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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Form 10-K

Commission file number 0-31095

Duke Energy Field Services, LLC

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

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

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

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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.

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	•		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.

     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.

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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 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.

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     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:

     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)

     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)

     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.

     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.

     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.

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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.

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     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).

     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.