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e10-k

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year ended December 31, 2001

Commission File Number 1-10403

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


Delaware (State of Incorporation or Organization)		76-0291058 (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 No

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

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

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

Documents Incorporated by Reference: None

TABLE OF CONTENTS


PART I
	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
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
PART IV
	Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
Amendment to the Credit Agreement
Second Amendment to Amended Credit Agreement
Agreement of Partnership of Jonah Gas Gathering Co
Unanimous Written Consent of Board-TEPPCO GP, Inc.
Computation of Ratio of Earnings to Fixed Charges
Subsidiaries of the Partnership
Consent of KPMG LLP
Powers of Attorney

TABLE OF CONTENTS


	PART I

ITEMS 1.	Business and Properties	1
AND 2.
ITEM 3.	Legal Proceedings	18
ITEM 4.	Submission of Matters to a Vote of Security Holders	19

	PART II

ITEM 5.	Market for Registrant’s Units and Related Unitholder Matters	19
ITEM 6.	Selected Financial Data	20
ITEM 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risks	37
ITEM 8.	Financial Statements and Supplementary Data	37
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	37

	PART III

ITEM 10.	Directors and Executive Officers of the Registrant	38
ITEM 11.	Executive Compensation	40
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management	45
ITEM 13.	Certain Relationships and Related Transactions	46

	PART IV

ITEM 14.	Exhibits, Financial Statement Schedules and Reports on Form 8-K	48

Items 1 and 2. Business and Properties

General

TEPPCO Partners, L.P. (the “Partnership”), a Delaware limited partnership, is a master limited partnership and was formed in March 1990. The Partnership operates through TE Products Pipeline Company, Limited Partnership (“TE Products”), TCTM, L.P. (“TCTM”) and TEPPCO Midstream Companies, L.P. (“TEPPCO Midstream”). Collectively, TE Products, TCTM and TEPPCO Midstream are referred to as the “Operating Partnerships.” Texas Eastern Products Pipeline Company, LLC (the “Company” or “General Partner”), a Delaware limited liability company, serves as the general partner of the Partnership. The General Partner is a wholly-owned subsidiary of Duke Energy Field Services (“DEFS”), a joint venture between Duke Energy Corporation (“Duke Energy”) and Phillips Petroleum Company (“Phillips”). Duke Energy holds an approximate 70% interest in DEFS and Phillips holds the remaining 30%. The Company, as general partner, performs all management and operating functions required for the Partnership and the Operating Partnerships, except for the management and operations of the TEPPCO Midstream assets, which is performed by DEFS under an agreement with the Partnership. The General Partner is reimbursed by the Partnership for all reasonable direct and indirect expenses incurred in managing the Partnership.

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

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

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

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

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

Downstream Segment — Transportation of Refined Products, Petrochemicals and LPGs

Operations

The Partnership conducts business in its Downstream Segment through TE Products and its subsidiary. TE Products owns and operates properties located in 13 states. These operations consist of interstate transportation, storage and terminaling of petroleum products; short-haul shuttle transportation of LPGs at the Mont Belvieu, Texas complex; intrastate transportation of petrochemicals; fractionation of natural gas liquids and other ancillary services.

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

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

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


	Partnership
	Ownership

Refined products and LPGs pipeline		100	%
Mont Belvieu LPGs storage and pipeline shuttle		100	%
Mont Belvieu to Port Arthur, Texas, petrochemical pipelines		100	%
Centennial Pipeline(1)		33	%

(1)

Accounted for as an equity investment.

Centennial Pipeline Joint Venture

In August 2000, TE Products entered into agreements with CMS Energy Corporation and Marathon Ashland Petroleum LLC to form a pipeline joint venture, Centennial Pipeline, LLC (“Centennial”). Centennial owns and operates an interstate refined petroleum products pipeline extending from the upper Texas Gulf Coast to Illinois. Each participant owns a one-third interest in Centennial. Centennial constructed a 74-mile, 24-inch diameter pipeline connecting TE Products’ facility in Beaumont, Texas, with an existing 720-mile, 26-inch diameter pipeline extending from Longville, Louisiana, to Bourbon, Illinois. The Centennial pipeline intersects TE Products’ existing mainline pipeline near Creal Springs, Illinois, where Centennial has constructed a new two million barrel refined petroleum products storage terminal. TE Products’ interest is not subject to any encumbrances from mortgages or other secured debt. Centennial has unsecured debt, one third of which, up to $50 million in principal, is guaranteed by each owner, including TE Products. As of December 31, 2001, TE Products has contributed approximately $70 million for its one-third interest in Centennial. The Partnership expects to contribute an additional $4.9 million to Centennial in 2002. Centennial commenced operations in the first quarter of 2002.

Refined Products and LPGs Pipeline System

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

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

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

The Products Pipeline System includes 30 storage facilities with an aggregate storage capacity of 13 million barrels of refined petroleum products and 38 million barrels of LPGs, including storage capacity leased to outside parties. The Products Pipeline System makes deliveries to customers at 53 locations including 18 owned truck racks, rail car facilities and marine facilities. Deliveries to other pipelines occur at various facilities owned by TE Products or by third parties.

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

Greater Cincinnati/Northern Kentucky International Airport and an 8-inch diameter pipeline connection to the George Bush Intercontinental Airport in Houston. In addition, there are numerous smaller diameter lines associated with the gathering and distribution system.

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

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

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

Major Business Sector Markets

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


			Product Deliveries (MMBbls)
			Years Ended December 31,

			2001		2000		1999

Refined Products Mainline Transportation:
	Central(1)			62.0		63.4		67.7
	Midwest(2)			37.4		36.7		37.9
	Ohio and Kentucky			23.5		28.0		27.0

		Subtotal		122.9		128.1		132.6

LPGs Mainline Transportation:
	Central, Midwest and Kentucky(1)(2)			23.8		23.4		22.9
	Ohio and Northeast(3)			16.2		16.2		14.7

		Subtotal		40.0		39.6		37.6

		Total Mainline Transportation		162.9		167.7		170.2

Mont Belvieu Operations:
	LPGs			23.1		27.2		28.5

		Total Product Deliveries		186.0		194.9		198.7

(1)		Arkansas, Louisiana, Missouri and Texas.

(2)		Illinois and Indiana.

(3)		New York and Pennsylvania.

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

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


			Product Deliveries (MMBbls)
			Years Ended December 31,

			2001		2000		1999

Refined Products Mainline Transportation:
	Gasoline			68.2		67.8		71.6
	Jet Fuels			25.4		28.1		26.9
	Middle Distillates(1)			28.1		26.6		28.4
	MTBE(2)/Toluene			1.2		5.6		5.7

		Subtotal		122.9		128.1		132.6

LPGs Mainline Transportation:
	Propane			32.8		33.1		30.8
	Butanes			7.2		6.5		6.8

		Subtotal		40.0		39.6		37.6

		Total Mainline Transportation		162.9		167.7		170.2

Mont Belvieu Operations:
	LPGs			23.1		27.2		28.5

		Total Product Deliveries		186.0		194.9		198.7

(1)		Primarily diesel fuel, heating oil and other middle distillates.

(2)		Methyl tertiary butyl ether, a fuels additive, the use of which has largely been discontinued.

Refined Products Mainline Transportation

The Products Pipeline System transports refined petroleum products from the upper Texas Gulf Coast, eastern Texas and southern Arkansas to the Central and Midwest regions of the United States with deliveries in Texas, Louisiana, Arkansas, Missouri, Illinois, Kentucky, Indiana and Ohio. At these points, refined petroleum products are delivered to terminals owned by TE Products, connecting pipelines and customer-owned terminals. TE Products canceled its tariff for deliveries of MTBE into the Chicago market area on July 1, 1999, and canceled contract deliveries of MTBE at its marine terminal near Beaumont, Texas, effective April 22, 2001. The Partnership no longer transports MTBE through the Products Pipeline System.

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

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

LPGs Mainline Transportation

The Products Pipeline System transports LPGs from the upper Texas Gulf Coast to the Central, Midwest and Northeast regions of the United States. The Products Pipeline System east of Todhunter, Ohio, is devoted solely to the transportation of LPGs. Since LPGs demand is generally stronger in the winter months, the Products Pipeline System often operates at or near capacity during such time. Propane deliveries are generally sensitive to the weather and meaningful year-to-year variations have occurred and will likely continue to occur.

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

Mont Belvieu LPGs Storage and Pipeline Shuttle

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

The Partnership’s Downstream Segment has approximately 36 million barrels of LPGs storage capacity, including storage capacity leased to outside parties, at the Mont Belvieu complex. The Downstream Segment includes a Mont Belvieu short-haul transportation shuttle system, consisting of a complex system of pipelines and interconnects, that ties Mont Belvieu to virtually every refinery and petrochemical facility on the upper Texas Gulf Coast.

In February 2000, the Partnership and Louis Dreyfus Plastics Corporation (“Louis Dreyfus”) announced a joint marketing and development alliance. The Partnership’s Mont Belvieu LPGs storage and transportation shuttle system services are jointly marketed by Louis Dreyfus and the Partnership. The purpose of the alliance is to expand services to the upper Texas Gulf Coast energy marketplace by increasing pipeline throughput and the mix of products handled through the existing system and establishing new receipt and delivery connections. TE Products operates the facilities for the alliance. The alliance is a service-oriented, fee-based venture with no commodity trading activity. Under the alliance, Louis Dreyfus has invested $4.4 million for expansion projects at Mont Belvieu. The Partnership is required to reimburse this amount to Louis Dreyfus if the alliance is terminated by either Louis Dreyfus or the Partnership.

Other Operating Revenues

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

Customers

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

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

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

Competition

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

Because pipelines are generally the lowest cost method for intermediate and long-haul overland movement of refined petroleum products and LPGs, the Products Pipeline System’s most significant competitors (other than indigenous production in its markets) are pipelines in the areas where the Products Pipeline System delivers products. Competition among common carrier pipelines is based primarily on transportation charges, quality of customer service and proximity to end users. The Partnership believes the Downstream Segment is competitive with other pipelines serving the same markets; however, comparison of different pipelines is difficult due to varying product mix and operations.

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

Upstream Segment — Transportation and Marketing of Crude Oil and NGL

Operations

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

Margins in the Upstream Segment are calculated as revenues generated from the sale of crude oil and lubrication oil, and transportation of crude oil and NGLs, less the costs of purchases of crude oil and lubrication oil. Margins are a more meaningful measure of financial performance than operating revenues and operating expenses due to the significant fluctuations in revenues and expenses caused by variations in the level of marketing activity and prices for products marketed.

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

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

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


		Years Ended December 31,

		2001		2000		1999

Total Barrels:
	Crude oil transportation		78,714		46,225		33,267
	Crude oil marketing		159,477		107,607		96,252
	Crude oil terminaling		121,932		56,473		—
	NGL transportation		21,538		5,201		4,580
Lubricants and chemicals (total gallons)			8,769		7,974		8,891

Properties

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


	Partnership
Crude Oil Pipeline	Ownership		Operator	Description

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

South Texas System		100%	TCO	690 miles of pipeline; 740,000 barrels storage — South Central Texas to Houston, Texas area

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

Seaway		50% general partnership interest(2)	TCO	500-mile, 30-inch diameter pipeline — Texas Gulf Coast to Cushing, Oklahoma

Rancho		25% joint ownership	Equilon Pipeline Company, LLC	400-mile, 24-inch diameter pipeline — West Texas to Houston, Texas

Basin		13% joint ownership	Equilon Pipeline Company, LLC	416-mile pipeline — Permian Basin (New Mexico and Texas) to Cushing, Oklahoma

(1)		TCO is a wholly-owned subsidiary of TCTM.

(2)		TCO’s participation in revenues and expenses of Seaway vary as described below in “Partnership Interest in Seaway Crude Pipeline.”

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

The majority of the Red River System crude oil is delivered to Cushing, Oklahoma via connecting pipelines or to two local refineries. The majority of the crude oil on the South Texas System is delivered on a tariff basis to Houston area refineries. The West Texas Trunk System connects gathering systems to TCTM’s Midland, Texas terminal. Other crude oil assets, located primarily in Texas and Louisiana, consist of 344 miles of pipeline and 295,000 barrels of storage capacity.

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


	Capacity
NGL Pipeline	(barrels/day)		Description

Dean		20,000	338 miles of pipeline — South Texas to Mont Belvieu, Texas

Panola		38,000	189 miles of pipeline — Carthage, Texas to Mont Belvieu, Texas

San Jacinto		11,000	34 miles of pipeline — Carthage, Texas to Longview, Texas

Wilcox		7,000	90 miles of pipeline — Southeast Texas

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

The Wilcox NGL Pipeline transports NGLs for DEFS from two of their natural gas processing plants. The Wilcox NGL Pipeline is currently supported by a throughput agreement with DEFS through 2005. The Panola Pipeline and San Jacinto Pipeline were purchased on December 31, 2000, from DEFS and originate at DEFS’ East Texas Plant Complex in Panola County, Texas.

Partnership Interest in Seaway Crude Pipeline

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

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

Line Transfers, Pumpovers and Other

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

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

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

Customers

TCTM purchases crude oil primarily from major integrated oil companies and independent oil producers. Crude oil sales are primarily to major integrated oil companies and independent refiners. During 2001, no single customer accounted for 10% or more of the margin of the Partnership’s Upstream Segment. The Company does not believe the loss of any single customer would have a material adverse effect on the consolidated financial position, results of operations or cash flows of the Partnership.

Competition

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

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

Credit Policies and Procedures

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

Midstream Segment — Natural Gas Gathering

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

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

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

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

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


Gathering — natural gas (Billion cubic feet (“Bcf”))			45.5
Sales — condensate (thousand barrels)			16.2

The Jonah Gas Gathering System

The Jonah System consists of approximately 350 miles of pipelines ranging in size from four to 20 inches in diameter, four compressor stations with an aggregate of approximately 21,200 horsepower and related metering facilities. Gas gathered on the Jonah System is collected from approximately 375 producing wells in the Green River Basin in southwestern Wyoming, which is one of the most prolific natural gas basins in the United States. A component of the system is a processing facility that extracts condensate prior to delivery of natural gas to DEFS’ Overland Trail Transmission system and Questar. Gas is delivered to gas processing facilities owned by others. From these processing facilities, the natural gas is delivered to several interstate pipeline systems located in the region for transportation to end-use markets, throughout the Midwest, the West Coast and the Rocky Mountain regions. Interstate pipelines in the region include the Overland Trail Transmission system, Kern River, Northwest, Colorado Interstate Gas and Questar.

Customers

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

Competition

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

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

Title to Properties

The Partnership believes it has satisfactory title to all of its assets. The properties are subject to liabilities in certain cases, such as customary interests generally contracted in connection with acquisition of the properties, liens for taxes not yet due, easements, restrictions, and other minor encumbrances. In February 2002, a producer on the Jonah System notified Alberta Energy Company that it has a right to acquire all or a portion of the assets comprising Jonah. See Items 1 and 2. Business and Properties, “Midstream Segment — Natural Gas Gathering” for a more detailed discussion of the matter. The Partnership believes none of these liabilities materially affects the value of its properties or the Partnership’s interest therein or will materially interfere with their use in the operation of the Partnership’s business.

Capital Expenditures

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

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


		Revenue		Maintenance		System		Capitalized
		Generating		Capital		Upgrades		Interest		Total

Downstream Segment		$	62.2	$	12.7	$	3.0	$	3.5	$	81.4
Upstream Segment			6.1		4.7		2.8		0.4		14.0
Midstream Segment			11.0		1.1		—		0.1		12.2

	Total	$	79.3	$	18.5	$	5.8	$	4.0	$	107.6

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

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

Regulation

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

Rates of interstate oil pipeline companies, like the Partnership, are currently regulated by the FERC primarily through an index methodology, whereby a pipeline is allowed to change its rates based on the change from year to year in the Producer Price Index for finished goods less 1% (“PPI Index”). In the alternative, interstate oil pipeline companies may elect to support rate filings by using a cost-of-service methodology, competitive market showings (“Market-Based Rates”) or agreements between shippers and the oil pipeline company that the rate is acceptable (“Settlement Rates”).

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

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

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

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

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

Environmental Matters

The operations of the Partnership are subject to federal, state and local laws and regulations governing the discharge of materials into the environment otherwise relating to environmental protection. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, imposition of injunctions delaying or prohibiting certain activities, and the need to perform investigatory and remedial activities. Although the Partnership believes its operations are in material compliance with applicable environmental laws and regulations, risks of significant costs and liabilities are inherent in pipeline operations, and there can be no assurance that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly strict environmental laws and regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from its operations, could result in substantial costs and liabilities to the Partnership. The Company does not anticipate that changes in environmental laws and regulations will have a material adverse effect on the Partnership’s financial position, results of operations or cash flows in the near term.

Water

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

Contamination resulting from spills or releases of refined petroleum products is an inherent risk within the petroleum pipeline industry. To the extent that groundwater contamination requiring remediation exists along its pipeline systems as a result of past operations, the Partnership believes any such contamination could be controlled or remedied without having a material adverse effect on the financial condition of the Partnership, but such costs are site specific, and there can be no assurance that the effect will not be material in the aggregate.

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

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

Air Emissions

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

Risk Management Plans

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

Solid Waste

The Partnership generates hazardous and non-hazardous solid wastes that are subject to requirements of the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. Amendments to RCRA required the EPA to promulgate regulations banning the land disposal of all hazardous wastes unless the wastes meet certain treatment standards or the land-disposal method meets certain waste containment criteria. From time to time,

the EPA considers the adoption of stricter disposal standards for non-hazardous wastes, including crude oil and gas wastes. The adoption of such stricter standards for non-hazardous wastes, or any future re-designation of non-hazardous wastes as hazardous wastes will likely increase the operating expenses of the Partnership as well as the industry in general. The Partnership utilizes waste minimization and recycling processes to reduce the volume of its waste. The Partnership currently has one permitted on-site waste water treatment facility. Operating expenses of this facility has not had a material adverse effect on the financial position, results of operations or cash flows of the Partnership.

Superfund

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

In December 1999, the Company was notified by the EPA of potential liability for alleged waste disposal at Container Recycling, Inc., located in Kansas City, Kansas. The Company was also asked to respond to an EPA Information Request. The Company’s response to the information request has been filed with the EPA Region VII office. Based on information the Company has received from the EPA, as well as through its internal investigations, the Company is pursuing dismissal from this matter.

Other Environmental Proceedings

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

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

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

Safety Regulation

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

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

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

The Partnership is also subject to the requirements of the federal OSHA and comparable state statutes. The Partnership believes it is in material compliance with OSHA and state requirements, including general industry standards, record keeping requirements and monitoring of occupational exposures.

The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require the Partnership to organize and disclose information about the hazardous materials used in its operations. Certain parts of this

information must be reported to employees, state and local governmental authorities, and local citizens upon request. The Partnership is subject to OSHA Process Safety Management (“PSM”) regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds; or any process which involves a flammable liquid or gas, as defined in the regulations, stored on-site in one location, in a quantity of 10,000 pounds or more. The Partnership utilizes certain covered processes and maintains storage of LPGs in pressurized tanks, caverns and wells, in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling point without benefit of chilling or refrigeration are exempt. The Partnership believes it is in material compliance with the PSM regulations.

In general, the General Partner expects to increase the expenditures of the Partnership during the next decade to comply with stricter industry and regulatory safety standards such as those described above. While such expenditures cannot be accurately estimated at this time, the Company does not believe that they will have a future material adverse effect on the Partnership’s financial condition, results of operations or cash flows.

Employees

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

Item 3. Legal Proceedings

Toxic Tort Litigation — Seymour, Indiana

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

Other Litigation

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

individually or in the aggregate have a future material adverse effect on the Partnership’s consolidated financial condition, results of operations or cash flows.

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

None.

PART II

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

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


	2001				2000

Quarter	High		Low		High		Low

First	$	27.44	$	24.38	$	22.94	$	19.00
Second		30.10		25.76		24.38		19.88
Third		32.90		26.00		26.75		22.75
Fourth		36.50		28.50		27.00		21.63

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

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


		Amount
Record Date	Payment Date	Per Unit

April 28, 2000	May 5, 2000	$	0.500
July 31, 2000	August 4, 2000		0.500
October 30, 2000	November 3, 2000		0.525
January 31, 2001	February 2, 2001		0.525

April 30, 2001	May 4, 2001	$	0.525
July 31, 2001	August 6, 2001		0.525
October 31, 2001	November 5, 2001		0.575
January 31, 2002	February 8, 2002		0.575

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

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

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

Item 6. Selected Financial Data

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


					Years Ended December 31,

					2001(1)			2000(2)			1999			1998(3)			1997

					(in thousands, except per Unit Amounts)
Income Statement Data:
	Operating revenues:
		Sales of crude oil and petroleum products			$	3,219,816		$	2,821,943		$	1,692,767		$	214,463		$	—
		Transportation — refined products				139,315			119,331			123,004			119,854			107,304
		Transportation — LPGs				77,823			73,896			67,701			60,902			79,371
		Transportation — crude oil and NGLs				44,925			24,533			11,846			3,392			—
		Gathering — natural gas				8,824			—			—			—			—
		Mont Belvieu operations				14,116			13,334			12,849			10,880			12,815
		Other				51,594			34,904			26,716			20,147			22,603

			Total operating revenues			3,556,413			3,087,941			1,934,883			429,638			222,093
	Purchases of crude oil and petroleum products					3,173,607			2,794,604			1,666,042			212,371			—
	Operating expenses					185,918			150,149			136,095			110,363			106,771
	Depreciation and amortization					45,899			35,163			32,656			26,938			23,772

	Operating income					150,989			108,025			100,090			79,966			91,550
	Interest expense — net					(62,057	)		(44,423	)		(29,430	)		(28,989	)		(32,229	)
	Equity earnings					17,398			12,214			—			—			—
	Other income — net					2,801			1,560			1,460			2,364			1,979

		Income before extraordinary item				109,131			77,376			72,120			53,341			61,300
	Extraordinary loss on debt extinguishment, net of minority interest(4)					—			—			—			(72,767	)		—

		Net income (loss)			$	109,131		$	77,376		$	72,120		$	(19,426	)	$	61,300

	Basic and diluted income per Unit:(5)
		Before extraordinary item			$	2.18		$	1.89		$	1.91		$	1.61		$	1.95
		Extraordinary loss on debt extinguishment(4)				—			—			—			(2.21	)		—

				Net income (loss) per Unit	$	2.18		$	1.89		$	1.91		$	(0.60	)	$	1.95

Balance Sheet Data (at period end):
	Property, plant and equipment — net				$	1,180,461		$	949,705		$	720,919		$	671,611		$	567,681
	Total assets					2,065,348			1,622,810			1,041,373			916,919			673,909
	Long-term debt (net of current maturities)					730,472			835,784			455,753			427,722			309,512
	Total debt					1,090,472			835,784			455,753			427,722			326,512
	Class B Units held by related party					105,630			105,411			105,859			105,036			—
	Partners’ capital					543,181			315,057			229,767			227,186			302,967
Cash Flow Data:
	Net cash provided by operating activities				$	169,148		$	108,045		$	103,070		$	93,215		$	83,604
	Maintenance capital expenditures					(18,578	)		(21,859	)		(24,890	)		(20,320	)		(18,904	)
	Distributions					(104,412	)		(82,231	)		(69,259	)		(56,774	)		(49,042	)
	Distributions paid per Unit				$	2.15		$	2.00		$	1.85		$	1.75		$	1.55

(1)		Data reflects the commencement of the Midstream Segment, effective September 30, 2001.

(2)		Data reflects the operations of the ARCO assets acquired on July 20, 2000.

(3)		Data reflects the commencement of the Upstream Segment, effective November 1, 1998.

(4)		Extraordinary item reflects the loss related to the early extinguishment of the First Mortgage Notes on January 27, 1998.

(5)

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

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

General

The following information is provided to facilitate increased understanding of the 2001, 2000 and 1999 consolidated financial statements and accompanying notes of the Partnership listed in the Index to Financial Statements on page F-1 of this report. Accounting policies that are among the most critical to the portrayal of the Partnership’s financial condition and results of operations are discussed under “Critical Accounting Policies.” Material period-to-period variances in the consolidated statements of income are discussed under “Results of Operations.” The “Financial Condition and Liquidity” section analyzes cash flows and financial position. Discussion included in “Other Considerations” addresses trends, future plans and contingencies that are reasonably likely to materially affect future liquidity or earnings.

The Partnership operates and reports in three business segments:

	•		Downstream Segment — interstate transportation, storage and terminaling of petroleum products and LPGs, intrastate transportation of petrochemicals and the fractionation of NGLs — conducted primarily through TE Products and its subsidiary;

	•		Upstream Segment — transportation, aggregation and marketing of crude oil and NGLs and the distribution of lube oils and specialty chemicals — conducted primarily through TCTM and its subsidiaries; and

	•		Midstream Segment — gathering of natural gas in the Green River Basin in southwestern Wyoming — conducted primarily through TEPPCO Midstream and its interest in Jonah.

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

The Downstream Segment revenues are derived from the transportation of refined products and LPGs, the storage and short-haul shuttle transportation of LPGs at the Mont Belvieu complex, intrastate transportation of petrochemicals, fractionation of NGLs, sale of product inventory and other ancillary services. Labor and electric power costs comprise the two largest operating expense items of the Downstream Segment. Operations are somewhat seasonal with higher revenues generally realized during the first and fourth quarters of each year. Refined products volumes are generally higher during the second and third quarters because of greater demand for gasolines during the spring and summer driving seasons. LPGs volumes are generally higher from November through March due to higher demand in the Northeast for propane, a major fuel for residential heating.

The Upstream Segment revenues are earned from the gathering, storage, transportation and marketing of crude oil and NGLs and the distribution of lube oils and specialty chemicals, principally in Oklahoma, Texas and the Rocky Mountain region. Marketing operations consist primarily of aggregating purchased crude oil along its pipeline systems, or from third party pipeline systems, and arranging the necessary logistics for the ultimate sale of the crude oil to local refineries, marketers or other end users.

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

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

The Midstream Segment commenced operations on September 30, 2001, when the Partnership acquired Jonah from Alberta Energy Company for $359.8 million. An additional $7.2 million was accrued December 31, 2001, for final purchase adjustments related primarily to construction projects in progress at the time of closing. The acquisition was accounted for under the purchase method of accounting. Accordingly, the results of operations of the acquisition are included in the Partnership’s consolidated financial statements in the fourth quarter of 2001. The Jonah assets are managed and operated by DEFS under a contract arrangement.

Critical Accounting Policies

Estimates

The preparation of financial statements in conformity with generally accepted accounting principles in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. Changes in these estimates could materially affect the financial condition, results of operations or cash flows.

Environmental Costs

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

Property, Plant and Equipment

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

deliveries into the Shreveport market area. The Partnership has evaluated the impact of the contract termination on the pipeline segment from Shreveport to El Dorado, Arkansas, in accordance with SFAS 144. The evaluation did not result in an impairment of the carrying value of the related transportation assets. The termination payment was recorded as refined products transportation revenue in 2001. However, if alternative revenue sources are not realized on this pipeline segment, an impairment may be recorded, which could have a material adverse effect on the Partnership’s financial condition, results of operations or cash flows.

Intangible Assets

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

Results of Operations

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


			Years Ended December 31,

			2001			2000		1999

Operating revenues:
	Downstream Segment		$	271,627		$	236,687	$	230,270
	Midstream Segment			9,146			—		—
	Upstream Segment			3,275,962			2,851,254		1,704,613
	Intercompany eliminations			(322	)		—		—

		Total operating revenues		3,556,413			3,087,941		1,934,883

Operating income:
	Downstream Segment			122,177			89,999		89,393
	Midstream Segment			3,143			—		—
	Upstream Segment			25,669			18,026		10,697

		Total operating income		150,989			108,025		100,090

Net income:
	Downstream Segment			92,080			60,695		61,227
	Midstream Segment			(418	)		—		—
	Upstream Segment			17,469			16,681		10,893

		Total net income	$	109,131		$	77,376	$	72,120

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

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

Downstream Segment

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


										Percentage
			Years Ended December 31,							Increase (Decrease)

			2001			2000		1999		2001			2000

			(in thousands, except tariff information)
Volumes Delivered
	Refined products			122,947			128,151		132,642		(4	)%		(3	)%
	LPGs			39,957			39,633		37,575		1	%		5	%
	Mont Belvieu operations			23,122			27,159		28,535		(15	)%		(5	)%

		Total		186,026			194,943		198,752		(5	)%		(2	)%

Average Tariff per Barrel
	Refined products		$	0.98	(1)	$	0.93	$	0.93		5	%		—
	LPGs			1.95			1.86		1.80		5	%		3	%
	Mont Belvieu operations			0.18			0.16		0.16		13	%		—
		Average system tariff per barrel	$	1.09		$	1.01	$	0.98		8	%		3	%

(1)

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

2001 Compared to 2000

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

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

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

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

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

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

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

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

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

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

2000 Compared to 1999

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

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

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

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

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

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

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

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

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

Upstream Segment

Margin of the Upstream Segment is calculated as revenues generated from the sale of crude oil and lubrication oil, and transportation of crude oil and NGLs, less the costs of purchases of crude oil and lubrication oil. Margin is a more meaningful measure of financial performance than operating revenues and operating expenses due to the significant fluctuations in revenues and expenses caused by variations in the level of marketing activity and prices for products marketed. Margin and volume information for the years ended 2001, 2000 and 1999 is presented below (in thousands, except per barrel and per gallon amounts):


			Years Ended December 31,

			2001		2000		1999

Margins:
	Crude oil transportation		$	34,316	$	23,486	$	17,873
	Crude oil marketing			21,664		13,320		12,065
	Crude oil terminaling			9,769		4,554		—
	NGL transportation			20,935		7,009		6,123
	Lubrication oil sales			4,127		3,503		2,510

		Total margin	$	90,811	$	51,872	$	38,571

Total barrels:
	Crude oil transportation			78,714		46,225		33,267
	Crude oil marketing			159,477		107,607		96,252
	Crude oil terminaling			121,932		56,473		—
	NGL transportation			21,538		5,201		4,580
Lubrication oil volume (total gallons):				8,769		7,974		8,891
Margin per barrel:
	Crude oil transportation		$	0.436	$	0.508	$	0.537
	Crude oil marketing		$	0.136	$	0.124	$	0.125
	Crude oil terminaling		$	0.080	$	0.081		—
	NGL transportation		$	0.972	$	1.348	$	1.337
Lubrication oil margin (per gallon):			$	0.471	$	0.439	$	0.282

2001 Compared to 2000

For the year ended 2001, the Upstream Segment reported net income of $17.5 million, compared with net income of $16.7 million for the year ended 2000. The $0.8 million increase in net income was primarily due to a $38.9 million increase in margin, a $6.4 million increase in other operating revenues, a $6.3 million increase in equity earnings of Seaway, and a $1.5 million increase in other income — net. These increases were partially offset by a $37.7 million increase in costs and expenses (excluding purchases of crude oil and petroleum products) and a $14.7 million increase in interest expense (net of capitalized interest). Factors influencing these variances are described below.

Margin increased $38.9 million during the year ended 2001, compared with 2000. NGL transportation margin increased $13.9 million primarily due to the acquisition of the Panola system on December 31, 2000, and was partially offset by decreased volumes on the Dean pipeline system in South Texas. Crude oil transportation margin increased $10.8 million primarily due to a full year benefit from the ARCO assets acquired in July 2000 and higher volume on the Red River and South Texas systems, which benefited from increased regional crude oil production and pipeline assets acquired from Valero Energy Corp. (formerly Ultramar Diamond Shamrock) (“UDS”), in March 2001. Crude oil marketing margin increased $8.3 million primarily due to volumes transported by Seaway on behalf of the Upstream Segment. The transportation revenues associated with these volumes resulted

in $10.1 million included as a component of crude oil marketing margin when consolidating the Upstream Segment’s equity ownership in Seaway. Lower margins on other crude oil volumes marketed partially offset the increase in crude oil marketing margin. Crude oil terminaling margin increased $5.2 million as a result of pumpover volumes at Midland and Cushing, related to the ARCO assets acquired in July 2000. Margin contributed from lubrication oil sales increased $0.6 million primarily due to increased volumes and increased rates on the margin realized per gallon.

Costs and expenses of the Upstream Segment, excluding expenses associated with purchases of crude oil and petroleum products, increased $37.7 million during the year ended 2001, compared with 2000. The increase was comprised of a $26.9 million increase in operating, general and administrative expenses, a $5.2 million increase in depreciation and amortization expense, a $4.9 million increase in taxes — other than income taxes, and a $0.7 million increase in operating fuel and power expense. The increase in operating, general and administrative expenses was primarily attributable to operating expenses of the acquired assets from ARCO, DEFS and UDS, a $4.4 million expense recorded in 2001 for environmental remediation, a $4.3 million reserve for a doubtful receivable balance under a transportation contract with an Enron Corp. subsidiary, increased labor related costs and increased general and administrative supplies and services expense. The increases in depreciation and amortization expense, taxes — other than income taxes, and operating fuel and power expense were primarily attributable to assets acquired.

Equity earnings in Seaway increased $6.3 million for the year ended 2001, compared with 2000, due to the full year contribution to earnings during 2001. Equity earnings in Seaway will be affected in 2002 as a result of the reduction of the sharing percentages of TCTM under the Seaway partnership agreement. Beginning in June 2002, the Partnership participation in Seaway will decrease from 80% of revenue and expense of Seaway to 60%. See Items 1 and 2. Business and Properties, “Upstream Segment — Transportation and Marketing of Crude Oil and NGL” for a more detailed discussion.

Other operating revenue of the Upstream Segment increased $6.4 million for the year ended 2001, compared with 2000, attributable to revenue from documentation and other services to support customer trading activity at Midland and Cushing. These revenues were added to the Partnership’s business on July 20, 2000, with the acquired ARCO assets.

Interest expense attributable to the Upstream Segment increased $15.1 million for the year ended 2001, compared with 2000, primarily due to interest expense on the term loan and revolving credit facilities used to finance the acquisition of acquired assets in the segment. Interest costs capitalized increased $0.4 million for the year ended 2001, compared with 2000, due to increased balances on construction projects in progress.

2000 Compared to 1999

For the year ended 2000, the Upstream Segment reported net income of $16.7 million, compared with net income of $10.9 million for the year ended 1999. The $5.8 million increase in net income was comprised of a $13.3 million increase in margin, a $4.8 million increase in other operating revenues and $12.2 million of equity earnings of Seaway, partially offset by a $10.8 million increase in costs and expenses (excluding purchases of crude oil and petroleum products) and a $13.6 million increase in interest expense. Factors influencing these variances are described below.

Margin increased $13.3 million for the year ended 2000, compared with 1999. The increase was comprised of a $5.6 million increase in crude oil transportation; a $4.6 million increase in crude oil terminaling attributable to pumpover fees charged at Midland and Cushing, related to the ARCO assets acquired in July 2000; a $1.3 million increase in crude oil marketing activity; a $1.0 million increase in lubrication oil sales; and a $0.9 million increase in NGL transportation. The increase in crude oil transportation margin was primarily attributable to $3.3 million contributed by the ARCO assets acquired and $2.3 million from increased volume and higher transportation rates on the South Texas and Red River systems, which benefited from higher crude oil market prices. The increase in crude oil marketing margin resulted from an increase in volumes marketed and higher sales prices on volumes in third party pipeline systems. Total lubrication oil volumes decreased 10% from the prior year due primarily to the

discontinuation of low margin fuel oil sales, effective April 2000. The increase in NGL transportation margin was attributable to increased volumes and higher prices on loss allowance barrels received on the Dean Pipeline.

Other operating revenue of the Upstream Segment included $4.8 million of revenue related to documentation and other services to support customer trading activity at Midland and Cushing. These revenues were added to the Partnership’s business on July 20, 2000, with the acquired ARCO assets.

Costs and expenses of the Upstream Segment, excluding expenses associated with purchases of crude oil and petroleum products, increased $10.8 million for the year ended 2000, compared with 1999, attributable primarily to $6.9 million in costs and expenses from the acquired ARCO assets and a $3.9 million increase in other operating, general and administrative expenses. The costs and expenses associated with the acquired ARCO assets included $4.3 million in operating, general and administrative expenses, $1.3 million in depreciation and amortization charges, $1.1 million in operating fuel and power and $0.2 million in taxes — other than income taxes. The remaining increase in operating, general and administrative expenses of the Upstream Segment resulted primarily from pipeline system maintenance on the South Texas System in the third quarter, increased labor related costs, additional operating costs associated with asset acquisitions in North Texas and increased general and administrative expenses for telecommunications and contract labor charges.

Net income of the Upstream Segment included $12.2 million of equity earnings in Seaway, which were added to the Partnership’s business on July 20, 2000, with the acquired ARCO assets.

Interest expense attributable to the Upstream Segment increased $13.6 million for the year ended 2000, compared with 1999, primarily due to interest expense on the term loan and revolving credit facilities used to finance the acquisition of the ARCO assets.

Midstream Segment

Three Months Ended December 31, 2001

The Midstream Segment was added to the Partnership’s operations with the purchase of Jonah, effective September 30, 2001. The acquisition was accounted for under the purchase method of accounting. Accordingly, results of operations of the acquisition are only included in the fourth quarter of 2001.

During the three months ended December 31, 2001, net loss of the Midstream Segment totaled $0.4 million. Natural gas gathering revenues totaled $8.8 million from volumes delivered of 45.5 billion cubic feet. An additional $0.3 million was generated from the sale of 16,180 barrels of condensate liquid to an Upstream Segment marketing affiliate. Costs and expenses of the Midstream Segment, which totaled $6.0 million were comprised of $4.5 million of depreciation and amortization expense, $1.4 million of operating, general and administrative expense and $0.1 million of taxes — other than income taxes. Interest expense attributable to the Midstream Segment totaled $3.7 million, partially offset by $0.1 million of interest costs capitalized.

Financial Condition and Liquidity

Net cash from operations for the year ended 2001 totaled $169.2 million, and was comprised of $155.0 million of income before charges for depreciation and amortization, and $14.2 million of cash provided by working capital changes. Net cash from operations for the year ended 2000 totaled $108.0 million, and was comprised of $112.5 million of income before charges for depreciation and amortization, partially offset by $4.5 million of cash used for working capital changes. Net cash from operations for the year ended 1999 totaled $103.1 million, and was comprised of $104.8 million of income before charges for depreciation and amortization, partially offset by $1.7 million of cash used for working capital changes. Net cash from operations for the years ended 2001, 2000, and 1999 included interest payments of $61.5 million, $36.8 million, and $28.6 million, respectively.

Cash flows used in investing activities totaled $557.9 million during the year ended 2001, and was 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 the Partnership’s interest in the Centennial joint venture, $20.0 million for the purchase of crude oil assets from UDS 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 $4.2 million received on matured cash investments and $1.3 million of cash received from the sale of vehicles. Cash flows used in investing activities totaled $494.1 million during the year ended 2000, and was comprised of $322.6 million for the purchase of the ARCO assets, $99.5 million for NGL and crude oil systems purchased in East Texas and North Texas, $68.5 million of capital expenditures, $5.0 million of cash contributions for the Partnership’s interest in the Centennial joint venture, and $2.0 million of cash investments. These uses of cash were partially offset by $3.5 million received from matured cash investments. Cash flows used in investing activities totaled $76.6 million for the year ended 1999, and included $77.4 million of capital expenditures and $2.3 million for the purchase of a 125-mile crude oil system in Southeast Texas, offset by net proceeds from cash investments of $3.0 million. Capital expenditures during the years ended 2000 and 1999 included $29.9 million and $43.8 million, respectively, of spending for construction of the petrochemical pipelines between the Partnership’s terminal in Mont Belvieu and Port Arthur.

In August 2000, TE Products entered into agreements with CMS Energy Corporation and Marathon Ashland Petroleum LLC to form Centennial. TE Products has contributed approximately $65.0 million and $5.0 million during the years ended 2001 and 2000, respectively, for its one-third interest in Centennial. The Partnership expects to contribute an additional $4.9 million to Centennial in 2002. Centennial commenced operations in the first quarter of 2002.

Centennial has entered into credit facilities totaling $150 million. The proceeds were used to fund construction and conversion costs of its pipeline system. As of December 31, 2001, Centennial had borrowed $128 million under its credit facility. TE Products has guaranteed one-third of the debt of Centennial up to a maximum amount of $50 million.

Credit Facilities and Interest Rate Swap Agreements

In July 2000, the Partnership entered into a $75 million term loan and a $475 million revolving credit facility (“Three Year Facility”) and borrowed $75 million and $340 million, respectively, to finance the acquisition of the ARCO assets and to refinance existing bank credit facilities. The term loan was repaid from proceeds received from the issuance of additional Limited Partner Units on October 25, 2000. In April 2001, the Three Year Facility was amended to provide for revolving borrowings of up to $500 million including the issuance of letters of credit of up to $20 million. The term of the revised Three Year Facility was extended to April 6, 2004. The interest rate is based on the Partnership’s option of either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement for the Three Year Facility contains restrictive financial covenants that require the Partnership to maintain a minimum level of partners’ capital as well as maximum debt-to-EBITDA (earnings before interest expense, income tax expense and depreciation and amortization expense) and minimum fixed charge coverage ratios.

In April 2001, the Partnership entered into a 364-day, $200 million revolving credit agreement (“Short-term Revolver”). The interest rate is based on the Partnership’s option of either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement contains restrictive financial covenants that require the Partnership to maintain a minimum level of partners’ capital as well as maximum debt-to-EBITDA and minimum fixed charge coverage ratios. The Partnership has requested an extension of the Short-term Revolver for an additional period of 364 days, commencing on the current termination date in April 2002. Extension of the Short-term Revolver is expected prior to the termination date.

On September 28, 2001, the Three Year Facility and the Short-term Revolver were amended to extend to December 31, 2001, the time period for the maximum debt-to-EBITDA ratio covenant to allow for the additional debt incurred for the acquisition of Jonah. On November 13, 2001, the Three Year Facility and the Short-term Revolver were further amended to require prepayment of outstanding borrowings only upon the receipt of net cash proceeds from asset dispositions or from insurance proceeds in accordance with the terms of the respective

agreements. At such time, certain lenders under the agreements elected to withdraw from the facilities, and the available borrowing capacities were reduced to $411 million and $164 million, respectively. At December 31, 2001 and 2000, $340.7 million and $446 million was outstanding under the Three Year Facility at a weighted average interest rate of 2.9% and 8.23%, respectively, and no letters of credit were outstanding. At December 31, 2001, $160 million, included in current liabilities, was outstanding under the Short-term Revolver at a weighted average interest rate of 2.9%. As of December 31, 2001, the Partnership was in compliance with the covenants contained in the agreements. On January 16, 2002, an additional $25 million was drawn down on the Three Year Facility. On February 20, 2002, the Partnership repaid $115.7 million of the then outstanding balance of the Three Year Facility and all of the then outstanding balance of the Short-term Revolver with proceeds from the issuance by the Partnership of the 7.625% Senior Notes, discussed below.

On September 28, 2001, the Partnership entered into a $400 million credit facility with SunTrust Bank (“Bridge Facility”). The Partnership borrowed $360 million under the Bridge Facility for the acquisition of the Jonah assets. During the fourth quarter of 2001, $160 million of the outstanding principal was repaid from the proceeds received from the issuance of the Limited Partner Units in November 2001. The interest rate is based on the Partnership’s option of either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. At December 31, 2001, $200 million was outstanding under the Bridge Facility at an interest rate of 3.2%. As of December 31, 2001, the Partnership was in compliance with the covenants contained in this credit agreement. On February 5, 2002, an additional $15 million was drawn down on the Bridge Facility. On February 20, 2002, the Partnership repaid the then outstanding balance of the Bridge Facility of $215 million, with proceeds from the issuance by the Partnership of its 7.625% Senior Notes, discussed below, and canceled the remaining commitment.

On February 20, 2002, the Partnership received $494.6 million in net proceeds from the issuance of $500 million principal amount of its 7.625% Senior Notes due 2012. The proceeds from the offering were used to reduce the outstanding balances of the credit facilities, described above, including those issued in connection with the acquisition of Jonah. The Senior Notes may be redeemed at any time at the option of the Partnership 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.

In 2001 and 2000, the Partnership entered into interest rate hedge agreements with notional amounts and expirations related to particular indebtedness, as more fully described in Item 7A, “Quantitative and Qualitative Disclosures About Market Risk.”

On March 1, 2002, the Partnership completed the acquisition of the Chaparral and Quanah pipelines from Diamond-Koch II, L.P. and Diamond-Koch III, L.P. for approximately $132 million. This purchase was funded by a drawdown on the Three Year Facility. The Chaparral system is an 800-mile pipeline that extends from West Texas and New Mexico to Mont Belvieu. The pipeline delivers NGLs to fractionators and existing Partnership storage in Mont Belvieu. The approximately 170-mile Quanah Pipeline is an NGL gathering system located in West Texas. The Quanah Pipeline begins in Sutton County, Texas and connects to the Chaparral Pipeline near Midland. The pipelines are connected to 27 gas plants in West Texas and have approximately 28,000 horsepower of pumping capacity at 14 stations. These systems will be managed and operated by DEFS under a contract arrangement.

The following table summarizes the credit facilities of the Partnership as of December 31, 2001, and March 7, 2002 (in millions):


	As of December 31, 2001					As of March 7, 2002

			Unused				Unused
	Outstanding		Borrowing		Maturity	Outstanding	Borrowing		Maturity
Description:	Principal		Capacity		Date	Principal	Capacity		Date

Short-term Revolver		$160.0	$	4.0	April 2002	$ —	$	164.0	April 2002
Three Year Facility		340.7		70.3	April 2004	382.0		29.0	April 2004
Bridge Facility		200.0		200.0	June 2002	—		—	—(1)
6.45% Senior Notes		180.0		—	January 2008	180.0		—	January 2008
7.51% Senior Notes		210.0		—	January 2028	210.0		—	January 2028
7.625% Senior Notes		—		—	—	500.0		—	January 2012

(1)

The remaining commitment under the Bridge Facility was canceled in February 2002.

Distributions and Issuance of Additional Limited Partner Units

The Partnership paid cash distributions of $104.4 million ($2.15 per Unit), $82.2 million ($2.00 per Unit) and $69.3 million ($1.85 per Unit), for each of the years ended 2001, 2000 and 1999, respectively. Additionally, on January 18, 2002, the Partnership declared a cash distribution of $0.575 per Limited Partner Unit and Class B Unit for the quarter ended December 31, 2001. The distribution of $33.5 million was paid on February 8, 2002, to unitholders of record on January 31, 2002.

On November 20, 2001, the Partnership completed the issuance by public offering of 5.5 million Limited Partner Units at $34.25 per Unit. The net proceeds from the offering totaled approximately $180.1 million and were used to repay $160.0 million under the Bridge Facility that was used to fund the Jonah acquisition. The remaining proceeds were used to finance contributions to Centennial and for other capital expenditures.

On February 6, 2001, the Partnership completed the issuance by public offering of 2.0 million Limited Partner Units at $25.50 per Unit. The net proceeds from the offering totaled approximately $48.5 million and was used to reduce borrowings under the Three Year Facility. On March 6, 2001, 250,000 Units were issued in connection with the over-allotment provision of the offering on February 6, 2001. Proceeds from the Units issued from the over-allotment totaled $6.1 million and were used for general Partnership purposes.

On October 25, 2000, the Partnership completed the issuance by public offering of 3.7 million Limited Partner Units at $25.06 per Unit. The net proceeds from the offering totaled approximately $88.5 million and was used to repay the $75 million principal amount of the term loan and $11 million of the outstanding principal amount of the revolving portion of the Three Year Facility.

Future Capital Needs and Commitments

Capital expenditures for the year ended December 31, 2001, and estimated capital expenditures, excluding acquisitions, for 2002 are described in Items 1 and 2, Business and Properties under the caption “Capital Expenditures.” The Partnership continually reviews and evaluates potential acquisitions, capital improvements and expansions and, to a more limited extent, joint venture opportunities that would be complementary to its present business segments. Should the Partnership elect to pursue any of these transactions, the Partnership will likely need additional capital to fund the purchase price and other capital improvements. These expenditures can vary greatly depending on the magnitude of these transactions by the Partnership. In March 2002, the Partnership completed the acquisition of the Chaparral and Quanah pipelines for approximately $132 million. The purchase was funded by a drawdown on the Three Year Facility.

The Partnerships’ debt repayment obligations consist of payments for principal and interest on (i) outstanding principal amounts under the Three Year Facility due in April 2004 ($382 million at March 7, 2002), (ii) the TE Products Senior Notes, $180 million principal amount due January 15, 2008, and $210 million principal amount due January 15, 2028, and (iii) the Partnership’s $500 million 7.625% Senior Notes due February 15, 2012. Repayment of the long-term, senior unsecured obligations and bank debt is expected to be repaid through issuance of additional long-term senior unsecured debt at the time the 2008, 2012 and 2028 debt matures, issuance of additional equity, proceeds from dispositions of assets, or any combination of the above items.

TE Products is also contingently liable as guarantor for the lesser of one-third or $50 million principal amount (plus interest) of the joint venture borrowings of Centennial. The Partnership expects to contribute an additional $4.9 million to Centennial in 2002. The Partnership does not rely on off-balance sheet borrowings to fund its acquisitions. Other than the limited guarantee of Centennial debt and leases covering assets utilized in several areas of its operations, the Partnership has no off-balance sheet commitments for indebtedness.

The following table summarizes the material contractual obligations of the Partnership as of December 31, 2001, after giving pro forma effect to the issuance and application of net proceeds of the Partnership’s 7.625% Senior Notes due 2012 in February 2002 and additional borrowings in March 2002 to fund the purchase of the Chaparral and Quanah pipelines (in millions).


		Amount of Commitment Expiration Per Period

				Less than						After 5
		Total		1 Year		2-3 Years		4-5 Years		Years

Short-term Revolver(1)		$	160.0	$	160.0	$	—	$	—	$	—
Three Year Facility(2)			340.7		—		340.7		—		—
Bridge Facility			200.0		200.0		—		—		—
6.45% Senior Notes due 2008(3)			180.0		—		—		—		180.0
7.51% Senior Notes due 2028(3)			210.0		—		—		—		210.0
7.625% Senior Notes due 2012(4)			500.0		—		—		—		500.0
Centennial cash contributions			4.9		4.9		—		—		—
Operating leases			36.0		8.8		14.8		11.0		1.4

	Total	$	1,631.6	$	373.7	$	355.5	$	11.0	$	891.4

(1)		Approximately $160 million was paid down in February 2002 from net proceeds from the offering of the Partnership’s 7.625% Senior Notes due 2012.

(2)		Approximately $115.7 million was paid down in February 2002 from net proceeds from the offering of the Partnership’s 7.625% Senior Notes due 2012. Approximately $132 million was subsequently drawn down in March 2002 to fund the purchase of the Chaparral and Quanah pipelines.

(3)		Obligations of TE Products.

(4)		Issued by the Partnership in February 2002.

Sources of Future Capital

Historically, the Partnership has funded its capital commitments from operating cash flow and borrowings under bank credit facilities or bridge loans. These loans were repaid in part by the issuance of long term debt in capital markets and the public offering of Limited Partner Units. The Company expects future capital needs would be similarly funded to the extent not otherwise available from excess cash flow from operations after payment of distributions on Limited Partner Units.

As of March 7, 2002, and after giving effect to borrowings required to fund the acquisition of the Chaparral and Quanah pipelines, the Partnership has approximately $193.0 million in combined available borrowing capacity under the Three Year Facility and the Short-term Revolver.

The Company expects that the Partnership’s cash flow from operating activities will be adequate to fund cash distributions and capital additions necessary to maintain existing operations. However, expansionary capital projects and acquisitions may require funding through proceeds from the sale of additional debt or equity capital markets offerings.

On February 11, 2002, Moody’s Investors Service assigned the Partnership a senior unsecured debt rating, including the rating on its 7.625% Senior Notes, of Baa2 and confirmed the Baa2 senior unsecured rating of the subsidiary, TE Products. These ratings were given with negative outlooks due primarily to Moody’s concerns about current debt levels resulting from financing of the Partnership’s recent acquisitions. Moody’s indicated they may lower the Partnership’s ratings if the Partnership is not successful in reducing its debt to target levels where the Partnership’s debt-to-EBITDA ratio would be below 4 to 1. The Company is evaluating alternatives to lowering its debt-to-EBITDA ratio. Reductions in the Partnership’s credit ratings could increase the debt financing costs or possibly reduce the availability of financing. A rating reflects only the view of a rating agency and is not a recommendation to buy, sell or hold any indebtedness. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant such a change.

Other Considerations

Credit Risks

Risks of nonpayment and nonperformance by customers are a major consideration in the Partnership’s businesses. The credit procedures and policies of the Partnership may not fully eliminate customer credit risk. The bankruptcy of Enron Corp. and certain of its subsidiaries in December 2001 has made collection by the Partnership of a receivable for transportation fees of approximately $4.3 million, or approximately $0.09 per limited partner and Class B Units at December 31, 2001, doubtful.

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 the Partnership’s operations to increased risks. Any terrorist attack on the Partnership’s facilities, customers’ facilities and, in some cases, those of other pipelines, could have a material adverse effect on the Partnership’s business. The Partnership has increased security initiatives and is working with various governmental agencies to minimize risks associated with additional terrorist attacks.

Environmental

The operations of the Partnership are subject to federal, state and local laws and regulations relating to protection of the environment. Although the Partnership believes its operations are in material compliance with applicable environmental regulations, risks of significant costs and liabilities are inherent in pipeline operations, and there can be no assurance that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly strict environmental laws and regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations of the pipeline system, could result in substantial costs and liabilities to the Partnership. The Partnership does not anticipate that changes in environmental laws and regulations will have a material adverse effect on its financial position, results of operations or cash flows in the near term.

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

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

Market-Based Rates

New Accounting Pronouncements

In July 2001, the FASB issued SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets. SFAS 141 requires that the purchase method of accounting be used for all business combinations and specifies that certain acquired intangible assets be reported apart from goodwill. SFAS 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized, but instead tested for impairment at least annually. SFAS 142 requires that intangible assets with definite useful lives be amortized over

their respective estimated useful lives. The Partnership adopted SFAS 141 during 2001, and SFAS 142 effective January 1, 2002. At the date of this report, the Partnership is evaluating the impact of adopting SFAS 142, including whether any transitional impairment losses will be required to be recognized as the cumulative effect of a change in accounting principle. At December 31, 2001, the Partnership had $14.7 million of unamortized goodwill. Amortization expense related to goodwill was $0.9 million and $0.1 million for the years ended December 31, 2001 and 2000, respectively. The goodwill associated with the acquisition of Jonah, which was completed on September 30, 2001, is not being amortized due to the adoption of certain provisions of SFAS 142.

In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS 143 requires the Partnership to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that results from the acquisition, construction, development and/or normal use of the assets. The Partnership also records a corresponding asset, which is depreciated over the life of the asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation will be adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. The Partnership is required to adopt SFAS 143 effective January 1, 2003.

In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS 144 supercedes SFAS No. 121, Accounting for Long-Lived Assets and For Long-Lived Assets to be Disposed Of, but retains its fundamental provisions for reorganizing and measuring impairment losses on long-lived assets held for use and long-lived assets to be disposed of by sale. The Partnership was required to adopt SFAS 144 effective January 1, 2002. The adoption of SFAS 144 did not have a material effect on the financial position, results of operations or cash flows of the Partnership.

Disclosures About Effects of Transactions with Related Parties

The Partnership has no employees and is managed by the Company, a wholly-owned subsidiary of DEFS. Duke Energy holds an approximate 70% interest in DEFS and Phillips 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 the Partnership and DEFS, Duke Energy and Phillips.

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 the Partnership expects or anticipates 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 the Partnership’s 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 the Partnership in light of its experience and its perception of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate under the circumstances. However, whether actual results and developments will conform with the Partnership’s 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 the Partnership, competitive actions by other pipeline companies, changes in laws or regulations, and other factors, many of which are beyond the control of the Partnership. Consequently, all of the forward-looking statements made in this document are qualified by these cautionary statements and there can be no assurance that actual results or developments anticipated by the Partnership will be realized or, even if substantially realized, that they will have the expected consequences to or effect on the Partnership or its business or operations.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

The Partnership may be exposed to market risk through changes in commodity prices and interest rates as discussed below. The Partnership has no foreign exchange risks. Risk management policies have been established for the Partnership by the Company’s Risk Management Committee to monitor and control these market risks. The Risk Management Committee is comprised, in part, of senior executives of the Company.

The Partnership has utilized and expects to continue to utilize derivative financial instruments with respect to a portion of its interest rate and fair value risks and its crude oil marketing activities. These transactions generally are swaps and forwards and are entered into with major financial institutions or commodities trading institutions. The derivative financial instrument related to the Partnership’s interest rate risk is intended to reduce the Partnership’s exposure to increases in the benchmark interest rates underlying the Partnership’s variable rate revolving credit facility. The derivative financial instrument related to the Partnership’s fair value risks is intended to reduce the Partnership’s exposure to changes in the fair value of the fixed rate Senior Notes resulting from changes in interest rates. The Partnership’s Upstream Segment uses derivative financial instruments to reduce the Partnership’s exposure to fluctuations in the market price of crude oil. Gains and losses from financial instruments used in the Partnership’s Upstream Segment have been recognized in revenues for the periods to which the derivative financial instruments relate, and gains and losses from its interest rate financial instruments have been recognized in interest expense for the periods to which the derivative financial instrument relate. As of December 31, 2001, the Upstream Segment had no open positions on derivative financial contracts.

At December 31, 2001, TE Products had outstanding $180 million principal amount of 6.45% Senior Notes due 2008. At December 31, 2001, the estimated fair value was approximately $172 million.

As of December 31, 2001, TE Products had in place 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. The swap agreement has a notional amount of $210 million and matures in January 2028 to match the principal and maturity of the Senior Notes. Under the swap agreement, TE Products pays a floating rate 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 year ended December 31, 2001, the Partnership recognized a gain of $1.8 million, included as a component of interest expense, on the interest rate swap. No gain or loss from ineffectiveness was required to be recognized.

As of December 31, 2001, the Partnership had in place an interest rate swap agreement to hedge its exposure to increases in the benchmark interest rate underlying its variable rate revolving credit facilities. The swap agreement is based on a notional amount of $250 million. Under the swap agreement, the Partnership pays a fixed rate of interest of 6.955% and receives a floating rate based on a three month U.S. Dollar LIBOR rate. The interest rate swap is designated as a cash flow hedge, therefore, 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. During the year ended December 31, 2001, the Partnership recognized $6.8 million in losses, included in interest expense, on the interest rate swap attributable to interest costs occurring in 2001. No gain or loss from ineffectiveness was required to be recognized. The fair value of the interest rate swap agreement was a loss of approximately $20.3 million at December 31, 2001. Approximately $11.7 million of such amount is anticipated to be transferred into earnings over the next twelve months.

Item 8. Financial Statements and Supplementary Data

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

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

None.

PART III

Item 10. Directors and Executive Officers of the Registrant

The Partnership does not have directors or officers. The General Partner manages the Partnership. Officers and directors of the General Partner have management responsibilities with respect to the Partnership. Set forth below is certain information concerning the directors and executive officers of the General Partner. 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.

William L. Thacker, age 56, was elected a director of the General Partner in 1992 and Chairman of the Board in October 1997. Mr. Thacker was elected Chief Executive Officer in January 1994. Mr. Thacker served as President and Chief Operating Officer from September 1992 until February 2001. Prior to joining the Company, Mr. Thacker was president of Unocal Pipeline Company from 1986 until 1992.

Jim W. Mogg, age 53, was elected a director of the General Partner in October 1997 and Vice Chairman of the Board and Chairman of the Compensation Committee in April 2000. Mr. Mogg is chairman, president and chief executive officer of DEFS, having been named to these positions in December 1999. Mr. Mogg also serves as Senior Vice President — Field Services of Duke Energy. Mr. Mogg was previously president of Centana Energy Corporation, a subsidiary of a predecessor of Duke Energy, from 1992 to 1999. Mr. Mogg joined Duke Energy in 1973 in the gas supply department of Panhandle Eastern Pipe Line Company.

Mark A. Borer, age 47, was elected a director of the General Partner in April 2000. Mr. Borer is senior vice president for the Southern Division of DEFS and is also responsible for DEFS’s natural gas liquids marketing organization. He was named to his current 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.

Milton Carroll, age 51, was elected a director of the General Partner in November 1997, is a member of the Compensation Committee and is Chairman of the Audit Committee. Mr. Carroll is the founder, and has been president and chief executive officer of Instrument Products, Inc., a manufacturer of oil field equipment and other precision products, since 1977. Mr. Carroll is a director of Reliant Energy, Inc., Reliant Resources, Inc., Ocean Energy Inc., and Health Care Service Corporation.

Carl D. Clay, age 69, is a director of the General Partner and a member of the Compensation and Audit Committees. He was elected in January 1995. Mr. Clay retired from Marathon Oil Company in 1994 after 33 years of service during which he served as director of transportation and logistics and president of Marathon Pipe Line Company.

Derrill Cody, age 63, is a director of the General Partner having been elected in 1989. He serves on the Compensation Committee and was Chairman of the Audit Committee until April 2000. Mr. Cody is currently of counsel to McKinney and Stringer, P. C., which represents Duke Energy, DEFS and the Partnership 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 1989.

John P. DesBarres, age 62, is a director of the General Partner, having been elected in May 1995. He is a member of the Compensation and Audit Committees. 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., L.L.C., an indirect wholly-owned subsidiary of Penn Virginia Corporation, which is the general partner of Penn Virginia Resource Partners, L.P.

Fred J. Fowler, age 56, was elected a director in November 1998 and served as Vice Chairman of the Board and Chairman of the Compensation Committee until April 2000. Mr. Fowler is group president, energy transmission of Duke Energy. Mr. Fowler joined PanEnergy Corp., a predecessor of Duke Energy, in 1985 and served in a variety of positions in marketing, transportation and exchange. He was appointed group vice president of PanEnergy in 1996. PanEnergy and Duke Power Company merged to form Duke Energy in 1997.

William W. Slaughter, age 54, was elected a director of the General Partner in April 2000. Mr. Slaughter is executive vice president of DEFS. He has been advisor to the chief executive officer of DEFS since January 1999. Mr. Slaughter was vice president of energy services for Duke Energy from 1997 until 1998, and was vice president of corporate strategic planning for PanEnergy and president of PanEnergy International Development Corporation from 1994 to 1997.

Barry R. Pearl, age 52, was elected President and Chief Operating Officer in February 2001. Prior to joining the Company, Mr. Pearl was vice president — finance and administration, treasurer, secretary and chief financial officer of Maverick Tube Corporation since 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, age 53, is Senior Vice President, Chief Financial Officer and Treasurer 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 Treasurer in October 1996.

James C. Ruth, age 54, is Senior Vice President, General Counsel and Secretary of the General Partner, having been elected in February 2001. Mr. Ruth was previously Vice President, General Counsel and Secretary from 1998 until February 2001, and Vice President, General Counsel from 1991 until 1998.

Thomas R. Harper, age 61, is Vice President, Commercial Downstream of the General Partner, having been elected in September 2000. Mr. Harper was previously 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.

David L. Langley, age 54, is Senior Vice President, Corporate Development of the General Partner, having been elected in February 2001. Mr. Langley was previously Vice President, Corporate Development since September 2000, and Vice President, Business Development and LPG Services from 1990 until September 2000. Mr. Langley has been with the Company in various managerial positions since 1975. Mr. Langley will retire effective March 31, 2002, from the General Partner, after 32 years of service.

J. Michael Cockrell, age 55, is Vice President, Commercial Upstream of the General Partner, having been elected in September 2000. Mr. Cockrell was elected Vice President of the General Partner in January 1999 and also serves as President of TEPPCO Crude Oil, L.P. He joined PanEnergy in 1987 and served in a variety of positions in supply and development, including president of Duke Energy Transport and Trading Company.

Leonard W. Mallett, age 45, 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, Engineering, from 1992 until 1994. Mr. Mallett joined the Company in 1979 as an engineer.

Stephen W. Russell, age 50, 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, age 52, 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 positions with ARCO International Oil and Gas Company from October 1996 until January 2000.

John N. Goodpasture, age 53, 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 had spent 19 years in various executive positions at Seagull Energy Corporation (now Ocean Energy, Inc.), 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, age 47, 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.

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, 2001, except for reports covering certain transactions that were filed late by Messrs. Thacker, Carroll, Mallett, Mogg and Owen.

Item 11. Executive Compensation

The officers of the General Partner manage and operate the Partnership’s business. The Partnership does not directly employ any of the persons responsible for managing or operating the Partnership’s operations, but instead reimburses the General Partner for the services of such persons. See Note 4 of the Notes to Consolidated Financial Statements contained elsewhere herein for additional information.

Directors of the General Partner who are neither officers nor employees of either the Company or DEFS receive a stipend of $18,000 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 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 $2,000 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 Limited Partner Units.

Effective April 1, 1999, 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 62.5 Limited Partner 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. Thacker, Mogg, Borer, Fowler and Slaughter were 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.

The following table reflects cash compensation paid or accrued by the General Partner for the years ended December 31, 2001, 2000 and 1999, with respect to its Chief Executive Officer and the four most highly compensated executive officers (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 ($)		($)(3)		($)(4)		($)(5)		($)(6)

William L. Thacker(1)				2001		288,488		204,000		35,260		431,780		27,119
		Chairman and		2000		269,434		149,400		15,200		188,335		25,039
		Chief Executive Officer		1999		261,321		106,100		57,809		133,124		22,924

Barry R. Pearl(2)				2001		190,385		131,900		7,800		—		78,423
	President and Chief			2000		—		—		—		—		—
	Operating Officer			1999		—		—		—		—		—

J. Michael Cockrell				2001		189,504		100,500		32,250		—		10,722
		Vice President		2000		182,021		78,000		30,000		—		14,853
				1999		179,393		51,000		27,750		—		14,064

Charles H. Leonard				2001		170,404		106,700		11,395		46,581		8,347
		Senior Vice President,		2000		155,965		83,400		5,000		52,354		13,818
		Chief Financial Officer		1999		153,507		62,200		—		98,679		12,687
		and Treasurer

James C. Ruth				2001		169,942		103,300		11,395		23,411		6,156
		Senior Vice President and		2000		147,899		76,400		5,000		40,182		13,013
		General Counsel		1999		142,344		57,600		28,904		60,741		11,738

(1)		Mr. Thacker served as President until February 2001.

(2)		Mr. Pearl was elected to his position in February 2001.

(3)		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 table on page 43.

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

(5)		Amounts represent the value of redemptions under the 1996 amendment to the LTICP and credits earned to Performance Unit accounts and options exercised under the terms of 1994 LTIP.

(6)		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 also includes $74,302 of relocation expenses.

Executive Employment Contracts and Termination of Employment Arrangements

On September 1, 1992, William L. Thacker, Jr. and the Company entered into an employment agreement, which set a minimum base salary of $190,000 per year. The Company may terminate the employment agreement for cause, death or disability. In addition, the Company or Mr. Thacker may terminate the agreement upon written notice. Mr. Thacker participates in other Company sponsored benefit plans on the same basis as other senior executives of the Company.

The Company has entered into employment agreements with the 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 2001, 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, Carl D. Clay, 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, Phillips 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 and personal objectives are met each year. The Compensation Committee of the General Partner (the “Committee”) determines at the beginning of each year which employees are eligible to become participants in the MICP. Each participant is assigned a target award by the Committee. Such target award determines the additional compensation to be paid if all Partnership performance and personal objectives are met and all Minimum Quarterly Distributions have been made for the year. The amount of the target awards may range from 10% to 56% of a participant’s base salary. Maximum payout under the MICP is 125% of a participant’s target award. Awards are paid as soon as practicable following approval by the 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 provides for cash credits to participants’ accounts when annual earnings exceed 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 2001 and the value of unexercised Unit options under the 1994 LTIP to the Named Executive Officers as of December 31, 2001. The value assigned to each unexercised, “in the money” option is based on the positive spread between the exercise price of such option and the fair market value of a Limited Partner Unit on December 31, 2001. The fair market value is the average of the high and low prices of a Limited Partner Unit as reported in The Wall Street Journal on the last business day in 2001. In assessing the value,

it should be kept in mind that no matter what theoretical value is placed on an option on a particular date, its ultimate value will be dependent on the market value of the Partnership’s Limited Partner Unit price at a future date. The future value will depend in part on the efforts of the Named Executive Officers to foster the future success of the Partnership for the benefit of all unitholders.

AGGREGATED OPTIONS EXERCISES IN YEAR ENDED DECEMBER 31, 2001 AND
OPTION VALUES AT DECEMBER 31, 2001

Value of

Unexercised

Number of Securities

In-the Money

Underlying Unexercised

Options

Shares

Options at FY-end

at FY-end

Acquired on

Value

Exercisable/

Name

Exercise

Realized

Unexercisable(1)

Unexercisable

Mr. Thacker

52,819

342,687

39,096/16,667

249,536/$79,585

Mr. Leonard

6,000

34,821

16,995/5,333

82,278/25,465

Mr. Ruth

659

11,650

30,065/5,333

222,925/25,465

(1)

Future exercisability of currently unexercisable options depends on the grantee remaining employed by the Company throughout the vesting period of the options, subject to provisions applicable at retirement, death, or total disability.

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 the Partnership’s 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 Limited Partner Units granted under the award multiplied by (3) the average of the closing prices of a Limited Partner 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 the Partnership’s 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 2001 is the three-year period that commenced on January 1, 2001, and ends on December 31, 2003. Each participant’s performance percentage is the result of [(A) minus (B)] multiplied by (C) where (A) is the Economic Value Added for the performance period, (B) is $48,160,000 (which represents the Economic Value Added for the three-year period immediately preceding the performance period) and (C) is 0.000007877. Thus, no amounts will be payable under the 2000 LTIP unless Economic Value Added for the performance period exceeds $48,160,000.

Economic Value Added means the Partnership’s average annual EBITDA for the performance period minus the product of the Partnership’s average asset base and the Partnership’s cost of capital for the performance period. For purposes of the 2000 LTIP, EBITDA means the Partnership’s earnings before interest income and expense, income taxes, depreciation and amortization as presented in the Partnership’s 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. Average asset base means the quarterly average, during the performance period, of the Partnership’s gross property,

plant and equipment, plus products linefill, crude linefill, goodwill, maintenance capital and expansion capital, minus retired capital. The Partnership’s cost of capital is the weighted average cost of the Partnership’s accumulated long and short-term debt for the performance period.

In addition to the payment described above, during the performance period, for so long as the participant is an employee of the General Partner, the General Partner will pay to the Participant the amount of cash distributions the Partnership would have paid to the participant had the participant been the owner of the number of Limited Partner Units equal to the number of phantom Limited Partner Units granted to the participant under this award.

The following table provides information concerning awards under the 2000 LTIP to each of the Named Executive Officers during 2001.

Number

Estimated Future Payouts(1)

Phantom

Performance

Threshold

Target

Maximum

Name

Units

Period

(#)(2)

(#)(3)

(#)(4)

Mr. Thacker

8,800

3 years

13,024

N/A

Mr. Pearl

4,800

3 years

7,104

N/A

Mr. Leonard

2,800

3 years

4,144

N/A

Mr. Ruth

2,800

3 years

4,144

N/A

(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 under the 2000 LTIP unless Economic Value Added for the performance period exceeds $48,160,000.

(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 39 percent increase in Economic Value Added for 2001 as compared with 2000 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)		There is no maximum limitation on potential payouts under the 2000 LTIP.

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 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. In addition, the Named Executive Officers participate 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.

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 ($84,900 for 2002). 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: William L. Thacker, $165,772; Barry R. Pearl, $55,328; J. Michael Cockrell, $44,441; Charles H. Leonard, $105,907; and James C. Ruth, $182,676. Such estimates were calculated assuming interest credits at a rate of 7% per annum and using a future Social Security taxable wage base equal to $84,900.

Item 12. Security Ownership of Certain Beneficial Owners and Management

(a) Security Ownership of Certain Beneficial Owners

As of March 7, 2002, Duke Energy, through its ownership of the Company and other subsidiaries, owns 2,500,000 Limited Partner Units, representing 6.2% of the Limited Partner Units outstanding; and 3,916,547 Class B Units, representing 100% of the Class B Units, or 8.8% of the two classes of Units combined. No other person is known by the Partnership to own more than 5% of the outstanding Units of the Partnership.

(b) Security Ownership of Management

The following table sets forth certain information, as of March 7, 2002, concerning the beneficial ownership of Limited Partner 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. Such information is based on data furnished by the persons named. Based on information furnished to the General Partner by such persons, no director or officer of the General Partner owned beneficially, as of March 7, 2002, more than 1% of the 40.5 million Limited Partner Units outstanding at that date.


	Number of
Name	Units(1)

Mark A. Borer		1,000
Milton Carroll		542
Carl D. Clay(2)		3,200
J. Michael Cockrell		5,000
Derrill Cody		13,000
John P. DesBarres		20,000
Fred J. Fowler(3)		3,100
Charles H. Leonard		406
Jim W. Mogg(4)		3,449
Barry R. Pearl		5,000
James C. Ruth		3,643
William W. Slaughter		8,000
William L. Thacker		37,987
All directors and officers (consisting of 23 people, including those named above)		133,239

(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 1,800 Units in wife’s name.

(3)		Includes 200 Units owned by son.

(4)		Includes 2,227 Units held in trust accounts for daughters.

Item 13. Certain Relationships and Related Transactions

Management of the Partnership

The Partnership has no employees and is managed by the Company, a wholly-owned subsidiary of DEFS. Duke Energy holds an approximate 70% interest in DEFS and Phillips holds the remaining 30%. According to the Partnership Agreements, the Company is entitled to reimbursement of all direct and indirect expenses related to business activities of the Partnership.

For the years ended December 31, 2001, 2000, and 1999, direct expenses incurred by the Company in the amount of $68.2 million, $50.4 million, and $49.6 million, respectively, were charged to the Partnership. Substantially all such costs were related to payroll and payroll related expenses. For the years ended December 31, 2001, 2000, and 1999, expenses for administrative service and overhead allocated to the Partnership by Duke Energy and its affiliates amounted to $0.6 million, $0.8 million, and $2.1 million, respectively.

Transactions with DEFS

Effective with the purchase of the fractionation facilities on March 31, 1998, TE Products and DEFS entered into a 20-year Fractionation Agreement, under which TE Products receives a variable fee for all fractionated volumes delivered to DEFS. Revenues recognized from the fractionation facilities totaled $7.4 million, $7.5 million and $7.3 million for the years ended December 31, 2001, 2000 and 1999, respectively. TE Products and DEFS also entered into an Operation and Maintenance Agreement, whereby DEFS operates and maintains the fractionation facilities. For these services, TE Products 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, $0.9 million and $0.8 million for the years ended December 31, 2001, 2000 and 1999, respectively.

Included with certain crude oil assets purchased from DEFS effective November 1, 1998, was the Wilcox NGL Pipeline located along the Texas Gulf Coast. The Wilcox NGL Pipeline transports NGLs for DEFS from two of their processing plants and is currently supported by a throughput agreement with DEFS through 2005. The fees on the agreement totaled $1.2 million, $1.1 million and $1.1 million for the years ended December 31, 2001, 2000 and 1999, respectively.

Effective May 2001, the Company entered into an agreement with DEFS to commit sole utilization of the Providence terminal to DEFS. The terminal is operated by the Partnership. During the year ended December 31, 2001, DEFS paid the Partnership $1.5 million pursuant to this agreement.

On September 30, 2001, the Partnership completed the acquisition of Jonah. The Jonah assets are managed and operated by DEFS under a contractual arrangement under which DEFS is reimbursed for its actual costs. Certain employees of DEFS also act as officers of TEPPCO GP in order to facilitate management of the Jonah assets by DEFS. These DEFS employees receive no additional compensation from the Partnership for these activities. During the year ended 2001, the Partnership recognized $0.6 million of expense related to the management of the Jonah assets by DEFS.

Interest in Seaway

On July 20, 2000, the Partnership, through TCTM, acquired a 50-percent ownership interest in Seaway. Phillips owns the remaining 50% interest in Seaway. The Partnership is the operator of this pipeline. During the years ended 2001 and 2000, the Partnership billed to Seaway $7.0 million and $2.9 million, respectively, for direct payroll and payroll related expenses for operating Seaway. Additionally, during the years ended 2001 and 2000, the Partnership billed to Seaway $2.1 million and $0.9 million, respectively, for indirect management fees for operating Seaway.

Interest of the General Partner in the Partnership

The Partnership makes quarterly cash distributions of all of its 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 on the portion that cash distributions on a per Unit basis 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 2001, incentive distributions paid to the General Partner totaled $20.3 million.

Interests of Duke Energy in the Partnership

In addition to its indirect ownership of the General Partner through its approximately 70% interest in DEFS, Duke Energy also holds, through wholly-owned subsidiaries, Limited Partner Units of the Partnership.

In connection with the formation of the Partnership in 1990, the Company received 2,500,000 Deferred Partnership Interests (“DPIs”). Effective April 1, 1994, all DPIs began participating in distributions of cash and allocations of profit and loss in a manner identical to Limited Partner Units and were converted into an equal number of Limited Partner Units. 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 its Partnership Agreement, the

Partnership has registered the resale by Duke Energy of such Limited Partner Units with the Securities and Exchange Commission. As of December 31, 2001, no such Limited Partner Units had been sold by Duke Energy.

At December 31, 2001, Duke Energy also held 3,916,547 Class B Units. The Class B Units share in income and distributions on the same basis as the Limited Partner Units, but they are not listed on the New York Stock Exchange. The Class B Units may be converted into Limited Partner Units upon approval by the unitholders. The Company has the option to seek approval for the conversion of the Class B Units into Limited Partner Units; however, if the conversion is denied, Duke Energy, as holder of the Class B Units, will have the right to sell them to the Partnership at 95.5% of the then current market price of the Limited Partner Units.

PART IV

Item 14. 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.

(a)

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).
10.1+		Texas Eastern Products Pipeline Company 1997 Employee Incentive Compensation Plan executed on July 14, 1997 (Filed as Exhibit 10 to Form 10-Q of TEPPCO Partners, L.P.


		(Commission File No. 1-10403) for the quarter ended September 30, 1997 and incorporated herein by reference).
10.2+		Texas Eastern Products Pipeline Company Management Incentive Compensation Plan executed on January 30, 1992 (Filed as Exhibit 10 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1992 and incorporated herein by reference).
10.3+		Texas Eastern Products Pipeline Company Long-Term Incentive Compensation Plan executed on October 31, 1990 (Filed as Exhibit 10.9 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1990 and incorporated herein by reference).
10.4+		Form of Amendment to Texas Eastern Products Pipeline Company Long-Term Incentive Compensation Plan (Filed as Exhibit 10.7 to the Partnership’s Form 10-K (Commission File No. 1-10403) for the year ended December 31, 1995 and incorporated herein by reference).
10.5+		Duke Energy Corporation Executive Savings Plan (Filed as Exhibit 10.7 to the Partnership’s Form 10-K (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).
10.6+		Duke Energy Corporation Executive Cash Balance Plan (Filed as Exhibit 10.8 to the Partnership’s Form 10-K (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).
10.7+		Duke Energy Corporation Retirement Benefit Equalization Plan (Filed as Exhibit 10.9 to the Partnership’s Form 10-K (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).
10.8+		Employment Agreement with William L. Thacker, Jr. (Filed as Exhibit 10 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1992 and incorporated herein by reference).
10.9+		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).
10.10+		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).
10.11		Asset Purchase Agreement between Duke Energy Field Services, Inc. and TEPPCO Colorado, LLC, dated March 31, 1998 (Filed as Exhibit 10.14 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).
10.12		Contribution Agreement between Duke Energy Transport and Trading Company and TEPPCO Partners, L.P., dated October 15, 1998 (Filed as Exhibit 10.16 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).
10.13		Guaranty Agreement by Duke Energy Natural Gas Corporation for the benefit of TEPPCO Partners, L.P., dated November 30, 1998, effective November 1, 1998 (Filed as Exhibit 10.17 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).
10.14		Letter Agreement regarding Payment Guarantees of Certain Obligations of TCTM, L.P. between Duke Capital Corporation and TCTM, L.P., dated November 30, 1998 (Filed as Exhibit 10.19 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).
10.15+		Form of Employment Agreement between the Company and Thomas R. Harper, David L. Langley, 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).


10.16		Agreement Between Owner and Contractor between TE Products Pipeline Company, Limited Partnership and Eagleton Engineering Company, dated February 4, 1999 (Filed as Exhibit 10.21 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).
10.17		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).
10.18		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).
10.19+		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).
10.20+		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).
10.21+		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).
10.22+		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).
10.23+		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).
10.24		Credit Agreement between TEPPCO Partners, L.P., SunTrust Bank, and Certain Lenders, dated July 14, 2000 (Filed as Exhibit 10.31 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2000 and incorporated herein by reference).
10.25		Amended and Restated Purchase Agreement By and Between Atlantic Richfield Company and Texas Eastern Products Pipeline Company With Respect to the Sale of ARCO Pipe Line Company, dated as of May 10, 2000. (Filed as Exhibit 2.1 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2000 and incorporated herein by reference).
10.26+		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).
10.27+		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).
10.28+		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).
10.29		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).


10.30		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).
10.31		Purchase and Sale Agreement By and Among Green River Pipeline, LLC and McMurry Oil Company, Sellers, and TEPPCO Partners, L.P., Buyer, dated as of September 7, 2000. 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).
10.32		Credit Agreement Among TEPPCO Partners, L.P. as Borrower, SunTrust Bank, as Administrative Agent and Certain Lenders, dated as of September 28, 2001 ($400,000,000 Term Facility) (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, 2001 and incorporated herein by reference).
10.33		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).
10.34		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).
10.35*		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).
10.36*		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).
10.37		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).
10.38		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).
10.39		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).
10.40*		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.
10.41*		Unanimous Written Consent of the Board of Directors of TEPPCO GP, Inc. dated February 13, 2002.
12.1*		Statement of Computation of Ratio of Earnings to Fixed Charges.
21*		Subsidiaries of the Partnership.
23*		Consent of KPMG LLP.
24*		Powers of Attorney.

*		Filed herewith.

+		A management contract or compensation plan or arrangement.

(b)

Reports on Form 8-K filed during the quarter ended December 31, 2001:


	Reports on Form 8-K were filed on October 15, 2001, November 9, 2001, November 13, 2001, November 19, 2001, and November 30, 2001.

SIGNATURES

TEPPCO Partners, L.P., pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	TEPPCO Partners, L.P. (Registrant) (A Delaware Limited Partnership)

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

	By: /s/ WILLIAM L. THACKER William L. Thacker, Chairman and Chief Executive Officer

	By: /s/ CHARLES H. LEONARD Charles H. Leonard, Senior Vice President, Chief Financial Officer and Treasurer

Dated: March 14, 2002

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 date indicated.


Signature WILLIAM L. THACKER* William L. Thacker	Title Chairman of the Board and Chief Executive Officer of Texas Eastern Products Pipeline Company, LLC	Date March 14, 2002

CHARLES H. LEONARD Charles H. Leonard	Senior Vice President, Chief Financial Officer and Treasurer of Texas Eastern Products Pipeline Company, LLC (Principal Accounting and Financial Officer)	March 14, 2002

JIM W. MOGG* Jim W. Mogg	Vice Chairman of the Board of Texas Eastern Products Pipeline Company, LLC	March 14, 2002

MARK A. BORER * Mark A. Borer	Director of Texas Eastern Products Pipeline Company, LLC	March 14, 2002

MILTON CARROLL* Milton Carroll	Director of Texas Eastern Products Pipeline Company, LLC	March 14, 2002

CARL D. CLAY* Carl D. Clay	Director of Texas Eastern Products Pipeline Company, LLC	March 14, 2002

DERRILL CODY* Derrill Cody	Director of Texas Eastern Products Pipeline Company, LLC	March 14, 2002

JOHN P. DESBARRES* John P. DesBarres	Director of Texas Eastern Products Pipeline Company, LLC	March 14, 2002

FRED J. FOWLER* Fred J. Fowler	Director of Texas Eastern Products Pipeline Company, LLC	March 14, 2002

WILLIAM W. SLAUGHTER* William W. Slaughter	Director of Texas Eastern Products Pipeline Company, LLC	March 14, 2002

* 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

Independent Auditors’ Report		F-2
Consolidated Balance Sheets as of December 31, 2001 and 2000		F-3
Consolidated Statements of Income for the years ended December 31, 2001, 2000 and 1999		F-4
Consolidated Statements of Cash Flows for the years ended December 31, 2001, 2000 and 1999		F-5
Consolidated Statements of Partners’ Capital for the years ended December 31, 2001, 2000 and 1999		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, 2001 and 2000, 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, 2001. 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, 2001 and 2000, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2001, 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 July 1, 2001, adopted the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 141, Business Combinations, and certain provisions of SFAS No. 142, Goodwill and Other Intangible Assets.

KPMG LLP

Houston, Texas
January 17, 2002

F-2

TEPPCO PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS
(in thousands)


					December 31,

					2001			2000

				ASSETS
Current assets:
	Cash and cash equivalents				$	25,479		$	27,096
	Accounts receivable, trade					221,541			303,394
	Accounts receivable, related party					4,310			—
	Inventories					17,243			24,784
	Other					14,907			8,123

				Total current assets		283,480			363,397

Property, plant and equipment, at cost (Net of accumulated depreciation and amortization of $290,248 and $251,165)						1,180,461			949,705
Equity investments						292,224			241,648
Intangible assets						253,413			34,174
Goodwill						14,743			4,214
Other assets						41,027			29,672

				Total assets	$	2,065,348		$	1,622,810

		LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
	Notes payable				$	360,000		$	—
	Accounts payable and accrued liabilities					228,075			293,720
	Accounts payable, general partner					22,680			6,637
	Accrued interest					15,649			18,633
	Other accrued taxes					8,888			10,501
	Other					33,550			28,780

			Total current liabilities			668,842			358,271

Senior Notes						389,814			389,784
Other long-term debt						340,658			446,000
Other liabilities and deferred credits						17,223			3,991
Minority interest						—			4,296
Redeemable Class B Units held by related party						105,630			105,411
Commitments and contingencies Partners’ capital:
	Accumulated other comprehensive loss					(20,324	)		—
	General partner’s interest					13,190			1,824
	Limited partners’ interests					550,315			313,233

				Total partners’ capital		543,181			315,057

				Total liabilities and partners’ capital	$	2,065,348		$	1,622,810

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,

			2001			2000			1999

Operating revenues:
	Sales of crude oil and petroleum products		$	3,219,816		$	2,821,943		$	1,692,767
	Transportation — refined products			139,315			119,331			123,004
	Transportation — LPGs			77,823			73,896			67,701
	Transportation — crude oil and NGLs			44,925			24,533			11,846
	Gathering — natural gas			8,824			—			—
	Mont Belvieu operations			14,116			13,334			12,849
	Other			51,594			34,904			26,716

		Total operating revenues		3,556,413			3,087,941			1,934,883

Costs and expenses:
	Purchases of crude oil and petroleum products			3,173,607			2,794,604			1,666,042
	Operating, general and administrative			135,253			104,918			94,340
	Operating fuel and power			36,575			34,655			31,265
	Depreciation and amortization			45,899			35,163			32,656
	Taxes — other than income taxes			14,090			10,576			10,490

		Total costs and expenses		3,405,424			2,979,916			1,834,793

		Operating income		150,989			108,025			100,090
Interest expense				(66,057	)		(48,982	)		(31,563	)
Interest capitalized				4,000			4,559			2,133
Equity earnings				17,398			12,214			—
Other income — net				3,601			2,349			2,196

		Income before minority interest		109,931			78,165			72,856
Minority interest				(800	)		(789	)		(736	)

		Net income	$	109,131		$	77,376		$	72,120

Net income allocated to Limited Partner Unitholders				76,986			56,091			55,349
Net income allocated to Class B Unitholder				8,642			7,385			7,475
Net income allocated to General Partner				23,503			13,900			9,296

		Total net income allocated	$	109,131		$	77,376		$	72,120

Basic and diluted net income per Limited Partner and Class B Unit			$	2.18		$	1.89		$	1.91

Weighted average Limited Partner and Class B Units outstanding				39,258			33,594			32,917

See accompanying Notes to Consolidated Financial Statements.

F-4

TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)


				Years Ended December 31,

				2001			2000			1999

Cash flows from operating activities:
	Net income			$	109,131		$	77,376		$	72,120
	Adjustments to reconcile net income to cash provided by operating activities:
		Depreciation and amortization			45,899			35,163			32,656
		Equity in earnings, net of distributions			14,377			(10,084	)		393
		Non-cash portion of interest expense			4,053			2,218			337
		Decrease (increase) in accounts receivable			81,190			(90,006	)		(92,225	)
		Decrease (increase) in inventories			7,541			(7,567	)		1,037
		Decrease (increase) in other current assets			(8,082	)		1,165			(2,500	)
		Increase (decrease) in accounts payable and accrued expenses			(71,757	)		106,662			93,317
		Other			(13,204	)		(6,882	)		(2,065	)

			Net cash provided by operating activities		169,148			108,045			103,070

Cash flows from investing activities:
	Proceeds from cash investments				4,236			3,475			6,275
	Purchases of cash investments				—			(2,000	)		(3,235	)
	Purchase of ARCO assets				(11,000	)		(322,640	)		—
	Purchase of Jonah Gas Gathering Company				(359,834	)		—			—
	Purchase of crude oil assets and NGL system				(20,000	)		(99,508	)		(2,250	)
	Proceeds from the sale of assets				1,300			—			—
	Investment in Centennial Pipeline, LLC				(64,953	)		(5,040	)		—
	Capital expenditures				(107,614	)		(68,481	)		(77,431	)

			Net cash used in investing activities		(557,865	)		(494,194	)		(76,641	)

Cash flows from financing activities:
	Proceeds from term and revolving credit facilities				546,148			552,000			33,000
	Repayments on term and revolving credit facilities				(291,490	)		(172,000	)		(5,000	)
	Debt issuance cost				(2,601	)		(7,074	)		—
	Issuance of Limited Partner Units, net				234,660			88,158			—
	General partner’s contributions				4,795			1,799			—
	Distributions				(104,412	)		(82,231	)		(69,259	)

			Net cash provided by (used in) financing activities		387,100			380,652			(41,259	)

Net decrease in cash and cash equivalents					(1,617	)		(5,497	)		(14,830	)
Cash and cash equivalents at beginning of period					27,096			32,593			47,423

Cash and cash equivalents at end of period				$	25,479		$	27,096		$	32,593

Supplemental disclosure of cash flows:
	Interest paid during the year (net of capitalized interest)			$	61,458		$	36,793		$	28,625

See accompanying Notes to Consolidated Financial Statements.

F-5

TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(in thousands)


								Accumulated
		General			Limited			Other
		Partner's			Partners'			Comprehensive
		Interest			Interests			Loss			Total

Partners’ capital (deficit) at December 31, 1998		$	(380	)	$	227,566		$	—		$	227,186
	1999 net income allocation		9,296			55,349			—			64,645
	1999 cash distributions		(8,259	)		(53,650	)		—			(61,909	)
	Option exercises, net of Unit repurchases		—			(155	)		—			(155	)

Partners’ capital at December 31, 1999			657			229,110			—			229,767
	Capital contributions		890			—			—			890
	Issuance of Limited Partner Units, net		—			88,158			—			88,158
	2000 net income allocation		13,900			56,091			—			69,991
	2000 cash distributions		(13,623	)		(59,943	)		—			(73,566	)
	Option exercises, net of Unit repurchases		—			(183	)		—			(183	)

Partners’ capital at December 31, 2000			1,824			313,233			—			315,057
	Capital contributions		4,795			—			—			4,795
	Issuance of Limited Partner Units, net		—			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 hedges		—			—			(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		$	13,190		$	550,315		$	(20,324	)	$	543,181

See accompanying Notes to Consolidated Financial Statements.

F-6

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. PARTNERSHIP ORGANIZATION

At formation in 1990, the Partnership completed an initial public offering of 26,500,000 Units representing Limited Partner Interests (“Limited Partner Units”) at $10 per Unit. In connection with the formation of the Partnership, 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 and are treated as Limited Partner Units for purposes of this Report. The Partnership has registered the resale of such Limited Partner Units with the Securities and Exchange Commission. As of December 31, 2001, no such Limited Partner Units had been sold by Duke Energy.

At December 31, 2001 and 2000, the Partnership had outstanding 40,450,000 and 32,700,000 Limited Partner Units and 3,916,547 and 3,916,547 Class B Limited Partner Units (“Class B Units”), respectively. All of the Class B Units were issued to Duke Energy in connection with an acquisition of assets initially acquired in the Upstream Segment in 1998. The Class B Units share in income and distributions on the same basis as the Limited Partner Units, but they are not listed on the New York Stock Exchange. The Class B Units may be converted into Limited Partner Units upon approval by the unitholders. The Company has the option to seek approval for the conversion of the Class B Units into Limited Partner Units; however, if the conversion is denied, Duke Energy, as holder of the Class B Units, will have the right to sell them to the Partnership at 95.5% of the then current market price of the Limited Partner Units. As a result of this option, the Class B Units were not included in partners’ capital at December 31, 2001 and 2000. Collectively, the Limited Partner Units and Class B Units are referred to as “Units.”

F-7

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The financial statements include the accounts of the Partnership 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. All significant intercompany items have been eliminated in consolidation. Certain amounts from prior years have been reclassified to conform to current presentation.

Use of Estimates

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

Environmental Expenditures

Business Segments

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

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

F-8

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Revenue Recognition

Revenues of the Downstream Segment are derived from interstate and intrastate transportation of petroleum products, storage and terminaling of petroleum products, intrastate transportation of petrochemicals, fractionation of natural gas liquids 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. Fractionation revenues are recognized ratably over the contract year as products are delivered to DEFS.

Revenues of the Upstream Segment are derived from the gathering, storage, transportation and marketing of crude oil and NGLs; and the distribution of lube oils and specialty chemicals in Colorado, Oklahoma, Kansas, New Mexico, Texas and Louisiana. Revenues are also generated from trade documentation and pumpover services, primarily at Cushing, Oklahoma, and Midland, Texas (effective July 20, 2000). 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 the Partnership’s crude oil marketing company, TEPPCO Crude Oil, L.P., which typically occurs upon receipt of the product by the Partnership. Revenues related to trade documentation and pumpover services are recognized as completed.

Revenues of the Midstream Segment are derived from the gathering of natural gas in the Green River Basin in southwestern Wyoming. Revenues are recognized as natural gas is delivered to customers. Revenues are earned from gathering fees based upon the volume and pressure of natural gas gathered on the Jonah Gas Gathering System (“Jonah System”). Revenues are also earned from the sale of condensate liquid extracted from the natural gas stream to an Upstream marketing affiliate. The Partnership does not take title to the natural gas gathered on the Jonah System, therefore, the results of the Jonah System are not directly affected by changes in the prices of natural gas or other commodities.

Except for crude oil purchased from time to time as inventory, the Partnership’s policy is to purchase only crude oil for which it has a market to sell and to structure sales contracts so that crude oil price fluctuations do not materially affect the margin received. As the Partnership purchases crude oil, it establishes a margin by selling crude oil for physical delivery to third party users or by entering into a future delivery obligation either physically or a futures contract on the New York Mercantile Exchange (“NYMEX”). Through these transactions, the Partnership seeks 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.

Use of Derivatives

Effective January 1, 2001, the Partnership adopted Statement of Financial Accounting Standards (“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. Special accounting for derivatives qualifying as fair value hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of income. For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the

F-9

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. 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. Any change in fair value resulting from ineffectiveness, as defined by SFAS 133, is recognized immediately in earnings.

Adoption of SFAS 133 at January 1, 2001, 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 being transferred to earnings as the forecasted transactions actually occur. Amounts were determined as of January 1, 2001, based on the market quote of the Partnership’s interest swap agreement in place at the time of adoption.

The Partnership has utilized and expects to continue to utilize derivative financial instruments with respect to a portion of its interest rate and fair value risks and its crude oil marketing activities, as each is explained below. The derivative financial instrument related to the Partnership’s interest rate risk is intended to reduce the Partnership’s exposure to increases in the benchmark interest rates underlying the Partnership’s variable rate revolving credit facility. The derivative financial instrument related to the Partnership’s fair value risks is intended to reduce the Partnership’s exposure to changes in the fair value of the fixed rate Senior Notes resulting from changes in interest rates. The Partnership’s Upstream Segment uses derivative financial instruments to reduce the Partnership’s exposure to fluctuations in the market price of crude oil. By using derivative financial instruments to hedge exposures to changes in interest rates, fair value of fixed rate Senior Notes and crude oil prices, the Partnership exposes itself 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 the Partnership, which creates credit risk for the Partnership. When the fair value of a derivative contract is negative, the Partnership owes the counterparty and, therefore, it does not possess credit risk. The Partnership minimizes the credit risk in derivative instruments by entering into transactions with major financial institutions or commodities trading institutions. These derivative financial instruments generally take the form of swaps and forward contracts. Market risk is the adverse effect on the value of a financial instrument that results from a change in interest rates or commodity prices. The market risk associated with interest-rate and commodity-price contracts is managed by establishing and monitoring parameters that limit the type and degree of market risk that may be undertaken.

At December 31, 2001, the Upstream Segment had no open positions on derivative financial contracts.

As of December 31, 2001, the Partnership had in place an interest rate swap agreement to hedge its exposure to increases in the benchmark interest rate underlying its variable rate revolving credit facilities. The Partnership has 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 million. Under the swap agreement, the Partnership pays a fixed rate of interest of 6.955% and receives 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. During the year ended December 31, 2001, the Partnership recognized $6.8 million in losses, included in interest expense, on the interest rate swap attributable to interest costs occurring in 2001. No gain or loss from ineffectiveness was required to be recognized. The fair value of the interest rate swap agreement was a loss of approximately $20.3 million at December 31, 2001. Approximately $11.7 million of such amount is anticipated to be transferred into earnings over the next twelve months.

F-10

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As of December 31, 2001, TE Products also had in place 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. The Partnership has designated this swap agreement, which hedges exposure to changes in the fair value of the TE Products Senior Notes, as a fair value hedge. The swap agreement has a notional amount of $210 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 based on a three month U.S. Dollar LIBOR rate, plus a spread, and receives a fixed rate of interest of 7.51%. Since this swap is designated as a fair value hedge, the changes in fair value are recognized in current earnings. During the year ended December 31, 2001, the Partnership recognized a gain of $1.8 million, included as a component of interest expense, on the interest rate swap. No gain or loss from ineffectiveness was required to be recognized.

During 2001, the Partnership entered into treasury rate lock agreements with a combined notional amount of $400 million to hedge its exposure to increases in the treasury rate that was to be used to establish the fixed interest rate for an anticipated debt offering planned to occur in the fourth quarter of 2001. The debt offering did not occur in 2001. Under the treasury rate lock agreements, the Partnership would pay a fixed rate of interest, and would receive a floating rate based on the three month treasury rate. The treasury rate locks were designated as cash flow hedges. As a result, the changes in fair value, to the extent the treasury rate locks were effective, would be recognized in other comprehensive income until the actual debt offering occurred. Upon completion of the debt offering, the realized gain or loss on the treasury rate locks would be amortized out of accumulated other comprehensive income into interest expense over the life of the debt obligation. During April 2001, a treasury lock with a notional amount of $200 million was terminated and a gain of $1.1 million was realized. The realized gain was recorded as a component of accumulated other comprehensive income. During December 2001, the remaining treasury lock with a notional amount of $200 million was terminated resulting in a realized loss of $1.1 million. The realized loss was recorded as a component of interest expense. The realized gain recorded in April 2001 to accumulated other comprehensive income was reclassified to interest expense in December, upon termination of the treasury lock agreement.

Inventories

Inventories consist primarily of petroleum products and crude oil which are valued at the lower of cost (weighted average cost method) or market. The 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.

Property, Plant and Equipment

Additions to property, plant and equipment, including major replacements or betterments, are recorded at cost. Replacements and renewals of minor items of property are charged to maintenance expense. Depreciation expense is computed on the straight-line method using rates based upon expected useful lives of various classes of assets (ranging from 2% to 20% per annum). Upon sale or retirement of properties regulated by the FERC, cost less salvage is normally charged to accumulated depreciation, and no gain or loss is recognized.

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 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.

F-11

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Capitalization of Interest

The Partnership capitalizes 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 6.46%, 7.45% and 7.01% for 2001, 2000 and 1999, respectively. During the years ended December 31, 2001, 2000 and 1999, the amount of interest capitalized was $4.0 million, $4.6 million and $2.1 million, respectively.

Intangible Assets

Intangible assets at December 31, 2001, consist primarily of production contracts assumed in the acquisition of Jonah Gas Gathering Company (“Jonah”) on September 30, 2001, and the fractionation agreement with DEFS. In connection with the acquisition of Jonah, the Partnership assumed contracts that dedicate future production from natural gas wells in the Green River Basin in the State of Wyoming (see Note 3. Acquisitions). 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. The value assigned to intangible assets are amortized over the expected lives of the contracts (approximately 16 years) in proportion to the timing of the expected contractual volumes. At December 31, 2001, the unamortized balance of these production contracts was $219.5 million.

The fractionation agreement with DEFS was entered into in 1998 and is being amortized over a period of 20 years. At December 31, 2001, the unamortized balance of this agreement was $30.9 million. (See Note 4. Related Party Transactions.)

Goodwill

Goodwill, which represents the excess of purchase price over fair value of net assets acquired, is amortized on a straight-line basis over the expected periods to be benefited, generally 20 years. Goodwill is presented on the consolidated balance sheets net of accumulated amortization. At December 31, 2001 and 2000, the Partnership had $14.7 million and $4.2 million, respectively, of unamortized goodwill. Amortization expense related to goodwill was $0.9 million and $0.1 million for the years ended December 31, 2001 and 2000, respectively.

In July 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 142, Goodwill and Other Intangible Assets. SFAS 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized, but instead tested for impairment at least annually. SFAS 142 requires that intangible assets with definite useful lives be amortized over their respective estimated useful lives. The Partnership adopted SFAS 142 effective January 1, 2002. At the date of this report, the Partnership is evaluating the impact of adopting SFAS 142, including whether any transitional impairment losses will be required to be recognized as the cumulative effect of a change in accounting principle. Beginning January 1, 2002, effective with the adoption of SFAS 142, the Partnership will no longer record amortization expense related to goodwill. The goodwill associated with the acquisition of Jonah, which was completed on September 30, 2001, is not being amortized due to the adoption of certain provisions of SFAS 142 (see Note 2. New Accounting Pronouncements).

Income Taxes

The Partnership is a limited partnership. As a result, the Partnership’s income or loss for federal income tax purposes is included in the tax return of the individual partners, and may vary substantially

F-12

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

from income or loss reported for financial reporting purposes. Accordingly, no recognition has been given to federal income taxes for the Partnership’s operations.

Cash Flows

For purposes of reporting cash flows, all liquid investments with maturities at date of purchase of 90-days or less are considered cash equivalents.

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 39.3 million Units for 2001, 33.6 million Units for 2000 and 32.9 million Units for 1999). The general partner’s percentage interest in net income is based on its percentage of cash distributions from Available Cash for each year (see Note 10. Quarterly Distributions of Available Cash). The general partner was allocated $23.5 million (representing 21.54%) of net income for the year ended December 31, 2001, $13.9 million (representing 17.96%) of net income for the year ended December 31, 2000, and $9.3 million (representing 12.89%) of net income for the year ended December 31, 1999.

Diluted net income per Unit is similar to the computation of basic net income per Unit above, except that the denominator was increased to include the dilutive effect of outstanding Unit options by application of the treasury stock method. For the years ended December 31, 2001, 2000 and 1999, the denominator was increased by 41,864 Units, 20,926 Units and 12,141 Units, respectively.

Unit Option Plan

The Partnership follows the intrinsic value based method of accounting for its stock-based compensation plans (see Note 11. Unit Option Plan). Under this method, the Partnership records no compensation expense for unit options granted when the exercise price of options granted is equal to the fair market value of the Units on the date of grant.

New Accounting Pronouncements

In July 2001, the FASB issued SFAS No. In July 2001, the FASB issued SFAS No. 141, Business Combinations. SFAS 141 requires that the purchase method of accounting be used for all business combinations and specifies that certain acquired intangible assets be reported apart from goodwill. The Partnership adopted SFAS 141 during 2001.

F-13

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Partnership was required to adopt SFAS 144 effective January 1, 2002. The adoption of SFAS 144 did not have a material effect on the financial position, results of operations or cash flows of the Partnership.

NOTE 3. ACQUISITIONS

On July 20, 2000, the Partnership completed an acquisition of ARCO Pipe Line Company (“ARCO”), a wholly-owned subsidiary of Atlantic Richfield Company, for $322.6 million, which included $4.1 million of acquisition related costs other than the purchase price. The purchased assets included ARCO’s 50-percent ownership interest in Seaway Crude Pipeline Company (“Seaway”), which 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 areas. The Partnership assumed ARCO’s role as operator of this pipeline. The Company also acquired: (i) ARCO’s crude oil terminal facilities in Cushing and Midland, Texas, including the line transfer and pumpover business at each location; (ii) an undivided ownership interest in both the Rancho Pipeline, a crude oil pipeline from West Texas to Houston, and the Basin Pipeline, a crude oil pipeline running from Jal, New Mexico, through Midland to Cushing, both of which are operated by another joint owner; and (iii) the receipt and delivery pipelines known as the West Texas Trunk System, which is located around the Midland terminal. The acquisition was accounted for under the purchase method of accounting. Accordingly, the results of the acquisition are included in the consolidated financial statements from July 20, 2000.

In October 2000, the Partnership received a settlement notice from Atlantic Richfield Company for payment of a net aggregate amount of approximately $12.9 million in post-closing adjustments related to the purchase of ARCO. A large portion of the requested adjustment related to an indemnity for payment of accrued income taxes. In August 2001, the Partnership and Atlantic Richfield Company reached a settlement of $11.0 million for the post-closing adjustments. The Partnership recorded the settlement as an increase to the purchase price of ARCO. The Partnership paid the settlement amount to Atlantic Richfield Company on October 15, 2001.

On September 30, 2001, subsidiaries of the Partnership completed the purchase of Jonah from Alberta Energy Company for $359.8 million. The acquisition serves as an entry into the natural gas gathering industry for the Partnership. Goodwill recognized in the purchase amounted to approximately $2.4 million. The acquisition was accounted for under the purchase method of accounting. Accordingly, the results of the acquisition are included in the consolidated financial statements from September 30, 2001. An additional $7.2 million was accrued at December 31, 2001, for final purchase adjustments related primarily to construction projects in progress at the time of closing.

The following table allocates the estimated fair value of Jonah assets acquired on September 30, 2001, and includes the additional purchase adjustment paid in February 2002 (in thousands):


Property, plant and equipment		$	141,835
Intangible assets (primarily gas transportation contracts)			222,800
Goodwill			2,486

	Total assets		367,121

Total liabilities assumed			(489	)

	Net assets acquired	$	366,632

F-14

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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. The value assigned to intangible assets will be amortized over the expected lives of the contracts (approximately 16 years) in proportion to the timing of expected contractual volumes.

The following table presents the unaudited pro forma results of the Partnership as though the acquisitions of the ARCO and Jonah businesses occurred at the beginning of the respective periods (in thousands, except per Unit amounts). The pro forma results do not include operating efficiencies or revenue growth from historical results.


	Years Ended December 31,

	2001		2000

Revenues	$	3,579,684	$	3,128,612
Operating income		141,720		107,916
Net income		88,124		61,255
Basic and diluted net income per Limited Partner and Class B Unit	$	1.76	$	1.50

On December 31, 2000, the Company completed an acquisition of certain pipeline assets from DEFS for $91.7 million, which included $0.7 million of acquisition related costs. The purchase included two natural gas liquids pipelines in East Texas: the Panola Pipeline, a pipeline from Carthage, Texas, to Mont Belvieu, Texas, and the San Jacinto Pipeline, a pipeline from Carthage to Longview, Texas. A lease of a condensate pipeline from Carthage to Marshall, Texas, was also assumed. All three pipelines originate at DEFS’ East Texas Plant Complex in Panola County, Texas. The acquisition of the assets was accounted for under the purchase method of accounting.

NOTE 4. RELATED PARTY TRANSACTIONS

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

F-15

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

On July 20, 2000, the Partnership, through TCTM, acquired a 50-percent ownership interest in Seaway. Phillips owns the remaining 50% interest in Seaway. The Partnership is the operator of this pipeline. During the years ended 2001 and 2000, the Partnership billed to Seaway $7.0 million and $2.9 million, respectively, for direct payroll and payroll related expenses for operating Seaway. Additionally, during the years ended December 31, 2001 and 2000, the Partnership billed to Seaway $2.1 million and $0.9 million, respectively, for indirect management fees for operating Seaway.

On September 30, 2001, the Partnership completed the acquisition of Jonah. The Jonah assets are managed and operated by employees of DEFS under a contractual arrangement under which DEFS is reimbursed for its actual costs. Certain employees of DEFS also act as officers of TEPPCO GP in order to facilitate management of the Jonah assets by DEFS. These DEFS employees receive no additional compensation from the Partnership for these activities. During the year ended December 31, 2001, the Partnership recognized $0.6 million of expense related to the management of the Jonah assets by DEFS.

NOTE 5. EQUITY INVESTMENTS

Seaway is a partnership between TCTM and Phillips. TCTM purchased its 50-percent ownership interest in Seaway on July 20, 2000 (see Note 3. Acquisitions). 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, TCTM receives 80% of revenue and expense of Seaway. From June 2002 until May 2006, TCTM receives 60% of revenue and expense of Seaway. Thereafter, the sharing ratio becomes 40% of revenue and expense to TCTM.

In August 2000, the Partnership entered into agreements with CMS Energy Corporation and Marathon Ashland Petroleum LLC to form Centennial Pipeline, LLC (“Centennial”). Centennial owns and operates an interstate refined petroleum products pipeline extending from the upper Texas Gulf Coast to Illinois. Each participant owns a one-third interest in Centennial. During 2001 and 2000, the Partnership contributed approximately $65.0 million and $5.0 million, respectively, for its investment in Centennial. Such amounts are included in the equity investment balance at December 31, 2001 and 2000.

F-16

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Partnership uses the equity method of accounting for its investments in Seaway and Centennial. Summarized combined financial information for Seaway as of and for the year ended December 31, 2001, and as of December 31, 2000, and for the period from July 20, 2000, through December 31, 2000, and for Centennial as of and for the year ended December 31, 2001, is presented below (in thousands):


	2001		2000

Current assets	$	57,368	$	36,883
Noncurrent assets		528,835		288,191
Current liabilities		31,308		9,220
Long-term debt		128,000		—
Partners’ capital		426,895		315,854
Revenues		72,026		31,989
Net income		30,294		12,449

The Partnership’s investment in Seaway at December 31, 2001 and 2000, includes an excess investment amount of $25.5 million and $26.4 million, net of accumulated amortization of $1.6 million and $0.7 million, respectively. This excess investment relates to the Partnership’s allocation of the purchase price on July 20, 2000, in excess of its proportionate share of the net assets of Seaway. The excess investment is being amortized using the straight-line method over 20 years.

NOTE 6. INVENTORIES

Inventories are valued at the lower of cost (based on weighted average cost method) or market. The major components of inventories were as follows (in thousands):


		December 31,

		2001		2000

Crude oil		$	3,783	$	14,635
Gasolines			4,548		3,795
Propane			1,096		—
Butanes			1,431		267
Other products			2,866		2,775
Materials and supplies			3,519		3,312

	Total	$	17,243	$	24,784

The costs of inventories did not exceed market values at December 31, 2001 and 2000.

F-17

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NOTE 7. PROPERTY, PLANT AND EQUIPMENT

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


			December 31,

			2001		2000

Land and right of way			$	92,664	$	77,798
Line pipe and fittings				822,332		739,372
Storage tanks				130,461		125,890
Buildings and improvements				15,131		13,127
Machinery and equipment				252,393		178,227
Construction work in progress				157,728		66,456

	Total property, plant and equipment		$	1,470,709	$	1,200,870
	Less accumulated depreciation and amortization			290,248		251,165

		Net property, plant and equipment	$	1,180,461	$	949,705

Depreciation expense on property, plant and equipment was $39.5 million, $33.0 million and $30.7 million for the years ended December 31, 2001, 2000 and 1999, respectively.

NOTE 8. LONG TERM DEBT

Senior Notes

On January 27, 1998, TE Products completed the issuance of $180 million principal amount of 6.45% Senior Notes due 2008, and $210 million principal amount of 7.51% Senior Notes due 2028 (collectively the “Senior Notes”). The 6.45% Senior Notes were issued at a discount and are being accreted to their face value over the term of the notes. The 6.45% Senior Notes due 2008 are not subject to redemption prior to January 15, 2008. The 7.51% Senior Notes due 2028, issued at par, may be redeemed at any time after January 15, 2008, at the option of TE Products, in whole or in part, at a premium.

The Senior Notes do not have sinking fund requirements. Interest on the Senior Notes is payable semiannually in arrears on January 15 and July 15 of each year. The Senior Notes are unsecured obligations of TE Products and rank on a parity with all other unsecured and unsubordinated indebtedness of TE Products. The indenture governing the Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit the Partnership’s ability to incur additional indebtedness. As of December 31, 2001, TE Products was in compliance with the covenants of the Senior Notes.

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 $210 million principal amount of 7.51% fixed rate Senior Notes. The swap agreement has a notional amount of $210 million and matures in January 2028 to match the principal and maturity of the Senior Notes. Under the swap agreement, TE Products pays a floating rate based on a three month U.S. Dollar LIBOR rate, plus a spread, and receives a fixed rate of interest of 7.51%.

At December 31, 2001 and 2000, the estimated fair value of the Senior Notes was approximately $362 million and $385 million, respectively. Market prices for recent transactions and rates currently available to the Partnership for debt with similar terms and maturities were used to estimate fair value.

F-18

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Other Long Term Debt and Credit Facilities

In connection with the purchase of fractionation assets from DEFS as of March 31, 1998, TEPPCO Colorado, a subsidiary of TE Products, received a $38 million bank loan. The interest rate on this loan was 6.53%, which was payable quarterly. The original maturity date was April 21, 2001. This loan was refinanced by the Partnership on July 21, 2000, through the credit facility discussed below.

On May 17, 1999, TE Products entered into a five-year $75 million term loan agreement to finance construction of three new pipelines between TE Products’ terminal in Mont Belvieu, Texas and Port Arthur, Texas. This loan was refinanced by the Partnership on July 21, 2000, through the credit facility discussed below.

On May 17, 1999, TE Products entered into a five-year $25 million revolving credit agreement, and TCTM entered into a three-year $30 million revolving credit agreement. Both of the credit facilities were terminated in connection with the refinancing on July 21, 2000, discussed below. TE Products did not make any borrowings under this revolving credit facility. TCTM had a $3 million principal amount outstanding under its revolving credit agreement as of July 21, 2000.

On July 14, 2000, the Partnership entered into a $75 million term loan and a $475 million revolving credit facility (“Three Year Facility”). On July 21, 2000, the Partnership borrowed $75 million under the term loan and $340 million under the Three Year Facility. The funds were used to finance the acquisition of the ARCO assets (see Note 3. Acquisitions) and to refinance existing bank credit facilities, other than the Senior Notes. The term loan was repaid from proceeds received from the issuance of additional Limited Partner Units on October 25, 2000.

On April 6, 2001, the Partnership’s Three Year Facility was amended to provide for revolving borrowings of up to $500 million including the issuance of letters of credit of up to $20 million. The term of the revised Three Year Facility was extended to April 6, 2004. The interest rate is based on the Partnership’s option of either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement for the Three Year Facility contains restrictive financial covenants that require the Partnership to maintain a minimum level of partners’ capital as well as maximum debt-to-EBITDA (earnings before interest expense, income tax expense and depreciation and amortization expense) and minimum fixed charge coverage ratios. On September 28, 2001, the Three Year Facility was amended to extend to December 31, 2001, the time period for the maximum debt-to-EBITDA ratio covenant to allow for the additional debt incurred for the acquisition of Jonah. On November 13, 2001, the Three Year Facility was further amended to require prepayment of outstanding borrowings only upon the receipt of net cash proceeds from asset dispositions or from insurance proceeds in accordance with the terms of the agreement. At such time, certain lenders under the agreement elected to withdraw from the facility, and the available borrowing capacity was reduced to $411 million. As of December 31, 2001, the Partnership was in compliance with the covenants contained in this credit agreement. At December 31, 2001 and 2000, $340.7 million and $446 million was outstanding under the Three Year Facility at a weighted average interest rate of 2.9% and 8.23%, respectively. At December 31, 2001 and 2000, the carrying value of the revolving credit facility approximated its fair value.

On July 21, 2000, the Partnership entered into a three year swap agreement to hedge its exposure to increases in the benchmark interest rate underlying its variable rate revolving credit facilities. On April 6, 2001, the swap agreement was extended until April 6, 2004, to match the maturity of the variable rate credit facility. The swap agreement is based on a notional amount of $250 million. Under the swap agreement, the Partnership pays a fixed rate of interest of 6.955% and receives a floating rate based on a three month U.S. Dollar LIBOR rate. At December 31, 2001 and 2000, the estimated fair value of the swap agreement was a loss of approximately $20.3 million and $10 million, respectively (see Note 2. Use of Derivatives).

F-19

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Short Term Credit Facilities

On April 6, 2001, the Partnership entered into a 364-day, $200 million revolving credit agreement (“Short-term Revolver”). The interest rate is based on the Partnership’s option of either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement contains restrictive financial covenants that require the Partnership to maintain a minimum level of partners’ capital as well as maximum debt-to-EBITDA and minimum fixed charge coverage ratios. On September 28, 2001, the Short-term Revolver was amended to extend to December 31, 2001, the time period for the maximum debt-to-EBITDA ratio covenant to allow for the additional debt incurred for the acquisition of Jonah. On November 13, 2001, the Short-term Revolver was further amended to require prepayment of outstanding borrowings only upon the receipt of net cash proceeds from asset dispositions or from insurance proceeds in accordance with the terms of the agreement. At such time, certain lenders under the agreement elected to withdraw from the facility, and the available borrowing capacity was reduced to $164 million. At December 31, 2001, $160 million, included in current liabilities, was outstanding under the Short-term Revolver at a weighted average interest rate of 2.9%. As of December 31, 2001, the Partnership was in compliance with the covenants contained in this credit agreement.

On September 28, 2001, the Partnership entered into a $400 million credit facility with SunTrust Bank (“Bridge Facility”). The Partnership borrowed $360 million under the Bridge Facility for the acquisition of the Jonah assets (see Note 3. Acquisitions). The Bridge Facility is payable in June 2002. During the fourth quarter of 2001, $160 million of the outstanding principal was repaid from the proceeds received from the issuance of the Limited Partner Units in November 2001. The interest rate is based on the Partnership’s option of either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreements contain restrictive financial covenants that require the Partnership to maintain a minimum level of partners’ capital as well as maximum debt-to-EBITDA and minimum fixed charge coverage ratios. At December 31, 2001, $200 million was outstanding under the Bridge Facility at an interest rate of 3.2%. As of December 31, 2001, the Partnership was in compliance with the covenants contained in this credit agreement.

The following table summarizes the principal outstanding under the credit facilities of the Partnership as of December 31, 2001 and 2000 (in thousands):


			2001		2000

Short Term Credit Facilities:
	Short-term Revolver, due April 2002		$	160,000	$	—
	Bridge Facility, due June 2002			200,000		—

		Total Short Term Credit Facilities	$	360,000	$	—

Long Term Credit Facilities:
	Three Year Facility, due April 2004		$	340,658	$	446,000
	6.45% Senior Notes, due January 2008			179,814		179,784
	7.51% Senior Notes, due January 2028			210,000		210,000

		Total Long Term Credit Facilities	$	730,472	$	835,784

NOTE 9. CONCENTRATIONS OF CREDIT RISK

The Partnership’s primary market areas are located in the Northeast, Midwest and Southwest regions of the United States. The Partnership has 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 the Partnership’s overall credit risk in that the customers may be

F-20

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

similarly affected by changes in economic, regulatory or other factors. The Partnership’s customers’ historical and future credit positions are thoroughly analyzed prior to extending credit. The Partnership manages its 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.

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

NOTE 10. QUARTERLY DISTRIBUTIONS OF AVAILABLE CASH

The Partnership makes quarterly cash distributions of all of its 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 on the portion that cash distributions on a per Unit basis 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	%

The following table reflects the allocation of total distributions paid for the years ended December 31, 2001, 2000 and 1999 (in thousands, except per Unit amounts).


		Years Ended December 31,

		2001		2000		1999

Limited Partner Units		$	73,961	$	59,943	$	53,650
General Partner Ownership Interest			1,273		685		609
General Partner Incentive			20,257		12,938		7,650

	Total Partners’ Capital Cash Distributions		95,491		73,566		61,909
Class B Units			8,421		7,833		6,651
Minority Interest			500		832		699

	Total Cash Distributions Paid	$	104,412	$	82,231	$	69,259

Total Cash Distributions Paid Per Unit		$	2.15	$	2.00	$	1.85

On February 8, 2002, the Partnership paid a cash distribution of $0.575 per Limited Partner Unit and Class B Unit for the quarter ended December 31, 2001. The fourth quarter 2001 cash distribution totaled $33.5 million.

NOTE 11. UNIT OPTION PLAN

During 1994, the Company adopted the Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan (“1994 LTIP”). The 1994 LTIP provides key employees with an incentive award whereby a participant is granted an option to purchase Limited Partner Units together with a stipulated number of Performance Units. Under the provisions of the 1994 LTIP, no more than one million options

F-21

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

and two million Performance Units may be granted. Each Performance Unit creates a credit to a participant’s Performance Unit account when earnings exceed a threshold. When earnings for a calendar year (exclusive of certain special items) exceed the threshold, the excess amount is credited to the participant’s Performance Unit account. The balance in the account may be used to exercise Limited Partner 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. Under the agreement for such Limited Partner Unit options, the options become exercisable in equal installments over periods of one, two, and three years from the date of the grant. Options may also be exercised by normal means once vesting requirements are met. A summary of Performance Units and Limited Partner Unit options granted under the terms of the 1994 LTIP is presented below:


	Performance		Earnings		Expiration
	Units		Threshold		Year

Performance Unit Grants:
1994		80,000	$	1.00		2006
1995		70,000	$	1.25		2007
1997		11,000	$	1.875		2009


			Options			Options			Exercise
			Outstanding			Exercisable			Range

Limited Partner Unit Options:
	Outstanding at December 31, 1998			190,796			72,359		$	13.81-$21.66
		Granted		162,000			—		$	25.25
		Became exercisable		—			40,737		$	21.66-$25.69
		Exercised		(14,000	)		(14,000	)	$	13.81-$14.34

	Outstanding at December 31, 1999			338,796			99,096		$	13.81-$25.69
		Forfeited		(28,000	)		(4,000	)	$	25.25-$25.69
		Became exercisable		—			85,365		$	21.66-$25.69
		Exercised		(19,932	)		(19,932	)	$	13.81-$14.34

	Outstanding at December 31, 2000			290,864			160,529		$	13.81-$25.69
		Forfeited		(10,666	)		—		$	25.25
		Became exercisable		—			81,669		$	25.25-$25.69
		Exercised		(98,376	)		(98,376	)	$	13.81-$25.69

	Outstanding at December 31, 2001			181,822			143,822		$	13.81-$25.69

As discussed in Note 2, the Partnership uses 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 the Partnership’s Limited Partner Units on the date of grant. Accordingly, no compensation expense was recognized 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 totaled $226,152, $202,634 and $99,076 during 1999, 2000 and 2001, respectively. The disclosures as required by SFAS 123 are not representative of the effects on pro forma net income for future years as options vest over several years and additional awards may be granted in subsequent years.

F-22

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For purposes of determining compensation costs using the provisions of SFAS 123, the fair value of 1999 option grants were determined using the Black-Scholes option-valuation model. The key input variables used in valuing the options were:


	1999

Risk-free interest rate		4.7	%
Dividend yield		7.6	%
Unit price volatility		23	%
Expected option lives	6 years

NOTE 12. LEASES

The Partnership utilizes leased assets in several areas of its operations. Total rental expense during 2001, 2000 and 1999 was $10.8 million, $10.7 million and $8.7 million, respectively. The minimum rental payments under the Partnership’s various operating leases for the years 2002 through 2006 are $8.8 million, $7.7 million, $7.1 million, $6.1 million and $4.9 million, respectively. Thereafter, payments aggregate $1.4 million through 2007.

NOTE 13. EMPLOYEE BENEFITS

Retirement Plans

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 (“Duke Energy RCBP”), which is a noncontributory, trustee-administered pension plan. In addition, certain executive officers participated in the Duke Energy Executive Cash Balance Plan (“Duke Energy ECBP”), which is a noncontributory, nonqualified, defined benefit retirement plan. The Duke Energy ECBP was established to restore benefit reductions caused by the maximum benefit limitations that apply to qualified plans. Effective January 1, 1999, the benefit formula for all eligible employees was 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. As part of the change in ownership, the Company is no longer responsible for the funding of the liabilities associated with these plans.

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 RCBP and the Duke Energy ECBP previously in effect prior to April 1, 2000.

F-23

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The components of net pension benefits costs for the TEPPCO RCBP and the TEPPCO SBP for the years ended December 31, 2001 and 2000, and for the Duke Energy RCBP and the Duke Energy ECBP for the years ended December 31, 2000 and 1999 were as follows (in thousands):


		2001			2000			1999

Service cost benefit earned during the year		$	2,419		$	2,054		$	1,651
Interest cost on projected benefit obligation			129			782			2,666
Expected return on plan assets			(166	)		(663	)		(2,243	)
Amortization of prior service cost			8			—			2
Amortization of net transition liability			—			4			15
Recognized net actuarial loss			—			—			285

	Net pension benefits costs	$	2,390		$	2,177		$	2,376

Other Postretirement Benefits

Prior to April 1, 2000, the Company’s employees were provided with certain health care and life insurance benefits for retired employees on a contributory and non-contributory basis through Duke Energy (“Duke Energy OPB”). Employees became eligible for these benefits if they had met certain age and service requirements at retirement, as defined in the plans. As part of the change in ownership, the Company is no longer responsible for the funding of the liabilities associated with these plans. Effective January 1, 2001, the Company provided its own plan for health care benefits for retired employees (“TEPPCO OPB”).

The Company provides a fixed dollar contribution towards retired employee medical costs. The fixed dollar contribution does not increase from year to year. The retiree pays all health care cost increases due to medical inflation.

The components of net postretirement benefits cost for the Duke Energy OPB for the years ended December 31, 2000 and 1999, and for the TEPPCO OPB for the year ended December 31, 2001, were as follows (in thousands):


		2001		2000			1999

Service cost benefit earned during the year		$	99	$	39		$	172
Interest cost on accumulated postretirement benefit obligation			113		134			500
Expected return on plan assets			—		(85	)		(299	)
Amortization of prior service cost			126		(96	)		(384	)
Amortization of net transition liability			—		54			217

	Net postretirement benefits costs	$	338	$	46		$	206

The weighted average assumptions used in the actuarial computations for the retirement plans and other postretirement benefit plans for the years ended December 31, 2001 and 2000 are as follows:


							Other Postretirement
	Pension Benefits						Benefits

	2001			2000			2001			2000

Discount rate		7.25	%		7.50	%		7.25	%		7.50	%
Increase in compensation levels		5.06	%		4.50	%		—			—
Expected long-term rate of return on plan assets		9.00	%		9.25	%		—			—

F-24

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table sets forth the Company’s pension and other postretirement benefits changes in benefit obligation, fair value of plan assets and funded status as of December 31, 2001 and 2000.


								Other Postretirement
		Pension Benefits						Benefits

		2001			2000			2001			2000(1)

Change in benefit obligation
	Benefit obligation at beginning of year	$	1,518		$	—		$	—		$	—
	Service cost		2,419			1,518			99			—
	Interest cost		129			(1	)		113			—
	Plan amendments		62			—			1,508			—
	Actuarial (gain)/loss		(136	)		1			57			—
	Retiree contributions		—			—			9			—
	Benefits paid		(206	)		—			(5	)		—

	Benefit obligation at end of year	$	3,786		$	1,518		$	1,781		$	—

Change in plan assets
	Fair value of plan assets at beginning of year	$	—		$	—		$	—		$	—
	Actual return on plan assets		(37	)		—			—			—
	Retiree contributions		—			—			9			—
	Employer contributions		4,202			—			(4	)		—
	Benefits paid		(206	)		—			(5	)		—

	Fair value of plan assets at end of year	$	3,959		$	—		$	—		$	—

Reconciliation of funded status
	Funded status	$	173		$	(1,518	)	$	(1,781	)	$	—
	Unrecognized prior service cost		54			—			1,381			—
	Unrecognized actuarial loss		68			—			57			—

	Net amount recognized	$	295		$	(1,518	)	$	(343	)	$	—

(1)

The TEPPCO OPB became effective on January 1, 2001.

Other Plans

Duke Energy also sponsors an employee savings plan, which covers substantially all employees. Plan contributions on behalf of the Company of $3.1 million, $2.2 million and $2.2 million were expensed in 2001, 2000 and 1999, respectively.

NOTE 14. COMMITMENTS AND CONTINGENCIES

F-25

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

release caused damages to the plaintiffs. In their complaints, the plaintiffs allege strict liability for both personal injury and property damage together with gross negligence, continuing nuisance, trespass, criminal mischief and loss of consortium. The plaintiffs are seeking compensatory, punitive and treble damages. The Company has filed an answer to both complaints, denying the allegations, as well as various other motions. These cases are in the early stages of discovery and are not covered by insurance. The Company is defending itself vigorously against the lawsuits. The plaintiffs have not stipulated the amount of damages that they are seeking in the suit. The Partnership cannot estimate the loss, if any, associated with these pending lawsuits.

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

In addition to the litigation discussed above, the Partnership has been, in the ordinary course of business, a defendant in various lawsuits and a party to various other legal proceedings, some of which are covered in whole or in part by insurance. The Company believes that the outcome of such lawsuits and other proceedings will not individually or in the aggregate have a material adverse effect on the Partnership’s consolidated financial condition, results of operations or cash flows.

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

F-26

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Record of Decision is issued, the Partnership will enter into a subsequent Agreed Order for the continued operation and maintenance of the remediation program. The Partnership has an accrued liability of $0.6 million at December 31, 2001, for future remediation costs at the Seymour terminal. In the opinion of the Company, the completion of the remediation program will not have a material adverse effect on the Partnership’s financial condition, results of operations or cash flows.

Rates of interstate oil pipeline companies, like the Partnership, are currently regulated by the FERC, primarily through an index methodology, whereby a pipeline is allowed to change its rates based on the change from year to year in the Producer Price Index for finished goods less 1% (“PPI Index”). In the alternative, interstate oil pipeline companies may elect to support rate filings by using a cost-of-service methodology, competitive market showings (“Market-Based Rates”) or agreements between shippers and the oil pipeline company that the rate is acceptable (“Settlement Rates”).

F-27

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Centennial has entered into credit facilities totaling $150 million. The proceeds were used to fund construction and conversion costs of its pipeline system. TE Products has guaranteed one-third of the debt of Centennial up to a maximum amount of $50 million.

Substantially all of the petroleum products transported and stored by the Partnership are owned by the Partnership’s customers. At December 31, 2001, TCTM and TE Products had approximately 3.8 million barrels and 19.7 million barrels, respectively, of products in its custody owned by customers. The Partnership is obligated for the transportation, storage and delivery of such products on behalf of its customers. The Partnership maintains insurance adequate to cover product losses through circumstances beyond its control.

NOTE 15. SEGMENT DATA

The Partnership has three reporting segments: refined products, LPGs, and petrochemicals transportation, which operates as the Downstream Segment; crude oil and NGLs transportation and marketing, which operates as the Upstream Segment; and natural gas gathering, which operates as the Midstream Segment. The amounts indicated below as “Partnership and Other” relate primarily to intercompany eliminations and assets held by the Partnership that have not been allocated to any reporting segment of the Partnership.

The Partnership’s Downstream Segment includes the interstate transportation, storage and terminaling of petroleum products and LPGs, intrastate transportation of petrochemicals and the fractionation of NGLs. Revenues are derived from the transportation of refined products and LPGs, the storage and short-haul shuttle transportation of LPGs at the Mont Belvieu, Texas, complex, sale of product inventory and other ancillary services. The Partnership’s Downstream Segment, operating through 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 a pipeline system extending from southeast Texas through the central and midwestern United States to the northeastern United States.

The Partnership’s Upstream Segment includes: gathering, storage, transportation and marketing of crude oil in Colorado, Oklahoma, Kansas, New Mexico, Texas and Louisiana; operating two trunkline NGL pipelines in South Texas and two NGL pipelines in East Texas; and distributing lube oils and specialty chemicals to industrial and commercial accounts. On July 20, 2000, the Partnership acquired certain assets from ARCO (see Note 3. Acquisitions). The acquisition was accounted for under the purchase method of accounting. The results of the acquisition have been included in the Partnership’s Upstream Segment since the purchase on July 20, 2000.

The Partnership’s Midstream Segment includes the gathering of natural gas in the Green River Basin in southwestern Wyoming, through Jonah, which was acquired by subsidiaries of the Partnership on September 30, 2001, from Alberta Energy Company (see Note 3. Acquisitions). The acquisition was accounted for under the purchase method of accounting. The results of operations of the Jonah acquisition are included in periods subsequent to September 30, 2001.

The accounting policies of the segments are the same as those described in the summary of significant accounting policies discussed above (see Note 2. Summary of Significant Accounting Policies).

F-28

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table includes financial information by reporting segment for the years ended December 31, 2001, 2000 and 1999 (in thousands):


		Downstream			Upstream			Midstream			Partnership
		Segment			Segment			Segment			and Other			Consolidated

2001
Unaffiliated revenues		$	271,627		$	3,275,962		$	8,824		$	—		$	3,556,413
Operating expenses, including power			120,736			3,237,635			1,154			—			3,359,525
Depreciation and amortization expense			28,714			12,658			4,527			—			45,899

	Operating income		122,177			25,669			3,143			—			150,989
Interest expense, net			(29,943	)		(28,553	)		(3,561	)		—			(62,057	)
Equity earnings			(1,149	)		18,547			—			—			17,398
Other income, net			995			1,806			—			—			2,801

	Net income	$	92,080		$	17,469		$	(418	)	$	—		$	109,131

Total assets		$	879,834		$	811,813		$	386,695		$	(12,994	)	$	2,065,348
Accounts receivable, trade			22,816			189,464			9,261			—			221,541
Accounts payable and accrued liabilities		$	18,994		$	201,569		$	7,512		$	—		$	228,075


		Downstream			Upstream
		Segment			Segment			Consolidated

2000
Unaffiliated revenues		$	236,687		$	2,851,254		$	3,087,941
Operating expenses, including power			118,945			2,825,808			2,944,753
Depreciation and amortization expense			27,743			7,420			35,163

	Operating income		89,999			18,026			108,025
Interest expense, net			(30,573	)		(13,850	)		(44,423	)
Equity earnings			—			12,214			12,214
Other income, net			1,269			291			1,560

	Net income	$	60,695		$	16,681		$	77,376

Total assets		$	755,508		$	867,302		$	1,622,810
Accounts receivable, trade			26,182			277,212			303,394
Accounts payable and accrued liabilities		$	12,177		$	281,543		$	293,720

F-29

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


		Downstream			Upstream
		Segment			Segment			Consolidated

1999
Unaffiliated revenues		$	230,270		$	1,704,613		$	1,934,883
Operating expenses, including power			113,768			1,688,369			1,802,137
Depreciation and amortization expense			27,109			5,547			32,656

	Operating income		89,393			10,697			100,090
Interest expense, net			(29,212	)		(218	)		(29,430	)
Other income, net			1,046			414			1,460

	Net income	$	61,227		$	10,893		$	72,120

Total assets		$	721,797		$	319,576		$	1,041,373
Accounts receivable, trade			22,358			183,408			205,766
Accounts payable and accrued liabilities		$	7,412		$	194,248		$	201,660

NOTE 16. COMPREHENSIVE INCOME

SFAS 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 year ended December 31, 2001, the components of comprehensive income were due to the interest rate swap related to its variable rate revolving credit facility. The table below reconciles reported net income to total comprehensive income for the year ended December 31, 2001 (in thousands).


Net income		$	109,131
Cumulative effect attributable to adoption of SFAS 133 (see Note 2. Use of Derivatives)			(10,103	)
Net loss on cash flow hedges			(10,221	)

	Total comprehensive income	$	88,807

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


Balance at December 31, 2000	$	—
Cumulative effect of accounting change		(10,103	)
Net loss on cash flow hedges		(10,221	)

Balance at December 31, 2001	$	(20,324	)

NOTE 17. SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Under the Partnership’s shelf registration statement on Form S-3 filed with the Securities and Exchange Commission on February 12, 2002, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, the Partnership’s significant operating subsidiaries (the “Guarantor Subsidiaries”), may issue unconditional guarantees of senior or subordinated debt securities of the Partnership in the event that the Partnership issues such securities from time to time under the registration statement. If issued, the guarantees will be full, unconditional and joint and several.

F-30

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following supplemental condensed consolidating financial information reflects the separate accounts of the Partnership, the combined accounts of the Guarantor Subsidiaries (including Jonah for all periods and dates from and after September 30, 2001, the date Jonah became a subsidiary of the Partnership), the combined accounts of the other non-guarantor subsidiaries of the Partnership, the combined consolidating adjustments and eliminations and the consolidated Partnership accounts for the dates and periods indicated. For purposes of the following consolidating information, the Partnership’s and Guarantor Subsidiaries’ investments in their respective subsidiaries are accounted for by the equity method of accounting.


												TEPPCO
			TEPPCO		Guarantor		Non-Guarantor		Consolidating			Partners, L.P.
December 31, 2001			Partners, L.P.		Subsidiaries		Subsidiaries		Adjustments			Consolidated

							(in thousands)
Assets
	Current assets		$	3,100	$	59,730	$	223,345	$	(2,695	)	$	283,480
	Property, plant and equipment — net			—		849,978		330,483		—			1,180,461
	Equity investments			669,370		309,080		222,815		(909,041	)		292,224
	Intercompany notes receivable			700,564		11,269		7,404		(719,237	)		—
	Other assets			3,853		244,448		65,386		(4,504	)		309,183

		Total assets	$	1,376,887	$	1,474,505	$	849,433	$	(1,635,477	)	$	2,065,348

Liabilities and partners’ capital
	Current liabilities		$	367,094	$	361,547	$	310,476	$	(370,275	)	$	668,842
	Long term debt			340,658		389,814		—		—			730,472
	Intercompany notes payable			—		45,410		294,801		(340,211	)		—
	Other long term liabilities and minority interest			—		8,364		231		8,628			17,223
	Redeemable Class B Units held by related party			105,630		—		—		—			105,630
	Total partners’ capital			563,505		669,370		243,925		(933,619	)		543,181

		Total liabilities and partners’ capital	$	1,376,887	$	1,474,505	$	849,433	$	(1,635,477	)	$	2,065,348

F-31

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


													TEPPCO
				TEPPCO		Guarantor		Non-Guarantor		Consolidating			Partners, L .P.
December 31, 2000				Partners, L .P.		Subsidiaries		Subsidiaries		Adjustments			Consolidated

								(in thousands)
Assets
	Current assets			$	6,083	$	52,773	$	315,488	$	(10,947	)	$	363,397
	Property, plant and equipment — net				—		640,657		309,048		—			949,705
	Equity investments				420,433		202,811		236,232		(617,828	)		241,648
	Intercompany notes receivable				441,836		—		—		(441,836	)		—
	Other assets				5,322		15,385		48,475		(1,122	)		68,060

			Total assets	$	873,674	$	911,626	$	909,243	$	(1,071,733	)	$	1,622,810

Liabilities and partners’ capital
	Current liabilities			$	7,206	$	45,085	$	318,049	$	(12,069	)	$	358,271
	Long term debt				446,000		389,784		—		—			835,784
	Intercompany notes payable				—		48,037		393,799		(441,836	)		—
	Other long term liabilities and minority interest				—		3,991		—		4,296			8,287
	Redeemable Class B Units held by related party				105,411		—		—		—			105,411
	Total partners’ capital				315,057		424,729		197,395		(622,124	)		315,057

		Total liabilities and partners’ capital		$	873,674	$	911,626	$	909,243	$	(1,071,733	)	$	1,622,810


															TEPPCO
			TEPPCO			Guarantor			Non-Guarantor			Consolidating			Partners, L.P.
Year Ended December 31, 2001			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			3,253,188			(322	)		3,405,424

	Operating income			—			120,821			30,168			—			150,989

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			2,064			(40,143	)		3,601

		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-32

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


														TEPPCO
		TEPPCO			Guarantor			Non-Guarantor			Consolidating			Partners, L.P.
Year Ended December 31, 2000		Partners, L .P.			Subsidiaries			Subsidiaries			Adjustments			Consolidated

								(in thousands)
Operating revenues		$	—		$	229,234		$	2,858,707		$	—		$	3,087,941
Costs and expenses			—			143,793			2,836,123			—			2,979,916

	Operating income		—			85,441			22,584			—			108,025

Interest expense — net			(17,773	)		(27,572	)		(16,851	)		17,773			(44,423	)
Equity earnings			77,376			18,602			12,214			(95,978	)		12,214
Other income — net			17,773			1,694			655			(17,773	)		2,349

	Income before minority interest		77,376			78,165			18,602			(95,978	)		78,165
Minority interest			—			—			—			(789	)		(789	)

	Net income	$	77,376		$	78,165		$	18,602		$	(96,767	)	$	77,376


													TEPPCO
		TEPPCO		Guarantor			Non-Guarantor			Consolidating			Partners, L.P.
Year Ended December 31, 1999		Partners, L .P.		Subsidiaries			Subsidiaries			Adjustments			Consolidated

							(in thousands)
Operating revenues		$	—	$	222,915		$	1,711,968		$	—		$	1,934,883
Costs and expenses			—		138,035			1,696,758			—			1,834,793

	Operating income		—		84,880			15,210			—			100,090

Interest expense — net			—		(26,682	)		(2,748	)		—			(29,430	)
Equity earnings			72,120		13,188			—			(85,308	)		—
Other income — net			—		1,470			726			—			2,196

	Income before minority interest		72,120		72,856			13,188			(85,308	)		72,856
Minority interest			—		—			—			(736	)		(736	)

	Net income	$	72,120	$	72,856		$	13,188		$	(86,044	)	$	72,120


																TEPPCO
				TEPPCO			Guarantor			Non-Guarantor			Consolidating			Partners, L.P.
Year Ended December 31, 2001				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
			Equity earnings, 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

F-33

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


																TEPPCO
				TEPPCO			Guarantor			Non-Guarantor			Consolidating			Partners, L.P.
Year Ended December 31, 2000				Partners, L.P.			Subsidiaries			Subsidiaries			Adjustments			Consolidated

										(in thousands)
Cash flows from operating activities
	Net income			$	77,376		$	78,165		$	18,602		$	(96,767	)	$	77,376
		Adjustments to reconcile net income to net cash provided by operating activities:
			Depreciation and amortization		—			25,728			9,435			—			35,163
			Equity earnings, net of distributions		4,025			(1,962	)		(10,260	)		(1,887	)		(10,084	)
			Changes in assets and liabilities and other		7,242			1,046			845			(3,543	)		5,590

Net cash provided by operating activities					88,643			102,977			18,622			(102,197	)		108,045

Cash flows from investing activities					(535,048	)		(67,225	)		(434,113	)		542,192			(494,194	)
Cash flows from financing activities					446,405			(42,870	)		417,112			(439,995	)		380,652

Net increase (decrease) in cash and cash equivalents					—			(7,118	)		1,621			—			(5,497	)
Cash and cash equivalents at beginning of period					—			16,284			16,309			—			32,593

Cash and cash equivalents at end of period				$	—		$	9,166		$	17,930		$	—		$	27,096


																TEPPCO
				TEPPCO			Guarantor			Non-Guarantor			Consolidating			Partners, L.P.
Year Ended December 31, 1999				Partners, L.P.			Subsidiaries			Subsidiaries			Adjustments			Consolidated

										(in thousands)
Cash flows from operating activities
	Net income			$	72,120		$	72,856		$	13,188		$	(86,044	)	$	72,120
		Adjustments to reconcile net income to net cash provided by operating activities:
			Depreciation and amortization		—			25,094			7,562			—			32,656
			Equity earnings, net of distributions		(3,561	)		(5,144	)		—			9,098			393
			Changes in assets and liabilities and other		369			451			(2,917	)		(2	)		(2,099	)

Net cash provided by operating activities					68,928			93,257			17,833			(76,948	)		103,070

Cash flows from investing activities					—			(66,282	)		(10,359	)		—			(76,641	)
Cash flows from financing activities					(68,928	)		(44,628	)		(4,651	)		76,948			(41,259	)

Net increase (decrease) in cash and cash equivalents					—			(17,653	)		2,823			—			(14,830	)
Cash and cash equivalents at beginning of period					—			33,937			13,486			—			47,423

Cash and cash equivalents at end of period				$	—		$	16,284		$	16,309		$	—		$	32,593

F-34

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NOTE 18. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)


	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter

	(in thousands, except per Unit amounts)
2001(1)
Operating revenues	$	785,235	$	1,073,682	$	990,816	$	706,680
Operating income		36,306		53,069		27,121		34,493
Net income		25,735		43,038		19,092		21,266
Basic income per Limited Partner and Class B Unit	$	0.55	$	0.90	$	0.35	$	0.40
Diluted income per Limited Partner and Class B Unit(1)	$	0.55	$	0.89	$	0.35	$	0.40
2000(2)
Operating revenues	$	750,692	$	747,704	$	749,898	$	839,647
Operating income		30,767		20,151		21,907		35,200
Net income		23,881		13,570		17,189		22,736
Basic and diluted income per Limited Partner and Class B Unit(2)	$	0.60	$	0.35	$	0.41	$	0.53

(1)		Per Unit calculation includes 2,000,000 Limited Partner Units issued in February 2001, 250,000 Limited Partner Units issued in March 2001, and 5,500,000 Limited Partner Units issued in November 2001.

(2)		Per Unit calculation includes 3,700,000 Limited Partner Units issued on October 25, 2000.

NOTE 19. SUBSEQUENT EVENTS

On January 9, 2002, the Partnership announced a definitive agreement to acquire the Chaparral and Quanah pipelines from Diamond-Koch II, L.P. and Diamond-Koch III, L.P. for approximately $130 million. The transaction closed on March 1, 2002, at a cost of approximately $132 million. The purchase was funded by a drawdown of the Partnership’s Three Year Facility.

In January and February 2002, $25 million and $15 million was drawn down on the Three Year Facility and the Bridge Facility, respectively.

On February 20, 2002, the Partnership received $494.6 million in net proceeds from the issuance of $500 million principal amount of 7.625% Senior Notes due 2012. The Senior Notes may be redeemed at any time at the option of the Partnership 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 proceeds from the offering were used to reduce the outstanding balances of the credit facilities (see Note 8. Long Term Debt). The repayments included $160 million outstanding on the Short-term Revolver, $215 million outstanding on the Bridge Facility and $115.7 million outstanding on the Three Year Facility. The Partnership’s Guarantor Subsidiaries issued unconditional guarantees of these Senior Notes (see Note 17. Supplemental Condensed Consolidating Financial Information).

F-35

EXHIBIT INDEX


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).
10.1+		Texas Eastern Products Pipeline Company 1997 Employee Incentive Compensation Plan executed on July 14, 1997 (Filed as Exhibit 10 to Form 10-Q of TEPPCO Partners, L.P.


		(Commission File No. 1-10403) for the quarter ended September 30, 1997 and incorporated herein by reference).
10.2+		Texas Eastern Products Pipeline Company Management Incentive Compensation Plan executed on January 30, 1992 (Filed as Exhibit 10 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1992 and incorporated herein by reference).
10.3+		Texas Eastern Products Pipeline Company Long-Term Incentive Compensation Plan executed on October 31, 1990 (Filed as Exhibit 10.9 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1990 and incorporated herein by reference).
10.4+		Form of Amendment to Texas Eastern Products Pipeline Company Long-Term Incentive Compensation Plan (Filed as Exhibit 10.7 to the Partnership’s Form 10-K (Commission File No. 1-10403) for the year ended December 31, 1995 and incorporated herein by reference).
10.5+		Duke Energy Corporation Executive Savings Plan (Filed as Exhibit 10.7 to the Partnership’s Form 10-K (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).
10.6+		Duke Energy Corporation Executive Cash Balance Plan (Filed as Exhibit 10.8 to the Partnership’s Form 10-K (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).
10.7+		Duke Energy Corporation Retirement Benefit Equalization Plan (Filed as Exhibit 10.9 to the Partnership’s Form 10-K (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).
10.8+		Employment Agreement with William L. Thacker, Jr. (Filed as Exhibit 10 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1992 and incorporated herein by reference).
10.9+		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).
10.10+		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).
10.11		Asset Purchase Agreement between Duke Energy Field Services, Inc. and TEPPCO Colorado, LLC, dated March 31, 1998 (Filed as Exhibit 10.14 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).
10.12		Contribution Agreement between Duke Energy Transport and Trading Company and TEPPCO Partners, L.P., dated October 15, 1998 (Filed as Exhibit 10.16 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).
10.13		Guaranty Agreement by Duke Energy Natural Gas Corporation for the benefit of TEPPCO Partners, L.P., dated November 30, 1998, effective November 1, 1998 (Filed as Exhibit 10.17 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).
10.14		Letter Agreement regarding Payment Guarantees of Certain Obligations of TCTM, L.P. between Duke Capital Corporation and TCTM, L.P., dated November 30, 1998 (Filed as Exhibit 10.19 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).
10.15+		Form of Employment Agreement between the Company and Thomas R. Harper, David L. Langley, 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).


10.16		Agreement Between Owner and Contractor between TE Products Pipeline Company, Limited Partnership and Eagleton Engineering Company, dated February 4, 1999 (Filed as Exhibit 10.21 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).
10.17		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).
10.18		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).
10.19+		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).
10.20+		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).
10.21+		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).
10.22+		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).
10.23+		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).
10.24		Credit Agreement between TEPPCO Partners, L.P., SunTrust Bank, and Certain Lenders, dated July 14, 2000 (Filed as Exhibit 10.31 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2000 and incorporated herein by reference).
10.25		Amended and Restated Purchase Agreement By and Between Atlantic Richfield Company and Texas Eastern Products Pipeline Company With Respect to the Sale of ARCO Pipe Line Company, dated as of May 10, 2000. (Filed as Exhibit 2.1 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2000 and incorporated herein by reference).
10.26+		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).
10.27+		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).
10.28+		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).
10.29		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).


10.30		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).
10.31		Purchase and Sale Agreement By and Among Green River Pipeline, LLC and McMurry Oil Company, Sellers, and TEPPCO Partners, L.P., Buyer, dated as of September 7, 2000. 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).
10.32		Credit Agreement Among TEPPCO Partners, L.P. as Borrower, SunTrust Bank, as Administrative Agent and Certain Lenders, dated as of September 28, 2001 ($400,000,000 Term Facility) (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, 2001 and incorporated herein by reference).
10.33		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).
10.34		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).
10.35*		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).
10.36*		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).
10.37		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).
10.38		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).
10.39		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).
10.40*		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.
10.41*		Unanimous Written Consent of the Board of Directors of TEPPCO GP, Inc. dated February 13, 2002.
12.1*		Statement of Computation of Ratio of Earnings to Fixed Charges.
21*		Subsidiaries of the Partnership.
23*		Consent of KPMG LLP.
24*		Powers of Attorney.


	* Filed herewith.
	+ A management contract or compensation plan or arrangement.

EXHIBIT 10.35 AMENDMENT AND RESTATEMENT AMENDMENT AND RESTATEMENT, dated as of November 13, 2001 (this "AMENDMENT AND RESTATEMENT"), to that certain CREDIT AGREEMENT, dated as of April 6, 2001 (the "EXISTING AGREEMENT", and as amended by this Amendment and Restatement, the "AMENDED AND RESTATED AGREEMENT"), among TEPPCO PARTNERS, L.P., a Delaware limited partnership (the "BORROWER"), the lenders party thereto and SunTrust Bank, as administrative agent for the lenders party thereto and as issuer of letters of credit (the "AGENT"). PRELIMINARY STATEMENT The Borrower, certain lenders and the Agent previously entered into the Existing Agreement. The Borrower and the other parties hereto (the "LENDERS") now wish to amend the Existing Agreement in its entirety to read as set forth in the Existing Agreement with the amendments set forth below. The parties therefore agree as follows (capitalized terms used but not defined herein having the meanings assigned to such terms in the Existing Agreement): SECTION 1. AMENDMENTS TO EXISTING AGREEMENT. The Existing Agreement is, effective as of the date hereof and subject to the satisfaction of the conditions precedent set forth in Section 2 hereof, hereby amended as follows: (a) Schedule 2 is hereby amended in its entirety to read as set forth in Exhibit A attached hereto. (b) Paragraph (ii) of Section 3.2(c) is amended in its entirety to read as follows: "The Borrower shall promptly notify the Administrative Agent upon the receipt of Net Cash Proceeds of any Asset Disposition or Recovery Event and, at any time that such Net Cash Proceeds received and not previously applied to any prepayment pursuant to this Section 3.2(c)(ii) shall equal or exceed $10,000,000, the Borrower shall prepay Borrowings, together with payment of any Funding Losses in an aggregate amount equal to 100% (without duplication) of such Net Cash Proceeds to the Borrowings." SECTION 2. CONDITIONS OF EFFECTIVENESS OF AMENDMENT AND RESTATEMENT. Section 1 of this Amendment and Restatement shall become effective as of the date first set forth above when each of the following conditions shall have been fulfilled: (i) all of the Lenders and the Borrower shall have executed and delivered to the Agent a counterpart of this Amendment and Restatement; (ii) all of the Guarantors shall have executed and delivered the consent to this Amendment and Restatement in substantially the form of Exhibit B attached hereto;

2 (iii) the representations and warranties set forth in Section 3 hereof shall be true and correct on and as of the date of effectiveness of this Amendment and Restatement as though made on and as of such date; and (iv) the Borrower shall have delivered an opinion of counsel in form reasonably acceptable to the Agent. SECTION 3. REPRESENTATIONS AND WARRANTIES. The Borrower represents and warrants that (a) the representations and warranties contained in Article VII of the Amended and Restated Agreement (with each reference therein to (i) "this Agreement", "hereunder" and words of like import referring to the Existing Agreement being deemed to be a reference to this Amendment and Restatement and the Amended and Restated Agreement and (ii) "Credit Documents", "thereunder" and words of like import being deemed to include this Amendment and Restatement and the Amended and Restated Agreement) are true and correct on and as of the date hereof as though made on and as of such date, and (b) no event has occurred and is continuing, or would result from the execution and delivery of this Amendment and Restatement, that constitutes an Event of Default. SECTION 4. EFFECT ON THE CREDIT AGREEMENT. Except as specifically amended above, the Existing Agreement shall continue to be in full force and effect and is hereby in all respects ratified and confirmed. The execution, delivery and effectiveness of this Amendment and Restatement shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of the Lenders under the Existing Agreement, nor constitute a waiver of any provision of the Existing Agreement. SECTION 5. COSTS AND EXPENSES. The Borrower agrees to pay on demand all costs and expenses of the Agent in connection with the preparation, execution and delivery of this Amendment and Restatement, including, without limitation, the reasonable fees and out-of-pocket expenses of counsel for the Agent with respect thereto, and all costs and expenses (including, without limitation, counsel fees and expenses), if any, in connection with the enforcement (whether through negotiations, legal proceedings or otherwise) of this Amendment and Restatement. In addition, the Borrower agrees to pay any and all stamp and other taxes payable or determined to be payable in connection with the execution and delivery of this Amendment and Restatement, and the other instruments and documents to be delivered hereunder, and agree to save the Lenders and the Agent harmless from and against any and all liabilities with respect to or resulting from any delay in paying or omission to pay such taxes. SECTION 6. EXECUTION IN COUNTERPARTS. This Amendment and Restatement may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed and delivered shall be deemed to be an original and all of which taken together shall constitute but one and the same instrument. SECTION 7. GOVERNING LAW. This Amendment and Restatement shall be governed by, and construed in accordance with, the internal laws of the State of New York.

S-1 IN WITNESS WHEREOF, the parties hereto have caused this Amendment and Restatement to be duly executed and delivered by their respective duly authorized officers as of the date first above written. TEPPCO PARTNERS, L.P., as Borrower By TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC, as General Partner By /s/ CHARLES H. LEONARD ----------------------------------- Name: Charles H. Leonard Title: SVP, CFO & Treasurer SUNTRUST BANK, as Administrative Agent, LC Issuing Bank and Lender By /s/ STEVE NEWBY -------------------------------------- Name: Steve Newby Title: Vice President SIGNATURE PAGE TO 364-DAY AMENDMENT AND RESTATEMENT

S-2 UBS AG, STAMFORD BRANCH By /s/ WILFRED V. SAINT -------------------------------------- Name: Wilfred V. Saint Title: Associate Director Banking Products Services, US By /s/ ANTHONY N. JOSEPH -------------------------------------- Name: Anthony N. Joseph Title: Associate Director Banking Products Services, US SIGNATURE PAGE TO 364-DAY AMENDMENT AND RESTATEMENT

S-3 BANK ONE, NA By /s/ THOMAS OKAMOTO -------------------------------------- Name: Thomas Okamoto Title: Vice President SIGNATURE PAGE TO 364-DAY AMENDMENT AND RESTATEMENT

S-4 FIRST UNION NATIONAL BANK By /s/ RUSSELL T. CLINGMAN -------------------------------------- Name: Russell T. Clingman Title: Vice President SIGNATURE PAGE TO 364-DAY AMENDMENT AND RESTATEMENT

S-5 THE BANK OF NEW YORK By /s/ PETER W. KELLER -------------------------------------- Name: Peter W. Keller Title: Vice President SIGNATURE PAGE TO 364-DAY AMENDMENT AND RESTATEMENT

S-6 ROYAL BANK OF CANADA By /s/ DAVID A. McCLUSKEY -------------------------------------- Name: David A. McCluskey Title: Manager SIGNATURE PAGE TO 364-DAY AMENDMENT AND RESTATEMENT

S-7 CREDIT LYONNAIS NEW YORK BRANCH By /s/ BERNARD WEYMULLER -------------------------------------- Name: Bernard Weymuller Title: Senior Vice President SIGNATURE PAGE TO 364-DAY AMENDMENT AND RESTATEMENT

S-8 WESTDEUTSCHE LANDESBANK GIROZENTRALE, NEW YORK BRANCH By /s/ JEFFREY S. DAVIDSON -------------------------------------- Name: Jeffrey S. Davidson Title: Associate Director By /s/ PAUL VERDI -------------------------------------- Name: Paul Verdi Title: Manager SIGNATURE PAGE TO 364-DAY AMENDMENT AND RESTATEMENT

S-9 INTENTIONALLY OMITTED SIGNATURE PAGE TO 364-DAY AMENDMENT AND RESTATEMENT

S-10 KBC BANK N.V. By /s/ JEAN-PIERRE DIELS -------------------------------------- Name: Jean-Pierre Diels Title: First Vice President By /s/ ERIC RASKIN -------------------------------------- Name: Eric Raskin Title: Vice President SIGNATURE PAGE TO 364-DAY AMENDMENT AND RESTATEMENT

S-11 BANK OF AMERICA, NATIONAL ASSOCIATION By /s/ RONALD E. McKAIG -------------------------------------- Name: Ronald E. McKaig Title: Managing Director SIGNATURE PAGE TO 364-DAY AMENDMENT AND RESTATEMENT

S-12 THE INDUSTRIAL BANK OF JAPAN, LIMITED By /s/ JAMES W. MASTERS --------------------------------------- Name: James W. Masters Title: Senior Vice President and Manager SIGNATURE PAGE TO 364-DAY AMENDMENT AND RESTATEMENT

S-13 INTENTIONALLY OMITTED SIGNATURE PAGE TO 364-DAY AMENDMENT AND RESTATEMENT

S-14 INTENTIONALLY OMITTED SIGNATURE PAGE TO 364-DAY AMENDMENT AND RESTATEMENT

S-15 NATEXIS BANQUES POPULAIRES By /s/ LOUIS P. LAVILLE, III -------------------------------------- Name: Louis P. Laville, III Title: Vice President and Group Manager By /s/ DANIEL PAYER -------------------------------------- Name: Daniel Payer Title: Vice President SIGNATURE PAGE TO 364-DAY AMENDMENT AND RESTATEMENT

EXHIBIT A SCHEDULE 2 LENDERS AND COMMITMENTS LENDER COMMITMENT SunTrust Bank $24,285,714.11 303 Peachtree St. N.E. 3rd Floor Atlanta, GA 30308 Attn: Steven J. Newby Vice President Phone: 404-658-4916 Fax: 404-827-6270 Bank One, NA $21,428,571.45 Mail Code IL1-0363 1 Bank One Plaza Chicago, IL 60670 Attn: Michele Cellini Assistant Vice President Phone: 312-732-2651 Fax: 312-732-3055 First Union National Bank $21,428,571.45 1001 Fannin Street, Suite 2255 Houston, TX 77002-6709 Attn: Russell T. Clingman Vice President, Energy Investment Banking Phone: 713-346-2716 Fax: 713-650-1071 UBS AG, Stamford Branch $20,000,000.31 677 Washington Boulevard Stamford, CT 06901 Attn: Dorothy L. McKinley Director Phone: 203-719-3158 Fax: 203-719-3092

2 The Bank of New York $14,285,714.30 Oil & Gas Division One Wall Street New York, NY 10286 Attn: Peter W. Keller Vice President Phone: 212-635-7861 Fax: 212-635-7923 Credit Lyonnais New York Branch $14,285,714.30 1301 Avenue of the Americas New York, NY 10019-6022 Attn: Philippe Soustra Executive Vice President Phone: 212-261-7000 Fax: 212-459-3170 Royal Bank of Canada $14,285,714.30 (Royal Bank Financial Group) Global Bank - Debt Products 2800 Post Oak Blvd. Houston, TX 77056 Attn: David McCluskey Manager Phone: 713-403-5666 Fax: 713-403-5624 Westdeutsche Landesbank Gironzentrale, New York Branch $11,428,571.44 1211 Avenue of the Americas New York, NY 10036 Attn: Duncan M. Robertson Director, Credit Department Phone: 212-852-6107 Fax: 212-852-6148 Bank of America, National Association $7,142,857.15 Energy & Power - Houston 333 Clay Street, Suite 4550 Houston, TX 77002 Attn: Mike Dillon Managing Director Phone: 713-651-4903 Fax: 713-651-4904

3 KBC Bank N.V $7,142,857.15 New York Branch 125 West 55th Street New York, NY 10019 Attn: Patrick A. Janssens Vice President Phone: 212-541-0714 Fax: 212-541-0784 The Industrial Bank of Japan, Limited $4,285,714.29 Corporate Finance Division #1 191 Peachtree St., N.E., Suite 3825 Atlanta, GA 30303-1757 Attn: William D. LaDuca Vice President Phone: 404-524-8770 ext. 105 Fax: 404-524-8509 Natexis Banque Populaires $4,285,714.00 333 Clay Street, Suite 4340 Houston, TX 77002 Attn: Parker Laville Vice President and Group Manager Phone: 713-759-9401 Fax: 713-759-9908 TOTAL COMMITMENTS $164,285,714.25

EXHIBIT B FORM OF CONSENT Dated as of November 13, 2001 The undersigned, [NAME OF GUARANTOR] (the "COMPANY"), as guarantor under the Guaranty, dated as of April 6, 2001, made by the Company to SunTrust Bank, as administrative agent (the "ADMINISTRATIVE AGENT") for the lenders (the "LENDERS") party to the 364-Day Credit Agreement, dated as of April 6, 2001, as amended as of September 28, 2001 (as amended, the "CREDIT AGREEMENT"), among TEPPCO Partners, L.P. (the "BORROWER"), the Lenders and the Administrative Agent, hereby consents to the amendment and restatement of the Credit Agreement by the Amendment and Restatement, dated as of November 13, 2001 (the "AMENDMENT AND RESTATEMENT"), among the Borrower, the Lenders signatories thereto and the Administrative Agent, and hereby confirms and agrees that (i) the Guaranty is, and shall continue to be, in full force and effect and is hereby ratified and confirmed in all respects except that, upon the effectiveness of, and on and after the date of, the Amendment and Restatement, each reference in the Guaranty to the "Credit Agreement", "thereunder", "thereof" or words of like import referring to the Credit Agreement shall mean and be a reference to the Credit Agreement, as amended by the Amendment and Restatement and (ii) the Guaranty is, and shall continue to, be an unconditional and irrevocable guaranty of all of the Obligations (as defined in the Guaranty). [NAME OF GUARANTOR] By ------------------------------------- Name: Title:

EXHIBIT 10.36 SECOND AMENDMENT AND RESTATEMENT SECOND AMENDMENT AND RESTATEMENT, dated as of November 13, 2001 (this "AMENDMENT AND RESTATEMENT"), to that certain AMENDED AND RESTATED CREDIT AGREEMENT, dated as of April 6, 2001 (the "EXISTING AGREEMENT", and as amended by this Amendment and Restatement, the "AMENDED AND RESTATED AGREEMENT"), among TEPPCO PARTNERS, L.P., a Delaware limited partnership (the "BORROWER"), the lenders party thereto and SunTrust Bank, as administrative agent for the lenders party thereto and as issuer of letters of credit (the "AGENT"). PRELIMINARY STATEMENT The Borrower, certain lenders and the Agent previously entered into the Existing Agreement. The Borrower and the other parties hereto (the "LENDERS") now wish to amend the Existing Agreement in its entirety to read as set forth in the Existing Agreement with the amendments set forth below. The parties therefore agree as follows (capitalized terms used but not defined herein having the meanings assigned to such terms in the Existing Agreement): SECTION 1. AMENDMENTS TO EXISTING AGREEMENT. The Existing Agreement is, effective as of the date hereof and subject to the satisfaction of the conditions precedent set forth in Section 2 hereof, hereby amended as follows: (a) Schedule 2 is hereby amended in its entirety to read as set forth in Exhibit A attached hereto. (b) Paragraph (ii) of Section 3.2(c) is amended in its entirety to read as follows: "The Borrower shall promptly notify the Administrative Agent upon the receipt of Net Cash Proceeds of any Asset Disposition or Recovery Event and, at any time that such Net Cash Proceeds received and not previously applied to any prepayment pursuant to this Section 3.2(c)(ii) shall equal or exceed $10,000,000, the Borrower shall prepay Borrowings, together with payment of any Funding Losses, and/or deposit funds in the Cash Collateral Account in respect of LC Outstandings pursuant to Section 12.1(d), as applicable, in an aggregate amount equal to 100% (without duplication) of such Net Cash Proceeds to the Borrowings and/or the cash collateralization of LC Outstandings pursuant to Section 12.1(d)." SECTION 2. CONDITIONS OF EFFECTIVENESS OF AMENDMENT AND RESTATEMENT. Section 1 of this Amendment and Restatement shall become effective as of the date first set forth above when each of the following conditions shall have been fulfilled:

2 (i) all of the Lenders and the Borrower shall have executed and delivered to the Agent a counterpart of this Amendment and Restatement; (ii) all of the Guarantors shall have executed and delivered the consent to this Amendment and Restatement in substantially the form of Exhibit B attached hereto; (iii) the representations and warranties set forth in Section 3 hereof shall be true and correct on and as of the date of effectiveness of this Amendment and Restatement as though made on and as of such date; and (iv) the Borrower shall have delivered an opinion of counsel in form reasonably acceptable to the Agent. SECTION 3. REPRESENTATIONS AND WARRANTIES. The Borrower represents and warrants that (a) the representations and warranties contained in Article VII of the Amended and Restated Agreement (with each reference therein to (i) "this Agreement", "hereunder" and words of like import referring to the Existing Agreement being deemed to be a reference to this Amendment and Restatement and the Amended and Restated Agreement and (ii) "Credit Documents", "thereunder" and words of like import being deemed to include this Amendment and Restatement and the Amended and Restated Agreement) are true and correct on and as of the date hereof as though made on and as of such date, and (b) no event has occurred and is continuing, or would result from the execution and delivery of this Amendment and Restatement, that constitutes an Event of Default. SECTION 4. EFFECT ON THE CREDIT AGREEMENT. Except as specifically amended above, the Existing Agreement shall continue to be in full force and effect and is hereby in all respects ratified and confirmed. The execution, delivery and effectiveness of this Amendment and Restatement shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of the Lenders under the Existing Agreement, nor constitute a waiver of any provision of the Existing Agreement. SECTION 5. COSTS AND EXPENSES. The Borrower agrees to pay on demand all costs and expenses of the Agent in connection with the preparation, execution and delivery of this Amendment and Restatement, including, without limitation, the reasonable fees and out-of-pocket expenses of counsel for the Agent with respect thereto, and all costs and expenses (including, without limitation, counsel fees and expenses), if any, in connection with the enforcement (whether through negotiations, legal proceedings or otherwise) of this Amendment and Restatement. In addition, the Borrower agrees to pay any and all stamp and other taxes payable or determined to be payable in connection with the execution and delivery of this Amendment and Restatement, and the other instruments and documents to be delivered hereunder, and agree to save the Lenders and the Agent harmless from and against any and all liabilities with respect to or resulting from any delay in paying or omission to pay such taxes. SECTION 6. EXECUTION IN COUNTERPARTS. This Amendment and Restatement may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed and delivered shall be deemed to be an original and all of which taken together shall constitute but one and the same instrument.

3 SECTION 7. GOVERNING LAW. This Amendment and Restatement shall be governed by, and construed in accordance with, the internal laws of the State of New York.

S-1 IN WITNESS WHEREOF, the parties hereto have caused this Amendment and Restatement to be duly executed and delivered by their respective duly authorized officers as of the date first above written. TEPPCO PARTNERS, L.P., as Borrower By TEXAS EASTERN PRODUCTS PIPELINE COMPANY, LLC, as General Partner By /s/ CHARLES H. LEONARD ---------------------------------- Name: Charles H. Leonard Title: SVP, CFO & Treasurer SUNTRUST BANK, as Administrative Agent, LC Issuing Bank and Lender By /s/ STEVE NEWBY ------------------------------------ Name: Steve Newby Title: Vice President SIGNATURE PAGE TO 3-YEAR AMENDMENT AND RESTATEMENT

S-2 UBS AG, STAMFORD BRANCH By /s/ WILFRED V. SAINT ------------------------------------- Name: Wilfred V. Saint Title: Associate Director Banking Products Services, US By /s/ ANTHONY N. JOSEPH ------------------------------------- Name: Anthony N. Joseph Title: Associate Director Banking Products Services, US SIGNATURE PAGE TO 3-YEAR AMENDMENT AND RESTATEMENT

S-3 BANK ONE, NA By /s/ THOMAS OKAMOTO ------------------------------------- Name: Thomas Okamoto Title: Vice President SIGNATURE PAGE TO 3-YEAR AMENDMENT AND RESTATEMENT

S-4 FIRST UNION NATIONAL BANK By /s/ RUSSELL T. CLINGMAN ------------------------------------- Name: Russell T. Clingman Title: Vice President SIGNATURE PAGE TO 3-YEAR AMENDMENT AND RESTATEMENT

S-5 THE BANK OF NEW YORK By /s/ PETER W. KELLER ------------------------------------- Name: Peter W. Keller Title: Vice President SIGNATURE PAGE TO 3-YEAR AMENDMENT AND RESTATEMENT

S-6 ROYAL BANK OF CANADA By /s/ DAVID A. McCLUSKEY ------------------------------------- Name: David A. McCluskey Title: Manager SIGNATURE PAGE TO 3-YEAR AMENDMENT AND RESTATEMENT

S-7 CREDIT LYONNAIS NEW YORK BRANCH By /s/ BERNARD WEYMULLER ------------------------------------- Name: Bernard Weymuller Title: Senior Vice President SIGNATURE PAGE TO 3-YEAR AMENDMENT AND RESTATEMENT

S-8 WESTDEUTSCHE LANDESBANK GIROZENTRALE, NEW YORK BRANCH By /s/ JEFFREY S. DAVIDSON ------------------------------------- Name: Jeffrey S. Davidson Title: Associate Director By /s/ PAUL VERDI ------------------------------------- Name: Paul Verdi Title: Manager SIGNATURE PAGE TO 3-YEAR AMENDMENT AND RESTATEMENT

S-9 INTENTIONALLY OMITTED SIGNATURE PAGE TO 3-YEAR AMENDMENT AND RESTATEMENT

S-10 KBC BANK N.V. By /s/ JEAN-PIERRE DIELS ------------------------------------- Name: Jean-Pierre Diels Title: First Vice President By /s/ ERIC RASKIN ------------------------------------- Name: Eric Raskin Title: Vice President SIGNATURE PAGE TO 3-YEAR AMENDMENT AND RESTATEMENT

S-11 BANK OF AMERICA, NATIONAL ASSOCIATION By /s/ RONALD E. McKAIG ------------------------------------- Name: Ronald E. McKaig Title: Managing Director SIGNATURE PAGE TO 3-YEAR AMENDMENT AND RESTATEMENT

S-12 THE INDUSTRIAL BANK OF JAPAN, LIMITED By /s/ JAMES W. MASTERS ------------------------------------- Name: James W. Masters Title: Senior Vice President and Manager SIGNATURE PAGE TO 3-YEAR AMENDMENT AND RESTATEMENT

S-13 INTENTIONALLY OMITTED SIGNATURE PAGE TO 3-YEAR AMENDMENT AND RESTATEMENT

S-14 INTENTIONALLY OMITTED SIGNATURE PAGE TO 3-YEAR AMENDMENT AND RESTATEMENT

S-15 NATEXIS BANQUES POPULAIRES By /s/ LOUIS P. LAVILLE, III --------------------------------------- Name: Louis P. Laville, III Title: Vice President and Group Manager By /s/ DANIEL PAYER --------------------------------------- Name: Daniel Payer Title: Vice President SIGNATURE PAGE TO 3-YEAR AMENDMENT AND RESTATEMENT

EXHIBIT A SCHEDULE 2 LENDERS AND COMMITMENTS LENDER COMMITMENT SunTrust Bank $60,714,285.89 303 Peachtree St. N.E. 3rd Floor Atlanta, GA 30308 Attn: Steven J. Newby Vice President Phone: 404-658-4916 Fax: 404-827-6270 Bank One, NA $53,571,428.55 Mail Code IL1-0363 1 Bank One Plaza Chicago, IL 60670 Attn: Michele Cellini Assistant Vice President Phone: 312-732-2651 Fax: 312-732-3055 First Union National Bank $53,571,428.55 1001 Fannin Street, Suite 2255 Houston, TX 77002-6709 Attn: Russell T. Clingman Vice President, Energy Investment Banking Phone: 713-346-2716 Fax: 713-650-1071 UBS AG, Stamford Branch $49,999,999.69 677 Washington Boulevard Stamford, CT 06901 Attn: Dorothy L. McKinley Director Phone: 203-719-3158 Fax: 203-719-3092

2 The Bank of New York $35,714,285.70 Oil & Gas Division One Wall Street New York, NY 10286 Attn: Peter W. Keller Vice President Phone: 212-635-7861 Fax: 212-635-7923 Credit Lyonnais New York Branch $35,714,285.70 1301 Avenue of the Americas New York, NY 10019-6022 Attn: Philippe Soustra Executive Vice President Phone: 212-261-7000 Fax: 212-459-3170 Royal Bank of Canada $35,714,285.70 (Royal Bank Financial Group) Global Bank - Debt Products 2800 Post Oak Blvd. Houston, TX 77056 Attn: David McCluskey Manager Phone: 713-403-5666 Fax: 713-403-5624 Westdeutsche Landesbank Gironzentrale, New York Branch $28,571,428.56 1211 Avenue of the Americas New York, NY 10036 Attn: Duncan M. Robertson Director, Credit Department Phone: 212-852-6107 Fax: 212-852-6148 Bank of America, National Association $17,857,142.85 Energy & Power - Houston 333 Clay Street, Suite 4550 Houston, TX 77002 Attn: Mike Dillon Managing Director Phone: 713-651-4903 Fax: 713-651-4904

3 KBC Bank N.V $17,857,142.85 New York Branch 125 West 55th Street New York, NY 10019 Attn: Patrick A. Janssens Vice President Phone: 212-541-0714 Fax: 212-541-0784 The Industrial Bank of Japan, Limited $10,714,285.71 Corporate Finance Division # 1 191 Peachtree St., N.E., Suite 3825 Atlanta, GA 30303-1757 Attn: William D. LaDuca Vice President Phone: 404-524-8770 ext. 105 Fax: 404-524-8509 Natexis Banque Populaires $10,714,286.00 333 Clay Street, Suite 4340 Houston, TX 77002 Attn: Parker Laville Vice President and Group Manager Phone: 713-759-9401 Fax: 713-759-9908 TOTAL COMMITMENTS $410,714,285.75

EXHIBIT B FORM OF CONSENT Dated as of November 13, 2001 The undersigned, [NAME OF GUARANTOR] (the "COMPANY"), as guarantor under the Guaranty, dated as of April 6, 2001, made by the Company to SunTrust Bank, as administrative agent (the "ADMINISTRATIVE AGENT") for the lenders (the "LENDERS") party to the 3-Year Amended and Restated Credit Agreement, dated as of April 6, 2001, as amended as of September 28, 2001 (as amended, the "CREDIT AGREEMENT"), among TEPPCO Partners, L.P. (the "Borrower"), the Lenders and the Administrative Agent, hereby consents to the amendment and restatement of the Credit Agreement by the Second Amendment and Restatement, dated as of November 13, 2001 (the "AMENDMENT AND RESTATEMENT"), among the Borrower, the Lenders signatories thereto and the Administrative Agent, and hereby confirms and agrees that (i) the Guaranty is, and shall continue to be, in full force and effect and is hereby ratified and confirmed in all respects except that, upon the effectiveness of, and on and after the date of, the Amendment and Restatement, each reference in the Guaranty to the "Credit Agreement", "thereunder", "thereof" or words of like import referring to the Credit Agreement shall mean and be a reference to the Credit Agreement, as amended by the Amendment and Restatement and (ii) the Guaranty is, and shall continue to, be an unconditional and irrevocable guaranty of all of the Obligations (as defined in the Guaranty). [NAME OF GUARANTOR] By ----------------------------------------- Name: Title:

EXHIBIT 10.40 JONAH GAS GATHERING COMPANY AGREEMENT OF PARTNERSHIP DATED: JUNE 20, 1996

TABLE OF CONTENTS ARTICLE I DEFINITIONS 1.01 Act.................................................................1 1.02 Additional Partner..................................................1 1.03 Admission Agreement.................................................1 1.04 Affiliate...........................................................1 1.05 Agreement and Partnership Agreement.................................2 1.06 Assignee............................................................2 1.07 Bankrupt Partner....................................................2 1.08 Book Adjustments....................................................2 1.09 Book Value..........................................................2 1.10 Business Day........................................................2 1.11 Capital Account.....................................................2 1.12 Capital Contribution................................................2 1.13 Code................................................................3 1.14 Commitment..........................................................3 1.15 Contributing Partners...............................................3 1.16 Default Interest Rate...............................................3 1.17 Delinquent Partner..................................................3 1.18 Disposition.........................................................3 1.19 Dissociation........................................................3 1.20 Dissociated Partner.................................................3 1.21 Distribution........................................................3 1.22 Effective Date......................................................4 1.23 Entity..............................................................4 1.24 Expansion...........................................................4 1.25 Fiscal Year.........................................................4 1.26 GAAP................................................................4 1.27 Initial Contribution................................................4 1.28 Initial Partners....................................................4 1.29 Jonah Field Gathering System........................................4 1.30 Liquidating Distribution............................................4 1.31 Majority of the Partners............................................4 1.32 Majority of the Remaining Partners..................................5 1.33 Management Committee................................................5 1.34 Management Right....................................................5 1.35 Managing Partner....................................................5 1.36 Money...............................................................5 1.37 Net Losses and Net Profits..........................................5 1.38 Nonrecourse Liabilities.............................................5 1.39 Notice..............................................................6 1.40 Operating Agreement.................................................6 1.41 Operator............................................................6 1.42 Partner.............................................................6 i

1.43 Partner Minimum Gain................................................6 1.44 Partner Nonrecourse Liability.......................................6 1.45 Partnership.........................................................6 1.46 Partnership Interest................................................6 1.47 Partnership Minimum Gain............................................6 1.48 Partnership Nonrecourse Liability...................................7 1.49 Partnership Property................................................7 1.50 Person..............................................................7 1.51 Proceeding..........................................................7 1.52 Property............................................................7 1.53 Regulations.........................................................7 1.54 Related Person......................................................7 1.55 Remaining Partners..................................................7 1.56 Reserves............................................................8 1.57 Revaluation.........................................................8 1.58 Revaluation Date....................................................8 1.59 Revaluation Event...................................................8 1.60 Sharing Ratio.......................................................8 1.61 Substitute Partner..................................................8 1.62 Taxable Year........................................................8 1.63 Taxing Jurisdiction.................................................8 ARTICLE II FORMATION OF PARTNERSHIP 2.01 Formation...........................................................8 2.02 Filings.............................................................9 2.03 Name................................................................9 2.04 Principal Place of Business.........................................9 2.05 Term................................................................9 2.06 Bank Accounts.......................................................9 ARTICLE III BUSINESS OF PARTNERSHIP ARTICLE IV ACCOUNTING AND RECORDS 4.01 Records to be Maintained...........................................10 4.02 Reports to Partners................................................11 ARTICLE V MANAGING PARTNER AND RIGHTS AND DUTIES OF PARTNERS 5.01 Management Rights..................................................11 5.02 Managing Partner...................................................12 5.03 Authority of Managing Partner to Bind the Partnership..............12 5.04 Compensation of Managing Partner...................................12 5.05 Managing Partner's Standard of Care................................12 5.06 Indemnification....................................................13 ii

5.07 Representations and Warranties.....................................13 5.08 Notice of Claims...................................................13 ARTICLE VI MANAGEMENT COMMITTEE 6.01 Establishment of Committee.........................................13 6.02 Powers and Duties of Management Committee..........................14 6.03 Authority to Vote..................................................14 6.04 Notice of Meeting..................................................14 6.05 Contents of Meeting Notice.........................................14 6.06 Location of Meetings...............................................15 6.07 Managing Partner's Duties for Meetings.............................15 6.08 Voting Procedure...................................................15 6.09 Record of Votes....................................................15 6.10 Minutes............................................................15 6.11 Voting by Notice...................................................15 6.12 Effect of Vote.....................................................16 ARTICLE VII CONFLICTS OF INTEREST 7.01 Partnership Opportunities..........................................16 7.02 Self Dealing.......................................................16 ARTICLE VIII CAPITAL CONTRIBUTIONS 8.01 Initial Contributions..............................................17 8.02 Additional Contributions...........................................17 8.03 Enforcement of Commitments.........................................17 8.04 Maintenance of Capital Accounts....................................18 8.05 Distribution of Assets.............................................18 8.06 Sale or Exchange of Interest.......................................18 8.07 Revaluation of Partnership Property................................19 8.08 Compliance with Section 704(b) of the Code.........................19 8.09 Non-Consent Operations.............................................19 ARTICLE IX ALLOCATION AND DISTRIBUTIONS 9.01 Allocations of Net Profits and Net Losses from Operations..........20 9.02 Partnership Minimum Gain Chargeback................................21 9.03 Partner Minimum Gain Chargeback....................................21 9.04 Qualified Income Offset............................................21 9.05 Interim Distributions..............................................22 9.06 Distributions......................................................22 ARTICLE X TAXES 10.01 Tax Returns........................................................22 iii

10.02 Tax Matters Partner................................................22 10.03 Information Request by TMP.........................................23 10.04 TMP Agreements with IRS............................................23 10.05 Inconsistent Treatment of Partnership Item.........................23 10.06 Requests for Administrative Adjustment.............................23 10.07 Judicial Proceedings...............................................24 10.08 Elections..........................................................24 10.09 Taxes of Taxing Jurisdictions......................................24 ARTICLE XI DISPOSITION OF PARTNERSHIP INTERESTS 11.01 Disposition........................................................25 11.02 Right of First Refusal.............................................25 11.03 Dispositions Not in Compliance With This Article Void..............26 ARTICLE XII DISSOCIATION OF A PARTNER 12.01 Dissociation.......................................................27 12.02 Purchase of Dissociated Partner's Partnership Interest.............27 12.03 Purchase Price of Dissociated Partner's Partnership Interest.......27 12.04 Damages. 28 ARTICLE XIII ADMISSION OF ASSIGNEES AND ADDITIONAL PARTNERS 13.01 Rights of Assignees................................................28 13.02 Admission of Substitute Partners...................................28 13.03 Admission of Additional Partners...................................28 ARTICLE XIV DISSOLUTION AND WINDING UP 14.01 Dissolution........................................................29 14.02 Effect of Dissolution..............................................29 14.03 Distribution of Assets on Dissolution..............................29 ARTICLE XV AMENDMENT ARTICLE XVI MISCELLANEOUS PROVISIONS 16.01 Entire Agreement...................................................30 16.02 Rights of Creditors and Third Parties Under Partnership Agreement..30 16.03 Notices. 30 16.04 Application of Wyoming Law.........................................30 16.05 Entire Agreement...................................................31 16.06 Waiver of Action for Partition.....................................31 16.07 Counterparts.......................................................31 iv

THIS AGREEMENT OF PARTNERSHIP is executed this 20th day of June, 1996, by and between Green River Pipeline Limited Liability Company ("Green River"), a Wyoming limited liability company with a business address of 350 Big Horn Road, Casper, Wyoming 82601, and Jonah Pipeline Company ("Jonah"), a Michigan corporation, with a business address of 150 West Jefferson Avenue, Suite 1900, Detroit, Michigan 48226. W I T N E S S E T H: WHEREAS, Green River and Jonah are the owners of the Jonah Field Gas Gathering System which is comprised of the real and personal property described on Exhibit "A-1" attached hereto, said property being hereinafter referred to as the "Jonah Field Gathering System"; and WHEREAS, the parties desire to form a general partnership (the "Partnership") under the Wyoming Uniform Partnership Act, Wyoming Statutes Annotated, Sections 17-21-101, et seq. as the same may be amended from time to time (the "Act") for the purposes of owning and operating the Jonah Field Gathering System and for such other purposes hereinafter set forth; NOW, THEREFORE, in consideration of the agreements and obligations of the parties set forth herein and for other good and valuable consideration, the receipt, sufficiency, adequacy and fairness of which being hereby acknowledged, the parties hereby agree as follows. ARTICLE I DEFINITIONS The following terms used in the Agreement shall (unless otherwise expressly provided herein) have the following meanings: 1.01 ACT. "Act" means the Wyoming Uniform Partnership Act, Wyo. Stats. Ann. Sections 17-21-101, et seq., as amended from time to time. Reference to any section of the Act shall be deemed to refer to a similar provision in any amendment to the Act. 1.02 ADDITIONAL PARTNER. A Partner other than an Initial Partner or a Substitute Partner who has acquired a Partnership Interest from the Partnership. 1.03 ADMISSION AGREEMENT. The Agreement governing the admission of an Additional Partner into the Partnership. 1.04 AFFILIATE. The term "Affiliate" shall mean when used with reference to a specified Person any Person which controls the specified Person, which is controlled by the specified Person, or which

is under common control with the specified Person. Control means the power to exercise, directly or indirectly, more than fifty percent (50%) of the voting rights of an Entity. 1.05 AGREEMENT AND PARTNERSHIP AGREEMENT. "Agreement and "Partnership Agreement" means this Agreement of Partnership, as originally executed and as amended or restated from time to time, as the context requires. 1.06 ASSIGNEE. "Assignee" means a person who has acquired from a Partner, in accordance with the terms of this Agreement, a beneficial interest in the Partnership's Profits, Losses, Credits, or Distributions, but who is not a Substitute Partner. 1.07 BANKRUPT PARTNER. A Partner who: (1) has become the subject of an Order for Relief under the United States Bankruptcy Code, (2) has initiated, either in an original proceeding or by way of answer in any state insolvency or receivership proceeding, an action for liquidation arrangement, composition, readjustment, dissolution, or similar relief. 1.08 BOOK ADJUSTMENTS. Adjustments with respect to the Book Value of Partnership Property for depreciation, depletion, amortization, and gain or loss, as computed in accordance with Section 1.704-1(b)(2)(iv)(g) of the Regulations. 1.09 BOOK VALUE. With respect to Property contributed to the Partnership, the fair market value of the Property at the time of Contribution as adjusted by Book Adjustments; with respect to Partnership Property which has been Revalued, the fair market value of such Partnership Property as adjusted by Book Adjustments. 1.10 BUSINESS DAY. Any day other than Saturday, Sunday or any legal holiday observed in the States of Wyoming or Michigan. 1.11 CAPITAL ACCOUNT. The account maintained for a Partner or Assignee determined in accordance with Article VIII. 1.12 CAPITAL CONTRIBUTION. "Capital Contribution" means the total amount of contributions by all the Partners, of any class of Partners or any one Partner, as the case may be (or the predecessor holders of the interests of such Partner or Partners), to the capital of the Partnership in cash, property or 2

services for an interest in the Partnership, valued at fair market value without deduction of selling, organization or other expenses; and shall include all such contributions to the capital of the Partnership whenever made. 1.13 CODE. "Code" means the Internal Revenue Code of 1986, as amended, or any corresponding provision or provisions of succeeding laws. 1.14 COMMITMENT. The obligation of a Partner or Assignee to make a Capital Contribution in the future. 1.15 CONTRIBUTING PARTNERS. Partners making Capital Contributions as a result of the failure of a Delinquent Partner to perform a Commitment as described in Article VIII. 1.16 DEFAULT INTEREST RATE. A floating rate equal to the prime rate quoted by Norwest Bank Colorado, N.A., plus three percent (3%). 1.17 DELINQUENT PARTNER. A Partner or Assignee who has failed to meet the Commitment of that Partner or Assignee. 1.18 DISPOSITION. Any sale, assignment, transfer, exchange, mortgage, pledge, grant, hypothecation, or other transfer, absolute or as security or encumbrance (including dispositions by operation of law). 1.19 DISSOCIATION. Any action which causes a Person to cease to be Partner as described in Article XII hereof. 1.20 DISSOCIATED PARTNER. A Person who has ceased to be Partner as a result of Dissociation in Article XII hereof. 1.21 DISTRIBUTION. "Distribution" means any cash or property which the Partnership distributes to a Partner in its capacity as a Partner. 3

1.22 EFFECTIVE DATE. "Effective Date" means June 20, 1996 at 12:01 A.M., Rocky Mountain Time. 1.23 ENTITY. "Entity" means any general partnership, limited partnership, corporation, joint venture, trust, business trust, cooperative, association, limited liability company, limited liability partnership or any other organization recognized by the law of Wyoming. 1.24 EXPANSION. "Expansion" shall mean any extension of the Jonah Field Gathering System to include acquisition or construction of additional gathering or delivery points and any increase in the capacity of said System to deliver natural gas through compression, the use of more or larger pipelines or otherwise. 1.25 FISCAL YEAR. "Fiscal Year" means the Partnership's fiscal year, which shall end on December 31. 1.26 GAAP. "GAAP" shall mean generally accepted accounting principles as prescribed from time to time by the Financial Accounting Standards Board. 1.27 INITIAL CONTRIBUTION. The Contribution agreed to be made by the Initial Partners as described in Article VIII. 1.28 INITIAL PARTNERS. Those persons identified on Exhibit "A" attached hereto and made a part hereof by this reference who have executed this Partnership Agreement. 1.29 JONAH FIELD GATHERING SYSTEM. "Jonah Field Gathering System" means that real and personal property described on Exhibit "A-1" attached hereto. 1.30 LIQUIDATING DISTRIBUTION. A Distribution made as consideration for a Partnership Interest. 1.31 MAJORITY OF THE PARTNERS. One or more Partners having Sharing Ratios in excess of one-half of the Sharing Ratios of all the Partners entitled to vote on, consent to, or approve a particular matter. Assignees shall not be considered Partners entitled to vote for the purpose of determining a majority. In the case 4

of a Partner who has disposed of that Partner's entire Partnership Interest to an Assignee, but has not ceased to be a Partner as provided below, the Sharing Ratio of such Assignee shall be considered in determining a Majority of the Partners and such Partner's vote or consent shall be determined by such Sharing Ratio. 1.32 MAJORITY OF THE REMAINING PARTNERS. Remaining Partners having Sharing Ratios equal to more than one-half of the Sharing Ratios of all the Remaining Partners entitled to vote on, consent to, or approve a particular matter. Assignees shall not be considered Partners entitled to vote for the purpose of determining a Majority of Remaining Partners. In the case of a Remaining Partner who has disposed of that Partner's entire Partnership Interest to an Assignee, but has not ceased to be a Partner as provided below, the Sharing Ratio of such Assignee shall be considered in determining a Majority of the Remaining Partners and such Remaining Partner's vote or consent shall be determined by such Sharing Ratio. 1.33 MANAGEMENT COMMITTEE. The committee composed of the representatives of the Partners and established pursuant to Article VI for the purpose of managing the Partnership. 1.34 MANAGEMENT RIGHT. The right of a Partner to participate in the management of the Partnership, including the rights to information and to consent or approve actions of the Partnership. 1.35 MANAGING PARTNER. "Managing Partner" shall be that Partner designated by the Management Committee to manage the Partnership's business. 1.36 MONEY. Cash or other legal tender of the United States, or any obligation that is immediately reducible to legal tender without delay or discount. Money shall be considered to have a fair market value equal to its face amount. 1.37 NET LOSSES AND NET PROFITS. The losses, deductions, income and gains of the Partnership shall be determined in accordance with Section 703(a) of the Code. 1.38 NONRECOURSE LIABILITIES. Nonrecourse liabilities include Partnership Nonrecourse Liabilities and Partner Nonrecourse Liabilities. 5

1.39 NOTICE. Notice shall be in writing and given as provided in Article XVI below. 1.40 OPERATING AGREEMENT. "Operating Agreement" shall mean that agreement between McMurry Oil Company and the Partnership providing for the day-to-day operation of the Jonah Field Gathering System, and any successor agreement. 1.41 OPERATOR. "Operator" shall be the Person designated to operate the Jonah Field Gathering System pursuant to the terms of the Operating Agreement. 1.42 PARTNER. An Initial Partner, Substituted Partner or Additional Partner, including, unless the context expressly indicates to the contrary, the Managing Partner and, for purposes of Articles VIII and IX only, an Assignee. 1.43 PARTNER MINIMUM GAIN. An amount determined pursuant to Regulation 1.704-2(g). Partner Minimum Gain and increases and decreases in Partner Minimum Gain are intended to be computed in accordance with Section 704 of the Code and the Regulations issued thereunder, as the same may be issued and interpreted from time to time. 1.44 PARTNER NONRECOURSE LIABILITY. "Partner Nonrecourse Liability" shall be as defined in Regulation 1.704-2(b)(4). 1.45 PARTNERSHIP. "Partnership" means the Partnership created by this Agreement. 1.46 PARTNERSHIP INTEREST. The rights of a Partner or, in the case of an Assignee, the rights of the assigning Partner in Distributions (liquidating or otherwise) and allocations of the profits, losses, gains, deductions, and credits of the Partnership. 1.47 PARTNERSHIP MINIMUM GAIN. An amount determined pursuant to Regulation 1.704-2(d). 6

1.48 PARTNERSHIP NONRECOURSE LIABILITY. A Partnership Liability to the extent that no Partner or Related Person bears the economic risk of loss (as defined in Section 1.752-2 of the Regulations) with respect to the liability. 1.49 PARTNERSHIP PROPERTY. Any Property owned by the Partnership. 1.50 PERSON. "Person" means any individual or Entity, and the heirs, executors, administrators, legal representatives, successors and assigns of such Person where the context so admits. 1.51 PROCEEDING. Any judicial or administrative trial, hearing or other activity, civil, criminal or investigative, the result of which may be that a court, arbitrator, or governmental agency may enter a judgment, order, decree, or other determination which, if not appealed and reversed, would be binding upon the Partnership, a Partner or other Person subject to the jurisdiction of such court, arbitrator, or governmental agency. 1.52 PROPERTY. Any property real or personal, tangible or intangible (including goodwill), including Money and any legal or equitable interest in such property, but excluding services and promises to perform services in the future. 1.53 REGULATIONS. Except where the context indicates otherwise, the permanent and temporary regulations of the Department of the Treasury under the Code as such regulations may be lawfully changed from time to time. 1.54 RELATED PERSON. A person having a relationship to a Partner that is described in Section 1.752-4(b) of the Regulations. 1.55 REMAINING PARTNERS. In the event of the Dissociation of a Partner, all of the Partners at the time of such Dissociation other than the Partner who has dissociated. In the event of a Partner who has any potential conflict of interest or transaction between a Partner and the Partnership, the Partners not having the potential conflict of interest or participating in the transaction. In the event of the transfer of a Partnership Interest, all of the Partners other than the transferring Partner. 7

1.56 RESERVES. "Reserves" means, with respect to any fiscal period, funds set aside or amounts allocated during such period to reserves which shall be maintained in amounts reasonably deemed sufficient by the Managing Partner for working capital or to pay taxes, insurance, debt service or other costs or expenses incident to the ownership or operation of the Partnership business. 1.57 REVALUATION. The adjustment to the Book Value of Partnership Property as provided in Section 8.07 of this Partnership Agreement. 1.58 REVALUATION DATE. The date on which a Revaluation Event occurs. 1.59 REVALUATION EVENT. (1) a Contribution (other than a de minimis amount, (2) a Liquidating Distribution (other than a de minimis amount), or (3) a Liquidation of the Partnership. 1.60 SHARING RATIO. With respect to any Partner, a fraction (expressed as a percentage), the numerator of which is the total of the Partner's Capital Account and the denominator is the total of all Capital Accounts of all Partners and Assignees. 1.61 SUBSTITUTE PARTNER. An Assignee who has been admitted to all of the rights of a Partner pursuant to this Partnership Agreement. 1.62 TAXABLE YEAR. The taxable year of the Partnership as determined pursuant to Section 706 of the Code. 1.63 TAXING JURISDICTION. Any state, local, or foreign government that collects tax, interest or penalties, however designated, on any Partner's share of the income or gain attributable to the Partnership. ARTICLE II FORMATION OF PARTNERSHIP 2.01 FORMATION. The parties hereby form and create a general partnership under and pursuant to the Act. 8

2.02 FILINGS. The Partners shall promptly sign a Statement of Partnership Authority pursuant to Section 303 of the Act and shall cause the Statement to be filed with the Wyoming Secretary of State and a certified copy of said filing to be recorded in the records of Sublette County, Wyoming, pursuant to Wyoming Statutes Annotated, Section 17-21-105. 2.03 NAME. The name of the Partnership is Jonah Gas Gathering Company, with such changes or variations as the Managing Partner may consider necessary or advisable to comply with the requirements of law or regulatory bodies in any jurisdiction in which the Partnership may do business. 2.04 PRINCIPAL PLACE OF BUSINESS. The principal place of business of the Partnership shall be at 350 Big Horn Road, Casper, Wyoming 82601, or at any other location as may hereafter be determined by the Managing Partner. The Managing Partner shall promptly notify each of the Partners of any change in the principal place of business of the Partnership. The Partnership's agent for service of process shall be John W. Martin at the foregoing address. 2.05 TERM. The term of the Partnership shall be from the Effective Date and shall continue in full force and effect until December 31, 2026, unless (i) the Partners unanimously agree to extend the term of the Partnership for a longer duration, or (ii) the Partnership is earlier dissolved in accordance with the provisions of this Agreement. 2.06 BANK ACCOUNTS. All funds received by the Partnership which are not distributed to the Partners shall be deposited in one or more accounts to be established in the name of the Partnership by the Managing Partner. All disbursements of Partnership funds shall be from such accounts upon the signature of the Managing Partner or its authorized representative. Partnership funds shall not be commingled with the funds of any other person, and shall not be used except for the business of the Partnership. ARTICLE III BUSINESS OF PARTNERSHIP The business of the Partnership shall be to acquire, hold, improve, develop, and operate the Jonah Field Gathering System and such other facilities as may be useful for the gathering, treating, processing, and transportation of natural gas and the various products derived therefrom from wells located in the Jonah Field Area (said area comprising: all of Townships 27 North through 30 North, Range 107 West; all of Townships 27 North through 29 North, Ranges 108 and 109 West; all of Township 30 North, Range 109 West; and all of Section 36 in Township 30 North, Range 108 West), Sublette County, Wyoming, to one or more delivery points owned by 9

parties other than the Partnership. Said delivery points may include gas processing plants, pipelines or end user facilities and to do all things and exercise all powers authorized under the Act which may be necessary, convenient or incidental to such purpose, including, without limitation: (a) entering into partnership or joint venture agreements, right-of-way easements, operating agreements providing for operation of the Jonah Field Gathering System or the various elements thereof, construction contracts, gas gathering and gas processing agreements, or other agreements; (b) establishing an office and retaining employees and independent contractors; (c) establishing bank accounts; and (d) exercising such powers of eminent domain as may be accorded to the Partnership under applicable law. ARTICLE IV ACCOUNTING AND RECORDS 4.01 RECORDS TO BE MAINTAINED. The Managing Partner shall maintain the following Partnership records at its principal office, all of which will be open to inspection and copying by any Partner: (a) a current list of the full name and last known business address of each Partner; (b) copies of this Agreement including all amendments thereto; (c) copies of the Partnership's federal and state income tax returns and reports, if any, until all audit periods have expired; (d) financial statements of the Partnership for each accounting year of the Partnership which shall be prepared in accordance with GAAP; and (e) writing or other data compilation from which information can be obtained through retrieval devices into reasonably usable form setting forth the following: The amount of cash and a description and statement of the agreed value of the other property or services contributed by each Partner and which each Partner has agreed to contribute. The Managing Partner shall also maintain, or cause the Operator to maintain, all Partnership invoices, receipts, vouchers and other business records pertaining to any period which is subject to audit by any governmental authority. Said records shall be maintained at Managing Partner's or Operator's principal place of business and shall be made available for inspection and audit as provided in the Operating Agreement. 10

4.02 REPORTS TO PARTNERS. The Managing Partner shall provide the Partners with the following Partnership reports at monthly and annual intervals: income statement, balance sheet, capital account statement and comparison of actual revenues and expenses with amounts budgeted. Said statements shall be prepared in accordance with GAAP. The Managing Partner shall also furnish to any Partner upon request such additional information as to the Partnership's activities as may be reasonably requested from time to time by any Partner. ARTICLE V MANAGING PARTNER AND RIGHTS AND DUTIES OF PARTNERS 5.01 MANAGEMENT RIGHTS. All Partners who are not Dissociated Partners shall be entitled to vote through their respective representatives on the Management Committee on all matters affecting the Partnership which are not delegated to the Managing Partner hereunder. Except as otherwise provided in this Partnership Agreement, any action taken by the Management Committee shall require the consent or affirmative vote, either in writing or at a meeting of the Management Committee, of a Majority of the Partners. The following decisions shall require the vote of two (2) or more Partners having Sharing Ratios totaling not less than seventy-five percent (75%): (a) The borrowing of funds by the Partnership; (b) The pledging of Partnership Property for the repayment of any indebtedness other than purchase money liens for materials and equipment procured by the Partnership in the ordinary course of its business; (c) Any capital expenditure by the Partnership exceeding $250,000. (d) The execution or amendment of any contract pursuant to which the Partnership will reasonably be anticipated to expend or collect more than $100,000 during any period of twelve (12) consecutive months; (e) To voluntarily dissolve the Partnership before the expiration of the Partnership's term; (f) To admit an Additional Partner into the Partnership; (g) To dispose of any Partnership Property having a value of more than $100,000; (h) To continue the Partnership after the dissociation of a Partner from the Partnership; (i) Amend or modify the Operating Agreement; 11

(j) To determine or modify compensation paid to any Partner or Affiliate thereof; (k) Require additional Capital Contributions from the Partners and approve budgets submitted by Operator; and (l) To remove and replace the Managing Partner which may be done with or without cause; provided, however, that the removal and replacement of the Managing Partner may be done upon the vote of a Majority of the Remaining Partners if such removal is for cause. The decisions of the Partners shall be binding on all of the Partners. 5.02 MANAGING PARTNER. There shall be one (1) Managing Partner. Green River shall act as the initial Managing Partner. Any Partner acting as Managing Partner shall serve in such capacity until the earliest of: (a) The Dissociation of such Partner; (b) The Resignation of such Managing Partner; or (c) Removal of such Managing Partner. The function of the Managing Partner shall be to implement the decisions of the Management Committee, to act as the Partnership's chief executive officer and to keep the Partners informed as to all aspects of the Partnership's business. 5.03 AUTHORITY OF MANAGING PARTNER TO BIND THE PARTNERSHIP. Only the Managing Partner and those agents of the Partnership authorized by the Managing Partner shall have the authority to bind the Partnership. No Partner who is not either the Managing Partner or otherwise authorized as an agent shall take any action to bind the Partnership, and each Partner shall indemnify the Partnership for any costs or damages incurred by the Partnership as a result of the unauthorized action of such Partner. 5.04 COMPENSATION OF MANAGING PARTNER. The Managing Partner shall be reimbursed all reasonable out-of-pocket expenses incurred in managing the Partnership, but shall not be entitled to any compensation. 5.05 MANAGING PARTNER'S STANDARD OF CARE. Managing Partner also has fiduciary duties as do all Partners. In discharging its duties, the Managing Partner shall be fully protected in relying in good faith upon the records required to be maintained under this Agreement and upon such information, opinions, reports or statements by any of its other Partners, or agents, or by any other person, as to matters the Managing Partner reasonably believes are within such other person's professional or expert 12

competence and who has been selected with reasonable care by or on behalf of the Partnership, including information, opinions, reports or statements as to the value and amount of the assets, liabilities, profits or losses of the Partnership or any other facts pertinent to the existence and amount of assets from which distributions to Partners might properly be paid. 5.06 INDEMNIFICATION. The Partnership shall indemnify Managing Partner and each of the other Partners, and their respective directors, officers, agents and employees, said parties being hereinafter referred to as "Indemnitees", for all costs, losses, liabilities, and damages paid or accrued by such parties in connection with the business of the Partnership except insofar as such items are the result of the Indemnitee's gross negligence, bad faith or ultra vires acts. 5.07 REPRESENTATIONS AND WARRANTIES. Each Partner, and in the case of an Entity, the person(s) executing this Partnership Agreement on behalf of the Entity, hereby represents and warrants to the Partnership and each other Partner that: (a) if that Partner is an Entity, that it is duly organized, validly existing, and in good standing under the law of its state of organization and that it has full organizational power to execute and agree to this Partnership Agreement to perform its obligations hereunder; (b) that the Partner is acquiring its interest in the Partnership for the Partner's own account as an investment and without an intent to distribute the interest; (c) the Partner acknowledges that the interests have not been registered under the Securities Act of 1933 or any state securities laws, and may not be resold or transferred by the Partner without appropriate registration or the availability of an exemption from such requirements. 5.08 NOTICE OF CLAIMS. Any Partner receiving notice of any claim against the Partnership or any Partnership Property shall give prompt written notice to Managing Partner and to each of the other Partners specifying the nature of the claim, the amount and all other relevant facts concerning the same. ARTICLE VI MANAGEMENT COMMITTEE 6.01 ESTABLISHMENT OF COMMITTEE. To provide for the overall management of the Partnership and the Project, there is established a Management Committee composed of representatives of each Partner. Each Partner, including, without limitation, the Managing Partner, shall appoint one (1) representative and one (1) alternate representative to serve on the Management Committee. Each Partner shall as soon as possible after the date of this Agreement give notice in writing to the other Partners of the name and address of its representative and alternate representative to serve on the Management Committee. Each Partner shall have the right to change its representative and alternate at any time by giving proper notice to such effect to the other Partners. 13

6.02 POWERS AND DUTIES OF MANAGEMENT COMMITTEE. The Management Committee shall have the power and duty to exercise exclusive managerial authority on behalf of the Partnership to the extent that such authority is not delegated to, or performed by, Operator under the Operating Agreement. 6.03 AUTHORITY TO VOTE. The representative of a Partner (including, without limitation, the Managing Partner), or in his absence his alternate representative, shall be authorized to represent and bind such Partner with respect to any matter which is within the powers of the Management Committee and is properly brought before the Management Committee. Each such representative shall have a vote equal to the Sharing Ratio of the Partner such person represents. Each alternate representative shall be entitled to attend all Management Committee meetings but shall have no vote at such meetings except in the absence of the representative for whom he is the alternate. In addition to the representative and alternate representative, each Partner may also bring to any Management Committee meetings such technical and other advisors as it may deem appropriate. 6.04 NOTICE OF MEETING. (A) Managing Partner may call a meeting of the Management Committee by giving notice to each of the Partners at least fifteen (15) days in advance of such meeting. (B) Any Partner may request a meeting of the Management Committee by giving proper notice to all the other Partners. Upon receiving such request, Managing Partner shall call such meeting for a date not less than ten (10) Business Days nor more than thirty (30) Calendar Days after receipt of the request. (C) The notice periods as above may only be waived with the unanimous consent of all the Partners. 6.05 CONTENTS OF MEETING NOTICE. (A) Each notice of a meeting of the Management Committee as provided by Managing Partner shall contain: (1) The date, time and location of the meeting; and (2) An agenda of the matters and proposals to be considered and/or voted upon. (B) A Partner, by notice to the other Partners given not less than five (5) Business Days prior to a meeting, may add additional matters to the agenda for a meeting. (C) On the request of a Partner, and with the unanimous consent of all Partners, the Management Committee may consider at a meeting a proposal not contained in such meeting agenda. 14

6.06 LOCATION OF MEETINGS. All meetings of the Management Committee shall be held at the Partnership's principal place of business in Casper, Wyoming, or elsewhere in the United States as may be decided by the Management Committee. 6.07 MANAGING PARTNER'S DUTIES FOR MEETINGS. With respect to meetings of the Management Committee, Managing Partner's duties shall include, but not be limited to: (1) Timely preparation and distribution of the agenda; (2) Organization and conduct of the meeting; and (3) Preparation of a written record or minutes of each meeting. 6.08 VOTING PROCEDURE. Except as otherwise expressly provided in Section 5.01 of this Agreement, all decisions, approvals and other actions of the Management Committee on all proposals coming before it under this Agreement shall be decided by the affirmative vote of a Majority of the Partners, provided that a quorum of the Partners is represented at the meeting at which such vote is taken. A quorum of the Partners shall be one (1) or more Partners having in the aggregate Sharing Ratios totaling more than fifty percent (50%). 6.09 RECORD OF VOTES. Managing Partner shall make a record of each proposal voted on and the results of such voting at each Management Committee meeting. Each representative shall sign and be provided a copy of such record at the end of such meeting and it shall be considered the final record of the decisions of the Management Committee. 6.10 MINUTES. Managing Partner shall provide each Partner with a copy of the minutes of the Management Committee meeting within fifteen (15) days after the end of the meeting. Each Partner shall have fifteen (15) days after receipt of such minutes to give notice of its objections to the minutes to the secretary. A failure to give notice specifying objection to such minutes within said fifteen (15) day period shall be deemed to be approval of such minutes. 6.11 VOTING BY NOTICE. (A) In lieu of a meeting, Managing Partner may submit any proposal for a decision of the Management Committee by giving each representative proper notice describing the proposal so submitted. Each Party shall communicate its vote by proper notice to Managing Partner and to each of the other members of the Management Committee within ten (10) calendar days after receipt of Operator's notice. 15

(B) Any member of the Management Committee may by notice delivered to Managing Partner and to all other members of the Management Committee within five (5) days of receipt of Operator's notice request that the proposal be decided at a meeting rather than by notice. In such an event, that proposal shall be decided at a meeting duly called for that purpose. (C) Any Partner failing to communicate its vote in a timely manner shall be deemed to have voted against such proposal. (D) If a meeting is not requested, then at the expiration of the appropriate time period, Managing Partner shall give each Member of the Management Committee a confirmation notice stating the tabulation and results of the vote. 6.12 EFFECT OF VOTE. All decisions taken by the Management Committee pursuant to this Article shall be conclusive and binding on all the Partners. ARTICLE VII CONFLICTS OF INTEREST 7.01 PARTNERSHIP OPPORTUNITIES. It is expressly understood and agreed that any Partner shall have the right to acquire and operate natural gas processing and transmission facilities outside of the Jonah Field Area for its own individual account without the prior consent of the Partnership or any other Partner. Notwithstanding the foregoing, nothing herein shall authorize any Partner to compete with the Partnership or to diminish any Partner's duty of loyalty to the Partnership and the other Partners under the Act. 7.02 SELF DEALING. A Partner does not violate a duty or obligation to the Partnership merely because the Partner's conduct furthers the Partner's own interest. A Partner may lend money to and transact other business with the Partnership so long as such dealings are fully disclosed in writing to all Partners in advance, are approved by a majority of the Remaining Partners and are on an arm's length basis. No transaction with the Partnership shall be voidable solely because a Partner has a direct or indirect interest in the transaction if either the transaction is fair to the Partnership or a majority of the Remaining Partners, knowing the material facts of the transaction and the Partner's interest, authorize, approve, or ratify the transaction. The Partners specifically ratify and approve of the Operating Agreement attached hereto as Exhibit "B" pursuant to which the Partnership will engage McMurry Oil Company to operate the Jonah Field Gathering System. 16

ARTICLE VIII CAPITAL CONTRIBUTIONS 8.01 INITIAL CONTRIBUTIONS. Each Initial Partner shall make the Contribution described for that Partner on Exhibit "A" at the time and on the terms specified on Exhibit "A" and shall perform that Partner's Commitment. If no time for the Contribution is specified, the Contributions shall be made upon the execution of this Agreement. The value of the Contributions shall be as set forth on Exhibit "A". No interest shall accrue on any Contribution and no Partner shall have the right to withdraw or be repaid any Contribution except as provided in this Partnership Agreement. Each Additional Partner shall make the Contribution and shall perform the Commitment described in the Admission Agreement. The value of the Additional Partner's Contribution and the time for making such contribution shall be set forth in the Admission Agreement. 8.02 ADDITIONAL CONTRIBUTIONS. In addition to the Initial Contributions and Commitments, the Management Committee may, upon the vote prescribed in Section 5.01 above, determine from time to time that additional contributions are needed to enable the Partnership to conduct its business, thereby increasing the Commitment of each Partner by an amount equal to such Partner's Sharing Ratio multiplied by the amount of such additional Capital Contribution. In the event of such a determination, the Managing Partner shall give Notice to all Partners in writing at least thirty (30) calendar days prior to the date on which such contribution is due. Such Notice shall set forth the amount of additional contribution needed, the purpose for which the contribution is needed, and the date by which the Partners should contribute. Each Partner shall thereupon be obligated to contribute a proportionate share of such additional contribution as provided in the Notice. 8.03 ENFORCEMENT OF COMMITMENTS. In the event any Partner (a "Delinquent Partner") fails to perform the Delinquent Partner's Commitment, the Managing Partner shall give the Delinquent Partner a Notice of the failure to meet the Commitment. If the Delinquent Partner fails to perform the Commitment (including any costs associated with the Commitment and interest on such obligation at the Default Interest Rate) within ten (10) Business Days of the giving of Notice, the Remaining Partners may take such action, including but not limited to enforcing the Commitment in the court of appropriate jurisdiction in the state in which the Principal Office is located or the state of the Delinquent Partner's address as reflected in this Partnership Agreement. Each Partner expressly agrees to the jurisdiction of such court but only for the enforcement of Commitments. The Remaining Partners may elect to contribute the amount of the Delinquent Partner's Commitment which is in default, each such Partner contributing that portion of the amount in default which is equal to its Sharing Ratio divided by the sum of the Sharing Ratio of all Remaining Partners. Those Partners who make such a contribution ("the Contributing Partners") shall be entitled to treat the amounts contributed pursuant to this section as a loan from the Contributing Partners to the Delinquent Partner bearing interest at the Default Interest Rate and secured by the Delinquent Partner's interest in the Partnership. Until they are fully repaid, the Contributing Partners shall be entitled to all Distributions to which the Delinquent Partner would 17

have been entitled. Notwithstanding the foregoing, no Commitment or other obligation to make an additional contribution may be enforced by a creditor of the Partnership or other person other than the Partnership and the Contributing Partners unless the Delinquent Partner expressly consents to such enforcement or to the assignment of the obligation to such creditor. 8.04 MAINTENANCE OF CAPITAL ACCOUNTS. The Partnership shall establish and maintain a Capital Account for each Partner and Assignee. Each Partner's Capital Account shall be increased by: (1) the amount of any Money actually contributed by the Partner to the capital of the Partnership, (2) the fair market value of any Property (other than Money) contributed, as determined by the Partnership and the Contributing Partner at arm's length at the time of contribution (net of liabilities assumed by the Partnership or subject to which the Partnership takes such Property, within the meaning of Section 752 of the Code), and (3) the Partner's share of Net Profits and of any separately allocated items of income or gain except adjustments to income and gain as a result of a Revaluation or in connection with Property Contributed in the manner described in Section 1.704-1(b)(2)(iv)(g) to reflect the difference between the Book Value and the adjusted basis of Partnership Property, but excluding allocations of income and gain described in Section 1.704-1(b)(4)(i) of the Regulations under which such difference is reflected for tax purposes). Each Partner's Capital Account shall be decreased by (1) the amount of any money distributed to the Partner by the Partnership, (2) the fair market value of any Property distributed to the Partner, as determined by the Partnership and the Partner receiving the Distribution at arm's length at the time of Distribution (net of liabilities of the Partnership assumed by the Partner or subject to which the Partner takes such Property within the meaning of Section 752 of the Code), and (3) the Partner's share of Net Losses and of any separately allocated items of Net Loss (including adjustments for depreciation, depletion, amortization, and loss as a result of a Revaluation or in connection with Property contributed in the manner described in Section 1.704-1(b)(2)(iv)(g) to reflect the difference between the Book Value and the adjusted basis of Partnership Property, but excluding allocations of depreciation, depletion, amortization, and loss described in Section 1.704-1(b)(4)(i) of the Regulations under which such difference is reflected for tax purposes). 8.05 DISTRIBUTION OF ASSETS. If the Partnership at any time distributes any Partnership Property (other than money) in-kind to any Partner, the Capital Account of each Partner shall be adjusted to account for that Partner's allocable share (as determined under Article below) of the Net Profits or Net Losses that would have been realized by the Partnership had it sold the assets that were distributed at their respective fair market values immediately prior to their distribution. 8.06 SALE OR EXCHANGE OF INTEREST. In the event of a sale or exchange of some or all of a Partnership Interest, the Capital Account of the Transferring Partner shall become the Capital Account of the Assignee, to the extent it relates to the portion of the Partnership Interest Transferred. 18

8.07 REVALUATION OF PARTNERSHIP PROPERTY. The Capital Accounts of the Partners shall be increased or decreased to reflect a revaluation of Partnership Property (including intangible assets such as goodwill) on the Partnership's books in connection with a Revaluation Event. Upon such Revaluation: (1) the Book Value of Partnership Property shall be adjusted based on the fair market value of Partnership Property (taking Section 7701(g) of the Code into account) on the Revaluation Date; (2) the unrealized income, gain, loss, or deduction inherent in such Partnership Property (that has not been reflected in the Capital Accounts previously) would be allocated among the Partners as if there were a taxable disposition of such Partnership property for such fair market value on the Revaluation Date. 8.08 COMPLIANCE WITH SECTION 704(b) OF THE CODE. The provisions of this Article as they relate to the maintenance of Capital Accounts are intended, and shall be construed, and, if necessary, modified to cause the allocations of profits, losses, income, gain and credit pursuant to Article VIII to have substantial economic effect under the Regulations promulgated under Section 704(b) of the Code, in light of the Distributions made pursuant to Articles IX and XIV and the Contributions made pursuant to this Article VIII. 8.09 NON-CONSENT OPERATIONS. Any Partner may propose an Expansion of the Jonah Field Gathering System by written notice (the "Expansion Proposal") to the Managing Partner specifying all pertinent information in reasonable detail, including, without limitation: the work to be done, the time for construction, the impact of the construction upon the existing operation of the Jonah Field Gathering System, the estimated cost of the Expansion and the economic benefits to be derived by the Partnership therefrom. Promptly upon receipt of such proposal, the Managing Partner shall call a meeting of the Management Committee to consider whether additional Capital Contributions shall be authorized for such purpose. If such Capital Contributions are authorized by the Management Committee, the Expansion Proposal shall be implemented and the approved Capital Contributions shall become part of each Partner's Commitment. In the event additional Capital Contributions or other funding measures to finance the Expansion Proposal are not approved by the Management Committee within thirty (30) days after the proposal has been first submitted to the Managing Partner, (the last day of such period or such earlier date on which the Expansion Proposal may be formally rejected by the Management Committee being hereinafter referred to as the "Rejection Date"), any Partner or Partners (the "Consenting Partners") may undertake or cause the Partnership to undertake the Expansion as follows: (a) Internal Expansions. To the extent that the proposed Expansion involves increasing the capacity of the Jonah Field Gathering System (the "System") to gather gas from those wells which are then connected to the System (an "Internal Expansion"), the Consenting Partners shall have the right for a period of thirty (30) days after the Rejection Date to deliver their unconditional and irrevocable agreement to contribute sufficient funds to the Partnership to enable the Partnership to complete the proposed Expansion. The Partnership shall upon receipt of such Commitment commence construction of the Expansion and complete the same in accordance with the original Expansion Proposal. Notwithstanding anything in this Agreement 19

to the contrary, the Sharing Ratios of the Partners shall not be adjusted to reflect any Capital Contributions made pursuant to this paragraph 8.09(a); provided, however, that all revenues accruing to the Partnership after the Expansion has been placed in service shall be allocated and distributed among the Partners as if their Sharing Ratios were so adjusted until the Consenting Partners have in the aggregate been allocated and have received out of such revenues an amount (the "Internal Expansion Cost Recovery Amount") the present value of which, discounted from the date received to the date of the earliest unrecovered Capital Contribution made pursuant to this paragraph at an annual rate of fifteen percent (15%), is equal to one hundred and twenty-five percent (125%) of all costs incurred by the Partnership in connection with such Expansion. All Partnership revenues thereafter accruing to the Partnership shall be allocated and distributed among all Partners in accordance with their respective Sharing Ratios as the same may be determined without regard to the provisions of this Section 8.09. Notwithstanding anything in Article IX to the contrary, all items of Partnership income and expenses allocable to the Consenting Partners pursuant to this Section 8.09 shall also be allocated to them for federal and state income tax purposes in the manner provided in this section. (b) External Expansions. To the extent that a proposed Expansion involves an Expansion other than an Internal Expansion as described in paragraph 8.09(a) above (an "External Expansion"), the Consenting Partners shall have the option for a period of one hundred eighty (180) days after the Rejection Date to commence construction of the External Expansion at their own expense and for their account in such manner as they may agree; provided, however, that upon the successful completion thereof said facilities and all easements and other appurtenances held in connection therewith shall be conveyed by the Consenting Partners to all Partners in undivided shares in accordance with the respective Sharing Ratios, said conveyance to be made free and clear of all liens and encumbrances except for the right of the Consenting Partners to recover from all of the revenues attributable to such property an amount (the "External Expansion Cost Recovery Amount") the present value of which, discounted from the date received to the date of the earliest unrecovered cost hereunder at an annual rate of fifteen percent (15%), is equal to one hundred and twenty-five percent (125%) of all costs incurred by the Consenting Partners in connection with such Expansion. Each of the Partners shall upon receipt of such conveyance convey all of its right, title and interest in said property to the Partnership subject to the right of the Consenting Partners to receive the External Expansion Cost Recovery Amount as provided above. Notwithstanding anything herein to the contrary, the Partnership and those Partners other than the Consenting Partners shall have the right to elect not to receive a conveyance of the External Expansion property hereunder. ARTICLE IX ALLOCATION AND DISTRIBUTIONS 9.01 ALLOCATIONS OF NET PROFITS AND NET LOSSES FROM OPERATIONS. Except as may be required by Section 704(c) of the Code, and Section 8.09(a) and Sections 9.02, 9.03, and 9.04 of this Article IX, net profits, net losses, and other items of income, gain, loss, deduction and credit shall be apportioned among the Partners in proportion to their respective Sharing Ratios. 20

9.02 PARTNERSHIP MINIMUM GAIN CHARGEBACK. If there is a net decrease in Partnership Minimum Gain for a Taxable Year, each Partner must be allocated items of income and gain for that Taxable Year equal to that Partner's share of the net decrease in Partnership Minimum Gain. A Partner's share of the net decrease in Partnership Minimum Gain is the amount of the total net decrease multiplied by the Partner's percentage share of the Partnership Minimum Gain at the end of the immediately preceding Taxable Year. A Partner's share of any decrease in Partnership Minimum Gain resulting from a Revaluation of Partnership Property equals the increase in the Partner's Capital Account attributable to the Revaluation to the extent the reduction in minimum gain is caused by the Revaluation. A Partner is not subject to the Partnership Minimum Gain Chargeback Requirement to the extent the Partner's share of the net decrease in Partnership Minimum Gain is caused by a guarantee, refinancing, or other change in the debt instrument causing it to become partially or wholly a Recourse Liability or a Partner Nonrecourse Liability, and the Partner bears the economic risk of loss (within the meaning of Section 1.752-2 of the Regulations) for the newly guaranteed, refinanced, or otherwise changed liability. 9.03 PARTNER MINIMUM GAIN CHARGEBACK. If during a Taxable Year there is a net decrease in Partner Minimum Gain, any Partner with a share of that Partner Minimum Gain ("partner minimum gain" as determined under Section 1.704-2(i)(5) of the Regulations) as of the beginning of that Taxable Year must be allocated items of income and gain for that Taxable Year (and, if necessary, for succeeding Taxable Years) equal to that Partner's share of the net decrease in the Partnership's Minimum Gain. A Partner's share of the net decrease in Partner Minimum Gain is determined in a manner consistent with the provisions of Section 1.704-2(g)(2) of the Regulations. A Partner is not subject to this Partner Minimum Gain Chargeback, however, to the extent the net decrease in Partner Minimum Gain arises because the liability ceases to be Partner Nonrecourse Liability due to a conversion, refinancing, or other change in the debt instrument that causes it to become partially or wholly a Partnership Nonrecourse Liability. The amount that would otherwise be subject to the Partner Minimum Gain Chargeback is added to the Partner's share of Partnership Minimum Gain. In addition, rules consistent with those applicable to Partnership Minimum Gain shall be applied to determine the shares of Partner Minimum Gain and Partner Minimum Gain Chargeback to the extent provided under the Regulations issued pursuant to Section 704(b) of the Code. 9.04 QUALIFIED INCOME OFFSET. Notwithstanding any provision of this Partnership Agreement to the contrary (other than Sections 9.02 and 9.03 above), in the event that a deficit in a Partner's Capital Account is created or increased (taking into account any allocations, adjustments, or distributions described in Section 1.704-1(b)(2)(ii)(d)(4), (5), or (6)) in excess of such Partner's share of Partnership Minimum Gain and Partner Minimum Gain, plus any amount that the Partner is obligated to restore to the Partnership, such Partner will be allocated items of income and gain (consisting of a pro rata portion of each item of partnership income and gain for such year) in an amount and manner sufficient to offset such Offsettable Decrease as quickly as possible. 21

9.05 INTERIM DISTRIBUTIONS. From time to time, the Management Committee shall determine to what extent, if any, the Partnership's cash on hand exceeds the current and anticipated needs, including, without limitation, needs for operating expenses, debt service, acquisitions, Reserves, and mandatory Distributions, if any. To the extent such excess exists, the Managing Partner shall cause Distributions to be made to the Partners in accordance with their Sharing Ratios. Such distributions shall be in cash or Property or partly in both, as determined by the Management Committee. All interim distributions which, when made, exceed the recipient Partner's basis in that Partner's Partnership Interest shall be considered advances or drawings against the Partner's distributive share of net income. To the extent it is determined at the end of the Taxable Year of the Partnership that the recipient Partner has not been allocated net income that equals or exceeds the total of such advances or drawings for such year, the recipient Partner shall be obligated to restore any such advances or drawings to the Partnership. Notwithstanding the foregoing sentence, the Partner will not be required to restore such advances or drawings to the extent that, on the last day of the Taxable Year, the recipient Partner's basis in the Partner's interest in the Partnership has increased from the time of such advance of drawing. 9.06 DISTRIBUTIONS. The Management Committee shall have the authority to determine the extent to which cash is available for distribution to the Partners and Managing Partner shall cause the distribution all such cash to the Partners on at least a quarterly basis in accordance with their respective Sharing Ratios. ARTICLE X TAXES 10.01 TAX RETURNS. The Tax Matters Partner ("TMP") shall cause the preparation and filing of all required federal and state partnership income tax returns. In preparing such returns, the TMP shall use its best efforts and in doing so shall incur no liability to any other Partners or Assignee with regard to such returns. Not less than sixty (60) days prior to the due date (including extensions), the TMP shall submit to each Partner a copy of the return as proposed for review. Each Partner agrees to furnish to the TMP not later than March 1 of each year such information relating to the operations conducted under this Agreement during the immediately preceding calendar year as may be required for the proper preparation of such returns and capital accounts. The Partners agree that the filing date for any return shall be extended at the request of any Partner. 10.02 TAX MATTERS PARTNER. The Managing Partner shall be the initial tax matters partner ("TMP") as defined in Internal Revenue Code ("Code" or "I.R.C.") Section 6231(a)(7). In the event of any change in the TMP, the Partner serving as TMP for a given Taxable Year shall continue as TMP with respect to all matters concerning such year. The TMP for a given Taxable Year shall continue as TMP with respect to all matters concerning such year. The TMP and other Partners shall use their best efforts to comply with responsibilities outlined in this section and in Code Sections 6222 through 6233 22

and 6050K (including any Treasury Regulations promulgated thereunder) and in doing so shall incur no liability to any other Partner. Notwithstanding TMP's obligation to use its best efforts in the fulfillment of its responsibilities, TMP shall not be required to incur any expenses for the preparation for, or pursuance of administrative or judicial proceedings, unless all of the Partners agree on a method for sharing such expenses. 10.03 INFORMATION REQUEST BY TMP. The Partners and any Assignee shall furnish TMP within two (2) weeks from the receipt of the request with such information (including information specified in Code Sections 6230(e) and 6050K) as TMP may reasonably request to permit it to provide the Internal Revenue Service with sufficient information for purposes of Code Sections 6230(e) and 6050K. 10.04 TMP AGREEMENTS WITH IRS. The TMP shall not agree to any extension of the statute of limitations for making assessments on behalf of any other Partner or Assignee without first obtaining the written consent of that Partner or Assignee. The TMP shall not bind any other Partner or Assignee to a settlement agreement in tax audits without obtaining the written concurrence of any such Partner or Assignee. Any other Partner or Assignee who enters into a settlement agreement with the Secretary of the Treasury with respect to any Partnership items, as defined by Code Section 6231(a)(3), shall notify the other Partners and any Assignee of such settlement agreement and its terms within ninety (90) days from the date of settlement. 10.05 INCONSISTENT TREATMENT OF PARTNERSHIP ITEM. If any Partner or Assignee intends to file a notice of inconsistent treatment under Code Section 6222(b), such party shall, prior to the filing of such notice, notify the TMP of such intent and the manner in which the Partner's or Assignee's intended treatment of a Partnership item is (or may be) inconsistent with the treatment of that item by the Partnership. Within one (1) week of receipt, the TMP shall remit copies of such notification to other Partners and Assignees. If any inconsistency notice is filed solely because of a Partner or Assignee not having received a Schedule K-1 in time for filing of its income tax return, the TMP need not be notified. 10.06 REQUESTS FOR ADMINISTRATIVE ADJUSTMENT. No Partner nor any Assignee shall file a request pursuant to Code Section 6227 for an administrative adjustment of Partnership items for any Partnership Taxable Year without first notifying all other Partners and Assignees. If all other Partners and Assignees agree with the requested adjustment, the TMP shall file the request for administrative adjustment on behalf of the Partnership. If unanimous consent is not obtained within thirty (30) days from such notice, or within the period required to timely file the request for administrative adjustment, if shorter, any Partner or Assignee, including the TMP, may file a request for administrative adjustment on its own behalf. 23

10.07 JUDICIAL PROCEEDINGS. Any Partner or Assignee intending to file a petition under Code Section 6225 or Code Section 6228, or any other Code section with respect to any Partnership item, or other tax matters involving the Partnership, shall notify the other Partners and Assignees, prior to such filing, of such intention and the nature of the contemplated proceeding. In the case where the TMP is the Partner intending to file such petition, such notice shall be given within a reasonable time to allow the other Partners and Assignees to participate in the choosing of the forum in which such petition will be filed. If the Partners and Assignees do not agree on the appropriate forum, then the appropriate forum shall be decided by a vote of majority of the Partners. Each Partner shall have a vote in accordance with its Sharing Ratio as of the end of the year under audit. If a majority cannot agree, the TMP shall choose the forum. If any Partner or Assignee intends to seek review of any court decision rendered as a result of such a proceeding, such party shall notify the other Partners and Assignees prior to seeking such review. 10.08 ELECTIONS. For both income and single business tax return and capital account purposes, the Partnership shall elect: (a) to use the maximum allowable accelerated tax method and the shortest permissible tax life for depreciation purposes, (b) to use the accrual method of accounting, (c) to report income on a calendar year basis, (d) to deduct currently all research and experimental expenditures, (e) to amortize start-up expenditures and organizational costs over a 60-month period, (f) the optional adjustment to the basis of Partnership Property under Code Section 754 in the event of a distribution of Partnership Property or a transfer of a Partnership Interest, and (g) such other elections as may be approved by a Majority of the Partners based upon their Sharing Ratios as of the end of the Taxable Year for which the election is made. 10.09 TAXES OF TAXING JURISDICTIONS. To the extent that the laws of any Taxing Jurisdiction requires, each Partner and Assignee (or such Partners as may be required by the Taxing Jurisdiction) will submit an agreement indicating that the Partner will make timely income tax payments to the Taxing Jurisdiction and that the Partner (or Assignee) accepts personal jurisdiction of the Taxing Jurisdiction with regard to the collection of income taxes attributable to the Partner's (or Assignee's) income, and interest, and penalties assessed on such income. If the Partner (or Assignee) fails to provide such 24

agreement, the Partnership may withhold and pay over to such Taxing Jurisdiction the amount of tax, penalty and interest determined under the laws of the Taxing Jurisdiction with respect to such income. Any such payments with respect to the income of a Partner (or Assignee) shall be treated as a distribution for purposes of Article IX. ARTICLE XI DISPOSITION OF PARTNERSHIP INTERESTS 11.01 DISPOSITION. Any Partner or Assignee may dispose of all or a portion of the Partner's or Assignee's Partnership Interest upon compliance with this Section 11.01 and the requirements of Section 11.02, if applicable. No Partnership Interest shall be disposed of: (a) if such disposition, alone or when combined with other transactions, would result in a termination of the Partnership within the meaning of Section 708 of the Code; (b) without an opinion of counsel satisfactory to the Managing Partner that such assignment is subject to an effective registration under, or exempt from the registration requirements of, the applicable state and federal securities laws; (c) unless and until the Partnership receives from the Assignee such information and agreements that the Managing Partner may reasonably require, including but not limited to any taxpayer identification number and any agreement that may be required by any Taxing Jurisdiction. Notwithstanding anything herein to the contrary, no transferee of a Partnership Interest shall be admitted into the Partnership as a Partner except as provided in Article XIII. 11.02 RIGHT OF FIRST REFUSAL. (a) Notice of Proposed Sale and Offer to Remaining Partners. In the event any Partner or Assignee desires to sell all or any portion of its Partnership Interest, such party being hereinafter referred to as the "Selling Party", the Selling Party shall give the Managing Partner written notice specifying the extent of the Partnership Interest to be sold (the "Offered Interest") and all of the terms and conditions of the proposed sale. The Managing Partner shall promptly give written notice of the terms of such proposal to each of the Remaining Partners. Each of the Remaining Partners shall have twenty (20) days after receipt of such notice within which to elect, by delivering written notice of such election to Managing Partner, to purchase its proportionate share of the Offered Interest on the terms specified in the Selling Party's offer. In the event fewer than all of the Remaining Partners elect to do so, Managing Partner shall notify those Partners electing to participate in such purchase (the "Purchasing Partners") of the extent to which the Offered Interest remains available for purchase and each of said Partners shall have the right for a period of five (5) days after receipt of such notice within which to elect to purchase a proportionate share of such remaining interest by giving written notice of such election to Managing Partner. In the event the Purchasing Partners fail to elect to purchase all of the Offered Interest during said five-day period, Managing Partner shall reoffer that portion of 25

the Offered Interest still available for purchase among those Purchasing Partners last electing to participate in the purchase of the Offered Interest for a period of five (5) days in the manner above provided. (b) Election to Purchase or Reject Offered Interest. In the event the Purchasing Partners elect to purchase all of the Offered Interest, Managing Partner shall give prompt written notice to the Selling Party and to each of the Purchasing Partners specifying that portion of Offered Interest to be purchased by each Purchasing partner and said Partners shall, within sixty (60) days after receipt of such notice, purchase and the Selling Party shall sell the Offered Interest on the terms specified in the offer. Notwithstanding anything herein to the contrary, in the event the Purchasing Partners fail to elect to purchase all of the Offered Interest, they shall not have the right to purchase any part of the same hereunder and Managing Partner shall notify the Selling Party of the Remaining Partners' election not to purchase the Offered Interest. (c) Effect of Reelection of Offered Interest. For a period of ninety (90) days after its receipt of notice rejecting its offer to sell its Partnership Interest, the Selling Party shall have the right to sell the Offered Interest to any third party on the terms set forth in the above Notice; provided, however, that such sale shall, nevertheless, be subject to the provisions of Article XI of this Partnership Agreement. In the event the Selling Party desires to sell all or any part of the Offered Interest more than ninety (90) days after the same has been offered to and rejected by the other Partners or at any time on terms which are different in any material respect from those previously offered to the Remaining Partners, such interest shall again be offered to the Remaining Partners in the manner provided above. (d) Allocation of Preferential Right Among Remaining Partners. For purposes of this Section 11.02, a Partner's proportionate share of the Offered Interest shall be equal to such Partner's Sharing Ratio divided by the sum of the Sharing Ratios of all Partners having the right to participate in the acquisition of the Offered Interest. Similarly, in the event a portion of the Offered Interest is reoffered to the Purchasing Partners for a period of five (5) days, each Purchasing Partner's proportionate share of the interest being reoffered shall be equal to such Partner's Sharing Ratio divided by the sum of the Sharing Ratios of all Partners to whom such interest is being reoffered. (e) Miscellaneous. The provisions of this paragraph shall not apply to the creation of a lien on any Partnership Interest but shall apply to any sale incident to the foreclosure of any such lien. The Partnership Interest of any Assignee shall be subject to the provisions of this section but no Assignee shall have the right to participate in the purchase of an Offered Interest hereunder, and any Remaining Partner which has conveyed all or a portion of its Partnership Interest to an Assignee hereunder shall be deemed to own the Sharing Ratio of its Assignee for purposes of this Section 11.02. 11.03 DISPOSITIONS NOT IN COMPLIANCE WITH THIS ARTICLE VOID. Any attempted Disposition of a Partnership Interest, or any part thereof, other than in accordance with Sections 11.01 and 11.02 shall be, and is declared to be, null and void ab initio. 26

ARTICLE XII DISSOCIATION OF A PARTNER 12.01 DISSOCIATION. Except upon the transfer of a Partner's entire Partnership Interest and the admission of such Partner's transferee into the Partnership as a Substitute Partner, a Partner shall not have the right to voluntarily retire, dissociate or withdraw from the Partnership. A Person shall cease to be a Partner upon the happening of any of the following events: (a) the Partner's becoming a Bankrupt Partner; (b) in the case of a Partner that is a separate Entity other than a corporation, the dissolution and commencement of winding up of the separate Entity; (c) in the case of a Partner that is a corporation, the filing of a certificate of dissolution, or its equivalent, for the corporation or the revocation of its charter; (d) the transfer of all of a Partner's Partnership Interest to an Assignee and the admission of the Assignee as a Substitute Partner; or (e) any other event of Dissociation under the Act. 12.02 PURCHASE OF DISSOCIATED PARTNER'S PARTNERSHIP INTEREST. Upon the Dissociation of a Partner by reason other than Section 12.01(d), when and if the Remaining Partners elect to continue the business of the Partnership, a Majority of the Remaining Partners shall, subject to the provisions of the Act, elect one of the two following provisions: (a) The Dissociated Partner's Partnership Interest shall be purchased by the Partnership for a purchase price equal to the aggregate fair market value of the Partner's Interest determined according to the provisions of Section 12.03. The purchase price of such interest shall be paid by the Partnership to the Dissociated Partner in cash within sixty (60) days of determination of the aggregate fair market value or, at the Partnership's option, said debt may be evidenced by a promissory note bearing interest at a fixed annual rate equal to the prime rate then being charged by Norwest Bank Colorado, N.A., which shall in the absence of prepayment (which shall be permitted at any time without penalty) be due and payable upon the earlier of (i) expiration of five years or (ii) the sale or other disposition of all of the Partnership's Property; or (b) The Dissociated Partner, or assignee of Dissociated Partner's Partnership Interest, shall hold the Dissociated Partner's Partnership Interest as an Assignee. 12.03 PURCHASE PRICE OF DISSOCIATED PARTNER'S PARTNERSHIP INTEREST. The fair market value of a Partner's Interest to be purchased by the Partnership pursuant to Section 12.02 shall be determined by agreement between the Dissociated Partner (or the 27

assignee of the Dissociated Partner's Partnership Interest, as the case may be) and the Partnership, which agreement is subject to approval by a Majority of the Remaining Partners. For this purpose, the fair market value of the Dissociated Partner's Partnership Interest shall be computed as the amount which could reasonably be expected to be realized by such Partner upon the sale of the Partnership's Property in the ordinary course of business at the time of Dissociation. If the Dissociated Partner (or the assignee of the Dissociated Partner's Partnership Interest, as the case may be) and the Partnership cannot agree upon the fair market value of such Partnership Interest within thirty (30) days, the fair market value thereof shall be determined by appraisal, the Partnership and the terminated Partner each to choose one appraiser and the two appraisers so chosen to choose a third appraiser. The decision of a majority of the appraisers as to the fair market value of such Partnership Interest shall be final and binding and may be enforced by legal proceedings. The Dissociated Partner and the Partnership shall each compensate the appraiser appointed by it and the compensation of the third appraiser shall be borne equally by such parties. 12.04 DAMAGES. The provision set forth herein shall not affect any claim for damages the Partnership may have against the Dissociated Partner if such Dissociation is in violation of this Partnership Agreement. The Partnership shall have the right to offset any payments due under this Article by any damages that the Partnership may incur as a result of a Dissociation of a Partner in contravention of this Partnership Agreement. ARTICLE XIII ADMISSION OF ASSIGNEES AND ADDITIONAL PARTNERS 13.01 RIGHTS OF ASSIGNEES. The Assignee of a Partnership Interest has no right to participate in the management of the business and affairs of the Partnership or to become a Partner. The Assignee is only entitled to receive the Distributions and return of capital, and to be allocated the Net Profits and Net Losses attributable the Partnership Interest. 13.02 ADMISSION OF SUBSTITUTE PARTNERS. An Assignee of a Partnership Interest shall be admitted as a Substitute Partner and admitted to all the rights of the Partner who initially assigned the Partnership Interest, only with the approval, which may be withheld in their sole and absolute discretion, of a Majority of the Remaining Partners. 13.03 ADMISSION OF ADDITIONAL PARTNERS. The Partners may admit Additional Partners and determine the Capital Contribution of such Partners. 28

ARTICLE XIV DISSOLUTION AND WINDING UP 14.01 DISSOLUTION. The Partnership shall be dissolved and its affairs wound up, upon the first to occur of the following events: (a) the expiration of the Term; (b) the written consent of two or more Partners having Sharing Ratios totaling seventy-five percent (75%) or more; (c) the Dissociation of any Partner, unless the business of the Partnership is continued with the consent of two or more Remaining Partners holding Sharing Ratios totaling at least seventy-five percent (75%) of the Sharing Ratios of all the Remaining Partners determined as of the date of the dissociation. 14.02 EFFECT OF DISSOLUTION. Upon dissolution, a Majority of the Remaining Partners shall designate one of the Partners to act as the Liquidator of the Partnership. The Partnership shall cease carrying on as distinguished from the winding up of the Partnership's business, but the Partnership is not terminated, but continues until the winding up of the affairs of the Partnership is completed. The Liquidator shall have exclusive authority to wind up the Partnership's business and distribute the Partnership's assets. 14.03 DISTRIBUTION OF ASSETS ON DISSOLUTION. Upon the winding up of the Partnership, the Partnership's Property shall be distributed by the Liquidator in the following manner: (a) to creditors of the Partnership, including Partners who are creditors, to the extent permitted by law, in satisfaction of Partnership Liabilities; (b) Partners in accordance with positive Capital Account balances taking into account all Capital Account adjustments for the Partnership's taxable year in which the liquidation occurs. Liquidation proceeds shall be paid within sixty (60) days of the end of the Partnership's taxable year or, if later, within ninety (90) days after the date of liquidation. Such distributions shall be in cash or Property or partly in both, as determined by the Managing Partner. Unless otherwise agreed, each such class of Property distributed shall be distributed proportionately among the Partners in accordance with their respective capital account balances as above provided. 29

ARTICLE XV AMENDMENT Amendment or Modification of Partnership Agreement. This Partnership Agreement may be amended or modified from time to time only by a written instrument executed by two (2) or more Partners having Sharing Ratios totaling at least seventy-five percent (75%), but, without the written consent of each Partner adversely affected thereby (the Affected Partner), no amendment of this Partnership Agreement shall be made that: (i) increases the obligations of the Affected Partner to make contributions, (ii) alters the allocation to the Affected Partner for tax purposes of any items of income, gain, loss, deduction or credit, or (iii) alters the manner of computing the distributions of the Affected Partner. Notwithstanding any other provision of this Partnership Agreement, the provisions of this Article may not be amended without the consent of all Partners. ARTICLE XVI MISCELLANEOUS PROVISIONS 16.01 ENTIRE AGREEMENT. This Partnership Agreement represents the entire agreement among all the Partners and between the Partners and the Partnership. 16.02 RIGHTS OF CREDITORS AND THIRD PARTIES UNDER PARTNERSHIP AGREEMENT. This Partnership Agreement is entered into among the Partnership and the Partners for the exclusive benefit of the Partnership, the Partners, and their successors and assignees. This Partnership Agreement is expressly not intended for the benefit of any creditor of the Partnership or any other person. Except and only to the extent provided by applicable statute, no such creditor or third party shall have any rights under this Partnership Agreement, Admission Agreement or any agreement between the Partnership and any Partner with respect to any Capital Contribution or otherwise. 16.03 NOTICES. Any notice, demand or communication required or permitted to be given by any provision of this Agreement shall be deemed to have been sufficiently given or served for all purposes if delivered personally in writing to the party to whom the same is directed or, if sent by private overnight delivery service or registered or certified mail, postage and charges prepaid, or by facsimile, addressed to such party's address as shown on Exhibit "A" of this Agreement. Any such notice shall be deemed to be given only on the date of receipt by the notified party. Any Partner may change its address for notice purposes by giving each of the other Partners at least ten (10) days prior written notice of such change. 16.04 APPLICATION OF WYOMING LAW. This Agreement, and the application or interpretation hereof, shall be governed exclusively by its terms and by the laws of the State of Wyoming. 30

16.05 ENTIRE AGREEMENT. This Agreement sets forth all of the promises, agreements, conditions, understandings, warranties and representations among the parties hereto with respect to the Partnership. 16.06 WAIVER OF ACTION FOR PARTITION. Each of the parties hereto irrevocably waives during the term of the Partnership any right that it may have to maintain any action for partition with respect to any property owned by the Partnership. 16.07 COUNTERPARTS. This Agreement may be executed in counterparts, each of which shall be deemed an original, but all of which together shall constitute one and the same document. 31

IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first written above. JONAH PIPELINE COMPANY, GREEN RIVER PIPELINE LIMITED a Michigan corporation LIABILITY COMPANY, a Wyoming limited liability company By: /s/ Pauline E. Dooham By: /s/ John W. Martin ------------------------------------ --------------------------------- Pauline E. Doohan John W. Martin, President of Attorney-in-Fact McMurry Oil Company, Manager STATE OF COLORADO ) CITY AND ) ss. COUNTY OF DENVER ) SUBSCRIBED AND SWORN to before me by Pauline E. Doohan as Attorney-in-Fact for Jonah Pipeline Company, a Michigan corporation, on behalf of the corporation, this 19th day of June, 1996. WITNESS MY HAND AND OFFICIAL SEAL. My Commission Expires: 10/5/1998 /s/ Kay A. Kisner - --------------------------- ------------------------------------ Notary Public Address: 1775 Sherman, #1400 Denver, CO 80203 STATE OF COLORADO ) CITY AND ) ss. COUNTY OF DENVER ) SUBSCRIBED AND SWORN to before me by John W. Martin as President of McMurry Oil Company, Manager, on behalf of Green River Pipeline Limited Liability Company, this 19th day of June, 1996. WITNESS MY HAND AND OFFICIAL SEAL. My Commission Expires: 10/5/1998 /s/ Kay A. Kisner - --------------------------- --------------------------------- Notary Public Address: 1775 Sherman, #1400 Denver, CO 80203

ASSIGNMENT OF PARTNERSHIP INTERESTS This ASSIGNMENT OF PARTNERSHIP INTERESTS (the "Assignment Agreement") is made and entered into as of September 28th, 2001, by and among Green River Pipeline, LLC, a Wyoming limited liability company ("Green River"), McMurry Oil Company, a Wyoming corporation ("MOC"), TEPPCO GP, Inc., a Delaware corporation ("TGP"), and TEPPCO Midstream Companies, L.P., a Delaware limited partnership ("TMC"). WITNESSETH: WHEREAS, Green River and MOC own 100% of the Partnership Interests (as defined in the Partnership Agreement, which is hereinafter defined) of Jonah Gas Gathering Company, a Wyoming general partnership (the "Company"), pursuant to the Jonah Gas Gathering Company Agreement of Partnership dated June 20, 1996 (the "Partnership Agreement") entered into by and between Green River and Jonah Pipeline Company, whose interest therein was previously acquired by MOC; WHEREAS, Green River, MOC and TEPPCO Partners, L.P., a Delaware limited partnership ("TEPPCO"), entered into that certain Purchase and Sale Agreement dated September 7, 2001 (the "Purchase and Sale Agreement"), in which Green River and MOC agreed to sell and convey to TEPPCO, and TEPPCO agreed to purchase from Green River and MOC, 100% of the Partnership Interests; WHEREAS, TEPPCO has agreed to assign the right to acquire 0.001% of the Partnership Interests to TGP and the right to acquire 99.999% of the Partnership Interests to TMC pursuant to an Assignment and Assumption of Contract Rights of even date herewith; and WHEREAS, Green River, MOC, TGP and TMC desire to enter into this Assignment Agreement to effect and evidence the conveyance by Green River and MOC to TGP to 0.001% of the Partnership Interests and to TMC of 99.999% of the Partnership Interests. NOW, THEREFORE, in consideration of the mutual covenants herein and other good and valuable consideration payable under and pursuant to the Purchase and Sale Agreement, the receipt and sufficiency of which is hereby acknowledged, the undersigned do hereby agree to the following: (1) Assignment. (a) Effective as of the Effective Date (as defined in the Purchase and Sale Agreement), Green River and MOC hereby assign to (i) TGP, its successors and assigns, and TGP hereby accepts and assumes all of Green River's and MOC's right, title and interest in and to, 0.001% of their respective Partnership Interests in the Company and (ii) TMC, its successors and assigns, and TMC hereby accepts and assumes all of Green River's and MOC's right, title and interest in and to, 99.999% of their respective Partnership Interests in the Company. (b) Upon consummation of the assignment set forth above in Section 1(a), each of TGP and TMC shall be admitted as s Substitute Partner of the Company.

(2) Assumption and Release. TGP and TMC shall (i) assume all obligations under the Partnership Agreement attributable to time periods after the Effective Date; and (ii) release MOC and Green River, their successors, assigns and affiliates from any rights or claims under or pursuant to the Partnership Agreement that may be due or owing, or that may be attributable to time periods on or prior to the Effective Date. (3) Governing Law. This Assignment Agreement shall be governed by and interpreted in accordance with the laws of the State of Wyoming without giving effect to principles thereof relating to conflicts of law rules that would direct the application of the laws of another jurisdiction. (4) Continuing Obligation. The parties to this Assignment Agreement acknowledge and agree that nothing in this Assignment Agreement shall be deemed to relieve, supersede, restrict, impair or diminish any obligations contained in the Purchase and Sale Agreement of Green River and MOC to TEPPCO nor of TEPPCO to Green River and MOC. (5) Modification; Waiver. This Assignment Agreement shall not be modified or waived except by an instrument signed by the parties to this Assignment Agreement. (6) Counterparts. This Assignment Agreement may be executed in counterparts, each of which shall be deemed an original and all of which, taken together, shall be deemed to constitute one and the same instrument. (7) Purchase and Sale Agreement. This Assignment Agreement is subject to the terms of the Purchase and Sale Agreement. [signatures on following page]

IN WITNESS WHEREOF, this Assignment Agreement has been signed by a duly authorized officer of each of the parties as of the date first above written. GREEN RIVER PIPELINE, INC. By: /s/ Roger J. Biemans --------------------------------- Name: Roger J. Biemans Title: President of Fort Collins Consolidated Royalties, Inc. Member of Green River Pipeline, LLC By: /s/ Roger J. Biemans ------------------------------------ Name: Roger J. Biemans Title: President of McMurry Oil Company, Member of Green River Pipeline, LLC MCMURRY OIL COMPANY By: /s/ Roger J. Biemans ------------------------------------ Name: Roger J. Biemans Title: President TEPPCO GP, INC. By: /s/ Michael J. Bradley ------------------------------------ Name: Michael J. Bradley Title: Agent and Attorney-in-Fact TEPPCO MIDSTREAM COMPANIES, L.P., BY TEPPCO GP, INC., ITS GENERAL PARTNER By: /s/ Michael J. Bradley ------------------------------------ Name: Michael J. Bradley Title: Agent and Attorney-in-Fact

EXHIBIT 10.41 TEPPCO GP, INC. UNANIMOUS WRITTEN CONSENT OF THE BOARD OF DIRECTORS IN LIEU OF MEETING FEBRUARY 13, 2002 Pursuant to the provisions of Section 141(f) of the General Corporation Law of the State of Delaware (the "General Corporation Law"), the undersigned, being the members of the Board of Directors of TEPPCO GP, Inc., a Delaware corporation, acting on its own behalf and in its capacity as general partner of each of TE Products Pipeline Company, Limited Partnership, a Delaware limited partnership, TCTM, L.P. a Delaware limited partnership, and TEPPCO Midstream Companies, L.P., a Delaware limited partnership, do hereby consent in writing to the adoption of the resolutions attached hereto without the holding of a meeting, such resolutions to have the same force and effect as if duly adopted at a meeting of the Board of Directors which was duly called and held in accordance with Section 141 of the General Corporation Law. IN WITNESS WHEREOF, the undersigned directors have executed this consent as of the date set forth above. /s/ William L. Thacker ------------------------------------ William L. Thacker /s/ Barry R. Pearl ------------------------------------ Barry R. Pearl /s/ Charles H. Leonard ------------------------------------ Charles H. Leonard

TEPPCO GP, INC. RESOLUTIONS ADOPTED BY UNANIMOUS WRITTEN CONSENT OF THE BOARD OF DIRECTORS FEBRUARY 13, 2002 SHELF REGISTRATION STATEMENT WHEREAS, on November 30, 2001, pursuant to directives of the Board of Directors of Texas Eastern Products Pipeline Company, LLC, a Delaware limited liability company ("TEPPCO"), the officers of TEPPCO and TEPPCO GP, Inc., a Delaware corporation (the "Company"), filed a registration statement (the "Registration Statement") on Form S-3 (File No. 333-74286) with the Securities and Exchange Commission (the "Commission") in order to register under the Securities Act of 1933, as amended (the "Securities Act") offerings by TEPPCO Partners, L.P., a Delaware limited partnership (the "MLP"), from time to time of units of limited partner interests ("Units") or debt securities ("Debt Securities") and including as co-registrants each of TE Products Pipeline Company, Limited Partnership, a Delaware limited partnership ("TE Products"), TCTM, L.P., a Delaware limited partnership ("TCTM"), TEPPCO Midstream Companies, L.P., a Delaware limited partnership ("TMC") and Jonah Gas Gathering Company, a Wyoming general partnership ("Jonah" and, collectively with TE Products, TCTM and TMC, the "Subsidiary Guarantors"), with respect to any guarantees of Debt Securities ("Guarantees") by such Subsidiary Guarantors, and including a related prospectus (the "Prospectus") together with the exhibits; WHEREAS, on January 17, 2002, February 4, 2002, and February 8, 2002, such officers of TEPPCO and the Company filed amendments to the Registration Statement with the Commission; WHEREAS, on February 12, 2002, the officers of TEPPCO and the Company filed an amendment to the Registration Statement together with a supplement to the Prospectus (the "Prospectus Supplement") relating to the offering of $500 million of Senior Notes due 2012 (the "2012 Notes") with the Commission; WHEREAS, on February 12, 2002, the staff of the Commission declared the Registration Statement effective; NOW, THEREFORE, BE IT RESOLVED, that any and all actions taken by or on behalf of the officers of the Company, for and on behalf of the Subsidiary Guarantors, related to the preparation and filing of the Registration Statement (including all amendments thereto), any exhibits thereto, the Prospectus and the Prospectus Supplement are hereby, in all respects, authorized, adopted, ratified, confirmed and approved; and

RESOLVED, that the appropriate officers of the Company be, and each of them individually is, authorized, empowered and directed, for and on behalf of the Subsidiary Guarantors, to cause to be prepared, executed and filed with the Commission such further amendments and post-effective amendments to the Registration Statement and exhibits thereto or supplements to the Prospectus constituting a part thereof, and to take all such further action, as may, in the judgment of such officers, be necessary, desirable or appropriate to maintain the effectiveness of the Registration Statement; and APPROVAL OF BLUE SKY MATTERS RESOLVED, that the appropriate officers of the Company be, and each of them individually is, acting for and on behalf of Subsidiary Guarantors, hereby authorized, empowered and directed, for and on behalf of the Subsidiary Guarantors, to determine the states in which action should be taken to qualify or register for sale therein all or part of Debt Securities (and any related Guarantees) and to perform such acts as may, in the judgment of such officers, be necessary, desirable or appropriate in order to comply with the applicable laws of such states, and in connection therewith to execute and fill all requisite papers and documents, including but not limited to, applications, reports, surety bonds, irrevocable consents and appointments of attorneys for service of process. ISSUANCE OF GUARANTEES RESOLVED, that each of the Subsidiary Guarantors are authorized to issue Guarantees relating to the 2012 Notes to be issued and sold pursuant to the Registration Statement and that the appropriate officers of the Company be, and each of them individually is, authorized, empowered and directed to negotiate with the underwriters the terms of the Guarantees and the terms of the Indenture (as hereinafter defined) under which the Guarantees may be issued; and RESOLVED, that the appropriate officers of the Company be, and each of them individually is, authorized, empowered and directed, on behalf and in the name of each of the Subsidiary Guarantors, to issue Guarantees of the 2012 Notes and, in connection with such issue, to determine the form and terms of the Guarantees of the 2012 Notes to be issued by the Subsidiary Guarantors and such other terms, conditions and provisions as such officers shall deem appropriate; and RESOLVED, that the President and any Vice President of the Company be, and each of them individually is, authorized, empowered and directed, in the name and on behalf of the Subsidiary Guarantors, and, if required, under its company seal attested by its Secretary or Assistant Secretary, to execute and deliver an Indenture substantially in the form previously presented to the Board of Directors, with such changes therein as the officer executing the same may approve, such approval to be conclusively evidenced by the execution thereof, and that such officers are authorized to execute and deliver, in similar manner, supplemental agreements thereto including a First Supplemental Indenture relating to the 2012 Notes (the indenture, as amended by the First Supplemental Indenture and any additional supplemental agreements thereto, referred to herein as the "Indenture"); that the 2012 Notes and related Guarantees be issued in accordance with the Indenture; and that the officers of the Company be, and each of them individually is, further authorized, empowered and directed to do, in the name and on -2-

behalf of the Company or any of the Subsidiary Guarantors, any and all acts which they, in their discretion, may deem necessary or advisable to make the Indenture the valid and effective act and agreement of each of the Subsidiary Guarantors; and RESOLVED, that the officers of the Company be, and each of them individually is, authorized, empowered and directed, in the name and on behalf of the Company or any of the Subsidiary Guarantors, to execute and deliver such other agreements, documents, certificates and instruments as may be required by any fiduciary in connection with the Indenture or as may be necessary or appropriate in connection with the issuance and sale of the2012 Notes and related Guarantees; and RESOLVED, that the Guarantees of the 2012 Notes, or any form of Indenture, notation on the 2012 Notes or other instrument evidencing such Guarantees, as the case may be, shall be executed in the name and on behalf of each of the Subsidiary Guarantors by the President and/or any Vice President, and, if required, attested by the Treasurer and/or any Assistant Treasurer or the Secretary or any Assistant Secretary; that the signature of each of such officers on such Indenture, notation or other such instrument evidencing such Guarantees may be manual or facsimile; that any Indenture, notation on the 2012 Notes or such other instrument evidencing the Guarantees bearing the manual or facsimile signatures of the individuals who were at any time officers of the Company shall bind each Subsidiary Guarantor notwithstanding that such individuals or any of them cease to hold such offices prior to the authentication of the 2012 Notes and related Guarantees and the issuance of any such Guarantee or the delivery of such 2012 Notes and related Guarantee; and that such Guarantee shall be in such form and of such character as shall be set forth in the respective Indenture or as shall otherwise be approved by the President or any Vice President; and UNDERWRITING AGREEMENT RESOLVED, that the President and any Vice President of the Company be, and each of them individually is, authorized, empowered and directed, in the name and on behalf of the Company, in its own capacity and in the name and on behalf of each of the Subsidiary Guarantors (in its capacity as general partner of the Subsidiary Guarantors), to execute and deliver an Underwriting Agreement relating to the offer and sale of the 2012 Notes substantially in the form previously presented to the Board of Directors, with such changes therein as the officer executing the same may approve, such approval to be conclusively evidenced by the execution thereof; and JONAH GAS GATHERING COMPANY RESOLVED, that the Company, in its capacity as general partner of Jonah and on behalf of and in its capacity as general partner of TCM, the other general partner of Jonah, authorizes and approves all matters set forth in these resolutions to be undertaken by, in the name of and on behalf of Jonah, including without limitation (i) the execution and delivery of the Indenture by Jonah as a Subsidiary Guarantor and any evidence of the Guarantee of Jonah and (ii) the execution and delivery of the Underwriting Agreement of the 2012 Notes; -3-

RESOLVED, that Company, in its capacity as general partner of Jonah and on behalf of and its capacity as general partner of TCM, the other general partner of Jonah, hereby causes each of the partners of Jonah to designate the Company as Managing Partner of Jonah (as such term is used in the agreement of partnership of Jonah), which designation is made hereby by agreement of all the partners of Jonah notwithstanding any provision of the agreement of partnership of Jonah to the contrary; and RESOLVED, that the President or any Vice President of the Company be, and each of them individually is, authorized, empowered and directed, to prepare, execute, deliver and perform such agreements, documents and other instruments in the name and on behalf of Jonah (in the Company's capacity as Managing Partner of Jonah) and to take such other action, in the name or on behalf of Jonah, as each of such officers, in his discretion, shall deem necessary or advisable to carry out the intent of or to effect the foregoing resolutions and the transactions contemplated thereby, the taking of such action and the preparation, execution, delivery and performance of any such agreements, documents and other instruments or the performance of any such act shall be conclusive evidence of the authorization and approval of this Board of Directors and of each of the partners of Jonah, and all matters relating thereto; RESOLVED, that any and all actions taken by or on behalf of the officers of the Company in the name and on behalf of Jonah prior to the adoption of these resolutions, which are within the authority conferred hereby, are hereby in all respects authorized, adopted, ratified, confirmed and approved; and RESOLVED, that any and all actions taken by or on behalf of Jonah as set forth in these resolutions, which have been authorized and approved by all partners of Jonah, shall be valid actions of Jonah notwithstanding any provision of the agreement of partnership of Jonah to the contrary, which agreement shall be deemed modified to the extent necessary to further the intent and purposes of these resolutions. FURTHER ACTION RESOLVED, that the appropriate officers of the Company be, and each of them individually is, authorized, empowered and directed, to prepare, execute, deliver and perform such agreements, documents and other instruments and to take such other action, in the name or on behalf of the Company or either of the Subsidiary Guarantors, to pay or cause to be paid on behalf of the Company or either of the Subsidiary Guarantors, such related costs and expenses, and to execute and deliver or cause to be executed and delivered such other notices, requests, demands, directors, consents, approvals, orders, applications, certificates, agreements, undertakings, supplements, amendments, further assurances or other instruments or communications, under the corporate seal of the Company, or otherwise, as each of such officers, in his discretion, shall deem necessary or advisable to carry out the intent of or to effect the foregoing resolutions and the transactions contemplated thereby, the taking of such action and the preparation, execution, delivery and performance of any such agreements, documents and other instruments or the performance of any such act shall be conclusive evidence of the approval of this Board of Directors thereof and all matters relating thereto; and -4-

RESOLVED, that any and all actions taken by or on behalf of the officers of the Company prior to the adoption of these resolutions, which are within the authority conferred hereby, are hereby in all respects authorized, adopted, ratified, confirmed and approved. -5-


                                                                    EXHIBIT 12.1


STATEMENT OF COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES



                                                                                YEARS ENDED DECEMBER 31,
                                                      ----------------------------------------------------------------------
                                                             1997           1998          1999          2000          2001
                                                             ----           ----          ----          ----          ----
                                                                                     (in thousands)
                                                                                                      
EARNINGS
        Income From Continuing Operations *                  61,925        53,885        72,856        65,951        92,533
        Fixed Charges                                        35,458        30,915        34,305        55,621        72,217
        Distributed Income of
            Equity Investment                                     -             -             -             -        40,800
        Capitalized Interest                                 (1,478)         (795)       (2,133)       (4,559)       (4,000)
                                                      ----------------------------------------------------------------------
            Total Earnings                                   95,905        84,005       105,028       117,013       201,550
                                                      ======================================================================

FIXED CHARGES
        Interest Expense                                     33,707        29,784        31,563        48,982        66,057
        Capitalized Interest                                  1,478           795         2,133         4,559         4,000
        Rental Interest Factor                                  273           336           609         2,080         2,160
                                                      ----------------------------------------------------------------------
            Total Fixed Charges                              35,458        30,915        34,305        55,621        72,217
                                                      ======================================================================


RATIO:  EARNINGS / FIXED CHARGES                               2.70          2.72          3.06          2.10          2.79
                                                      ======================================================================


        * Excludes minority interest, extraordinary loss and undistributed
equity earnings.


                                                                     EXHIBIT 21

                         SUBSIDIARIES OF THE PARTNERSHIP

                        TEPPCO PARTNERS, L.P. (DELAWARE)


TEPPCO GP, Inc. (Delaware)
TE Products Pipeline Company, Limited Partnership (Delaware)
TEPPCO Colorado, LLC (Delaware)
TEPPCO Midstream Companies, L.P. (Delaware)
Chaparral Pipeline Company, L.P. (Delaware)
Quanah Pipeline Company, L.P. (Delaware)
Jonah Gas Gathering Company (Wyoming general partnership)
TCTM, L.P. (Delaware)
TEPPCO Crude GP, LLC (Delaware)
TEPPCO Crude Pipeline, L.P. (Delaware)
TEPPCO Seaway, L.P. (Delaware)
TEPPCO Crude Oil, L.P. (Delaware)
Lubrication Services, L.P. (Delaware)

EXHIBIT 23 INDEPENDENT AUDITORS' CONSENT To the Partners of TEPPCO Partners, L.P.: We consent to the incorporation by reference in the registration statements (No. 33-81976) and (No. 333-74286) on Form S-3 and the registration statement (No. 333-82892) on Form S-8 of TEPPCO Partners, L.P. of our report dated January 17, 2002, with respect to the consolidated balance sheets of TEPPCO Partners, L.P. as of December 31, 2001 and 2000 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, 2001, which report appears in the December 31, 2001 annual report on Form 10-K of TEPPCO Partners, L.P. Our report on the consolidated financial statements refers to a change in the method of accounting for derivative financial instruments and hedging activities and the adoption of Statement of Financial Accounting Standards ("SFAS") No. 141, Business Combinations and certain provisions of SFAS No. 142, Goodwill and Other Intangible Assets in 2001. KPMG LLP Houston, Texas March 14, 2002

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, does hereby appoint CHARLES H. LEONARD, BARRY R. PEARL, JAMES C. RUTH AND WILLIAM L. THACKER, 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 advise and consent of Counsel, said attorney and agent may deem necessary or advisable to enable the Company 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, 2001, 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 14th day of March, 2002. /s/ WILLIAM L. THACKER /s/ JIM W. MOGG - --------------------------------- ----------------------------------- William L. Thacker Jim W. Mogg /s/ MILTON CARROLL /s/ FRED J. FOWLER - --------------------------------- ----------------------------------- Milton Carroll Fred J. Fowler /s/ CARL D. CLAY /s/ MARK A. BORER - --------------------------------- ----------------------------------- Carl D. Clay Mark A. Borer /s/ JOHN P. DESBARRES /s/ WILLIAM W. SLAUGHTER - --------------------------------- ----------------------------------- John P. DesBarres William W. Slaughter /s/ DERRILL CODY /s/ CHARLES H. LEONARD - --------------------------------- ----------------------------------- Derrill Cody Charles H. Leonard Senior Vice President