10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)
[X]	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2002
or
[   ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from                to

Commission file number 0-31095

Duke Energy Field Services, LLC

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)	76-0632293 (I.R.S. Employer Identification No.)
370 17th Street, Suite 900 Denver, Colorado (Address of principal executive offices)	80202 (Zip Code)

Registrant’s telephone number, including area code
303-595-3331
Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Name of Each Exchange on Which Registered
None	Not Applicable

Securities registered pursuant to Section 12(g) of the Act:
Limited Liability Company Member Interests
(Title of class)

     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 12 months or for such shorter period that the registrant was required to file such reports and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [   ]

     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. [X]

     Indicate by check mark whether the registrant is an accelerated filer as defined by Rule 12b-2 of the Act. Yes [   ] No[X]

     As of March 17, 2003, 69.7% of the registrant’s outstanding member interests is beneficially owned by Duke Energy Corporation and 30.3% is beneficially owned by ConocoPhillips. The aggregate market value of the voting and non-voting member interests held by non-affiliates of the registrant computed by reference to the price at which the member interests were last sold, or the average bid and asked price for such member interests, as of the last business day of the registrant’s most recently completed fiscal quarter was $0.

Documents incorporated by reference:
None

TABLE OF CONTENTS

PART I.
	ITEM 1. Business.
		Our Business
		Our Business Strategy
		Natural Gas Gathering, Processing, Transportation, Marketing and Storage
		Natural Gas Liquids Transportation, Fractionation, Marketing and Trading
		TEPPCO
		Natural Gas Suppliers
		Competition
		Regulation
		Environmental Matters
		Employees
	ITEM 2. Properties.
	ITEM 3. Legal Proceedings.
	ITEM 4. Submission of Matters to a Vote of Security Holders.
PART II.
	ITEM 5. Market for Registrant’s Common Equity and Related Stockholder 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.
	ITEM 14. Controls and Procedures
PART IV.
	ITEM 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
SIGNATURES
CERTIFICATIONS
EXHIBIT INDEX
EX-10.4 Second Amendment to Services Agreement
EX-10.5 Amendment to Services Agreement
EX-12.1 Calculation of Ratio of Earnings
EX-21.1 Subsidiaries
EX-23.1 Consent of Deloitte & Touche LLP
EX-23.2 Consent of KPMG LLP
EX-99.1 Certification Pursuant to 18 USC Sec. 1350
EX-99.2 Certification Pursuant to 18 USC Sec. 1350
EX-99.3 Consolidated Financial Statements

DUKE ENERGY FIELD SERVICES, LLC
FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2002

TABLE OF CONTENTS

Item				Page
PART I.
	1.	Business			3
			Our Business		3
			Our Business Strategy		4
			Natural Gas Gathering, Processing, Transportation, Marketing and Storage		5
			Natural Gas Liquids Transportation, Fractionation and Marketing and Trading		11
			TEPPCO		12
			Natural Gas Suppliers		13
			Competition		13
			Regulation		14
			Environmental Matters		16
			Employees		17
	2.	Properties			17
	3.	Legal Proceedings			17
	4.	Submission of Matters to a Vote of Security Holders			17
PART II.
	5.	Market for Registrant’s Common Equity and Related Stockholder Matters			18
	6.	Selected Financial Data			19
	7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations			21
	7A.	Quantitative and Qualitative Disclosures About Market Risk			31
	8.	Financial Statements and Supplementary Data			38
	9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			66
PART III.
	10.	Directors and Executive Officers of the Registrant			66
	11.	Executive Compensation			68
	12.	Security Ownership of Certain Beneficial Owners and Management			72
	13.	Certain Relationships and Related Transactions			72
	14.	Controls and Procedures			73
PART IV.
	15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K			75
		Signatures			76
		Exhibit Index			79

1

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

     Our reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements by the use of forward-looking words, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and other similar words.

     All statements that are not statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.

     These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. Known risks include, but are not limited to, the following:

• our ability to access the debt and equity markets, which will depend on general market conditions and the credit ratings for our debt obligations;

• our use of derivative financial instruments to hedge commodity and interest rate risks;

• the level of creditworthiness of counterparties to transactions;

• the amount of collateral required to be posted from time to time in our transactions;

• changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment or the increased regulation of the gathering and processing industry;

• the timing and extent of changes in commodity prices, interest rates, foreign currency exchange rates and demand for our services;

• weather and other natural phenomena;

• industry changes, including the impact of consolidations, and changes in competition;

• our ability to obtain required approvals for construction or modernization of gathering and processing facilities, and the timing of production from such facilities, which are dependent on the issuance by federal, state and municipal governments, or agencies thereof, of building, environmental and other permits, the availability of specialized contractors and work force and prices of and demand for products;

• the extent of success in connecting natural gas supplies to gathering and processing systems;

• the effect of accounting policies issued periodically by accounting standard-setting bodies; and

• general economic conditions.

     In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than we have described. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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PART I.

ITEM 1. Business.

     Duke Energy Field Services, LLC is a company formed in 1999 that holds to the extent that it existed at the time, the combined North American midstream natural gas gathering, processing, marketing and natural gas liquids (“NGL”) business of Duke Energy Corporation (“Duke Energy”) and Phillips Petroleum Company (“Phillips”) prior to its merger with Conoco Inc. (“ConocoPhillips”). References to ConocoPhillips, for periods prior to the merger of Conoco Inc. and Phillips, are references to Phillips. The transaction in which those businesses were combined is referred to in this Form 10-K as the “Combination.” Our limited liability company agreement limits the scope of our business to the midstream natural gas industry in the United States and Canada, the marketing of NGLs in Mexico and the transportation, marketing and storage of other petroleum products, unless otherwise approved by our Board of Directors.

     Unless the context otherwise requires, descriptions of assets, operations and results in this Form 10-K give effect to the Combination and related transactions, the transfer to us of additional midstream natural gas assets acquired by Duke Energy or ConocoPhillips prior to the Combination and the transfer to us of the general partner of TEPPCO Partners, L.P., all of which are described in more detail under “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” In this Form 10-K, the terms “the Company,” “we,” “us” and “our” refer to Duke Energy Field Services, LLC and our subsidiaries, giving effect to the Combination and related transactions.

     From a financial reporting perspective, we are the successor to Duke Energy’s North American midstream natural gas business that existed at the time of the Combination. The subsidiaries of Duke Energy that conducted this business were contributed to us immediately prior to the Combination. For periods prior to the Combination, Duke Energy Field Services and these subsidiaries of Duke Energy are collectively referred to herein as the “Predecessor Company.”

     We are a Delaware limited liability company, and we were formed on December 15, 1999. Our principal executive offices are located at 370 17th Street, Suite 900, Denver, Colorado 80202. Our telephone number is 303-595-3331 and our internet website is www.defs.com.

Our Business

     The midstream natural gas industry is the link between exploration and production of raw natural gas and the delivery of its components to end-use markets. We operate in the two principal segments of the midstream natural gas industry:

• natural gas gathering, compression, treating, processing, transportation, trading and marketing and storage (“Natural Gas Segment”); and

• NGL fractionation, transportation, marketing and trading (“NGL Segment”).

     We believe that we are one of the largest gatherers of raw natural gas, based on wellhead volume, in North America. We are the largest producer, and we believe that we are one of the largest marketers, of NGLs in North America. In 2002:

• we handled an average of approximately 8.3 trillion British thermal units (“Btus”) per day of raw natural gas;

• we produced an average of approximately 392,000 barrels per day of NGLs;

• we marketed and traded an average of approximately 576,000 barrels per day of NGLs; and

• we marketed an average of approximately 2.6 trillion Btus per day of natural gas.

     We gather raw natural gas through gathering systems located in seven major natural gas producing regions: Permian Basin, Mid-Continent, East Texas-Austin Chalk-North Louisiana, Onshore Gulf of Mexico, Rocky Mountains, Offshore Gulf of Mexico and Western Canada. At December 31, 2002, our gathering systems consisted of approximately 60,000 miles of gathering and transmission pipe, with approximately 35,000 active receipt points.

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     Our natural gas processing operations involve the separation of raw natural gas gathered both by our gathering systems and by third party systems into NGLs and residue gas. We process the raw natural gas at our 60 owned and operated plants and at 11 third party operated facilities in which we hold an equity interest.

     The NGLs separated from the raw natural gas by our processing operations are either sold and transported as NGL raw mix or further separated through a process known as fractionation into their individual components (ethane, propane, butanes and natural gasoline) and then sold as components. We fractionate NGL raw mix at our 11 owned and operated fractionators and at four third party operated fractionators located on the Gulf Coast in which we hold an equity interest.

     We sell NGLs to a variety of customers ranging from large, multi-national petrochemical and refining companies to small regional retail propane distributors. Substantially all of our NGL sales are made at market-based prices, including approximately 40% of our NGL production that is committed to ConocoPhillips and Chevron Phillips Chemical Company LLC under an existing contract which expires December 31, 2014. In addition, we use trading and storage to manage our price risk and provide additional services to our customers. (See “Natural Gas Liquids Transportation, Fractionation and Marketing” in this section.)

     The residue gas that results from our processing is sold at market-based prices to marketers and end-users, including large industrial customers and natural gas and electric utilities serving individual consumers. We market residue gas directly or through our wholly-owned gas marketing company. We also store residue gas at our 7.5 billion cubic foot natural gas storage facility.

     On March 31, 2000, we combined the gas gathering, processing, marketing and NGLs businesses of Duke Energy and ConocoPhillips that existed at that time. In connection with the Combination, Duke Energy and ConocoPhillips transferred to us all of their respective interests in their subsidiaries that conducted their midstream natural gas business. Concurrent with the Combination, on March 31, 2000, we obtained by transfer from Duke Energy ownership of the general partner of TEPPCO Partners, L.P. (“TEPPCO”), a publicly traded master limited partnership which owns and operates a network of pipelines and storage and terminal facilities for refined products, liquefied petroleum gases, petrochemicals, natural gas and crude oil. The general partner is responsible for the management and operations of TEPPCO. We believe that our ownership of the general partner of TEPPCO improves our business position in the gathering and transportation sectors of the midstream natural gas industry and provides additional flexibility in pursuing our disciplined acquisition strategy by providing an alternative acquisition vehicle.

     Duke Energy and ConocoPhillips are currently having discussions regarding possible changes to DEFS ownership. Member interests in DEFS are currently held 69.7% by Duke Energy and 30.3% by ConocoPhillips. As a result of the merger between Conoco Inc. (“Conoco”) and Phillips Petroleum Company that created ConocoPhillips, ConocoPhillips owns the midstream natural gas assets that were formerly owned by Conoco. Duke Energy and ConocoPhillips are currently discussing the possible contribution by ConocoPhillips of certain of these assets to DEFS. There is no certainty that these discussions will lead to a transaction in which ConocoPhillips would contribute these assets to DEFS or what the terms of such a transaction might be.

     A discussion of the current business and operations of each of our segments follows the description of our business strategy. For further discussion of these segments, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” For financial information concerning our business segments, see Note 17, “Business Segments,” of the Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplemental Data.

Our Business Strategy

     We are one of the largest gatherers of raw natural gas, based on wellhead volume, in North America. We are the largest producer and one of the largest marketers of NGLs in North America. Our limited liability company agreement limits the scope of our business to the midstream natural gas industry in the United States and Canada, the marketing of NGLs in Mexico, and the transportation, marketing and storage of other petroleum products, unless otherwise approved by our board of directors. We have significant midstream natural gas operations in five of the largest natural gas producing regions in North America. In the current economic environment, we are pursuing the following strategies:

• Size and focus of our existing operations. Our size, scope and concentration of our assets in our regions of operation provide for opportunities to acquire additional supplies of raw natural gas. Our significant market presence and asset base generally provide us opportunities to use our economies of scale to be the low cost provider in connecting new raw natural gas supplies and providing value chain gathering and processing services. In addition, we believe our size and geographic diversity allow us to benefit from the growth of natural gas production in multiple regions while mitigating the adverse effects from a downturn in any one region.

4

• Increase our presence in each aspect of the midstream business. We are active in each significant aspect of the midstream natural gas value chain, including raw natural gas gathering, processing and transportation, NGL fractionation, and NGL and residue gas transportation and marketing. Each link in the value chain provides us with an opportunity to earn incremental income from the raw natural gas that we gather and from the NGLs and residue gas that we produce.

• Increase our presence in high growth production areas. We intend to use our strategic asset base in North America and our leading position in the midstream natural gas industry as a platform for future growth. We plan to increase our operations by following a disciplined acquisition strategy, and by expanding existing infrastructure and constructing new gathering lines and processing facilities.

• Further streamline our low-cost structure. Our economies of scale, operating efficiency and resulting low cost structure enhance our ability to attract new raw natural gas supplies and generate current income. The low-cost provider in any region can more readily attract new raw natural gas volumes by offering more competitive terms to producers. We believe that we have a complementary base of assets from which to further extract operating efficiencies and cost reductions, while continuing to provide superior customer service. In addition, we continue to optimize our existing assets by looking at potential plant consolidation, reviewing our contract structure and ensuring reliability in our plant operations.

Natural Gas Gathering, Processing, Transportation, Marketing and Storage

Overview

     At December 31, 2002, our raw natural gas gathering and processing operations consisted of:

• approximately 60,000 miles of gathering and transmission pipe, with connections to approximately 35,000 active receipt points; and

• 60 owned and operated processing plants and ownership interests in 11 additional third party operated plants, with a combined processing capacity of approximately 8.0 billion cubic feet per day.

     In 2002, we gathered, processed and/or transported approximately 8.3 trillion Btus per day of raw natural gas. As a result of new connections resulting from both increased drilling and released raw natural gas, we connected approximately 1,600 additional receipt points in 2002.

     Our raw natural gas gathering and processing operations are located in 11 contiguous states in the United States and two provinces in Western Canada. We provide services in the following key North American natural gas and oil producing regions: Permian Basin, Mid-Continent, East Texas-Austin Chalk-North Louisiana, Onshore Gulf of Mexico, Rocky Mountains, Offshore Gulf of Mexico and Western Canada. We have a significant presence in the first five of these producing regions. According to Hart Downstream Energy Services “Gas Processors Report” dated November 18, 2002, we are the largest NGL producer in North America.

     Raw Natural Gas Supply Arrangements. Typically, we take ownership, control or custody of raw natural gas at the wellhead. The producer may dedicate to us the raw natural gas produced from designated oil and natural gas leases for a specific term. The term for dedicated gas can range from 30 days to life of lease. We obtain access to raw natural gas and provide our midstream natural gas service principally under three types of processing contracts: percentage-of-proceeds contracts, fee-based contracts and keep-whole and wellhead-purchase contracts. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview — Effects of Our Raw Natural Gas Supply Arrangements” for a description of these types of contracts.

     Raw Natural Gas Gathering. We receive raw natural gas from a diverse group of producers under contracts with varying durations to provide a stable supply of raw natural gas through our processing plants. A significant portion of the raw natural gas that is processed by us is produced by large producers, including ConocoPhillips, Anadarko Petroleum, Exxon Mobil, EOG Resources, and Dominion, which together account for approximately 20% of our processed raw natural gas.

     We continually seek new supplies of raw natural gas, both to offset natural declines in production from connected wells and to increase throughput volume. We obtain new well connections in our operating areas by contracting for production from new wells or by obtaining raw natural gas that has been released from other third party gathering systems. Producers may switch raw natural gas from one gathering system to another to obtain better commercial terms, conditions and service levels.

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     We believe our significant asset base and scope of our operations provide us with significant opportunities to add released raw natural gas to our systems. In addition, we have significant processing capacity in the Offshore Gulf of Mexico and Rocky Mountain regions, which contain significant quantities of proved natural gas reserves. We also have a presence in other potential high-growth areas such as the Western Canadian Sedimentary Basin.

     Gathering systems are operated at design pressures that will maximize the total throughput from all connected wells. On gathering systems where it is economically feasible, we operate at a relatively low pressure, which can allow us to offer a significant benefit to producers. Specifically, lower pressure gathering systems allow wells, which produce at progressively lower field pressures as they age, to remain connected to gathering systems and continue to produce for longer periods of time. As the pressure of a well declines, it becomes increasingly more difficult to deliver the remaining production in the ground against a higher pressure that exists in the connecting gathering system. Field compression is typically used to lower the pressure of a gathering system. If field compression is not installed, then the remaining production in the ground will not be produced because it cannot overcome the higher gathering system pressure. In contrast, if field compression is installed, then a well can continue delivering production that otherwise would not be produced. Our field compression systems provide the flexibility of connecting a high pressure well to the downstream side of the compressor even though the well is producing at a pressure greater than the upstream side. As the well ages and the pressure naturally declines, the well can be reconnected to the upstream, low pressure side of the compressor and continue to produce. By maintaining low pressure systems with field compression units, we believe that the wells connected to our systems are able to produce longer and at higher volumes before disconnection is required.

     Raw Natural Gas Processing. Most of our natural gas gathering systems feed into our natural gas processing plants. Our processing plants received an average of approximately 6.5 trillion Btus per day of raw natural gas and produced an average of 392,000 barrels per day of NGLs during 2002.

     Our natural gas processing operations involve the extraction of NGLs from raw natural gas, and, at certain facilities, the fractionation of NGLs into their individual components (ethane, propane, butanes and natural gasoline). We sell NGLs produced by our processing operations to a variety of customers ranging from large, multi-national petrochemical and refining companies, including one of our owners, ConocoPhillips, to small, regional retail propane distributors. At four of our Mid-Continent facilities the element helium is isolated from the raw gas stream and sold to industrial gas companies.

     We also remove off-quality crude oil, nitrogen, hydrogen sulfide, carbon dioxide and brine from the raw natural gas stream. The nitrogen and carbon dioxide are released into the atmosphere, and the crude oil and brine are accumulated and stored temporarily at field compressors or at various plants. The brine is transported to licensed disposal wells owned either by us or by third parties. The crude oil is sold in the off-quality crude oil market.

     Residue Gas Marketing. In addition to our gathering and processing activities, we are involved in the purchase and sale of residue gas, directly or through our wholly owned gas marketing company and our affiliates. Our gas marketing efforts involve supplying the residue gas demands of end-user customers that are physically attached to our pipeline systems, supplying the gas processing requirements associated with our keep-whole processing agreements and selling gas into downstream pipelines. We are focused on extracting the highest possible value for the residue gas that results from our processing and transportation operations.

     Our gas trading and marketing activities are supported by our ownership of the Spindletop storage facility and various intrastate pipelines which give us access to market centers/hubs such as Waha, Texas; Katy, Texas and the Houston Ship Channel. We undertake these activities through the use of fixed forward sales, basis and spread trades, storage opportunities, put/call options, term contracts and spot market trading. We believe there are additional opportunities to grow our services to our customer base.

     Our Spindletop storage facility plays an important role in our ability to act as a full-service natural gas trader and marketer. We lease over half of the facility’s capacity to our customers, and we use the balance to manage relatively constant natural gas supply volumes with uneven demand levels, provide “backup” service to our customers and support our trading activities.

     The natural gas marketing industry is a highly competitive commodity business. We provide a full range of natural gas marketing services in conjunction with the gathering, processing and transportation services we offer on our facilities, which allows us to use our asset infrastructure to enhance our revenues across each aspect of the midstream natural gas value chain.

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Regions of Operations

     Our operations cover substantially all of the major natural gas producing regions in the United States, as well as portions of Western Canada. Our geographic diversity reduces the impact of regional price fluctuations and regional changes in drilling activity.

     Our raw natural gas gathering and processing assets are managed in line with the seven geographic regions in which we operate. The following table provides information concerning the raw natural gas gathering systems and processing plants owned or operated by us at December 31, 2002.

									2002 Operating Data
	Gas
	Gathering		Company		Plants		Net Plant		Plant Inlet			NGLs
	System		Operated		Operated		Capacity(1)		Volume(1)			Production
Region	(miles)		Plants		by Others		(MMcf/d)(3)		(BBtu/d)(3)			(Bbls/d)(3)
Permian Basin		16,664		17		2		1,380		1,364			121,559
Mid-Continent		30,270		13		1		2,019		1,896			123,759
East Texas-Austin Chalk-North Louisiana		4,614		6		—		1,185		1,026			61,743
Onshore Gulf of Mexico		4,561		7		1		1,118		1,015			48,053
Rocky Mountains		2,756		9		—		475		399			21,294
Offshore Gulf of Mexico		685		2		6		1,332		357	(2)		9,265
Western Canada		921		6		1		543		401			6,240
Total		60,471		60		11		8,052		6,458			391,913

(1)	Note that while capacity is measured volumetrically (in cubic feet), inlet volumes are measured using heating value (in British thermal units).
(2)	Excludes inlet volumes of about 335 BBtu/d net for plants operated by others.
(3)	MMcf/d: million cubic feet per day; BBtu/d: billion British thermal units per day; Bbls/d: barrels per day.

     Our key suppliers of raw natural gas in these seven regions include major integrated oil companies, independent oil and gas producers, intrastate pipeline companies and natural gas marketing companies. Our principal competitors in this segment of our business consist of major integrated oil companies, independent oil and gas producers, independent oil and gas gatherers, and interstate and intrastate pipeline companies.

     Regional Strategies. Continued raw natural gas supply is key to our success. Maintaining our raw natural gas supply enables us to maintain throughput volumes and asset utilization throughout our entire midstream natural gas value chain. As we develop our regional strategies, we evaluate the nature of the opportunity that a particular region presents. The attributes that we evaluate include the nature of the gas reserves and production profile, existing midstream infrastructure including capacity and capabilities, the regulatory environment, the characteristics of the competition and the competitive position of our assets and capabilities. In a general sense, we employ one or more of the strategies described below:

• Growth - in regions where production is expected to grow significantly and/or there is a need for additional gathering and processing infrastructure, we plan to expand our gathering and processing assets by following a disciplined acquisition strategy, by expanding existing infrastructure and by constructing new gathering lines and processing facilities.

• Consolidation - in regions that include mature producing basins with flat to declining production or that have excess gathering and processing capacity, we seek opportunities to efficiently consolidate the existing asset base to increase utilization and operating efficiencies and realize economies of scale.

• Opportunistic - in regions where production growth is not primarily generated by new exploration drilling activity, we intend to optimize our existing assets and selectively expand certain facilities or construct new facilities to seize opportunities to increase our throughput. These regions are generally experiencing stable to increasing production through the application of new drilling technologies like 3-D seismic, horizontal drilling and improved well completion techniques. The application of new technologies is causing the drilling of additional wells in areas of existing production and recompletions of existing wells which create additional opportunities to add new gas supplies.

     In each region, we plan to apply both our broad overall business strategy and the strategy uniquely suited to each region. We believe this plan will yield balanced growth initiatives, including new construction in certain high growth areas, expansion of existing

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systems, combined with efficiency improvements and/or asset consolidation. We also plan to rationalize assets and redeploy capital to higher value opportunities.

     A description of our operations, key suppliers and principal competitors in each region is set forth below:

     Permian Basin. Our facilities in this region are located in West Texas and Southeast New Mexico. We own majority interests in, and we are the operator of, 17 natural gas processing plants in this region. In addition, we own minority interests in two other natural gas processing plants that are operated by others. Our natural gas processing plants are strategically located to access Permian Basin production. Our plants have processing capacity net to our interest of 1.4 billion cubic feet of raw natural gas per day. Operations in this region are primarily focused on gathering, processing and marketing of natural gas and NGLs. We offer low, intermediate and high pressure gathering services, and processing and treating services for both sweet and sour gas production. Three of our processing facilities provide fractionation services. Residue gas sales are enhanced by access to the Waha Hub where multiple pipeline interconnects source gas for virtually every market in the United States. Our older facilities have been modernized to improve product recoveries, and some of our plants include facilities for the production of sulfur. During 2002, these plants operated at an overall 81% capacity utilization rate. On average, the raw natural gas from West Texas and Southeast New Mexico contains approximately 4.0 gallons of NGLs per thousand cubic feet.

     As we generally pursue a consolidation strategy in this region, our assets will allow us to compete for new gas supplies in most major fields and benefit from the increases in drilling and production from technological advances. In addition, our ability to redirect gas between several processing plants allows us to maximize utilization of our processing capacity in this region.

     Our key suppliers in this region include ExxonMobil, Occidental, Anadarko Petroleum, ConocoPhillips, Dominion Resources, Chevron-Texaco, and Yates Petroleum. Our principal competitors in this region include Dynegy, Sid Richardson, ConocoPhillips, Western Gas Resources, BP, El Paso Energy Partners, Marathon and Chevron-Texaco.

     Mid-Continent. Our facilities in this region are located in Oklahoma, Kansas, the Texas Panhandle and four counties in Southeast Colorado. In this region, we own and are the operator of 13 natural gas processing plants. We also own a minority interest in one other natural gas processing plant that is operated by a third party. We gather and process raw natural gas primarily from the Arkoma, Ardmore, and Anadarko Basins, including the prolific Hugoton and Panhandle fields. Our plants have processing capacity net to our interest of 2.0 billion cubic feet of raw natural gas per day. During 2002, our plants operated at an overall 82% capacity utilization rate. On average, the raw natural gas from this region contains 4.1 gallons of NGLs per thousand cubic feet.

     We also produce approximately 25% of the United States’ domestic supply of helium from our Mid-Continent facilities. Annual growth in demand for helium over the past five years has been approximately 8% per year. Because of its unique characteristics and use as an industrial gas, we expect demand for helium to grow well into the future.

     Existing production in the Mid-Continent region is typically from mature fields with shallow decline profiles that will provide our plants with a dependable source of raw natural gas over a long term. With the development of improved exploration and production techniques such as 3-D seismic and horizontal drilling over the past several years, additional reserves have become economically producible in this region. We hold large acreage dedication positions with various producers who have developed programs to add substantially to their reserve base. The infrastructure of our plants and gathering facilities is uniquely positioned to pursue our consolidation strategy in this region.

     Our key suppliers in this region include ConocoPhillips, OXY USA, Dominion Resources, EOG Resources, Marathon Oil Company, Chesapeake Energy Corporation, Apache Corporation and Anadarko Petroleum. Our principal competitors in this region include Oneok Field Services, Enogex Inc., CMS Field Services, Pioneer, Enbridge, and BP.

     East Texas-Austin Chalk-North Louisiana. Our facilities in this region are located in East Texas, North Louisiana and the Austin Chalk formation of East Central Texas and Central Louisiana. We own majority interests in and are the operator of six natural gas processing plants in this region. Our plants have processing capacity net to our interest of 1.2 billion cubic feet of raw natural gas per day. During 2002, these plants operated at an overall 74% capacity utilization rate.

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     Our East Texas operations are centered around our East Texas Complex, located near Carthage, Texas. This plant complex is the third largest raw natural gas processing facility in the continental United States, based on liquids recovery, and currently produces approximately 38,000 barrels per day of NGLs. The plant is connected to and processes raw natural gas from our own gathering systems as well as from several third party gathering systems, including those owned by Gulf South, Anadarko Petroleum and American Central. Most of the raw natural gas processed at the complex is contracted under percent-of-proceeds agreements with an average remaining term of approximately five years. The complex is adjacent to our Carthage Hub, which delivers residue gas to interconnects with 12 interstate and intrastate pipelines. The Carthage Hub, with an aggregate delivery capacity of 1.5 billion cubic feet per day, acts as a key exchange point for the purchase and sale of residue gas.

     In the Austin Chalk area, where we provide essential low pressure gathering and compression services, infill drilling and recompletion activity continue to offset the lower decline rates of this mature production area. Given the maturity of this area, consolidation of our own facilities and/or consolidation with other gathering and processing companies could occur. In the Eastern Chalk area (Brookeland and Masters Creek), consolidation of the gas processing facilities was completed in July 2002. Gas prices are supporting new drilling activity, which has reduced decline rates. Volume declines in the near term, however, are expected to continue. Additional improvements in technology or sustained higher gas prices could significantly increase activity and reserve recovery in either of these two areas.

     In North Louisiana, we gather and process or gather and transport over 420 billion Btus per day. We operate one of the largest intrastate pipelines in Louisiana, the PELICO System, which delivers gas to industrial customers and electric generators within the state and also makes deliveries to six interstate pipelines at or near the Perryville Hub.

     Our key suppliers in this region include Anadarko Petroleum, Devon Energy and ConocoPhillips. Our principal competitors in this region include Gulf South, El Paso Energy Partners and Energy Transfer.

     Onshore Gulf of Mexico. Our facilities in this region are located in South Texas and the Southeastern portions of the Texas Gulf Coast. We own a 100% interest in and are the operator of seven natural gas processing plants and the Spindletop gas storage facility in this region. In addition, we own a minority interest in one natural gas processing plant that is operated by another entity. Our plants have processing capacity net to our interest of 1.1 billion cubic feet of raw natural gas per day. During 2002, the plants in this region ran at an overall 80% capacity utilization rate.

     Our Spindletop natural gas storage facility is located near Beaumont, Texas and has current working natural gas capacity of 7.5 billion cubic feet, plus expansion potential of up to an additional ten billion cubic feet. We currently have approximately 3.75 billion cubic feet of the available storage capacity under lease with third parties with expiration terms out to July 2003. This high deliverability storage facility interconnects with 10 interstate and intrastate pipelines and is positioned to meet the hourly demand needs of the natural gas-fired electric generation marketplace, currently the fastest growing demand segment of the natural gas industry.

     To achieve growth in our Onshore Gulf of Mexico region, we intend to fully integrate our acquired assets and use the diversity of our current asset base to provide value-added services to our broad customer base. We will also seek additional opportunities to participate in the anticipated growth in supply from this region.

     Our key suppliers in this region include Apache Corporation, United Oil and Minerals and El Paso Production Company. Our principal competitors in this region include El Paso Field Services, Kinder Morgan and Houston Pipe Line Company.

     Rocky Mountains. Our facilities in this region are located in the DJ Basin of Northern Colorado, the Greater Green River Basin and Overthrust Belt areas of Southwest Wyoming and Northeast Utah. We own a 100% interest in and are the operator of nine natural gas processing plants in this region. Our plants have processing capacity of 475 million cubic feet of raw natural gas per day. During 2002, our plants in this region operated at an overall 70% capacity utilization rate.

     The Rocky Mountains region has well placed assets with strong competitive positions in areas that are expected to benefit from increased drilling activity, providing us with a platform for growth. In this region, we expect to achieve growth through our existing assets, strategic acquisitions and development of new facilities. In addition, we intend to pursue an opportunistic strategy in areas of the region where new technologies and recovery methods are being employed.

     Our key suppliers in the region include Patina Oil & Gas, BP, Kerr McGee and Anadarko Petroleum. Our principal competitors in this region include Kerr McGee, Williams Field Services and Western Gas Resources.

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     Offshore Gulf of Mexico. Our facilities in this region are located along the Gulf Coast areas of Louisiana, Mississippi and Alabama. We own an average 48% interest in and are the operator of two natural gas processing plants in this region. In addition, we own a 51% interest in one natural gas processing plant and minority interests in five other natural gas processing plants, all of which are operated by other entities. The plants have processing capacity net to our interest of 1.3 billion cubic feet of raw natural gas per day. During 2002, our plants in this region operated at an overall 49% capacity utilization rate. All of these plants straddle offshore pipeline systems delivering a lower NGL content gas stream than that of our onshore gathering systems.

     In addition, we own a 71.8% interest in Dauphin Island Gathering Partners (“Dauphin Island”), a partnership which owns and operates an offshore gathering and transmission system. Dauphin Island has attractive market outlets, including deliveries to Texas Eastern Transmission (“TETCO”), Gulfstream Natural Gas System, Transco, Gulf South, and Florida Gas Transmission for re-delivery to the Southeast, Mid-Atlantic, Northeast and New England natural gas markets. Dauphin Island’s leased capacity on TETCO’s pipeline provides us with a means to cross the Mississippi River to deliver or receive production from the Venice, Louisiana natural gas hub area. Further, the Main Pass Oil Gathering Company system, in which we own a 33.3% interest, also has access to a variety of shallow-water and deep-water oil production platforms and dual market outlets into Shell’s Delta terminal as well as Chevron-Texaco’s Cypress terminal.

     On May 31, 2002, we acquired 33.3% of the outstanding membership interests in Discovery Producer Services, LLC (“DPS”). The DPS assets, which were primarily constructed in 1997, extend from deepwater offshore Louisiana to onshore delivery points approximately 30 miles south of New Orleans. DPS owns and operates a 600 million cubic feet per day (MMcf/d) interstate pipeline, including a 30-inch mainline that extends to the edge of the outer continental shelf, a condensate handling facility, a 600 MMcf/d cryogenic gas processing plant, a 42,000 barrels per day fractionator, 400 MMcf/d of deepwater gathering laterals and a fixed-leg platform at Grand Isle 115 to host deepwater developments.

     We believe that the Offshore Gulf of Mexico production area will be one of the most active regions for new drilling in the United States. Our strategic plan for this region is to connect new facilities to our existing base so that we can realize new offshore development opportunities. Our existing assets in the eastern Gulf of Mexico are positioned to access new and ongoing production developments. Based on our broad range of assets in the region, we intend to capture incremental margins along the natural gas value chain.

     Our key suppliers in the Offshore Gulf of Mexico region include El Paso Production Company, ExxonMobil, Dominion Resources and AGIP. Our principal competitors in this region include BP Pipelines, Shell Gas Transmission, Williams Field Services and El Paso Field Services.

     Western Canada. We own interests in seven natural gas processing plants in Western Canada and operate six of these plants. These facilities are located in northeastern British Columbia, the Peace River Arch area of northwestern Alberta and the central foothills area of Alberta. In total, the facilities in this region have processing capacity net to our interest of 543 million cubic feet of raw sour natural gas per day. Over 900 miles of gathering systems and 100,000 horsepower of compression support these facilities. During 2002, our processing plants in this area operated at an overall 66% capacity utilization rate. Our processing facilities in this area are new, with the majority having been constructed since 1995. Our processing arrangements are primarily fee-based, providing an income stream that is not directly subject to fluctuations in commodity prices. Our foreign operations in Canada are subject to risks inherent in transactions involving foreign currencies.

     The Peace River Arch area continues to be an active drilling area with land widely held among several large and small producers. Multiple residue gas market outlets can be accessed from our facilities through connections to TransCanada’s NOVA system, the Westcoast system into British Columbia and the Alliance Pipeline.

     We believe that significant growth opportunities exist in this region. We anticipate that producers in this area may follow the lead of United States producers and divest their midstream assets over the next few years. We are positioned to capitalize on this fundamental shift in the Canadian natural gas processing industry and plan to expand our position in Alberta and British Columbia through additional acquisitions and greenfield projects.

     Our key suppliers in this region include Burlington Resources Canada Ltd., Canadian Natural Resources Ltd., Alberta Energy Company and Devon Energy Canada. Our principal competitors in the area include Gibson Gas Processing Ltd., BP Amoco, Petro Canada and Keyspan Energy.

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Natural Gas Liquids Transportation, Fractionation, Marketing and Trading

Overview

     We market our NGLs and provide marketing services to third party NGL producers and sales customers in significant NGL production and market centers in the United States. In 2002, we marketed and traded approximately 576,000 barrels per day of NGLs, of which approximately 63% was production for our own account, ranking us as one of the largest NGL marketers in the country.

     Our NGL services include plant tailgate purchases, transportation, fractionation, flexible pricing options, price risk management and product-in-kind agreements. Our primary NGL operations are located in close proximity to our gathering and processing assets in each of the regions in which we operate, other than Western Canada.

     In 2001, we acquired five propane rail terminals and constructed one in the northeastern United States, establishing us as a prominent wholesale purchaser and seller of propane in the Northeast. Marketing propane from these rail terminals, along with volume from TEPPCO’s Providence, Rhode Island import facility, accounts for approximately 23,000 barrels per day of wholesale business.

     We possess a large asset base of NGL fractionators and pipelines that are used to provide value-added services to our refining, chemical, industrial, retail and wholesale propane-marketing customers. We intend to capture premium value in local markets while maintaining a low cost structure by maximizing facility utilization at our 11 owned and operated fractionators, including two at the Mont Belvieu market center, and ten pipeline systems. Our current total fractionation capacity is approximately 177,000 barrels per day.

Strategy

     Our strategy is to utilize the size, scope and reliability of supply from our raw natural gas processing operations and apply our knowledge of NGL market dynamics to make additional investments in NGL infrastructure. Our interconnected natural gas processing operations provide us with an opportunity to capture fee-based investment opportunities in certain NGL assets, including pipelines, fractionators and terminals. In conjunction with this investment strategy and as an enhancement to the margin generation from our NGL assets, we also intend to focus on the following areas: producer services, local sales and fractionation, market hub fractionation, transportation and market center trading and storage, each of which is discussed briefly below.

     Customer Services. We plan to continue to expand our services to customers, including producers and end users, principally in the areas of price risk management and marketing of their products. Over the last several years, we have expanded our supply base significantly beyond our own equity production by providing a long term market for third party NGLs at competitive prices.

     Local Sales and Fractionation. We will seek opportunities to maximize the value of our product by continuing to expand local sales. We have fractionation capabilities at 11 of our owned and operated raw natural gas processing plants, and at two raw natural gas processing plants in which we own minority interests and which are operated by others. Our ability to fractionate NGLs at regional processing plants provides us with direct access to local NGL markets.

     Market Hub Fractionation. We will continue to focus on optimizing our product slate from our two Mont Belvieu, Texas market center fractionators, the Mont Belvieu I and Enterprise Products fractionators, where we have a combined owned capacity of 57,000 barrels per day. The control of products from these fractionators complements our market center trading activity.

     Transportation. We will seek additional opportunities to invest in NGL pipelines and secure favorable third party transportation arrangements. We use company owned NGL pipelines to transport approximately 49,500 barrels per day of our total NGL pipeline volumes, providing transportation to market center fractionation hubs or to end use markets. We also are a significant shipper on third party pipelines in the Rocky Mountains, East Texas, Mid-Continent and Permian Basin producing regions and, as a result, receive the benefit of incentive rates on many of our NGL shipments.

     Market Center Trading and Storage. We use trading and storage at the Mont Belvieu, Texas and Conway, Kansas NGL market centers to manage our price risk and provide additional services to our customers. We undertake these activities through the use of fixed forward sales, basis and spread trades, storage opportunities, put/call options, term contracts and spot market trading. We believe there are additional opportunities to grow our price risk management services with our customer base.

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     Wholesale Propane Marketing. We continue to expand our propane wholesale marketing activity into areas where asset infrastructure exists. We currently utilize rail, pipeline and waterborne import facility assets to transport propane to market. Propane wholesale marketing involves the purchase of propane from both our Natural Gas Segment and third party producers for delivery and sale to wholesale and end use customers. Additionally, we provide our wholesale customers price risk products such as fixed price and option contracts to mitigate the seasonal price fluctuations of propane.

Key Suppliers and Competition

     The marketing of NGLs is a highly competitive business that involves integrated oil and natural gas companies, midstream gathering and processing companies, trading houses, international liquid propane gas producers and refining and chemical companies. There is competition to source NGLs from plant operators for movement through pipeline networks and fractionation facilities as well as to supply large consumers such as multi-state propane, refining and chemical companies with their NGL needs. Our largest suppliers are our own processing plants and Oneok, Koch, ConocoPhillips and RME Petroleum Co. Our largest sales customers are Chevron Phillips Chemical Company, ConocoPhillips, Dow Hydrocarbons and Eastman Chemical which accounted for approximately 19%, 13%, 5%, and 3%, respectively, of our total NGL transportation, fractionation and marketing revenues in 2002. Our principal competitors in the marketing of NGLs are Enterprise Products, Koch, Dynegy and Louis Dreyfus. In 2002, we marketed and traded an average of approximately 576,000 barrels per day, or approximately 25% of the available domestic supply, which includes gas plant production, refinery plant production and imports.

TEPPCO

     On March 31, 2000, we obtained by transfer from Duke Energy, ownership of the general partner of TEPPCO, a publicly traded master limited partnership. TEPPCO operates in three principal areas:

• refined products, liquefied petroleum gases and petrochemicals transportation (Downstream Segment);

• crude oil gathering, transportation and marketing (Upstream Segment); and

• natural gas gathering, NGLs transportation and NGLs fractionation (Midstream Segment).

     TEPPCO’s Downstream Segment is one of the largest pipeline common carriers of refined petroleum products and liquefied petroleum gases in the United States. This system is comprised of an approximate 4,300 mile products pipeline system, extending from southeast Texas through central and midwest states to the northeast United States and is the only pipeline system that transports liquefied petroleum gases to the northeast United States from the Texas Gulf Coast. Its operations include the interstate transportation, storage and terminaling of petroleum products; short-haul shuttle transportation of liquefied petroleum gas at its Mont Belvieu, Texas complex; and other ancillary services. TEPPCO’s Downstream Segment owns and operates three petrochemical pipelines in Texas between Mont Belvieu and Port Arthur. As of February 10, 2003, TEPPCO’s Downstream Segment also owns a 50% interest in Centennial Pipeline LLC (“Centennial”). Marathon Ashland Petroleum LLC owns the other 50% interest. Centennial owns and operates an interstate refined petroleum products pipeline extending from the upper Texas Gulf Coast to Illinois.

     TEPPCO’s Upstream Segment owns and operates approximately 2,600 miles of crude oil trunk line and gathering pipelines, primarily in Texas and Oklahoma. It also owns a 50% interest in Seaway Crude Pipeline Company, or Seaway, which owns an approximately 500 mile, large diameter crude oil pipeline that transports primarily imported crude oil from the Texas Gulf Coast to the mid-continent and midwest refining sectors. ConocoPhillips owns the remaining interest in Seaway. In addition, TEPPCO’s Upstream Segment owns crude oil storage tanks at Cushing, Oklahoma and Midland, Texas, and interests in two crude oil pipelines operating in New Mexico, Oklahoma and Texas.

     TEPPCO’s Midstream Segment owns and operates approximately 650 miles of NGLs pipelines located along the Texas Gulf Coast and two fractionators in Colorado. In September 2001, TEPPCO’s Midstream Segment acquired Jonah Gas Gathering Company, which gathers natural gas in the Green River Basin in southwestern Wyoming. The Jonah natural gas gathering system consists of approximately 350 miles of pipelines. Natural gas gathered on the Jonah system is delivered to several interstate pipeline systems that provide access to a number of West Coast, Rocky Mountain and midwest markets. On March 1, 2002, TEPPCO’s Midstream Segment expanded its NGLs operations with the acquisition of the Chaparral and Quanah pipelines, which consist of a combined 970 miles of gathering and trunk pipelines extending from southeastern New Mexico and West Texas to Mont Belvieu, Texas. On June 30, 2002, TEPPCO’s Midstream Segment acquired the Val Verde coal seam gas gathering system from a subsidiary of Burlington Resources Inc. The Val Verde gathering system consists of 360 miles of pipeline, 14 compressor stations and a large amine treating facility for

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the removal of carbon dioxide. The system has a pipeline capacity of approximately one billion cubic feet of gas per day. The Val Verde gathering system gathers coal seam gas from the Fruitland Coal Formation of the San Juan Basin in New Mexico. The system is one of the largest coal seam gas gathering and treating facilities in the United States. Certain of the assets of TEPPCO’s Midstream Segment are operated and commercially managed by us under agreements with TEPPCO.

     We believe that our ownership of the general partnership interest of TEPPCO improves our business position in the gathering and transportation sector of the midstream natural gas industry and provides us additional flexibility in pursuing our disciplined acquisition strategy by providing an alternative acquisition vehicle.

     The general partner of TEPPCO manages and directs TEPPCO under the TEPPCO partnership agreement and the partnership agreements of its operating partnerships. Under these partnership agreements, the general partner of TEPPCO is reimbursed for all direct and indirect expenses it incurs and payments it makes on behalf of TEPPCO.

     TEPPCO makes quarterly cash distributions of its available cash, which consists generally of all cash receipts less disbursements and cash reserves necessary for working capital, anticipated capital expenditures and contingencies and debt payments, the amounts of which are determined by the general partner of TEPPCO.

     The partnership agreements provide for incentive distributions payable to the general partner of TEPPCO out of TEPPCO’s available cash in the event quarterly distributions to its unitholders exceed certain specified targets. In general, subject to certain limitations, if a quarterly distribution exceeds a target of $.275 per limited partner unit, the general partner of TEPPCO will receive incentive distributions equal to:

• 15% of that portion of the distribution per limited partner unit which exceeds the minimum quarterly distribution amount of $.275 but is not more than $.325, plus

• 25% of that portion of the quarterly distribution per limited partner unit which exceeds $.325 but is not more than $.45, plus

• 50% of that portion of the quarterly distribution per limited partner unit which exceeds $.45.

     At TEPPCO’s 2002 per unit distribution level, the general partner received approximately 25% of the cash distributed by TEPPCO to its partners, which consisted of 23% from the incentive cash distribution and 2% from the general partner interest. During 2002, total cash distributions to the general partner of TEPPCO were $37.7 million. Also during 2002, equity contributions of $7.6 million were paid by the general partner to TEPPCO.

Natural Gas Suppliers

     We purchase substantially all of our raw natural gas from producers under varying term contracts. Typically, we take ownership of raw natural gas at the wellhead, settling payments with producers on terms set forth in the applicable contracts. These producers range in size from small independent owners and operators to large integrated oil companies, such as ConocoPhillips, our largest single supplier. No single producer accounted for more than 10% of our natural gas throughput in 2002. Each producer often dedicates to us the raw natural gas produced from designated oil and natural gas leases for a specific term. The term for dedicated gas can range from 30 days to life of lease. We consider our relationships with our many producers to be good. For a description of the types of contracts we have entered into with our suppliers, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview — Effects of Our Raw Natural Gas Supply Arrangements.”

Competition

     We face strong competition in acquiring raw natural gas supplies. Our competitors in obtaining additional gas supplies and in gathering and processing raw natural gas include:

• major integrated oil companies;

• major interstate and intrastate pipelines or their affiliates;

• independent oil and gas producers;

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• other large raw natural gas gatherers that gather, process and market natural gas and/or NGLs; and

• a relatively large number of smaller raw natural gas gatherers of varying financial resources and experience.

     Competition for raw natural gas supplies is concentrated in geographic regions based upon the location of gathering systems and processing plants. Although we are one of the largest gatherers and processors in most of the geographic regions in which we operate, most producers in these areas have alternate gathering and processing facilities available to them. In addition, producers have other alternatives, such as building their own gathering facilities or in some cases selling their raw natural gas supplies without processing. Competition for raw natural gas supplies in these regions is primarily based on:

• the reputation, efficiency and reliability of the gatherer/processor, including the operating pressure of the gathering system;

• the availability of gathering and transportation;

• the pricing arrangement offered by the gatherer/processor; and

• the ability of the gatherer/processor to obtain a satisfactory price for the producers’ residue gas and extracted NGLs.

     In addition to competition in raw natural gas gathering and processing, there is vigorous competition in the marketing of residue gas. Competition for customers is based primarily upon the price of the delivered gas, the services offered by the seller, and the reliability of the seller in making deliveries. Residue gas also competes on a price basis with alternative fuels such as oil and coal, especially for customers that have the capability of using these alternative fuels and on the basis of local environmental considerations. Also, to foster competition in the natural gas industry, certain regulatory actions of the Federal Energy Regulatory Commission (“FERC”) and some states have allowed buying and selling to occur at more points along transmission and distribution systems.

     Competition in the NGLs marketing area comes from other midstream NGL marketing companies, international producers/traders, chemical companies, refineries and other asset owners. Along with numerous marketing competitors, we offer price risk management and other services. We believe it is important that we tailor our services to the end-use customer to remain competitive.

Regulation

     Transportation. Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978, and the regulations promulgated thereunder by the FERC. In the past, the federal government regulated the prices at which natural gas could be sold. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all Natural Gas Act and Natural Gas Policy Act price and non-price controls affecting wellhead sales of natural gas. Congress could, however, reenact field natural gas price controls in the future, though we know of no current initiative to do so.

     As a gatherer, processor and marketer of raw natural gas, we depend on the natural gas transportation and storage services offered by various interstate and intrastate pipeline companies to enable the delivery and sale of our residue gas supplies. In accordance with methods required by the FERC for allocating the system capacity of “open access” interstate pipelines, at times other system users can preempt the availability of interstate natural gas transportation and storage service necessary to enable us to make deliveries and sales of residue gas. Moreover, shippers and pipelines may negotiate the rates charged by pipelines for such services within certain allowed parameters. These rates will also periodically vary depending upon individual system usage and other factors. An inability to obtain transportation and storage services at competitive rates can hinder, in some instances, our processing and marketing operations and affect our sales margins.

     The intrastate pipelines that we own are subject to state regulation and, to the extent they provide interstate services under Section 311 of the Natural Gas Policy Act of 1978, also are subject to FERC regulation. Dauphin Island owns and operates a natural gas gathering system and interstate transmission system located in offshore waters south of Louisiana and Alabama. The offshore gathering system does not provide jurisdictional service under the Natural Gas Act; the interstate offshore transmission system is regulated by the FERC.

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     Commencing in April 1992 the FERC issued Order No. 636 and a series of related orders that require interstate pipelines to provide open-access transportation on a basis that is equal for users of the pipeline services. The FERC has stated that it intends for Order No. 636 to foster increased competition within all phases of the natural gas industry. Order No. 636 applies to our activities in Dauphin Island. The courts have largely affirmed the significant features of Order No. 636 and the numerous related orders pertaining to individual pipelines, although certain appeals remain pending and the FERC continues to review and modify its regulations. For example, the FERC issued Order No. 637 in February 2000 which, among other things:

• permits pipelines to charge different maximum cost-based rates for peak and off-peak periods;

• encourages, but does not mandate, auctions for pipeline capacity;

• requires pipelines to implement imbalance management services;

• restricts the ability of pipelines to impose penalties for imbalances, overruns and non-compliance with operational flow orders; and

• implements a number of new pipeline reporting requirements.

     Order No. 637 also requires the FERC to analyze whether it should implement additional fundamental policy changes, including, among other things, whether to pursue performance-based ratemaking or other non-cost based ratemaking techniques and whether the FERC should mandate greater standardization in terms and conditions of service across the interstate pipeline grid. In addition, the FERC implemented regulations governing the procedure for obtaining authorization to construct new pipeline facilities and has issued a policy statement, which it largely affirmed in a recent order on rehearing, establishing a presumption in favor of requiring owners of new pipeline facilities to charge rates based solely on the costs associated with such new pipeline facilities. We cannot predict what further action the FERC will take on these matters. However, we do not believe that we will be affected by any action taken previously or in the future on these matters materially differently than other natural gas gatherers, transporters, processors and marketers with which we compete.

     Some of our interstate natural gas pipelines are subject to the regulations of the U.S. Department of Transportation (“DOT”) concerning pipeline safety. The DOT is developing regulations that will require pipelines to implement integrity management programs, including more frequent inspections and other safety protections in areas where the consequences of potential pipeline accidents pose the greatest risk to people and their property. The Pipeline Safety Improvement Act of 2002, which was enacted on December 17, 2002, establishes mandatory inspections of high-consequence areas for all U.S. oil and natural gas pipelines within 10 years. At this time we cannot estimate the expected cost of complying with these regulations.

     Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC and the courts. The natural gas industry historically has been heavily regulated; therefore, there is no assurance that the less stringent and pro-competition regulatory approach recently pursued by the FERC and Congress will continue.

     Gathering. The Natural Gas Act exempts natural gas gathering facilities from FERC jurisdiction. Interstate natural gas transmission facilities, on the other hand, remain subject to FERC jurisdiction. The FERC has historically distinguished between these two types of facilities on a fact-specific basis. We believe that our gathering facilities and operations meet the current tests that the FERC uses to grant non-jurisdictional gathering facility status. However, there is no assurance that the FERC will not modify such tests or that all of our facilities will remain classified as natural gas gathering facilities.

     Some states in which we own gathering facilities have adopted laws and regulations that require gatherers either to purchase without undue discrimination as to source or supplier or to take ratably, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. For example, the states of Oklahoma and Kansas have adopted complaint-based statutes that allow the Oklahoma Corporation Commission and the Kansas Corporation Commission, respectively, to remedy discriminatory rates for providing gathering service where the parties are unable to agree. In a similar way, the Railroad Commission of Texas sponsors a complaint procedure for resolving grievances about natural gas gathering access and rate discrimination.

     In April 2000, the FERC issued Order No. 639, requiring that virtually all non-proprietary pipeline gatherers of natural gas on the outer-continental shelf report information on their affiliations, rates and conditions of service. Among the FERC’s purposes in issuing these rules was the desire to provide shippers on the outer-continental shelf with greater assurance of open-access services on pipelines located on the outer-continental shelf and non-discriminatory rates and conditions of service on these pipelines. The FERC

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exempted Natural Gas Act-regulated pipelines, like that owned and operated by Dauphin Island, from the new reporting requirements, reasoning that the information that these pipelines were already reporting was sufficient to monitor conformity with existing non-discrimination mandates. The Company and others challenged the rule, and on January 11, 2002, the U.S. District Court for the District of Columbia issued a summary judgment in favor of the Company and the other plaintiffs, and a permanent injunction against the FERC prohibiting enforcement of Order No. 639. On February 20, 2002, FERC filed its notice of appeal to the D.C. Circuit Court of Appeals. A ruling in favor of the FERC could increase our cost of regulatory compliance and place us at a disadvantage in comparison to companies that are not required to satisfy the reporting requirements. Order No. 639 may be altered on appeal, and it is not known at this time what effect these new rules, as they may be altered, will have on our business. We currently believe that Order No. 639 and the related reporting requirements will not have a material adverse effect on our existing business activities.

     Processing. The primary functions of our natural gas processing plants are the extraction of NGLs and the conditioning of natural gas for marketing. The FERC has traditionally maintained that a processing plant that primarily extracts NGLs is not a facility for transportation or sale of natural gas for resale in interstate commerce and therefore is not subject to its jurisdiction under the Natural Gas Act. We believe that our natural gas processing plants are primarily involved in removing NGLs and, therefore, are exempt from FERC jurisdiction.

     Transportation and Sales of Natural Gas Liquids. We have non-operating interests in two pipelines that transport NGLs in interstate commerce. The rates, terms and conditions of service on these pipelines are subject to regulation by the FERC under the Interstate Commerce Act. The Interstate Commerce Act requires, among other things, that petroleum products (including NGLs) pipeline rates be just and reasonable and non-discriminatory. The FERC allows petroleum pipeline rates to be set on at least three bases, including historic cost, historic cost plus an index or market factors.

     Sales of Natural Gas Liquids. Our sales of NGLs are not currently regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such NGLs is dependent on liquids pipelines whose rates, terms and conditions of service are subject to the Interstate Commerce Act. Although certain regulations implemented by the FERC in recent years could result in an increase in the cost of transporting NGLs on certain pipelines, we do not believe that these regulations affect us any differently than other marketers of NGLs with whom we compete.

     U.S. Department of Transportation. Some of our pipelines are subject to regulation by the DOT with respect to their design, installation, testing, construction, operation, replacement and management. Comparable regulations exist in some states where we do business. These regulations provide for safe pipeline operations and include potential fines and penalties for violations.

     Safety and Health. Certain federal statutes impose significant liability upon the owner or operator of natural gas pipeline facilities for failure to meet certain safety standards. The most significant of these is the Natural Gas Pipeline Safety Act, which regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities. In addition, we are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act and comparable state statutes, whose purpose is to maintain the safety of workers, both generally and within the pipeline industry. We have an internal program of inspection designed to monitor and enforce compliance with pipeline and worker safety requirements.

     Canadian Regulation. Our Canadian assets in the province of Alberta are regulated by the Alberta Energy and Utilities Board. Our West Doe natural gas gathering pipeline, which crosses the Alberta/British Columbia border, falls under the jurisdiction of the National Energy Board of Canada and is classified as a Group 2 company, which is regulated on a complaint only basis by the National Energy Board.

Environmental Matters

     The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with United States and Canadian laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. Environmental regulations and laws affecting us include:

• The Clean Air Act and the 1990 amendments to the Act, as well as counterpart state laws and regulations affecting emissions to the air, that impose responsibilities on the owners and/or operators of air emissions sources including obtaining permits and annual compliance and reporting obligations;

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• The Federal Water Pollution Control Act and other amendments, which require permits for facilities that discharge treated wastewater or other materials into waters of the United States;

• Federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act and its amendments, which regulate the management, treatment, and disposal of solid and hazardous wastes, and state programs addressing parallel state issues;

• The Comprehensive Environmental Response, Compensation, and Liability Act and its amendments, which may impose liability, regardless of fault, for historic or future disposal or releases of hazardous substances into the environment, including cleanup obligations associated with such releases or discharges;

• State regulations for the reporting, assessment and remediation of releases of material to the environment, including historic releases of hydrocarbon liquids; and

• Canadian Environmental Laws.

     Costs of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits which can include the assessment of monetary penalties, the imposition of remedial requirements, the issuance of injunctions or restrictions on operation.

     For further discussion of our environmental matters, including possible liability and capital costs, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Environmental Considerations” and Note 2, “Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements.

Employees

     As of December 31, 2002, we had approximately 3,800 employees, which includes approximately 970 employees of our wholly-owned subsidiary Texas Eastern Products Pipeline Company, LLC, the general partner of TEPPCO. We are a party to one collective bargaining agreement which covers approximately 65 of our employees. We believe our relations with our employees are good.

ITEM 2. Properties.

     For information regarding the Company’s properties, see “Item 1. Business - - Natural Gas Gathering, Processing, Transportation, Marketing and Storage,” and “Natural Gas Liquids Transportation, Fractionation and Marketing,” and “TEPPCO” in this section, each of which is incorporated herein by reference.

ITEM 3. Legal Proceedings.

     See Note 14, “Commitments and Contingent Liabilities,” of the Notes to Consolidated Financial Statements for discussion of the Company’s legal proceedings which is incorporated herein by reference.

     Management believes that the resolution of the matters discussed will not have a material adverse effect on the consolidated results of operations or the financial position of the Company.

     In addition to the foregoing, from time to time, we are named as parties in legal proceedings arising in the ordinary course of our business. We believe we have meritorious defenses to all of these lawsuits and legal proceedings and will vigorously defend against them. Based on our evaluation of pending matters and after consideration of reserves established, we believe that the resolution of these proceedings will not have a material adverse effect on our business, financial position or results of operations.

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

     No matters were submitted to a vote of the Company’s members during the last quarter of 2002.

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PART II.

ITEM 5. Market for Registrant’s Common Equity and Related Stockholder Matters.

     Duke Energy beneficially owns 69.7% of our outstanding member interests and ConocoPhillips beneficially owns the remaining 30.3%. There is no market for our member interests. Unless otherwise approved by our board of directors, we are prohibited from making any distributions except in an amount sufficient to pay certain tax obligations of our members that arise from their ownership of member interests.

     In August 2000, we issued $300.0 million of preferred members interests to affiliates of Duke Energy and ConocoPhillips in proportion to their ownership interests. The proceeds from this financing were used to repay a portion of our outstanding commercial paper. The preferred member interests are entitled to cumulative preferential distributions of 9.5% per annum payable, unless deferred, semiannually. We have the right to defer payments of preferential distributions on the preferred member interests, other than certain tax distributions, at any time and from time to time, for up to 10 consecutive semiannual periods. Deferred preferred distributions will accrue additional amounts based on the preferential distribution rate (plus 0.5% per annum) to the date of payment. The preferred member interests, together with all accrued and unpaid preferential distributions, must be redeemed and paid on the earlier of the thirtieth anniversary date of issuance or consummation of an initial public offering of the Company’s equity securities. At December 31, 2002 there were no outstanding preferred distributions.

     On September 9, 2002, we redeemed $100.0 million of our preferred members’ interest by paying cash to each of our members (Duke Energy and ConocoPhillips) in proportion to their ownership interests.

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ITEM 6. Selected Financial Data.

     The following table sets forth selected historical consolidated financial and other data for the Company and the Predecessor Company. The selected historical Annual Income Statement Data, Cash Flow Data and Balance Sheet Data as of December 31, 2002, 2001 and 2000 and for the periods then ended have been derived from the audited consolidated financial statements of the Company. The selected historical combined financial data as of December 31, 1999 and 1998 and for the periods then ended have been derived from the Predecessor Company’s audited historical financial statements.

     The data should be read in conjunction with the financial statements and related notes and other financial information appearing elsewhere in this Form 10-K.

			2002			2001			2000(1)			1999(2)		1998
			(In thousands)
Annual Income Statement Data:
Operating revenues:
	Sales of natural gas and petroleum products		$	5,185,728		$	7,695,080		$	5,983,473		$	2,105,961	$	175,947
	Transportation, storage and processing			291,431			281,744			199,851			148,050		115,187
	Trading and marketing net margin			14,397			47,870			15,100			15,368		8,232
		Total operating revenues		5,491,556			8,024,694			6,198,424			2,269,379		299,366
Costs and expenses:
	Natural gas and petroleum products			4,440,371			6,740,894			4,980,476			1,776,366		53,175
	Operating and maintenance			449,318			373,477			331,572			181,392		113,556
	Depreciation and amortization			298,953			278,930			234,862			130,788		75,573
	General and administrative			167,115			129,968			171,154			73,685		44,946
	Asset impairments			40,440			—			—			—		—
	Net loss (gain) on sale of assets			4,256			(1,277	)		(10,660	)		2,377		(33,759	)
		Total costs and expenses		5,400,453			7,521,992			5,707,404			2,164,608		253,491
Operating income				91,103			502,702			491,020			104,771		45,875
Equity in earnings of unconsolidated affiliates				38,196			30,069			27,424			22,502		11,845
Interest expense				165,841			165,670			149,220			52,915		52,403
(Loss) income before income taxes and cumulative effect of accounting change				(36,542	)		367,101			369,224			74,358		5,317
Income tax expense (benefit)				10,009			2,783			(310,937	)		31,029		3,289
Net (loss) income before cumulative effect of accounting change				(46,551	)		364,318			680,161			43,329		2,028
Cumulative effect of accounting change				—			411			—			—		—
Net (loss) income			$	(46,551	)	$	363,907		$	680,161		$	43,329	$	2,028

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	2002			2001			2000(1)			1999(2)			1998
	(In thousands, except ratios and per unit data)
Balance Sheet Data (end of period):
Total assets	$	6,580,435		$	6,630,209		$	6,527,997		$	3,482,296		$	1,770,838
Long term debt	$	2,255,508		$	2,235,034		$	1,688,157		$	101,600		$	101,600
Preferred members’ interest	$	200,000		$	300,000		$	300,000		$	—		$	—
Members’ equity	$	2,450,563		$	2,653,042		$	2,420,835			(8	)		(8	)
Cash Flow Data:
Cash flow from operations	$	431,075		$	450,463		$	713,072		$	173,136		$	40,409
Cash flow from investing activities		(236,860	)		(538,587	)		(234,848	)		(1,571,446	)		(203,625	)
Cash flow from financing activities		(191,617	)		84,981			(477,578	)		1,398,934			162,514
Other Data:
Acquisitions and other capital expenditures	$	301,631		$	597,370		$	371,063		$	1,570,083		$	185,479
EBITDA(3)	$	428,252		$	811,701		$	753,306		$	258,061		$	133,293
Ratio of EBITDA to interest expense(4)		2.58			4.90			5.05			4.88			2.54
Ratio of earnings to fixed charges(5)		0.85			3.17			3.43			2.33			1.07
Gas transported and/or processed (TBtu/d)		8.3			8.6			7.6			5.1			3.6
NGLs production (MBbl/d)		392			397			359			192			110
Market Data:
Average NGLs price per gallon(6)	$	.38		$	.45		$	.53		$	.34		$	.26
Average natural gas price per MMBtu(7)	$	3.22		$	4.27		$	3.89		$	2.27		$	2.11

(1)	Includes the results of operations of ConocoPhillips’ gas gathering, processing, marketing and NGL business for the nine months ended December 31, 2000. To the extent that it existed at the time, ConocoPhillips’ gas gathering, processing, marketing and NGL business was acquired by the Predecessor Company on March 31, 2000.
(2)	Includes the results of operations of Union Pacific Fuels for the nine months ended December 31, 1999. Union Pacific Fuels was acquired by the Predecessor Company on March 31, 1999.
(3)	EBITDA consists of income from continuing operations before interest expense, income tax expense, and depreciation and amortization expense. EBITDA is not a measurement presented in accordance with generally accepted accounting principles. You should not consider this measure in isolation from or as a substitute for net income or cash flow measures prepared in accordance with generally accepted accounting principles or as a measure of our profitability or liquidity. EBITDA is included as a supplemental disclosure because it may provide useful information regarding our ability to service debt and to fund capital expenditures. However, not all EBITDA may be available to service debt. This measure may not be comparable to similarly titled measures reported by other companies.
(4)	The ratio of EBITDA to interest expense represents a ratio that provides an investor with information as to our company’s current ability to meet our financing costs.
(5)	The ratios of earnings to fixed charges are computed utilizing the Securities and Exchange Commission (“SEC”) guidelines. As a result of losses, earnings were insufficient to cover fixed charges by $25.6 million for the year ended December 31, 2002.
(6)	Based on index prices from the Mont Belvieu and Conway market hubs that are weighted by our component and location mix for the periods indicated.
(7)	Based on the NYMEX Henry Hub prices for the periods indicated.
(8)	Not applicable due to change in corporate structure as of March 31, 2000.

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

     Duke Energy Field Services, LLC holds the combined North American midstream natural gas gathering, processing, marketing and NGL business of Duke Energy and ConocoPhillips that existed at the time of the Combination.

     On March 31, 2000, we combined the gas gathering, processing, marketing and NGLs businesses of Duke Energy and ConocoPhillips. In connection with the Combination, Duke Energy and ConocoPhillips transferred all of their then existing respective interests in their subsidiaries that conducted their midstream natural gas business to us. In connection with the Combination, Duke Energy and ConocoPhillips also transferred to us additional midstream natural gas assets acquired by Duke Energy or ConocoPhillips prior to consummation of the Combination, including the Mid-Continent gathering and processing assets of Conoco and Mitchell Energy. Concurrently with the Combination, we obtained by transfer from Duke Energy the general partner of TEPPCO. In exchange for the asset contribution, ConocoPhillips received 30.3% of the member interests in our company, with Duke Energy holding the remaining 69.7% of the outstanding member interests in our company. In connection with the closing of the Combination, we borrowed approximately $2.8 billion in the commercial paper market and made one-time cash distributions (including reimbursements for acquisitions) of approximately $1.5 billion to Duke Energy and approximately $1.2 billion to ConocoPhillips. This debt was subsequently refinanced through the issuance of unsecured senior debt securities. See “Liquidity and Capital Resources.”

     The Combination was accounted for as a purchase business combination in accordance with Accounting Principles Board Opinion (APB) No. 16, “Accounting for Business Combinations.” The Predecessor Company was the acquirer of ConocoPhillips’ midstream natural gas business in the Combination.

     The following discussion details the material factors that affected our historical financial condition and results of operations in 2002, 2001 and 2000. This discussion should be read in conjunction with “Item 1. Business,” and the consolidated financial statements with the related notes, included elsewhere in this Form 10-K.

     From a financial reporting perspective, we are the successor to Duke Energy’s North American midstream natural gas business that existed at the time of the Combination. The subsidiaries of Duke Energy that conducted this business were contributed to us immediately prior to the Combination. For periods prior to the Combination, Duke Energy Field Services and these subsidiaries of Duke Energy are collectively referred to herein as the “Predecessor Company.”

     Unless the context otherwise requires, the discussion of our business contained in this section for periods ending on or prior to March 31, 2000 relates solely to the Predecessor Company on a historical basis and does not give effect to the Combination, the transfer to our company of additional midstream natural gas assets acquired by Duke Energy or ConocoPhillips prior to consummation of the Combination or the transfer to our company of the general partner of TEPPCO from Duke Energy.

Overview

     We operate in the two principal business segments of the midstream natural gas industry:

• Natural gas gathering, processing, transportation and storage, from which we generate revenues primarily by providing services such as compression, gathering, treating, processing, transportation of residue gas, storage and trading and marketing (the “Natural Gas Segment”). In 2002, approximately 80% of the Company’s operating revenues prior to intersegment revenue elimination and approximately 95% of the Company’s gross margin were derived from this segment.

• NGLs fractionation, transportation, marketing and trading, from which we generate revenues from transportation fees, market center fractionation and the marketing and trading of NGLs (the “NGLs Segment”). In 2002, approximately 20% of the Company’s operating revenues prior to intersegment revenue elimination and approximately 5% of the Company’s gross margin were derived from this segment.

     Our limited liability company agreement limits the scope of our business to the midstream natural gas industry in the United States and Canada, the marketing of NGLs in Mexico and the transportation, marketing and storage of other petroleum products, unless otherwise approved by our board of directors. This limitation in scope is not currently expected to materially impact the results of our operations.

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Effects of Commodity Prices

     The Company is exposed to commodity prices as a result of being paid for certain services in the form of commodities rather than cash. For gathering services, the Company receives fees or commodities from the producers to bring the raw natural gas from the well head to the processing plant. For processing services, the Company either receives fees or commodities as payment for these services, depending on the types of contract which are described below. Based on the Company’s current contract mix, the Company has a long NGL position and is sensitive to changes in NGL prices. The Company also has a short gas position, however, the short gas position is less significant than the long NGL position.

     During the three years ended December 31, 2002, approximately 75% of our gross margin was generated by commodity sensitive arrangements and approximately 25% of our gross margin was generated by fee-based arrangements. The commodity exposure is actively managed by the Company as discussed below.

     The midstream natural gas industry is cyclical, with the operating results of companies in the industry significantly affected by the prevailing price of NGLs, which in turn has been generally correlated to the price of crude oil. Although the prevailing price of natural gas has less short term significance to our operating results than the price of NGLs, in the long term, the growth of our business depends on natural gas prices being at levels sufficient to provide incentives and capital for producers to increase natural gas exploration and production. In the past, the prices of NGLs and natural gas have been extremely volatile.

     We generally expect NGL prices to follow changes in crude oil prices over the long term, which we believe will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy. However, the relationship or correlation between crude oil value and NGL prices declined significantly during 2001 and 2002. In late 2002, this relationship strengthened moving back toward historical trends.

     We believe that future natural gas prices will be influenced by supply deliverability, the severity of winter and summer weather and the level of United States economic growth. The price increases in crude oil, NGLs and natural gas experienced during 2000 and first half of 2001 spurred increased natural gas drilling activity. However, a decline in commodity prices in late 2001, continuing into 2002, negatively affected drilling activity. The average number of active rigs drilling in North America declined to 1,204 at December 31, 2002 from 1,282 at December 31, 2001. Recent significant increases in natural gas prices could result in increased drilling activity in 2003. However, energy market uncertainty could negatively impact North American drilling activity in the short term. Lower drilling levels over a sustained period would have a negative effect on natural gas volumes gathered and processed.

     To better address the risks associated with volatile commodity prices, we employ a comprehensive commodity price risk management program. We closely monitor the risks associated with these commodity price changes on our future operations and, where appropriate, use various commodity instruments such as natural gas, crude oil and NGL contracts to hedge the value of our assets and operations from such price risks. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.” Our 2002 and 2001 results of operations include a hedging loss of $27.1 million and a gain of $6.0 million, respectively.

Effects of Our Raw Natural Gas Supply Arrangements

     Our results are affected by the types of arrangements we use to process raw natural gas. We obtain access to raw natural gas and provide our midstream natural gas services principally under three types of processing contracts:

• Percentage-of-Proceeds Contracts — Under these contracts we receive as our fee a negotiated percentage of the residue natural gas and NGLs value derived from our gathering and processing activities, with the producer retaining the remainder of the value or product. These type of contracts permit us and the producers to share proportionately in price changes. Under these contracts, we share in both the increases and decreases in natural gas prices and NGL prices. During 2002 approximately 55% of our gross margin from the Natural Gas Segment was generated from percentage-of-proceeds contracts.

• Fee-Based Contracts — Under these contracts we receive a set fee for gathering, processing and/or treating raw natural gas. Our revenue stream from these contracts is correlated with our level of gathering and processing activity and is not directly dependent on commodity prices. During 2002, approximately 25% of our gross margin from the Natural Gas Segment was generated from fee-based contracts including our general partnership interest in TEPPCO.

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• Keep-Whole and Wellhead Purchase Contracts — Under the terms of a wellhead purchase contract, we purchase raw natural gas from the producer at the wellhead or defined receipt point for processing and then market the resulting NGLs and residue gas at market prices. Under the terms of a keep-whole processing contract, we gather raw natural gas from the producer for processing and then we market the NGLs and return to the producer residue natural gas with a Btu content equivalent to the Btu content of the raw natural gas gathered. This arrangement keeps the producer whole to the thermal value of the raw natural gas we received. Under these types of contracts the Company is exposed to the frac spread. The frac spread is the difference between the value of the NGLs extracted from processing and the value of the Btu equivalent of the residue natural gas. We benefit in periods when NGL prices are higher relative to natural gas prices. During 2002, approximately 10% of our gross margin from the Natural Gas Segment was generated from wellhead and keep-whole contracts.

• In addition, during 2002 approximately 10% of the gross margin from the Natural Gas Segment was generated from sales of condensate, which is low grade crude oil that is produced in association with natural gas.

     Our current mix of percentage-of-proceeds contracts (where we are exposed to decreases in natural gas prices) and keep-whole and wellhead purchase contracts (where we are exposed to increases in natural gas prices) helps to mitigate our exposure to changes in natural gas prices. Our exposure to decreases in NGL prices is partially offset by our hedging program. Our hedging program reduces the potential negative impact that commodity price changes could have on our earnings and improves our ability to adequately plan for cash needed for debt service, dividends and capital expenditures. The primary goals of our hedging program include maintaining minimum cash flows to fund debt service, dividends, production replacement and maintenance capital projects; avoiding disruption of our growth capital and value creation process; and retaining a high percentage of potential upside relating to price increases of NGLs.

Accounting Adjustments

     The Company has completed a comprehensive account reconciliation project to review and analyze its balance sheet accounts. As a result of this account reconciliation project, the Company recorded approximately $53.0 million of adjustments that may be related to corrections of accounting errors in prior periods. The $53.0 million reduced Gross Margin, as defined under “Results of Operations” below, by $32.8 million, increased costs and expenses by $16.0 million, increased depreciation by $2.3 million, increased other costs and expenses by $4.1 million and reduced interest expense by $2.2 million. Numerous items identified in the account reconciliation project resulted from system conversions and otherwise unsupportable balance sheet amounts. Due to the nature of certain of these account reconciliation adjustments, it would be impractical to determine what periods such adjustments relate to. Management has determined that the charges related to error corrections are immaterial both individually and in the aggregate on both a quantitative and qualitative basis to the trends in the financial statements for the periods presented, the prior periods affected and to a fair presentation of the Company’s financial statements.

     See Note 19 to the Consolidated Financial Statements included elsewhere in this Form 10-K and Item 14. Controls and Procedures.

Other Factors That Have Significantly Affected Our Results

     Our results of operations are impacted by increases and decreases in the volume of raw natural gas that we handle through our system, which we refer to as throughput volume, and the percentage of capacity at which our processing facilities operate, which we refer to as our capacity utilization rate. Throughput volumes and capacity utilization rates generally are driven by well head production and our competitive position on a regional basis and more broadly by demand for residue natural gas and NGLs.

     Risk management activities have also affected our results of operations. Our 2002, 2001 and 2000 results of operations include a hedging loss of $27.1 million, a gain of $6.0 million, and a loss of $127.7 million respectively. See “Item 7A. Quantitative and Qualitative Disclosure About Market Risk.”

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Results of Operations

     The following is a discussion of our historical results of operations. The discussion for periods ending on or prior to the Combination on March 31, 2000 relates solely to the Predecessor Company and does not give effect to the Combination, the transfer to our company of additional midstream natural gas assets acquired by Duke Energy or ConocoPhillips prior to consummation of the Combination or the transfer to our company of the general partner of TEPPCO from Duke Energy.

			2002		2001		2000
			(In thousands)
Operating revenues:
	Sales of natural gas and petroleum products		$	5,185,728	$	7,695,080	$	5,983,473
	Transportation, storage and processing			291,431		281,744		199,851
	Trading and marketing net margin			14,397		47,870		15,100
		Total operating revenues		5,491,556		8,024,694		6,198,424
	Purchases of natural gas and petroleum products			4,440,371		6,740,894		4,980,476
Gross margin				1,051,185		1,283,800		1,217,948
Equity earnings of unconsolidated affiliates				38,196		30,069		27,424
Total gross margin and equity earnings of unconsolidated affiliates (1)			$	1,089,381	$	1,313,869	$	1,245,372

(1) Gross margin and equity in earnings (“Gross Margin”) consists of income from continuing operations before operating and general and administrative expense, interest expense, income tax expense, and depreciation and amortization expense. Gross margin as defined is not a measurement presented in accordance with generally accepted accounting principles. You should not consider this measure in isolation from or as a substitute for net income or cash flow measures prepared in accordance with generally accepted accounting principles or as an isolated measure of our profitability or liquidity. Gross margin is included as a supplemental disclosure because it may provide useful information regarding the impact of key drivers such as commodity prices and supply contract mix on the Company’s earnings.

2002 compared with 2001

     Gross Margin. Gross Margin decreased $224.5 million, or 17% to $1,089.4 million from $1,313.9 million in 2001. This decrease was primarily the result of lower NGL prices of approximately $199.0 million (including hedging) due to a $.07 per gallon decrease in average NGL prices and volume declines. These decreases were partially offset by approximately $44.0 million due to a $1.05 per million Btu decrease in natural gas prices. Average prices for 2002 were $.38 per gallon for NGLs and $3.22 per million Btu for natural gas, respectively, as compared with $.45 per gallon and $4.27 per million Btu during 2001. NGL and natural gas trading contributed another $8.7 million, and $24.8 million to the Gross Margin decrease, respectively. Natural gas trading includes derivative settlements associated with our trading and marketing efforts around our natural gas intrastate pipelines and storage.

     Gross Margin was also negatively impacted in 2002 by a $25 million provision ($12 million relating to prior periods) recorded as a result of the Company’s completion of its analysis of gas imbalances with suppliers and customers dating back to 1999. This charge was recorded to reflect management’s current best estimate of necessary reserves for uncollectible imbalances, and unrecorded liabilities related to imbalances and incorrectly valued imbalances. Gross Margin was further reduced by $23 million of charges recorded in 2002 related to completion of the Company’s account reconciliation project, including a $6 million writedown for storage inventory. See “Accounting Adjustments” above.

     Gross Margin associated with the Natural Gas Segment decreased $232.3 million, or 19%, to $996.0 million in 2002 from $1,228.3 million in 2001, primarily as a result of lower NGL prices. Commodity sensitive processing arrangements accounted for approximately $154.0 million (net of hedging) of this decrease mainly due to the $.07 per gallon decrease in average NGL prices, partially offset by a $1.05 per million Btu decrease in natural gas prices. This reduction was the result of the interaction of our gas supply arrangements. Natural gas trading and natural gas trading and marketing associated with our natural gas intrastate pipeline and storage assets contributed approximately $24 million to this decrease. Gross Margin associated with this segment was also negatively affected by the charges related to reserves for gas imbalances with suppliers and customers, a writedown of storage inventory and charges related to completion of the Company’s account reconciliation project.

     Gross Margin associated with the NGLs Segment decreased $.4 million, or 1% to $55.1 million during 2002 from $55.5 million in 2001. Decreases in NGL trading margins during 2002 were offset by the 2001 acquisition of northeast propane terminal and marketing assets.

24

     NGL production during 2002 decreased 5,300 barrels per day, or 1%, to 391,900 barrels per day from 397,200 barrels per day during 2001, and natural gas transported and/or processed during 2002 decreased .3 trillion Btus per day, or 3%, to 8.3 trillion Btus per day from 8.6 trillion Btus per day during 2001. The primary cause of the decrease in NGL production was periodic reduction in keep-whole processing activity during 2002 due to marginally economic processing margins and reduced drilling activity, partially offset by acquisitions.

     Costs and Expenses. Operating and maintenance expenses increased $75.8 million, or 20%, to $449.3 million in 2002 from $373.5 million in 2001. This increase was primarily the result of the full year impact of acquisitions for approximately $20 million, accrual increases of $14.0 million due to higher spending levels, and increased maintenance, equipment overhauls, cost of labor and pipeline integrity projects. Included in the $14.0 million is $11 million of accounting adjustments (see “Accounting Adjustments” above). General and administrative expenses increased $37.1 million, or 29%, to $167.1 million in 2002 from $130.0 million in 2001. The primary causes of this increase were $11 million for core business process improvements, increased allocated costs from Duke Energy due to increased service levels, expanded business activity resulting from acquisitions and outside services for accounting and technology projects and accounting adjustments of $5 million (see “Accounting Adjustments” above).

     Depreciation and amortization increased $42.1 million (excluding $22.0 million of goodwill amortization in 2001), or 16%, to $299.0 million in 2002 from $256.9 million in 2001. This increase was due primarily to acquisitions, ongoing capital expenditures for well connections and facility maintenance and enhancements.

     Asset impairments were $40.4 million in 2002 compared to none in 2001. The impairment was related to certain assets located in Eastern Oklahoma, Offshore Gulf of Mexico, Northern Louisiana and Alabama and writeoff of a leasehold interest. As part of the Company’s periodic asset performance evaluations, it was determined in December 2002 that certain gas plants and gathering systems have recently generated cash flow losses and are expected to continue to generate minimal or negative cash flows in future years. Accordingly, at December 31, 2002, the Company performed tests for recoverability on these assets in accordance with the requirements of applicable accounting standards using probability weighted undiscounted future cash flow models. Based upon the results of these analyses, the Company determined that the carrying value of these assets was impaired and accordingly, wrote them down to their fair value. Fair value was determined based on management’s best estimates of sales value and/or discounted future cash flow models. The charge associated with these impairments was $40.4 million for 2002 relating to the Natural Gas Segment.

     Other costs and expenses increased to a loss of $4.3 million in 2002 from a gain of $1.3 million in 2001. The primary reason for the increase was the loss on sale of assets associated with a partnership investment of $5.2 million. This amount relates to accounting corrections (see “Accounting Adjustments” above).

     Interest. Interest expense increased $0.1 million, or less than 1%, to $165.8 million in 2002 from $165.7 million in 2001. This increase was primarily the result of slightly higher debt levels, offset by lower interest rates and capitalized interest adjustments (see “Accounting Adjustments” above).

     Income Taxes. The Company is a limited liability company, which is a pass-through entity for U.S. income tax purposes. Income tax expense represents federal, state and foreign taxes associated with tax-paying subsidiaries. Income tax expense increased $7.2 million to $10.0 million in 2002 from $2.8 million in 2001 due primarily to increased earnings associated with tax-paying subsidiaries obtained through acquisitions in 2001 and prior.

     Net (Loss) Income. Net (loss) income decreased $410.5 million to a loss of ($46.6) million in 2002 from income of $363.9 million in 2001. This decrease was partly the result of decreased NGL prices and increases in operating and maintenance, and general and administrative expenses, partially offset by lower natural gas prices and acquisition activity. Net income was also negatively affected by charges related to asset impairments, reserves for imbalances, storage inventory write-offs, loss on asset sale, charges related to completion of the Company’s account reconciliation project and increases in our accrual for unrecorded liabilities.

2001 compared with 2000

     Gross Margin. Gross Margin increased $68.5 million, or 6% to $1,313.9 million in 2001 from $1,245.4 million in 2000. Of this increase, approximately $183.0 million was related to the addition of the ConocoPhillips’ midstream natural gas business to our operations in the Combination on March 31, 2000. Additional increases of approximately $28.0 million were attributable to the combination of our acquisition of Canadian midstream facilities, Texas intrastate pipelines, northeast propane terminal and marketing assets, and the acquisition of the general partnership interest in TEPPCO. These increases were offset by approximately $130.0 million (net of hedging) due to an $.08 per gallon decrease in average NGL prices, and approximately $12.0 million due to a $.38 per

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million Btu increase in natural gas prices. Average prices for 2001 were $.45 per gallon for NGLs and $4.27 per million Btus for natural gas, respectively, as compared with $.53 per gallon and $3.89 per million Btus during 2000. NGL trading contributed another $13.9 million to the Gross Margin increase.

     Gross Margin associated with the Natural Gas Segment increased $59.0 million, or 5%, to $1,228.3 million in 2001 from $1,169.3 million in 2000, mainly as a result of the Combination. Commodity sensitive processing arrangements offset this increase by approximately $130.0 million (net of hedging) due to the $.08 per gallon decrease in average NGL prices. This reduction was the result of the interaction of commodity prices and our gas supply arrangements.

     Gross Margin associated with the NGL Segment increased $6.9 million to $55.5 million in 2001 from $48.6 million in 2000. This increase was primarily the result of NGL trading, the acquisition of northeast propane terminal and marketing assets, offset by the sale of an East Texas NGL pipeline.

     NGL production during 2001 increased 38,700 barrels per day, or 11%, to 397,200 barrels per day from 358,500 barrels per day in 2000, and natural gas transported and/or processed during 2001 increased 1.0 trillion Btus per day, or 13%, to 8.6 trillion Btus per day from 7.6 trillion Btus per day during 2000. The primary cause of the increase in NGL production was the addition of the ConocoPhillips’ midstream natural gas business in the Combination partially offset by reduced recoveries at certain facilities resulting from tightened fractionation spreads driven by high natural gas prices experienced during the first two quarters and low NGL prices experienced during the fourth quarter of 2001.

     Costs and Expenses. Operating and maintenance expenses increased $41.9 million, or 13%, to $373.5 million in 2001 from $331.6 million in 2000. Of this increase, approximately $35.6 million was related to the addition of the ConocoPhillips’ midstream natural gas business in the Combination. The remainder was primarily the result of acquisitions partially offset by plant consolidation and cost reduction efforts. General and administrative expenses decreased $41.2 million, or 24%, to $130.0 million in 2001 from $171.2 million in 2000. This decrease was primarily the result of decreased allocated overhead from our parents, decreased incentive compensation accruals and focused cost reduction efforts partially offset by the addition of the ConocoPhillips’ midstream natural gas business in the Combination.

     Depreciation and amortization increased $44.0 million, or 19%, to $278.9 million in 2001 from $234.9 million in 2000. Of this increase, $21.8 million was due to the addition of the ConocoPhillips’ midstream natural gas business in the Combination. The remainder was due to acquisitions, ongoing capital expenditures for well connections and facility maintenance and enhancements.

     Interest. Interest expense increased $16.5 million, or 11%, to $165.7 million in 2001 from $149.2 million in 2000. This increase was primarily the result of higher outstanding debt levels, partially offset by lower interest rates.

     Income Taxes. The Company is a limited liability company, which is a pass-through entity for U.S. income tax purposes. As a result of the March 31, 2000 Predecessor Company conversion to a limited liability company, substantially all of the Predecessor Company’s existing net deferred tax liability ($327.0 million) was eliminated and a corresponding income tax benefit was recorded. The 2001 income tax expense of $2.8 million is mainly the result of foreign and other miscellaneous taxes.

     Net Income. Net income decreased $316.3 million to $363.9 million in 2001 from $680.2 million in 2000. This decrease was largely the result of the tax benefit recognition discussed above, offset by the addition of the ConocoPhillips’ midstream natural gas business in the Combination and cost reduction efforts. Lower NGL prices and higher gas prices also contributed to this decrease.

Environmental Considerations

     We have various ongoing remedial matters related to historical operations similar to others in the industry, based primarily on state authorities generally described under “Item 1. Business — Environmental Matters.” These are typically managed in conjunction with the relevant state or federal agencies to address specific conditions, and in some cases are the responsibility of other entities based upon contractual obligations related to the assets.

     We make expenditures in connection with environmental matters as part of our normal operations and as capital expenses. For each of 2003 and 2004, we estimate that our aggregate expensed and capital-related environmental costs will be approximately $29 million.

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Critical Accounting Policies

     The selection and application of accounting policies is an important process that has developed as our operations mature and accounting guidance evolves. We have identified certain critical accounting policies that require the use of material estimates and have a material impact on our consolidated financial position and results of operations. These policies require significant estimations and judgment. Management bases its estimates and judgments on historical experience and on various assumptions that it believes are reasonable at the time of application. The estimations and judgments may change as more historical experience and information becomes available. If estimations and judgments are different than actual amounts recorded, adjustments are made in subsequent periods to take into consideration the new information. We discuss each of our critical accounting policies with senior members of management and the audit committee, as appropriate. Our critical accounting policies include:

     Risk Management Activities — We use two comprehensive accounting models for our risk management activities in reporting our consolidated financial position and results of operations as required by generally accepted accounting principles — a fair value model and an accrual model. For the three years ended December 31, 2002, the determination as to which model was appropriate was primarily based on accounting guidance issued by the Financial Accounting Standards Board (“FASB”) and the Emerging Issues Task Force (“EITF”). Effective January 1, 2003, we adopted EITF Issue 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and for Contracts Involved in Energy Trading and Risk Management Activities.” While the implementation of such guidance will change which accounting model is used for certain of our transactions, the overall application of the model remains the same. See Note 2 to the Consolidated Financial Statements for further discussion of EITF Issue 02-03 and its expected impact on our 2003 financial position and results of operations.

     The fair value model incorporates the use of mark-to-market (“MTM”) accounting. Under this method, an asset or liability is recognized at fair value on the Consolidated Balance Sheet and the change in the fair value of that asset or liability is recognized in Trading and Marketing Net Margin in the Consolidated Statements of Operations during the current period. Through December 31, 2002, we applied MTM accounting to our derivatives, unless subject to hedge accounting or the normal purchase and normal sale exemption (as described below), and energy trading contracts, as defined by EITF Issue 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities”.

     MTM accounting is applied within the context of an overall valuation framework. When available, quoted market prices are used to record a contract’s fair value. However, market values for energy trading contracts may not be readily determinable because the duration of the contracts exceeds the liquid activity in a particular market. If no active trading market exists for a commodity or for a contract’s duration, holders and issuers of these contracts must calculate fair value using internally developed valuation techniques or models. Key components used in these valuation techniques include price curves, volatility, correlation, interest rates and tenor. Of these components, volatility and correlation are the most subjective. Internally developed valuation techniques include the use of interpolation, extrapolation and fundamental analysis in the calculation of a contract’s fair value. All risk components for new and existing transactions are valued using the same valuation technique and market data and discounted using a London Interbank Offered Rate (“LIBOR”) based interest rate. Valuation adjustments for performance and market risk and administration costs are used to adjust the fair value of the contract to the gain or loss ultimately recognized in the Consolidated Statements of Operations.

     Validation of a contract’s fair value occurs by an internal group independent of our trading area. They perform pricing model validation, back testing and stress testing of valuation techniques and inputs and valuation of curves against market activity. In addition, we validate a contract’s fair value through collateral negotiation with third parties. While we use industry best practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values and income recognition.

     Often for a derivative that is initially subject to MTM accounting, we apply either hedge accounting or the normal purchase and sale exemption in accordance with SFAS No. 133. The use of hedge accounting or the normal purchase and sales exemption provide effectively for the use of the accrual model. Under this model, there is no recognition in the Consolidated Statements of Operations for changes in the fair value of a contract until the service is provided or the associated delivery period occurs.

     Hedge accounting treatment is used when we contract to buy or sell a commodity such as natural gas at a fixed price for future delivery corresponding with anticipated physical sales or purchase of natural gas (cash flow hedge). In addition, hedge accounting treatment is used when we hold firm commitments or asset positions and enter into transactions that hedge the risk that the price of the commodity may change between the contract’s inception and the physical delivery date of the commodity (fair value hedge). To the extent that the fair value of the hedge instrument is effective in offsetting the transaction being hedged, there is no impact to the Consolidated Statements of Operations prior to settlement of the hedge. However, due to the locational differences that exist in the

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energy commodity prices and the fact that not all of our hedges relate to the exact location and commodity being hedged, a certain degree of hedge ineffectiveness may be realized in the Consolidated Statements of Operations.

     The normal purchase and sales exemption, as provided in SFAS No. 133 and interpreted by Derivative Implementation Group Issue C15, indicates that no recognition of the contract’s fair value in the consolidated financial statements is required until settlement of the contract (in the Company’s case, the purchase or delivery of natural gas or NGLs). The Company has applied this exemption for contracts involving the purchase or sale of natural gas or NGLs in future periods.

     Revenue Recognition — The Company recognizes revenues on sales of natural gas and petroleum products in the period of delivery and transportation revenues in the period service is provided. For gathering services, the Company receives fees from the producers to bring the natural gas from the wellhead to the processing plant. For processing services, the Company either receives fees or commodities as payment for these services, depending on the type of contract. Under the percentage-of-proceeds contract type, the Company is paid for its services by keeping a percentage of the NGLs produced and the residue gas resulting from processing the natural gas. Under a keep-whole contract, the Company keeps a portion of the NGLs produced, but returns the equivalent British thermal unit (“Btu”) content of the gas back to the producer. The Company also receives fees for further fractionation of the NGLs produced, for transportation and storage of NGLs and residue gas. In addition, the Company recognizes revenue for its NGL and residue gas marketing activities. Revenue for goods and services provided but not billed is estimated each month based on estimated commodity prices, preliminary throughput measurements and contract data.

     Gas Imbalance Accounting — Quantities of natural gas over-delivered or under-delivered related to imbalance agreements with producers or pipelines are recorded monthly as other receivables or other payables using then current index prices or the weighted average prices of natural gas at the plant or system. These imbalances are settled with cash or deliveries of natural gas.

     Impairment of Long-lived Assets — We evaluate the carrying value of long-lived assets when circumstances indicate the carrying value of those assets may not be recoverable. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the asset. We consider various factors when determining if impairment has occurred, including but not limited to:

• Significant adverse change in legal factors or in the business climate;

• A current-period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset;

• An accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;

• Significant adverse changes in the extent or manner in which an asset is used or in its physical condition;

• A significant change in the market value of an asset;

• A current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.

     If the carrying value is not recoverable, the impairment loss is measured as the excess of the asset’s carrying value over its fair value measure. Fair value is determined based upon management’s best estimates of sales value and/or discounted future cash flow models.

     Our revenues and expenses are significantly dependent on commodity prices such as NGL’s and natural gas. Past and current trends in the price changes of these commodities may not be indicative of future trends. If negative market conditions persist over time and estimated cash flows over the lives of our assets do not exceed the carrying value of those individual assets, asset impairments may occur in the future under existing accounting rules. Furthermore, a change in management’s intent about the use of individual assets could also impact an impairment analysis. At this time, management has not determined any asset impairments for 2003 and beyond. At December 31, 2002, we had property, plant and equipment of $4,642 million.

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Liquidity and Capital Resources

     Operating Cash Flows

     During 2002, funds of $431.1 million were provided by operating activities, a decrease of $19.4 million from $450.5 million during 2001. This decrease was due primarily to a $410.5 million decrease in net income, partially offset by changes in working capital balances, unrealized mark-to-market and hedging activity, and non-cash charges, including asset impairments. The decrease in net income is due largely to lower NGLs prices and increased operating expenses and general and administrative expenses.

     Price volatility in crude oil, NGLs and natural gas prices have a direct impact on our generation of cash from operations.

     Investing Cash Flows

     During 2002, funds of $236.9 million were used in investing activities, a decrease of $301.7 million from $538.6 million in 2001. Our capital expenditures consist of expenditures for acquisitions and construction of additional gathering systems, processing plants, fractionators and other facilities and infrastructure in addition to well connections and upgrades to our existing facilities. For the year ended December 31, 2002, we spent approximately $301.6 million on capital expenditures compared to $597.4 million in 2001.

     Our level of capital expenditures for acquisitions and construction and other investments depends on many factors, including industry conditions, the availability of attractive acquisition opportunities and construction projects, the level of commodity prices and competition. We expect to finance our capital expenditures with our cash on hand, cash flow from operations and borrowings available under our commercial paper program, our credit facilities or other available sources of financing.

     Investments in unconsolidated affiliates provided $53.9 million in cash distributions to us during 2002.

     Financing Cash Flows

     Bank Financing and Commercial Paper

     In March 2002, we entered into a $650 million credit facility (“the Facility”), of which $150.0 million can be used for letters of credit. The Facility is used to support our commercial paper program and for working capital and other general corporate purposes. The Facility matures on March 28, 2003, however, any outstanding loans under the Facility at maturity may, at our option, be converted to a one-year term loan. The Facility requires us to maintain at all times a debt to total capitalization ratio of less than or equal to 53%. The Company entered into an amendment to the Facility on November 13, 2002. The Facility, as amended, bears interest at a rate equal to, at our option, either (1) LIBOR plus 1.25% per year or (2) the higher of (a) the Bank of America prime rate and (b) the Federal Funds rate plus 0.50% per year. At December 31, 2002, there were no borrowings or letters of credit outstanding against the Facility. We plan to replace the existing facility with a new $350 million credit facility (the “New Facility”). We expect to close on the New Facility on March 28, 2003. The New Facility is expected to have similar terms as the Facility being replaced, except it is likely to include an interest coverage ratio and a new restriction on dividends to our members. In addition, we plan to put into place a $100 million funded short-term facility (the “Funded Facility”) with a six month term. The Funded Facility is expected to have similar terms as the New Facility and is expected to close on or before March 28, 2003.

     At December 31, 2002, we had $215.1 million in outstanding commercial paper, with maturities ranging from three to 30 days and annual interest rates ranging from 1.83% to 1.90%. At no time did the amount of our outstanding commercial paper exceed the available amount under the Facility. In the future, our debt levels will vary depending on our liquidity needs, capital expenditures and cash flow.

     In April 2002, we filed a shelf registration statement increasing our ability to issue securities to $500 million. The shelf registration statement provides for the issuance of senior notes, subordinated notes and trust preferred securities.

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     Based on current and anticipated levels of operations, we believe that our cash on hand and cash flow from operations, combined with borrowings available under the commercial paper program and the expected New Facility and Funded Facility, will be sufficient to enable us to meet our current and anticipated cash operating requirements and working capital needs for the next year. Actual capital requirements, however, may change, particularly as a result of any acquisitions or distributions that we may make. Our ability to meet current and anticipated operating requirements will depend on our future performance.

     Preferred Financing

     In August 2000, we issued $300 million of preferred member interests to affiliates of Duke Energy and ConocoPhillips in proportion to their ownership interests. The proceeds from this financing were used to repay a portion of our outstanding commercial paper. On September 9, 2002, we redeemed $100.0 million of our preferred members’ interest by paying cash to each member (Duke Energy and ConocoPhillips) in proportion to their ownership interests. The outstanding preferred member interests are entitled to cumulative preferential distributions of 9.5% per annum payable, unless deferred, semiannually. We have the right to defer payments of preferential distributions on the preferred member interests, other than certain tax distributions, at any time and from time to time, for up to 10 consecutive semiannual periods. Deferred preferred distributions will accrue additional amounts based on the preferential distribution rate (plus 0.5% per annum) to the date of payment. At December 31, 2002 there were no outstanding deferred distributions. The preferred member interests, together with all accrued and unpaid preferential distributions, must be redeemed and paid on the earlier of the thirtieth anniversary date of issuance or consummation of an initial public offering of equity securities. For the years ending December 31, 2002 and 2001, we paid preferential distributions of $25.5 million and $28.5 million, respectively.

     Debt Securities

     During 2000 and 2001, we issued the following series of unsecured senior debt securities:

Issue	Principal		Interest
Date	($000s)		Rate			Due Date
August 16, 2000	$	600,000		7 1/2	%	August 16, 2005
August 16, 2000	$	800,000		7 7/8	%	August 16, 2010
August 16, 2000	$	300,000		8 1/8	%	August 16, 2030
February 2, 2001	$	250,000		6 7/8	%	February 1, 2011
November 9, 2001	$	300,000		5 3/4	%	November 15, 2006

     The notes mature and become due and payable on their respective due dates, and are not subject to any sinking fund provisions. Interest is payable semiannually. Each series of notes is redeemable, in whole or in part, at our option. The proceeds from the issuance of debt securities were used to repay a portion of our outstanding commercial paper.

     In October 2001, the Company entered into an interest rate swap to convert the fixed interest rate on $250 million of debt securities that were issued in August 2000 to floating rate debt. The interest rate fair value hedge is at a floating rate based on 6-month LIBOR rates, which is re-priced semiannually through 2005. The terms of the swap match the associated debt which permits the assumption of no ineffectiveness, as defined by Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities.” As such, for the life of the swap no ineffectiveness will be recognized. As of December 31, 2002, the fair value of the interest rate swap of $14.3 million was included in the Consolidated Balance Sheets as Unrealized Gains or Losses on Trading and Hedging Transactions with an offset to the underlying debt included in Long Term Debt.

     Distributions

     We are required to make quarterly distributions to Duke Energy and ConocoPhillips based on allocated taxable income. Our Limited Liability Company Agreement provides for taxable income to be allocated in accordance with the Internal Revenue Code Section 704(c). This Code section takes into account the variation between the adjusted tax basis and the fair market value of assets contributed to the joint venture. The required distribution is based on the highest taxable income allocated to either member, with the other member receiving a proportionate amount to maintain the ownership capital accounts at 69.7% for Duke Energy and 30.3% for ConocoPhillips. As of December 31, 2002, there were no distributions payable based on taxable income allocated to the members.

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     Contractual Obligations and Commercial Commitments

     As part of our normal business, we are a party to various financial guarantees, performance guarantees and other contractual commitments to extend guarantees of credit and other assistance to various subsidiaries, investees and other third parties. To varying degrees, these guarantees involve elements of performance and credit risk, which are not included on the Consolidated Balance Sheets. The possibility of us having to honor our contingencies is largely dependent upon future operations of various subsidiaries, investees and other third parties, or the occurrence of certain future events. We would record a reserve if events occurred that required that one be established. See Note 18 to the Consolidated Financial Statements for more information on guarantee obligations.

     At December 31, 2002, we were the guarantor of approximately $100.5 million of debt associated with unconsolidated subsidiaries, of which $84.5 million is related to our 33.3% ownership interest in Discovery Producer Services, LLC. These guarantees expire December 31, 2003. The debt related to Discovery Producer Services, LLC is due December 31, 2003, and is expected to be refinanced. In the event that the unconsolidated subsidiaries default on the debt payments, we would be required to pay the debt. Assets of the unconsolidated subsidiaries are pledged as collateral for the debt. At December 31, 2002, we had no liability recorded for the guarantees of the debt associated with the unconsolidated subsidiaries.

     At December 31, 2002, we have various indemnification agreements outstanding contained in asset purchase and sale agreements. These indemnification agreements generally relate to the change in environmental and tax laws or settlement of outstanding litigation. These indemnification agreements generally have terms of one to five years, although some are longer. We cannot estimate the maximum potential amount of future payments under these indemnification agreements due to the uncertainties related to changes in laws and regulation with regard to taxes, safety and protection of the environment or the settlement of outstanding litigation, which are outside our control. At December 31, 2002, we had no liability recorded for these outstanding indemnification agreements.

ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk.

Risk and Accounting Policies

     We are exposed to market risks associated with commodity prices, credit exposure, interest rates, and, to a limited extent, foreign currency exchange rates. Management has established comprehensive risk management policies to monitor and manage these market risks. Duke Energy Field Services’ Risk Management Committee is responsible for the overall approval of market risk management policies and the delegation of approval and authorization levels. The Risk Management Committee is composed of senior executives who receive regular briefings on the Company’s positions and exposures as well as periodic updates from and consultations with the Duke Energy Chief Risk Officer (CRO) and other expert resources at Duke Energy regarding market risk positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits.

     See Critical Accounting Policies — Risk Management Activities for further discussion of Risk and Accounting Policies.

Commodity Price Risk

     We are exposed to the impact of market fluctuations primarily in the price of NGLs that we own as a result of our processing activities. We employ established policies and procedures to manage our risks associated with these market fluctuations using various commodity derivatives, including forward contracts, swaps and options for non-trading activity (primarily hedge strategies). (See Notes 2 and 12 to the Consolidated Financial Statements.)

     Commodity Derivatives — Trading — The risk in the commodity trading portfolio is measured and monitored on a daily basis utilizing a Value-at-Risk model to determine the potential one-day favorable or unfavorable Daily Earnings at Risk (“DER”) as described below. DER is monitored daily in comparison to established thresholds. Other measures are also used to limit and monitor the risk in the commodity trading portfolio (which includes all trading contracts not designated as hedge positions) on a monthly and annual basis. These measures include limits on the nominal size of positions and periodic loss limits.

     DER computations are based on a historical simulation, which uses price movements over a specified period (generally ranging from seven to 14 days) to simulate forward price curves in the energy markets to estimate the potential favorable or unfavorable impact of one day’s price movement on the existing portfolio. The historical simulation emphasizes the most recent market activity, which is considered the most relevant predictor of immediate future market movements for crude oil, NGLs, gas and other energy-

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related products. DER computations use several key assumptions, including a 95% confidence level for the resultant price movement and the holding period specified for the calculation. The Company’s DER amounts for commodity derivatives instruments held for trading purposes are shown in the following table.

Daily Earnings at Risk (in thousands)

	Estimated Average		Estimated Average
	One-Day Impact on		One-Day Impact on		High One-Day Impact		Low One-Day Impact
	EBIT for 2002		EBIT for 2001		on EBIT for 2002		on EBIT for 2002
Calculated DER	$	2,102	$	1,630	$	4,840	$	441

     DER is an estimate based on historical price volatility. Actual volatility can exceed predicted results. DER also assumes a normal distribution of price changes, thus if the actual distribution is not normal, the DER may understate or overstate actual results. DER is used to estimate the risk of the entire portfolio, and for locations that do not have daily trading activity, it may not accurately estimate risk due to limited price information. Stress tests may be employed in addition to DER to measure risk where market data information is limited. In the current DER methodology, options are modeled in a manner equivalent to forward contracts which may understate the risk.

     Our exposure to commodity price risk is influenced by a number of factors, including contract size, length of contract, market liquidity, location and unique or specific contract terms. The following table illustrates the movements in the fair value of our trading instruments during 2002.

Changes in Fair Value of Trading Contracts (in thousands)

Fair value of contracts outstanding at the beginning of the year	$	33,242
Contracts realized or otherwise settled during the year		(67,516	)
Net premiums received for new option contracts during the year		(4,919	)
Net mark-to-market changes in fair values		11,206
Fair value of contracts outstanding at the end of the year		($27,987	)

     The fair value of these contracts is expected to be realized in future periods, as detailed in the following table. The amount of cash ultimately realized for these contracts will differ from the amounts shown in the following table due to factors such as market volatility, counterparty default and other unforeseen events that could impact the amount and/or realization of these values. At December 31, 2002, we held cash or letters of credit of $33.7 million to secure such future performance, and had $9.3 million deposited with counterparties.

     When available, quoted market prices are used to record a contract’s fair value. However, market values for energy trading contracts may not be readily determinable because the duration of the contracts exceeds the liquid activity in a particular market. If no active trading market exists for a commodity or for a contract’s duration, holders of these contracts must calculate fair value using internally developed valuation techniques or models. Key components used in these valuation techniques include price curves, volatility, correlation, interest rates, and tenor. Of these components, volatility and correlation are the most subjective. Internally developed valuation techniques include the use of interpolation, extrapolation, and fundamental analysis in the calculation of a contract’s fair value. All risk components for new and existing transactions are valued using the same valuation technique and market data and discounted using a LIBOR based interest rate. Valuation adjustments for performance and market risk and administration costs are used to adjust the fair value of the contract to the gain or loss ultimately recognized in the Consolidated Statements of Operations.

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     The following table shows the fair value of our trading portfolio as of December 31, 2002.

		Fair Value of Contracts as of December 31, 2002 (in thousands)
										Maturity in 2006
Sources of Fair Value		Maturity in 2003			Maturity in 2004		Maturity in 2005			and Thereafter			Total Fair Value
Prices supported by quoted market prices and other external sources		$	(23,700	)	$	1,052	$	331		$	—		$	(22,317	)
Prices based on models and other valuation methods			(5,791	)		513		(384	)		(8	)		(5,670	)
	Total	$	(29,491	)	$	1,565	$	(53	)	$	(8	)	$	(27,987	)

     The “Prices supported by quoted market prices and other external sources” category includes our New York Mercantile Exchange (“NYMEX”) swap positions in natural gas and crude oil. The NYMEX has currently quoted prices for the next 32 months. In addition, this category includes our forward positions and options in natural gas and natural gas basis swaps at points for which over-the-counter (“OTC”) broker quotes are available. On average, OTC quotes for natural gas forwards and swaps extend 22 and 32 months into the future, respectively. OTC quotes for natural gas options extend 12 months into the future, on average. We value these positions against internally developed forward market price curves that are validated and recalibrated against OTC broker quotes. This category also includes “strip” transactions whose prices are obtained from external sources and then modeled to daily or monthly prices as appropriate.

     The “Prices based on models and other valuation methods” category includes (i) the value of options not quoted by an exchange or OTC broker, (ii) the value of transactions for which an internally developed price curve was constructed as a result of the long dated nature of the transaction or the illiquidity of the market point, and (iii) the value of structured transactions. In certain instances structured transactions can be decomposed and modeled by us as simple forwards and options based on prices actively quoted. Although the valuation of the simple structures might not be different from the valuation of contracts in other categories, the effective model price for any given period is a combination of prices from two or more different instruments and therefore have been included in this category due to the complex nature of these transactions.

     Hedging Strategies - We are exposed to market fluctuations in the prices of energy commodities related to natural gas gathering, processing and marketing activities. We closely monitor the risks associated with these commodity price changes on our future operations and, where appropriate, use various commodity instruments such as natural gas, crude oil and NGL contracts to hedge the value of our assets and operations from such price risks. In accordance with SFAS No. 133, our primary use of commodity derivatives is to hedge the output and production of assets we physically own. Contract terms are up to three years, however, since these contracts are designated and qualify as effective hedge positions of future cash flows, or fair values of assets owned by us, to the extent that the hedge relationships are effective, their market value change impacts are not recognized in current earnings. The unrealized gains or losses on these contracts are deferred in Other Comprehensive (Loss) Income (“OCI”) for cash flow hedges or included in Other Current or Noncurrent Assets or Liabilities on the Consolidated Balance Sheets for fair value hedges of firm commitments, in accordance with SFAS No. 133. Amounts deferred in OCI are realized in earnings concurrently with the transaction being hedged. However, in instances where the hedging contract no longer qualifies for hedge accounting, amounts included in OCI through the date of de-designation remain in OCI until the underlying transaction actually occurs. The derivative contract (if continued as an open position) will be marked to market currently through earnings. Several factors influence the effectiveness of a hedge contract, including counterparty credit risk and using contracts with different commodities or unmatched terms. Hedge effectiveness is monitored regularly and measured each month.

     The following table shows when gains and losses deferred on the Consolidated Balance Sheets for derivative instruments qualifying as effective hedges of firm commitments or anticipated future transactions will be recognized into earnings. Contracts with terms extending several years are generally valued using models and assumptions developed internally or by industry standards. However, as mentioned previously, the effective portion of the gains and losses for these contracts are not recognized in earnings until

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settlement at their then market price. Therefore, assumptions and valuation techniques for these contracts have no impact on reported earnings prior to settlement for the effective portion of these hedges.

     The fair value of our qualifying hedge positions at a point in time is not necessarily indicative of the results realized when such contracts settle.

		Fair Value of Contracts as of December 31, 2002 (in thousands)
									Maturity in 2006
Sources of Fair Value		Maturity in 2003			Maturity in 2004		Maturity in 2005		and Thereafter		Total Fair Value
Quoted market prices		$	(56,794	)	$	2,767	$	2,079	$	—	$	(51,948	)
Prices based on models or other valuation techniques			(292	)		—		—		—		(292	)
	Total	$	(57,086	)	$	2,767	$	2,079	$	—	$	(52,240	)

     Based upon our portfolio of supply contracts, without giving effect to hedging activities that would reduce the impact of commodity price decreases, a decrease of $.01 per gallon in the price of NGLs and $.10 per million Btus in the average price of natural gas would result in changes in annual pre-tax net income of approximately $(25) million and $5 million, respectively.

Credit Risk

     Our principle customers in the Natural Gas Segment are large, natural gas marketing services and industrial end-users. In the NGLs segment, our principle customers are large multi-national petrochemical and refining companies to small regional propane distributors. Substantially all of our natural gas and NGLs sales are made at index, market-based prices. Approximately 40% of our NGLs production is committed to ConocoPhillips and Chevron Phillips Chemical LLC, under an existing 15-year contract which expires in 2014. This concentration of credit risk may affect our overall credit risk in that these customers may be similarly affected by changes in economic, regulatory or other factors. Where exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of these limits on an ongoing basis. The corporate credit policy prescribes the use of master collateral agreements to mitigate credit exposure. Collateral agreements provide for a counterparty to post cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an open credit limit, determined in accordance with the corporate credit policy. The collateral agreements also provide that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions. Substantially all other agreements contain adequate assurance provisions, which would allow us, at our discretion, to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment satisfactory to us.

     Despite the current credit environment in the energy sector, management believes that the credit risk management process described above is operating effectively. As of December 31, 2002, we had cash or letters of credit of $33.7 million to secure future performance by counterparties, and had deposited with counterparties $9.3 million of such collateral to secure our obligations to provide future services. Collateral amounts held or posted may be fixed or may vary depending on the value of the underlying contracts and could cover normal purchases and sales, trading and hedging contracts. In many cases, we and our counterparties’ publicly disclosed credit ratings impact the amounts of collateral requirements.

     Generally speaking, all physical and financial derivative contracts are settled in cash at the expiration of the contract term.

34

Interest Rate Risk

     We enter into debt arrangements that are exposed to market risks related to changes in interest rates. We periodically utilize interest rate lock agreements and interest rate swaps to hedge interest rate risk associated with new debt issuances. Our primary goals include (1) maintaining an appropriate ratio of fixed-rate debt to total debt for the Company’s debt rating; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates based on historical averages. As of December 31, 2002, the fair value of our interest rate swap was an asset of $14.3 million. (See Notes 2 and 12 to the Consolidated Financial Statements.)

     As of December 31, 2002, we had approximately $215.1 million outstanding under a commercial paper program. As a result, we are exposed to market risks related to changes in interest rates. In the future, we intend to manage our interest rate exposure using a mix of fixed and floating interest rate debt. An increase of .5% in interest rates would result in an increase in annual interest expense of approximately $2.3 million.

Foreign Currency Risk

     Our primary foreign currency exchange rate exposure at December 31, 2002 was the Canadian dollar. Foreign currency risk associated with this exposure was not material.

Accounting Pronouncements

     In January 2003, the FASB issued Interpretation No. 46 (FIN 46), “Consolidation of Variable Interest Entities.” FIN 46 requires an entity to consolidate a variable interest entity if it is the primary beneficiary of the variable interest entity’s activities. The primary beneficiary is the party that absorbs a majority of the expected losses, receives a majority of the expected residual returns, or both, of the variable interest entity’s activities. FIN 46 is applicable immediately to variable interest entities created, or interests in variable interest entities obtained, after January 31, 2003. For those variable interest entities created, or interests in variable interest entities obtained, on or before January 31, 2003, FIN 46 is required to be applied in the first fiscal year or interim period beginning after June 15, 2003. FIN 46 may be applied prospectively with a cumulative-effect adjustment as of the date it is first applied, or by restating previously issued financial statements with a cumulative-effect adjustment as of the beginning of the first year restated. FIN 46 also requires certain disclosures of an entity’s relationship with variable interest entities. The Company is currently assessing FIN 46 but has not yet determined the impact that it will have on its consolidated results of operations, cash flows or financial position.

     In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure — an amendment of FASB Statement No. 123.” SFAS No. 148 amends SFAS No. 123, “Accounting for Stock-Based Compensation,” to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. We adopted the disclosure only provisions of SFAS No. 148 as of December 31, 2002. Adoption of the new standard had no material effect on our consolidated results of operations or financial position.

     In November 2002, the FASB issued Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” which elaborates on the disclosures to be made by a guarantor about its obligations under certain guarantees issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. We will adopt the initial recognition and measurement provisions of Interpretation No. 45 on a prospective basis to guarantees issued or modified after December 31, 2002. We adopted the disclosure only provisions of Interpretation No. 45 as of December 31, 2002. Adoption of the new interpretation had no material effect on our consolidated results of operations or financial position.

     In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally EITF No. 94-3. We will adopt the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF No. 94-3, a liability for an exit cost was recognized at the date of the Company’s commitment to an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amounts recognized.

35

     In June 2002, the EITF reached a partial consensus on Issue No. 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.” The EITF concluded that, effective for periods ending after July 15, 2002, mark-to-market gains and losses on energy trading contracts (including those to be physically settled) must be shown on a net basis in the Consolidated Statements of Operations. The Company had previously chosen to report certain of its energy trading contracts on a gross basis, as sales in operating revenues and the associated costs recorded in operating expenses, in accordance with prevailing industry practice. The amounts in the comparative Consolidated Statements of Operations have been reclassified to conform to the 2002 presentation of all amounts on a net basis. The following table shows the impact of changing from gross to net presentation for energy trading activities on our revenues (offsetting adjustments were made to operating expenses resulting in no impact on net income).

	For the Year Ended
	December 31,
	2001			2000
	(In thousands)
Total revenues before adjustment	$	9,597,665		$	9,093,366
Adjustment		(1,572,971	)		(2,894,942	)
Revenue as reported	$	8,024,694		$	6,198,424

     In October 2002, the EITF, as part of their further deliberations on Issue No. 02-03, rescinded the consensus reached in Issue No. 98-10. As a result, all energy trading contracts that do not meet the definition of a derivative under SFAS No. 133, and trading inventories that previously had been recorded at fair values, will be recorded at their historical cost and reported on an accrual basis resulting in the recognition of earnings or losses at the time of contract settlement or termination. New non-derivative energy trading contracts entered into after October 25, 2002 are accounted for under the accrual accounting basis. Non-derivative energy trading contracts and trading inventories that were recorded at fair values were adjusted to historical cost via a cumulative effect adjustment of $5.4 million as a reduction to 2003 earnings.

     In October 2002, the EITF also reached a consensus in Issue No. 02-03 that, effective for periods beginning after December 15, 2002, all gains and losses on all derivative instruments held for trading purposes should be shown on a net basis in the income statement. Gains and losses on non-derivative energy trading contracts should similarly be presented on a gross or net basis in connection with the guidance in Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.” Upon application of this presentation, comparative financial statements for prior periods are required to be reclassified to conform to the consensus. Therefore, the Company’s trading revenue presentation on the Consolidated Statements of Operations may be revised again in 2003 based on the final consensus of the EITF.

     We adopted SFAS No. 142, “Goodwill and Other Intangible Assets,” on January 1, 2002. SFAS No. 142 requires that goodwill no longer be amortized over an estimated useful life, as previously required. Instead, goodwill amounts are subject to a fair-value-based annual impairment assessment. We did not recognize any impairments due to the implementation of SFAS No. 142. The standard also requires certain identifiable intangible assets to be recognized separately and amortized as appropriate. No adjustments to intangibles were identified by us at transition.

     The following table shows what net (loss) income would have been if amortization related to goodwill that is no longer being amortized had been excluded from prior periods.

		For the Year Ended
		December 31,
		2002			2001		2000
		(In thousands)
Reported net (loss) income		$	(46,551	)	$	363,907	$	680,161
Add: Goodwill amortization			—			21,989		17,859
	Adjusted net (loss) income	$	(46,551	)	$	385,896	$	698,020

36

     The changes in the carrying amount of goodwill for the years ended December 31, 2002 and December 31, 2001 are as follows (in thousands):

								Purchase
		Balance		Acquired		Price		Balance
		December 31, 2001		Goodwill		Adjustments		December 31, 2002
Natural gas gathering, processing, transportation, marketing and storage		$	394,054	$	—	$	521	$	394,575
NGL fractionation, transportation, marketing and trading			27,122		—		13,418		40,540
	Total consolidated	$	421,176	$	—	$	13,939	$	435,115

		Balance		Acquired		Amortization and			Balance
		December 31, 2000		Goodwill		Other			December 31, 2001
Natural gas gathering, processing, transportation, marketing and storage		$	376,195	$	53,799	$	(35,940	)	$	394,054
NGL fractionation, transportation, marketing and trading			—		28,053		(931	)		27,122
	Total consolidated	$	376,195	$	81,852	$	(36,871	)	$	421,176

     We adopted SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” on January 1, 2002. The new rules supersede SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of.” The new rules retain many of the fundamental recognition and measurement provisions of SFAS No. 121, but significantly change the criteria for classifying an asset as held-for-sale. Adoption of the new standard had no material effect on our consolidated results of operations or financial position.

     In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and (or) normal use of the asset.

     SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability is increased due to the passage of time based on the time value of money until the obligation is settled.

     We adopted the provisions of SFAS No. 143 as of January 1, 2003. In accordance with the transition provisions of SFAS No. 143, we recorded a cumulative-effect adjustment of $17.4 million as a reduction in 2003 earnings.

37

ITEM 8. Financial Statements and Supplementary Data.

DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED STATEMENTS OF OPERATIONS
Years Ended December 31, 2002, 2001 and 2000
(In thousands)

				2002			2001			2000
OPERATING REVENUES:
	Sales of natural gas and petroleum products			$	3,025,554		$	4,766,449		$	3,609,775
	Sales of natural gas and petroleum products — affiliates				2,160,174			2,928,631			2,373,698
	Transportation, storage and processing				291,431			281,744			188,501
	Transportation, storage and processing — affiliates				—			—			11,350
	Trading and marketing net margin				14,397			47,870			15,100
			Total operating revenues		5,491,556			8,024,694			6,198,424
COSTS AND EXPENSES:
	Purchases of natural gas and petroleum products				3,935,943			6,049,010			4,236,098
	Purchases of natural gas and petroleum products — affiliates				504,428			691,884			744,378
	Operating and maintenance				449,318			373,477			331,572
	Depreciation and amortization				298,953			278,930			234,862
	General and administrative				149,316			118,249			140,557
	General and administrative — affiliates				17,799			11,719			30,597
	Asset impairments				40,440			—			—
	Net loss (gain) on sale of assets				4,256			(1,277	)		(10,660	)
		Total costs and expenses			5,400,453			7,521,992			5,707,404
OPERATING INCOME					91,103			502,702			491,020
EQUITY IN EARNINGS OF UNCONSOLIDATED AFFILIATES					38,196			30,069			27,424
INTEREST EXPENSE:
	Interest expense				165,841			165,670			134,016
	Interest expense — affiliates				—			—			15,204
		Total interest expense			165,841			165,670			149,220
(LOSS) INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE					(36,542	)		367,101			369,224
INCOME TAX EXPENSE (BENEFIT)					10,009			2,783			(310,937	)
(LOSS) INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE					(46,551	)		364,318			680,161
CUMULATIVE EFFECT OF ACCOUNTING CHANGE					—			411			—
NET (LOSS) INCOME					(46,551	)		363,907			680,161
DIVIDENDS ON PREFERRED MEMBERS’ INTEREST					25,544			28,500			11,717
(DEFICIT) EARNINGS AVAILABLE FOR MEMBERS’ INTEREST				$	(72,095	)	$	335,407		$	668,444

See Notes to Consolidated Financial Statements.

38

DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME
Years Ended December 31, 2002, 2001 and 2000
(In thousands)

			2002			2001			2000
NET (LOSS) INCOME			$	(46,551	)	$	363,907		$	680,161
OTHER COMPREHENSIVE (LOSS) INCOME:
	Cumulative effect of change in accounting principle			—			6,626			—
	Foreign currency translation adjustment			161			(4,460	)		(2,717	)
	Net unrealized (losses) gains on cash flow hedges			(129,015	)		51,621			—
	Reclassification into earnings			15,963			(3,313	)		—
		Total other comprehensive (loss) income		(112,891	)		50,474			(2,717	)
TOTAL COMPREHENSIVE (LOSS) INCOME			$	(159,442	)	$	414,381		$	677,444

See Notes to Consolidated Financial Statements.

39

DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31, 2002, 2001 and 2000
(In thousands)

				2002			2001			2000
CASH FLOWS FROM OPERATING ACTIVITIES:
	Net (loss) income			$	(46,551	)	$	363,907		$	680,161
	Adjustments to reconcile net (loss) income to net cash provided by operating activities:
		Depreciation and amortization			298,953			278,930			234,862
		Deferred income taxes (benefit)			1,951			2,783			(308,001	)
		Equity in earnings of unconsolidated affiliates			(38,196	)		(30,069	)		(27,424	)
		Asset impairments			40,440			—			—
		Loss on asset sales and other			1,401			91			(10,653	)
	Change in operating assets and liabilities (net of effects of acquisitions) which provided (used) cash:
		Accounts receivable			893			533,109			(492,475	)
		Accounts receivable — affiliates			43,944			22,756			(189,300	)
		Inventories			(3,624	)		9,856			(73,348	)
		Net unrealized loss (gains) on mark-to-market transactions			71,778			(35,744	)		5,376
		Other current assets			3,097			1,013			41,324
		Other noncurrent assets			(1,917	)		76			(9,414	)
		Accounts payable			(9,662	)		(633,599	)		808,980
		Accounts payable — affiliates			51,389			(35,844	)		(906	)
		Accrued interest payable			1,877			7,807			49,641
		Other current liabilities			4,031			(11,868	)		51,036
		Other long term liabilities			11,271			(22,741	)		(46,787	)
			Net cash provided by operating activities		431,075			450,463			713,072
CASH FLOWS FROM INVESTING ACTIVITIES:
	Expenditures for acquisitions				—			(220,097	)		(163,565	)
	Other capital expenditures				(301,631	)		(377,273	)		(207,498	)
	Investment expenditures, net of cash acquired				392			(4,795	)		(5,323	)
	Investment distributions				53,878			41,278			43,557
	Proceeds from sales of assets				10,501			22,300			97,981
			Net cash used in investing activities		(236,860	)		(538,587	)		(234,848	)
CASH FLOWS FROM FINANCING ACTIVITIES:
	Net decreases in advances from members				(2,498	)		(11,347	)		(55,509	)
	Redemption of preferred members interests				(100,000	)		—			—
	Distributions to members				(63,165	)		(235,564	)		(2,744,319	)
	Proceeds from issuing preferred members’ interest				—			—			300,000
	Short term debt — net				2,139			(133,455	)		346,410
	Proceeds from issuing debt — net				—			546,918			1,691,114
	Debt issuance costs				(1,959	)		(2,034	)		(3,557	)
	Payment of debt				(590	)		(51,037	)		—
	Payment of dividends				(25,544	)		(28,500	)		(11,717	)
			Net cash (used in) provided by financing activities		(191,617	)		84,981			(477,578	)
EFFECT OF FOREIGN EXCHANGE RATE CHANGES ON CASH					(21	)		6,496			115
NET INCREASE IN CASH					2,577			3,353			761
CASH, BEGINNING OF YEAR					4,906			1,553			792
CASH, END OF YEAR				$	7,483		$	4,906		$	1,553
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION — Cash paid for interest (net of amounts capitalized)				$	167,266		$	155,946		$	95,805

See Notes to Consolidated Financial Statements.

40

DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED BALANCE SHEETS
As of December 31, 2002 and 2001
(In thousands)

				2002			2001
ASSETS
CURRENT ASSETS:
	Cash			$	7,483		$	4,906
	Accounts receivable:
		Customers, net			599,116			520,118
		Affiliates			186,577			230,521
		Other			50,466			136,810
	Inventories				86,559			82,935
	Unrealized gains on trading and hedging transactions				187,000			180,809
	Other				6,713			9,060
			Total current assets		1,123,914			1,165,159
PROPERTY, PLANT AND EQUIPMENT, NET					4,642,204			4,711,960
INVESTMENT IN AFFILIATES					179,684			132,252
INTANGIBLE ASSETS:
	Natural gas liquids sales and purchases contracts, net				84,304			94,019
	Goodwill, net				435,115			421,176
			Total intangible assets		519,419			515,195
UNREALIZED GAINS ON TRADING AND HEDGING TRANSACTIONS					25,710			19,095
OTHER NONCURRENT ASSETS					89,504			86,548
			TOTAL ASSETS	$	6,580,435		$	6,630,209
LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES:
	Accounts payable:
		Trade		$	638,826		$	620,094
		Affiliates			77,009			25,620
		Other			45,786			76,914
	Short term debt				215,094			212,955
	Accrued taxes other than income				31,059			24,646
	Distributions payable to members				—			45,672
	Accrued interest payable				59,294			57,417
	Unrealized losses on trading and hedging transactions				273,578			89,032
	Other				88,370			98,473
			Total current liabilities		1,429,016			1,250,823
DEFERRED INCOME TAXES					11,740			14,362
LONG TERM DEBT					2,255,508			2,235,034
UNREALIZED LOSSES ON TRADING AND HEDGING TRANSACTIONS					19,361			25,188
OTHER LONG TERM LIABILITIES					89,427			15,845
MINORITY INTERESTS					124,820			135,915
PREFERRED MEMBERS’ INTEREST					200,000			300,000
COMMITMENTS AND CONTINGENT LIABILITIES MEMBERS’ EQUITY:
	Members’ interest				1,709,290			1,709,290
	Retained earnings				806,119			895,707
	Accumulated other comprehensive (loss) income				(64,846	)		48,045
			Total members’ equity		2,450,563			2,653,042
TOTAL LIABILITIES AND MEMBERS’ EQUITY				$	6,580,435		$	6,630,209

See Notes to Consolidated Financial Statements.

41

DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY
Years Ended December 31, 2002, 2001 and 2000
(In thousands)

														Accumulated
					Additional									Other
		Common			Paid-In			Members’			Retained			Comprehensive
		Stock			Capital			Interest			Earnings			(Loss) Income			Total
Balance, January 1, 2000			1			213,091			—			173,091			288			386,471
Combination at March 31, 2000 — see Note 2:
	Contribution of TEPPCO general partnership interest		—			2,148			—			—			—			2,148
	Contribution of DEFS Inc. and DEFSCL to DEFS, LLC		(1	)		(215,239	)		215,240			—			—			—
	Contribution of notes and advances payable		—			—			2,318,569			—			—			2,318,569
	Contribution of GPM assets and liabilities		—			—			1,919,800			—			—			1,919,800
	Distributions		—			—			(2,744,319	)		(127,561	)		—			(2,871,880	)
Dividends on preferred members’ interest			—			—			—			(11,717	)		—			(11,717	)
Net Income			—			—			—			680,161			—			680,161
Other			—			—			—			—			(2,717	)		(2,717	)
Balance, December 31, 2000			—			—			1,709,290			713,974			(2,429	)		2,420,835
Distributions			—			—			—			(153,674	)		—			(153,674	)
Dividends on preferred members’ interest			—			—			—			(28,500	)		—			(28,500	)
Net Income			—			—			—			363,907			—			363,907
Other			—			—			—			—			50,474			50,474
Balance, December 31, 2001			—			—			1,709,290			895,707			48,045			2,653,042
Distributions			—			—			—			(17,493	)		—			(17,493	)
Dividends on preferred members’ interest			—			—			—			(25,544	)		—			(25,544	)
Net loss			—			—			—			(46,551	)		—			(46,551	)
Other			—			—			—			—			(112,891	)		(112,891	)
Balance, December 31, 2002		$	—		$	—		$	1,709,290		$	806,119		$	(64,846	)	$	2,450,563

See Notes to Consolidated Financial Statements.

42

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2002, 2001 and 2000

1. General

     Basis of Presentation — Duke Energy Field Services, LLC (with its consolidated subsidiaries, “the Company” or “Field Services LLC”) operates in the midstream natural gas gathering, marketing and natural gas liquids industries. The Company operates in the two principal segments of the midstream natural gas industry of (1) natural gas gathering, processing, transportation, marketing and storage; and (2) natural gas liquids (“NGLs”) fractionation, transportation, trading and marketing and trading. Field Services LLC’s limited liability company agreement limits the scope of the Company’s business to the midstream natural gas industry in the United States and Canada, the marketing of natural gas liquids in Mexico and the transportation, marketing and storage of other petroleum products.

     The Company is the successor to Duke Energy Corporation’s (“Duke Energy”) North American midstream natural gas business that existed at the time of the Combination (see Note 3). The subsidiaries of Duke Energy that conducted this business were contributed to the Company immediately prior to the Combination (see Note 3). For periods prior to the Combination, the Company and these subsidiaries of Duke Energy are collectively referred to herein as the “Predecessor Company.”

2. Summary of Significant Accounting Policies

     Consolidation — The Consolidated Financial Statements include the accounts of the Company and all majority-owned subsidiaries, after eliminating significant intercompany transactions and balances. Investments in 20% to 50% owned affiliates are accounted for using the equity method. Investments greater than 50% are consolidated unless the Company does not operate these investments and as a result does not have the ability to exercise control (see Note 9).

     Use of Estimates — Conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the financial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could be different from those estimates.

     Inventories — Inventories consist primarily of materials and supplies and natural gas and NGLs held in storage for transmission and processing and sales commitments. Inventories are recorded at the lower of cost or market value using the average cost method (see Note 7). Historically, natural gas storage arbitrage volumes were marked to market. However, effective with the Financial Accounting Standard Board’s (“FASB”) Emerging Issues Task Force’s (“EITF”) rescission of Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” all gas storage inventory will be recorded at the lower of cost or market, (see “New Accounting Standards” below).

     Accounting for Hedges and Commodity Trading Activities — All derivatives not qualifying for the normal purchases and sales exemption under Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities” are recorded in the Consolidated Balance Sheets at their fair value as Unrealized Gains or Unrealized Losses on Trading and Hedging Transactions. On the date that derivative contracts are entered into, the Company designates the derivative as either held for trading (trading instruments); as a hedge of a recognized asset, liability or firm commitment (fair value hedges); as a hedge of a forecasted transaction or future cash flows (cash flow hedges); as a normal purchase or sale contract; or leaves the derivative undesignated and marks it to market.

     For hedge contracts, the Company formally assesses, both at the hedge contract’s inception and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in fair values or cash flows of hedged items. The Company excludes time value of the options when assessing hedge effectiveness.

     When available, quoted market prices or prices obtained through external sources are used to verify a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical and expected correlations with quoted market prices.

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     Values are adjusted to reflect the potential impact of liquidating the positions held in an orderly manner over a reasonable time period under current conditions. Changes in market price and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term.

     Commodity Trading — A favorable or unfavorable price movement of any derivative contract held for trading purposes is reported as Trading and Marketing Net Margin in the Consolidated Statements of Operations. An offsetting amount is recorded in the Consolidated Balance Sheets as Unrealized Gains or Unrealized Losses on Trading and Hedging Transactions. When a contract is settled, the realized gain or loss is reclassified to a receivable or payable account. Settlement has no revenue presentation effect on the Consolidated Statements of Operations.

     See the “New Accounting Standards” section below for a discussion of the implications of EITF Issue 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” on the accounting for trading activities subsequent to October 25, 2002.

     Commodity Cash Flow Hedges — The effective portion of the change in fair value of a derivative designated and qualified as a cash flow hedge are included in the Consolidated Statements of Comprehensive (Loss) Income as Other Comprehensive (Loss) Income (“OCI”) until earnings are affected by the hedged item. Settlement amounts of cash flow hedges are removed from OCI and recorded in the Consolidated Statements of Operations in the same accounts as the item being hedged. The Company discontinues hedge accounting prospectively when it is determined that the derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged transaction will occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative continues to be carried on the Consolidated Balance Sheets at its fair value, with subsequent changes in its fair value recognized in current-period earnings. Gains and losses related to discontinued hedges that were previously accumulated in OCI will remain in OCI until earnings are affected by the hedged item, unless it is no longer probable that the hedged transaction will occur, in which case, the gains and losses that were accumulated in OCI will be immediately recognized in current-period earnings.

     Commodity Fair Value Hedges — Changes in the fair value of a derivative that is designated and qualifies as a fair value hedge are included in the Consolidated Statements of Operations as Sales of Natural Gas and Petroleum Products and Purchases of Natural Gas and Petroleum Products, as appropriate. Changes in the fair value of the physical portion of a fair value hedge (i.e., the hedged item) are recorded in the Consolidated Statements of Operations in the same accounts as the changes in the fair value of the derivative, with offsetting amounts in the Consolidated Balance Sheets as Other Current Assets, Other Noncurrent Assets, Other Current Liabilities, or Other Long Term Liabilities, as appropriate.

     Interest Rate Fair Value Hedges — The Company enters into interest rate swaps to convert some of its fixed-rate long term debt to floating-rate long term debt. Hedged items in fair value hedges are marked to market with the respective derivative instruments. Accordingly, the Company’s hedged fixed-rate debt is carried at fair value. The terms of the outstanding swap match those of the associated debt which permits the assumption of no ineffectiveness, as defined by SFAS No. 133. As such, for the life of the swap no ineffectiveness will be recognized.

     Intangible Assets — Intangible assets consist of goodwill and NGLs sales and purchases contracts. Goodwill is the cost of an acquisition less the fair value of the net assets of the acquired business. Prior to January 1, 2002, the Company amortized goodwill on a straight-line basis over the useful lives of the acquired assets, ranging from 15 to 20 years. The Company implemented SFAS No. 142, “Goodwill and Other Intangible Assets” as of January 1, 2002. For information on the impact of SFAS No. 142 on goodwill and goodwill amortization see the “New Accounting Standards” section of this footnote. (See Notes 3 and 4 for information on significant goodwill additions.) NGLs sales and purchases contracts are amortized on a straight-line basis over the term of the contract, ranging from one to 15 years.

     Property, Plant and Equipment — Property, plant and equipment are recorded at original cost. Depreciation is computed using the straight-line method over the estimated useful lives of the individual assets (see Note 8). The costs of maintenance and repairs, which are not significant improvements, are expensed when incurred. Interest totaling $4.7 million for 2002, $0.8 million for 2001 and $0.3 million for 2000 has been capitalized on construction projects.

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     Impairment of Long-Lived Assets — The Company reviews the recoverability of long-lived assets and intangible assets when circumstances indicate that the carrying amount of the asset may not be recoverable. This evaluation is based on undiscounted cash flow projections. For the year ended December 31, 2002, the Company recorded an impairment charge for certain assets of $40.4 million. For the years ended December 31, 2001 and 2000, there was no impairment.

     Revenue Recognition — The Company recognizes revenues on sales of natural gas and petroleum products in the period of delivery and transportation revenues in the period service is provided. For gathering services, the Company receives fees from the producers to bring the natural gas from the wellhead to the processing plant. For processing services, the Company either receives fees or commodities as payment for these services, depending on the type of contract. Under the percentage-of-proceeds contract type, the Company is paid for its services by keeping a percentage of the NGLs produced and the residue gas resulting from processing the natural gas. Under a keep-whole contract, the Company keeps a portion of the NGLs produced, but returns the equivalent British thermal unit (“Btu”) content of the gas back to the producer. The Company also receives fees for further fractionation of the NGLs produced, for transportation and storage of NGLs and residue gas. In addition, the Company recognizes revenue for its NGL and residue gas marketing activities. Revenue for goods and services provided but not billed is estimated each month based upon estimated commodity prices, preliminary throughput measurements and contract data.

     Significant Customers — Duke Energy Trading and Marketing, L.L.C. (“DETM”), an affiliated company, was a significant customer in each of the past three years. Sales to DETM, primarily residue gas, totaled approximately $1,119.1 million during 2002, $1,628.8 million during 2001 and $1,444.0 million during 2000. Effective February 28, 2003, the Company’s Master Natural Gas Sales and Purchase Agreement with DETM terminated. DETM provided a thirty-day notice of termination on January 30, 2003. The Company expects to continue to conduct business with DETM on a transactional basis in the future at a reduced volume level. Given the Company’s extensive gas marketing experience for the remainder of its business, management does not expect the termination of this contract to have any material impact on the Company’s financial position or its results of operations.

     ConocoPhillips, an affiliated company, was also a significant customer. Sales to ConocoPhillips, including its affiliate, Chevron Phillips Chemical Company LLC (“CP Chem”) totaled approximately $1,022.6 million during 2002, $1,309.5 million during 2001 and $942.3 million during 2000.

     Unamortized Debt Premium, Discount and Expense — Premiums, discounts and expenses incurred with the issuance of long term debt are amortized over the terms of the debt issues.

     Environmental Expenditures — Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not generate current or future revenue, are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. Recorded environmental liabilities were $26.0 million at the end of 2002 and $40.0 million at the end of 2001.

     Gas Imbalance Accounting — Quantities of natural gas over-delivered or under-delivered related to imbalance agreements with producers or pipelines are recorded monthly as other receivables or other payables using then current index prices or the weighted average prices of natural gas at the plant or system. These balances are settled with cash or deliveries of natural gas.

     Foreign Currency Translation — The Company translates assets and liabilities of its Canadian operations, where the Canadian dollar is the functional currency, at the year-end exchange rates. Revenues and expenses are translated using average exchange rates during the year. Foreign currency translation adjustments are included in the Consolidated Statements of Comprehensive (Loss) Income.

     Income Taxes — The Company follows the asset and liability method of accounting for income taxes. Deferred taxes are provided for temporary differences in the tax and financial reporting basis of assets and liabilities (see Note 10). At March 31, 2000, the Company converted to a limited liability company which is a pass-through entity for U.S. income tax purposes. As a result, substantially all of the existing net deferred tax liability of $327.0 million was eliminated and a corresponding income tax benefit recorded.

     The Company owns corporations who file their own respective federal and state corporate income tax returns. The income tax expense related to these corporations is included in the income tax expense of the Company, along with other miscellaneous state, local and franchise taxes of the limited liability company and other subsidiaries. In addition, the Company has Canadian subsidiaries that are levied certain foreign taxes.

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     In connection with the Combination (see Note 3), the Company is required to make quarterly distributions to Duke Energy and ConocoPhillips based on allocated taxable income. The limited liability company agreement, as amended, provides for taxable income to be allocated in accordance with Internal Revenue Code Section 704(c). This Code Section accounts for the variation between the adjusted tax basis and the fair market value of assets contributed to the joint venture. The distribution is based on the highest taxable income allocated to either member, with the other member receiving a proportionate amount to maintain the ownership capital accounts at 69.7% for Duke Energy and 30.3% for ConocoPhillips. As of December 31, 2002, no additional distributions were due the members.

     Stock Based Compensation — Under Duke Energy’s 1998 Long Term Incentive Plan, stock options for Duke Energy’s common stock may be granted to the Company’s key employees. The Company accounts for stock based compensation using the intrinsic method of accounting. Under this method, any compensation cost is measured as the quoted market price of stock at the date of the grant less the amount an employee must pay to acquire the stock. Restricted stock grants and Company performance awards are recorded as compensation cost over the requisite vesting period based on the market value on the date of the grant. (See Note 15 for pro forma disclosures using the fair value accounting method.) All outstanding common stock amounts and compensation awards have been adjusted to reflect Duke Energy’s two-for-one common stock split effected January 26, 2001. (See Note 15 for additional information on the stock split.)

     Cumulative Effect of Change in Accounting Principle — The Company adopted SFAS No. 133 on January 1, 2001. In accordance with the transition provisions of SFAS No. 133, the Company recorded a cumulative-effect adjustment of $0.4 million as a reduction in earnings and a cumulative-effect adjustment increasing OCI and member’s equity by $6.6 million. For the years ended December 31, 2002 and 2001, the Company reclassified as earnings $0.9 million and $12.1 million of losses, respectively, from OCI for derivatives included in the transition adjustment related to hedge transactions that settled. All hedge transactions in the transition adjustment had been settled as of December 31, 2002. The amounts reclassified out of OCI were different from the amounts included in the transition adjustment due to market price changes since January 1, 2001.

     New Accounting Standards — In January 2003, the FASB issued Interpretation No. 46 (FIN 46), “Consolidation of Variable Interest Entities.” FIN 46 requires an entity to consolidate a variable interest entity if it is the primary beneficiary of the variable interest entity’s activities. The primary beneficiary is the party that absorbs a majority of the expected losses, receives a majority of the expected residual returns, or both, of the variable interest entity’s activities. FIN 46 is applicable immediately to variable interest entities created, or interests in variable interest entities obtained, after January 31, 2003. For those variable interest entities created, or interests in variable interest entities obtained, on or before January 31, 2003, FIN 46 is required to be applied in the first fiscal year or interim period beginning after June 15, 2003. FIN 46 may be applied prospectively with a cumulative-effect adjustment as of the date it is first applied, or by restating previously issued financial statements with a cumulative-effect adjustment as of the beginning of the first year restated. FIN 46 also requires certain disclosures of an entity’s relationship with variable interest entities. The Company is currently assessing FIN 46 but has not yet determined the impact that it will have on its consolidated results of operations, cash flows or financial position.

     In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure — an amendment of FASB Statement No. 123.” SFAS No. 148 amends SFAS No. 123, “Accounting for Stock-Based Compensation,” to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The Company adopted the disclosure only provisions of SFAS No. 148 as of December 31, 2002. Adoption of the new standard had no material effect on the Company’s consolidated results of operations or financial position.

     In November 2002, the FASB issued Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” which elaborates on the disclosures to be made by a guarantor about its obligations under certain guarantees issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The Company will adopt the initial recognition and measurement provisions of Interpretation No. 45 on a prospective basis to guarantees issued or modified after December 31, 2002. The Company adopted the disclosure only provisions of Interpretation No. 45 as of December 31, 2002. Adoption of the new interpretation had no material effect on the Company’s consolidated results of operations or financial position.

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     In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally EITF No. 94-3. The Company will adopt the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF No. 94-3, a liability for an exit cost was recognized at the date of the Company’s commitment to an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amounts recognized.

     In June 2002, the EITF reached a partial consensus on Issue No. 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.” The EITF concluded that, effective for periods ending after July 15, 2002, mark-to-market gains and losses on energy trading contracts (including those to be physically settled) must be shown on a net basis in the Consolidated Statements of Operations. The Company had previously chosen to report certain of its energy trading contracts on a gross basis, as sales in operating revenues and the associated costs recorded in operating expenses, in accordance with prevailing industry practice. The amounts in the comparative Consolidated Statements of Operations have been reclassified to conform to the 2002 presentation of all amounts on a net basis. The following table shows the impact of changing from gross to net presentation for energy trading activities on the Company’s revenues (offsetting adjustments were made to operating expenses resulting in no impact on operating or net income).

	For the Year Ended
	December 31,
	2001			2000
	(In thousands)
Total revenues before adjustment	$	9,597,665		$	9,093,366
Adjustment		(1,572,971	)		(2,894,942	)
Revenue as reported	$	8,024,694		$	6,198,424

     In October 2002, the EITF, as part of their further deliberations on Issue No. 02-03, rescinded the consensus reached in Issue No. 98-10. As a result, all energy trading contracts that do not meet the definition of a derivative under SFAS No. 133, and trading inventories that previously had been recorded at fair values, will be recorded at the lower of cost or market and reported on an accrual basis resulting in the recognition of earnings or losses at the time of contract settlement or termination. New non-derivative energy trading contracts entered into after October 25, 2002 will be accounted for under the accrual accounting basis. Non-derivative energy trading contracts on the Consolidated Balance Sheet as of January 1, 2003 that existed at October 25, 2002 and inventories that were recorded at fair values were adjusted to historical cost via a cumulative effect adjustment of $5.4 million as a reduction to 2003 earnings. In connection with the consensus reached on Issue No. 02-03, the FASB staff observed that, effective July 1, 2002, an entity should not recognize unrealized gains or losses at the inception of a derivative instrument unless the fair value of that instrument is evidenced by quoted market prices or current market transactions.

     In October 2002, the EITF also reached a consensus in Issue No. 02-03 that, effective for periods beginning after December 15, 2002, all gains and losses on all derivative instruments held for trading purposes should be shown on a net basis in the income statement. Gains and losses on non-derivative energy trading contracts should similarly be presented on a gross or net basis in connection with the guidance in Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.” Upon application of this presentation, comparative financial statements for prior periods should be reclassified to conform to the consensus. Therefore, the Company’s trading revenue presentation on the Consolidated Statements of Operations may be restated again in 2003 based on the final consensus of the EITF. All gains and losses on all energy trading contracts are currently presented on a net basis in the Consolidated Statement of Operations. The new gross versus net revenue presentation requirements will have no impact on operating income or net income.

     The Company adopted SFAS No. 141, “Business Combinations,” as of July 1, 2001. SFAS No. 141 required that all business combinations initiated after June 30, 2001 be accounted for using the purchase method. Companies may no longer use the pooling method of accounting for future combinations.

     The Company adopted SFAS No. 142, “Goodwill and Other Intangible Assets,” on January 1, 2002. SFAS No. 142 requires that goodwill no longer be amortized over an estimated useful life, as previously required. Instead, goodwill amounts are subject to a fair-value-based annual impairment assessment. The Company did not recognize any impairments due to the implementation of SFAS No. 142. The standard also requires certain identifiable intangible assets to be recognized separately and amortized as appropriate. No adjustments to intangibles were identified by the Company at transition.

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     The following table shows what net (loss) income would have been if amortization related to goodwill that is no longer being amortized had been excluded from prior periods.

		For the Year Ended
		December 31,
		2002			2001		2000
		(In thousands)
Reported net (loss) income		$	(46,551	)	$	363,907	$	680,161
Add: Goodwill amortization			—			21,989		17,859
	Adjusted net (loss) income	$	(46,551	)	$	385,896	$	698,020

     The changes in the carrying amount of goodwill for the year ended December 31, 2002 and December 31, 2001 are as follows:

						Purchase
		Balance		Acquired		Price		Balance
		December 31, 2001		Goodwill		Adjustments		December 31, 2002
		(In thousands)
Natural gas gathering, processing, transportation, marketing and storage		$	394,054	$	—	$	521	$	394,575
NGL fractionation, transportation, marketing and trading			27,122		—		13,418		40,540
	Total consolidated	$	421,176	$	—	$	13,939	$	435,115

		Balance		Acquired		Amortization			Balance
		December 31, 2000		Goodwill		and Other			December 31, 2001
		(In thousands)
Natural gas gathering, processing, transportation, marketing and storage		$	376,195	$	53,799	$	(35,940	)	$	394,054
NGL fractionation, transportation, marketing and trading			—		28,053		(931	)		27,122
	Total consolidated	$	376,195	$	81,852	$	(36,871	)	$	421,176

     The gross carrying amount and accumulated amortization for NGLs sales and purchases contracts are as follows:

		For the Year Ended
		December 31,
		2002			2001
		(In thousands)
NGLs sales and purchases contracts		$	121,124		$	121,124
Less: Accumulated amortization			(36,820	)		(27,105	)
	NGLs sales and purchases contracts, net	$	84,304		$	94,019

     During the years ended December 31, 2002 and 2001, the Company recorded amortization expense associated with NGLs sales and purchases contracts of $9.7 million and $9.0 million, respectively. Estimated amortization for these contracts for the next five years is as follows:

	Estimated Amortization
	(in thousands)
2003	$	9,701
2004		8,128
2005		7,192
2006		7,192
2007		7,186
Thereafter		44,905
Total	$	84,304

     The Company adopted SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” on January 1, 2002. The new rules supersede SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of.” The new rules retain many of the fundamental recognition and measurement provisions of SFAS No. 121, but

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significantly change the criteria for classifying an asset as held-for-sale. Adoption of the new standard had no material effect on the Company’s consolidated results of operations or financial position.

     In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability is increased due to the passage of time based on the time value of money until the obligation is settled. The Company adopted the provisions of SFAS No. 143 as of January 1, 2003. In accordance with the transition provisions of SFAS No. 143, the Company recorded a cumulative-effect adjustment of $17.4 million as a reduction in 2003 earnings.

     Reclassifications — Certain prior period amounts have been reclassified in the Consolidated Financial Statements to conform to the current presentation.

3. Combination

     On March 31, 2000, the natural gas gathering, processing and NGL assets, operations, and subsidiaries of Duke Energy that existed at the time were contributed to Field Services LLC. In connection with the contribution of assets and subsidiaries at March 31, 2000, notes and advances payable to subsidiaries of Duke Energy were eliminated and contributed to equity. Also on March 31, 2000, ConocoPhillips contributed its then existing midstream natural gas gathering, processing and NGL operations to Field Services LLC. This contribution and Duke Energy’s contribution to Field Services LLC are referred to as the “Combination.” In connection with the Combination, the Company made one-time distributions to ConocoPhillips of $1,219.8 million and to Duke Energy of $1,524.5 million. In exchange for the contributions, and after the one-time distributions, Duke Energy received a 69.7% member interest in Field Services LLC, with ConocoPhillips holding the remaining 30.3% member interest.

     TEPPCO General Partner — On March 31, 2000, and in connection with the Combination, Duke Energy contributed the general partner of TEPPCO Partners, L.P. (“TEPPCO”) to Field Services LLC. In connection with the contribution of the general partner of TEPPCO, the Company recorded an investment in TEPPCO of $2.1 million and increased equity by $2.1 million.

     TEPPCO is a publicly traded master limited partnership that owns and operates a network of pipelines and storage and terminal facilities for refined products, liquefied petroleum gases, petrochemicals, natural gas gathering and crude oil. The general partner is responsible for TEPPCO’s management and operations. Because Field Services LLC owns the general partner of TEPPCO, it has the right to receive incentive cash distributions from TEPPCO in addition to a 2% share of distributions based on the general partner interest. At TEPPCO’s 2002 per unit distribution level, the general partner received approximately 25% of the cash distributed by TEPPCO to its partners. Due to the general partner’s share of unit distributions and degree of control exercised through its management of the partnership and other partnership governance issues, the Company’s investment in TEPPCO is accounted for under the equity method.

4. Acquisitions and Dispositions

     Acquisition of Discovery Producer Services — On May 31, 2002, the Company acquired 33.3% of the outstanding membership interests in Discovery Producer Services, LLC (“DPS”). The base purchase price of $71.0 million was adjusted for working capital and certain capital expenditures. This adjusted purchase price was then reduced by approximately $84.6 million of DPS debt guaranteed by the Company, resulting in the Company receiving cash of approximately $11.5 million on the closing date of the transaction. This investment is accounted for under the equity method of accounting. The pro forma impact of the acquisition on the Company’s results of operations was not material.

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     Acquisition of Additional Equity Interests — On July 10, 2001, the Company acquired additional interests in Mobile Bay Processing Partners, Gulf Coast NGL Pipeline, L.L.C. and Dauphin Island Gathering Partners from MCNIC Energy Enterprise Inc. (“MCNIC”) for approximately $66.2 million. This acquisition of additional interests has been accounted for under the purchase method of accounting. As a result, the Company has controlling interests in each of these entities, and the assets and liabilities and results of operations of the three affiliates have been consolidated in the Company’s financial statements since the date of the purchases with an offsetting amount recorded as minority interest. The pro forma impact of the acquisition on the Company’s results of operations was not material.

     Canadian Midstream Services, Ltd. — On May 1, 2001, the Company acquired the outstanding shares of Canadian Midstream Services, Ltd. (“CMSL”) for a purchase price of approximately $162.0 million. The purchase price included assumed debt of approximately $49.3 million. The acquisition was accounted for under the purchase method of accounting, and the assets and liabilities and results of operations of CMSL have been consolidated in the Company’s financial statements since the date of purchase. On a pro forma basis, revenues and net income for the year ended December 31, 2001 would have increased $7.8 million and $1.4 million, respectively, if the acquisition of CMSL had occurred on January 1, 2001. The following is a summary of the allocated purchase price (in millions):

Property, plant and equipment		$	139.0
Goodwill			53.7
Current assets			14.0
Current liabilities			(57.3	)
Other noncurrent liabilities			(35.9	)
	Total purchase price	$	113.5

     Gas Supply Resources, Inc. — On April 30, 2001, the Company acquired in a purchase transaction, Gas Supply Resources, Inc. (“GSRI”), a propane wholesaler located in the northeast, for approximately $45.0 million. The pro forma impact of the acquisition on the Company’s results of operations was not material. Goodwill of $28.1 million has been recorded as a result of allocating the purchase price to the individual assets and liabilities acquired.

     Disposition of NGL Pipeline Assets — On December 31, 2000, the Company sold NGL pipeline assets to TEPPCO for $91.0 million. The NGL pipeline assets sold included the Panola Pipeline and the San Jacinto Pipeline. TEPPCO also assumed the lease of a 34-mile condensate pipeline. A $12.0 million gain and a $3.2 million deferred gain were recorded in connection with the sale.

     Conoco and Mitchell Assets — On March 31, 2000, Field Services LLC acquired gathering and processing facilities located in central Oklahoma from Conoco, Inc. and Mitchell Energy & Development Corp. Field Services LLC paid cash of $99.8 million, and exchanged its interests in certain gathering and marketing joint ventures located in southeast Texas having a total fair value of $42.0 million as consideration for these facilities. The pro forma impact of the acquisition on the Company’s results of operations was not material.

5. Agreements and Transactions with Duke Energy

     Services Agreement with Duke Energy — In connection with the Combination, the Company entered into a services agreement with Duke Energy and some of its subsidiaries, dated March 14, 2000. Under this agreement, Duke Energy and those subsidiaries provide the Company with various staff and support services, including information technology products and services, payroll, employee benefits, insurance, cash management, ad valorem taxes, treasury, media relations, printing, records management, legal functions and investor services. These services are priced on the basis of a monthly charge which management believes approximates market prices. Additionally, the Company may use other Duke Energy services subject to hourly rates, including legal, insurance, internal audit, tax planning, human resources and security departments. This agreement, as amended, expires on December 31, 2003. Total expenditures, including capital spending, resulting from this agreement were $17.7 million, $10.0 million and $7.4 million in 2002, 2001 and 2000, respectively.

     License Agreement — In connection with the Combination, Duke Energy has licensed to the Company a non-exclusive right to use the phrase “Duke Energy” and its logo and certain other trademarks in identifying the Company’s businesses. This right may be terminated by Duke Energy at its sole option any time after Duke Energy’s direct or indirect ownership interest in the Company is less than or equal to 35%; or Duke Energy no longer controls, directly or indirectly, the management and policies of the Company.

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     Transactions between Duke Energy and the Company — The Company sells a portion of its residue gas and NGLs to, purchases raw natural gas and other petroleum products from, and provides gathering and transportation services to Duke Energy and its subsidiaries, including TEPPCO, at contractual prices that management believes approximated market prices in the ordinary course of the Company’s business. The Company anticipates continuing to purchase and sell these commodities and provide these services to Duke Energy in the ordinary course of business (see Note 2, “Significant Customers”). The Company’s total revenues from these activities, including amounts netted in trading and marketing net margin, were approximately $1,167.1 million, $1,648.5 million and $1,459.2 million for 2002, 2001 and 2000, respectively. The Company’s total purchases from these activities were approximately $161.6 million, $327.5 million and $420.6 million for 2002, 2001 and 2000, respectively.

6. Agreements and Transactions with ConocoPhillips

     Long Term NGLs Purchases Contract with ConocoPhillips — In connection with the Combination, the Company agreed to maintain the NGL Output Purchase and Sale Agreement (the “ConocoPhillips NGL Agreement”) between ConocoPhillips and the midstream natural gas assets that were contributed by ConocoPhillips to the Company in the Combination. Under the ConocoPhillips NGL Agreement, Phillips 66 Company, a wholly-owned subsidiary of ConocoPhillips, has the right to purchase at index-based prices substantially all NGLs produced by the processing plants which were contributed to the Company from ConocoPhillips in the Combination. The ConocoPhillips NGL Agreement also grants Phillips 66 Company, and subsequently Chevron Phillips Chemical Company, the right to purchase at index-based prices certain quantities of NGLs produced at processing plants that are acquired and/or constructed by the Company in the future in various counties in the Mid-Continent and Permian Basin regions, and the Austin Chalk area. The primary term of the agreement is effective until December 31, 2014.

     Transactions between ConocoPhillips and the Midstream Business Acquired from ConocoPhillips — Through March 31, 2000, the ConocoPhillips’ businesses (the “ConocoPhillips Combined Subsidiaries”) that owned the midstream natural gas assets that were contributed to the Company in the Combination had conducted a series of transactions with ConocoPhillips in which the ConocoPhillips Combined Subsidiaries sold a portion of their residue gas and other by-products to ConocoPhillips and its affiliate, CP Chem at contractual prices that the Company believes approximated market prices. In addition, the ConocoPhillips Combined Subsidiaries purchased raw natural gas from ConocoPhillips at contractual prices that the Company believes approximated market prices. The Company is continuing these transactions in the ordinary course of business. The Company’s total revenues from these activities, including amounts netted in trading and marketing net margin, were approximately $1,022.6 million, $1,309.5 million and $942.3 million for 2002, 2001 and 2000, respectively (see Note 2, “Summary of Significant Accounting Policies — Significant Customers”.) The Company’s total purchases from these activities, including amounts netted in trading and marketing net margin, were approximately $423.1 million, $491.1 million, and $340.7 million for 2002, 2001 and 2000, respectively.

7. Inventories

     A summary of inventories by category follows:

		December 31,
		2002		2001
		(In thousands)
Gas held for resale		$	29,827	$	32,553
NGLs			53,186		44,310
Materials and supplies			3,546		6,072
	Total inventories	$	86,559	$	82,935

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8. Property, Plant and Equipment

     A summary of property, plant and equipment by classification follows:

					December 31,
		Depreciation
		Rates			2002			2001
		(In thousands)
Gathering			4% - 6	%	$	2,437,487		$	2,308,905
Processing			4	%		1,995,743			1,786,431
Transmission			4	%		1,240,057			1,241,408
Underground storage			2% - 5	%		91,951			91,205
General plant			20% - 33	%		192,707			126,125
Construction work in progress						61,372			253,831
						6,019,317			5,807,905
	Accumulated depreciation					(1,377,113	)		(1,095,945	)
	Property, plant and equipment, net				$	4,642,204		$	4,711,960

     Asset Impairments — As part of the Company’s periodic asset performance evaluations, it was determined in December 2002 that certain gas plants and gathering systems have recently generated cash flow losses and are expected to continue to generate minimal or negative cash flows in future years. Accordingly, at December 31, 2002, the Company performed tests for recoverability on these assets in accordance with the requirements of SFAS No. 144 using probability weighted undiscounted future cash flow models. Based upon the results of these analyses, the Company determined that the carrying value of these assets was impaired and, accordingly, wrote them down to their fair value. Fair value was determined based on management’s best estimates of sales value and/or discounted future cash flow models. The charge associated with these impairments was $40.4 million for 2002 relating to the natural gas gathering, processing, transportation, marketing and storage segment.

     The Company’s revenues and expenses are significantly dependent on commodity prices such as NGLs and natural gas. Past and current trends in the price changes of these commodities may not be indicative of future trends. If negative market conditions persist over time and estimated cash flows over the lives of assets do not exceed the carrying value of those individual assets, asset impairments may occur in the future under existing accounting rules. Furthermore, a change in management’s intent about the use of individual assets could also impact an impairment analysis.

9. Investments in Affiliates

     The Company has investments in the following businesses accounted for using the equity method:

					December 31,
		2002
		Ownership			2002		2001
		(In thousands)
Discovery Producer Services, LLC			33.33	%	$	50,737	$	—
Mont Belvieu I			20.00	%		34,521		37,706
Sycamore Gas System General Partnership			48.45	%		17,051		18,803
Main Pass Oil Gathering			33.33	%		15,041		16,817
Tri-States NGL Pipeline, LLC			10.00	%		13,735		13,971
TEPPCO Partners, L.P.			2.00	%		12,177		13,401
Black Lake Pipeline			50.00	%		10,085		8,996
Fox Plant LLC			50.00	%		8,572		8,247
Other affiliates		Various				17,765		14,311
	Total investments in affiliates				$	179,684	$	132,252

     Discovery Producer Services, LLC— Discovery Producer Services, LLC owns and operates a 600 MMcf/d interstate pipeline, a condensate handling facility, a cryogenic gas processing plant, and other gathering assets in deepwater offshore Louisiana.

     Mont Belvieu I — Mont Belvieu I operates a 200 MBbl/d fractionation facility in the Mont Belvieu, Texas Market Center.

     Sycamore Gas System General Partnership — Sycamore Gas System General Partnership is a partnership formed for the purpose of constructing, owning and operating a gas gathering and compression system in Carter County, Oklahoma.

     Main Pass Oil Gathering — Main Pass Oil Gathering is a joint venture whose primary operation is a crude oil gathering pipeline system of 81 miles in the Main Pass East and Viosca Knoll Block areas in the Gulf of Mexico.

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     Tri-States NGL Pipeline, LLC — Tri-States NGL Pipeline, LLC owns 169 miles of NGL pipeline, extending from a point near Mobile Bay, Alabama to a point near Kenner, Louisiana.

     Black Lake Pipeline — Black Lake Pipeline owns a 317 mile long NGL pipeline, with a current capacity of approximately 40 MBbl/d. The pipeline receives NGLs from a number of gas plants in Louisiana and Texas. The NGLs are transported to Mont Belvieu fractionators.

     Fox Plant LLC — Fox Plant LLC is a limited liability company formed for the purpose of constructing, owning and operating a gathering facility and gas processing plant in Carter County, Oklahoma.

     Equity in earnings amounted to the following for the years ended December 31:

		2002			2001			2000
		(In thousands)
Discovery Producer Services, LLC		$	2,119		$	—		$	—
Mont Belvieu I			(1,422	)		(766	)		(501	)
Sycamore Gas System General Partnership			(299	)		(302	)		44
Main Pass Oil Gathering			5,134			3,768			2,973
TEPPCO Partners, L.P.			28,750			24,517			10,589
Tri-States NGL Pipeline, LLC			1,287			554			—
Black Lake Pipeline			1,639			1,322			1,833
Fox Plant LLC			324			202			508
Dauphin Island Gathering Partners (1)			—			1,287			3,835
Mobile Bay Processing Partners (1)			—			(971	)		2,413
Other affiliates			664			458			5,730
	Total equity earnings	$	38,196		$	30,069		$	27,424

     (1) On July 10, 2001, the Company acquired additional interests in Mobile Bay Processing Partners and Dauphin Island Gathering Partners. As a result of these acquisitions, the assets and liabilities and results of operations of these affiliates have been consolidated in the Company’s Consolidated Financial Statements since the date of the purchase (see Note 4).

     Distributions in excess of earnings were $15.7 million, $11.2 million and $16.1 million in 2002, 2001 and 2000, respectively.

     The following summarizes combined financial information of unconsolidated affiliates for the years ended December 31:

			2002			2001			2000
			(In thousands)
Income statement:
	Operating revenues		$	295,946		$	211,792		$	242,900
	Operating expenses			(229,100	)		(167,289	)		(216,334	)
	Net income			55,282			40,352			27,278
Balance sheet:
	Current assets		$	154,723		$	73,466
	Noncurrent assets			745,207			599,727
	Current liabilities			(69,327	)		(35,014	)
	Noncurrent liabilities			(190,455	)		(260,583	)
		Net assets	$	640,148		$	377,596

10. Income Taxes

     At March 31, 2000, the Company converted to a limited liability company which is a pass-through entity for U.S. income tax purposes. As a result, substantially all of the existing net deferred tax liability of $327.0 million was eliminated and a corresponding income tax benefit was recorded.

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     The Predecessor Company’s taxable income was included in a consolidated U.S. federal income tax return with Duke Energy until conversion to a limited liability company. Therefore, income tax for 2000 has been provided in accordance with Duke Energy’s tax allocation policy, which requires subsidiaries to calculate federal income tax as if separate taxable income, as defined, was reported.

     The Company owns corporations who file their own respective federal and state corporate income tax returns. The income tax expense related to these corporations is included in the income tax expense of the Company, along with other miscellaneous state, local and franchise taxes of the limited liability company and other subsidiaries. In addition, the Company has Canadian subsidiaries that are levied certain foreign taxes.

     Income tax as presented in the Statements of Operations is summarized as follows:

			Years Ended December 31,
			2002		2001		2000
			(In thousands)
Current:
	Federal		$	6,249	$	—	$	(5,066	)
	State			989		480		2,130
	Foreign			820		1,324		—
		Total current		8,058		1,804		(2,936	)
Deferred:
	Federal			944		—		(268,911	)
	State			1,007		979		(39,090	)
		Total deferred		1,951		979		(308,001	)
Total income tax expense			$	10,009	$	2,783	$	(310,937	)

11. Financing

     Credit Facility with Financial Institutions — In March 2000, Field Services LLC entered into a $2,800.0 million credit facility with several financial institutions. No amounts were ever borrowed under this facility. On April 3, 2000, Field Services LLC borrowed $2,790.9 million in the commercial paper market to fund one-time cash distributions of $1,524.5 million to Duke Energy and $1,219.8 million to ConocoPhillips, and to meet working capital requirements. These borrowings were subsequently paid down with proceeds from the issuance of debt securities and preferred financing (see below). The credit facility has since been replaced by a new $650.0 million revolving credit facility (the “Facility”), of which $150.0 million can be used for letters of credit. The Facility is used to support the Company’s commercial paper program and for working capital and other general corporate purposes. The Facility matures on March 28, 2003, however, any outstanding loans under the Facility at maturity may, at the Company’s option, be converted to a one-year term loan. The Facility requires the Company to maintain at all times a debt to total capitalization ratio of less than or equal to 53%. The Company entered into an amendment to the Facility on November 13, 2002. The Facility, as amended, bears interest at a rate equal to, at the Company’s option, either (1) London Interbank Borrowing Rate (“LIBOR”) plus 1.25% per year or (2) the higher of (a) the Bank of America prime rate and (b) the Federal Funds rate plus 0.50% per year. At December 31, 2002, there were no borrowings or letters of credit outstanding against the Facility. At December 31, 2002 and 2001, the Company had $215.1 million and $213.0 million in outstanding commercial paper, respectively, with maturities ranging from three to 30 days and annual interest rates ranging from 1.83% to 1.90%. The weighted average interest rate on the outstanding commercial paper was 1.89% and 2.53% as of December 31, 2002 and 2001, respectively. The amount of the Company’s outstanding commercial paper never exceeded the available amount under the Facility.

     Preferred Financing — In August 2000, the Company issued $300.0 million of preferred member interests to affiliates of Duke Energy and ConocoPhillips in proportion to their ownership interests. The proceeds from this financing were used to repay a portion of the Company’s outstanding commercial paper. The preferred member interests are entitled to cumulative preferential distributions of 9.5% per annum payable, unless deferred, semi-annually. The Company has the right to defer payments of preferential distributions on the preferred member interests, other than certain tax distributions, at any time, for up to 10 consecutive semiannual periods. Deferred preferred distributions will accrue additional amounts based on the preferential distribution rate (plus 0.5% per annum) to the date of payment. The preferred member interests, together with all accrued and unpaid preferential distributions, must be redeemed and paid on the earlier of the thirtieth anniversary date of issuance or consummation of an initial public offering of equity securities. On September 9, 2002, the Company redeemed $100.0 million of its preferred member interests by paying cash to each member in proportion to their ownership interests. For the years ended December 31, 2002 and 2001, the Company has paid preferential distributions of $25.5 million and $28.5 million, respectively. There are no outstanding deferred preferential distributions.

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     Debt Securities — Long term debt at December 31, 2002 and 2001 was as follows (in thousands):

	Principal/Discount
								Interest
	2002			2001			Issue Date	Rate			Due Date
Debt Securities	$	600,000		$	600,000		August 16, 2000		7 1/2	%	August 16, 2005
		800,000			800,000		August 16, 2000		7 7/8	%	August 16, 2010
		300,000			300,000		August 16, 2000		8 1/8	%	August 16, 2030
		250,000			250,000		February 2, 2001		6 7/8	%	February 1, 2011
		300,000			300,000		November 9, 2001		5 3/4	%	November 15, 2006
Interest rate swap		14,258			(4,659	)
Capitalized leases		2,697			3,288
Unamortized discount		(11,447	)		(13,595	)
Net long term debt	$	2,255,508		$	2,235,034

     The notes mature and become payable on the respective due dates, and are not subject to any sinking fund provisions. Debt securities maturing over the next five years include $600.0 million in 2005 and $300.0 million in 2006. Interest is payable semiannually. The notes are redeemable at the option of the Company. The Company used the proceeds from the issuance of the debt securities to repay short term commercial paper borrowings.

     In October 2001, the Company entered into an interest rate swap to convert the fixed interest rate on $250.0 million of debt securities that were issued in August 2000 to floating rate debt. The interest rate fair value hedge is at a floating rate based on 6-month LIBOR rates, which is re-priced semiannually through 2005.

12. Derivative Instruments, Hedging Activities and Credit Risk

     Commodity price risk — The Company’s principal operations of gathering, processing, transportation and storage of natural gas, and the accompanying operations of fractionation, transportation, trading and marketing of NGLs create commodity price risk exposure due to market fluctuations in commodity prices, primarily with respect to the prices of NGLs, natural gas and crude oil. As an owner and operator of natural gas processing and other midstream assets, the Company has an inherent exposure to market variables and commodity price risk. The amount and type of price risk is dependent on the underlying natural gas contracts entered into to purchase and process raw natural gas. Risk is also dependent on the types and mechanisms for sales of natural gas and NGLs and related products produced, processed, transported or stored.

     Energy trading (market) risk — Certain of the Company’s subsidiaries are engaged in the business of trading energy related products and services including managing purchase and sales portfolios, storage contracts and facilities, and transportation commitments for products. These energy trading operations are exposed to market variables and commodity price risk with respect to these products and services, and may enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments.

     Corporate economic risks — The Company enters into debt arrangements that are exposed to market risks related to changes in interest rates. The Company periodically uses interest rate lock agreements and interest rate swaps to hedge interest rate risk associated with new debt issuances. The Company’s primary goals include (1) maintaining an appropriate ratio of fixed-rate debt to total debt for the Company’s debt rating; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates based on historical rates.

     Counterparty risks — The Company sells various commodities (i.e., natural gas, NGLs and crude oil) to a variety of customers. The natural gas customers include local utilities, industrial consumers, independent power producers and merchant energy trading organizations. The NGLs customers range from large, multi-national petrochemical and refining companies to small regional retail propane distributors. Substantially all of the Company’s NGLs sales are made at market-based prices, including approximately 40% of NGLs production that is committed to ConocoPhillips and Chevron Phillips Chemical LLC, under a contract with a primary term that expires on January 1, 2015. This concentration of credit risk may affect the Company’s overall credit risk in that these customers may be similarly affected by changes in economic, regulatory or other factors. On all transactions where the Company is exposed to credit risk, the Company analyzes the counterparties’ financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of these limits on an ongoing basis. The corporate credit policy prescribes the use of master collateral agreements to mitigate credit exposure. The collateral agreements provide for a counterparty to post cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an open credit limit, determined in accordance with

55

the corporate credit policy. The collateral agreements also provide that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions.

     Physical forward contracts and financial derivatives are generally cash settled at the expiration of the contract term. These transactions are generally subject to specific credit provisions within the contracts that would allow the seller, at its discretion, to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment satisfactory to the seller.

     Commodity cash flow hedges — The Company uses cash flow hedges, as specifically defined by SFAS No. 133, to reduce the potential negative impact that commodity price changes could have on the Company’s earnings, and its ability to adequately plan for cash needed for debt service, dividends, capital expenditures and tax distributions. The Company’s primary corporate hedging goals include maintaining minimum cash flows to fund debt service, dividends, production replacement, maintenance capital projects and tax distributions; and retaining a high percentage of potential upside relating to price increases of NGLs.

     The Company uses natural gas, crude oil and NGLs swaps and options to hedge the impact of market fluctuations in the price of NGLs, natural gas and other energy-related products. For the year ended December 31, 2002, the Company recognized a net loss of $27.2 million, of which $9.7 million represented the total ineffectiveness of all cash flow hedges and $16.1 million represented the total derivative settlements. The time value of options was excluded in the assessment of hedge effectiveness.For the year ended December 31, 2002, a $1.4 million loss related to the time value of options is included in Sales of Natural Gas and Petroleum Products in the Consolidated Statements of Operations. No derivative gains or losses were reclassified from OCI to current period earnings as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.

     Gains and losses on derivative contracts that are reclassified from accumulated OCI to current period earnings are included in the line item in which the hedged item is recorded. As of December 31, 2002, $57.1 million of deferred net losses on derivative instruments accumulated in OCI are expected to be reclassified into earnings during the next 12 months as the hedge transactions occur; however, due to the volatility of the commodities markets, the corresponding value in OCI is subject to change prior to its reclassification into earnings. The maximum term over which the Company is hedging its exposure to the variability of future cash flows is three years.

     Commodity fair value hedges — The Company uses fair value hedges to hedge exposure to changes in the fair value of an asset or a liability (or an identified portion thereof) that is attributable to price risk. The Company may hedge producer price locks (fixed price gas purchases) and market locks (fixed price gas sales) to reduce the Company’s exposure to fixed price risk via swapping out the fixed price risk for a floating price position (New York Mercantile Exchange or index based).

     For the year ended December 31, 2002, the gains or losses representing the ineffective portion of the Company’s fair value hedges were not material. All components of each derivative’s gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted. The Company did not have any firm commitments that no longer qualified as fair value hedge items and therefore, did not recognize an associated gain or loss.

     Interest rate fair value hedge — In October 2001, the Company entered into an interest rate swap to convert the fixed interest rate on $250.0 million of debt securities that were issued in August 2000 to floating rate debt. The interest rate fair value hedge is at a floating rate based on a six-month LIBOR, which is re-priced semiannually through 2005. The swap meets conditions which permit the assumption of no ineffectiveness, as defined by SFAS 133. As such, for the life of the swap no ineffectiveness will be recognized. As of December 31, 2002, the fair value of the interest rate swap of $14.3 million gain was included in the Consolidated Balance Sheets as Unrealized Gains or Losses on Trading and Hedging Transactions with an offset to the underlying debt included in Long Term Debt.

     Commodity Derivatives — Trading — The trading of energy related products and services exposes the Company to the fluctuations in the market values of traded instruments. The Company manages its traded instrument portfolio with strict policies which limit exposure to market risk and require daily reporting to management of potential financial exposure. These policies include statistical risk tolerance limits using historical price movements to calculate a daily earnings at risk measurement.

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13. Estimated Fair Value of Financial Instruments

     The following fair value amounts have been determined by the Company using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that the Company could realize in a current market exchange. The use of different market assumptions and/or estimation methods may have a material effect on the estimated fair value amounts.

	December 31, 2002						December 31, 2001
	Carrying			Estimated Fair			Carrying			Estimated Fair
	Amount			Value			Amount			Value
	(In thousands)
Accounts receivable	$	836,159		$	836,159		$	887,449		$	887,449
Accounts payable		(761,621	)		(761,621	)		(722,628	)		(722,628	)
Natural gas, NGLs and oil hedge and trading contracts		(80,229	)		(80,229	)		85,684			85,684
Short term debt		(215,094	)		(215,094	)		(212,955	)		(212,955	)
Long term debt		(2,255,508	)		(2,447,511	)		(2,235,034	)		(2,342,795	)

     The fair value of accounts receivable, accounts payable and short term debt are not materially different from their carrying amounts because of the short term nature of these instruments or the stated rates approximating market rates.

     Notes receivable are carried in the accompanying balance sheet at cost.

     The estimated fair value of the natural gas, NGLs and oil hedge contracts is determined by multiplying the difference between the quoted termination prices for natural gas, NGLs and oil and the hedge contract prices by the quantities under contract. The estimated fair value of options is determined by the Black-Scholes options valuation model.

     The estimated fair value of long term debt is determined by prices obtained from market quotes.

14. Commitments and Contingent Liabilities

     Litigation — The midstream natural gas industry has seen a number of class action lawsuits involving royalty disputes, mismeasurement and mispayment allegations. Although the industry has seen these types of cases before, they were typically brought by a single plaintiff or small group of plaintiffs. A number of these cases are now being brought as class actions. The Company and its subsidiaries are currently named as defendants in some of these cases. Management believes the Company and its subsidiaries have meritorious defenses to these cases, and therefore will continue to defend them vigorously. However, these class actions can be costly and time consuming to defend.

     Management believes that the final disposition of these proceedings will not have a material adverse effect on the consolidated results of operations or financial position of the Company.

     Other Commitments and Contingencies — The Company utilizes assets under operating leases in several areas of operation. Combined rental expense amounted to $9.2 million, $11.1 million and $13.8 million in 2002, 2001 and 2000, respectively. Minimum rental payments under the Company’s various operating leases for the years 2003 through 2007 are $7.9 million, $5.7 million, $5.5 million, $3.6 million and $2.0 million, respectively. Thereafter, payments aggregate $4.8 million through 2011.

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15. Stock-Based Compensation

     Duke Energy applies APB Opinion No. 25, “Accounting for Stock Issued to Employees” and related Interpretations in accounting for the stock-based compensation plans described below. Accordingly, no compensation expense has been recognized for stock options. The following table illustrates the effect on (deficit) earnings available for members’ interest if Duke Energy had applied the fair value recognition provisions of FASB Statement No. 123, “Accounting for Stock-Based Compensation” to all stock-based compensation awards.

	Year Ended December 31
	(In thousands)
	2002			2001			2000
(Deficit) Earnings Available for Members’ Interest, as reported	$	(72,095	)	$	335,407		$	668,444
Add: stock-based compensation expense included in reported net income, net of related tax effects		750			591			1,137
Deduct: Total stock-based compensation expense determined under fair value based method for all awards, net of related tax effects
Pro forma (Deficit) Earnings		(3,593	)		(2,909	)		(2,975	)
Available for Members’
Interest, net of tax effects	$	(74,938	)	$	333,089		$	666,606

     Under Duke Energy’s 1998 Long Term Incentive Plan, stock options for Duke Energy’s common stock may be granted to the Company’s key employees. Under the plan, the exercise price of each option granted cannot be less than the market price of Duke Energy’s common stock on the date of grant. Vesting periods range from one to five years with a maximum term of 10 years.

     On December 20, 2000, Duke Energy announced a two-for-one common stock split effective January 26, 2001, to shareholders of record on January 3, 2001. The following option information has been restated to reflect the stock split, and appropriate adjustments have been made in the exercise price and number of shares subject to stock options.

     The following tables show information regarding options to purchase Duke Energy’s common stock granted to employees of the Company.

Stock Option Activity

					Weighted-
					Average
		Options			Exercise
		(in thousands)			Price
Outstanding at December 31, 1999			2,522		$	26
	Granted		837			41
	Exercised		(568	)		22
	Forfeited		(223	)		27
Outstanding at December 31, 2000			2,568			31
	Granted		815			38
	Exercised		(251	)		27
	Forfeited		(144	)		32
Outstanding at December 31, 2001			2,988			33
	Granted		68			37
	Exercised		(79	)		25
	Forfeited		(108	)		35
Outstanding at December 31, 2002			2,869		$	33

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Stock Options at December 31, 2002

			Outstanding						Exercisable
					Weighted-		Weighted-				Weighted-
					Average		Average				Average
Range of			Number		Remaining		Exercise		Number		Exercise
Exercise Prices			(in thousands)		Life (Years)		Price		(in thousands)		Price
$8 to $10				9		2.1	$	10		9	$	10
$11 to $16				20		2.4		12		20		12
$17 to $22				16		4.1		22		16		22
$23 to $28				1,153		6.4		26		855		26
$29 to $34				190		6.9		30		120		30
$35 to $40				825		9.0		38		227		38
	> $40			656		8.0		43		328		43
		Total		2,869		7.5		33		1,575		31

     On December 31, 2002, there were approximately 1,575,000 exercisable options outstanding with a $31 weighted-average exercise price. On December 31, 2001, there were approximately 813,000 outstanding options exercisable with a weighted-average exercise price of $29 per option.

     The weighted-average fair value of options granted was $10 per option during 2002, 2001 and 2000. The fair value of each option granted was estimated on the date of grant using the Black-Scholes options valuation model.

Weighted-Average Assumptions for Option-Pricing

	2002			2001			2000
Stock dividend yield		3.3	%		3.4	%		3.7	%
Expected stock price volatility		30.5	%		29.7	%		25.1	%
Risk-free interest rates		5.1	%		5.0	%		5.3	%
Expected option lives	7 years			7 years			7 years

     Duke Energy granted performance awards of Duke Energy common stock to key employees of the Predecessor Company under the 1998 Long Term Incentive Plan (the “1998 Plan”). Performance awards under the 1998 plan vest over periods ranging from three to seven years. Vesting can occur in year three, at the earliest if performance is met. Duke Energy did not award any performance awards in 2002, 2001 or 2000. Compensation expense for the performance grants is charged to the Company’s earnings over the vesting period and amounted to approximately $216,000, $217,000, and $1.2 million, in 2002, 2001, and 2000, respectively.

     Duke Energy granted phantom shares of Duke Energy common stock to employees of the Predecessor Company under the 1998 Plan. Phantom stock awards under the 1998 Plan vest over periods ranging from one to four years. Duke Energy did not award any phantom awards in 2002. Duke awarded 34,190 shares (fair value of approximately $1.3 million at grant dates) in 2001 and 13,100 shares (fair value of approximately $0.6 million at grant date) in 2000. Compensation expense for the stock grants is charged to the Company’s earnings over the vesting period, and amounted to approximately $750,000 and $300,000 in 2002 and 2001, respectively. Compensation expense for the stock grants in 2000 was immaterial.

     In addition, Duke Energy granted restricted shares of Duke Energy common stock to key employees of the Predecessor Company under the 1996 Stock Incentive Plan. Restricted stock grants under the 1996 plan vest over periods ranging from one to five years. No restricted shares were awarded in 2002 or 2001. Duke Energy awarded 28,526 restricted shares (fair value of approximately $822,000 at grant dates) in 2000. Compensation expense for the stock grants is charged to the Company’s earnings over the vesting period, and amounted to approximately $191,000, $418,000 and $402,000 in 2002, 2001 and 2000, respectively.

16. Pension and Other Benefits

     Effective April 1, 2000, the Company’s employees began participation in the Company’s 401(k) and retirement plan in which the Company contributes 4% of each eligible employee’s qualified earnings. Additionally, the Company matches employees’ contributions in the plan up to 6% of qualified earnings. During 2002, 2001 and 2000, the Company expensed plan contributions of $13.8 million, $14.1 million and $8.9 million, respectively.

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     Prior to April 1, 2000, employees of the Predecessor Company participated in Duke Energy’s non-contributory trustee pension plan, which covered eligible employees with minimum service requirements using a cash balance formula. Duke Energy’s policy is to fund amounts, as necessary, on an actuarial basis to meet benefits to be paid to plan members. Aspects of the plan specific to the Predecessor Company are as follows:

     Components of Net Periodic Pension Costs

	Year Ended
	December 31, 2000
	(In thousands)
Service cost benefit earned during year	$	480
Interest cost on projected benefit obligation		460
Expected return on plan assets		(674	)
Amortization of net transition asset		(21	)
Amortization of prior service cost		8
Recognized actuarial loss		—
Net periodic pension cost		253
Impact of terminating plan participation		483
Total pension cost	$	736

     Assumptions Used for Pension Benefit Accounting

	Year Ended
	December 31, 2000
Discount rate		7.50	%
Rate of increase in compensation levels		4.53	%
Expected long term rate of return on plan assets		9.25	%

     Duke Energy also sponsored, and the Predecessor Company participated in, an employee savings plan. Predecessor Company employees became ineligible to participate in the plan on March 31, 2000 in connection with the Combination.

     The Company offers certain eligible executives the opportunity to participate in the Duke Energy Field Services’, LP Non-Qualified Executive Deferred Compensation Plan. This plan allows participants to defer current compensation on a pre-tax basis and to receive tax deferred earnings on such contributions. The plan also has make whole provisions for plan participants who may otherwise be limited in the amount that the Company can contribute to the 401(k) plan on the participant’s behalf. All amounts contributed to or earned by the plan’s investments are held in a trust account for the benefit of the participants. The trust is part of the general assets of the Company. Total Company expense for this plan was $1.3 million, $1.9 million and $1.5 million in 2002, 2001 and 2000, respectively.

17. Business Segments

     The Company operates in two principal business segments: (1) natural gas gathering, treatment, processing, transportation, trading and marketing and storage, and (2) NGL fractionation, transportation, marketing and trading. These segments are monitored separately by management for performance against its internal forecast and are consistent with the Company’s internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Margin, earnings before interest, taxes, depreciation and amortization (“EBITDA”) and earnings before interest and taxes (“EBIT”) are the performance measures utilized by management to monitor the business of each segment. The accounting policies for the segments are the same as those described in Note 2. Foreign operations are not material and are therefore not separately identified.

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     The following table sets forth the Company’s segment information.

			Years Ended December 31,
			2002			2001			2000
			(In thousands)
Operating revenues:
	Natural gas, including trading and marketing net margin		$	5,498,640		$	7,760,535		$	7,036,003
	NGLs, including trading and marketing net margin			1,399,975			2,536,171			757,178
	Intersegment(a)			(1,407,059	)		(2,272,012	)		(1,594,757	)
		Total operating revenues	$	5,491,556		$	8,024,694		$	6,198,424
Margin:
	Natural gas, including trading and marketing net margin		$	996,046		$	1,228,344		$	1,169,286
	NGLs, including trading and marketing net margin			55,139			55,456			48,662
		Total margin	$	1,051,185		$	1,283,800		$	1,217,948
Other operating costs:
	Natural gas		$	484,201		$	364,664		$	329,054
	NGLs			9,813			7,536			(8,142	)(c)
	Corporate			167,115			129,968			171,154
		Total other operating costs	$	661,129		$	502,168		$	492,066
Equity in earnings of unconsolidated affiliates:
	Natural gas		$	36,811		$	28,899		$	25,554
	NGLs			1,385			1,170			1,870
		Total equity in earnings of unconsolidated affiliates	$	38,196		$	30,069		$	27,424
EBITDA(b):
	Natural gas		$	548,656		$	892,579		$	865,786
	NGLs			46,711			49,090			58,674
	Corporate			(167,115	)		(129,968	)		(171,154	)
		Total EBITDA	$	428,252		$	811,701		$	753,306
Depreciation and amortization:
	Natural gas		$	283,898		$	264,445		$	218,593
	NGLs			11,242			10,077			12,636
	Corporate			3,813			4,408			3,633
		Total depreciation and amortization	$	298,953		$	278,930		$	234,862
EBIT(b):
	Natural gas		$	264,758		$	628,134		$	647,193
	NGLs			35,469			39,013			46,038
	Corporate			(170,928	)		(134,376	)		(174,787	)
		Total EBIT	$	129,299		$	532,771		$	518,444
Corporate interest expense			$	165,841		$	165,670		$	149,220
(Loss) income before income taxes:
	Natural gas		$	264,758		$	628,134		$	647,193
	NGLs			35,469			39,013			46,038
	Corporate			(336,769	)		(300,046	)		(324,007	)
		Total (loss) income before income taxes	$	(36,542	)	$	367,101		$	369,224
Capital Expenditures:
	Natural gas		$	279,105		$	565,515		$	356,657
	NGLs			9,322			10,911			1,284
	Corporate			13,204			20,944			13,122
		Total Capital Expenditures	$	301,631		$	597,370		$	371,063

			As of December 31,
			2002		2001
			(In thousands)
Total assets:
	Natural gas		$	5,190,492	$	5,326,889
	NGLs			293,398		258,177
	Corporate(d)			1,096,545		1,045,143
		Total assets	$	6,580,435	$	6,630,209

(a) Intersegment sales represent sales of NGLs from the Natural Gas Segment to the NGLs Segment at either index prices or weighted average prices of NGLs. Both measures of intersegment sales are effectively based on current economic market conditions.

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(b)	EBITDA consists of income from continuing operations before interest expense, income tax expense, and depreciation and amortization expense. EBIT is EBITDA less depreciation and amortization. These measures are not a measurement presented in accordance with generally accepted accounting principles and should not be considered in isolation from or as a substitute for net income or cash flow measures prepared in accordance with generally accepted accounting principles or as a measure of the Company’s profitability or liquidity. The measures are included as a supplemental disclosure because it may provide useful information regarding the Company’s ability to service debt and to fund capital expenditures. However, not all EBITDA or EBIT may be available to service debt. This measure may not be comparable to similarly titled measures reported by other companies.
(c)	Other operating cost for NGLs in 2000 include a gain on sale of NGL Pipeline Assets of $12 million.
(d)	Includes items such as unallocated working capital, intercompany accounts and intangible and other assets.

18. Guarantor’s Obligations Under Guarantees

     At December 31, 2002, the Company was the guarantor of approximately $100.5 million of debt associated with unconsolidated subsidiaries, of which $84.5 million is related to our 33.3% ownership interest in Discovery Producer Services, LLC. These guarantees expire December 31, 2003. The debt related to Discovery Producer Services, LLC is due December 31, 2003, and is expected to be refinanced. In the event that the unconsolidated subsidiaries default on the debt payments, the Company would be required to pay the debt. Assets of the unconsolidated subsidiaries are pledged as collateral for the debt. At December 31, 2002, the Company had no liability recorded for the guarantees of the debt associated with the unconsolidated subsidiaries.

     At December 31, 2002, the Company has various indemnification agreements outstanding contained in asset purchase and sale agreements. These indemnification agreements generally relate to changes in environmental and tax laws or settlement of outstanding litigation. These indemnification agreements generally have terms of one to five years, although some are longer. The Company cannot estimate the maximum potential amount of future payments under these indemnification agreements due to the uncertainties related to changes in laws and regulations with regard to taxes, safety and protection of the environment or the settlement of outstanding litigation, which are outside the Company’s control. In addition, many of these indemnification agreements do not contain any limits on potential liability.

     Management believes that it is not probable that the Company would be required to perform or incur any significant losses associated with the guarantees and indemnities discussed above and has, therefore, not recorded any liabilities for contingent losses at December 31, 2002.

19. Accounting Adjustments

     The Company has completed a comprehensive account reconciliation project to review and analyze its balance sheet accounts. This account reconciliation project identified the following five categories where account adjustments were necessary: operating expense accruals; gas inventory adjustments; gas imbalances; joint venture and investment account reconciliation; and other balance sheet accounts. As a result of this account reconciliation project, the Company recorded numerous adjustments in 2002. Adjustments totaling approximately $53 million may be related to corrections of accounting errors in prior periods. However, management has determined that the charges related to error corrections are immaterial both individually and in the aggregate on both a quantitative and qualitative basis to the trends in the financial statements for the periods presented, the prior periods affected and to a fair presentation of the Company’s financial statements. In addition, numerous items identified in the account reconciliation project resulted from system conversions and otherwise unsupportable balance sheet amounts. Due to the nature of certain of these account reconciliation adjustments, it would be impractical to determine what periods such adjustments relate to. Accordingly, the corrections have been made in the current year’s financial statements.

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20. Quarterly Financial Data (Unaudited)

		First			Second			Third		Fourth
		Quarter			Quarter			Quarter		Quarter			Total
		(In thousands)
2002
	Operating revenue	$	1,132,274		$	1,365,571		$	1,307,623	$	1,686,088		$	5,491,556
	Operating income		24,999			19,092			40,614		6,398			91,103
	Net (loss) income		(17,000	)		(21,344	)		12,040		(20,247	)		(46,551	)
2001
	Operating revenue	$	2,957,530		$	1,963,408		$	1,423,138	$	1,680,618		$	8,024,694
	Operating income		179,688			145,393			114,672		62,949			502,702
	Net income		142,378			115,642			78,836		27,051			363,907

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DUKE ENERGY FIELD SERVICES, LLC

Schedule II — Valuation and Qualifying Accounts and Reserves

				Additions
		Balance at				Charged to			Principal Cash			Balance at
		Beginning		Charged to		Other			Payments and Reserve			End of
		of Period		Expenses		Accounts(b)			Reversals			Period
December 31, 2002:
	Allowance for doubtful accounts	$	5.9	$	.4	$	1.8		$	—		$	8.1
	Environmental		40.0		—		1.1			(15.1	)		26.0
	Litigation		7.5		1.5		—			(5.0	)		4.0
	Other(a)		12.1		30.5		(10.9	)		(22.3	)		9.4
		$	65.5	$	32.4	$	(8.0	)	$	(42.4	)	$	47.5
December 31, 2001:
	Allowance for doubtful accounts	$	3.6	$	3.3	$	—		$	(1.0	)	$	5.9
	Environmental		38.7		—		8.9			(7.6	)		40.0
	Litigation		28.7		—		1.2			(22.4	)		7.5
	Other(a)		18.6		—		16.2			(22.7	)		12.1
		$	89.6	$	3.3	$	26.3		$	(53.7	)	$	65.5
December 31, 2000:
	Allowance for doubtful accounts	$	6.7	$	1.2	$	—		$	(4.3	)	$	3.6
	Environmental		15.7		.7		26.5			(4.2	)		38.7
	Litigation		10.9		—		20.0			(2.2	)		28.7
	Other(a)		19.5		—		2.6			(3.5	)		18.6
		$	52.8	$	1.9	$	49.1		$	(14.2	)	$	89.6

(a)	Principally consists of other contingency reserves which are included in “Other Current Liabilities” or “Other Long Term Liabilities.”
(b)	Principally consists of environmental, litigation and other contingency reserves assumed in business acquisitions and combinations.

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INDEPENDENT AUDITORS’ REPORT

To the Board of Directors and Members of
Duke Energy Field Services, LLC

     We have audited the accompanying consolidated balance sheets of Duke Energy Field Services, LLC and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of operations, comprehensive (loss) income, members’ equity, and cash flows for each of the three years in the period ended December 31, 2002. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule 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, such consolidated financial statements present fairly, in all material respects, the financial position of Duke Energy Field Services, LLC and subsidiaries at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

     As discussed in Note 2 to the Consolidated Financial Statements, in 2002 the Company changed its method of accounting for goodwill to conform to Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets and in 2001 the Company changed its method of accounting for derivative instruments and hedging activities to conform to Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities.

DELOITTE & TOUCHE LLP

Denver, Colorado
March 12, 2003

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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 following table provides information regarding our directors and executive officers:

Name	Age		Position
Jim W. Mogg		54	Director and Chairman of the Board, President and Chief Executive Officer
Mark A. Borer		48	Executive Vice President, Marketing and Corporate Development
Michael J. Bradley		48	Executive Vice President, Gathering and Processing
Robert F. Martinovich		45	Senior Vice President, Northern Division
Rose M. Robeson		42	Vice President and Chief Financial Officer
Brent L. Backes		43	Vice President, General Counsel and Secretary
William W. Slaughter		55	Executive Vice President
Philip L. Frederickson		46	Director
Fred J. Fowler		57	Director
John E. Lowe		44	Director
Richard J. Osborne		52	Director

     Jim W. Mogg is Chairman of the Board, President and Chief Executive Officer of our company. Mr. Mogg also serves as Senior Vice President — Field Services for Duke Energy. Mr. Mogg was President and Chief Executive Officer of the Predecessor Company from 1994 until the Combination. Mr. Mogg is also a director, Chairman of the Board and Chairman of the Compensation Committee of the general partner of TEPPCO. Mr. Mogg has been in the energy industry since 1973.

     Fred J. Fowler, a Director of our company, is President and Chief Operating Officer of Duke Energy and has held that position since November 2002. Mr. Fowler previously served as Group President — Energy Transmission of Duke Energy from 1997 to 2002. From 1996 to 1997, Mr. Fowler served as Group Vice President of Pan Energy. From 1994 until 1996, Mr. Fowler served as President of Texas Eastern Transmission Corporation. Mr. Fowler is a member of our Audit Committee. Mr. Fowler has been in the energy industry since 1968.

     Richard J. Osborne, a Director of our company, is the Executive Vice President and Chief Risk Officer of Duke Energy. Mr. Osborne is also responsible for the Duke Ventures Group of non-energy businesses. Mr. Osborne served as the Executive Vice President and Chief Financial Officer of Duke Energy from 1997 to 2000. From 1994 to 1997, Mr. Osborne served as Senior Vice President and Chief Financial Officer of Duke Power. From 1991 to 1994, he served as Vice President and Chief Financial Officer of Duke Power. Mr. Osborne has been in the energy industry since 1975.

     Philip L. Frederickson, a Director of our company, is the Executive Vice President, Commercial for ConocoPhillips. Mr. Frederickson previously served as Senior Vice President of Corporate Strategy and Business Development of Conoco Inc. from 2001 to 2002. From 1998 to 2001, Mr. Frederickson served as Vice President, Business Development of Conoco Inc.. From 1997 to 1998, he served as General Manager, Strategy and Portfolio Management, Upstream of Conoco Inc.

     John E. Lowe, a Director of our company, is the Executive Vice President, Planning and Strategic Transactions for ConocoPhillips. Mr. Lowe previously served as the Senior Vice President of Corporate Strategy and Development of Phillips Petroleum Company from 2001 to 2002 and as Senior Vice President of Planning and Strategic Transactions of Phillips Petroleum Company from 2000 to 2001. From 1999 to 2000, Mr. Lowe served as Vice President of Planning and Strategic Transactions of Phillips Petroleum Company. During 1999 before being appointed Vice President, Planning & Strategic Transactions, Mr. Lowe served as Manager, Strategic Growth Projects. From 1997 to 1999, Mr. Lowe served as Supply Chain Manager for Refining, Marketing and Transportation of Phillips Petroleum Company. From 1993 to 1997 he served as either Director or Manager of Finance for Phillips Petroleum Company. Mr. Lowe is a member of our Audit Committee. Mr. Lowe has been in the energy industry since 1981.

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     William W. Slaughter is Executive Vice President of our company. Mr. Slaughter held the position of Advisor to the Chief Executive Officer of the Predecessor Company from 1998 until his appointment as Executive Vice President in 2000. From 1997 until 1998, Mr. Slaughter was Vice President of Energy Services for Duke Energy. From 1994 until 1997, Mr. Slaughter served as Vice President of Corporate Strategic Planning for PanEnergy and President of PanEnergy International Development Corporation. Mr. Slaughter is also a director of the general partner of TEPPCO. Mr. Slaughter has been in the energy industry since 1970.

     Rose M. Robeson was named Vice President and Chief Financial Officer of our company in January 2002. Ms. Robeson joined the Company in May 2000 as Vice President and Treasurer. She was previously Vice President and Treasurer of Kinder Morgan, Inc. (formerly KN Energy, Inc.) from April 1998 to April 2000 and Assistant Treasurer of Kinder Morgan, Inc. from August 1996 to April 1998. Ms. Robeson has been in the energy industry since 1987.

     Robert F. Martinovich was named Senior Vice President, Northern Division of our Company in July 2002. Mr. Martinovich joined the Company in April 2000 as Senior Vice President, Western Division. He was Senior Vice President of GPM Gas Corporation, a subsidiary of Phillips Petroleum Company, from 1999 until the Combination. From 1996 until 1999, Mr. Martinovich was Vice President, Oklahoma Region for GPM Gas Corporation, and from 1994 until 1996, he was Business Development Manager for GPM Gas Corporation. Mr. Martinovich has been in the energy industry since 1980.

     Michael J. Bradley was named Executive Vice President, Gathering and Processing of our company in April 2002. He was previously Senior Vice President, Northern Division since 1999. Mr. Bradley is also a director of the general partner of TEPPCO. Mr. Bradley has been in the energy industry since 1979.

     Mark A. Borer was named Executive Vice President, Marketing and Corporate Development of our company in April 2002. Mr. Borer joined the Predecessor Company in April 1999 as Senior Vice President, Southern Division. From 1992 until 1999, Mr. Borer served as Vice President of Natural Gas Marketing for Union Pacific Fuels, Inc. Mr. Borer is also a director of the general partner of TEPPCO. Mr. Borer has been in the energy industry since 1978.

     Brent L. Backes was named Vice President, General Counsel and Secretary of our company in January 2002. Mr. Backes joined the Predecessor Company in April 1998 as Senior Attorney. He was previously Senior Associate Attorney at LeBoeuf, Lamb, Greene & MacRae, LLP. Mr. Backes has been in the energy industry since 1998 and prior to that represented energy companies in various capacities while in private practice.

     Pursuant to our limited liability company agreement, we have five directors, two of which are appointed by ConocoPhillips and three of which are appointed by Duke Energy.

     There are no family relationships between any of the executive officers nor any arrangement or understanding between any executive officer and any other person pursuant to which the officer was selected.

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ITEM 11. Executive Compensation.

     The following table sets forth compensation information for the years ended December 31, 2000, December 31, 2001 and December 31, 2002 for the Chief Executive Officer and each of our next four most highly compensated executive officers of our company. These five individuals are referred to as the “Named Executive Officers.”

										Long Term Compensation
						Annual Compensation							Securities
										Restricted			Underlying
									Other Annual	Stock			Stock		LTIP		All Other
				Salary		Bonus			Compensation	Awards			Options		Payouts		Compensation
Name and Principal Position		Year		($)		($)			($)(5)	($)(6)			(#)(10)		($)		($)(11)
Jim W. Mogg(1)			2002		450,000		40,072				(7	)		7,500		319,560		93,225
	Chairman of the Board,		2001		419,231		201,482				337,990			74,800				91,825
	President and Chief		2000		376,474		475,219				193,513			133,000		76,102		37,399
	Executive Officer
Mark A. Borer(1)			2002		269,615		59,531				(8	)		6,100				41,057
	Executive Vice President,		2001		219,230		65,500				116,431			25,800				39,457
	Marketing and Corporate		2000		196,154		166,300				145,730			33,600				24,497
	Development
Michael J. Bradley(1)			2002		269,615		59,501				(9	)		2,300				41,367
	Executive Vice President,		2001		219,230		61,800				116,431			25,800				27,587
	Gathering and Processing		2000		196,154		169,400				145,730			34,400		52,553		19,277
Robert F. Martinovich(2)			2002		250,000		54,687											87,246
	Senior Vice President,		2001		219,230		55,800				116,431			25,800				38,632
	Northern Division		2000		190,797		160,400				145,730			33,600				54,507
William W. Slaughter (1)(3)			2002		236,304		102,824	(4)						57,492				58,294
	Executive Vice President		2001		198,261		89,217											68,658
			2000		260,878		73,565				112,500			48,720				56,613

(1)	Prior to the Combination on March 31, 2000 all compensation paid to Messrs. Mogg, Borer, Bradley and Slaughter was paid by Duke Energy and was attributable to services provided to the Predecessor Company.
(2)	Prior to the Combination on March 31, 2000 all compensation paid to Mr. Martinovich was paid by ConocoPhillips.
(3)	Mr. Slaughter provides services to our company pursuant to a Consulting Agreement, which provides for the terms of his compensation as Executive Vice President. For a description of his current agreement, see the disclosure below under the heading “Consulting Agreement.” For the years ended December 31, 2000 and 2001, Mr. Slaughter received compensation that included allocations for base salary, bonus and supplemental payments to offset his ineligibility for company benefits. In addition, he received phantom restricted stock and phantom stock options from the Company. The agreement was amended on June 28, 2002. The amended agreement provides for allocations for base salary, bonus, supplemental payments to offset his ineligibility for company benefits and phantom stock options, but no other benefits.
(4)	The bonus paid to Mr. Slaughter for fiscal year 2000 and 2001, and the first half of 2002 was an allocation of his billing rate under his Consulting Agreement. The Consulting Agreement was amended in June 2002, and under the amended agreement Mr. Slaughter’s bonus is based on Company and personal performance similar to other executive officers.
(5)	Perquisites and other personal benefits received by each Named Executive Officer did not exceed the lesser of $50,000 or 10% of any such officer’s salary and bonus disclosed in the table.

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(6)

Messrs. Mogg, Borer, Bradley and Martinovich elected to receive a portion of the value of their long term incentive component for their 2001 and 2002 compensation in the form of phantom stock. The awards were granted under the Duke Energy 1998 Long Term Incentive Plan. Phantom stock is represented by units denominated in shares of Duke Energy common stock. Each phantom stock unit represents the right to receive, upon vesting, one share of Duke Energy common stock. One quarter of each award vests on each of the first four anniversaries of the grant date provided the recipient continues to be employed by the Company or his or her employment terminates on account of retirement. The awards fully vest in the event of the recipient’s death or disability or a change in control as specified in the Plan. If the recipient’s employment terminates other than on account of retirement, death or disability, any unvested shares remaining on the termination date are forfeited. The phantom stock awards also grant an equal number of dividend equivalents, which represent the right to receive cash payments equivalent to the cash dividends paid on the number of shares of Duke Energy common stock represented by the phantom stock units awarded, until the related phantom stock units vest or are forfeited.

The aggregate number of phantom stock units held by Messrs. Mogg, Borer, Bradley and Martinovich at December 31, 2002 and their values on that date are as follows:

	Number of		Value At
	Phantom Stock		December 31,
	Units		2002
J. Mogg		8,988	$	175,626
M. Borer		2,878		56,236
M. Bradley		2,878		56,236
R. Martinovich		2,878		56,236

(7)	In addition to the 8,988 phantom stock units in note 5, at December 31, 2002, Mr. Mogg held an aggregate of 24,000 restricted shares of Duke Energy common stock having a value of $468,960. Dividends are paid on such shares. The vesting of these shares is determined by, among other things, the performance of Duke Energy.
(8)	In addition to the 2,878 phantom stock units in note 5, at December 31, 2002, Mr. Borer held an aggregate of 3,390 restricted shares of Duke Energy common stock having a value of $66,241. Dividends are paid on such shares. These restricted shares will vest on May 26, 2003.
(9)	In addition to the 2,878 phantom stock units in note 5, at December 31, 2002, Mr. Bradley held an aggregate of 3,390 restricted shares of Duke Energy common stock having a value of $66,241. Dividends are paid on such shares. These restricted shares will vest on May 26, 2003.
(10)	Represents options granted by Duke Energy to purchase shares of Duke Energy common stock, except for Mr. Slaughter, who received phantom stock options that track the performance of Duke Energy common stock.
(11)	Represents the following for 2002:

• Matching contributions under the Company’s 401(k) and Retirement Plan as follows: J. Mogg, $20,000; M. Borer, $19,000; M. Bradley, $19,000; R. Martinovich, $19,000.

• Make-whole contributions under the Company’s Executive Deferred Compensation Plan as follows: J. Mogg, $72,445; M. Borer, $21,553; M. Bradley, $21,863; R. Martinovich, $20,963.

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• Life Insurance premiums paid by the Company as follows: J. Mogg, $810; M. Borer, $504; M. Bradley, $504; R. Martinovich, $450.

• Supplemental relocation payments made under the Company’s relocation policy as follows: R. Martinovich, $46,833.

• Supplemental payment to offset ineligibility for Company benefit plan as follows: W. Slaughter, $58,297.

Board Compensation

     Our Directors do not receive a retainer or fees for service on our Board of Directors or any committees. All of our directors are reimbursed for reasonable out-of-pocket expenses incurred in attending meetings of our Board of Directors or committees and for other reasonable expenses related to the performance of their duties as directors.

Consulting Agreement

     We have entered into a contract for consulting services with Mr. Slaughter that terminates in December 2003. The agreement was amended on June 28, 2002. The amended agreement provides for a billing rate of $1,272 per day for 2002 and a billing rate of $1,335 per day for 2003 until the agreement terminates. In addition, the amended agreement provides that Mr. Slaughter is eligible for a bonus award with a target of 55% of his base annual compensation. In addition, under the terms of the amended agreement, Mr. Slaughter was awarded a long term incentive award for 2002 that tracks the performance of Duke Energy common stock. The award, valued at $387,500 at the time of grant, vests on December 31, 2003 and is exercisable for three years following vesting. The agreement also provides that Mr. Slaughter will be awarded a long term incentive award for 2003, that tracks the performance of Duke Energy common stock. This award will be valued at $406,875 at the time of grant, will vest December 31, 2003 and is exercisable for three years following vesting. Mr. Slaughter is not eligible for any other benefits under the Company’s compensation plans.

Option Grants in Last Fiscal Year

     None of the Named Executive Officers has received options to purchase members interests in our company. None of the Named Executive Officers held options to purchase member interests in our company at December 31, 2002.

     This table shows options granted of Duke Energy common stock to the Named Executive Officers during 2002, along with the present value of the options on the date they were granted, calculated as described in footnote 2 to the table.

Option/SAR Grants in Last Fiscal Year

	Individual Grants
	Number of Shares		% of Total
	Underlying		Options/SARS							Grant Date
	Options/SARS		Granted to			Exercise or Base				Present
Name	Granted(1)(#)		Employees(2)			Price ($/Sh)		Expiration Date		Value(3)($)
J. W. Mogg		7,500		—	(5)		38.33		1/17/2012		80,250
M. A. Borer		6,100		—	(5)		38.33		1/17/2012		65,270
M. J. Bradley		2,300		—	(5)		38.33		1/17/2012		24,610
R. F. Martinovich		0		—	(5)		—		—		—
W. W. Slaughter(4)		57,492		—			31.10		12/31/2006		387,500

(1) Neither the Company nor Duke Energy has granted any SARs to the Named Executive Officers or any other persons except for Mr. Slaughter who received phantom stock options.

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(2)	Reflects percentage that the grant represents of the total options granted to employees of Duke Energy and its subsidiaries during 2002.
(3)	Based on the Black-Scholes option valuation model. The following table lists key input variables used in valuing the options:

Input Variable:
Risk-free Interest Rate		5.23	%
Dividend Yield		3.37	%
Stock Price Volatility		29.71	%
Option Term	10 years

	With respect to all option grants listed in the table, the volatility variable reflected historical monthly stock price trading date from November 30, 1998 through November 30, 2001. An adjustment was made with respect to each valuation for a risk of forfeiture during the vesting period. The actual value, if any, that a grantee may realized will depend on the excess of the stock price over the exercise price on the date the option is exercised, so that there is no assurance the value realized will be at or near the value estimated based upon the Black-Scholes option valuation model.
(4)	Mr. Slaughter was not an employee at the time of grant but provided services to the Company under a Consulting Agreement (See above under the heading “Consulting Agreement”).
(5)	Less than one percent.

OPTION EXERCISES AND YEAR-END VALUES

     This table shows aggregate exercises of options for Duke Energy common stock during 2002 by the Named Executive Officers, and the aggregate year-end value of the unexercised options held by them. The value assigned to each unexercised “in-the-money” stock option is based on the positive spread between the exercise price of the stock option and the fair market value of Duke Energy common stock on December 31, 2002, which was $19.5442. The fair market value is the average of the high and low prices of a share of Duke Energy common stock on that date as reported on the New York Stock Exchange Composite Transactions Tape. The ultimate value of a stock option will depend on the market value of the underlying shares on a future date.

Aggregated Option/SAR Exercises in Last Fiscal Year
and Fiscal Year-End Option/SAR Values

					Number of
					Securities
					Underlying		Value of Unexercised
					Unexercised		In-the-Money
					Options/SARS at		Options/SARS at
					FY-End*(#)		FY-End($)
	Shares Acquired				Exercisable/		Exercisable/
Name	on Exercise(#)		Value Realized($)		Unexercisable		Unexercisable
J. W. Mogg		0		0		206,471/133,517		0/0
M. A. Borer		0		0		42,050/37,050		0/0
M. J. Bradley		1,899		43,346		35,100/37,250		0/0
R. F. Martinovich		0		0		27,750/34,650		0/0
W. W. Slaughter		0		0		48,720/57,492		0/0

* Neither the Company nor Duke Energy has granted any SARs to the Named Executive Officers or any other persons.

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ITEM 12. Security Ownership of Certain Beneficial Owners and Management.

     The following table sets forth information regarding the beneficial ownership of the member interests in our company by:

• each holder of more than 5% of our member interests;

• the Named Executive Officers;

• each director; and

• all directors and executive officers as a group.

Name of Beneficial Owners		Beneficial Ownership
Duke Energy Corporation			69.7	%
	526 South Church Street Charlotte, North Carolina 28201-1006
ConocoPhillips			30.3
	600 N. Dairy Ashford Houston, TX 77079		—
Jim W. Mogg			—
Mark A. Borer			—
Michael J. Bradley			—
Robert F. Martinovich			—
Philip L. Frederickson			—
Fred J. Fowler			—
John E. Lowe			—
Richard J. Osborne			—
All directors and executive officers as a group (11 persons)			—

     In August 2000, we issued $300.0 million of preferred member interests to affiliates of Duke Energy and ConocoPhillips. Duke Energy Field Services Investment Corp. was issued a preferred member interest representing 69.7% of the outstanding preferred member interests in our company and Phillips Gas Investment Company was issued a preferred member interest representing a 30.3% of the outstanding preferred member interests in our company. See Note 11 to the Notes to Consolidated Financial Statements. The preferred member interests have no voting rights in the election of our directors. On September 9, 2003, we redeemed $100.0 million of our preferred members’ interest by paying cash to each of our members (Duke Energy and ConocoPhillips) in proportion to their ownership interests. Duke Energy may be deemed to have dispositive power over the preferred member interest held by Duke Energy Field Services Investment Corp., and ConocoPhillips may be deemed to have dispositive power over the preferred member interest held by Phillips Gas Investment Company.

     The Company does not have any equity compensation plans. However, employees of the Company receive stock options under the Duke Energy 1998 Long Term Incentive Plan.

ITEM 13. Certain Relationships and Related Transactions.

     On March 31, 2000, we combined the then existing midstream natural gas businesses of Duke Energy and ConocoPhillips. In connection with the Combination, Duke Energy and ConocoPhillips transferred all of their respective interests in their subsidiaries that conducted their midstream natural gas business at that time to us. In connection with the Combination, Duke Energy and ConocoPhillips also transferred to us additional midstream natural gas assets acquired by Duke Energy or ConocoPhillips prior to consummation of the Combination, including the Mid-Continent gathering and processing assets of Conoco and Mitchell Energy. In addition, concurrently with the Combination, we obtained by transfer from Duke Energy the general partner of TEPPCO. In exchange for the asset contributions, ConocoPhillips received 30.3% of the outstanding non-preferred member interests in our company, with Duke Energy holding the remaining 69.7% of the outstanding non-preferred member interests in our company. In connection with the closing of the Combination, we borrowed approximately $2.8 billion in the commercial paper market and made one-time cash distributions (including reimbursements for acquisitions) of approximately $1.5 billion to Duke Energy and approximately $1.2 billion to ConocoPhillips.

     There are significant transactions and relationships between us, Duke Energy and ConocoPhillips. For purposes of governing these ongoing relationships and transactions, we will continue in effect the agreements described below. We intend that the terms of any future transactions and agreements between us and Duke Energy or ConocoPhillips will be at least as favorable to us as could be

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obtained from third parties. Depending on the nature and size of the particular transaction, in any such reviews, our Board of Directors may rely on our management’s knowledge, use outside experts or consultants, secure appropriate appraisals, refer to industry statistics or prices, or take other actions as are appropriate under the circumstances.

Transactions with Duke Energy

Services Agreement

     We entered into a services agreement with Duke Energy and some of its subsidiaries, dated as of March 14, 2000. Under this agreement, Duke Energy and those subsidiaries provide us with various staff and support services, including information technology products and services, payroll, employee benefits, insurance, cash management, ad valorem taxes, treasury, media relations, printing, records management, and legal functions. These services are priced on the basis of a monthly charge approximating market prices. Additionally, we may use other Duke Energy services subject to hourly rates, including legal, insurance, internal audit, tax planning, human resources and security departments. This agreement, as amended, expires on December 31, 2003. We believe that the overall charges under this agreement will not exceed charges we would have incurred had we obtained similar services from outside sources.

License Agreement

     In connection with the Combination, Duke Energy has licensed to us a non-exclusive right to use the phrase “Duke Energy” and its logo and certain other trademarks in identifying our businesses. This right may be terminated by Duke Energy at its sole option any time after:

• Duke Energy’s direct or indirect ownership interest in our company is less than or equal to 35%; or

• Duke Energy no longer controls, directly or indirectly, the management and policies of our company.

     Following the receipt of Duke Energy’s notice of termination, we have agreed to amend our organizational documents and those of our subsidiaries to remove the “Duke” name and to phase out within 180 days of the date of the notice the use of existing signage, printed literature, sales and other materials bearing a name, phrase or logo incorporating “Duke.”

Other Transactions

     Prior to the Combination, Duke Energy and its subsidiaries engaged in a number of transactions with the Predecessor Company. This included sales of residue gas and NGLs, the purchase of raw natural gas and other petroleum products and providing natural gas gathering and transportation services to Duke Energy and its subsidiaries. We continue to engage in such activities with Duke Energy and its subsidiaries in the ordinary course of business. In 2002, 2001 and 2000, our total revenues from such activities, including amounts netted in trading and marketing net margin, with Duke Energy and its subsidiaries, including TEPPCO, were approximately $1,167.1 million, $1,648.5 million, and $1,459.2 million.

Transactions with ConocoPhillips

     Prior to the Combination, ConocoPhillips engaged in a number of transactions with GPM Gas Corporation, the subsidiary of ConocoPhillips that owned its midstream natural gas assets that were transferred to us as part of the Combination. This included the sale of residue gas, NGLs and sulfur, and the purchase of raw natural gas. In addition, it included a long term agreement with ConocoPhillips, and subsequently its affiliate CP Chem, for the sale of NGLs at index-based prices. This agreement expires December 31, 2014. We anticipate that we will continue to engage in such activities with ConocoPhillips and its subsidiaries and CP Chem in the ordinary course of business. For the years ended December 31, 2002 2001 and 2000, our total revenues from such activities, including amounts netted in trading and marketing net margin, with ConocoPhillips and its subsidiaries, and CP Chem were approximately $1,022.6 million, $1,309.5 million and $942.3 million, respectively.

ITEM 14. Controls and Procedures

     Within the 90 days prior to the date of this report, we carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Financial Officer and Chief Executive Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rule 13a-14 of the Securities Exchange Act of 1934. Based upon that evaluation, the Chief Financial Officer and Chief Executive Officer concluded that the Company’s

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disclosure controls and procedures are effective in timely alerting them to material information relating to the Company required to be included in the Company’s periodic SEC reports.

     As part of the audit for 2001, our external auditors identified certain deficiencies in the design and operation of our internal control procedures that were “reportable conditions” as defined by the American Institute of Certified Public Accountants. These conditions were related to balance sheet reconciliation, supervisory review of such reconciliation, analysis of balance sheet accounts, imbalances, joint venture accounting, employee benefit accruals and revenue related functions. Accordingly, the Company significantly improved its controls related to account reconciliations, including supervisory review of such account reconciliations. In addition, the Company developed and implemented an accounting policy related to gas imbalances, and improved the process for monthly review and tracking of gas imbalances. Many other control enhancements were made in 2002 related to joint venture accounting, revenue accounting, NGL accounting, middle office procedures and other areas.

     We have also completed a comprehensive account reconciliation project to review and analyze our balance sheet accounts. The account reconciliation project identified the following five categories where account adjustments were necessary: operating expense accruals; gas inventory adjustments: gas imbalances; joint venture and investment account reconciliation; and other balance sheet accounts. As a result of this account reconciliation project, the Company recorded certain charges in the current year as discussed above under “Results of Operations.” Management believes approximately $53 million may be related to corrections of accounting errors in prior periods. However, management has determined that the charges related to error corrections are immaterial both individually and in the aggregate on both a quantitative and qualitative basis to the trends in the financial statements for the periods presented, the prior periods affected and to a fair presentation of the Company’s financial statements. In addition, numerous items identified in the account reconciliation project resulting from system conversions and otherwise unsupportable balance sheet amounts. Due to the nature of certain of these account reconciliation adjustments, it would be impractical to determine what periods such adjustments relate to. Accordingly, the corrections have been recorded in the current year’s financial statements.

     The Company believes it has strengthened its internal controls to ensure the integrity of its financial statements. Internal control enhancements will continue over the next several months, however, appropriate detective controls are in place to prevent material misstatements of financial results and financial position.

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PART IV.

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

     (a)  Consolidated Financial Statements, Supplemental Financial Data and Supplemental Schedule included in Part II of this annual report are as follows:

Consolidated Financial Statements

Consolidated Statements of Operations for the Years Ended December 31, 2002, 2001 and 2000

Consolidated Statements of Comprehensive (Loss) Income for the Years Ended December 31, 2002, 2001 and 2000

Consolidated Statements of Cash Flows for the Years Ended December 31, 2002, 2001 and 2000

Consolidated Balance Sheets as of December 31, 2002 and 2001

Consolidated Statements of Members’ Equity for the Years Ended December 31, 2002, 2001 and 2000

Notes to Consolidated Financial Statements

Quarterly Financial Data (unaudited) (included in Note 20 of the Notes to Consolidated Financial Statements)

Consolidated Financial Statement Schedule II — Valuation and Qualifying Accounts and Reserves for the Years Ended December 31, 2002, 2001 and 2000

     All other schedules are omitted because of the absence of the conditions under which they are required or because the required information is included in the financial statements or notes thereto.

     Consolidated Financial Statements of TEPPCO Partners, L.P. are contained in Exhibit 99.3 to this annual report.

     (b)  Reports on Form 8-K

     None.

     (c)  Exhibits — See Exhibit Index immediately following the signature page.

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SIGNATURES

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

DUKE ENERGY FIELD SERVICES, LLC
By:	/s/ JIM W. MOGG
	Jim W. Mogg
	Chairman of the Board, President and Chief Executive Officer

March 21, 2003

     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	Title
/s/ JIM W. MOGG Jim W. Mogg	Chairman of the Board, President and Chief Executive Officer (Principal Executive Officer)
/s/ ROSE M ROBESON Rose M. Robeson	Chief Financial Officer (Principal Financial and Accounting Officer)
/s/ PHILIP L. FREDERICKSON Philip L. Frederickson	Director
/s/ FRED J. FOWLER Fred J. Fowler	Director
/s/ JOHN E. LOWE John E. Lowe	Director
/s/ RICHARD J. OSBORNE Richard J. Osborne	Director

Date: March 21, 2003

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CERTIFICATIONS

I, Rose M. Robeson certify that:

1.     I have reviewed this annual report on Form 10-K of Duke Energy Field Services, LLC;

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

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

4.     The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

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

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

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

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6.     The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 21, 2003

/s/ Rose M. Robeson

Rose M. Robeson
Vice President and Chief Financial Officer

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CERTIFICATIONS

I, Jim W. Mogg certify that:

1.     I have reviewed this annual report on Form 10-K of Duke Energy Field Services, LLC;

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

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

4.     The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

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

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

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

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6.     The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 21, 2003

/s/ Jim W. Mogg

Jim W. Mogg

Chairman of the Board, President and Chief Executive Officer

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EXHIBIT INDEX

     Exhibits filed herewith are designated by an asterisk(*). All exhibits not so designated are incorporated by reference to a prior filing, as indicated. Items constituting management contracts or compensatory plans or arrangements are designated by a double asterisk (**).

Exhibit Number		Description
3.1	—		Amended and Restated Limited Liability Company Agreement of Duke Energy Field Services, LLC by and between Phillips Gas Company and Duke Energy Field Services Corporation, dated as of March 31, 2000 (incorporated by reference to Exhibit 3.1 to Form 10 (Registration No. 000-31095) of registrant filed on July 20, 2000).
3.2	—		First Amendment to Amended and Restated Limited Liability Company Agreement of Duke Energy Field Services, LLC dated as of August 4, 2000 (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K of registrant filed on August 16, 2000).
4.1	—		Form of Indenture (incorporated by reference to Exhibit 4.1 to Registration Statement on Form S-3/A (Registration No. 333-41854) of registrant filed on August 2, 2000).
4.2	—		First Supplemental Indenture between Duke Energy Field Services, LLC and The Chase Manhattan Bank, as trustee, dated as of August 16, 2000 (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K of registrant filed on August 16, 2000).
4.3	—		Second Supplemental Indenture between Duke Energy Field Services, LLC and The Chase Manhattan Bank, as trustee, dated as of February 2, 2001 (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K of registrant filed on February 1, 2001).
4.4	—		Third Supplemental Indenture between Duke Energy Field Services, LLC and The Chase Manhattan Bank, as trustee, dated as of November 9, 2001 (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K of registrant filed on November 9, 2002.
10.1	—		Second Amendment to Parent Company Agreement among Phillips Petroleum Company, Duke Energy Corporation, Duke Energy Field Services, LLC and Duke Energy Field Services Corporation dated as of August 4, 2000 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K of registrant filed on August 16, 2000).
10.2	—		Services Agreement dated as of March 14, 2000 by and between Duke Energy Corporation, Duke Energy Business Services, LLC, Pan Service Company, Duke Energy Gas Transmission Corporation and Duke Energy Field Services, LLC (incorporated by reference to Exhibit 10.3 to Registration Statement on Form S-1/A (Registration No. 333-32502) of Duke Energy Field Services Corporation, filed on March 27, 2000).
10.3	—		First Amendment to Services Agreement dated as of December 15, 2000 between Duke Energy Corporation, Duke Energy Business Services, LLC, Pan Service Company, Duke Energy Gas Transmission Corporation and Duke Energy Field Services, LLC. (incorporated by reference to Exhibit 10.5 to Annual Report on Form 10-K of registrant filed on March 30, 2001).
*10.4	—		Second Amendment to Services Agreement effective January 1, 2002 between Duke Energy Corporation, Duke Energy Business Services, LLC, Pan Service Company, Duke Energy Gas Transmission Corporation and Duke Energy Field Services, LLC.
*10.5	—		Amendment to Services Agreement effective January 1, 2003 between Duke Energy Corporation, Duke Energy Business Services, LLC, Pan Service Company, Duke Energy Gas Transmission Corporation and Duke Energy Field Services, LLC.
10.6	—		Transition Services Agreement dated as of March 17, 2000 among Phillips Petroleum Company and Duke Energy Field Services, LLC (incorporated by reference to Exhibit 10.4 to Registration Statement on Form S-1/A (Registration No. 333-32502) of Duke Energy Field Services Corporation, filed on March 27, 2000).
10.7	—		Trademark License Agreement dated as of March 31, 2000 among Duke Energy Corporation and Duke Energy Field

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Exhibit Number			Description
				Services, LLC (incorporated by reference to Exhibit 10.5 to Registration Statement on Form S-1/A (Registration No. 333-32502) of Duke Energy Field Services Corporation, filed on May 4, 2000).
10.8		—		Contribution Agreement dated as of December 16, 1999 among Duke Energy Corporation, Phillips Petroleum Company and Duke Energy Field Services, LLC (incorporated by reference to Exhibit 2.1 to Duke Energy Corporation’s Form 8-K filed on December 30, 1999).
10.9		—		First Amendment to Contribution and Governance Agreement dated as of March 23, 2000 among Phillips Petroleum Company, Duke Energy Corporation and Duke Energy Field Services, LLC (incorporated by reference to Exhibit 10.7(b) to Registration Statement on Form S-1/A (Registration No. 333-32502) of Duke Energy Field Services Corporation, filed on March 27, 2000).
10.10		—		NGL Output Purchase and Sale Agreement effective as of January 1, 2000 between GPM Gas Corporation and Phillips 66 Company, a division of Phillips Petroleum Company, as amended by Amendment No. 1 dated December 16, 1999 (incorporated by reference to Exhibit 10.8 to Registration Statement on Form S-1/A (Registration No. 333-32502) of Duke Energy Field Services Corporation, filed on March 15, 2000).
10.11		—		Sulfur Sales Agreement effective as of January 1, 1999 between Phillips 66 Company, a division of Phillips Petroleum Company, and GPM Gas Corporation (incorporated by reference to Exhibit 10.9 to Registration Statement on Form S-1/A (Registration No. 333-32502) of Duke Energy Field Services Corporation, filed on March 27, 2000).
10.12		—		Parent Company Agreement dated as of March 31, 2000 among Phillips Petroleum Company, Duke Energy Corporation, Duke Energy Field Services, LLC and Duke Energy Field Services Corporation (incorporated by reference to Exhibit 10.10 to Registration Statement on Form S-1/A (Registration No. 333-32502) of Duke Energy Field Services Corporation, filed on May 4, 2000).
10.13		—		First Amendment to the Parent Company Agreement dated as of May 25, 2000 among Phillips Petroleum Company, Duke Energy Corporation, Duke Energy Field Services, LLC and Duke Energy Field Services Corporation (incorporated by reference to Exhibit 10.8(b) to Form 10 (Registration No. 333-41854) of registrant filed on July 20, 2000).
10.14	**	—		Contract for Services dated as of April 1, 2000 between Duke Energy Field Services Assets, LLC and William W. Slaughter (incorporated by reference to Exhibit 10.11 to Registration Statement on Form S-1/A (Registration No. 333-32502) of Duke Energy Field Services Corporation, filed on May 4, 2000).
10.15	**	—		First Amendment to Contract for Services dated as of June 29, 2000 between Duke Energy Field Services Assets, LLC and William W. Slaughter (incorporated by reference to Exhibit 10.9(b) to Form 10/A (Registration No. 333-41854) of registrant filed on August 2, 2000).
10.16	**	—		Second Amendment to Contract for Services between Duke Energy Field Services, LP and William W. Slaughter (incorporated by Reference to Exhibit 10.1 to Quarterly Report on Form 10-Q of registrant filed on August  14, 2002).
10.17		—		364-Day Credit Facility among Duke Energy Field Services, LLC, Duke Energy Field Services Corporation, Bank of America, N.A., as Agent and the Lenders named therein, Dated March 29, 2002 (incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10-Q of registrant filed on May 15, 2002).
*12.1		—		Calculation of Ratio of Earnings to Fixed Charges.
*21.1		—		Subsidiaries of the Company.
*23.1		—		Consent of Deloitte & Touche LLP.
*23.2		—		Consent of KPMG LLP
*99.1		—		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2003.
*99.2		—		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2003.
*99.3		—		Consolidated Financial Statements of TEPPCO Partners, L.P.

80 EX-10.4 3 d04125exv10w4.txt EX-10.4 SECOND AMENDMENT TO SERVICES AGREEMENT EXHIBIT 10.4 ------------------------------------------------------------- SECOND AMENDMENT TO SERVICES AGREEMENT by and between DUKE ENERGY CORPORATION, DUKE ENERGY BUSINESS SERVICES, LLC, PAN SERVICE COMPANY, DUKE ENERGY GAS TRANSMISSION CORPORATION and DUKE ENERGY FIELD SERVICES, LLC Dated as of January 1, 2002 ------------------------------------------------------------- Second Amendment to Services Agreement This Second Amendment to the Services Agreement (this "Amendment") is made this 5th day of March 2002, but effective as of January 1, 2002, by and between Duke Energy Corporation, Duke Energy Business Services LLC, Pan Service Company and Duke Energy Gas Transmission Corporation (collectively "Duke"), and Duke Energy Field Services, LLC (the "Company") (each, a "Party", and collectively, the "Parties"). RECITALS: WHEREAS, Duke and the Company are parties to that certain Services Agreement dated March 14, 2000, as amended by that certain First Amendment to Services Agreement dated December 15, 2000, (the Services Agreement and First Amendment to Services Agreement together are referred to as the "Services Agreement") (capitalized terms used but not defined here shall have the meaning given thereto in the Services Agreement); and WHEREAS, Duke and the Company desire to amend the Services Agreement as discussed in this Amendment. NOW, THEREFORE, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereby agree as follows: 1. The rate sheet found in Exhibit A, Article I of the Services Agreement shall be replaced in its entity with the Rate Sheet attached hereto as Exhibit A, Article I. 2. The Services listed in Exhibit A, Article II of the Services Agreement shall be replaced in their entirety with the Services attached hereto as Exhibit A, Article II. 3. Section 3.1 of the Services Agreement shall be terminated in its entity and replaced with the following new Section 3.1: Term. The term of this Agreement shall begin on January 1, 2002 and remain in effect until December 31, 2002. If both Duke and the Company desire to renew this Agreement for an additional 12-month term to begin on January 1 of a particular year, then beginning on August 1 of the existing year, the Parties shall renegotiate the terms and conditions of this Agreement (including without limitation the Services to be provided and their associated expense) which shall be applicable solely for the extended 12-month term. 4. Except as amended hereby, the Services Agreement shall remain in full force and effect as previously executed and the Parties ratify the Services Agreement as amended hereby. IN WITNESS WHEREOF, each of the undersigned has caused this Amendment to be duly executed and delivered on the date first set forth above. DUKE ENERGY CORPORATION DUKE ENERGY BUSINESS SERVICES LLC By: /s/ KEITH G. BUTLER By: /s/ CAROL O. SMITH, JR. --------------------------------- ---------------------------------- Name: Keith G. Butler Name: Cecil O. Smith, Jr. Title: Senior Vice President Title: President and Controller PAN SERVICE COMPANY DUKE ENERGY GAS TRANSMISSION CORPORATION By: /s/ ROBERT B. EVANS By: /s/ ROBERT B. EVANS --------------------------------- ---------------------------------- Name: Robert B. Evans Name: Robert B. Evans Title: President Title: President and Chairman DUKE ENERGY FIELD SERVICES, LLC By: /s/ ROSE M. ROBESON --------------------------------- Name: Rose M. Robeson Title: Vice President and Chief Financial Officer 2 EX-10.5 4 d04125exv10w5.txt EX-10.5 AMENDMENT TO SERVICES AGREEMENT EXHIBIT 10.5 ------------------------------------------------------------ AMENDMENT TO SERVICES AGREEMENT by and between DUKE ENERGY CORPORATION, DUKE ENERGY BUSINESS SERVICES, LLC, PAN SERVICE COMPANY, DUKE ENERGY GAS TRANSMISSION CORPORATION and DUKE ENERGY FIELD SERVICES, LLC Dated as of January 1, 2003 ------------------------------------------------------------ Amendment to Services Agreement This Amendment to the Services Agreement (this "Amendment") is made this ___ day of January, 2003, but effective as of January 1, 2003, by and between Duke Energy Corporation, Duke Energy Business Services LLC, Pan Service Company and Duke Energy Gas Transmission Corporation (collectively "Duke"), and Duke Energy Field Services, LLC (the "Company") (each, a "Party", and collectively, the "Parties"). RECITALS: WHEREAS, Duke and the Company are parties to that certain Services Agreement dated March 14, 2000, as amended (the "Services Agreement") (capitalized terms used but not defined here shall have the meaning given thereto in the Services Agreement); and WHEREAS, Duke and the Company desire to amend the Services Agreement to include various additional services and confirm the rates for 2003. NOW, THEREFORE, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereby agree as follows: 1. The rate sheet found in Exhibit A, Article I of the Services Agreement shall be replaced with the new rate sheet attachment hereto entitled "Exhibit A, Article I (as amended)". 2. The Services listed in Exhibit A, Article II of the Services Agreement shall be amended to include the additional services described in the attachment hereto entitled "Exhibit A, Article II (as amended)". 3. Except as amended hereby, the Services Agreement shall remain in full force and effect as previously executed and amended by the Parties, and the Parties ratify the Services Agreement as amended hereby. IN WITNESS WHEREOF, each of the undersigned has caused this Amendment to be duly executed and delivered on the date first set forth above. DUKE ENERGY CORPORATION DUKE ENERGY BUSINESS SERVICES LLC By: /s/ KEITH G. BUTLER By: /s/ A. R. MULLINAX ---------------------------------- ---------------------------------- Name: Keith G. Butler Name: A. R. Mullinax Title: Senior Vice President Title: Executive Vice President and Controller PAN SERVICE COMPANY DUKE ENERGY GAS TRANSMISSION CORPORATION By: /s/ DOROTHY M. ABLES By: /s/ THOMAS C. O'CONNOR ---------------------------------- ---------------------------------- Name: Dorothy M. Ables Name: Thomas C. O'Connor Title: Senior Vice President Title: President DUKE ENERGY FIELD SERVICES, LLC By: /s/ ROSE M. ROBESON ---------------------------------- Name: Rose M. Robeson Title: Vice President and Chief Financial Officer 2 EX-12.1 5 d04125exv12w1.txt EX-12.1 CALCULATION OF RATIO OF EARNINGS . . . EXHIBIT 12.1 DUKE ENERGY FIELD SERVICES, LLC COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

Years Ended ----------------------------------------------------- 1998 1999 2000 2001 2002 Predecessor Company Historical -------------------------------- Earnings: Pretax income from continuing operations before equity earnings (6,528) 51,856 341,800 337,032 (74,738) Add: Fixed charges 54,791 55,021 151,567 168,789 172,341 Distributed income of equity investees 11,845 22,502 27,424 30,069 53,878 Subtract: Interest Capitalized 1,565 930 324 769 4,702 -------- -------- -------- -------- -------- Income as adjusted 58,543 128,449 520,467 535,121 146,779 -------- -------- -------- -------- -------- Fixed charges: Interest and Debt expense per Statement of Income 52,403 52,915 149,220 165,670 165,841 Capitalized Interest 1,565 930 324 769 4,702 Portion of rents representative of the interest factor 823 1,176 2,023 2,350 1,798 -------- -------- -------- -------- -------- TOTAL FIXED CHARGES 54,791 55,021 151,567 168,789 172,341 -------- -------- -------- -------- -------- RATIO OF EARNINGS TO FIXED CHARGES 1.07 2.33 3.43 3.17 0.85 Amount Needed to cover fixed charges: 25,562

EX-21.1 6 d04125exv21w1.txt EX-21.1 SUBSIDIARIES EXHIBIT 21.1 Subsidiaries of the Company 1. Duke Energy Field Services, LP (Delaware) 2. DEFS Holding 1, LLC (Delaware) 3. National Helium, LLC (Delaware) 4. TEPPCO Partners, L.P. (Delaware) 5. Texas Eastern Products Pipeline Company, LLC (Delaware) EX-23.1 7 d04125exv23w1.txt EX-23.1 CONSENT OF DELOITTE & TOUCHE LLP EXHIBIT 23.1 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement No. 333-57376 of Duke Energy Field Services, LLC on Form S-3 of our report dated March 12, 2003, (which expresses an unqualified opinion and includes an explanatory paragraph relating to the Company's changes in methods of accounting for goodwill and derivative instruments to conform to Statement of Financial Accounting Standards Nos. 142 and 133, respectively, as described in Note 2) appearing in this Annual Report on Form 10-K of Duke Energy Field Services, LLC for the year ended December 31, 2002. DELOITTE & TOUCHE LLP Denver, Colorado March 21, 2003 EX-23.2 8 d04125exv23w2.txt EX-23.2 CONSENT OF KPMG LLP EXHIBIT 23.2 Independent Auditors' Consent To the Partners of TEPPCO Partners, L.P.: We consent to the use of our report dated January 22, 2003, except as to Note 22 which is as of February 10, 2003, related to the consolidated financial statements of TEPPCO Partners, L.P. included in the Duke Energy Field Services, LLC Annual Report on Form 10-K for the fiscal year ended December 31, 2002 filed on March 21, 2003. Our report on the consolidated financial statements of TEPPCO Partners, L.P. refers to a change in the method of accounting for derivative financial instruments and hedging activities in 2001 and the adoption of Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets in 2002. KPMG LLP Houston, Texas March 21, 2003 EX-99.1 9 d04125exv99w1.txt EX-99.1 CERTIFICATION PURSUANT TO 18 USC SEC. 1350 EXHIBIT 99.1 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report of Duke Energy Field Services, LLC (the "Company") on Form 10-K for the period ending December 31, 2002 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Jim W. Mogg, Chairman of the Board, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. /s/ Jim W. Mogg - ------------------------------- Jim W. Mogg Chairman of the Board, President and Chief Executive Officer March 21, 2003 EX-99.2 10 d04125exv99w2.txt EX-99.2 CERTIFICATION PURSUANT TO 18 USC SEC. 1350 EXHIBIT 99.2 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report of Duke Energy Field Services, LLC (the "Company") on Form 10-K for the period ending December 31, 2002 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Rose M. Robeson, Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. /s/ Rose M. Robeson - -------------------------------- Rose M. Robeson Vice President and Chief Financial Officer March 21, 2003 EX-99.3 11 d04125exv99w3.txt EX-99.3 CONSOLIDATED FINANCIAL STATEMENTS EXHIBIT 99.3 CONSOLIDATED FINANCIAL STATEMENTS OF TEPPCO PARTNERS, L.P. INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTAL SCHEDULE

PAGE Financial Statements: Independent Auditors' Report.................................................................... F-2 Consolidated Balance Sheets as of December 31, 2002 and 2001.................................... F-3 Consolidated Statements of Income for the years ended December 31, 2002, 2001 and 2000.......... F-4 Consolidated Statements of Cash Flows for the years ended December 31, 2002, 2001 and 2000...... F-5 Consolidated Statements of Partners' Capital for the years ended December 31, 2002, 2001 and 2000................................................................................ F-6 Notes to Consolidated Financial Statements....................................................... F-7 Supplemental Schedule: Independent Auditors' Report on Consolidated Financial Statement Schedule....................... S-1 Schedule II - Valuation and Qualifying Accounts and Reserves.................................... S-2

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, 2002 and 2001, 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, 2002. 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, 2002 and 2001, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. As described in Note 2 to the consolidated financial statements, as of January 1, 2001, the Partnership changed its method of accounting for derivative instruments and hedging activities and, effective January 1, 2002, adopted Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets. KPMG LLP Houston, Texas January 22, 2003, except as to Note 22, which is as of February 10, 2003 F-2 TEPPCO PARTNERS, L.P. CONSOLIDATED BALANCE SHEETS (IN THOUSANDS)

DECEMBER 31, ------------------------------- 2002 2001 ------------- -------------- ASSETS Current assets: Cash and cash equivalents................................................ $ 30,968 $ 25,479 Accounts receivable, trade............................................... 276,450 221,541 Accounts receivable, related party....................................... 4,313 4,310 Inventories.............................................................. 17,166 17,243 Other.................................................................... 31,670 14,907 ------------- -------------- Total current assets............................................... 360,567 283,480 ------------- -------------- Property, plant and equipment, at cost (Net of accumulated depreciation and amortization of $338,746 and $290,248)............................... 1,587,824 1,180,461 Equity investments......................................................... 284,705 292,224 Intangible assets.......................................................... 465,374 251,487 Goodwill................................................................... 16,944 16,669 Other assets............................................................... 55,228 41,027 ------------- -------------- Total assets....................................................... $ 2,770,642 $ 2,065,348 ============= ==============

LIABILITIES AND PARTNERS' CAPITAL

Current liabilities: Notes payable.......................................................... $ -- $ 360,000 Accounts payable and accrued liabilities................................. 261,080 228,075 Accounts payable, general partner........................................ 6,619 22,680 Accrued interest......................................................... 29,726 15,649 Other accrued taxes...................................................... 11,260 8,888 Other.................................................................... 58,098 33,550 ------------- -------------- Total current liabilities.......................................... 366,783 668,842 ------------- -------------- Senior Notes............................................................... 945,692 375,184 Other long-term debt....................................................... 432,000 340,658 Other liabilities and deferred credits..................................... 30,962 31,853 Redeemable Class B Units held by related party............................. 103,363 105,630 Commitments and contingencies Partners' capital: Accumulated other comprehensive loss..................................... (20,055) (20,324) General partner's interest............................................... 12,770 13,190 Limited partners' interests.............................................. 899,127 550,315 ------------- -------------- Total partners' capital............................................ 891,842 543,181 ------------- -------------- Total liabilities and partners' capital............................ $ 2,770,642 $ 2,065,348 ============= ==============

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, -------------------------------------------------- 2002 2001 2000 ------------ ------------ ------------ Operating revenues: Sales of crude oil and petroleum products....................... $ 2,823,800 $ 3,219,816 $ 2,821,943 Transportation - Refined products............................... 123,476 139,315 119,331 Transportation - LPGs........................................... 74,577 77,823 73,896 Transportation - Crude oil...................................... 27,414 24,223 17,524 Transportation - NGLs........................................... 38,870 20,702 7,009 Gathering - Natural gas........................................ 90,053 8,824 -- Mont Belvieu operations......................................... 15,238 14,116 13,334 Other........................................................... 48,735 51,594 34,904 ------------ ------------ ------------ Total operating revenues.................................. 3,242,163 3,556,413 3,087,941 ------------ ------------ ------------ Costs and expenses: Purchases of crude oil and petroleum products................... 2,772,328 3,172,805 2,793,643 Operating, general and administrative........................... 158,753 135,253 104,918 Operating fuel and power........................................ 36,814 36,575 34,655 Depreciation and amortization................................... 86,032 45,899 35,163 Taxes - other than income taxes................................. 17,989 14,090 10,576 ------------ ------------ ------------ Total costs and expenses.................................. 3,071,916 3,404,622 2,978,955 ------------ ------------ ------------ Operating income.......................................... 170,247 151,791 108,986 Interest expense.................................................. (70,537) (66,057) (48,982) Interest capitalized.............................................. 4,345 4,000 4,559 Equity earnings................................................... 11,980 17,398 12,214 Other income - net................................................ 1,827 2,799 1,388 ------------ ------------ ------------ Income before minority interest .......................... 117,862 109,931 78,165 Minority interest................................................. -- (800) (789) ------------ ------------ ------------ Net income................................................ $ 117,862 $ 109,131 $ 77,376 ============ ============ ============ Net Income Allocation: Limited Partner Unitholders....................................... 81,238 76,986 56,091 Class B Unitholder................................................ 6,943 8,642 7,385 General Partner................................................... 29,681 23,503 13,900 ------------ ------------ ------------ Total net income allocated................................ $ 117,862 $ 109,131 $ 77,376 ============ ============ ============ Basic and diluted net income per Limited Partner and Class B Unit........................................ $ 1.79 $ 2.18 $ 1.89 ============ ============ ============ Weighted average Limited Partner and Class B Units outstanding............................................... 49,202 39,258 33,594

See accompanying Notes to Consolidated Financial Statements. F-4 TEPPCO PARTNERS, L.P. CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)

YEARS ENDED DECEMBER 31, ---------------------------------------- 2002 2001 2000 ---------- ---------- ---------- Cash flows from operating activities: Net income .............................................................. $ 117,862 $ 109,131 $ 77,376 Adjustments to reconcile net income to cash provided by operating activities: Depreciation and amortization ......................................... 86,032 45,899 35,163 Earnings in equity investments, net of distributions .................. 18,401 14,377 (10,084) Non-cash portion of interest expense .................................. 4,916 4,053 2,218 Decrease (increase) in accounts receivable ............................ (54,909) 81,190 (90,006) Decrease (increase) in inventories .................................... 77 7,541 (7,567) Decrease (increase) in other current assets ........................... (16,263) (8,082) 1,165 Increase (decrease) in accounts payable and accrued expenses........... 73,294 (71,757) 106,662 Other ................................................................. 5,507 (13,204) (6,882) ---------- ---------- ---------- Net cash provided by operating activities ........................ 234,917 169,148 108,045 ---------- ---------- ---------- Cash flows from investing activities: Proceeds from the sale of assets ........................................ 3,380 1,300 -- Proceeds from cash investments .......................................... -- 4,236 3,475 Purchases of cash investments ........................................... -- -- (2,000) Purchase of ARCO assets ................................................. -- (11,000) (322,640) Purchase of Val Verde Gathering System .................................. (444,150) -- -- Purchase of Jonah Gas Gathering Company ................................. (7,319) (359,834) -- Purchase of Chaparral NGL System ........................................ (132,372) -- -- Purchase of crude oil assets ............................................ -- (20,000) (99,508) Investment in Centennial Pipeline LLC ................................... (10,882) (64,953) (5,040) Capital expenditures .................................................... (133,372) (107,614) (68,481) ---------- ---------- ---------- Net cash used in investing activities ............................ (724,715) (557,865) (494,194) ---------- ---------- ---------- Cash flows from financing activities: Proceeds from term and revolving credit facilities ...................... 675,000 546,148 552,000 Repayments on term and revolving credit facilities ...................... (943,659) (291,490) (172,000) Issuance of Senior Notes ................................................ 497,805 -- -- Debt issuance costs ..................................................... (7,025) (2,601) (7,074) Proceeds from termination of interest rate swaps ........................ 44,896 -- -- Issuance of Limited Partner Units, net .................................. 372,506 234,660 88,158 General partner's contributions ......................................... 7,617 4,795 1,799 Distributions paid ...................................................... (151,853) (104,412) (82,231) ---------- ---------- ---------- Net cash provided by financing activities ........................ 495,287 387,100 380,652 ---------- ---------- ---------- Net increase (decrease) in cash and cash equivalents ...................... 5,489 (1,617) (5,497) Cash and cash equivalents at beginning of period .......................... 25,479 27,096 32,593 ---------- ---------- ---------- Cash and cash equivalents at end of period ................................ $ 30,968 $ 25,479 $ 27,096 ========== ========== ========== SUPPLEMENTAL DISCLOSURE OF CASH FLOWS: Interest paid during the year (net of capitalized interest) ............. $ 48,908 $ 61,458 $ 36,793

See accompanying Notes to Consolidated Financial Statements. F-5 TEPPCO PARTNERS, L.P. CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL (IN THOUSANDS, EXCEPT UNIT AMOUNTS)

OUTSTANDING ACCUMULATED LIMITED GENERAL LIMITED OTHER PARTNER PARTNER'S PARTNERS' COMPREHENSIVE UNITS INTEREST INTERESTS LOSS TOTAL ----------- ----------- ----------- -------------- ----------- Partners' capital at December 31, 1999 ..... 29,000,000 $ 657 $ 229,110 $ -- $ 229,767 Capital contributions .................... -- 890 -- -- 890 Issuance of Limited Partner Units, net ... 3,700,000 -- 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 ..... 32,700,000 1,824 313,233 -- 315,057 Capital contributions .................... -- 4,795 -- -- 4,795 Issuance of Limited Partner Units, net ... 7,750,000 -- 234,660 -- 234,660 Minority interest restructured ........... -- 4,598 -- -- 4,598 Cumulative effect of accounting change ... -- -- -- (10,103) (10,103) Net loss on cash flow 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 ..... 40,450,000 13,190 550,315 (20,324) 543,181 Capital contributions .................... -- 7,568 -- -- 7,568 Issuance of Limited Partner Units, net ... 13,260,000 -- 370,108 -- 370,108 Net gain on cash flow hedges ............. -- -- -- 269 269 2002 net income allocation ............... -- 29,681 81,238 -- 110,919 2002 cash distributions .................. -- (37,718) (104,932) -- (142,650) Issuance of Limited Partner Units upon exercise of options .................. 99,597 49 2,398 -- 2,447 ----------- ----------- ----------- ----------- ----------- Partners' capital at December 31, 2002 ..... 53,809,597 $ 12,770 $ 899,127 $ (20,055) $ 891,842 =========== =========== =========== =========== ===========

See accompanying Notes to Consolidated Financial Statements. F-6 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1. PARTNERSHIP ORGANIZATION TEPPCO Partners, L.P. (the "Partnership"), a Delaware limited partnership, is a master limited partnership formed in March 1990. We operate through TE Products Pipeline Company, Limited Partnership ("TE Products"), TCTM, L.P. ("TCTM") and TEPPCO Midstream Companies, L.P. ("TEPPCO Midstream"). Collectively, TE Products, TCTM and TEPPCO Midstream are referred to as the "Operating Partnerships." Texas Eastern Products Pipeline Company, LLC (the "Company" or "General Partner"), a Delaware limited liability company, serves as our general partner and owns a 2% general partner interest in us. The General Partner is a wholly owned subsidiary of Duke Energy Field Services, LLC ("DEFS"), a joint venture between Duke Energy Corporation ("Duke Energy") and ConocoPhillips. Duke Energy holds an approximate 70% interest in DEFS, and ConocoPhillips holds the remaining 30%. The Company, as general partner, performs all management and operating functions required for us, except for the management and operations of certain of the TEPPCO Midstream assets that are managed by DEFS on our behalf. We reimburse the General Partner for all reasonable direct and indirect expenses incurred in managing us. As used in this Report, "we," "us," "our," and the "Partnership" means TEPPCO Partners, L.P. and, where the context requires, includes our subsidiaries. On July 26, 2001, the Company restructured its general partner ownership of the Operating Partnerships to cause them to be indirectly wholly owned by us. TEPPCO GP, Inc. ("TEPPCO GP"), our subsidiary, succeeded the Company as general partner of the Operating Partnerships. All remaining partner interests in the Operating Partnerships not already owned by us were transferred to us. In exchange for this contribution, the Company's interest as our general partner was increased to 2%. The increased percentage is the economic equivalent of the aggregate interest that the Company had prior to the restructuring through its combined interests in us and the Operating Partnerships. As a result, we hold a 99.999% limited partner interest in the Operating Partnerships and TEPPCO GP holds a 0.001% general partner interest. This reorganization was undertaken to simplify required financial reporting by the Operating Partnerships when the Operating Partnerships issue guarantees of our debt. At formation in 1990, we completed an initial public offering of 26,500,000 Units representing Limited Partner Interests ("Limited Partner Units") at $10.00 per Unit. In connection with our formation, the Company received 2,500,000 Deferred Participation Interests ("DPIs"). Effective April 1, 1994, the DPIs began participating in distributions of cash and allocations of profit and loss in a manner identical to Limited Partner Units and are treated as Limited Partner Units for purposes of this Report. These Limited Partner Units were assigned to Duke Energy when ownership of the Company was transferred from Duke Energy to DEFS in 2000. Pursuant to our Partnership Agreement, we have registered the resale by Duke Energy of such Limited Partner Units with the Securities and Exchange Commission. As of December 31, 2002, no such Limited Partner Units had been sold by Duke Energy. At December 31, 2002 and 2001, we had outstanding 53,809,597 and 40,450,000 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. We have the option to seek approval for the conversion of the Class B Units into Limited Partner Units; however, if the conversion is denied, Duke Energy, as holder of the Class B Units, will have the right to sell them to us at 95.5% of the 20-day average market closing price of the Limited Partner Units, as determined under our Partnership Agreement. As a result of this option, we have not included the Class B Units in partners' capital at December 31, 2002 and 2001. 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 We follow the following significant accounting policies in the preparation of our consolidated financial statements. BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION The financial statements include our accounts on a consolidated basis. The Company's 1% general partner interest in the Operating Partnerships, prior to July 26, 2001, is accounted for as a minority interest. We have eliminated all significant intercompany items in consolidation. We have reclassified certain amounts from prior periods to conform with the current presentation. USE OF ESTIMATES The preparation of financial statements in conformity with generally accepted accounting principles in the United States requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. ENVIRONMENTAL EXPENDITURES We accrue for environmental costs that relate to existing conditions caused by past operations. Environmental costs include initial site surveys and environmental studies of potentially contaminated sites, costs for remediation and restoration of sites determined to be contaminated and ongoing monitoring costs, as well as fines, damages and other costs, when estimable. We monitor the balance of accrued undiscounted environmental liabilities on a regular basis. We record liabilities for environmental costs at a specific site when our liability for such costs, including direct internal and legal costs, is probable and a reasonable estimate of the associated costs can be made. Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information developed in subsequent periods. Estimates of our ultimate liabilities associated with environmental costs are particularly difficult to make with certainty due to the number of variables involved, including the early stage of investigation at certain sites, the lengthy time frames required to complete remediation alternatives available and the evolving nature of environmental laws and regulations. BUSINESS SEGMENTS We operate and report in three business segments: transportation and storage of refined products, liquefied petroleum gases ("LPGs") and petrochemicals ("Downstream Segment"); gathering, transportation, marketing and storage of crude oil; and distribution of lubrication oils and specialty chemicals ("Upstream Segment"); and gathering of natural gas, fractionation of natural gas liquids ("NGLs") and transportation of NGLs ("Midstream Segment"). Our reportable segments offer different products and services and are managed separately because each requires different business strategies. Effective January 1, 2002, we realigned our three business segments to reflect our entry into the natural gas gathering business and the expanded scope of NGLs operations. We transferred the fractionation of NGLs, which was previously reflected as part of the Downstream Segment, to the Midstream Segment. The operation of NGL F-8 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) pipelines, which was previously reflected as part of the Upstream Segment, was also transferred to the Midstream Segment. We have adjusted our period-to-period comparisons to conform with the current presentation. Our interstate transportation operations, including rates charged to customers, are subject to regulations prescribed by the Federal Energy Regulatory Commission ("FERC"). Refined products, LPGs, petrochemicals, crude oil, NGLs and natural gas are referred to in this Report, collectively, as "petroleum products" or "products." REVENUE RECOGNITION Our Downstream Segment revenues are earned from transportation and storage of refined products and LPGs, storage and short-haul transportation of LPGs at the Mont Belvieu complex, intrastate transportation of petrochemicals, sale of product inventory and other ancillary services. Transportation revenues are recognized as products are delivered to customers. Storage revenues are recognized upon receipt of products into storage and upon performance of storage services. Terminaling revenues are recognized as products are out-loaded. Revenues from the sale of product inventory are recognized when the products are sold. Our Upstream Segment revenues are earned from gathering, transportation, marketing and storage of crude oil, and distribution of lubrication oils and specialty chemicals principally in Oklahoma, Texas and the Rocky Mountain region. 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 our crude oil marketing company, TEPPCO Crude Oil, L.P., which typically occurs upon our receipt of the product. Revenues related to trade documentation and pumpover fees are recognized as services are completed. Except for crude oil purchased from time to time as inventory, our policy is to purchase only crude oil for which we have a market to sell and to structure sales contracts so that crude oil price fluctuations do not materially affect the margin received. As we purchase crude oil, we establish a margin by selling crude oil for physical delivery to third party users or by entering into a future delivery obligation. Through these transactions, we seek to maintain a position that is balanced between crude oil purchases and sales and future delivery obligations. However, certain basis risks (the risk that price relationships between delivery points, classes of products or delivery periods will change) cannot be completely hedged. Our Midstream Segment revenues are derived from the gathering of natural gas, fractionation of NGLs and transportation of NGLs. Gathering and transportation revenues are recognized as natural gas or NGLs are delivered to customers. Revenues are also earned from the sale of condensate liquid extracted from the natural gas stream to an Upstream marketing affiliate. Fractionation revenues are recognized ratably over the contract year as products are delivered to DEFS. We do not take title to the natural gas gathered, NGLs transported or NGLs fractionated, therefore, the results of our Midstream Segment are not directly affected by changes in the prices of natural gas or NGLs. NATURAL GAS IMBALANCES Gas imbalances occur when gas producers (customers) deliver more or less actual natural gas gathering volumes to our gathering systems than they originally nominated. Actual deliveries are different from nominated volumes due to fluctuations in gas production at the wellhead. If the customers supply more natural gas gathering volumes than they nominated, the Val Verde Gathering System ("Val Verde") and the Jonah Gas Gathering System ("Jonah") record a payable for the amount due to customers and also record a receivable for the same amount due from connecting pipeline transporters or shippers. If the customers supply less natural gas gathering volumes than F-9 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) they nominated, the Val Verde and the Jonah systems record a receivable reflecting the amount due from customers and a payable for the same amount due to connecting pipeline transporters or shippers. Quantities of natural gas over or under delivered related to imbalance agreements are recorded monthly using then current index prices. These imbalances are settled with cash or deliveries of natural gas. Gains are recorded when gas volumes owed (receivables) are settled by gas producers at a later date during a period of increasing prices, or if Val Verde and Jonah settle payables at later date during a period of falling prices. Losses are recorded if these processes are reversed. USE OF DERIVATIVES We account for derivative financial instruments in accordance with 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 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. We have utilized and expect to continue to utilize interest rate swap agreements to hedge a portion of our cash flow and fair value risks. Interest rate swap agreements are used to manage the fixed and floating interest rate mix of our total debt portfolio and overall cost of borrowing. The interest rate swap related to our cash flow risk is intended to reduce our exposure to increases in the benchmark interest rates underlying our variable rate revolving credit facility. The interest rate swaps related to our fair value risks are intended to reduce our exposure to changes in the fair value of our fixed rate Senior Notes. The interest rate swap agreements involve the periodic exchange of payments without the exchange of the notional amount upon which the payments are based. The related amount payable to or receivable from counterparties is included as an adjustment to accrued interest. By using interest rate swap agreements to hedge exposures to changes in interest rates and the fair value of fixed rate Senior Notes, we are exposed to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk for us. When the fair value of a derivative contract is negative, we owe the counterparty and, therefore, we do not possess credit risk. We minimize the credit risk in derivative instruments by entering into transactions with major financial institutions. Market risk is the adverse effect on the value of a financial instrument that results from a change in interest rates. We manage market risk associated with interest rate contracts by establishing and monitoring parameters that limit the type and degree of market risk that may be undertaken. We adopted SFAS 133 at January 1, 2001, which resulted in the recognition of approximately $10.1 million of derivative liabilities, $4.1 million of which were current liabilities and $6.0 million of which were noncurrent liabilities, and $10.1 million of hedging losses included in accumulated other comprehensive income, a component of partners' capital, as the cumulative effect of the change in accounting. The hedging losses included in accumulated other comprehensive loss are transferred to earnings as the forecasted transactions actually occur. Amounts determined as of January 1, 2001, were based on the market quote of our interest swap agreement in place at the time of adoption. F-10 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) INVENTORIES Inventories consist primarily of petroleum products and crude oil which are valued at the lower of cost (weighted average cost method) or market. Our Downstream Segment acquires and disposes of various products under exchange agreements. Receivables and payables arising from these transactions are usually satisfied with products rather than cash. The net balances of exchange receivables and payables are valued at weighted average cost and included in inventories. PROPERTY, PLANT AND EQUIPMENT We record property, plant and equipment at its acquisition cost. Additions to property, plant and equipment, including major replacements or betterments, are recorded at cost. We charge replacements and renewals of minor items of property that do not materially increase values or extend useful lives to maintenance expense. Depreciation expense is computed on the straight-line method using rates based upon expected useful lives of various classes of assets (ranging from 2% to 20% per annum). We evaluate impairment of long-lived assets in accordance with SFAS No. 121, Accounting for the Impairment of Long-Lived Assets to Be Disposed Of, and effective January 1, 2002, SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of the carrying amount of assets to be held and used is measured by a comparison of the carrying amount of the asset to future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. CAPITALIZATION OF INTEREST We capitalize interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average rate used to capitalize interest on borrowed funds was 5.11%, 6.46% and 7.45% for the years ended December 31, 2002, 2001 and 2000, respectively. During the years ended December 31, 2002, 2001 and 2000, the amount of interest capitalized was $4.3 million, $4.0 million and $4.6 million, respectively. INTANGIBLE ASSETS Intangible assets at December 31, 2002, consist primarily of production contracts assumed in the acquisition of Jonah on September 30, 2001, and the acquisition of Val Verde on June 30, 2002, and the fractionation agreement with DEFS. In connection with the acquisitions of Jonah and Val Verde, we assumed contracts that dedicate future production from natural gas wells in the Green River Basin in Wyoming, and we assumed fixed-term contracts with customers that transport coal bed methane ("CBM") from the Fruitland Coal Formation of the San Juan Basin in New Mexico and Colorado, respectively (see Note 5. 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 is amortized on a unit of production basis, based upon the actual throughput of the system over the expected total throughput for the lives of the contracts. The amortization of the Jonah and Val Verde systems are expected to average approximately 16 years and 20 years, respectively. On a quarterly basis, we update production estimates of the natural gas wells and evaluate the remaining expected useful life of the contract F-11 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) assets. At December 31, 2002, the unamortized balance of the Jonah and Val Verde production contracts were $205.2 million and $228.6 million, respectively. In connection with the purchase of the fractionation facilities in 1998, we entered into a fractionation agreement with DEFS. The fractionation agreement is being amortized over a period of 20 years, which is the term of the agreement with DEFS. At December 31, 2002, the unamortized balance of this agreement was $29.0 million (see Note 7. Related Party Transactions.) GOODWILL Goodwill represents the excess of purchase price over fair value of net assets acquired and is presented on the consolidated balance sheets net of accumulated amortization. We account for goodwill under SFAS No. 142, Goodwill and Other Intangible Assets which was issued by the Financial Accounting Standards Board ("FASB") in July 2001 (see Note 3. Goodwill and Other Intangible Assets). SFAS 142 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. Beginning January 1, 2002, effective with the adoption of SFAS 142, we no longer record amortization expense related to goodwill or amortization expense related to the excess investment on our equity investment (equity method goodwill). INCOME TAXES We are a limited partnership. As such, we are not a taxable entity for federal and state income tax purposes and do not directly pay federal and state income tax. Our taxable income or loss, which may vary substantially from the net income or net loss we report in our consolidated statements of income, is includable in the federal and state income tax returns of each unitholder. Accordingly, no recognition has been given to federal income taxes for our operations. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined as we do not have access to information about each unitholders' tax attributes in the Partnership. 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 49.2 million Units, 39.3 million Units and 33.6 million Units for the years ended December 31, 2002, 2001 and 2000, respectively). 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 13. Quarterly Distributions of Available Cash). The General Partner was allocated $29.7 million (representing 25.18%) of net income for the year ended December 31, 2002, $23.5 million (representing 21.54%) of net income for the year ended December 31, 2001, and $13.9 million (representing 17.96%) of net income for the year ended December 31, 2000. The General Partner's percentage interest in our net income increases as cash distributions paid per Unit increases. 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 F-12 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) treasury stock method. For the years ended December 31, 2002, 2001 and 2000, the denominator was increased by 32,053 Units, 41,864 Units and 20,926 Units, respectively. UNIT OPTION PLAN We have not granted options for any periods presented. For options outstanding under the 1994 Long Term Incentive Plan (see Note 14. Unit-Based Compensation), we followed the intrinsic value method of accounting for recognizing stock-based compensation expense. Under this method, we record no compensation expense for unit options granted when the exercise price of the options granted is equal to, or greater than, the market price of our Limited Partner Units on the date of the grant. In December 2002, SFAS No. 148, Accounting for Stock-Based Compensation - - Transition and Disclosure was issued. SFAS 148 amends SFAS No. 123, Accounting for Stock-Based Compensation, and provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS 148 amends the disclosure requirements of SFAS 123 to require prominent disclosure in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. Certain of the disclosure modifications are required for fiscal years ending after December 15, 2002, and are included in Note 14. Unit-Based Compensation. The following table summarizes pro forma net income and net income per Unit for the years ended December 31, 2002, 2001 and 2000 assuming we had used the fair value method of accounting for our unit option plan (in thousands, except per Unit amounts):

YEARS ENDED DECEMBER 31, ------------------------------------------------ 2002 2001 2000 ------------ ------------ ------------ Net income: Reported net income ......................................... $ 117,862 $ 109,131 $ 77,376 Deduct: Total unit-based employee compensation expense determined under fair value based method for all awards ... (6) (118) (201) ------------ ------------ ------------ Pro forma net income .................................... $ 117,856 $ 109,013 $ 77,175 ============ ============ ============ Pro forma net income allocation: Limited Partner Unitholders ................................. $ 81,234 $ 76,902 $ 55,945 Class B Unitholder .......................................... 6,943 8,633 7,366 General Partner ............................................. 29,679 23,478 13,864 ------------ ------------ ------------ Total pro forma net income allocated .................... $ 117,856 $ 109,013 $ 77,175 ============ ============ ============ Basic and diluted net income per Limited Partner and Class B Unit: As reported ................................................. $ 1.79 $ 2.18 $ 1.89 Deduct: Total unit-based employee compensation expense determined under fair value based method for all awards ... -- -- (0.01) ------------ ------------ ------------ Pro forma net income per Unit ........................... $ 1.79 $ 2.18 $ 1.88 ============ ============ ============

For purposes of determining compensation costs using the provisions of SFAS 123, the fair value of option grants was determined using the Black-Scholes option-valuation model. The key input variables used in valuing the options were as follows: average risk-free interest rate based on five- and 10-year Treasury bonds - 4.7%; Unit price volatility - 23%; dividend yield - 7.6%; and estimated option lives - six years. F-13 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) NEW ACCOUNTING PRONOUNCEMENTS In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS 143 requires us to record the fair value of an asset retirement obligation as a liability in the period in which we incur a legal obligation for the retirement of tangible long-lived assets. A corresponding asset is also recorded and depreciated over the life of the asset. After the initial measurement of the asset retirement obligation, the liability will be adjusted at the end of each reporting period to reflect changes in the estimated future cash flows underlying the obligation. We will adopt SFAS 143 effective January 1, 2003. Determination of any amounts to be recognized upon adoption is based upon numerous estimates and assumptions, including future retirement costs, future inflation rates and the credit-adjusted risk-free interest rates. The Downstream Segment assets consist primarily of a pipeline system and a series of storage facilities that originate along the upper Texas Gulf Coast and extend through the Midwest and northeastern United States. We transport refined products, LPGs and petrochemicals through the pipeline system. These products are primarily received in the south end of the system and stored and/or transported to various points along the system per customer nominations. The Upstream Segment's operations include purchasing crude oil from producers at the wellhead and providing delivery, storage and other services to its customers. The properties in the Upstream Segment consist of interstate trunk pipelines, pump stations, trucking facilities, storage tanks and various gathering systems primarily in Texas and Oklahoma. The Midstream Segment gathers natural gas from producers and transports natural gas and NGLs on its pipeline systems, primarily in Texas, Wyoming, New Mexico and Colorado. The Midstream Segment also owns and operates two NGL fractionating facilities in Colorado. The fair value of the asset retirement obligations for our trunk and interstate pipelines and our surface facilities cannot be reasonably estimated, as future dismantlement and removal dates are indeterminate. We will record such asset retirement obligations in the period in which we determine the settlement dates of the retirement obligations. Other assets in which future operating lives may be determinable include our gathering assets in our Midstream and Upstream Segments. However, our rights-of-way agreements, in general, do not require us to remove pipe or otherwise perform restoration upon taking the pipelines permanently out of service. We are continuing to evaluate the effect of SFAS 143 on our Midstream and Upstream gathering assets, but we do not currently anticipate that the adoption of SFAS 143 will have a material impact on our financial position, results of operations or cash flows. In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS 144 supercedes SFAS No. 121, Accounting for Long-Lived Assets and For Long-Lived Assets to be Disposed Of, but retains its fundamental provisions for reorganizing and measuring impairment losses on long-lived assets held for use and long-lived assets to be disposed of by sale. We adopted SFAS 144 effective January 1, 2002. The adoption of SFAS 144 did not have a material effect on our financial position, results of operations or cash flows. In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections. SFAS 145 eliminates the requirement to classify gains and losses from the extinguishment of indebtedness as extraordinary, requires certain lease modifications to be treated the same as a sale-leaseback transaction, and makes other non-substantive technical corrections to existing pronouncements. SFAS 145 is effective for fiscal years beginning after May 15, 2002, with earlier adoption encouraged. We are required to adopt SFAS 145 effective January 1, 2003. We do not believe that the adoption of SFAS 145 will have a material effect on our financial position, results of operations or cash flows. In July 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force ("EITF") Issue No. 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). SFAS 146 requires recognition of a liability for a cost associated with an exit or disposal activity F-14 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) when the liability is incurred, as opposed to when the entity commits to an exit plan under EITF No. 94-3. SFAS 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002. We do not believe that the adoption of SFAS 146 will have a material effect on our financial position, results of operations or cash flows. In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure. SFAS 148 amends SFAS No. 123, Accounting for Stock-Based Compensation, to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS 148 amends the disclosure requirements of SFAS 123 to require prominent disclosure in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. The provisions of SFAS 148 are effective for financial statements for fiscal years ending after December 15, 2002. The adoption of SFAS 148 did not affect our financial position, results of operations or cash flows. In November 2002, the FASB issued Interpretation No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others ("FIN 45"), which addresses the disclosure to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees. FIN 45 also requires the recognition of a liability by a guarantor at the inception of certain guarantees. FIN 45 requires the guarantor to recognize a liability for the non-contingent component of the guarantee, which is the obligation to stand ready to perform in the event that specified triggering events or conditions occur. The initial measurement of this liability is the fair value of the guarantee at inception. The recognition of the liability is required even it is not probable that payments will be required under the guarantee or if the guarantee was issued with a premium payment or as part of a transaction with multiple elements. We have adopted the disclosure requirements of FIN 45 (see Note 17. Commitments and Contingencies) and will apply the recognition and measurement provisions for all guarantees entered into or modified after December 31, 2002. To date, we have not entered into or modified guarantees pursuant to the provisions of FIN 45. In January 2003, the FASB issued FASB Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51 ("FIN 46"). FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. We are required to apply FIN 46 to all new variable interest entities created or acquired after January 31, 2003. For variable interest entities created or acquired prior to February 1, 2003, we are required to apply FIN 46 on July 1, 2003. We do not believe FIN 46 will have a significant impact on our financial position, results of operations or cash flows. NOTE 3. GOODWILL AND OTHER INTANGIBLE ASSETS In July 2001, the 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. Beginning January 1, 2002, effective with the adoption of SFAS 142, we no longer record amortization expense related to goodwill or amortization expense related to the excess investment on our equity investment in Seaway Crude Pipeline Company (see Note 6. Equity Investments). The following table presents our results on a comparable basis, as if we had not recorded amortization expense of goodwill or amortization expense of our excess investment in Seaway Crude Pipeline Company for the years ended December 31, 2002, 2001 and 2000 (in thousands, except per Unit amounts): F-15 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

YEARS ENDED DECEMBER 31, ---------------------------------------------- 2002 2001 2000 ------------ ------------ ------------ Net income: Reported net income ............................... $ 117,862 $ 109,131 $ 77,376 Amortization of goodwill and excess investment .... -- 2,396 767 ------------ ------------ ------------ Adjusted net income ............................. $ 117,862 $ 111,527 $ 78,143 ============ ============ ============ Net income allocation: Limited Partner Unitholders ....................... $ 81,238 $ 78,676 $ 56,647 Class B Unitholder ................................ 6,943 8,832 7,458 General Partner ................................... 29,681 24,019 14,038 ------------ ------------ ------------ Total net income allocated ...................... $ 117,862 $ 111,527 $ 78,143 ============ ============ ============ Basic and diluted net income per Limited Partner and Class B Unit: As reported ....................................... $ 1.79 $ 2.18 $ 1.89 Amortization of goodwill and excess investment .... -- 0.05 0.02 ------------ ------------ ------------ Adjusted net income per Unit .................... $ 1.79 $ 2.23 $ 1.91 ============ ============ ============

Upon the adoption of SFAS 142, we were required to reassess the useful lives and residual values of all intangible assets acquired, and make necessary amortization period adjustments by the end of the first interim period after adoption. We completed this analysis during the year ended December 31, 2002, resulting in no change to the amortization period for our intangible assets. We will continue to reassess the useful lives and residual values of all intangible assets on an annual basis. In connection with the transitional goodwill impairment evaluation required by SFAS 142, we were required to perform an assessment of whether there was an indication that goodwill was impaired as of the date of adoption. We accomplished this by identifying our reporting units and determining the carrying value of each reporting unit by assigning the assets and liabilities, including the existing goodwill and intangible assets, to those reporting units as of the date of adoption. We then determined the fair value of each reporting unit and compared it to the carrying value of the reporting unit. We completed this analysis during the second quarter of 2002, resulting in no transitional impairment loss. We will continue to compare the fair value of each reporting unit to the carrying value on an annual basis to determine if an impairment loss has occurred. At December 31, 2002, we had $16.9 million of unamortized goodwill and $25.5 million of excess investment in our equity investment (equity method goodwill). We completed an impairment analysis of the excess investment in our equity investment during the year ended December 31, 2002, and we noted no indication of impairment. The excess investment is included in our equity investments account at December 31, 2002. The following table presents the carrying amount of goodwill and excess investment at December 31, 2002, by business segment (in thousands):

DOWNSTREAM MIDSTREAM UPSTREAM SEGMENTS SEGMENT SEGMENT SEGMENT TOTAL ------------ ------------ ------------ ------------ Goodwill...................... $ -- $ 2,777 $ 14,167 $ 16,944 Equity method goodwill........ -- -- 25,502 25,502

F-16 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) The following table reflects the components of amortized intangible assets, excluding goodwill (in thousands):

DECEMBER 31, 2002 DECEMBER 31, 2001 ----------------------------------------------------------------- GROSS CARRYING ACCUMULATED GROSS CARRYING ACCUMULATED AMOUNT AMORTIZATION AMOUNT AMORTIZATION -------------- -------------- -------------- -------------- Amortized intangible assets: Fractionation agreement.................. $ 38,000 $ (9,025) $ 38,000 $ (7,125) Natural gas transportation contracts..... 462,449 (28,710) 222,800 (3,275) Other.................................... 3,745 (1,085) 1,458 (371) -------------- -------------- -------------- -------------- Total................................. $ 504,194 $ (38,820) $ 262,258 $ (10,771) ============== ============== ============== ==============

Excluding goodwill, amortization expense on intangible assets was $27.9 million, $5.5 million and $2.0 million for the years ended December 31, 2002, 2001 and 2000, respectively. The following table sets forth the estimated amortization expense on intangible assets for the years ending December 31 (in thousands): 2003................................................... $ 50,799 2004................................................... 52,384 2005................................................... 52,657 2006................................................... 47,153 2007................................................... 42,174 NOTE 4. DERIVATIVE FINANCIAL INSTRUMENTS We have entered into an interest rate swap agreement to hedge our exposure to increases in the benchmark interest rate underlying our variable rate revolving credit facility. The term of the interest rate swap matches the maturity of the credit facility. We designated this swap agreement, which hedges exposure to variability in expected future cash flows attributed to changes in interest rates, as a cash flow hedge. The swap agreement is based on a notional amount of $250.0 million. Under the swap agreement, we pay a fixed rate of interest of 6.955% and receive a floating rate based on a three month U.S. Dollar LIBOR rate. Since this swap is designated as a cash flow hedge, the changes in fair value, to the extent the swap is effective, are recognized in other comprehensive income until the hedged interest costs are recognized in earnings. During the years ended December 31, 2002, and 2001, we recognized increases in interest expense of $12.9 million and $6.8 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap. During the year ended December 31, 2002, we measured the hedge effectiveness of this interest rate swap and noted that no gain or loss from ineffectiveness was required to be recognized. The fair value of the interest rate swap agreement was a loss of approximately $20.1 million and $20.3 million at December 31, 2002, and 2001, respectively. We anticipate that approximately $13.5 million of the fair value will be transferred into earnings over the next twelve months. On October 4, 2001, our TE Products subsidiary entered into an interest rate swap agreement to hedge its exposure to changes in the fair value of its fixed rate 7.51% Senior Notes due 2028. We designated this swap agreement as a fair value hedge. The swap agreement has a notional amount of $210.0 million and matures in January 2028 to match the principal and maturity of the TE Products Senior Notes. Under the swap agreement, TE Products pays a floating rate based on a three month U.S. Dollar LIBOR rate, plus a spread, and receives a fixed rate of interest of 7.51%. During the years ended December 31, 2002, and 2001, we recognized reductions in interest expense of $8.6 million and $1.8 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap. During the year ended December 31, 2002, we measured the hedge effectiveness of this interest rate swap and noted that no gain or loss from ineffectiveness was required to be F-17 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) recognized. The fair value of this interest rate swap agreement was a gain of approximately $13.6 million at December 31, 2002, and a loss of approximately $14.6 million at December 31, 2001. On February 20, 2002, we entered into interest rate swap agreements to hedge our exposure to changes in the fair value of our fixed rate 7.625% Senior Notes due 2012. We designated these swap agreements as fair value hedges. The swap agreements had a combined notional amount of $500.0 million and matured in 2012 to match the principal and maturity of the Senior Notes. Under the swap agreements, we paid a floating rate based on a six month U.S. Dollar LIBOR rate, plus a spread, and received a fixed rate of interest of 7.625%. On July 16, 2002, we terminated these interest rate swap agreements. Upon termination, the fair value of the interest rate swap agreements was $25.8 million. From inception of the swap agreements on February 20, 2002, through the termination on July 16, 2002, $7.8 million had been recognized as a reduction to interest expense. The remaining gain of approximately $18.0 million has been deferred as an adjustment to the carrying value of the Senior Notes and is being amortized using the effective interest method as a reduction to future interest expense over the remaining term of the Senior Notes. In the event of early extinguishment of the Senior Notes, any remaining unamortized gain would be recognized in the consolidated statement of income at the time of extinguishment. Additionally, on July 16, 2002, we entered into new interest rate swap agreements to hedge our exposure to changes in the fair value of our $500.0 million principal amount of 7.625% fixed rate Senior Notes due 2012. We designated these swap agreements as fair value hedges. The swap agreements had a combined notional amount of $500.0 million and matured in 2012 to match the principal and maturity of the Senior Notes. Under these swap agreements, we paid a floating rate based on a six month U.S. Dollar LIBOR rate, plus a spread, which increased by approximately 50 basis points from the previous swap agreements, and received a fixed rate of interest of 7.625%. On December 12, 2002, we terminated these interest rate swap agreements. Upon termination, the fair value of the interest rate swap agreements was $33.5 million. From inception of the swap agreements on July 16, 2002, through the termination on December 12, 2002, $6.6 million had been recognized as a reduction to interest expense. The remaining gain of approximately $26.9 million has been deferred as an adjustment to the carrying value of the Senior Notes and is being amortized using the effective interest method as a reduction to future interest expense over the remaining term of the Senior Notes. In the event of early extinguishment of the Senior Notes, any remaining unamortized gain would be recognized in the consolidated statement of income at the time of extinguishment. NOTE 5. ACQUISITIONS On July 20, 2000, we 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% 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. We assumed ARCO's role as operator of this pipeline. We 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, we 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, we reached a settlement with Atlantic Richfield Company of $11.0 million for the post-closing adjustments. F-18 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) We recorded the settlement as an increase to the purchase price of ARCO. We paid the settlement amount to Atlantic Richfield Company on October 15, 2001. On December 31, 2000, we completed an acquisition of 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. We also assumed a lease of a condensate pipeline from Carthage to Marshall, Texas. All three pipelines originate at DEFS' East Texas Plant Complex in Panola County, Texas. We accounted for the acquisition of these assets under the purchase method of accounting. On September 30, 2001, our subsidiaries completed the purchase of Jonah from Alberta Energy Company for $359.8 million. The acquisition served as our entry into the natural gas gathering industry. We recognized goodwill on the purchase of approximately $2.8 million. We accounted for the acquisition under the purchase method of accounting. Accordingly, the results of the acquisition are included in the consolidated financial statements from September 30, 2001. We paid an additional $7.3 million on February 4, 2002, for final purchase adjustments related primarily to construction projects in progress at the time of closing. Under a contractual agreement, DEFS manages and operates Jonah on our behalf. The following table allocates the estimated fair value of Jonah assets acquired on September 30, 2001, and includes the additional purchase adjustment paid on February 4, 2002 (in thousands): Property, plant and equipment .............................. $ 141,835 Intangible assets (primarily gas transportation contracts) . 222,800 Goodwill ................................................... 2,777 Other ...................................................... 147 ------------ Total assets ........................................... 367,559 ============ Total liabilities assumed .................................. (489) ------------ Net assets acquired .................................... $ 367,070 ============ The value assigned to intangible assets relates to contracts with customers that are for either a fixed term or which dedicate total future lease production. We are amortizing the value assigned to intangible assets on a unit of production basis, based upon the actual throughput of the system over the expected total throughput for the contracts (averaging approximately 16 years). On March 1, 2002, we completed the purchase of the Chaparral NGL system ("Chaparral") for $132.4 million from Diamond-Koch II, L.P. and Diamond-Koch III, L.P., including acquisition related costs of approximately $0.4 million. We funded the purchase by a drawdown of our $500.0 million revolving credit facility (see Note 10. Debt). Chaparral is an NGL pipeline system that extends from West Texas and New Mexico to Mont Belvieu. The pipeline delivers NGLs to fractionators and to our existing storage in Mont Belvieu. Under a contractual agreement, DEFS manages and operates these assets on our behalf. We accounted for the acquisition of these assets under the purchase method of accounting. We allocated the purchase price to property, plant and equipment. Accordingly, the results of the acquisition are included in the consolidated financial statements from March 1, 2002. On June 30, 2002, we completed the purchase of Val Verde for $444.2 million from Burlington Resources Gathering Inc., a subsidiary of Burlington Resources Inc., including acquisition related costs of approximately $1.2 million. We funded the purchase by drawing down $168.0 million under our $500.0 million revolving credit facility, $72.0 million under our 364-day revolving credit facility, and $200.0 million under a six-month term loan with SunTrust Bank (see Note 10. Debt). The remaining purchase price was funded through working capital sources of cash. The Val Verde system gathers CBM from the Fruitland Coal Formation of the San Juan Basin in F-19 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) New Mexico and Colorado. The system is one of the largest CBM gathering and treating facilities in the United States. Under a contractual agreement, DEFS manages and operates Val Verde on our behalf. We accounted for the acquisition of these assets under the purchase method of accounting. Accordingly, the results of the acquisition are included in the consolidated financial statements from June 30, 2002. The following table allocates the estimated fair value of the Val Verde assets acquired on June 30, 2002 (in thousands): Property, plant and equipment ................................. $ 205,146 Intangible assets (primarily gas transportation contracts) .... 239,649 ------------- Total assets ................................................ 444,795 ============= Total liabilities assumed ..................................... (645) ------------- Net assets acquired ......................................... $ 444,150 ============= The value assigned to intangible assets relates to fixed-term contracts with customers. We are amortizing the value assigned to intangible assets on a unit of production basis, based upon the actual throughput of the system over the expected total throughput for the contracts (averaging approximately 20 years). The following table presents our unaudited pro forma results as though the acquisitions of Jonah and Val Verde occurred at the beginning of 2001 or 2002 (in thousands, except per Unit amounts). The unaudited pro forma results give effect to certain pro forma adjustments including depreciation and amortization expense adjustments of property, plant and equipment and intangible assets based upon the purchase price allocations, interest expense related to financing the acquisitions, amortization of debt issue costs and the removal of income tax effects in historical results of operations. The pro forma results do not include operating efficiencies or revenue growth from historical results.

YEARS ENDED DECEMBER 31, ---------------------------------- 2002 2001 ------------ ------------ Revenues....................................................... $ 3,279,948 $ 3,659,496 Operating income............................................... 181,717 179,600 Net income..................................................... 130,335 119,286 Basic and diluted net income per Limited Partner and Class B Unit........................... $ 1.70 $ 2.00

The summarized pro forma information has been prepared for comparative purposes only. It is not intended to be indicative of the actual operating results that would have occurred had the acquisitions been consummated at the beginning of 2001 or 2002, or the results which may be attained in the future. NOTE 6. EQUITY INVESTMENTS The acquisition of the ARCO assets in July 2000 included ARCO's 50% ownership interest in 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. Seaway is a partnership between a subsidiary of TCTM, TEPPCO Seaway, L.P. ("TEPPCO Seaway"), and ConocoPhillips. TCTM purchased the 50% ownership interest in Seaway on July 20, 2000, and transferred the investment to TEPPCO Seaway. 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, TEPPCO Seaway received 80% of revenue and expense of Seaway. From June 2002 through May 2006, TEPPCO Seaway will receive 60% of revenue and expense of Seaway. Thereafter, the sharing ratio becomes 40% of revenue and F-20 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) expense to TEPPCO Seaway. For the year ended December 31, 2002, our portion of equity earnings on a pro-rated basis averaged approximately 67%. In August 2000, TE Products entered into agreements with Panhandle Eastern Pipeline Company ("PEPL"), a subsidiary of CMS Energy Corporation, and Marathon Ashland Petroleum LLC ("Marathon") to form Centennial Pipeline LLC ("Centennial"). Centennial owns an interstate refined petroleum products pipeline extending from the upper Texas Gulf Coast to Illinois. Through December 31, 2002, each participant owned a one-third interest in Centennial. During the years ended December 31, 2002 and 2001, we contributed approximately $10.9 million and $70.0 million, respectively, for our investment in Centennial. These amounts are included in the equity investment balance at December 31, 2002 and 2001. We use the equity method of accounting to report our investments in Seaway and Centennial. Summarized combined income statement data for Seaway and Centennial for the years ended December 31, 2002, and 2001, is presented below (in thousands):

YEARS ENDED DECEMBER 31, ----------------------------- 2002 2001 ---------- ---------- Revenues.................................... $ 83,237 $ 55,719 Net income.................................. 5,389 26,218

Summarized combined balance sheet data for Seaway and Centennial as of December 31, 2002, and 2001, is presented below (in thousands):

DECEMBER 31, ----------------------------- 2002 2001 ---------- ---------- Current assets.............................. $ 32,528 $ 57,368 Noncurrent assets........................... 551,324 528,835 Current liabilities......................... 28,681 31,308 Long-term debt.............................. 140,000 128,000 Noncurrent liabilities...................... 14,875 -- Partners' capital........................... 400,296 426,895

Our investment in Seaway at December 31, 2002, and 2001, includes an excess net investment amount of $25.5 million. Excess investment is the amount by which our investment balance exceeds our proportionate share of the net assets of the investment. Prior to January 1, 2002, and our adoption of SFAS 142, we were amortizing the excess investment in Seaway using the straight-line method over 20 years. NOTE 7. RELATED PARTY TRANSACTIONS We have no employees and are managed by the Company, a wholly owned subsidiary of DEFS. Duke Energy holds an approximate 70% interest in DEFS and ConocoPhillips holds the remaining 30%. According to the Partnership Agreements, the Company is entitled to reimbursement of all direct and indirect expenses related to our business activities (see Note 1. Partnership Organization). For the years ended December 31, 2002, 2001, and 2000, direct expenses incurred by the Company of $69.6 million, $68.2 million and $50.4 million, respectively, were charged to us by DEFS. Substantially all such costs were related to payroll and payroll related expenses. For the years ended December 31, 2002, 2001, and 2000, expenses for administrative services and overhead allocated to us by Duke Energy and its affiliates were $0.8 million, $0.6 million and $0.8 million, respectively. F-21 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) Effective with the purchase of the fractionation facilities on March 31, 1998, TEPPCO Colorado, LLC ("TEPPCO Colorado") and DEFS entered into a 20-year Fractionation Agreement, under which TEPPCO Colorado receives a variable fee for all fractionated volumes delivered to DEFS. Revenues recognized from the fractionation facilities totaled $7.4 million, $7.4 million and $7.5 million for the years ended December 31, 2002, 2001 and 2000, respectively. TEPPCO Colorado and DEFS also entered into an Operation and Maintenance Agreement, whereby DEFS operates and maintains the fractionation facilities. For these services, TEPPCO Colorado pays DEFS a set volumetric rate for all fractionated volumes delivered to DEFS. Expenses related to the Operation and Maintenance Agreement totaled $0.9 million, $0.9 million and $0.9 million for the years ended December 31, 2002, 2001 and 2000, respectively. Included with 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 paid to us by DEFS under the agreement totaled $1.2 million, $1.2 million and $1.1 million for the years ended December 31, 2002, 2001 and 2000, respectively. The Panola Pipeline and San Jacinto Pipeline were purchased on December 31, 2000, from DEFS for $91.7 million. These pipelines originate at DEFS' East Texas Plant Complex in Panola County, Texas. For the years ended December 31, 2002 and 2001, revenues recognized included $12.0 million and $13.9 million, respectively, from a subsidiary of DEFS for NGL transportation fees on the Panola and San Jacinto Pipelines. On July 20, 2000, we, through TCTM, acquired a 50% ownership interest in Seaway. ConocoPhillips owns the remaining 50% interest in Seaway. TEPPCO Crude Pipeline, L.P. is the operator of this pipeline. During the years ended December 31, 2002, 2001 and 2000, we billed Seaway $7.1 million, $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, 2002, 2001 and 2000, we billed Seaway $2.1 million, $2.1 million and $0.9 million, respectively, for indirect management fees for operating Seaway. Effective May 2001, we entered into an agreement with DEFS to commit sole utilization of our Providence terminal to DEFS. We operate the terminal and provide propane loading services to DEFS. During the years ended December 31, 2002 and 2001, revenues of $2.3 million and $1.5 million from DEFS, respectively, were recognized pursuant to this agreement. On September 30, 2001, we completed the acquisition of Jonah. The Jonah assets are managed and operated by employees of DEFS under a contractual agreement under which DEFS is reimbursed for its actual costs. During the years ended December 31, 2002, and 2001, we recognized $3.3 million and $0.6 million, respectively, of expense related to the management of the Jonah assets by DEFS. On March 1, 2002, we completed the acquisition of the Chaparral NGL system. The Chaparral assets are managed and operated by employees of DEFS under a contractual agreement under which DEFS is reimbursed for its actual costs. During the year ended December 31, 2002, we recognized $1.7 million of expenses related to the management of the Chaparral assets by DEFS. On June 30, 2002, we completed the acquisition of Val Verde. The Val Verde assets are managed and operated by employees of DEFS under a contractual agreement under which DEFS is reimbursed for its actual costs. During the year ended December 31, 2002, we recognized $1.2 million of expenses related to the management of the Val Verde assets by DEFS. In August 2000, TE Products entered into agreements with PEPL and Marathon to form Centennial (see Note 6. Equity Investments). At December 31, 2002, TE Products had a one-third ownership interest in Centennial. TE Products has entered into a management agreement with Centennial to operate Centennial's terminal at Creal Springs and pipeline connection in Beaumont, Texas. For the year ended December 31, 2002, we recognized management fees of $0.2 million from Centennial, and actual operating expenses billed to Centennial were $0.3 F-22 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) million. TE Products also has a joint tariff with Centennial to deliver products at TE Products' locations using Centennial's pipeline as part of the delivery route to connecting carriers. TE Products, as the delivering pipeline, invoices the shippers for the entire delivery rate, records only the net rate attributable to it as transportation revenues and records a liability for the amounts due to Centennial for its share of the tariff. At December 31, 2002, we have a payable balance of $1.0 million to Centennial for its share of the joint tariff deliveries. In addition, TE Products performs ongoing construction services for Centennial and bills Centennial for labor and other costs to perform the construction. At December 31, 2002, TE Products has a receivable of $1.9 million due from Centennial for reimbursement of construction services provided to Centennial. NOTE 8. 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, ----------------------------- 2002 2001 ------------ ------------ Crude oil.................................. $ -- $ 3,783 Gasolines.................................. 4,700 4,548 Propane.................................... -- 1,096 Butanes.................................... 1,991 1,431 Transmix................................... 2,526 878 Other products............................. 3,836 1,988 Materials and supplies..................... 4,113 3,519 ------------ ----------- Total............................... $ 17,166 $ 17,243 ============ ===========

The costs of inventories did not exceed market values at December 31, 2002 and 2001. NOTE 9. PROPERTY, PLANT AND EQUIPMENT Major categories of property, plant and equipment were as follows (in thousands):

DECEMBER 31, ----------------------------- 2002 2001 ------------- ------------ Land and right of way............................................. $ 106,279 $ 92,664 Line pipe and fittings...................... ..................... 1,090,848 822,332 Storage tanks..................................................... 143,740 130,461 Buildings and improvements........................................ 20,408 15,131 Machinery and equipment........................................... 463,049 252,393 Construction work in progress..................................... 102,246 157,728 ------------- ------------ Total property, plant and equipment........................ $ 1,926,570 $ 1,470,709 Less accumulated depreciation and amortization............. 338,746 290,248 ------------- ------------ Net property, plant and equipment........................ $ 1,587,824 $ 1,180,461 ============= ============

Depreciation expense on property, plant and equipment was $56.0 million, $39.5 million and $33.0 million for the years ended December 31, 2002, 2001 and 2000, respectively. F-23 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) NOTE 10. LONG TERM DEBT SENIOR NOTES On January 27, 1998, TE Products completed the issuance of $180.0 million principal amount of 6.45% Senior Notes due 2008, and $210.0 million principal amount of 7.51% Senior Notes due 2028 (collectively the "TE Products Senior Notes"). The 6.45% TE Products Senior Notes were issued at a discount of $0.3 million and are being accreted to their face value over the term of the notes. The 6.45% TE Products Senior Notes due 2008 are not subject to redemption prior to January 15, 2008. The 7.51% TE Products Senior Notes due 2028, issued at par, may be redeemed at any time after January 15, 2008, at the option of TE Products, in whole or in part, at a premium. The TE Products Senior Notes do not have sinking fund requirements. Interest on the TE Products Senior Notes is payable semiannually in arrears on January 15 and July 15 of each year. The TE Products Senior Notes are unsecured obligations of TE Products and rank on a parity with all other unsecured and unsubordinated indebtedness of TE Products. The indenture governing the TE Products Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit our ability to incur additional indebtedness. As of December 31, 2002, TE Products was in compliance with the covenants of the TE Products Senior Notes. On February 20, 2002, we received $494.6 million in net proceeds, after underwriting discount, from the issuance of $500.0 million principal amount of 7.625% Senior Notes due 2012. The 7.625% Senior Notes were issued at a discount of $2.2 million and are being accreted to their face value over the term of the notes. We used the proceeds from the offering to reduce a portion of the outstanding balances of our credit facilities, including those issued in connection with the acquisition of Jonah. The Senior Notes may be redeemed at any time at our option with the payment of accrued interest and a make-whole premium determined by discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of comparable remaining maturity plus 35 basis points. The indenture governing our 7.625% Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit our ability to incur additional indebtedness. As of December 31, 2002, we were in compliance with the covenants of these Senior Notes. At December 31, 2002 and 2001, the estimated fair value of the Senior Notes was approximately $914.9 million and $362.0 million, respectively. Market prices for recent transactions and rates currently available to us for debt with similar terms and maturities were used to estimate fair value. We have entered into interest rate swap agreements to hedge our exposure to changes in the fair value on a portion of the Senior Notes discussed above. See Note 4. Derivative Financial Instruments. OTHER LONG TERM DEBT AND CREDIT FACILITIES On July 14, 2000, we entered into a $75.0 million term loan and a $475.0 million revolving credit facility ("Three Year Facility"). On July 21, 2000, we borrowed $75.0 million under the term loan and $340.0 million under the Three Year Facility. The funds were used to finance the acquisition of the ARCO assets (see Note 5. 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 Three Year Facility was amended to provide for revolving borrowings of up to $500.0 million for a period of three years including the issuance of letters of credit of up to $20.0 million. The interest rate is based, at our option, on either the lender's base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement for the Three Year Facility contains restrictive financial covenants that require us to maintain a minimum level of partners' capital as well as maximum debt-to-EBITDA (earnings before interest expense, income F-24 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) tax expense and depreciation and amortization expense) and minimum fixed charge coverage ratios. On February 20, 2002, we repaid $115.7 million of the then outstanding balance of the Three Year Facility with proceeds from the issuance of our 7.625% Senior Notes. On March 1, 2002, we borrowed $132.0 million under the Three Year Facility to finance the acquisition of the Chaparral NGL system. On March 22, 2002, we repaid a portion of the Three Year Facility with proceeds we received from the issuance of additional Limited Partner Units (see Note 11. Partners' Capital). To facilitate our financing of a portion of the purchase price of the Val Verde assets, on June 27, 2002, the Three Year Facility was amended to increase the maximum permitted debt-to-EBITDA ratio covenant to allow us to incur additional indebtedness. For the twelve month period ending June 30, 2002, the maximum permitted ratio was 5.5-to-1 on a pro forma basis. For the twelve month period ending September 30, 2002, the maximum permitted ratio was 5.0-to-1 on a pro forma basis. At December 31, 2002, the maximum permitted debt-to-EBITDA ratio under our revolving credit facility returned to its pre-amendment level of 4.5-to-1. We then drew down the existing capacity of the Three Year Facility and acquired the Val Verde assets. During the fourth quarter of 2002, we repaid $68.0 million of the outstanding balance of the Three Year Facility with proceeds from our November 2002 equity offering (see Note 11. Partners' Capital) and proceeds from the termination of our interest rate swaps (see Note 4. Derivative Financial Instruments). At December 31, 2002, $432.0 million was outstanding under the Three Year Facility at a weighted average interest rate of 2.5%. As of December 31, 2002, we were in compliance with the covenants contained in this credit agreement. We have entered into an interest rate swap agreement to hedge our exposure to increases in interest rates on the Three Year Facility discussed above. See Note 4. Derivative Financial Instruments. SHORT TERM CREDIT FACILITIES On April 6, 2001, we entered into a 364-day, $200.0 million revolving credit agreement ("Short-term Revolver"). The interest rate is based, at our option, on either the lender's base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement contains restrictive financial covenants that require us to maintain a minimum level of partners' capital as well as maximum debt-to-EBITDA and minimum fixed charge coverage ratios. On March 28, 2002, the Short-term Revolver was extended for an additional period of 364 days, ending in March 2003. To facilitate our financing of a portion of the purchase price of the Val Verde assets, on June 27, 2002, the Short-term Revolver was amended to increase the maximum permitted debt-to-EBITDA ratio covenant to allow us to incur additional indebtedness. For the twelve month period ending June 30, 2002, the maximum permitted ratio was 5.5-to-1 on a pro forma basis. For the twelve month period ending September 30, 2002, the maximum permitted ratio was 5.0-to-1 on a pro forma basis. At December 31, 2002, the maximum permitted debt-to-EBITDA ratio under our revolving credit facility returned to its pre-amendment level of 4.5-to-1. We then drew down $72.0 million under the Short-term Revolver. In the fourth quarter of 2002, we repaid the existing amounts outstanding under the Short-term Revolver with proceeds we received from the issuance of Limited Partner Units in November and December 2002. At December 31, 2002, no amounts were outstanding under the Short-term Revolver. As of December 31, 2002, we were in compliance with the covenants contained in this credit agreement. In February 2003, we gave notice that we will not renew the Short-term Revolver. As a result, the facility will expire on March 27, 2003. On September 28, 2001, we entered into a $400.0 million credit facility with SunTrust Bank ("Bridge Facility") payable in June 2002. We borrowed $360.0 million under the Bridge Facility to acquire the Jonah assets (see Note 5. Acquisitions). During the fourth quarter of 2001, we repaid $160.0 million of the outstanding principal from proceeds received from the issuance of Limited Partner Units in November 2001. On February 5, 2002, we drew down an additional $15.0 million under the Bridge Facility. On February 20, 2002, we repaid the outstanding balance of the Bridge Facility of $215.0 million with proceeds from the issuance of the 7.625% Senior Notes and canceled the facility. On June 27, 2002, we entered into a $200.0 million six-month term loan with SunTrust Bank ("Six-Month Term Loan") payable in December 2002. We borrowed $200.0 million under the Six-Month Term Loan to acquire F-25 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) the Val Verde assets (see Note 5. Acquisitions). The interest rate was based, at our option, on either the lender's base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement contained restrictive financial covenants that required us to maintain a minimum level of partners' capital as well as maximum debt-to-EBITDA and minimum fixed charge coverage ratios. On July 11, 2002, we repaid $90.0 million of the outstanding principal from proceeds primarily received from the issuance of Limited Partner Units in July 2002. On September 10, 2002, we repaid the remaining outstanding balance of $110.0 million with proceeds received from the issuance of Limited Partner Units in September 2002 (see Note 11. Partners' Capital), and canceled the facility. The following table summarizes the principal amounts outstanding under our credit facilities as of December 31, 2002 and 2001 (in thousands):

DECEMBER 31, ------------------------------------ 2002 2001 ---------------- ---------------- Short Term Credit Facilities: Short-term Revolver, due March 2003...................... $ -- $ 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...................... $ 432,000 $ 340,658 6.45% TE Products Senior Notes, due January 2008......... 179,845 179,814 7.51% TE Products Senior Notes, due January 2028......... 210,000 210,000 7.625% Senior Notes, due February 2012................... 497,995 -- ---------------- ---------------- Total borrowings...................................... 1,319,840 730,472 Adjustment to carrying value associated with hedges of fair value............................................ 57,852 (14,630) ---------------- ---------------- Total Long Term Credit Facilities.................. $ 1,377,692 $ 715,842 ================ ================

NOTE 11. PARTNERS' CAPITAL On February 6, 2001, we sold in an underwritten public offering 2.0 million Limited Partner Units at $25.50 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $48.7 million and were used to reduce borrowings under the Three Year Facility. On March 6, 2001, 250,000 Units were sold upon exercise of the underwriters' over-allotment option granted in connection with the offering on February 6, 2001. Proceeds from that sale totaled $6.1 million and were used for general purposes. On November 14, 2001, we sold in an underwritten public offering 5.5 million Limited Partner Units at $34.25 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $180.3 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 March 22, 2002, we sold in an underwritten public offering 1.92 million Limited Partner Units at $31.18 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $57.3 million and were used to repay $50.0 million of the outstanding balance on the Three Year Facility, with the remaining amount being used for general purposes. On July 11, 2002, we sold in an underwritten public offering 3.0 million Limited Partner Units at $30.15 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $86.6 million and were used to reduce borrowings under our Six-Month Term Loan. On August 14, 2002, 175,000 Units were sold F-26 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) upon exercise of the underwriters' over-allotment option granted in connection with the offering on July 11, 2002. Proceeds from that sale totaled $5.1 million and were used for general purposes. On September 6, 2002, we sold in an underwritten public offering 3.8 million Limited Partner Units at $29.72 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $108.1 million and were used to reduce borrowings under our Six-Month Term Loan. On September 19, 2002, 570,000 Units were sold upon exercise of the underwriters' over-allotment option granted in connection with the offering on September 6, 2002. Proceeds from that sale totaled $16.2 million and were used to reduce borrowings under our Short-term Revolver. On November 7, 2002, we sold in an underwritten public offering 3.3 million Limited Partner Units at $26.83 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $84.8 million and were used to reduce borrowings under our Short-term Revolver and Three Year Facility. On December 4, 2002, 495,000 Units were sold upon exercise of the underwriters' over-allotment option granted in connection with the offering on November 7, 2002. Proceeds from that sale totaled $12.7 million and were used to reduce borrowings under our Short-term Revolver and Three Year Facility. NOTE 12. CONCENTRATIONS OF CREDIT RISK Our primary market areas are located in the Northeast, Midwest and Southwest regions of the United States. We have a concentration of trade receivable balances due from major integrated oil companies, independent oil companies and other pipelines and wholesalers. These concentrations of customers may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors. We thoroughly analyze our customers' historical and future credit positions prior to extending credit. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions may utilize letters of credit, prepayments and guarantees. For the years ended December 31, 2002, 2001 and 2000, we had one customer from the Upstream Segment, Valero Energy Corp., which accounted for 16%, 14% and 12%, respectively, of our total consolidated revenues. The carrying amount of cash and cash equivalents, accounts receivable, 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 13. QUARTERLY DISTRIBUTIONS OF AVAILABLE CASH We make quarterly cash distributions of all of our Available Cash, generally defined as consolidated cash receipts less consolidated cash disbursements and cash reserves established by the General Partner in its sole discretion. Pursuant to the Partnership Agreement, the Company receives incremental incentive cash distributions when cash distributions exceed certain target thresholds 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%

F-27 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) The following table reflects the allocation of total distributions paid for the years ended December 31, 2002, 2001 and 2000 (in thousands, except per Unit amounts).

YEARS ENDED DECEMBER 31, ------------------------------------------ 2002 2001 2000 ----------- ----------- ----------- Limited Partner Units........................................ $ 104,932 $ 73,961 $ 59,943 General Partner Ownership Interest........................... 2,329 1,273 685 General Partner Incentive.................................... 35,389 20,257 12,938 ----------- ----------- ---------- Total Partners' Capital Cash Distributions............... 142,650 95,491 73,566 Class B Units................................................ 9,204 8,421 7,833 Minority Interest............................................ -- 500 832 ----------- ----------- ---------- Total Cash Distributions Paid............................ $ 151,854 $ 104,412 $ 82,231 =========== =========== ========== Total Cash Distributions Paid Per Unit....................... $ 2.35 $ 2.15 $ 2.00 =========== =========== ==========

On February 7, 2003, we paid a cash distribution of $0.60 per Limited Partner Unit and Class B Unit for the quarter ended December 31, 2002. The fourth quarter 2002 cash distribution totaled $46.5 million. NOTE 14. UNIT-BASED COMPENSATION 1994 LONG TERM INCENTIVE PLAN During 1994, the Company adopted the Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan ("1994 LTIP"). The 1994 LTIP provides certain key employees with an incentive award whereby a participant is granted an option to purchase Limited Partner Units. These same employees are also granted a stipulated number of Performance Units, the cash value of which may be used to pay for the exercise of the respective Limited Partner Unit options awarded. Under the provisions of the 1994 LTIP, no more than one million options and two million Performance Units may be granted. When our calendar year earnings per unit (exclusive of certain special items) exceeds a stated threshold, each participant receives a credit to their respective Performance Unit account equal to the earnings per unit excess multiplied by the number of Performance Units awarded. The balance in the Performance Unit account may be used to offset the cost of exercising 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. We accrue compensation expense for the Performance Units awarded annually based upon the terms of the plan discussed above. 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........................................... 11,100 $ 1.875 2009

F-28 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

OPTIONS OPTIONS EXERCISE OUTSTANDING EXERCISABLE RANGE ------------ ---------------- ------------------ Limited Partner Unit Options: 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................................ (2,800) -- $25.25 Became exercisable....................... -- 81,669 $25.25 - $25.69 Exercised................................ (98,376) (98,376) $13.81 - $25.69 ------------ ---------------- Outstanding at December 31, 2001............ 189,688 143,822 $13.81 - $25.69 Forfeited................................ -- -- $25.25 Became exercisable....................... -- 45,866 $25.25 Exercised................................ (99,597) (99,597) $13.81 - $25.69 ------------ ---------------- Outstanding at December 31, 2002............ 90,091 90,091 $13.81 - $25.69 ============ ================

We have not granted options for any periods presented. For options outstanding, we followed the intrinsic value method for recognizing stock-based compensation expense. The exercise price of all options awarded under the 1994 LTIP equaled the market price of our Limited Partner Units on the date of grant. Accordingly, we recognized no compensation expense at the date of grant. Had compensation expense been determined consistent with SFAS No. 123, Accounting for Stock-Based Compensation, compensation expense related to option grants would have totaled $5,570, $118,820 and $202,634 during the years ended December 31, 2002, 2001 and 2000, 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. For purposes of determining compensation costs using the provisions of SFAS 123, the fair value of option grants was determined using the Black-Scholes option-valuation model. The key input variables used in valuing the options were: Risk-free interest rate................................ 4.7% Dividend yield......................................... 7.6% Unit price volatility.................................. 23% Expected option lives.................................. 6 years 1999 AND 2002 PHANTOM UNIT PLANS Effective September 1, 1999, the Company adopted the Texas Eastern Products Pipeline Company, LLC 1999 Phantom Unit Retention Plan ("1999 PURP"). Effective June 1, 2002 the Company adopted the Texas Eastern Products Pipeline Company, LLC 2002 Phantom Unit Retention Plan ("2002 PURP"). The 1999 PURP and the 2002 PURP provide key employees with incentive awards whereby a participant is granted phantom units. These phantom units are automatically redeemed for cash based on the vested portion of the fair market value of the phantom units at stated redemption dates. The fair market value of each phantom unit is equal to the closing price of a Limited Partnership Unit as reported on the New York Stock Exchange on the redemption date. Under the agreement for the phantom units, each participant will vest 10% of the number of phantom units initially granted under his or her award at the end of each of the first four years and will vest the final 60% at the end of the fifth year. Each participant is required to redeem their units as they vest. They are also entitled to quarterly cash distributions equal to the product of the number of phantom units outstanding for the participant and the F-29 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) amount of the cash distribution that we paid per unit to Limited Partner Unitholders. A total of 58,800 phantom units have been granted under the 1999 PURP, of which 30,330 remain outstanding at December 31, 2002. A total of 71,400 phantom units have been granted under the 2002 PURP, of which all 71,400 remain outstanding at December 31, 2002. We accrue compensation expense annually based upon the terms of the 1999 PURP and 2002 PURP discussed above. 2000 LONG TERM INCENTIVE PLAN Effective January 1, 2000, the General Partner established the Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan ("2000 LTIP") to provide key employees incentives to achieve improvements in our financial performance. Generally, upon the close of a three-year performance period, if the participant is then still an employee of the General Partner, the participant will receive a cash payment in an amount equal to (1) the applicable performance percentage specified in the award multiplied by (2) the number of phantom 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 our Economic Value Added during a three-year performance period over the Economic Value Added during the three-year period immediately preceding the performance period. The performance percentage may not exceed 150%. If a participant incurs a separation from service during the performance period due to death, disability or retirement (as such terms are defined in the 2000 LTIP), the participant will be entitled to receive a cash payment in an amount equal to the amount computed as described above multiplied by a fraction, the numerator of which is the number of days that have elapsed during the performance period prior to the participant's separation from service and the denominator of which is the number of days in the performance period. At December 31, 2002, phantom Limited Partner Units outstanding were 22,300, 24,013 and 18,425 for awards granted in 2002, 2001 and 2000, respectively. Economic Value Added means our average annual EBITDA for the performance period minus the product of our average asset base and our cost of capital for the performance period. For purposes of the 2000 LTIP for plan years 2000 through 2002, EBITDA means our earnings before net interest expense, depreciation and amortization and our proportional interest in EBITDA of our joint ventures as presented in our consolidated financial statements prepared in accordance with generally accepted accounting principles, except that in its discretion the Compensation Committee of the General Partner may exclude gains or losses from extraordinary, unusual or non-recurring items. Average asset base means the quarterly average, during the performance period, of our gross value of property, plant and equipment, plus products and crude oil linefill and the gross value of intangibles and equity investments. Our cost of capital is approved by the Committee at the date of award grant. In addition to the payment described above, during the performance period, the General Partner will pay to the Participant the amount of cash distributions that we would have paid to our Unitholders had the participant been the owner of the number of Limited Partner Units equal to the number of phantom Limited Partner Units granted to the participant under this award. The maximum potential payout under the 2000 LTIP is 150% of phantom units awarded. We accrue compensation expense annually based upon the terms of the 2000 LTIP discussed above. F-30 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) NOTE 15. OPERATING LEASES We utilize leased assets in several areas of our operations. Total rental expense during the years ended December 31, 2002, 2001 and 2000 was $14.2 million, $10.8 million and $10.7 million, respectively. The following table sets forth our minimum rental payments under our various operating leases for the years ending December 31 (in thousands): 2003...................................... $ 9,479 2004...................................... 8,903 2005...................................... 8,102 2006...................................... 6,035 2007...................................... 1,820 Thereafter................................ 1,068 ---------- $ 35,407 ========== NOTE 16. 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. The components of net pension benefits costs for the TEPPCO RCBP and the TEPPCO SBP for the years ended December 31, 2002, 2001 and 2000, and for the Duke Energy RCBP and the Duke Energy ECBP for the year ended December 31, 2000 were as follows (in thousands):

2002 2001 2000 ---------- ---------- ---------- Service cost benefit earned during the year........... $ 2,925 $ 2,419 $ 2,054 Interest cost on projected benefit obligation......... 315 129 782 Expected return on plan assets........................ (390) (166) (663) Amortization of prior service cost.................... 7 8 -- Amortization of net transition liability.............. -- -- 4 Recognized net actuarial loss ........................ 12 -- -- ---------- ---------- --------- Net pension benefits costs........................ $ 2,869 $ 2,390 $ 2,177 ========== ========== =========

F-31 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) 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 year ended December 31, 2000, and for the TEPPCO OPB for the years ended December 31, 2002 and 2001, were as follows (in thousands):

2002 2001 2000 ---------- --------- --------- Service cost benefit earned during the year...................... $ 115 $ 99 $ 39 Interest cost on accumulated postretirement benefit obligation... 119 113 134 Expected return on plan assets................................... -- -- (85) Amortization of prior service cost............................... 126 126 (96) Amortization of net transition liability......................... -- -- 54 ---------- --------- --------- Net postretirement benefits costs........................... $ 360 $ 338 $ 46 ========== ========= =========

The weighted average assumptions used in the actuarial computations for the retirement plans and other postretirement benefit plans for the years ended December 31, 2002 and 2001 are as follows:

OTHER POSTRETIREMENT PENSION BENEFITS BENEFITS ------------------------- ------------------------ 2002 2001 2002 2001 ---------- ---------- ---------- ---------- Discount rate........................................ 6.75% 7.25% 6.75% 7.25% Increase in compensation levels...................... 5.00% 5.06% -- -- Expected long-term rate of return on plan assets..... 9.00% 9.00% -- --

F-32 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, 2002 and 2001 (in thousands):

OTHER POSTRETIREMENT PENSION BENEFITS BENEFITS ------------------------- ------------------------ 2002 2001 2002 2001 ----------- --------- ---------- --------- CHANGE IN BENEFIT OBLIGATION Benefit obligation at beginning of year............ $ 3,786 $ 1,518 $ 1,781 $ -- Service cost....................................... 2,925 2,419 115 99 Interest cost...................................... 315 129 118 113 Plan amendments.................................... -- 62 -- 1,508 Actuarial (gain)/loss.............................. 711 (136) 1 57 Retiree contributions.............................. -- -- 29 9 Benefits paid...................................... (159) (206) (43) (5) ----------- --------- ---------- --------- Benefit obligation at end of year.................. $ 7,578 $ 3,786 $ 2,001 $ 1,781 =========== ========= ========== ========= CHANGE IN PLAN ASSETS Fair value of plan assets at beginning of year..... $ 3,959 $ -- $ -- $ -- Actual return on plan assets....................... (99) (37) -- -- Retiree contributions.............................. -- -- 29 9 Employer contributions............................. 3,119 4,202 14 (4) Benefits paid...................................... (159) (206) (43) (5) ----------- --------- ---------- --------- Fair value of plan assets at end of year........... $ 6,820 $ 3,959 $ -- $ -- =========== ========= ========== ========= RECONCILIATION OF FUNDED STATUS Funded status...................................... $ (758) $ 173 $ (2,001) $ (1,781) Unrecognized prior service cost.................... 47 54 1,255 1,381 Unrecognized actuarial loss........................ 1,255 68 58 57 ----------- --------- ---------- --------- Net amount recognized.............................. $ 544 $ 295 $ (688) $ (343) =========== ========= ========== =========

- ----------------------- (1) The TEPPCO OPB became effective on January 1, 2001. OTHER PLANS DEFS also sponsors an employee savings plan, which covers substantially all employees. Plan contributions on behalf of the Company of $2.8 million, $3.1 million and $2.2 million were expensed during the years ended December 31, 2002, 2001 and 2000, respectively. NOTE 17. COMMITMENTS AND CONTINGENCIES In the fall of 1999 and on December 1, 2000, the General Partner and the Partnership were named as defendants in two separate lawsuits in Jackson County Circuit Court, Jackson County, Indiana, styled Ryan E. McCleery and Marcia S. McCleery, et. al. v. Texas Eastern Corporation, et. al. (including the General Partner and Partnership) and Gilbert Richards and Jean Richards v. Texas Eastern Corporation, et. al. (including the General Partner and Partnership). In both cases, the plaintiffs contend, among other things, that we and other defendants stored and disposed of toxic and hazardous substances and hazardous wastes in a manner that caused the materials to be released into the air, soil and water. They further contend that the release caused damages to the plaintiffs. In F-33 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) their complaints, the plaintiffs allege strict liability for both personal injury and property damage together with gross negligence, continuing nuisance, trespass, criminal mischief and loss of consortium. The plaintiffs are seeking compensatory, punitive and treble damages. We have filed an answer to both complaints, denying the allegations, as well as various other motions. These cases are not covered by insurance. Discovery is ongoing, and we are defending ourselves vigorously against the lawsuits. The plaintiffs have not stipulated the amount of damages that they are seeking in the suit. We cannot estimate the loss, if any, associated with these pending lawsuits. On December 21, 2001, TE Products was named as a defendant in a lawsuit in the 10th Judicial District, Natchitoches Parish, Louisiana, styled Rebecca L. Grisham et. al. v. TE Products Pipeline Company, Limited Partnership. In this case, the plaintiffs contend that our pipeline, which crosses the plaintiff's property, leaked toxic products onto the plaintiff's property. The plaintiffs further contend that this leak caused damages to the plaintiffs. We have filed an answer to the plaintiff's petition denying the allegations. The plaintiffs have not stipulated the amount of damages they are seeking in the suit. We are defending ourselves vigorously against the lawsuit. We cannot estimate the damages, if any, associated with this pending lawsuit; however, this case is covered by insurance. On April 19, 2002, we, through our subsidiary TEPPCO Crude Oil, L.P., filed a declaratory judgment action in the U.S. District Court for the Western District of Oklahoma against D.R.D. Environmental Services, Inc. ("D.R.D.") seeking resolution of billing and other contractual disputes regarding potential overcharges for environmental remediation services provided by D.R.D. On May 28, 2002, D.R.D. filed a counterclaim for alleged breach of contract in the amount of $2,243,525, and for unspecified damages for alleged tortious interference with D.R.D.'s contractual relations with DEFS. We have denied the counterclaims. Discovery is ongoing. If D.R.D. should be successful, management believes that a substantial portion of the $2,243,525 breach of contract claim will be covered under an indemnity from DEFS. We cannot predict the outcome of the litigation against us; however, we are defending ourselves vigorously against the counterclaim. We do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows. In addition to the litigation discussed above, we have been, in the ordinary course of business, a defendant in various lawsuits and a party to various other legal proceedings, some of which are covered in whole or in part by insurance. We believe that the outcome of these lawsuits and other proceedings will not individually or in the aggregate have a material adverse effect on our consolidated financial position, results of operations or cash flows. In February 2002, a producer on the Jonah system sent a letter to Alberta Energy Company implying that as a result of our acquisition of the Jonah system, it may have a right to acquire all or a portion of the assets comprising the Jonah system pursuant to an alleged right of first refusal in a gas gathering agreement between the producer and Jonah. Subsidiaries of Alberta Energy Company have agreed to indemnify us against losses resulting from any breach of representations concerning the absence of third party rights in connection with our acquisition of the entity that owns the Jonah system. We believe that we have adequate legal defenses if the producer should assert a claim, and we also believe that no right of first refusal on any of the underlying Jonah system assets has been triggered. Our operations are subject to federal, state and local laws and regulations governing the discharge of materials into the environment. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of injunctions delaying or prohibiting certain activities and the need to perform investigatory and remedial activities. Although we believe our operations are in material compliance with applicable environmental laws and regulations, risks of significant costs and liabilities are inherent in pipeline operations, and we cannot assure you that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly strict environmental laws and regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us. We believe that changes in environmental laws and regulations will not have a material adverse effect on our financial position, results of operations or cash flows in the near term. F-34 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) In 1994, we entered into an Agreed Order with the Indiana Department of Environmental Management ("IDEM") that resulted in the implementation of a remediation program for groundwater contamination attributable to our operations at the Seymour, Indiana, terminal. In 1999, the IDEM approved a Feasibility Study, which includes our proposed remediation program. We expect the IDEM to issue a Record of Decision formally approving the remediation program. After the Record of Decision is issued, we will enter into a subsequent Agreed Order for the continued operation and maintenance of the remediation program. We have an accrued liability of $0.4 million at December 31, 2002, for future remediation costs at the Seymour terminal. We do not expect that the completion of the remediation program will have a future material adverse effect on our financial position, results of operations or cash flows. In 1994, the Louisiana Department of Environmental Quality ("LDEQ") issued a compliance order for environmental contamination at our Arcadia, Louisiana, facility. This contamination may be attributable to our operations, as well as adjacent petroleum terminals operated by other companies. In 1999, our Arcadia facility and adjacent terminals were directed by the Remediation Services Division of the LDEQ to pursue remediation of this containment phase. At December 31, 2002, we have an accrued liability of $0.2 million for remediation costs at our Arcadia facility. We do not expect that the completion of the remediation program that we have proposed will have a future material adverse effect on our financial position, results of operations or cash flows. At December 31, 2002, we have an accrued liability of $5.6 million and a receivable of $4.2 million from DEFS related to various TCTM sites requiring environmental remediation activities. The receivable is based on a contractual indemnity obligation we received in connection with our acquisition of assets from a DEFS affiliate in November 1998. The indemnity relates to future environmental remediation activities attributable to operations of these assets prior to our acquisition. Under this indemnity obligation, we are responsible for the first $3.0 million in specified environmental liabilities, and DEFS is responsible for those environmental liabilities in excess of $3.0 million, up to a maximum amount of $25.0 million. The majority of the receivable from DEFS relates to remediation activities at the Velma crude oil site in Stephens County, Oklahoma. The accrued liability balance at December 31, 2002, also includes an accrual of $2.3 million related to the Shelby crude oil site in Stephens County, Oklahoma. At December 31, 2002, it is uncertain if these costs related to Shelby are covered under the indemnity obligation from DEFS. We are currently in discussions with DEFS regarding these matters. We do not expect that the completion of remediation programs associated with TCTM activities will have a future material adverse effect on our financial position, results of operations or cash flows. Centennial entered into credit facilities totaling $150.0 million, and as of December 31, 2002, $150.0 million was outstanding under those credit facilities. The proceeds were used to fund construction and conversion costs of its pipeline system. Each of the participants in Centennial, including TE Products, originally guaranteed one-third of Centennial's debt up to a maximum amount of $50.0 million. During the third quarter of 2002, PEPL, one of the participants in Centennial, was downgraded by Moody's and Standard & Poors to below investment grade, which resulted in PEPL being in default under its portion of the Centennial guaranty. Effective September 27, 2002, TE Products and Marathon increased their guaranteed amounts to one-half of the debt of Centennial, up to a maximum amount of $75.0 million each, to avoid a default on the Centennial debt. As compensation to TE Products and Marathon for providing their additional guarantees, PEPL was required to pay interest at a rate of 4% per annum to each of TE Products and Marathon on the portion of the additional guaranty that each has provided for PEPL. In February 2000, we entered into a joint marketing and development alliance with Louis Dreyfus Plastics Corporation, now known as Louis Dreyfus Energy Services, L.P. ("Louis Dreyfus"), in which our Mont Belvieu LPGs storage and transportation shuttle system services were jointly marketed by Louis Dreyfus and TE Products. The purpose of the alliance was to expand services to the upper Texas Gulf Coast energy marketplace by increasing pipeline throughput and the mix of products handled through the existing system and establishing new receipt and delivery connections. The alliance was a service-oriented, fee-based venture with no commodity trading activity. TE Products operated the facilities for the alliance. Under the alliance, Louis Dreyfus invested $6.1 million for expansion projects at Mont Belvieu. The alliance also stipulated that if certain earnings thresholds were achieved, a F-35 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) partnership between TE Products and Louis Dreyfus was to be created effective January 1, 2003. All terms and earnings thresholds have been met; therefore, we will be contributing our Mont Belvieu assets to the newly formed partnership. The economic terms of the partnership are the same as those under the joint development and marketing alliance. TE Products will continue to operate the facilities for the partnership. The net book value of the Mont Belvieu assets that we are contributing to the partnership is approximately $68.2 million. Our interest in the partnership will be accounted for as an equity investment. Rates of interstate refined petroleum products and crude oil pipeline companies, like us, are currently regulated by the FERC primarily through an index methodology, which allows a pipeline to change its rates based on the change from year to year in the Producer Price Index for finished goods ("PPI Index"). Effective as of February 24, 2003, FERC Order on Remand modified the PPI Index from PPI - 1% to PPI. In the alternative, interstate refined petroleum products and crude oil pipeline companies may elect to support rate filings by using a cost-of-service methodology, competitive market showings ("Market-Based Rates") or agreements between shippers and refined petroleum products and crude oil pipeline companies 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, and Arcadia and Shreveport-Arcadia, Louisiana, destination markets, which are currently subject to the PPI Index. As a result, we made refunds of approximately $1.0 million in the third quarter of 2001 for those destination markets. Substantially all of the petroleum products that we transport and store are owned by our customers. At December 31, 2002, TCTM and TE Products had approximately 2.7 million barrels and 17.4 million barrels, respectively, of products in their custody that was owned by customers. We are obligated for the transportation, storage and delivery of such products on behalf of our customers. We maintain insurance adequate to cover product losses through circumstances beyond our control. NOTE 18. SEGMENT DATA We have three reporting segments: transportation and storage of refined products, LPGs and petrochemicals, which operates as the Downstream Segment; gathering, transportation, marketing and storage of crude oil, and distribution of lubrication oils and specialty chemicals, which operates as the Upstream Segment; and gathering of natural gas, fractionation of NGLs and transportation of NGLs, which operates as the Midstream Segment. The amounts indicated below as "Partnership and Other" relate primarily to intercompany eliminations and assets that we hold that have not been allocated to any of our reporting segments. Effective January 1, 2002, we realigned our three business segments to reflect our entry into the natural gas gathering business and the expanded scope of NGLs operations. We transferred the fractionation of NGLs, which was previously reflected as part of the Downstream Segment, to the Midstream Segment. The operation of NGL pipelines, which was previously reflected as part of the Upstream Segment, was also transferred to the Midstream Segment. We have adjusted our period-to-period comparisons to conform with the current presentation. Our Downstream Segment includes the interstate transportation, storage and terminaling of petroleum products and LPGs and intrastate transportation of petrochemicals. Revenues are earned from transportation and F-36 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) storage of refined products and LPGs, storage and short-haul shuttle transportation of LPGs at the Mont Belvieu complex, intrastate transportation of petrochemicals, sale of product inventory and other ancillary services. Our Downstream Segment's pipeline system extends from southeast Texas through the central and midwestern United States to the northeastern United States, and is one of the largest pipeline common carriers of refined petroleum products and LPGs in the United States. Our Downstream Segment also includes our equity investment in Centennial. Our Upstream Segment includes the gathering, transportation, marketing and storage of crude oil and distribution of lubrication oils and specialty chemicals, principally in Oklahoma, Texas and the Rocky Mountain region. Our Upstream Segment also includes the equity earnings from our investment in Seaway. Seaway is a large diameter pipeline that transports crude oil from the U.S. Gulf Coast to Cushing, Oklahoma, a central crude oil distribution point for the Central United States. Our Midstream Segment includes the fractionation of NGLs in Colorado; the ownership and operation of two trunkline NGL pipelines in South Texas and two NGL pipelines in East Texas; and the gathering of natural gas in the Green River Basin in southwestern Wyoming, through Jonah, which was acquired by our subsidiaries on September 30, 2001. This segment also includes Chaparral, which we acquired on March 1, 2002. Chaparral is an NGL pipeline system that extends from West Texas and New Mexico to Mont Belvieu. The pipeline delivers NGLs to fractionators and to our existing storage in Mont Belvieu. On June 30, 2002, we acquired the Val Verde system, which gathers CBM from the Fruitland Coal Formation of the San Juan Basin in New Mexico and Colorado, and is one of the largest CBM gathering and treating facilities in the United States. The results of operations of the Jonah, Chaparral, and Val Verde acquisitions are included in periods subsequent to September 30, 2001, March 1, 2002, and June 30, 2002, respectively (See Note 5. Acquisitions). The tables below include financial information by reporting segment for the years ended December 31, 2002, 2001 and 2000 (in thousands):.

YEAR ENDED DECEMBER 31, 2002 --------------------------------------------------------------------------------------- DOWNSTREAM UPSTREAM MIDSTREAM SEGMENTS PARTNERSHIP SEGMENT SEGMENT SEGMENT TOTAL AND OTHER CONSOLIDATED ---------- ----------- ---------- ----------- ----------- -------------- Revenues...................... $ 243,538 $ 2,861,700 $ 138,922 $ 3,244,160 $ (1,997) $ 3,242,163 Operating expenses, including power............ 130,324 2,824,106 33,451 2,987,881 (1,997) 2,985,884 Depreciation and amortization expense....... 30,116 11,186 44,730 86,032 -- 86,032 ---------- ----------- ---------- ----------- ----------- -------------- Operating income........... 83,098 26,408 60,741 170,247 -- 170,247 Equity earnings............... (6,815) 18,795 -- 11,980 -- 11,980 Other income, net............. 832 1,532 269 2,633 (806) 1,827 ---------- ----------- ---------- ----------- ----------- -------------- Earnings before interest... $ 77,115 $ 46,735 $ 61,010 $ 184,860 $ (806) $ 184,054 ========== =========== ========== =========== =========== ==============

F-37 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

YEAR ENDED DECEMBER 31, 2001 ------------------------------------------------------------------------------------------ DOWNSTREAM UPSTREAM MIDSTREAM SEGMENTS PARTNERSHIP SEGMENT SEGMENT SEGMENT TOTAL AND OTHER CONSOLIDATED ----------- ----------- ---------- ------------- ------------ ------------ Revenues ..................... $ 264,233 $ 3,255,260 $ 37,242 $ 3,556,735 $ (322) $ 3,556,413 Operating expenses, including power ........... 119,858 3,227,705 11,482 3,359,045 (322) 3,358,723 Depreciation and amortization expense ...... 26,699 9,263 9,937 45,099 -- 45,899 ----------- ----------- ---------- ------------ ------------ ------------ Operating income .......... 117,676 18,292 15,823 151,791 -- 151,791 Equity earnings .............. (1,149) 18,547 -- 17,398 -- 17,398 Other income, net ............ 1,537 1,188 74 2,799 -- 2,799 ----------- ----------- ---------- ------------ ------------ ------------ Earnings before interest... $ 118,064 $ 38,027 $ 15,897 $ 171,988 $ -- $ 171,988 =========== =========== ========== ============ ============ ============

YEAR ENDED DECEMBER 31, 2000 --------------------------------------------------------- -------------------------------- DOWNSTREAM UPSTREAM MIDSTREAM SEGMENTS PARTNERSHIP SEGMENT SEGMENT SEGMENT TOTAL AND OTHER CONSOLIDATED ----------- ----------- ---------- ------------ ------------ ------------ Revenues...................... $ 229,234 $ 2,844,245 $ 14,462 $ 3,087,941 $ -- $ 3,087,941 Operating expenses, including power............ 118,065 2,823,304 2,423 2,943,792 -- 2,943,792 Depreciation and amortization expense....... 25,728 6,282 3,153 35,163 -- 35,163 ----------- ----------- ---------- ------------ ------------ ------------ Operating income........... 85,441 14,659 8,886 108,986 -- 108,986 Equity earnings............... -- 12,214 -- 12,214 -- 12,214 Other income, net............. 1,651 (500) 237 1,388 -- 1,388 ----------- ----------- ---------- ------------ ------------ ------------ Earnings before interest... $ 87,092 $ 26,373 $ 9,123 $ 122,588 $ -- $ 122,588 =========== =========== ========== ============ ============ ============

The following table provides the total assets for each segment as of December 31, 2002, 2001 and 2000 (in thousands):

DOWNSTREAM UPSTREAM MIDSTREAM SEGMENTS PARTNERSHIP SEGMENT SEGMENT SEGMENT TOTAL AND OTHER CONSOLIDATED ----------- ----------- ------------ ------------ ----------- -------------- 2002....................... $ 883,450 $ $ 1,174,010 $ 2,782,320 $ (11,678) $ 2,770.672 2001....................... 844,036 541,195 2,080,165 (14,817) 2,065,348 2000....................... 714,233 156,662 1,623,476 (666) 1,622,810

The following table reconciles the segments total to consolidated net income (in thousands):

YEARS ENDED DECEMBER 31, --------------------------------------------- 2002 2001 2000 ------------ ------------ ------------ Earnings before interest.................................. $ 184,054 $ 171,988 $ 122,588 Interest expense.......................................... (70,537) (66,057) (48,982) Interest capitalized...................................... 4,345 4,000 4,559 Minority interest......................................... -- (800) (789) ------------ ------------ ------------ Net income............................................ $ 117,862 $ 109,131 $ 77,376 ============ ============ ============

F-38 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) NOTE 19. COMPREHENSIVE INCOME SFAS No. 130, Reporting Comprehensive Income requires certain items such as foreign currency translation adjustments, minimum pension liability adjustments, and unrealized gains and losses on certain investments to be reported in a financial statement. As of and for the years ended December 31, 2002 and 2001, the components of comprehensive income were due to the interest rate swap related to our variable rate revolving credit facility, which is designated as a cash flow hedge. Changes in the fair value of the cash flow hedge, to the extent the hedge is effective, are recognized in other comprehensive income until the hedge interest costs are recognized in earnings. The table below reconciles reported net income to total comprehensive income for the years ended December 31, 2002, 2001 and 2000 (in thousands).

YEARS ENDED DECEMBER 31, -------------------------------------- 2002 2001 2000 ----------- ----------- ---------- Net income......................................................... $ 117,862 $ 109,131 $ 77,376 Cumulative effect attributable to adoption of SFAS 133............. -- (10,103) -- Net income (loss) on cash flow hedge............................... 269 (10,221) -- ----------- ----------- ---------- Total comprehensive income..................................... $ 118,131 $ 88,807 $ 77,376 =========== =========== ==========

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 hedge..................................... (10,221) Balance at December 31, 2001....................................... $ (20,324) Net income on cash flow hedge................................... 269 --------------- Balance at December 31, 2002....................................... $ (20,055) ===============

NOTE 20. SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION In connection with our issuance of Senior Notes on February 20, 2002, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, our significant operating subsidiaries, issued unconditional guarantees of our debt securities. Effective with the acquisition of the Val Verde assets on June 30, 2002, our subsidiary, Val Verde Gas Gathering Company, L.P. also became a significant operating subsidiary and issued unconditional guarantees of our debt securities. The guarantees are full, unconditional, and joint and several. TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Jonah Gas Gathering Company and Val Verde Gas Gathering Company, L.P. are collectively referred to as the "Guarantor Subsidiaries." The following supplemental condensed consolidating financial information reflects our separate accounts, the combined accounts of the Guarantor Subsidiaries, the combined accounts of our other non-guarantor subsidiaries, the combined consolidating adjustments and eliminations and our consolidated accounts for the dates and periods indicated. For purposes of the following consolidating information, our investments in our subsidiaries and the Guarantor Subsidiaries' investments in their subsidiaries are accounted for under the equity method of accounting. F-39 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

DECEMBER 31, 2002 --------------------------------------------------------------------------- TEPPCO TEPPCO GUARANTOR NON-GUARANTOR CONSOLIDATING PARTNERS, L.P. PARTNERS, L.P. SUBSIDIARIES SUBSIDIARIES ADJUSTMENTS CONSOLIDATED -------------- ------------ ------------- ------------- ------------- (IN THOUSANDS) Assets Current assets ................................ $ 241 $ 92,798 $ 286,379 $ (18,851) $ 360,567 Property, plant and equipment - net ........... -- 1,128,803 459,021 -- 1,587,824 Equity investments ............................ 1,011,935 846,991 211,229 (1,785,450) 284,705 Intercompany notes receivable ................. 986,852 -- -- (986,852) -- Intangible assets ............................. -- 434,941 30,433 -- 465,374 Other assets .................................. 6,200 31,135 34,837 -- 72,172 ---------- ---------- ---------- ------------ ---------- Total assets ............................... $2,005,228 $2,534,668 $1,021,899 $ (2,791,153) $2,770,642 ========== ========== ========== ============ ========== Liabilities and partners' capital Current liabilities ........................... $ 30,715 $ 123,169 $ 272,538 $ (59,639) $ 366,783 Long-term debt ................................ 974,264 403,428 -- -- 1,377,692 Intercompany notes payable .................... -- 508,652 437,411 (946,063) -- Other long term liabilities and minority interest ................................... 6,523 24,230 209 -- 30,962 Redeemable Class B Units held by related party ...................................... 103,363 -- -- -- 103,363 Total partners' capital ....................... 890,363 1,475,189 311,741 (1,785,451) 891,842 ---------- ---------- ---------- ------------ ---------- Total liabilities and partners' capital .... $2,005,228 $2,534,668 $1,021,899 $ (2,791,153) $2,770,642 ========== ========== ========== ============ ==========

DECEMBER 31, 2002 --------------------------------------------------------------------------- TEPPCO TEPPCO GUARANTOR NON-GUARANTOR CONSOLIDATING PARTNERS, L.P. 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) -- Intangible assets ............................. -- 219,525 31,962 -- 251,487 Other assets .................................. 3,853 24,923 33,424 (4,504) 57,696 ----------- ----------- ----------- ----------- ----------- 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 ................................ 340,658 375,184 -- -- 715,842 Intercompany notes payable .................... -- 45,410 294,801 (340,211) -- Other long term liabilities and minority interest ................................... -- 22,994 231 8,628 31,853 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-40 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

YEAR ENDED DECEMBER 31, 2002 ------------------------------------------------------------------------------- TEPPCO TEPPCO GUARANTOR NON-GUARANTOR CONSOLIDATING PARTNERS, L.P. PARTNERS, L.P. SUBSIDIARIES SUBSIDIARIES ADJUSTMENTS CONSOLIDATED -------------- ------------ ------------- ------------- ------------- (IN THOUSANDS) Operating revenues .................... $ -- $ 336,045 $ 2,908,115 $ (1,997) $ 3,242,163 Costs and expenses .................... -- 216,552 2,857,361 (1,997) 3,071,916 ----------- ----------- ----------- ----------- ----------- Operating income ................... -- 119,493 50,754 -- 170,247 ----------- ----------- ----------- ----------- ----------- Interest expense - net ................ (51,947) (40,651) -26,347 52,753 (66,192) Equity earnings ....................... 117,862 59,428 18,795 (184,105) 11,980 Other income - net .................... 51,947 967 1,666 (52,753) 1,827 ----------- ----------- ----------- ----------- ----------- Net income ......................... $ 117,862 $ 139,237 $ 44,868 $ (184,105) $ 117,862 =========== =========== =========== =========== ===========

YEAR ENDED DECEMBER 31, 2001 ------------------------------------------------------------------------------- TEPPCO TEPPCO GUARANTOR NON-GUARANTOR CONSOLIDATING PARTNERS, L.P. PARTNERS, L.P. SUBSIDIARIES SUBSIDIARIES ADJUSTMENTS CONSOLIDATED -------------- ------------ ------------- ------------- ------------- (IN THOUSANDS) Operating revenues .................... $ -- $ 273,379 $ 3,283,356 $ (322) $ 3,556,413 Costs and expenses .................... -- 152,558 3,252,386 (322) 3,404,622 ----------- ----------- ----------- ----------- ----------- Operating income ................... -- 120,821 30,970 -- 151,791 ----------- ----------- ----------- ----------- ----------- Interest expense - net ................ (40,143) (30,605) (31,452) 40,143 (62,057) Equity earnings ....................... 109,131 18,178 18,547 (128,458) 17,398 Other income - net .................... 40,143 1,537 1,262 (40,143) 2,799 ----------- ----------- ----------- ----------- ----------- Income before minority interest .... 109,131 109,931 19,327 (128,458) 109,931 Minority interest ..................... -- -- -- (800) (800) ----------- ----------- ----------- ----------- ----------- Net income ......................... $ 109,131 $ 109,931 $ 19,327 $ (129,258) $ 109,131 =========== =========== =========== =========== ===========

YEAR ENDED DECEMBER 31, 2000 ------------------------------------------------------------------------------- TEPPCO TEPPCO GUARANTOR NON-GUARANTOR CONSOLIDATING PARTNERS, L.P. PARTNERS, L.P. SUBSIDIARIES SUBSIDIARIES ADJUSTMENTS CONSOLIDATED -------------- ------------ ------------- ------------- ------------- (IN THOUSANDS) Operating revenues .................... $ -- $ 229,234 $ 2,858,707 $ -- $ 3,087,941 Costs and expenses .................... -- 143,793 2,835,162 -- 2,978,955 ----------- ----------- ----------- ----------- ----------- Operating income ...................... -- 85,441 23,545 -- 108,986 ----------- ----------- ----------- ----------- ----------- Interest expense - net ................ (17,773) (27,529) (16,894) 17,773 (44,423) Equity earnings ....................... 77,376 18,602 12,214 (95,978) 12,214 Other income - net .................... 17,773 1,651 (263) (17,773) 1,388 ----------- ----------- ----------- ----------- ----------- 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 =========== =========== =========== =========== ===========

F-41 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

YEAR ENDED DECEMBER 31, 2002 ------------------------------------------------------------------------------- TEPPCO TEPPCO GUARANTOR NON-GUARANTOR CONSOLIDATING PARTNERS, L.P. PARTNERS, L.P. SUBSIDIARIES SUBSIDIARIES ADJUSTMENTS CONSOLIDATED -------------- ------------ ------------- ------------- ------------- (IN THOUSANDS) Cash flows from operating activities Net income .................................. $ 117,862 $ 139,237 $ 44,869 $ (184,106) $ 117,862 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization .......... -- 66,175 19,857 -- 86,032 Earnings in equity investments, net of distributions ................. 33,994 (2,496) 11,586 (24,683) 18,401 Changes in assets and liabilities and other ............................ (269,102) 48,638 40,253 192,833 12,622 ----------- ----------- ----------- ----------- ----------- Net cash provided by operating activities .... (117,246) 251,554 116,565 (15,956) 234,917 ----------- ----------- ----------- ----------- ----------- Cash flows from investing activities ......... (378,039) (1,150,967) (253,879) 1,058,170 (724,715) Cash flows from financing activities ......... 495,285 904,006 138,210 (1,042,214) 495,287 ----------- ----------- ----------- ----------- ----------- Net increase (decrease) in cash and cash equivalents .......................... -- 4,593 896 -- 5,489 Cash and cash equivalents at beginning of period ................................. -- 3,654 21,825 -- 25,479 ----------- ----------- ----------- ----------- ----------- Cash and cash equivalents at end of period ................................. $ -- $ 8,247 $ 22,721 $ -- $ 30,968 =========== =========== =========== =========== ===========

YEAR ENDED DECEMBER 31, 2001 ------------------------------------------------------------------------------- TEPPCO TEPPCO GUARANTOR NON-GUARANTOR CONSOLIDATING PARTNERS, L.P. PARTNERS, L.P. SUBSIDIARIES SUBSIDIARIES ADJUSTMENTS CONSOLIDATED -------------- ------------ ------------- ------------- ------------- (IN THOUSANDS) Cash flows from operating activities Net income ................................. $ 109,131 $ 109,931 $ 19,327 $ (129,258) $ 109,131 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization .......... -- 31,226 14,673 -- 45,899 Earnings in equity investments, net of distributions .................. (5,219) 10,131 13,417 (3,952) 14,377 Changes in assets and liabilities and other ............................. 2,874 16,850 (20,783) 800 (259) ----------- ----------- ----------- ----------- ----------- Net cash provided by operating activities .... 106,786 168,138 26,634 (132,410) 169,148 ----------- ----------- ----------- ----------- ----------- Cash flows from investing activities ......... (498,711) (514,178) (43,687) 498,711 (557,865) Cash flows from financing activities ......... 391,925 340,529 20,947 (366,301) 387,100 ----------- ----------- ----------- ----------- ----------- Net increase (decrease) in cash and cash equivalents .......................... -- (5,511) 3,894 -- (1,617) Cash and cash equivalents at beginning of period ................................. -- 9,166 17,930 -- 27,096 ----------- ----------- ----------- ----------- ----------- Cash and cash equivalents at end of period ................................. $ -- $ 3,655 $ 21,824 $ -- $ 25,479 =========== =========== =========== =========== ===========

F-42 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

YEAR ENDED DECEMBER 31, 2000 ------------------------------------------------------------------------------- TEPPCO TEPPCO GUARANTOR NON-GUARANTOR CONSOLIDATING PARTNERS, L.P. PARTNERS, L.P. SUBSIDIARIES SUBSIDIARIES ADJUSTMENTS CONSOLIDATED -------------- ------------ ------------- ------------- ------------- (IN THOUSANDS) Cash flows from operating activities Net income ................................. $ 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 Earnings in equity investments, 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 =========== =========== =========== =========== ===========

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

FIRST SECOND THIRD FOURTH QUARTER QUARTER QUARTER QUARTER ---------- ---------- ---------- ---------- (IN THOUSANDS, EXCEPT PER UNIT AMOUNTS) 2002 (2) Operating revenues ...................... $ 631,137 $ 888,329 $ 880,804 $ 841,893 Operating income ........................ 37,586 37,356 47,087 48,218 Net income .............................. 26,808 24,377 32,093 34,584 Basic and Diluted income per Limited .... $ 0.46 $ 0.39 $ 0.48 $ 0.46 Partner and Class B Unit (2) 2001 (3) Operating revenues ...................... $ 785,235 $1,073,682 $ 990,816 $ 706,680 Operating income ........................ 36,465 53,247 27,352 34,727 Net income .............................. 25,735 43,038 19,092 21,266 Basic income per Limited ................ $ 0.55 $ 0.90 $ 0.35 $ 0.40 Partner and Class B Unit (3) Diluted income per Limited .............. $ 0.55 $ 0.89 $ 0.35 $ 0.40 Partner and Class B Unit (3)

- --------- (1) Certain reclassifications have been made to the quarterly information to conform with the current presentation. (2) 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. F-43 TEPPCO PARTNERS, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued) (3) Per Unit calculation includes 1,920,000 Limited Partner Units issued in March 2002, 3,175,000 Limited Partner Units issued in July and August 2002, 4,370,000 Limited Partner Units issued in September 2002, 3,300,000 Limited Partner Units issued in November 2002, 495,000<< Limited Partner Units issued in December 2002, and 99,597 Limited Partner Units issued through the exercise of Unit options in 2002. NOTE 22. SUBSEQUENT EVENTS On January 30, 2003, we received $197.3 million in net proceeds, after underwriting discount, from the issuance of $200.0 million principal amount of 6.125% Senior Notes due 2013. The 6.125% Senior Notes were issued at a discount of $1.4 million and will be accreted to their face value over the term of the notes. We used $182.0 million of the proceeds from the offering to reduce the outstanding principal on the Three Year Facility to $250.0 million. The balance of the proceeds of $15.3 million was used for general purposes. The Senior Notes may be redeemed at any time at our option with the payment of accrued interest and a make-whole premium determined by discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of comparable remaining maturity plus 35 basis points. The indenture governing our 6.125% Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit our ability to incur additional indebtedness. Our Guarantor Subsidiaries issued unconditional guarantees of these Senior Notes (see Note 20. Supplemental Condensed Consolidating Financial Information). In January 2003, TE Products entered into a pipeline capacity lease agreement with Centennial for a period of five years. On February 10, 2003, TE Products acquired an additional interest in Centennial from PEPL for $20.0 million, increasing its percentage ownership in Centennial to 50%. Upon closing of the acquisition, TE Products and Marathon each own a 50% ownership interest in Centennial. In connection with the acquisition of the additional interest in Centennial, the guaranty agreement between TE Products, Marathon and PEPL was terminated. TE Products' guaranty of up to a maximum of $75.0 million of Centennial's debt remains in effect. F-44 INDEPENDENT AUDITORS' REPORT ON CONSOLIDATED FINANCIAL STATEMENT SCHEDULE To the Partners of TEPPCO Partners, L.P.: Under date of January 22, 2003, except as to note 22 which is as of February 10, 2003, we reported on the consolidated balance sheets of TEPPCO Partners, L.P. as of December 31, 2002 and 2001, 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, 2002. In connection with our audits of the aforementioned consolidated financial statements, we also audited the related consolidated financial statement schedule. This consolidated financial statement schedule is the responsibility of the Partnership's management. Our responsibility is to express an opinion on the consolidated financial statement schedule based on our audits. In our opinion, the consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. KPMG LLP Houston, Texas January 22, 2003 S-1 SCHEDULE II TEPPCO PARTNERS, L.P. VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE YEARS ENDED DECEMBER 31, 2000, 2001 AND 2002 (IN THOUSANDS)

BALANCE AT ADDITIONS CHARGED TO BEGINNING OF RELATED TO COSTS AND DEDUCTIONS AND BALANCE AT OF PERIOD ACQUISITIONS EXPENSES OTHER END OF PERIOD ------------ ------------- ------------ -------------- ------------- ENVIRONMENTAL RESERVE: Year Ended December 31, 2000.................... $ (5,089) $ -- $ (497) $ 1,938 $ (3,648) Year Ended December 31, 2001.................... (3,648) (300) (8,691) 6,205 (6,434) Year Ended December 31, 2002.................... (6,434) -- (5,785) 4,526 (7,693) ALLOWANCE FOR DOUBTFUL ACCOUNTS: Year Ended December 31, 2000.................... $ -- $ -- $ -- $ -- $ -- Year Ended December 31, 2001.................... -- -- (4,422) -- (4,422) Year Ended December 31, 2002.................... (4,422) -- (325) 139 (4,608)

S-2 -----END PRIVACY-ENHANCED MESSAGE-----

EX-10.4

                                                                   EXHIBIT 10.4


         -------------------------------------------------------------



                               SECOND AMENDMENT TO

                               SERVICES AGREEMENT


                                 by and between


        DUKE ENERGY CORPORATION, DUKE ENERGY BUSINESS SERVICES, LLC, PAN
           SERVICE COMPANY, DUKE ENERGY GAS TRANSMISSION CORPORATION

                                       and

                         DUKE ENERGY FIELD SERVICES, LLC


                           Dated as of January 1, 2002



         -------------------------------------------------------------






                     Second Amendment to Services Agreement

         This Second Amendment to the Services Agreement (this "Amendment") is
made this 5th day of March 2002, but effective as of January 1, 2002, by and
between Duke Energy Corporation, Duke Energy Business Services LLC, Pan Service
Company and Duke Energy Gas Transmission Corporation (collectively "Duke"), and
Duke Energy Field Services, LLC (the "Company") (each, a "Party", and
collectively, the "Parties").



                                    RECITALS:

         WHEREAS, Duke and the Company are parties to that certain Services
Agreement dated March 14, 2000, as amended by that certain First Amendment to
Services Agreement dated December 15, 2000, (the Services Agreement and First
Amendment to Services Agreement together are referred to as the "Services
Agreement") (capitalized terms used but not defined here shall have the meaning
given thereto in the Services Agreement); and

         WHEREAS, Duke and the Company desire to amend the Services Agreement as
discussed in this Amendment.

         NOW, THEREFORE, for good and valuable consideration, the receipt and
sufficiency of which are hereby acknowledged, the Parties hereby agree as
follows:

1.       The rate sheet found in Exhibit A, Article I of the Services Agreement
         shall be replaced in its entity with the Rate Sheet attached hereto as
         Exhibit A, Article I.

2.       The Services listed in Exhibit A, Article II of the Services Agreement
         shall be replaced in their entirety with the Services attached hereto
         as Exhibit A, Article II.

3.       Section 3.1 of the Services Agreement shall be terminated in its entity
         and replaced with the following new Section 3.1:

         Term. The term of this Agreement shall begin on January 1, 2002 and
         remain in effect until December 31, 2002. If both Duke and the Company
         desire to renew this Agreement for an additional 12-month term to begin
         on January 1 of a particular year, then beginning on August 1 of the
         existing year, the Parties shall renegotiate the terms and conditions
         of this Agreement (including without limitation the Services to be
         provided and their associated expense) which shall be applicable solely
         for the extended 12-month term.

4.       Except as amended hereby, the Services Agreement shall remain in full
         force and effect as previously executed and the Parties ratify the
         Services Agreement as amended hereby.






         IN WITNESS WHEREOF, each of the undersigned has caused this Amendment
to be duly executed and delivered on the date first set forth above.


DUKE ENERGY CORPORATION                     DUKE ENERGY BUSINESS SERVICES LLC





By: /s/ KEITH G. BUTLER                     By: /s/ CAROL O. SMITH, JR.
  ---------------------------------           ----------------------------------
Name:  Keith G. Butler                      Name:   Cecil O. Smith, Jr.
Title: Senior Vice President                Title:  President
          and Controller



PAN SERVICE COMPANY                         DUKE ENERGY GAS TRANSMISSION
                                            CORPORATION



By: /s/ ROBERT B. EVANS                     By: /s/ ROBERT B. EVANS
  ---------------------------------           ----------------------------------
Name:  Robert B. Evans                      Name:   Robert B. Evans
Title:    President                         Title:  President and Chairman





DUKE ENERGY FIELD SERVICES, LLC



By: /s/ ROSE M. ROBESON
  ---------------------------------
Name:   Rose M. Robeson
Title:  Vice President
          and Chief Financial Officer




                                       2

EX-10.5

                                                                   EXHIBIT 10.5


         ------------------------------------------------------------




                                  AMENDMENT TO

                               SERVICES AGREEMENT


                                 by and between


        DUKE ENERGY CORPORATION, DUKE ENERGY BUSINESS SERVICES, LLC, PAN
            SERVICE COMPANY, DUKE ENERGY GAS TRANSMISSION CORPORATION

                                       and

                         DUKE ENERGY FIELD SERVICES, LLC


                           Dated as of January 1, 2003




         ------------------------------------------------------------







                         Amendment to Services Agreement

         This Amendment to the Services Agreement (this "Amendment") is made
this ___ day of January, 2003, but effective as of January 1, 2003, by and
between Duke Energy Corporation, Duke Energy Business Services LLC, Pan Service
Company and Duke Energy Gas Transmission Corporation (collectively "Duke"), and
Duke Energy Field Services, LLC (the "Company") (each, a "Party", and
collectively, the "Parties").



                                    RECITALS:

         WHEREAS, Duke and the Company are parties to that certain Services
Agreement dated March 14, 2000, as amended (the "Services Agreement")
(capitalized terms used but not defined here shall have the meaning given
thereto in the Services Agreement); and

         WHEREAS, Duke and the Company desire to amend the Services Agreement to
include various additional services and confirm the rates for 2003.

         NOW, THEREFORE, for good and valuable consideration, the receipt and
sufficiency of which are hereby acknowledged, the Parties hereby agree as
follows:

1.       The rate sheet found in Exhibit A, Article I of the Services Agreement
         shall be replaced with the new rate sheet attachment hereto entitled
         "Exhibit A, Article I (as amended)".

2.       The Services listed in Exhibit A, Article II of the Services Agreement
         shall be amended to include the additional services described in the
         attachment hereto entitled "Exhibit A, Article II (as amended)".

3.       Except as amended hereby, the Services Agreement shall remain in full
         force and effect as previously executed and amended by the Parties, and
         the Parties ratify the Services Agreement as amended hereby.






         IN WITNESS WHEREOF, each of the undersigned has caused this Amendment
to be duly executed and delivered on the date first set forth above.



DUKE ENERGY CORPORATION                     DUKE ENERGY BUSINESS SERVICES LLC





By: /s/ KEITH G. BUTLER                     By: /s/ A. R. MULLINAX
  ----------------------------------          ----------------------------------
Name:   Keith G. Butler                     Name:   A. R. Mullinax
Title:  Senior Vice President               Title:  Executive Vice President
           and Controller



PAN SERVICE COMPANY                         DUKE ENERGY GAS TRANSMISSION
                                            CORPORATION



By: /s/ DOROTHY M. ABLES                    By: /s/ THOMAS C. O'CONNOR
  ----------------------------------          ----------------------------------
Name:   Dorothy M. Ables                    Name:   Thomas C. O'Connor
Title:  Senior Vice President               Title:  President





DUKE ENERGY FIELD SERVICES, LLC



By: /s/ ROSE M. ROBESON
  ----------------------------------
Name:   Rose M. Robeson
Title:  Vice President
           and Chief Financial Officer





                                       2

EX-12.1

                                                                               .
                                                                               .
                                                                               .
                                                                   EXHIBIT 12.1


                         DUKE ENERGY FIELD SERVICES, LLC
                COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES




                                                                                          Years Ended
                                                                      -----------------------------------------------------
                                                                        1998       1999       2000       2001      2002
                                                                        Predecessor Company Historical
                                                                      --------------------------------

Earnings:
                                                                                                    
 Pretax income from continuing operations before equity earnings        (6,528)    51,856    341,800     337,032    (74,738)
 Add:
  Fixed charges                                                         54,791     55,021    151,567     168,789    172,341
  Distributed income of equity investees                                11,845     22,502     27,424      30,069     53,878

 Subtract:
  Interest Capitalized                                                   1,565        930        324         769      4,702

                                                                      --------   --------   --------    --------   --------
 Income as adjusted                                                     58,543    128,449    520,467     535,121    146,779
                                                                      --------   --------   --------    --------   --------

Fixed charges:
  Interest and Debt expense per Statement of Income                     52,403     52,915    149,220     165,670    165,841
  Capitalized Interest                                                   1,565        930        324         769      4,702
  Portion of rents representative of the interest factor                   823      1,176      2,023       2,350      1,798

                                                                      --------   --------   --------    --------   --------
TOTAL FIXED CHARGES                                                     54,791     55,021    151,567     168,789    172,341
                                                                      --------   --------   --------    --------   --------


RATIO OF EARNINGS TO FIXED CHARGES                                        1.07       2.33       3.43        3.17       0.85


Amount Needed to cover fixed charges:                                                                                25,562

EX-21.1

                                                                   EXHIBIT 21.1



                           Subsidiaries of the Company



1.       Duke Energy Field Services, LP (Delaware)

2.       DEFS Holding 1, LLC (Delaware)

3.       National Helium, LLC (Delaware)

4.       TEPPCO Partners, L.P. (Delaware)

5.       Texas Eastern Products Pipeline Company, LLC  (Delaware)

EX-23.1

                                                                   EXHIBIT 23.1


INDEPENDENT AUDITORS' CONSENT



We consent to the incorporation by reference in Registration Statement No.
333-57376 of Duke Energy Field Services, LLC on Form S-3 of our report dated
March 12, 2003, (which expresses an unqualified opinion and includes an
explanatory paragraph relating to the Company's changes in methods of accounting
for goodwill and derivative instruments to conform to Statement of Financial
Accounting Standards Nos. 142 and 133, respectively, as described in Note 2)
appearing in this Annual Report on Form 10-K of Duke Energy Field Services, LLC
for the year ended December 31, 2002.


DELOITTE & TOUCHE LLP


Denver, Colorado
March 21, 2003

EX-23.2

                                                                    EXHIBIT 23.2



                          Independent Auditors' Consent


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

We consent to the use of our report dated January 22, 2003, except as to Note 22
which is as of February 10, 2003, related to the consolidated financial
statements of TEPPCO Partners, L.P. included in the Duke Energy Field Services,
LLC Annual Report on Form 10-K for the fiscal year ended December 31, 2002 filed
on March 21, 2003.

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

                                                  KPMG LLP


Houston, Texas
March 21, 2003

EX-99.1

                                                                    EXHIBIT 99.1


                            CERTIFICATION PURSUANT TO
                             18 U.S.C. SECTION 1350,
                             AS ADOPTED PURSUANT TO
                  SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002


In connection with the Annual Report of Duke Energy Field Services, LLC (the
"Company") on Form 10-K for the period ending December 31, 2002 as filed with
the Securities and Exchange Commission on the date hereof (the "Report"), I, Jim
W. Mogg, Chairman of the Board, President and Chief Executive Officer of the
Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, that:

                  (1) The Report fully complies with the requirements of section
13(a) or 15(d) of the Securities Exchange act of 1934; and

                  (2) The information contained in the Report fairly presents,
in all material respects, the financial condition and results of operations of
the Company.



      /s/ Jim W. Mogg
- -------------------------------
Jim W. Mogg
Chairman of the Board, President and Chief Executive Officer
March 21, 2003

EX-99.2

                                                                   EXHIBIT 99.2



                           CERTIFICATION PURSUANT TO
                            18 U.S.C. SECTION 1350,
                             AS ADOPTED PURSUANT TO
                 SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Duke Energy Field Services, LLC (the
"Company") on Form 10-K for the period ending December 31, 2002 as filed with
the Securities and Exchange Commission on the date hereof (the "Report"), I,
Rose M. Robeson, Vice President and Chief Financial Officer of the Company,
certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002, that:

                  (1) The Report fully complies with the requirements of section
13(a) or 15(d) of the Securities Exchange act of 1934; and

                  (2) The information contained in the Report fairly presents,
in all material respects, the financial condition and results of operations of
the Company.



       /s/ Rose M. Robeson
- --------------------------------
Rose M. Robeson
Vice President and Chief Financial Officer
March 21, 2003

EX-99.3

                                                                    EXHIBIT 99.3


                        CONSOLIDATED FINANCIAL STATEMENTS
                            OF TEPPCO PARTNERS, L.P.

             INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTAL SCHEDULE






                                                                                                            PAGE
                                                                                                          
Financial Statements:

     Independent Auditors' Report....................................................................        F-2

     Consolidated Balance Sheets as of December 31, 2002 and 2001....................................        F-3

     Consolidated Statements of Income for the years ended December 31, 2002, 2001 and 2000..........        F-4

     Consolidated Statements of Cash Flows for the years ended December 31, 2002, 2001 and 2000......        F-5

     Consolidated Statements of Partners' Capital for the years ended December 31, 2002,

        2001 and 2000................................................................................        F-6

    Notes to Consolidated Financial Statements.......................................................        F-7

Supplemental Schedule:

     Independent Auditors' Report on Consolidated Financial Statement Schedule.......................        S-1

     Schedule II - Valuation and Qualifying Accounts and Reserves....................................        S-2




                                      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, 2002 and 2001, 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, 2002. 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, 2002 and 2001, and the results of their
operations and their cash flows for each of the years in the three-year period
ended December 31, 2002, in conformity with accounting principles generally
accepted in the United States of America.

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




                                                        KPMG LLP




Houston, Texas
January 22, 2003, except as
   to Note 22, which is as of
   February 10, 2003



                                      F-2





                              TEPPCO PARTNERS, L.P.

                           CONSOLIDATED BALANCE SHEETS
                                 (IN THOUSANDS)




                                                                                               DECEMBER 31,
                                                                                     -------------------------------
                                                                                         2002             2001
                                                                                     -------------    --------------
                                                                                                
                                     ASSETS
Current assets:
  Cash and cash equivalents................................................          $      30,968    $       25,479
  Accounts receivable, trade...............................................                276,450           221,541
  Accounts receivable, related party.......................................                  4,313             4,310
  Inventories..............................................................                 17,166            17,243
  Other....................................................................                 31,670            14,907
                                                                                     -------------    --------------
        Total current assets...............................................                360,567           283,480
                                                                                     -------------    --------------
Property, plant and equipment, at cost (Net of accumulated depreciation
  and amortization of $338,746 and $290,248)...............................              1,587,824         1,180,461
Equity investments.........................................................                284,705           292,224
Intangible assets..........................................................                465,374           251,487
Goodwill...................................................................                 16,944            16,669
Other assets...............................................................                 55,228            41,027
                                                                                     -------------    --------------
        Total assets.......................................................          $   2,770,642    $    2,065,348
                                                                                     =============    ==============


                        LIABILITIES AND PARTNERS' CAPITAL



                                                                                                
Current liabilities:
    Notes payable..........................................................          $          --    $      360,000
  Accounts payable and accrued liabilities.................................                261,080           228,075
  Accounts payable, general partner........................................                  6,619            22,680
  Accrued interest.........................................................                 29,726            15,649
  Other accrued taxes......................................................                 11,260             8,888
  Other....................................................................                 58,098            33,550
                                                                                     -------------    --------------
        Total current liabilities..........................................                366,783           668,842
                                                                                     -------------    --------------
Senior Notes...............................................................                945,692           375,184
Other long-term debt.......................................................                432,000           340,658
Other liabilities and deferred credits.....................................                 30,962            31,853
Redeemable Class B Units held by related party.............................                103,363           105,630
Commitments and contingencies
Partners' capital:
  Accumulated other comprehensive loss.....................................                (20,055)          (20,324)
  General partner's interest...............................................                 12,770            13,190
  Limited partners' interests..............................................                899,127           550,315
                                                                                     -------------    --------------
        Total partners' capital............................................                891,842           543,181
                                                                                     -------------    --------------
        Total liabilities and partners' capital............................          $   2,770,642    $    2,065,348
                                                                                     =============    ==============


          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,
                                                                     --------------------------------------------------
                                                                         2002              2001             2000
                                                                     ------------      ------------      ------------
                                                                                                  
Operating revenues:
  Sales of crude oil and petroleum products.......................   $  2,823,800      $  3,219,816      $  2,821,943
  Transportation - Refined products...............................        123,476           139,315           119,331
  Transportation - LPGs...........................................         74,577            77,823            73,896
  Transportation - Crude oil......................................         27,414            24,223            17,524
  Transportation - NGLs...........................................         38,870            20,702             7,009
  Gathering - Natural gas........................................          90,053             8,824                --
  Mont Belvieu operations.........................................         15,238            14,116            13,334
  Other...........................................................         48,735            51,594            34,904
                                                                     ------------      ------------      ------------
        Total operating revenues..................................      3,242,163         3,556,413         3,087,941
                                                                     ------------      ------------      ------------

Costs and expenses:
  Purchases of crude oil and petroleum products...................      2,772,328         3,172,805         2,793,643
  Operating, general and administrative...........................        158,753           135,253           104,918
  Operating fuel and power........................................         36,814            36,575            34,655
  Depreciation and amortization...................................         86,032            45,899            35,163
  Taxes - other than income taxes.................................         17,989            14,090            10,576
                                                                     ------------      ------------      ------------
        Total costs and expenses..................................      3,071,916         3,404,622         2,978,955
                                                                     ------------      ------------      ------------

        Operating income..........................................        170,247           151,791           108,986

Interest expense..................................................        (70,537)          (66,057)          (48,982)
Interest capitalized..............................................          4,345             4,000             4,559
Equity earnings...................................................         11,980            17,398            12,214
Other income - net................................................          1,827             2,799             1,388
                                                                     ------------      ------------      ------------
        Income before minority interest ..........................        117,862           109,931            78,165
Minority interest.................................................             --              (800)             (789)
                                                                     ------------      ------------      ------------
        Net income................................................   $    117,862      $    109,131      $     77,376
                                                                     ============      ============      ============

Net Income Allocation:
Limited Partner Unitholders.......................................         81,238            76,986            56,091
Class B Unitholder................................................          6,943             8,642             7,385
General Partner...................................................         29,681            23,503            13,900
                                                                     ------------      ------------      ------------
        Total net income allocated................................   $    117,862      $    109,131      $     77,376
                                                                     ============      ============      ============

Basic and diluted net income per Limited
  Partner and Class B Unit........................................   $       1.79      $       2.18      $       1.89
                                                                     ============      ============      ============

Weighted average Limited Partner and Class B
  Units outstanding...............................................         49,202            39,258            33,594



          See accompanying Notes to Consolidated Financial Statements.



                                      F-4




                              TEPPCO PARTNERS, L.P.

                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                 (IN THOUSANDS)




                                                                                       YEARS ENDED DECEMBER 31,
                                                                               ----------------------------------------
                                                                                  2002           2001           2000
                                                                               ----------     ----------     ----------
                                                                                                   
Cash flows from operating activities:
  Net income ..............................................................    $  117,862     $  109,131     $   77,376
  Adjustments to reconcile net income to cash provided by
  operating activities:
    Depreciation and amortization .........................................        86,032         45,899         35,163
    Earnings in equity investments, net of distributions ..................        18,401         14,377        (10,084)
    Non-cash portion of interest expense ..................................         4,916          4,053          2,218
    Decrease (increase) in accounts receivable ............................       (54,909)        81,190        (90,006)
    Decrease (increase) in inventories ....................................            77          7,541         (7,567)
    Decrease (increase) in other current assets ...........................       (16,263)        (8,082)         1,165
    Increase (decrease) in accounts payable and accrued expenses...........        73,294        (71,757)       106,662
    Other .................................................................         5,507        (13,204)        (6,882)
                                                                               ----------     ----------     ----------
         Net cash provided by operating activities ........................       234,917        169,148        108,045
                                                                               ----------     ----------     ----------

Cash flows from investing activities:
  Proceeds from the sale of assets ........................................         3,380          1,300             --
  Proceeds from cash investments ..........................................            --          4,236          3,475
  Purchases of cash investments ...........................................            --             --         (2,000)
  Purchase of ARCO assets .................................................            --        (11,000)      (322,640)
  Purchase of Val Verde Gathering System ..................................      (444,150)            --             --
  Purchase of Jonah Gas Gathering Company .................................        (7,319)      (359,834)            --
  Purchase of Chaparral NGL System ........................................      (132,372)            --             --
  Purchase of crude oil assets ............................................            --        (20,000)       (99,508)
  Investment in Centennial Pipeline LLC ...................................       (10,882)       (64,953)        (5,040)
  Capital expenditures ....................................................      (133,372)      (107,614)       (68,481)
                                                                               ----------     ----------     ----------
         Net cash used in investing activities ............................      (724,715)      (557,865)      (494,194)
                                                                               ----------     ----------     ----------

Cash flows from financing activities:
  Proceeds from term and revolving credit facilities ......................       675,000        546,148        552,000
  Repayments on term and revolving credit facilities ......................      (943,659)      (291,490)      (172,000)
  Issuance of Senior Notes ................................................       497,805             --             --
  Debt issuance costs .....................................................        (7,025)        (2,601)        (7,074)
  Proceeds from termination of interest rate swaps ........................        44,896             --             --
  Issuance of Limited Partner Units, net ..................................       372,506        234,660         88,158
  General partner's contributions .........................................         7,617          4,795          1,799
  Distributions paid ......................................................      (151,853)      (104,412)       (82,231)
                                                                               ----------     ----------     ----------
         Net cash provided by financing activities ........................       495,287        387,100        380,652
                                                                               ----------     ----------     ----------

Net increase (decrease) in cash and cash equivalents ......................         5,489         (1,617)        (5,497)

Cash and cash equivalents at beginning of period ..........................        25,479         27,096         32,593
                                                                               ----------     ----------     ----------
Cash and cash equivalents at end of period ................................    $   30,968     $   25,479     $   27,096
                                                                               ==========     ==========     ==========

SUPPLEMENTAL DISCLOSURE OF CASH FLOWS:
  Interest paid during the year (net of capitalized interest) .............    $   48,908     $   61,458     $   36,793



          See accompanying Notes to Consolidated Financial Statements.



                                      F-5




                              TEPPCO PARTNERS, L.P.

                  CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
                       (IN THOUSANDS, EXCEPT UNIT AMOUNTS)




                                                OUTSTANDING                                   ACCUMULATED
                                                  LIMITED       GENERAL         LIMITED          OTHER
                                                  PARTNER       PARTNER'S       PARTNERS'    COMPREHENSIVE
                                                   UNITS        INTEREST        INTERESTS         LOSS            TOTAL
                                                -----------    -----------     -----------   --------------    -----------
                                                                                               
Partners' capital at December 31, 1999 .....     29,000,000    $       657     $   229,110     $        --     $   229,767
  Capital contributions ....................             --            890              --              --             890
  Issuance of Limited Partner Units, net ...      3,700,000             --          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 .....     32,700,000          1,824         313,233              --         315,057
  Capital contributions ....................             --          4,795              --              --           4,795
  Issuance of Limited Partner Units, net ...      7,750,000             --         234,660              --         234,660
  Minority interest restructured ...........             --          4,598              --              --           4,598
  Cumulative effect of accounting change ...             --             --              --         (10,103)        (10,103)
  Net loss on cash flow 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 .....     40,450,000         13,190         550,315         (20,324)        543,181
  Capital contributions ....................             --          7,568              --              --           7,568
  Issuance of Limited Partner Units, net ...     13,260,000             --         370,108              --         370,108
  Net gain on cash flow hedges .............             --             --              --             269             269
  2002 net income allocation ...............             --         29,681          81,238              --         110,919
  2002 cash distributions ..................             --        (37,718)       (104,932)             --        (142,650)
  Issuance of Limited Partner Units upon
      exercise of options ..................         99,597             49           2,398              --           2,447
                                                -----------    -----------     -----------     -----------     -----------

Partners' capital at December 31, 2002 .....     53,809,597    $    12,770     $   899,127     $   (20,055)    $   891,842
                                                ===========    ===========     ===========     ===========     ===========



          See accompanying Notes to Consolidated Financial Statements.


                                      F-6




                              TEPPCO PARTNERS, L.P.

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1.  PARTNERSHIP ORGANIZATION

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

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

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

         At formation in 1990, we completed an initial public offering of
26,500,000 Units representing Limited Partner Interests ("Limited Partner
Units") at $10.00 per Unit. In connection with our formation, the Company
received 2,500,000 Deferred Participation Interests ("DPIs"). Effective April 1,
1994, the DPIs began participating in distributions of cash and allocations of
profit and loss in a manner identical to Limited Partner Units and are treated
as Limited Partner Units for purposes of this Report. These Limited Partner
Units were assigned to Duke Energy when ownership of the Company was transferred
from Duke Energy to DEFS in 2000. Pursuant to our Partnership Agreement, we have
registered the resale by Duke Energy of such Limited Partner Units with the
Securities and Exchange Commission. As of December 31, 2002, no such Limited
Partner Units had been sold by Duke Energy.

         At December 31, 2002 and 2001, we had outstanding 53,809,597 and
40,450,000 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. We have the option to
seek approval for the conversion of the Class B Units into Limited Partner
Units; however, if the conversion is denied, Duke Energy, as holder of the Class
B Units, will have the right to sell them to us at 95.5% of the 20-day average
market closing price of the Limited Partner Units, as determined under our
Partnership Agreement. As a result of this option, we have not included the
Class B Units in partners' capital at December 31, 2002 and 2001. 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


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


BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION

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


USE OF ESTIMATES

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


ENVIRONMENTAL EXPENDITURES

         We accrue for environmental costs that relate to existing conditions
caused by past operations. Environmental costs include initial site surveys and
environmental studies of potentially contaminated sites, costs for remediation
and restoration of sites determined to be contaminated and ongoing monitoring
costs, as well as fines, damages and other costs, when estimable. We monitor the
balance of accrued undiscounted environmental liabilities on a regular basis. We
record liabilities for environmental costs at a specific site when our liability
for such costs, including direct internal and legal costs, is probable and a
reasonable estimate of the associated costs can be made. Adjustments to initial
estimates are recorded, from time to time, to reflect changing circumstances and
estimates based upon additional information developed in subsequent periods.
Estimates of our ultimate liabilities associated with environmental costs are
particularly difficult to make with certainty due to the number of variables
involved, including the early stage of investigation at certain sites, the
lengthy time frames required to complete remediation alternatives available and
the evolving nature of environmental laws and regulations.


BUSINESS SEGMENTS

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

         Effective January 1, 2002, we realigned our three business segments to
reflect our entry into the natural gas gathering business and the expanded scope
of NGLs operations. We transferred the fractionation of NGLs, which was
previously reflected as part of the Downstream Segment, to the Midstream
Segment. The operation of NGL



                                      F-8




                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

pipelines, which was previously reflected as part of the Upstream Segment, was
also transferred to the Midstream Segment. We have adjusted our period-to-period
comparisons to conform with the current presentation.

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


REVENUE RECOGNITION

         Our Downstream Segment revenues are earned from transportation and
storage of refined products and LPGs, storage and short-haul transportation of
LPGs at the Mont Belvieu complex, intrastate transportation of petrochemicals,
sale of product inventory and other ancillary services. Transportation revenues
are recognized as products are delivered to customers. Storage revenues are
recognized upon receipt of products into storage and upon performance of storage
services. Terminaling revenues are recognized as products are out-loaded.
Revenues from the sale of product inventory are recognized when the products are
sold.

         Our Upstream Segment revenues are earned from gathering,
transportation, marketing and storage of crude oil, and distribution of
lubrication oils and specialty chemicals principally in Oklahoma, Texas and the
Rocky Mountain region. 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 our crude oil marketing company, TEPPCO Crude Oil, L.P.,
which typically occurs upon our receipt of the product. Revenues related to
trade documentation and pumpover fees are recognized as services are completed.

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

         Our Midstream Segment revenues are derived from the gathering of
natural gas, fractionation of NGLs and transportation of NGLs. Gathering and
transportation revenues are recognized as natural gas or NGLs are delivered to
customers. Revenues are also earned from the sale of condensate liquid extracted
from the natural gas stream to an Upstream marketing affiliate. Fractionation
revenues are recognized ratably over the contract year as products are delivered
to DEFS. We do not take title to the natural gas gathered, NGLs transported or
NGLs fractionated, therefore, the results of our Midstream Segment are not
directly affected by changes in the prices of natural gas or NGLs.


NATURAL GAS IMBALANCES

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



                                      F-9



                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

they nominated, the Val Verde and the Jonah systems record a receivable
reflecting the amount due from customers and a payable for the same amount due
to connecting pipeline transporters or shippers.

         Quantities of natural gas over or under delivered related to imbalance
agreements are recorded monthly using then current index prices. These
imbalances are settled with cash or deliveries of natural gas. Gains are
recorded when gas volumes owed (receivables) are settled by gas producers at a
later date during a period of increasing prices, or if Val Verde and Jonah
settle payables at later date during a period of falling prices. Losses are
recorded if these processes are reversed.


USE OF DERIVATIVES

         We account for derivative financial instruments in accordance with
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 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.

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

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

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



                                      F-10




                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

INVENTORIES

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


PROPERTY, PLANT AND EQUIPMENT

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

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


CAPITALIZATION OF INTEREST


         We capitalize interest on borrowed funds related to capital projects
only for periods that activities are in progress to bring these projects to
their intended use. The weighted average rate used to capitalize interest on
borrowed funds was 5.11%, 6.46% and 7.45% for the years ended December 31, 2002,
2001 and 2000, respectively. During the years ended December 31, 2002, 2001 and
2000, the amount of interest capitalized was $4.3 million, $4.0 million and $4.6
million, respectively.


INTANGIBLE ASSETS

         Intangible assets at December 31, 2002, consist primarily of production
contracts assumed in the acquisition of Jonah on September 30, 2001, and the
acquisition of Val Verde on June 30, 2002, and the fractionation agreement with
DEFS.

         In connection with the acquisitions of Jonah and Val Verde, we assumed
contracts that dedicate future production from natural gas wells in the Green
River Basin in Wyoming, and we assumed fixed-term contracts with customers that
transport coal bed methane ("CBM") from the Fruitland Coal Formation of the San
Juan Basin in New Mexico and Colorado, respectively (see Note 5. 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 is amortized on a unit of production basis,
based upon the actual throughput of the system over the expected total
throughput for the lives of the contracts. The amortization of the Jonah and Val
Verde systems are expected to average approximately 16 years and 20 years,
respectively. On a quarterly basis, we update production estimates of the
natural gas wells and evaluate the remaining expected useful life of the
contract



                                      F-11



                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

assets. At December 31, 2002, the unamortized balance of the Jonah and Val Verde
production contracts were $205.2 million and $228.6 million, respectively.

         In connection with the purchase of the fractionation facilities in
1998, we entered into a fractionation agreement with DEFS. The fractionation
agreement is being amortized over a period of 20 years, which is the term of the
agreement with DEFS. At December 31, 2002, the unamortized balance of this
agreement was $29.0 million (see Note 7. Related Party Transactions.)


GOODWILL

         Goodwill represents the excess of purchase price over fair value of net
assets acquired and is presented on the consolidated balance sheets net of
accumulated amortization. We account for goodwill under SFAS No. 142, Goodwill
and Other Intangible Assets which was issued by the Financial Accounting
Standards Board ("FASB") in July 2001 (see Note 3. Goodwill and Other Intangible
Assets). SFAS 142 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. Beginning January 1,
2002, effective with the adoption of SFAS 142, we no longer record amortization
expense related to goodwill or amortization expense related to the excess
investment on our equity investment (equity method goodwill).


INCOME TAXES

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


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 49.2 million Units,
39.3 million Units and 33.6 million Units for the years ended December 31, 2002,
2001 and 2000, respectively). 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 13. Quarterly Distributions of Available Cash). The General
Partner was allocated $29.7 million (representing 25.18%) of net income for the
year ended December 31, 2002, $23.5 million (representing 21.54%) of net income
for the year ended December 31, 2001, and $13.9 million (representing 17.96%) of
net income for the year ended December 31, 2000. The General Partner's
percentage interest in our net income increases as cash distributions paid per
Unit increases.

         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



                                      F-12




                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

treasury stock method. For the years ended December 31, 2002, 2001 and 2000, the
denominator was increased by 32,053 Units, 41,864 Units and 20,926 Units,
respectively.


UNIT OPTION PLAN

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

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

         The following table summarizes pro forma net income and net income per
Unit for the years ended December 31, 2002, 2001 and 2000 assuming we had used
the fair value method of accounting for our unit option plan (in thousands,
except per Unit amounts):




                                                                                  YEARS ENDED DECEMBER 31,
                                                                      ------------------------------------------------
                                                                          2002              2001              2000
                                                                      ------------      ------------      ------------
                                                                                                 
Net income:
    Reported net income .........................................     $    117,862      $    109,131      $     77,376
    Deduct:  Total unit-based employee compensation expense
      determined under fair value based method for all awards ...               (6)             (118)             (201)
                                                                      ------------      ------------      ------------
        Pro forma net income ....................................     $    117,856      $    109,013      $     77,175
                                                                      ============      ============      ============

Pro forma net income allocation:
    Limited Partner Unitholders .................................     $     81,234      $     76,902      $     55,945
    Class B Unitholder ..........................................            6,943             8,633             7,366
    General Partner .............................................           29,679            23,478            13,864
                                                                      ------------      ------------      ------------
        Total pro forma net income allocated ....................     $    117,856      $    109,013      $     77,175
                                                                      ============      ============      ============

Basic and diluted net income per Limited
  Partner and Class B Unit:
    As reported .................................................     $       1.79      $       2.18      $       1.89
    Deduct:  Total unit-based employee compensation expense
      determined under fair value based method for all awards ...               --                --             (0.01)
                                                                      ------------      ------------      ------------
        Pro forma net income per Unit ...........................     $       1.79      $       2.18      $       1.88
                                                                      ============      ============      ============



         For purposes of determining compensation costs using the provisions of
SFAS 123, the fair value of option grants was determined using the Black-Scholes
option-valuation model. The key input variables used in valuing the options were
as follows: average risk-free interest rate based on five- and 10-year Treasury
bonds - 4.7%; Unit price volatility - 23%; dividend yield - 7.6%; and estimated
option lives - six years.



                                      F-13




                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

NEW ACCOUNTING PRONOUNCEMENTS

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

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

         The fair value of the asset retirement obligations for our trunk and
interstate pipelines and our surface facilities cannot be reasonably estimated,
as future dismantlement and removal dates are indeterminate. We will record such
asset retirement obligations in the period in which we determine the settlement
dates of the retirement obligations. Other assets in which future operating
lives may be determinable include our gathering assets in our Midstream and
Upstream Segments. However, our rights-of-way agreements, in general, do not
require us to remove pipe or otherwise perform restoration upon taking the
pipelines permanently out of service. We are continuing to evaluate the effect
of SFAS 143 on our Midstream and Upstream gathering assets, but we do not
currently anticipate that the adoption of SFAS 143 will have a material impact
on our financial position, results of operations or cash flows.

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

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

         In July 2002, the FASB issued SFAS No. 146, Accounting for Costs
Associated with Exit or Disposal Activities. SFAS 146 addresses financial
accounting and reporting for costs associated with exit or disposal activities
and nullifies Emerging Issues Task Force ("EITF") Issue No. 94-3, Liability
Recognition for Certain Employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring). SFAS 146
requires recognition of a liability for a cost associated with an exit or
disposal activity



                                      F-14




                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

when the liability is incurred, as opposed to when the entity commits to an exit
plan under EITF No. 94-3. SFAS 146 is to be applied prospectively to exit or
disposal activities initiated after December 31, 2002. We do not believe that
the adoption of SFAS 146 will have a material effect on our financial position,
results of operations or cash flows.

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

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

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


NOTE 3. GOODWILL AND OTHER INTANGIBLE ASSETS

         In July 2001, the 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.

         Beginning January 1, 2002, effective with the adoption of SFAS 142, we
no longer record amortization expense related to goodwill or amortization
expense related to the excess investment on our equity investment in Seaway
Crude Pipeline Company (see Note 6. Equity Investments). The following table
presents our results on a comparable basis, as if we had not recorded
amortization expense of goodwill or amortization expense of our excess
investment in Seaway Crude Pipeline Company for the years ended December 31,
2002, 2001 and 2000 (in thousands, except per Unit amounts):



                                      F-15



                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)




                                                                       YEARS ENDED DECEMBER 31,
                                                            ----------------------------------------------
                                                                2002             2001             2000
                                                            ------------     ------------     ------------
                                                                                     
Net income:
    Reported net income ...............................     $    117,862     $    109,131     $     77,376
    Amortization of goodwill and excess investment ....               --            2,396              767
                                                            ------------     ------------     ------------
      Adjusted net income .............................     $    117,862     $    111,527     $     78,143
                                                            ============     ============     ============

Net income allocation:
    Limited Partner Unitholders .......................     $     81,238     $     78,676     $     56,647
    Class B Unitholder ................................            6,943            8,832            7,458
    General Partner ...................................           29,681           24,019           14,038
                                                            ------------     ------------     ------------
      Total net income allocated ......................     $    117,862     $    111,527     $     78,143
                                                            ============     ============     ============

Basic and diluted net income per Limited
  Partner and Class B Unit:
    As reported .......................................     $       1.79     $       2.18     $       1.89
    Amortization of goodwill and excess investment ....               --             0.05             0.02
                                                            ------------     ------------     ------------
      Adjusted net income per Unit ....................     $       1.79     $       2.23     $       1.91
                                                            ============     ============     ============


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

         In connection with the transitional goodwill impairment evaluation
required by SFAS 142, we were required to perform an assessment of whether there
was an indication that goodwill was impaired as of the date of adoption. We
accomplished this by identifying our reporting units and determining the
carrying value of each reporting unit by assigning the assets and liabilities,
including the existing goodwill and intangible assets, to those reporting units
as of the date of adoption. We then determined the fair value of each reporting
unit and compared it to the carrying value of the reporting unit. We completed
this analysis during the second quarter of 2002, resulting in no transitional
impairment loss. We will continue to compare the fair value of each reporting
unit to the carrying value on an annual basis to determine if an impairment loss
has occurred.

         At December 31, 2002, we had $16.9 million of unamortized goodwill and
$25.5 million of excess investment in our equity investment (equity method
goodwill). We completed an impairment analysis of the excess investment in our
equity investment during the year ended December 31, 2002, and we noted no
indication of impairment. The excess investment is included in our equity
investments account at December 31, 2002. The following table presents the
carrying amount of goodwill and excess investment at December 31, 2002, by
business segment (in thousands):




                                 DOWNSTREAM      MIDSTREAM       UPSTREAM        SEGMENTS
                                  SEGMENT         SEGMENT         SEGMENT          TOTAL
                                ------------    ------------    ------------    ------------
                                                                     
Goodwill......................   $       --      $    2,777      $   14,167      $   16,944
Equity method goodwill........           --              --          25,502          25,502





                                      F-16




                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

         The following table reflects the components of amortized intangible
assets, excluding goodwill (in thousands):





                                                           DECEMBER 31, 2002               DECEMBER 31, 2001
                                                    -----------------------------------------------------------------
                                                    GROSS CARRYING     ACCUMULATED    GROSS CARRYING     ACCUMULATED
                                                        AMOUNT        AMORTIZATION        AMOUNT        AMORTIZATION
                                                    --------------   --------------   --------------   --------------
                                                                                            
  Amortized intangible assets:
     Fractionation agreement..................        $   38,000      $   (9,025)      $   38,000       $   (7,125)
     Natural gas transportation contracts.....           462,449         (28,710)         222,800           (3,275)
     Other....................................             3,745          (1,085)           1,458             (371)
                                                    --------------   --------------   --------------   --------------
        Total.................................        $  504,194      $  (38,820)      $  262,258       $   (10,771)
                                                    ==============   ==============   ==============   ==============


         Excluding goodwill, amortization expense on intangible assets was $27.9
million, $5.5 million and $2.0 million for the years ended December 31, 2002,
2001 and 2000, respectively.

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

                                                                  
        2003...................................................       $    50,799
        2004...................................................            52,384
        2005...................................................            52,657
        2006...................................................            47,153
        2007...................................................            42,174




NOTE 4.  DERIVATIVE FINANCIAL INSTRUMENTS

         We have entered into an interest rate swap agreement to hedge our
exposure to increases in the benchmark interest rate underlying our variable
rate revolving credit facility. The term of the interest rate swap matches the
maturity of the credit facility. We designated this swap agreement, which hedges
exposure to variability in expected future cash flows attributed to changes in
interest rates, as a cash flow hedge. The swap agreement is based on a notional
amount of $250.0 million. Under the swap agreement, we pay a fixed rate of
interest of 6.955% and receive a floating rate based on a three month U.S.
Dollar LIBOR rate. Since this swap is designated as a cash flow hedge, the
changes in fair value, to the extent the swap is effective, are recognized in
other comprehensive income until the hedged interest costs are recognized in
earnings. During the years ended December 31, 2002, and 2001, we recognized
increases in interest expense of $12.9 million and $6.8 million, respectively,
related to the difference between the fixed rate and the floating rate of
interest on the interest rate swap. During the year ended December 31, 2002, we
measured the hedge effectiveness of this interest rate swap and noted that no
gain or loss from ineffectiveness was required to be recognized. The fair value
of the interest rate swap agreement was a loss of approximately $20.1 million
and $20.3 million at December 31, 2002, and 2001, respectively. We anticipate
that approximately $13.5 million of the fair value will be transferred into
earnings over the next twelve months.

         On October 4, 2001, our TE Products subsidiary entered into an interest
rate swap agreement to hedge its exposure to changes in the fair value of its
fixed rate 7.51% Senior Notes due 2028. We designated this swap agreement as a
fair value hedge. The swap agreement has a notional amount of $210.0 million and
matures in January 2028 to match the principal and maturity of the TE Products
Senior Notes. Under the swap agreement, TE Products pays a floating rate based
on a three month U.S. Dollar LIBOR rate, plus a spread, and receives a fixed
rate of interest of 7.51%. During the years ended December 31, 2002, and 2001,
we recognized reductions in interest expense of $8.6 million and $1.8 million,
respectively, related to the difference between the fixed rate and the floating
rate of interest on the interest rate swap. During the year ended December 31,
2002, we measured the hedge effectiveness of this interest rate swap and noted
that no gain or loss from ineffectiveness was required to be



                                      F-17




                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


recognized. The fair value of this interest rate swap agreement was a gain of
approximately $13.6 million at December 31, 2002, and a loss of approximately
$14.6 million at December 31, 2001.

         On February 20, 2002, we entered into interest rate swap agreements to
hedge our exposure to changes in the fair value of our fixed rate 7.625% Senior
Notes due 2012. We designated these swap agreements as fair value hedges. The
swap agreements had a combined notional amount of $500.0 million and matured in
2012 to match the principal and maturity of the Senior Notes. Under the swap
agreements, we paid a floating rate based on a six month U.S. Dollar LIBOR rate,
plus a spread, and received a fixed rate of interest of 7.625%. On July 16,
2002, we terminated these interest rate swap agreements. Upon termination, the
fair value of the interest rate swap agreements was $25.8 million. From
inception of the swap agreements on February 20, 2002, through the termination
on July 16, 2002, $7.8 million had been recognized as a reduction to interest
expense. The remaining gain of approximately $18.0 million has been deferred as
an adjustment to the carrying value of the Senior Notes and is being amortized
using the effective interest method as a reduction to future interest expense
over the remaining term of the Senior Notes. In the event of early
extinguishment of the Senior Notes, any remaining unamortized gain would be
recognized in the consolidated statement of income at the time of
extinguishment.

         Additionally, on July 16, 2002, we entered into new interest rate swap
agreements to hedge our exposure to changes in the fair value of our $500.0
million principal amount of 7.625% fixed rate Senior Notes due 2012. We
designated these swap agreements as fair value hedges. The swap agreements had a
combined notional amount of $500.0 million and matured in 2012 to match the
principal and maturity of the Senior Notes. Under these swap agreements, we paid
a floating rate based on a six month U.S. Dollar LIBOR rate, plus a spread,
which increased by approximately 50 basis points from the previous swap
agreements, and received a fixed rate of interest of 7.625%. On December 12,
2002, we terminated these interest rate swap agreements. Upon termination, the
fair value of the interest rate swap agreements was $33.5 million. From
inception of the swap agreements on July 16, 2002, through the termination on
December 12, 2002, $6.6 million had been recognized as a reduction to interest
expense. The remaining gain of approximately $26.9 million has been deferred as
an adjustment to the carrying value of the Senior Notes and is being amortized
using the effective interest method as a reduction to future interest expense
over the remaining term of the Senior Notes. In the event of early
extinguishment of the Senior Notes, any remaining unamortized gain would be
recognized in the consolidated statement of income at the time of
extinguishment.


NOTE 5.  ACQUISITIONS

         On July 20, 2000, we 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% 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. We assumed ARCO's role as operator of this
pipeline. We 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, we 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, we reached a settlement with Atlantic
Richfield Company of $11.0 million for the post-closing adjustments.



                                      F-18




                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

We recorded the settlement as an increase to the purchase price of ARCO. We paid
the settlement amount to Atlantic Richfield Company on October 15, 2001.

         On December 31, 2000, we completed an acquisition of 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. We
also assumed a lease of a condensate pipeline from Carthage to Marshall, Texas.
All three pipelines originate at DEFS' East Texas Plant Complex in Panola
County, Texas. We accounted for the acquisition of these assets under the
purchase method of accounting.

         On September 30, 2001, our subsidiaries completed the purchase of Jonah
from Alberta Energy Company for $359.8 million. The acquisition served as our
entry into the natural gas gathering industry. We recognized goodwill on the
purchase of approximately $2.8 million. We accounted for the acquisition under
the purchase method of accounting. Accordingly, the results of the acquisition
are included in the consolidated financial statements from September 30, 2001.
We paid an additional $7.3 million on February 4, 2002, for final purchase
adjustments related primarily to construction projects in progress at the time
of closing. Under a contractual agreement, DEFS manages and operates Jonah on
our behalf.

         The following table allocates the estimated fair value of Jonah assets
acquired on September 30, 2001, and includes the additional purchase adjustment
paid on February 4, 2002 (in thousands):


                                                               
Property, plant and equipment ..............................      $    141,835
Intangible assets (primarily gas transportation contracts) .           222,800
Goodwill ...................................................             2,777
Other ......................................................               147
                                                                  ------------
    Total assets ...........................................           367,559
                                                                  ============

Total liabilities assumed ..................................              (489)
                                                                  ------------
    Net assets acquired ....................................      $    367,070
                                                                  ============



         The value assigned to intangible assets relates to contracts with
customers that are for either a fixed term or which dedicate total future lease
production. We are amortizing the value assigned to intangible assets on a unit
of production basis, based upon the actual throughput of the system over the
expected total throughput for the contracts (averaging approximately 16 years).

         On March 1, 2002, we completed the purchase of the Chaparral NGL system
("Chaparral") for $132.4 million from Diamond-Koch II, L.P. and Diamond-Koch
III, L.P., including acquisition related costs of approximately $0.4 million. We
funded the purchase by a drawdown of our $500.0 million revolving credit
facility (see Note 10. Debt). Chaparral is an NGL pipeline system that extends
from West Texas and New Mexico to Mont Belvieu. The pipeline delivers NGLs to
fractionators and to our existing storage in Mont Belvieu. Under a contractual
agreement, DEFS manages and operates these assets on our behalf. We accounted
for the acquisition of these assets under the purchase method of accounting. We
allocated the purchase price to property, plant and equipment. Accordingly, the
results of the acquisition are included in the consolidated financial statements
from March 1, 2002.

         On June 30, 2002, we completed the purchase of Val Verde for $444.2
million from Burlington Resources Gathering Inc., a subsidiary of Burlington
Resources Inc., including acquisition related costs of approximately $1.2
million. We funded the purchase by drawing down $168.0 million under our $500.0
million revolving credit facility, $72.0 million under our 364-day revolving
credit facility, and $200.0 million under a six-month term loan with SunTrust
Bank (see Note 10. Debt). The remaining purchase price was funded through
working capital sources of cash. The Val Verde system gathers CBM from the
Fruitland Coal Formation of the San Juan Basin in



                                      F-19




                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

New Mexico and Colorado. The system is one of the largest CBM gathering and
treating facilities in the United States. Under a contractual agreement, DEFS
manages and operates Val Verde on our behalf. We accounted for the acquisition
of these assets under the purchase method of accounting. Accordingly, the
results of the acquisition are included in the consolidated financial statements
from June 30, 2002.

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

                                                                  
Property, plant and equipment .................................      $     205,146
Intangible assets (primarily gas transportation contracts) ....            239,649
                                                                     -------------
  Total assets ................................................            444,795
                                                                     =============

Total liabilities assumed .....................................               (645)
                                                                     -------------
  Net assets acquired .........................................      $     444,150
                                                                     =============



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

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



                                                                                YEARS ENDED
                                                                                DECEMBER 31,
                                                                     ----------------------------------
                                                                         2002                  2001
                                                                     ------------          ------------
                                                                                     
Revenues.......................................................      $  3,279,948          $  3,659,496
Operating income...............................................           181,717               179,600
Net income.....................................................           130,335               119,286
Basic and diluted net income per
    Limited Partner and Class B Unit...........................      $       1.70        $         2.00


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


NOTE 6.  EQUITY INVESTMENTS

         The acquisition of the ARCO assets in July 2000 included ARCO's 50%
ownership interest in 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. Seaway is a partnership between a subsidiary of TCTM, TEPPCO
Seaway, L.P. ("TEPPCO Seaway"), and ConocoPhillips. TCTM purchased the 50%
ownership interest in Seaway on July 20, 2000, and transferred the investment to
TEPPCO Seaway. 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, TEPPCO Seaway received 80% of revenue and
expense of Seaway. From June 2002 through May 2006, TEPPCO Seaway will receive
60% of revenue and expense of Seaway. Thereafter, the sharing ratio becomes 40%
of revenue and



                                      F-20




                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

expense to TEPPCO Seaway. For the year ended December 31, 2002, our portion of
equity earnings on a pro-rated basis averaged approximately 67%.

         In August 2000, TE Products entered into agreements with Panhandle
Eastern Pipeline Company ("PEPL"), a subsidiary of CMS Energy Corporation, and
Marathon Ashland Petroleum LLC ("Marathon") to form Centennial Pipeline LLC
("Centennial"). Centennial owns an interstate refined petroleum products
pipeline extending from the upper Texas Gulf Coast to Illinois. Through December
31, 2002, each participant owned a one-third interest in Centennial. During the
years ended December 31, 2002 and 2001, we contributed approximately $10.9
million and $70.0 million, respectively, for our investment in Centennial. These
amounts are included in the equity investment balance at December 31, 2002 and
2001.

         We use the equity method of accounting to report our investments in
Seaway and Centennial. Summarized combined income statement data for Seaway and
Centennial for the years ended December 31, 2002, and 2001, is presented below
(in thousands):



                                                         YEARS ENDED
                                                         DECEMBER 31,
                                                 -----------------------------
                                                    2002               2001
                                                 ----------         ----------
                                                              
Revenues....................................     $   83,237         $   55,719
Net income..................................          5,389             26,218


         Summarized combined balance sheet data for Seaway and Centennial as of
December 31, 2002, and 2001, is presented below (in thousands):



                                                         DECEMBER 31,
                                                 -----------------------------
                                                    2002               2001
                                                 ----------         ----------
                                                             
Current assets..............................     $   32,528         $   57,368
Noncurrent assets...........................        551,324            528,835
Current liabilities.........................         28,681             31,308
Long-term debt..............................        140,000            128,000
Noncurrent liabilities......................         14,875                 --
Partners' capital...........................        400,296            426,895


         Our investment in Seaway at December 31, 2002, and 2001, includes an
excess net investment amount of $25.5 million. Excess investment is the amount
by which our investment balance exceeds our proportionate share of the net
assets of the investment. Prior to January 1, 2002, and our adoption of SFAS
142, we were amortizing the excess investment in Seaway using the straight-line
method over 20 years.


NOTE 7.  RELATED PARTY TRANSACTIONS

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

         For the years ended December 31, 2002, 2001, and 2000, direct expenses
incurred by the Company of $69.6 million, $68.2 million and $50.4 million,
respectively, were charged to us by DEFS. Substantially all such costs were
related to payroll and payroll related expenses. For the years ended December
31, 2002, 2001, and 2000, expenses for administrative services and overhead
allocated to us by Duke Energy and its affiliates were $0.8 million, $0.6
million and $0.8 million, respectively.



                                      F-21




                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

         Effective with the purchase of the fractionation facilities on March
31, 1998, TEPPCO Colorado, LLC ("TEPPCO Colorado") and DEFS entered into a
20-year Fractionation Agreement, under which TEPPCO Colorado receives a variable
fee for all fractionated volumes delivered to DEFS. Revenues recognized from the
fractionation facilities totaled $7.4 million, $7.4 million and $7.5 million for
the years ended December 31, 2002, 2001 and 2000, respectively. TEPPCO Colorado
and DEFS also entered into an Operation and Maintenance Agreement, whereby DEFS
operates and maintains the fractionation facilities. For these services, TEPPCO
Colorado pays DEFS a set volumetric rate for all fractionated volumes delivered
to DEFS. Expenses related to the Operation and Maintenance Agreement totaled
$0.9 million, $0.9 million and $0.9 million for the years ended December 31,
2002, 2001 and 2000, respectively.

         Included with 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 paid to us by DEFS under the agreement totaled $1.2 million, $1.2 million
and $1.1 million for the years ended December 31, 2002, 2001 and 2000,
respectively. The Panola Pipeline and San Jacinto Pipeline were purchased on
December 31, 2000, from DEFS for $91.7 million. These pipelines originate at
DEFS' East Texas Plant Complex in Panola County, Texas. For the years ended
December 31, 2002 and 2001, revenues recognized included $12.0 million and $13.9
million, respectively, from a subsidiary of DEFS for NGL transportation fees on
the Panola and San Jacinto Pipelines.

         On July 20, 2000, we, through TCTM, acquired a 50% ownership interest
in Seaway. ConocoPhillips owns the remaining 50% interest in Seaway. TEPPCO
Crude Pipeline, L.P. is the operator of this pipeline. During the years ended
December 31, 2002, 2001 and 2000, we billed Seaway $7.1 million, $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, 2002,
2001 and 2000, we billed Seaway $2.1 million, $2.1 million and $0.9 million,
respectively, for indirect management fees for operating Seaway.

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

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

         On March 1, 2002, we completed the acquisition of the Chaparral NGL
system. The Chaparral assets are managed and operated by employees of DEFS under
a contractual agreement under which DEFS is reimbursed for its actual costs.
During the year ended December 31, 2002, we recognized $1.7 million of expenses
related to the management of the Chaparral assets by DEFS.

         On June 30, 2002, we completed the acquisition of Val Verde. The Val
Verde assets are managed and operated by employees of DEFS under a contractual
agreement under which DEFS is reimbursed for its actual costs. During the year
ended December 31, 2002, we recognized $1.2 million of expenses related to the
management of the Val Verde assets by DEFS.

         In August 2000, TE Products entered into agreements with PEPL and
Marathon to form Centennial (see Note 6. Equity Investments). At December 31,
2002, TE Products had a one-third ownership interest in Centennial. TE Products
has entered into a management agreement with Centennial to operate Centennial's
terminal at Creal Springs and pipeline connection in Beaumont, Texas. For the
year ended December 31, 2002, we recognized management fees of $0.2 million from
Centennial, and actual operating expenses billed to Centennial were $0.3



                                      F-22



                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

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


NOTE 8.  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,
                                                         -----------------------------
                                                             2002             2001
                                                         ------------     ------------

                                                                   
        Crude oil..................................      $         --     $     3,783
        Gasolines..................................             4,700           4,548
        Propane....................................                --           1,096
        Butanes....................................             1,991           1,431
        Transmix...................................             2,526             878
        Other products.............................             3,836           1,988
        Materials and supplies.....................             4,113           3,519
                                                         ------------     -----------
               Total...............................      $     17,166     $    17,243
                                                         ============     ===========


         The costs of inventories did not exceed market values at December 31,
2002 and 2001.


NOTE 9.  PROPERTY, PLANT AND EQUIPMENT

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




                                                                                       DECEMBER 31,
                                                                              -----------------------------
                                                                                  2002             2001
                                                                              -------------    ------------

                                                                                         
        Land and right of way.............................................    $     106,279    $     92,664
        Line pipe and fittings...................... .....................        1,090,848         822,332
        Storage tanks.....................................................          143,740         130,461
        Buildings and improvements........................................           20,408          15,131
        Machinery and equipment...........................................          463,049         252,393
        Construction work in progress.....................................          102,246         157,728
                                                                              -------------    ------------
               Total property, plant and equipment........................    $   1,926,570    $  1,470,709
               Less accumulated depreciation and amortization.............          338,746         290,248
                                                                              -------------    ------------
                 Net property, plant and equipment........................    $   1,587,824    $  1,180,461
                                                                              =============    ============


         Depreciation expense on property, plant and equipment was $56.0
million, $39.5 million and $33.0 million for the years ended December 31, 2002,
2001 and 2000, respectively.



                                      F-23



                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

NOTE 10. LONG TERM DEBT


SENIOR NOTES

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

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

         On February 20, 2002, we received $494.6 million in net proceeds, after
underwriting discount, from the issuance of $500.0 million principal amount of
7.625% Senior Notes due 2012. The 7.625% Senior Notes were issued at a discount
of $2.2 million and are being accreted to their face value over the term of the
notes. We used the proceeds from the offering to reduce a portion of the
outstanding balances of our credit facilities, including those issued in
connection with the acquisition of Jonah. The Senior Notes may be redeemed at
any time at our option with the payment of accrued interest and a make-whole
premium determined by discounting remaining interest and principal payments
using a discount rate equal to the rate of the United States Treasury securities
of comparable remaining maturity plus 35 basis points. The indenture governing
our 7.625% Senior Notes contains covenants, including, but not limited to,
covenants limiting the creation of liens securing indebtedness and sale and
leaseback transactions. However, the indenture does not limit our ability to
incur additional indebtedness. As of December 31, 2002, we were in compliance
with the covenants of these Senior Notes.

         At December 31, 2002 and 2001, the estimated fair value of the Senior
Notes was approximately $914.9 million and $362.0 million, respectively. Market
prices for recent transactions and rates currently available to us for debt with
similar terms and maturities were used to estimate fair value.

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


OTHER LONG TERM DEBT AND CREDIT FACILITIES

         On July 14, 2000, we entered into a $75.0 million term loan and a
$475.0 million revolving credit facility ("Three Year Facility"). On July 21,
2000, we borrowed $75.0 million under the term loan and $340.0 million under the
Three Year Facility. The funds were used to finance the acquisition of the ARCO
assets (see Note 5. 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 Three Year Facility was amended to provide for
revolving borrowings of up to $500.0 million for a period of three years
including the issuance of letters of credit of up to $20.0 million. The interest
rate is based, at our option, on either the lender's base rate plus a spread, or
LIBOR plus a spread in effect at the time of the borrowings. The credit
agreement for the Three Year Facility contains restrictive financial covenants
that require us to maintain a minimum level of partners' capital as well as
maximum debt-to-EBITDA (earnings before interest expense, income



                                      F-24



                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

tax expense and depreciation and amortization expense) and minimum fixed charge
coverage ratios. On February 20, 2002, we repaid $115.7 million of the then
outstanding balance of the Three Year Facility with proceeds from the issuance
of our 7.625% Senior Notes. On March 1, 2002, we borrowed $132.0 million under
the Three Year Facility to finance the acquisition of the Chaparral NGL system.
On March 22, 2002, we repaid a portion of the Three Year Facility with proceeds
we received from the issuance of additional Limited Partner Units (see Note 11.
Partners' Capital). To facilitate our financing of a portion of the purchase
price of the Val Verde assets, on June 27, 2002, the Three Year Facility was
amended to increase the maximum permitted debt-to-EBITDA ratio covenant to allow
us to incur additional indebtedness. For the twelve month period ending June 30,
2002, the maximum permitted ratio was 5.5-to-1 on a pro forma basis. For the
twelve month period ending September 30, 2002, the maximum permitted ratio was
5.0-to-1 on a pro forma basis. At December 31, 2002, the maximum permitted
debt-to-EBITDA ratio under our revolving credit facility returned to its
pre-amendment level of 4.5-to-1. We then drew down the existing capacity of the
Three Year Facility and acquired the Val Verde assets. During the fourth quarter
of 2002, we repaid $68.0 million of the outstanding balance of the Three Year
Facility with proceeds from our November 2002 equity offering (see Note 11.
Partners' Capital) and proceeds from the termination of our interest rate swaps
(see Note 4. Derivative Financial Instruments). At December 31, 2002, $432.0
million was outstanding under the Three Year Facility at a weighted average
interest rate of 2.5%. As of December 31, 2002, we were in compliance with the
covenants contained in this credit agreement.

         We have entered into an interest rate swap agreement to hedge our
exposure to increases in interest rates on the Three Year Facility discussed
above. See Note 4. Derivative Financial Instruments.


SHORT TERM CREDIT FACILITIES

         On April 6, 2001, we entered into a 364-day, $200.0 million revolving
credit agreement ("Short-term Revolver"). The interest rate is based, at our
option, on either the lender's base rate plus a spread, or LIBOR plus a spread
in effect at the time of the borrowings. The credit agreement contains
restrictive financial covenants that require us to maintain a minimum level of
partners' capital as well as maximum debt-to-EBITDA and minimum fixed charge
coverage ratios. On March 28, 2002, the Short-term Revolver was extended for an
additional period of 364 days, ending in March 2003. To facilitate our financing
of a portion of the purchase price of the Val Verde assets, on June 27, 2002,
the Short-term Revolver was amended to increase the maximum permitted
debt-to-EBITDA ratio covenant to allow us to incur additional indebtedness. For
the twelve month period ending June 30, 2002, the maximum permitted ratio was
5.5-to-1 on a pro forma basis. For the twelve month period ending September 30,
2002, the maximum permitted ratio was 5.0-to-1 on a pro forma basis. At December
31, 2002, the maximum permitted debt-to-EBITDA ratio under our revolving credit
facility returned to its pre-amendment level of 4.5-to-1. We then drew down
$72.0 million under the Short-term Revolver. In the fourth quarter of 2002, we
repaid the existing amounts outstanding under the Short-term Revolver with
proceeds we received from the issuance of Limited Partner Units in November and
December 2002. At December 31, 2002, no amounts were outstanding under the
Short-term Revolver. As of December 31, 2002, we were in compliance with the
covenants contained in this credit agreement. In February 2003, we gave notice
that we will not renew the Short-term Revolver. As a result, the facility will
expire on March 27, 2003.

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

         On June 27, 2002, we entered into a $200.0 million six-month term loan
with SunTrust Bank ("Six-Month Term Loan") payable in December 2002. We borrowed
$200.0 million under the Six-Month Term Loan to acquire



                                      F-25



                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

the Val Verde assets (see Note 5. Acquisitions). The interest rate was based, at
our option, on either the lender's base rate plus a spread, or LIBOR plus a
spread in effect at the time of the borrowings. The credit agreement contained
restrictive financial covenants that required us to maintain a minimum level of
partners' capital as well as maximum debt-to-EBITDA and minimum fixed charge
coverage ratios. On July 11, 2002, we repaid $90.0 million of the outstanding
principal from proceeds primarily received from the issuance of Limited Partner
Units in July 2002. On September 10, 2002, we repaid the remaining outstanding
balance of $110.0 million with proceeds received from the issuance of Limited
Partner Units in September 2002 (see Note 11. Partners' Capital), and canceled
the facility.

         The following table summarizes the principal amounts outstanding under
our credit facilities as of December 31, 2002 and 2001 (in thousands):



                                                                               DECEMBER 31,
                                                                  ------------------------------------
                                                                        2002                2001
                                                                  ----------------    ----------------
                                                                                
Short Term Credit Facilities:
    Short-term Revolver, due March 2003......................     $             --    $        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......................     $        432,000    $        340,658
    6.45% TE Products Senior Notes, due January 2008.........              179,845             179,814
    7.51% TE Products Senior Notes, due January 2028.........              210,000             210,000
    7.625% Senior Notes, due February 2012...................              497,995                  --
                                                                  ----------------    ----------------
       Total borrowings......................................            1,319,840             730,472

    Adjustment to carrying value associated with hedges of
       fair value............................................               57,852             (14,630)
                                                                  ----------------    ----------------
          Total Long Term Credit Facilities..................     $      1,377,692    $        715,842
                                                                  ================    ================



NOTE 11. PARTNERS' CAPITAL

         On February 6, 2001, we sold in an underwritten public offering 2.0
million Limited Partner Units at $25.50 per Unit. The proceeds from the
offering, net of underwriting discount, totaled approximately $48.7 million and
were used to reduce borrowings under the Three Year Facility. On March 6, 2001,
250,000 Units were sold upon exercise of the underwriters' over-allotment option
granted in connection with the offering on February 6, 2001. Proceeds from that
sale totaled $6.1 million and were used for general purposes.

         On November 14, 2001, we sold in an underwritten public offering 5.5
million Limited Partner Units at $34.25 per Unit. The proceeds from the
offering, net of underwriting discount, totaled approximately $180.3 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 March 22, 2002, we sold in an underwritten public offering 1.92
million Limited Partner Units at $31.18 per Unit. The proceeds from the
offering, net of underwriting discount, totaled approximately $57.3 million and
were used to repay $50.0 million of the outstanding balance on the Three Year
Facility, with the remaining amount being used for general purposes.

         On July 11, 2002, we sold in an underwritten public offering 3.0
million Limited Partner Units at $30.15 per Unit. The proceeds from the
offering, net of underwriting discount, totaled approximately $86.6 million and
were used to reduce borrowings under our Six-Month Term Loan. On August 14,
2002, 175,000 Units were sold



                                      F-26




                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

upon exercise of the underwriters' over-allotment option granted in connection
with the offering on July 11, 2002. Proceeds from that sale totaled $5.1 million
and were used for general purposes.

         On September 6, 2002, we sold in an underwritten public offering 3.8
million Limited Partner Units at $29.72 per Unit. The proceeds from the
offering, net of underwriting discount, totaled approximately $108.1 million and
were used to reduce borrowings under our Six-Month Term Loan. On September 19,
2002, 570,000 Units were sold upon exercise of the underwriters' over-allotment
option granted in connection with the offering on September 6, 2002. Proceeds
from that sale totaled $16.2 million and were used to reduce borrowings under
our Short-term Revolver.

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


NOTE 12. CONCENTRATIONS OF CREDIT RISK

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

         For the years ended December 31, 2002, 2001 and 2000, we had one
customer from the Upstream Segment, Valero Energy Corp., which accounted for
16%, 14% and 12%, respectively, of our total consolidated revenues.

         The carrying amount of cash and cash equivalents, accounts receivable,
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 13. QUARTERLY DISTRIBUTIONS OF AVAILABLE CASH

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




                                      F-27




                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

         The following table reflects the allocation of total distributions paid
for the years ended December 31, 2002, 2001 and 2000 (in thousands, except per
Unit amounts).



                                                                           YEARS ENDED DECEMBER 31,
                                                                 ------------------------------------------
                                                                     2002           2001            2000
                                                                 -----------    -----------     -----------
                                                                                         
Limited Partner Units........................................    $   104,932    $    73,961     $   59,943
General Partner Ownership Interest...........................          2,329          1,273            685
General Partner Incentive....................................         35,389         20,257         12,938
                                                                 -----------    -----------     ----------
    Total Partners' Capital Cash Distributions...............        142,650         95,491         73,566
Class B Units................................................          9,204          8,421          7,833
Minority Interest............................................             --            500            832
                                                                 -----------    -----------     ----------
    Total Cash Distributions Paid............................    $   151,854    $   104,412     $   82,231
                                                                 ===========    ===========     ==========
Total Cash Distributions Paid Per Unit.......................    $      2.35    $      2.15     $     2.00
                                                                 ===========    ===========     ==========


         On February 7, 2003, we paid a cash distribution of $0.60 per Limited
Partner Unit and Class B Unit for the quarter ended December 31, 2002. The
fourth quarter 2002 cash distribution totaled $46.5 million.

NOTE 14. UNIT-BASED COMPENSATION


1994 LONG TERM INCENTIVE PLAN

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

         When our calendar year earnings per unit (exclusive of certain special
items) exceeds a stated threshold, each participant receives a credit to their
respective Performance Unit account equal to the earnings per unit excess
multiplied by the number of Performance Units awarded. The balance in the
Performance Unit account may be used to offset the cost of exercising 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. We accrue compensation expense for the Performance Units
awarded annually based upon the terms of the plan discussed above.

         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...........................................       11,100           $ 1.875           2009




                                      F-28




                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)





                                                     OPTIONS           OPTIONS             EXERCISE
                                                   OUTSTANDING       EXERCISABLE             RANGE
                                                   ------------    ----------------    ------------------
                                                                                     
Limited Partner Unit Options:
 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................................            (2,800)                 --               $25.25
    Became exercisable.......................                --              81,669      $25.25 - $25.69
    Exercised................................           (98,376)            (98,376)     $13.81 - $25.69
                                                   ------------    ----------------
 Outstanding at December 31, 2001............           189,688             143,822      $13.81 - $25.69
    Forfeited................................                --                  --               $25.25
    Became exercisable.......................                --              45,866               $25.25
    Exercised................................           (99,597)            (99,597)     $13.81 - $25.69
                                                   ------------    ----------------
 Outstanding at December 31, 2002............            90,091              90,091      $13.81 - $25.69
                                                   ============    ================


         We have not granted options for any periods presented. For options
outstanding, we followed the intrinsic value method for recognizing stock-based
compensation expense. The exercise price of all options awarded under the 1994
LTIP equaled the market price of our Limited Partner Units on the date of grant.
Accordingly, we recognized no compensation expense at the date of grant. Had
compensation expense been determined consistent with SFAS No. 123, Accounting
for Stock-Based Compensation, compensation expense related to option grants
would have totaled $5,570, $118,820 and $202,634 during the years ended December
31, 2002, 2001 and 2000, 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.

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


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




1999 AND 2002 PHANTOM UNIT PLANS

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

         Under the agreement for the phantom units, each participant will vest
10% of the number of phantom units initially granted under his or her award at
the end of each of the first four years and will vest the final 60% at the end
of the fifth year. Each participant is required to redeem their units as they
vest. They are also entitled to quarterly cash distributions equal to the
product of the number of phantom units outstanding for the participant and the



                                      F-29




                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

amount of the cash distribution that we paid per unit to Limited Partner
Unitholders. A total of 58,800 phantom units have been granted under the 1999
PURP, of which 30,330 remain outstanding at December 31, 2002. A total of 71,400
phantom units have been granted under the 2002 PURP, of which all 71,400 remain
outstanding at December 31, 2002. We accrue compensation expense annually based
upon the terms of the 1999 PURP and 2002 PURP discussed above.


2000 LONG TERM INCENTIVE PLAN

         Effective January 1, 2000, the General Partner established the Texas
Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan ("2000
LTIP") to provide key employees incentives to achieve improvements in our
financial performance. Generally, upon the close of a three-year performance
period, if the participant is then still an employee of the General Partner, the
participant will receive a cash payment in an amount equal to (1) the applicable
performance percentage specified in the award multiplied by (2) the number of
phantom 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 our Economic Value Added during a three-year performance period over the
Economic Value Added during the three-year period immediately preceding the
performance period. The performance percentage may not exceed 150%. If a
participant incurs a separation from service during the performance period due
to death, disability or retirement (as such terms are defined in the 2000 LTIP),
the participant will be entitled to receive a cash payment in an amount equal to
the amount computed as described above multiplied by a fraction, the numerator
of which is the number of days that have elapsed during the performance period
prior to the participant's separation from service and the denominator of which
is the number of days in the performance period. At December 31, 2002, phantom
Limited Partner Units outstanding were 22,300, 24,013 and 18,425 for awards
granted in 2002, 2001 and 2000, respectively.

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

         In addition to the payment described above, during the performance
period, the General Partner will pay to the Participant the amount of cash
distributions that we would have paid to our Unitholders had the participant
been the owner of the number of Limited Partner Units equal to the number of
phantom Limited Partner Units granted to the participant under this award. The
maximum potential payout under the 2000 LTIP is 150% of phantom units awarded.
We accrue compensation expense annually based upon the terms of the 2000 LTIP
discussed above.




                                      F-30



                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


NOTE 15. OPERATING LEASES

         We utilize leased assets in several areas of our operations. Total
rental expense during the years ended December 31, 2002, 2001 and 2000 was $14.2
million, $10.8 million and $10.7 million, respectively. The following table sets
forth our minimum rental payments under our various operating leases for the
years ending December 31 (in thousands):


                                                 
        2003......................................   $    9,479
        2004......................................        8,903
        2005......................................        8,102
        2006......................................        6,035
        2007......................................        1,820
        Thereafter................................        1,068
                                                     ----------
                                                     $   35,407
                                                     ==========




NOTE 16. 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.

         The components of net pension benefits costs for the TEPPCO RCBP and
the TEPPCO SBP for the years ended December 31, 2002, 2001 and 2000, and for the
Duke Energy RCBP and the Duke Energy ECBP for the year ended December 31, 2000
were as follows (in thousands):



                                                           2002          2001          2000
                                                        ----------    ----------    ----------
                                                                                 
Service cost benefit earned during the year...........  $    2,925    $    2,419    $   2,054
Interest cost on projected benefit obligation.........         315           129          782
Expected return on plan assets........................        (390)         (166)        (663)
Amortization of prior service cost....................           7             8           --
Amortization of net transition liability..............          --            --            4
Recognized net actuarial loss ........................          12            --           --
                                                        ----------    ----------    ---------
    Net pension benefits costs........................  $    2,869    $    2,390    $   2,177
                                                        ==========    ==========    =========



                                      F-31




                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

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 year ended December 31, 2000, and for the TEPPCO OPB for the years
ended December 31, 2002 and 2001, were as follows (in thousands):



                                                                            2002           2001         2000
                                                                        ----------      ---------    ---------
                                                                                            
Service cost benefit earned during the year......................       $      115      $      99    $      39
Interest cost on accumulated postretirement benefit obligation...              119            113          134
Expected return on plan assets...................................               --             --          (85)
Amortization of prior service cost...............................              126            126          (96)
Amortization of net transition liability.........................               --             --           54
                                                                        ----------      ---------    ---------
     Net postretirement benefits costs...........................       $      360      $     338    $      46
                                                                        ==========      =========    =========


         The weighted average assumptions used in the actuarial computations for
the retirement plans and other postretirement benefit plans for the years ended
December 31, 2002 and 2001 are as follows:



                                                                                        OTHER POSTRETIREMENT
                                                            PENSION BENEFITS                  BENEFITS
                                                        -------------------------     ------------------------
                                                           2002           2001           2002           2001
                                                        ----------     ----------     ----------    ----------
                                                                                           
Discount rate........................................       6.75%         7.25%          6.75%         7.25%
Increase in compensation levels......................       5.00%         5.06%            --            --
Expected long-term rate of return on plan assets.....       9.00%         9.00%            --            --





                                      F-32




                              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, 2002 and 2001 (in thousands):



                                                                                        OTHER POSTRETIREMENT
                                                             PENSION BENEFITS                 BENEFITS
                                                        -------------------------     ------------------------
                                                            2002           2001          2002           2001
                                                        -----------     ---------     ----------     ---------
                                                                                          
CHANGE IN BENEFIT OBLIGATION
  Benefit obligation at beginning of year............   $     3,786     $   1,518     $    1,781     $      --
  Service cost.......................................         2,925         2,419            115            99
  Interest cost......................................           315           129            118           113
  Plan amendments....................................            --            62             --         1,508
  Actuarial (gain)/loss..............................           711          (136)             1            57
  Retiree contributions..............................            --            --             29             9
  Benefits paid......................................          (159)         (206)           (43)           (5)
                                                        -----------     ---------     ----------     ---------
  Benefit obligation at end of year..................   $     7,578     $   3,786     $    2,001     $   1,781
                                                        ===========     =========     ==========     =========

CHANGE IN PLAN ASSETS
  Fair value of plan assets at beginning of year.....   $     3,959     $      --     $       --     $      --
  Actual return on plan assets.......................           (99)          (37)            --            --
  Retiree contributions..............................            --            --             29             9
  Employer contributions.............................         3,119         4,202             14            (4)
  Benefits paid......................................          (159)         (206)           (43)           (5)
                                                        -----------     ---------     ----------     ---------
  Fair value of plan assets at end of year...........   $     6,820     $   3,959     $       --     $      --
                                                        ===========     =========     ==========     =========

RECONCILIATION OF FUNDED STATUS
  Funded status......................................   $      (758)    $     173     $   (2,001)    $  (1,781)
  Unrecognized prior service cost....................            47            54          1,255         1,381
  Unrecognized actuarial loss........................         1,255            68             58            57
                                                        -----------     ---------     ----------     ---------
  Net amount recognized..............................   $       544     $     295     $     (688)    $    (343)
                                                        ===========     =========     ==========     =========


- -----------------------
(1)      The TEPPCO OPB became effective on January 1, 2001.


OTHER PLANS

         DEFS also sponsors an employee savings plan, which covers substantially
all employees. Plan contributions on behalf of the Company of $2.8 million, $3.1
million and $2.2 million were expensed during the years ended December 31, 2002,
2001 and 2000, respectively.


NOTE 17. COMMITMENTS AND CONTINGENCIES

         In the fall of 1999 and on December 1, 2000, the General Partner and
the Partnership were named as defendants in two separate lawsuits in Jackson
County Circuit Court, Jackson County, Indiana, styled Ryan E. McCleery and
Marcia S. McCleery, et. al. v. Texas Eastern Corporation, et. al. (including the
General Partner and Partnership) and Gilbert Richards and Jean Richards v. Texas
Eastern Corporation, et. al. (including the General Partner and Partnership). In
both cases, the plaintiffs contend, among other things, that we and other
defendants stored and disposed of toxic and hazardous substances and hazardous
wastes in a manner that caused the materials to be released into the air, soil
and water. They further contend that the release caused damages to the
plaintiffs. In



                                      F-33




                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

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

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

         On April 19, 2002, we, through our subsidiary TEPPCO Crude Oil, L.P.,
filed a declaratory judgment action in the U.S. District Court for the Western
District of Oklahoma against D.R.D. Environmental Services, Inc. ("D.R.D.")
seeking resolution of billing and other contractual disputes regarding potential
overcharges for environmental remediation services provided by D.R.D. On May 28,
2002, D.R.D. filed a counterclaim for alleged breach of contract in the amount
of $2,243,525, and for unspecified damages for alleged tortious interference
with D.R.D.'s contractual relations with DEFS. We have denied the counterclaims.
Discovery is ongoing. If D.R.D. should be successful, management believes that a
substantial portion of the $2,243,525 breach of contract claim will be covered
under an indemnity from DEFS. We cannot predict the outcome of the litigation
against us; however, we are defending ourselves vigorously against the
counterclaim. We do not believe that the outcome of this lawsuit will have a
material adverse effect on our financial position, results of operations or cash
flows.

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

         In February 2002, a producer on the Jonah system sent a letter to
Alberta Energy Company implying that as a result of our acquisition of the Jonah
system, it may have a right to acquire all or a portion of the assets comprising
the Jonah system pursuant to an alleged right of first refusal in a gas
gathering agreement between the producer and Jonah. Subsidiaries of Alberta
Energy Company have agreed to indemnify us against losses resulting from any
breach of representations concerning the absence of third party rights in
connection with our acquisition of the entity that owns the Jonah system. We
believe that we have adequate legal defenses if the producer should assert a
claim, and we also believe that no right of first refusal on any of the
underlying Jonah system assets has been triggered.

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



                                      F-34




                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

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

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

         At December 31, 2002, we have an accrued liability of $5.6 million and
a receivable of $4.2 million from DEFS related to various TCTM sites requiring
environmental remediation activities. The receivable is based on a contractual
indemnity obligation we received in connection with our acquisition of assets
from a DEFS affiliate in November 1998. The indemnity relates to future
environmental remediation activities attributable to operations of these assets
prior to our acquisition. Under this indemnity obligation, we are responsible
for the first $3.0 million in specified environmental liabilities, and DEFS is
responsible for those environmental liabilities in excess of $3.0 million, up to
a maximum amount of $25.0 million. The majority of the receivable from DEFS
relates to remediation activities at the Velma crude oil site in Stephens
County, Oklahoma. The accrued liability balance at December 31, 2002, also
includes an accrual of $2.3 million related to the Shelby crude oil site in
Stephens County, Oklahoma. At December 31, 2002, it is uncertain if these costs
related to Shelby are covered under the indemnity obligation from DEFS. We are
currently in discussions with DEFS regarding these matters. We do not expect
that the completion of remediation programs associated with TCTM activities will
have a future material adverse effect on our financial position, results of
operations or cash flows.

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

         In February 2000, we entered into a joint marketing and development
alliance with Louis Dreyfus Plastics Corporation, now known as Louis Dreyfus
Energy Services, L.P. ("Louis Dreyfus"), in which our Mont Belvieu LPGs storage
and transportation shuttle system services were jointly marketed by Louis
Dreyfus and TE Products. The purpose of the alliance was to expand services to
the upper Texas Gulf Coast energy marketplace by increasing pipeline throughput
and the mix of products handled through the existing system and establishing new
receipt and delivery connections. The alliance was a service-oriented, fee-based
venture with no commodity trading activity. TE Products operated the facilities
for the alliance. Under the alliance, Louis Dreyfus invested $6.1 million for
expansion projects at Mont Belvieu. The alliance also stipulated that if certain
earnings thresholds were achieved, a



                                      F-35




                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

partnership between TE Products and Louis Dreyfus was to be created effective
January 1, 2003. All terms and earnings thresholds have been met; therefore, we
will be contributing our Mont Belvieu assets to the newly formed partnership.
The economic terms of the partnership are the same as those under the joint
development and marketing alliance. TE Products will continue to operate the
facilities for the partnership. The net book value of the Mont Belvieu assets
that we are contributing to the partnership is approximately $68.2 million. Our
interest in the partnership will be accounted for as an equity investment.

         Rates of interstate refined petroleum products and crude oil pipeline
companies, like us, are currently regulated by the FERC primarily through an
index methodology, which allows a pipeline to change its rates based on the
change from year to year in the Producer Price Index for finished goods ("PPI
Index"). Effective as of February 24, 2003, FERC Order on Remand modified the
PPI Index from PPI - 1% to PPI. In the alternative, interstate refined petroleum
products and crude oil pipeline companies may elect to support rate filings by
using a cost-of-service methodology, competitive market showings ("Market-Based
Rates") or agreements between shippers and refined petroleum products and crude
oil pipeline companies 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, and Arcadia and
Shreveport-Arcadia, Louisiana, destination markets, which are currently subject
to the PPI Index. As a result, we made refunds of approximately $1.0 million in
the third quarter of 2001 for those destination markets.

         Substantially all of the petroleum products that we transport and store
are owned by our customers. At December 31, 2002, TCTM and TE Products had
approximately 2.7 million barrels and 17.4 million barrels, respectively, of
products in their custody that was owned by customers. We are obligated for the
transportation, storage and delivery of such products on behalf of our
customers. We maintain insurance adequate to cover product losses through
circumstances beyond our control.


NOTE 18. SEGMENT DATA

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

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

         Our Downstream Segment includes the interstate transportation, storage
and terminaling of petroleum products and LPGs and intrastate transportation of
petrochemicals. Revenues are earned from transportation and



                                      F-36




                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

storage of refined products and LPGs, storage and short-haul shuttle
transportation of LPGs at the Mont Belvieu complex, intrastate transportation of
petrochemicals, sale of product inventory and other ancillary services. Our
Downstream Segment's pipeline system extends from southeast Texas through the
central and midwestern United States to the northeastern United States, and is
one of the largest pipeline common carriers of refined petroleum products and
LPGs in the United States. Our Downstream Segment also includes our equity
investment in Centennial.

         Our Upstream Segment includes the gathering, transportation, marketing
and storage of crude oil and distribution of lubrication oils and specialty
chemicals, principally in Oklahoma, Texas and the Rocky Mountain region. Our
Upstream Segment also includes the equity earnings from our investment in
Seaway. Seaway is a large diameter pipeline that transports crude oil from the
U.S. Gulf Coast to Cushing, Oklahoma, a central crude oil distribution point for
the Central United States.

         Our Midstream Segment includes the fractionation of NGLs in Colorado;
the ownership and operation of two trunkline NGL pipelines in South Texas and
two NGL pipelines in East Texas; and the gathering of natural gas in the Green
River Basin in southwestern Wyoming, through Jonah, which was acquired by our
subsidiaries on September 30, 2001. This segment also includes Chaparral, which
we acquired on March 1, 2002. Chaparral is an NGL pipeline system that extends
from West Texas and New Mexico to Mont Belvieu. The pipeline delivers NGLs to
fractionators and to our existing storage in Mont Belvieu. On June 30, 2002, we
acquired the Val Verde system, which gathers CBM from the Fruitland Coal
Formation of the San Juan Basin in New Mexico and Colorado, and is one of the
largest CBM gathering and treating facilities in the United States. The results
of operations of the Jonah, Chaparral, and Val Verde acquisitions are included
in periods subsequent to September 30, 2001, March 1, 2002, and June 30, 2002,
respectively (See Note 5. Acquisitions).

         The tables below include financial information by reporting segment for
the years ended December 31, 2002, 2001 and 2000 (in thousands):.



                                                             YEAR ENDED DECEMBER 31, 2002
                                ---------------------------------------------------------------------------------------
                                DOWNSTREAM      UPSTREAM      MIDSTREAM      SEGMENTS     PARTNERSHIP
                                 SEGMENT        SEGMENT        SEGMENT        TOTAL        AND OTHER      CONSOLIDATED
                                ----------    -----------    ----------    -----------    -----------    --------------
                                                                                       
Revenues......................  $  243,538    $ 2,861,700    $  138,922    $ 3,244,160    $    (1,997)   $    3,242,163
Operating expenses,
   including power............     130,324      2,824,106        33,451      2,987,881         (1,997)        2,985,884
Depreciation and
   amortization expense.......      30,116         11,186        44,730         86,032             --            86,032
                                ----------    -----------    ----------    -----------    -----------    --------------
   Operating income...........      83,098         26,408        60,741        170,247             --           170,247
Equity earnings...............      (6,815)        18,795            --         11,980             --            11,980
Other income, net.............         832          1,532           269          2,633           (806)            1,827
                                ----------    -----------    ----------    -----------    -----------    --------------
   Earnings before interest...  $   77,115    $    46,735    $   61,010    $   184,860    $      (806)   $      184,054
                                ==========    ===========    ==========    ===========    ===========    ==============




                                      F-37




                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)




                                                             YEAR ENDED DECEMBER 31, 2001
                                  ------------------------------------------------------------------------------------------
                                  DOWNSTREAM       UPSTREAM      MIDSTREAM      SEGMENTS       PARTNERSHIP
                                    SEGMENT         SEGMENT       SEGMENT         TOTAL         AND OTHER       CONSOLIDATED
                                  -----------     -----------    ----------    -------------   ------------     ------------
                                                                                             
Revenues .....................    $   264,233     $ 3,255,260    $   37,242     $  3,556,735   $       (322)    $  3,556,413
Operating expenses,
   including power ...........        119,858       3,227,705        11,482        3,359,045           (322)       3,358,723
Depreciation and
   amortization expense ......         26,699           9,263         9,937           45,099             --           45,899
                                  -----------     -----------    ----------     ------------   ------------     ------------
   Operating income ..........        117,676          18,292        15,823          151,791             --          151,791
Equity earnings ..............         (1,149)         18,547            --           17,398             --           17,398
Other income, net ............          1,537           1,188            74            2,799             --            2,799
                                  -----------     -----------    ----------     ------------   ------------     ------------
   Earnings before interest...    $   118,064     $    38,027    $   15,897     $    171,988   $         --     $    171,988
                                  ===========     ===========    ==========     ============   ============     ============


                                                             YEAR ENDED DECEMBER 31, 2000
                                  --------------------------------------------------------- --------------------------------
                                  DOWNSTREAM       UPSTREAM      MIDSTREAM      SEGMENTS       PARTNERSHIP
                                    SEGMENT         SEGMENT       SEGMENT         TOTAL         AND OTHER       CONSOLIDATED
                                  -----------     -----------    ----------     ------------   ------------     ------------
                                                                                              
Revenues......................    $   229,234     $ 2,844,245    $   14,462     $  3,087,941   $         --     $  3,087,941
Operating expenses,
   including power............        118,065       2,823,304         2,423        2,943,792             --        2,943,792
Depreciation and
   amortization expense.......         25,728           6,282         3,153           35,163             --           35,163
                                  -----------     -----------    ----------     ------------   ------------     ------------
   Operating income...........         85,441          14,659         8,886          108,986             --          108,986
Equity earnings...............             --          12,214            --           12,214             --           12,214
Other income, net.............          1,651            (500)          237            1,388             --            1,388
                                  -----------     -----------    ----------     ------------   ------------     ------------
   Earnings before interest...    $    87,092     $    26,373    $    9,123     $    122,588   $         --     $    122,588
                                  ===========     ===========    ==========     ============   ============     ============


         The following table provides the total assets for each segment as of
December 31, 2002, 2001 and 2000 (in thousands):



                                DOWNSTREAM     UPSTREAM     MIDSTREAM        SEGMENTS     PARTNERSHIP
                                 SEGMENT       SEGMENT       SEGMENT          TOTAL        AND OTHER      CONSOLIDATED
                               -----------   -----------   ------------    ------------   -----------    --------------
                                                                                       
2002.......................    $  883,450    $            $  1,174,010     $  2,782,320   $  (11,678)    $  2,770.672

2001.......................       844,036                      541,195        2,080,165      (14,817)       2,065,348

2000.......................       714,233                      156,662        1,623,476         (666)       1,622,810


         The following table reconciles the segments total to consolidated net
income (in thousands):



                                                                        YEARS ENDED DECEMBER 31,
                                                              ---------------------------------------------
                                                                  2002            2001             2000
                                                              ------------    ------------     ------------
                                                                                       
  Earnings before interest..................................  $    184,054    $    171,988     $    122,588
  Interest expense..........................................       (70,537)        (66,057)         (48,982)
  Interest capitalized......................................         4,345           4,000            4,559
  Minority interest.........................................            --            (800)            (789)
                                                              ------------    ------------     ------------
      Net income............................................  $    117,862    $    109,131     $     77,376
                                                              ============    ============     ============




                                      F-38




                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

NOTE 19. COMPREHENSIVE INCOME

         SFAS No. 130, Reporting Comprehensive Income requires certain items
such as foreign currency translation adjustments, minimum pension liability
adjustments, and unrealized gains and losses on certain investments to be
reported in a financial statement. As of and for the years ended December 31,
2002 and 2001, the components of comprehensive income were due to the interest
rate swap related to our variable rate revolving credit facility, which is
designated as a cash flow hedge. Changes in the fair value of the cash flow
hedge, to the extent the hedge is effective, are recognized in other
comprehensive income until the hedge interest costs are recognized in earnings.
The table below reconciles reported net income to total comprehensive income for
the years ended December 31, 2002, 2001 and 2000 (in thousands).




                                                                              YEARS ENDED DECEMBER 31,
                                                                      --------------------------------------
                                                                          2002          2001         2000
                                                                      -----------   -----------   ----------
                                                                                         
Net income.........................................................   $   117,862   $   109,131   $   77,376
Cumulative effect attributable to adoption of SFAS 133.............            --       (10,103)          --
Net income (loss) on cash flow hedge...............................           269       (10,221)          --
                                                                      -----------   -----------   ----------
    Total comprehensive income.....................................   $   118,131   $    88,807   $   77,376
                                                                      ===========   ===========   ==========


         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 hedge.....................................                (10,221)
        Balance at December 31, 2001.......................................        $       (20,324)
           Net income on cash flow hedge...................................                    269
                                                                                   ---------------
        Balance at December 31, 2002.......................................        $       (20,055)
                                                                                   ===============


NOTE 20. SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

         In connection with our issuance of Senior Notes on February 20, 2002,
TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream
Companies, L.P. and Jonah Gas Gathering Company, our significant operating
subsidiaries, issued unconditional guarantees of our debt securities. Effective
with the acquisition of the Val Verde assets on June 30, 2002, our subsidiary,
Val Verde Gas Gathering Company, L.P. also became a significant operating
subsidiary and issued unconditional guarantees of our debt securities. The
guarantees are full, unconditional, and joint and several. TE Products Pipeline
Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P.,
Jonah Gas Gathering Company and Val Verde Gas Gathering Company, L.P. are
collectively referred to as the "Guarantor Subsidiaries."

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



                                      F-39

                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)




                                                                                  DECEMBER 31, 2002
                                                      ---------------------------------------------------------------------------
                                                                                                                       TEPPCO
                                                         TEPPCO      GUARANTOR      NON-GUARANTOR   CONSOLIDATING   PARTNERS, L.P.
                                                     PARTNERS, L.P.  SUBSIDIARIES   SUBSIDIARIES    ADJUSTMENTS     CONSOLIDATED
                                                     --------------  ------------   -------------   -------------   -------------
                                                                                        (IN THOUSANDS)
                                                                                                      
Assets
   Current assets ................................     $      241     $   92,798     $  286,379     $    (18,851)     $  360,567
   Property, plant and equipment - net ...........             --      1,128,803        459,021               --       1,587,824
   Equity investments ............................      1,011,935        846,991        211,229       (1,785,450)        284,705
   Intercompany notes receivable .................        986,852             --             --         (986,852)             --
   Intangible assets .............................             --        434,941         30,433               --         465,374
   Other assets ..................................          6,200         31,135         34,837               --          72,172
                                                       ----------     ----------     ----------     ------------      ----------
      Total assets ...............................     $2,005,228     $2,534,668     $1,021,899     $ (2,791,153)     $2,770,642
                                                       ==========     ==========     ==========     ============      ==========
Liabilities and partners' capital
   Current liabilities ...........................     $   30,715     $  123,169     $  272,538     $    (59,639)     $  366,783
   Long-term debt ................................        974,264        403,428             --               --       1,377,692
   Intercompany notes payable ....................             --        508,652        437,411         (946,063)             --
   Other long term liabilities and minority
      interest ...................................          6,523         24,230            209               --          30,962
   Redeemable Class B Units held by related
      party ......................................        103,363             --             --               --         103,363
   Total partners' capital .......................        890,363      1,475,189        311,741       (1,785,451)        891,842
                                                       ----------     ----------     ----------     ------------      ----------
      Total liabilities and partners' capital ....     $2,005,228     $2,534,668     $1,021,899     $ (2,791,153)     $2,770,642
                                                       ==========     ==========     ==========     ============      ==========






                                                                                  DECEMBER 31, 2002
                                                      ---------------------------------------------------------------------------
                                                                                                                       TEPPCO
                                                         TEPPCO       GUARANTOR     NON-GUARANTOR   CONSOLIDATING   PARTNERS, L.P.
                                                     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)              --
   Intangible assets .............................            --         219,525          31,962              --          251,487
   Other assets ..................................         3,853          24,923          33,424          (4,504)          57,696
                                                     -----------     -----------     -----------     -----------      -----------
      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         375,184              --              --          715,842
   Intercompany notes payable ....................            --          45,410         294,801        (340,211)              --
   Other long term liabilities and minority
      interest ...................................            --          22,994             231           8,628           31,853
   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-40



                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)



                                                                     YEAR ENDED DECEMBER 31, 2002
                                            -------------------------------------------------------------------------------
                                                                                                                 TEPPCO
                                               TEPPCO         GUARANTOR      NON-GUARANTOR   CONSOLIDATING   PARTNERS, L.P.
                                            PARTNERS, L.P.   SUBSIDIARIES    SUBSIDIARIES     ADJUSTMENTS     CONSOLIDATED
                                            --------------   ------------    -------------   -------------   -------------
                                                                             (IN THOUSANDS)
                                                                                                 
Operating revenues ....................     $        --      $   336,045      $ 2,908,115     $    (1,997)     $ 3,242,163
Costs and expenses ....................              --          216,552        2,857,361          (1,997)       3,071,916
                                            -----------      -----------      -----------     -----------      -----------
   Operating income ...................              --          119,493           50,754              --          170,247
                                            -----------      -----------      -----------     -----------      -----------
Interest expense - net ................         (51,947)         (40,651)         -26,347          52,753          (66,192)
Equity earnings .......................         117,862           59,428           18,795        (184,105)          11,980
Other income - net ....................          51,947              967            1,666         (52,753)           1,827
                                            -----------      -----------      -----------     -----------      -----------
   Net income .........................     $   117,862      $   139,237      $    44,868     $  (184,105)     $   117,862
                                            ===========      ===========      ===========     ===========      ===========





                                                                     YEAR ENDED DECEMBER 31, 2001
                                            -------------------------------------------------------------------------------
                                                                                                                 TEPPCO
                                               TEPPCO         GUARANTOR      NON-GUARANTOR   CONSOLIDATING   PARTNERS, L.P.
                                            PARTNERS, L.P.   SUBSIDIARIES    SUBSIDIARIES     ADJUSTMENTS     CONSOLIDATED
                                            --------------   ------------    -------------   -------------   -------------
                                                                             (IN THOUSANDS)
                                                                                                 
Operating revenues ....................     $        --      $   273,379      $ 3,283,356      $      (322)     $ 3,556,413
Costs and expenses ....................              --          152,558        3,252,386             (322)       3,404,622
                                            -----------      -----------      -----------      -----------      -----------
   Operating income ...................              --          120,821           30,970               --          151,791
                                            -----------      -----------      -----------      -----------      -----------
Interest expense - net ................         (40,143)         (30,605)         (31,452)          40,143          (62,057)
Equity earnings .......................         109,131           18,178           18,547         (128,458)          17,398
Other income - net ....................          40,143            1,537            1,262          (40,143)           2,799
                                            -----------      -----------      -----------      -----------      -----------
   Income before minority interest ....         109,131          109,931           19,327         (128,458)         109,931
Minority interest .....................              --               --               --             (800)            (800)
                                            -----------      -----------      -----------      -----------      -----------
   Net income .........................     $   109,131      $   109,931      $    19,327      $  (129,258)     $   109,131
                                            ===========      ===========      ===========      ===========      ===========





                                                                     YEAR ENDED DECEMBER 31, 2000
                                            -------------------------------------------------------------------------------
                                                                                                                 TEPPCO
                                               TEPPCO         GUARANTOR      NON-GUARANTOR   CONSOLIDATING   PARTNERS, L.P.
                                            PARTNERS, L.P.   SUBSIDIARIES    SUBSIDIARIES     ADJUSTMENTS     CONSOLIDATED
                                            --------------   ------------    -------------   -------------   -------------
                                                                             (IN THOUSANDS)
                                                                                                 
Operating revenues ....................      $        --      $   229,234      $ 2,858,707      $        --      $ 3,087,941
Costs and expenses ....................               --          143,793        2,835,162               --        2,978,955
                                             -----------      -----------      -----------      -----------      -----------
Operating income ......................               --           85,441           23,545               --          108,986
                                             -----------      -----------      -----------      -----------      -----------
Interest expense - net ................          (17,773)         (27,529)         (16,894)          17,773          (44,423)
Equity earnings .......................           77,376           18,602           12,214          (95,978)          12,214
Other income - net ....................           17,773            1,651             (263)         (17,773)           1,388
                                             -----------      -----------      -----------      -----------      -----------
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
                                             ===========      ===========      ===========      ===========      ===========


                                      F-41


                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)



                                                                            YEAR ENDED DECEMBER 31, 2002
                                                   -------------------------------------------------------------------------------
                                                                                                                        TEPPCO
                                                      TEPPCO         GUARANTOR      NON-GUARANTOR   CONSOLIDATING    PARTNERS, L.P.
                                                   PARTNERS, L.P.   SUBSIDIARIES    SUBSIDIARIES     ADJUSTMENTS     CONSOLIDATED
                                                   --------------   ------------    -------------   -------------    -------------
                                                                                  (IN THOUSANDS)
                                                                                                       
Cash flows from operating activities
  Net income ..................................     $   117,862      $   139,237      $    44,869      $  (184,106)     $   117,862
   Adjustments to reconcile net
    income to net cash provided by
    operating activities:
      Depreciation and amortization ..........              --           66,175           19,857               --           86,032
      Earnings in equity investments,
        net of distributions .................          33,994           (2,496)          11,586          (24,683)          18,401
      Changes in assets and liabilities
        and other ............................        (269,102)          48,638           40,253          192,833           12,622
                                                   -----------      -----------      -----------      -----------      -----------
Net cash provided by operating activities ....        (117,246)         251,554          116,565          (15,956)         234,917
                                                   -----------      -----------      -----------      -----------      -----------
Cash flows from investing activities .........        (378,039)      (1,150,967)        (253,879)       1,058,170         (724,715)
Cash flows from financing activities .........         495,285          904,006          138,210       (1,042,214)         495,287
                                                   -----------      -----------      -----------      -----------      -----------
Net increase (decrease) in cash and
   cash equivalents ..........................              --            4,593              896               --            5,489
Cash and cash equivalents at  beginning
   of period .................................              --            3,654           21,825               --           25,479
                                                   -----------      -----------      -----------      -----------      -----------
Cash and cash equivalents at end
   of period .................................     $        --      $     8,247      $    22,721      $        --      $    30,968
                                                   ===========      ===========      ===========      ===========      ===========




                                                                             YEAR ENDED DECEMBER 31, 2001
                                                   -------------------------------------------------------------------------------
                                                                                                                        TEPPCO
                                                      TEPPCO         GUARANTOR      NON-GUARANTOR   CONSOLIDATING    PARTNERS, L.P.
                                                   PARTNERS, L.P.   SUBSIDIARIES    SUBSIDIARIES     ADJUSTMENTS      CONSOLIDATED
                                                   --------------   ------------    -------------   -------------    -------------
                                                                                 (IN THOUSANDS)
                                                                                                         
Cash flows from operating activities
  Net income .................................     $   109,131      $   109,931      $    19,327      $  (129,258)     $   109,131
    Adjustments to reconcile net
    income to net cash provided by
    operating activities:
      Depreciation and amortization ..........              --           31,226           14,673               --           45,899
      Earnings in equity investments,
       net of distributions ..................          (5,219)          10,131           13,417           (3,952)          14,377
      Changes in assets and liabilities
       and other .............................           2,874           16,850          (20,783)             800             (259)
                                                   -----------      -----------      -----------      -----------      -----------
Net cash provided by operating activities ....         106,786          168,138           26,634         (132,410)         169,148
                                                   -----------      -----------      -----------      -----------      -----------
Cash flows from investing activities .........        (498,711)        (514,178)         (43,687)         498,711         (557,865)
Cash flows from financing activities .........         391,925          340,529           20,947         (366,301)         387,100
                                                   -----------      -----------      -----------      -----------      -----------
Net increase (decrease) in cash and
   cash equivalents ..........................              --           (5,511)           3,894               --           (1,617)
Cash and cash equivalents at beginning
   of period .................................              --            9,166           17,930               --           27,096
                                                   -----------      -----------      -----------      -----------      -----------
Cash and cash equivalents at end
   of period .................................     $        --      $     3,655      $    21,824      $        --      $    25,479
                                                   ===========      ===========      ===========      ===========      ===========



                                      F-42


                              TEPPCO PARTNERS, L.P.

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)



                                                                         YEAR ENDED DECEMBER 31, 2000
                                                   -------------------------------------------------------------------------------
                                                                                                                        TEPPCO
                                                      TEPPCO         GUARANTOR      NON-GUARANTOR   CONSOLIDATING    PARTNERS, L.P.
                                                   PARTNERS, L.P.   SUBSIDIARIES    SUBSIDIARIES     ADJUSTMENTS      CONSOLIDATED
                                                   --------------   ------------    -------------   -------------    -------------
                                                                                 (IN THOUSANDS)
                                                                                                         
Cash flows from operating activities
  Net income .................................     $    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
      Earnings in equity investments,
       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
                                                   ===========      ===========      ===========      ===========      ===========



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




                                                 FIRST          SECOND         THIRD         FOURTH
                                                QUARTER        QUARTER        QUARTER       QUARTER
                                              ----------     ----------     ----------     ----------
                                                         (IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
                                                                               
2002 (2)
Operating revenues ......................     $  631,137     $  888,329     $  880,804     $  841,893
Operating income ........................         37,586         37,356         47,087         48,218
Net income ..............................         26,808         24,377         32,093         34,584

Basic and Diluted income per Limited ....     $     0.46     $     0.39     $     0.48     $     0.46
      Partner and Class B Unit (2)

2001 (3)
Operating revenues ......................     $  785,235     $1,073,682     $  990,816     $  706,680
Operating income ........................         36,465         53,247         27,352         34,727
Net income ..............................         25,735         43,038         19,092         21,266
Basic income per Limited ................     $     0.55     $     0.90     $     0.35     $     0.40
Partner and Class B Unit (3)
Diluted income per Limited ..............     $     0.55     $     0.89     $     0.35     $     0.40
      Partner and Class B Unit (3)



- ---------

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

   (2)   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.


                                      F-43



                              TEPPCO PARTNERS, L.P.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)

     (3) Per Unit calculation includes 1,920,000 Limited Partner Units issued in
         March 2002, 3,175,000 Limited Partner Units issued in July and August
         2002, 4,370,000 Limited Partner Units issued in September 2002,
         3,300,000 Limited Partner Units issued in November 2002, 495,000<<
         Limited Partner Units issued in December 2002, and 99,597 Limited
         Partner Units issued through the exercise of Unit options in 2002.


NOTE 22. SUBSEQUENT EVENTS

         On January 30, 2003, we received $197.3 million in net proceeds, after
underwriting discount, from the issuance of $200.0 million principal amount of
6.125% Senior Notes due 2013. The 6.125% Senior Notes were issued at a discount
of $1.4 million and will be accreted to their face value over the term of the
notes. We used $182.0 million of the proceeds from the offering to reduce the
outstanding principal on the Three Year Facility to $250.0 million. The balance
of the proceeds of $15.3 million was used for general purposes. The Senior Notes
may be redeemed at any time at our option with the payment of accrued interest
and a make-whole premium determined by discounting remaining interest and
principal payments using a discount rate equal to the rate of the United States
Treasury securities of comparable remaining maturity plus 35 basis points. The
indenture governing our 6.125% Senior Notes contains covenants, including, but
not limited to, covenants limiting the creation of liens securing indebtedness
and sale and leaseback transactions. However, the indenture does not limit our
ability to incur additional indebtedness. Our Guarantor Subsidiaries issued
unconditional guarantees of these Senior Notes (see Note 20. Supplemental
Condensed Consolidating Financial Information).

         In January 2003, TE Products entered into a pipeline capacity lease
agreement with Centennial for a period of five years. On February 10, 2003, TE
Products acquired an additional interest in Centennial from PEPL for $20.0
million, increasing its percentage ownership in Centennial to 50%. Upon closing
of the acquisition, TE Products and Marathon each own a 50% ownership interest
in Centennial. In connection with the acquisition of the additional interest in
Centennial, the guaranty agreement between TE Products, Marathon and PEPL was
terminated. TE Products' guaranty of up to a maximum of $75.0 million of
Centennial's debt remains in effect.



                                      F-44




        INDEPENDENT AUDITORS' REPORT ON CONSOLIDATED FINANCIAL STATEMENT
                                    SCHEDULE

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

         Under date of January 22, 2003, except as to note 22 which is as of
February 10, 2003, we reported on the consolidated balance sheets of TEPPCO
Partners, L.P. as of December 31, 2002 and 2001, 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, 2002. In connection with our audits of
the aforementioned consolidated financial statements, we also audited the
related consolidated financial statement schedule. This consolidated financial
statement schedule is the responsibility of the Partnership's management. Our
responsibility is to express an opinion on the consolidated financial statement
schedule based on our audits.

         In our opinion, the consolidated financial statement schedule, when
considered in relation to the basic consolidated financial statements taken as a
whole, presents fairly, in all material respects, the information set forth
therein.


                                                                        KPMG LLP

Houston, Texas
January 22, 2003



                                      S-1




                                   SCHEDULE II
                              TEPPCO PARTNERS, L.P.
                 VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
              FOR THE YEARS ENDED DECEMBER 31, 2000, 2001 AND 2002
                                 (IN THOUSANDS)




                                                    BALANCE AT     ADDITIONS      CHARGED TO
                                                   BEGINNING OF    RELATED TO      COSTS AND     DEDUCTIONS AND     BALANCE AT
                                                    OF PERIOD     ACQUISITIONS      EXPENSES         OTHER        END OF PERIOD
                                                   ------------   -------------   ------------   --------------   -------------
                                                                                                   
ENVIRONMENTAL RESERVE:

Year Ended December 31, 2000....................   $   (5,089)    $      --       $    (497)      $   1,938        $   (3,648)

Year Ended December 31, 2001....................       (3,648)         (300)         (8,691)          6,205            (6,434)

Year Ended December 31, 2002....................       (6,434)           --          (5,785)          4,526            (7,693)


ALLOWANCE FOR DOUBTFUL ACCOUNTS:

Year Ended December 31, 2000....................   $       --     $      --       $      --       $      --        $       --

Year Ended December 31, 2001....................           --            --          (4,422)             --            (4,422)

Year Ended December 31, 2002....................       (4,422)           --            (325)            139            (4,608)




                                      S-2