 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2000 and incorporated herein by reference).

10.16+		Employment Agreement with Barry R. Pearl (Filed as Exhibit 10.30 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2001 and incorporated herein by reference).

10.17		Amended and Restated Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent and LC Issuing Bank, and Certain Lenders, dated as of April 6, 2001 ($500,000,000 Revolving Facility) (Filed as Exhibit 10.31 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2001 and incorporated herein by reference).


10.18		Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent, and Certain Lenders, dated as of April 6, 2001 ($200,000,000 Revolving Facility) (Filed as Exhibit 10.32 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2001 and incorporated herein by reference).

10.19		Amendment 1, dated as of September 28, 2001, to the Amended and Restated Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent and LC Issuing Bank, and Certain Lenders, dated as of April 6, 2001 ($500,000,000 Revolving Facility) (Filed as Exhibit 10.33 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).

10.20		Amendment 1, dated as of September 28, 2001, to the Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent, and Certain Lenders, dated as of April 6, 2001 ($200,000,000 Revolving Facility) (Filed as Exhibit 10.34 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).

10.21		Amendment and Restatement, dated as of November 13, 2001, to the Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent, and Certain Lenders, dated as of April 6, 2001 ($200,000,000 Revolving Facility) (Filed as Exhibit 10.35 to Form 10-K of TEPPCO Partners, L.P (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).

10.22		Second Amendment and Restatement, dated as of November 13, 2001, to the Amended and Restated Credit Agreement amount TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent and LC Issuing Bank, and Certain Lenders, dated as of April 6, 2001 ($500,000,000 Revolving Facility) (Filed as Exhibit 10.36 to Form 10-K of TEPPCO Partners, L.P (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).

10.23		Second Amended and Restated Agreement of Limited Partnership of TE Products Pipeline Company, Limited Partnership, dated September 21, 2001 (Filed as Exhibit 3.8 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).

10.24		Amended and Restated Agreement of Limited Partnership of TCTM, L.P., dated September 21, 2001 (Filed as Exhibit 3.9 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).

10.25		Contribution, Assignment and Amendment Agreement among TEPPCO Partners, L.P., TE Products Pipeline Company, Limited Partnership, TCTM, L.P., Texas Eastern Products Pipeline Company, LLC, and TEPPCO GP, Inc., dated July 26, 2001 (Filed as Exhibit 3.6 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2001 and incorporated herein by reference).

10.26		Certificate of Formation of TEPPCO Colorado, LLC (Filed as Exhibit 3.2 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1998 and incorporated herein by reference).

10.27		Agreement of Limited Partnership of TEPPCO Midstream Companies, L.P., dated September 24, 2001 (Filed as Exhibit 3.10 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).

10.28		Agreement of Partnership of Jonah Gas Gathering Company dated June 20, 1996 as amended by that certain Assignment of Partnership Interests dated September 28, 2001 (Filed as Exhibit 10.40 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).

10.29		Unanimous Written Consent of the Board of Directors of TEPPCO GP, Inc. dated February 13, 2002 (Filed as Exhibit 10.41 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).


10.30		Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent and Certain Lenders, as Lenders dated as of March 28, 2002 ($200,000,000 Revolving Credit Facility) (Filed as Exhibit 10.44 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the three months ended March 31, 2002 and incorporated herein by reference).

10.31		Amended and Restated Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank, as Administrative Agent and LC Issuing Bank and Certain Lenders, as Lenders dated as of March 28, 2002 ($500,000,000 Revolving Facility) (Filed as Exhibit 10.45 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the three months ended March 31, 2002 and incorporated herein by reference).

10.32		Purchase and Sale Agreement between Burlington Resources Gathering Inc. as Seller and TEPPCO Partners, L.P., as Buyer, dated May 24, 2002 (Filed as Exhibit 99.1 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).

10.33		Credit Agreement among TEPPCO Partners, L.P., as Borrower, SunTrust Bank, as Administrative Agent and Certain Lenders, as Lenders dated as of June 27, 2002 ($200,000,000 Term Facility) (Filed as Exhibit 99.2 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).

10.34		Amendment, dated as of June 27, 2002 to the Amended and Restated Credit Agreement among TEPPCO Partners, L.P., as Borrower, SunTrust Bank, as Administrative Agent, and Certain Lenders, dated as of March 28, 2002 ($500,000,000 Revolving Credit Facility) (Filed as Exhibit 99.3 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).

10.35		Amendment 1, dated as of June 27, 2002 to the Credit Agreement among TEPPCO Partners, L.P., as Borrower, SunTrust Bank, as Administrative Agent and Certain Lenders, dated as of March 28, 2002 ($200,000,000 Revolving Credit Facility) (Filed as Exhibit 99.4 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).

10.36		Agreement of Limited Partnership of Val Verde Gas Gathering Company, L.P., dated May 29, 2002 (Filed as Exhibit 10.48 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by reference).

10.37+		Texas Eastern Products Pipeline Company, LLC 2002 Phantom Unit Retention Plan, effective June 1, 2002 (Filed as Exhibit 10.43 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by reference).

10.38+		Amended and Restated TEPPCO Supplemental Benefit Plan, effective November 1, 2002 (Filed as Exhibit 10.44 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.39+		Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan, Second Amendment and Restatement, effective January 1, 2003 (Filed as Exhibit 10.45 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.40+		Amended and Restated Texas Eastern Products Pipeline Company, LLC Management Incentive Compensation Plan, effective January 1, 2003 (Filed as Exhibit 10.46 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.41+		Amended and Restated TEPPCO Retirement Cash Balance Plan, effective January 1, 2002 (Filed as Exhibit 10.47 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.42		Formation Agreement between Panhandle Eastern Pipe Line Company and Marathon Ashland Petroleum LLC and TE Products Pipeline Company, Limited Partnership, dated as of August 10, 2000 (Filed as Exhibit 10.48 to Form 10-K of TEPPCO Partners, L.P.


		(Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.43		Amended and Restated Limited Liability Company Agreement of Centennial Pipeline LLC dated as of August 10, 2000 (Filed as Exhibit 10.49 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.44		Guaranty Agreement, dated as of September 27, 2002, between TE Products Pipeline Company, Limited Partnership and Marathon Ashland Petroleum LLC for Note Agreements of Centennial Pipeline LLC (Filed as Exhibit 10.50 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.45		LLC Membership Interest Purchase Agreement By and Between CMS Panhandle Holdings, LLC, As Seller and Marathon Ashland Petroleum LLC and TE Products Pipeline Company, Limited Partnership, Severally as Buyers, dated February 10, 2003 (Filed as Exhibit 10.51 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).

10.46		Joint Development Agreement between TE Products Pipeline Company, Limited Partnership and Louis Dreyfus Plastics Corporation dated February 10, 2000 (Filed as Exhibit 10.52 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2003 and incorporated herein by reference).

10.47		Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent and LC Issuing Bank and The Lenders Party Hereto, as Lenders, dated as of June 27, 2003 ($550,000,000 Revolving Facility) (Filed as Exhibit 10.52 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2003 and incorporated herein by reference).

10.48		Agreement of Limited Partnership of Mont Belvieu Storage Partners, L.P. dated effective January 21, 2003 (Filed as Exhibit 10.53 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2003 and incorporated herein by reference).

10.49		Letter of Agreement Clarifying Rights and Obligations of the Parties Under the Mont Belvieu Storage Partners, L.P., Partnership Agreement and the Mont Belvieu Venture, LLC, LLC Agreement, dated October 13, 2003 (Filed as Exhibit 10.54 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2003 and incorporated herein by reference).

12.1*		Statement of Computation of Ratio of Earnings to Fixed Charges.

21		Subsidiaries of the Partnership (Filed as Exhibit 21 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by reference).

23*		Consent of KPMG LLP.

24*		Powers of Attorney.

31.1*		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1**		Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2**		Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.1*		Charter of the Audit Committee of the Board of Directors of the General Partner.

*		Filed herewith.

**		Furnished herewith pursuant to Item 601(b)-(32) of Regulation S-K.

+		A management contract or compensation plan or arrangement.

exv12w1

Exhibit 12.1
Statement of Computation of Ratio of Earnings to Fixed Charges


			Years Ended December 31,

			1999			2000			2001			2002			2003

Earnings
	Income From Continuing Operations *			72,856			65,951			92,533			105,882			108,906
	Fixed Charges			34,305			55,621			72,217			77,726			99,212
	Distributed Income of Equity Investment			—			—			40,800			30,938			27,733
	Capitalized Interest			(2,133	)		(4,559	)		(4,000	)		(4,345	)		(5,290	)

		Total Earnings		105,028			117,013			201,550			210,201			230,561

Fixed Charges
	Interest Expense			31,563			48,982			66,057			70,537			89,540
	Capitalized Interest			2,133			4,559			4,000			4,345			5,290
	Rental Interest Factor			609			2,080			2,160			2,844			4,382

		Total Fixed Charges		34,305			55,621			72,217			77,726			99,212

Ratio: Earnings / Fixed Charges				3.06			2.10			2.79			2.70			2.32

* Excludes minority interest, extraordinary loss and equity earnings.

exv23

Exhibit 23

INDEPENDENT AUDITORS’ CONSENT

We consent to the incorporation by reference in the registration statement on Form S-3 (No. 333-110207), the registration statement on Form S-3 (No. 33-81976), and the registration statement on Form S-8 (No. 333-82892) of TEPPCO Partners, L.P. of our report dated February 12, 2004, related to the consolidated financial statements of TEPPCO Partners, L.P., included in the Annual Report on Form 10-K for the fiscal year ended December 31, 2003 filed on February 23, 2004.

Our report on the consolidated financial statements refers to a change in the method of accounting for derivative financial instruments and hedging activities in 2001 and the adoption of Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets in 2002.


		KPMG LLP

Houston, Texas
February 23, 2004

exv24

Exhibit 24

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each of the undersigned directors and/or officers of TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC (the “Company”), a Delaware limited liability company, acting in its capacity as general partner of TEPPCO Partners, L.P., and TE Products Pipeline Company, Limited Partnership, each a Delaware limited partnership (collectively, “Partnership”), does hereby appoint CHARLES H. LEONARD, BARRY R. PEARL, and JAMES C. RUTH, and each of them, his true and lawful attorney and agent to do any and all acts and things, and execute any and all instruments which, with the advice and consent of Counsel, said attorney and agent may deem necessary or advisable to enable the Company and Partnership to comply with the Securities Act of 1934, as amended, and any rules, regulations, and requirements thereof, to sign his name as a director and/or officer of the Company to the Form 10-K Report for TEPPCO Partners, L.P. and for TE Products Pipeline Company, Limited Partnership, each for the year ended December 31, 2003, and to any instrument or document filed as a part of, or in accordance with, each said Form 10-K or amendment thereto; and the undersigned do hereby ratify and confirm all that said attorney and agent shall do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned have subscribed these presents this 23rd day of February, 2004.


		/s/ MARK A. BORER		/s/ MICHAEL J. BRADLEY

		Mark A. Borer		Michael J. Bradley
		Director		Director

		/s/ MILTON CARROLL		/s/ DERRILL CODY

		Milton Carroll		Derrill Cody
		Director		Director

		/s/ JOHN P. DESBARRES		/s/ WILLIAM H. EASTER III

		John P. DesBarres		William H. Easter III
		Director		Director

		/s/ JIM W. MOGG		/s/ BARRY R. PEARL

		Jim W. Mogg		Barry R. Pearl
		Chairman		Director

		/s/ R. A. WALKER		/s/ CHARLES H. LEONARD

		R. A. Walker		Charles H. Leonard
		Director		Senior Vice President and
				Chief Financial Officer

exv31w1

Exhibit 31.1

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

I, Barry R. Pearl, certify that:

1.		I have reviewed this annual report on Form 10-K of TEPPCO Partners, L.P.;

2.		Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3.		Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4.		The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

	a)		Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

	b)		[intentionally omitted pursuant to SEC Release No. 34-47986];

	c)		Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this annual report based on such evaluation; and

	d)		Disclosed in this annual report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

	a)		All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

	b)		Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



February 23, 2004		/s/ BARRY R. PEARL

		Barry R. Pearl President and Chief Executive Officer Texas Eastern Products Pipeline Company, LLC, as General Partner

exv31w2

Exhibit 31.2

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

I, Charles H. Leonard, certify that:

1.		I have reviewed this annual report on Form 10-K of TEPPCO Partners, L.P.;

2.		Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3.		Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4.		The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

	a)		Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

	b)		[intentionally omitted pursuant to SEC Release No. 34-47986];

	c)		Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this annual report based on such evaluation; and

	d)		Disclosed in this annual report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

	a)		All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

	b)		Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



February 23, 2004		/s/ CHARLES H. LEONARD

		Charles H. Leonard
		Senior Vice President and Chief Financial Officer
		Texas Eastern Products Pipeline Company, LLC,
		as General Partner

exv32w1

Exhibit 32.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002

The undersigned, being the Chief Executive Officer of Texas Eastern Products Pipeline Company, LLC, the sole general partner of TEPPCO Partners, L.P. (the “Company”), hereby certifies that, to his knowledge, the Company’s Annual Report on Form 10-K for the annual period ended December 31, 2003, filed with the United States Securities and Exchange Commission pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)), fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Annual Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

This written statement is being furnished to the Securities and Exchange Commission as an exhibit to such Form 10-K. A signed original of this written statement required by Section 906 has been provided to TEPPCO Partners, L.P. and will be retained by TEPPCO Partners, L.P. and furnished to the Securities and Exchange Commission or its staff upon request.

February 23, 2004

Date


/s/ BARRY R. PEARL

Barry R. Pearl
President and Chief Executive Officer
Texas Eastern Products Pipeline Company, LLC, General Partner

exv32w2

Exhibit 32.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002

The undersigned, being the Chief Financial Officer of Texas Eastern Products Pipeline Company, LLC, the sole general partner of TEPPCO Partners, L.P. (the “Company”), hereby certifies that, to his knowledge, the Company’s Annual Report on Form 10-K for the annual period ended December 31, 2003, filed with the United States Securities and Exchange Commission pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)), fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Annual Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

February 23, 2004

Date


/s/ CHARLES H. LEONARD

Charles H. Leonard
Senior Vice President and Chief Financial Officer
Texas Eastern Products Pipeline Company, LLC, General Partner

exv99w1

Exhibit 99.1

CHARTER OF THE AUDIT COMMITTEE
OF THE BOARD OF DIRECTORS
OF TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC

Organization

This charter (“Charter”) governs the operations of the Audit Committee (the “Committee”) of the Board of Directors of Texas Eastern Products Pipeline Company, LLC (the “Company”), which is the sole general partner of TEPPCO Partners, L.P. The Committee shall annually review and reassess the adequacy of this Charter and recommend to the Board any changes to this Charter that the Committee deems necessary or valuable.

Purpose

The Committee is a standing committee of the Board whose primary function shall be to assist the Board in fulfilling oversight responsibility to TEPPCO Partners, L.P.’s unitholders, potential unitholders, the investment community and others relating to:

	•		The integrity of TEPPCO Partners, L.P. and its subsidiaries (collectively “Partnership”) financial reporting process and systems of internal controls regarding finance, accounting and legal compliance.

	•		The appointment, qualifications (including independence) and performance of the Partnership’s independent auditors.

	•		The performance of the internal auditing function performed by Duke Energy Corporation’s Audit Services Department or any other persons or entities performing or carrying on the internal audit function (“internal auditors”).

	•		The adequacy and adherence to (and waivers from) the Partnership’s Code of Business Ethics.

	•		The review of areas of potential significant financial risk to the Partnership.

	•		The Partnership’s compliance with legal and regulatory requirements.

	•		The review, preparation, discussion and approval of all reports that the Partnership must file with the Securities and Exchange Commission (“SEC”).

The Committee shall also carry out such other functions as shall from time to time be assigned to it by the Board of Directors.

		In carrying out its purpose, the goal of the Committee shall be to serve as an independent and objective monitor of the Partnership’s financial reporting process and internal control systems, including the activities of the Partnership’s independent auditor and internal auditors, and to provide an open avenue of communication between the Committee, the independent auditors, the internal auditors, and management of the Company.

		In discharging its oversight role, the Committee is empowered to (i) investigate any matter brought to its attention with full access to all books, records, facilities and personnel of the Partnership and the Company, and (ii) engage and, on behalf of the Partnership, compensate independent counsel and other advisers as it determines necessary to carry out its duties. The Company and/or the Partnership shall provide the Committee with adequate funding for its operation and the appropriate officers of the Company are hereby authorized to expend the funds necessary for the conduct of the Committee’s business upon direction of the Committee or the Chairman thereof, without further authorization of the Board of Directors.

		Committee Composition and Meetings

	A.		Experience. The Committee members shall meet the experience requirements of the New York Stock Exchange, Inc. (“NYSE”). All members of the Committee shall be financially literate, and at least one member of the Committee shall be an “audit committee financial expert” all as defined in regulations adopted by the SEC under the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”) and applicable NYSE listing standards.

	B.		Independence and Number. The Committee shall be comprised of at least three (3) directors, each of whom shall be determined by the Board to be “independent” in accordance with regulations adopted by the SEC under the Sarbanes-Oxley Act and applicable NYSE listing standards. A director shall generally be considered independent if he or she has no material relationship with the Company, or the Partnership, (other than service as a director of the Company). The Board shall determine whether such a material relationship exists; provided, however, that the following shall be deemed to constitute a material relationship and shall disqualify a director from serving on the Committee.

	•		Employment with the Company, the Partnership or their affiliates in an executive capacity within the last five (5) years;

	•		Employment or other material relationship with a present or former auditor of the Company, the Partnership or their affiliates within the last five (5) years after the end of the affiliation or auditing relationship;

	•		Part of an interlocking directorate in which an executive officer of the Company serves on the compensation committee of another company that currently employs the director;

	•		Employment or other material relationship with an entity that is an adviser or consultant to the Company, the Partnership or their affiliates;

	•		Employment or other material relationship with a significant customer or supplier of the Company, the Partnership or their affiliates;

	•		Any personal services contract(s) with the Company, the Partnership or their affiliates;

	•		Any business relationship with the Company, the Partnership or their affiliates (other than service as a director) for which the Company or the Partnership has been required to make disclosure under Regulation S-K within the last five (5) years;

	•		An immediate family relationship with any person described above; or

	•		Otherwise be considered an “affiliated person” of the Company or the Partnership as such term is defined under applicable SEC rules.

			In addition, to be considered “independent, no Committee member may receive any compensation, directly or indirectly, from the Company or the Partnership other than director’s fees. The fee may be received in cash or other in kind consideration ordinarily available to outside directors, as well as all of the regular benefits that other outside directors receive as Board members.

Appointment/Removal and Chairman. The members of the Committee shall be appointed by the Board at the annual meeting of the Board for terms of one (1) year, or until their successors shall be duly elected and qualified. Any member can be removed by the Board at any time for any reason. Any Committee member who ceases to be “independent” as described above shall automatically be removed from the Committee. Any vacancies in the Committee shall be filled by the Board as soon as reasonably possible. Unless a Chairman of the Committee is appointed by the Board, the members of the Committee may designate a Chairman by majority vote of the full membership of the Committee.

Meetings.

	•		The Committee shall meet at least quarterly, or more frequently as circumstances dictate. The Committee Chairman after consultation with management of the Company, other Committee members, internal auditors and independent auditors, shall prepare and/or approve an agenda in advance of each meeting.

	•		The Committee should meet at least annually, or more frequently as circumstances dictate, in separate executive sessions with management, the internal auditors, the independent auditors, and as a committee to discuss any matters that the Committee or each of these groups believe should be discussed privately.

	•		The Committee, or at least its Chairman, should communicate with management and the independent auditors quarterly to review the Partnership’s financial statements and significant findings based upon the auditors limited review procedures.

	E.		Limitations on Outside Service

			No member of the Committee may serve on the audit committee of more than three public companies, including the Company, unless the Board of Directors has determined that such simultaneous service would not impair the ability of such member to effectively serve on the Committee.

		Duties and Responsibilities.

		The primary general responsibility of the Committee is to oversee the financial reporting process on behalf of the Board and report the results of its activities to the Board. While the Committee has the responsibilities and powers set forth in this Charter, it is not the duty of the Committee to plan or conduct audits or to determine that the Partnership’s financial statements are complete and accurate and are in accordance with generally accepted accounting principles. Management is responsible for the preparation, presentation and integrity of the Partnership’s financial statements and for the appropriateness of the accounting principles and reporting policies that are used by the Partnership. The independent auditors are responsible for auditing the Partnership’s financial statements and for reviewing the Partnership’s unaudited interim financial statements.

		The Committee, in carrying out its responsibilities, believes its policies and procedures should remain flexible in order to best react to changing conditions and circumstances. The Committee should take appropriate actions to set the overall “tone” of the Partnership for quality public disclosure and financial reporting, sound business risk

practices, and ethical behavior. Within the overall general responsibility the following shall be the principal specific duties and responsibilities of the Committee. These are set forth as a guide with the understanding that the Committee may supplement them as appropriate, but shall have them reviewed and approved annually by the Board.

	•		The Committee shall be directly responsible for, and have sole authority as to, the retention and termination, evaluation, compensation and oversight of the work of the independent auditors, including resolution of disagreements between management and the auditors regarding accounting matters and financial reporting. The independent auditor shall report directly to the Committee and in the conduct of the annual audit shall be subject to direction only by the Committee.

	•		The Committee shall have sole authority to, and shall, pre-approve all audit and non-audit services provided by the independent auditors to the Partnership and shall assure that the independent auditors are not engaged to perform the specific nonaudit services proscribed by law or regulation. The Committee may delegate preapproval authority to a member or members of the Committee. The decisions of any Committee member or members to whom pre-approval authority is delegated must be presented to the full Committee at its next scheduled meeting.

— provided, however, that the provision by the independent auditor of non-audit services shall be permissible without the prior approval of the Committee in cases where (i) the aggregate compensation for all such non-audit services constitutes not more than 5% of the total compensation payable by the Partnership to the auditor for the fiscal year of the Partnership in which such non-audit services are provided, (ii) such non-audit services were not considered by the Committee as services that might be provided to the Partnership by the independent auditor at the time of its appointment, and (iii) the provision of such services by the independent auditor are promptly brought to the attention of the Committee and approved prior to completion of the audit for the year in which such services were provided (which approval may be provided by the Chairman of the Committee or any other member or members to whom the Committee delegates such approval authority).

•

At least annually, the Committee shall obtain and review a report by the independent auditors describing

	-		the auditing firm’s internal quality control procedures.

	-		any material issues raised by the most recent internal quality control review, or peer review, of the auditing firm, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, respecting one or more independent audits carried out by the auditing firm, and any steps taken to deal with any such issues.

all relationships between the independent auditors and the Partnership (to assess the auditor’s independence).

•

Based on a review of such annual report and the work of the independent auditors throughout the year, the Committee shall evaluate the independent auditors’ qualifications, performance and independence, which evaluation will include the review and evaluation of the lead partner of the independent auditor. In conducting its review and evaluation, the Committee should:

	(a)		determine whether the lead audit partner (having primary responsibility for the audit) or the audit partner responsible for reviewing the audit is required to rotate in compliance with applicable law,

	(b)		take into account the opinions of management and the internal auditors, and

	(c)		consider whether, in order to assure continuing auditor independence, there should be a regular rotation of the firm conducting the independent audit.

	The Committee shall present its conclusions with respect to the independent auditors and its evaluation thereof to the Board annually.

	•		In addition, the Committee shall establish hiring policies for the Partnership and the Company as to employees or former employees of the independent auditors.

	•		The Committee shall discuss with the internal auditors and the independent auditors the overall scope and plans for their respective audits, including the adequacy of staffing and compensation or expense coverage. The Committee shall discuss with management, the internal auditors, and the independent auditors the adequacy and effectiveness of the Partnership’s accounting and financial controls, including the Partnership’s policies and procedures to assess, monitor and manage business risk and legal and ethical compliance programs (e.g., Partnership’s Code of Business Ethics).

	•		The Committee shall periodically meet separately with management, the internal auditors, and the independent auditors to discuss issues and concerns warranting Committee attention. The Committee shall provide sufficient opportunity for the internal auditors and the independent auditors to meet privately with the members of the Committee. The Committee shall review with the independent auditors (i) any audit problems or difficulties and management’s response, (ii) accounting adjustments noted or proposed by the independent auditors, whether passed or accepted, (iii) any communications between the audit team and the independent auditors’ national office as to the Partnership, (iv) any internal control letter

			issued or proposed to be issued to the Partnership by the independent auditors, and (v) the responsibilities, budget, and staffing of the internal audit function.

	•		The Committee shall review and discuss the regular reports from the independent auditors on (i) the critical accounting policies and practices of the Partnership, (ii) alternative treatments of financial information within generally accepted accounting principles that have been discussed with management, and (iii) other material written communications between the independent auditor and management regarding the Partnership’s financial reports, such as any management letter or schedule of unadjusted differences.

	•		The Committee shall review with the independent auditor and management: the adequacy of the Partnership’s internal accounting and financial controls and procedures and disclosure controls and procedures, including computerized information system controls, procedures and security and including any report provided by the internal audit function to the chief financial officer or chief executive officer regarding any material aspect of the Partnership’s internal accounting and financial control system; and, in such regard, (i) management and the independent auditor shall brief the Committee on any significant deficiencies in the design or operation of the Partnership’s internal controls which could adversely affect the Partnership’s ability to record, process, summarize and report financial data and any fraudulent activity, whether or not material, that involves management or other employees who have a significant role in the Partnership’s internal controls which come to their attention, (ii) the Committee shall review the recommendations of the independent auditor for addressing any such matters, together with management’s responses thereto, and receive a report on and consider, at least annually, the implementation of any improvements to the Partnership’s internal controls and procedures for financial reporting undertaken as a result of any such review, until such improvements have been fully implemented, and (iii) the Committee shall review management’s annual assessment of the Partnership’s internal controls and procedures for financial reporting and the independent auditor’s annual attestation of such assessment, as such are required by SEC rules.

	•		The Committee shall review and discuss with management and independent auditors as may be appropriate, earnings press releases, as well as financial information and earnings guidance provided to analysts and rating agencies.

	•		The Committee shall review with management and the independent auditors the Partnership’s interim financial statements and disclosures under Management’s Discussion and Analysis of Financial Condition and Results of Operations with management and the independent auditors prior to the filing of the Partnership’s Quarterly Reports on Form 10-Q. Also, the Committee shall discuss with the independent auditors the results of the quarterly review and any other matters required to be discussed by Statement of Auditing Standards No. 61.

	•		The Committee shall review with management and the independent auditors the financial statements and disclosures under Management’s Discussion and Analysis of Financial Condition and Results of Operations (MDA) to be included in the Partnership’s Annual Reports on Form 10-K (or in any annual report to unitholders if distributed prior to the filing of a Form 10-K), including their judgment about the quality, not just the acceptability, of accounting principles, the reasonableness of significant judgments, and the clarity of the disclosures in the financial statements and MDA. Also, the Committee shall discuss with the independent auditors the results of the annual audit and any other matters required to be discussed by Statement of Auditing Standards No. 61.

	•		While the fundamental responsibility for the Partnership’s financial statements and disclosures rests with management, as reviewed by the independent auditors, the Committee shall review.

	-		Major issues regarding accounting principles and financial statement presentations, including any significant changes in the Partnership’s selection or application of accounting principles, and major issues as to the adequacy of the Partnership’s internal controls and any special audit steps adopted in light of material control deficiencies.

	-		Analyses prepared by management and/or the independent auditors setting forth significant financial reporting issues and judgments made in connection with the preparation of the financial statements, including analyses of the effects of alternative GAAP methods on the financial statements.

	-		The effect of regulatory and accounting initiatives, as well as off-balance sheet structures, on the financial statements of the Partnership.

	-		Earnings press releases disclosing “pro forma,” or “adjusted” non-GAAP, information.

•

The Committee shall establish procedures for

	-		The receipt, retention, and treatment of complaints received by the Partnership regarding accounting, internal accounting controls, or auditing matters.

	-		The confidential, anonymous submission by employees of the Company of concerns regarding questionable accounting or auditing matters relating in any manner to the Partnership.

•

The Committee shall review any attorney’s report of evidence of a material violation of securities laws or breaches of fiduciary duty or similar violation by the Company, the Partnership or any agent thereof.

	•		The Committee shall periodically require each of its members to certify that such person meets the independence requirements prescribed by law and/or NYSE rules, including that such person has received no compensation from the Company or Partnership other than director and Board committee fees.

	•		The Committee shall review its membership annually to assure that all its members are financially literate and that at least one of its members is an audit committee financial expert, all in accordance with applicable SEC regulations and NYSE listing standards.

	•		As appropriate, but not less than annually, the Committee shall review with the Partnership’s counsel any legal matters that could have a significant impact on the Partnership’s financial statements, the Partnership’s compliance with applicable laws and regulations, and inquiries received from regulators or governmental agencies.

	•		The Committee shall establish, review and update periodically a Code of Business Ethics for officers and employees of the Company, including Senior Financial Officers, and ensure that management has established a system to enforce such Code.

	•		The Committee shall review at least annually the Partnership’s risk assessment and risk management policies contained in the Risk Management Plan and discuss with independent auditors any significant areas of concern they may have with such Plan or its implementation.

	•		The Committee shall report regularly to the Board of Directors following each meeting, which reports shall include any issues that arise with respect to the quality or integrity of the Partnership’s financial statements, the Partnership’s compliance with legal or regulatory requirements, the performance and independence of the Partnership’s independent auditors or the performance of the internal audit function and with respect to such other matters as are relevant to the Committee’s discharge of its responsibilities and, in such regard, the Committee shall provide such recommendations as the Committee may deem appropriate.

	•		The Committee shall perform any activities consistent with this Charter, the Partnership’s organizational documents, and governing law, as the Committee or the Board deems necessary or appropriate.

	•		The Committee shall maintain minutes or other records of meetings and actions of the Committee.

Annual Self-Evaluation

The Committee shall conduct an annual self-evaluation of the performance of the Committee, including its effectiveness and compliance with the Charter of the Committee.