UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Form 10-K

or

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, 2004, 69.7% of the registrant’s outstanding member interests is beneficially owned by Duke Energy Corporation and 30.3% is beneficially owned by ConocoPhillips. The aggregate market value of the voting and non-voting member interests held by non-affiliates of the registrant computed by reference to the price at which the member interests were last sold, or the average bid and asked price for such member interests, as of the last business day of the registrant’s most recently completed fiscal quarter was $0.

Documents incorporated by reference:
None

Table of Contents

DUKE ENERGY FIELD SERVICES, LLC
FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2003

TABLE OF CONTENTS

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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;
•		general economic conditions, including any potential effects arising from terrorist attacks and any consequential hostilities or other hostilities; and
•		The effect of accounting pronouncements issued periodically by accounting standard-setting bodies.

     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 2500, 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 (“NGLs 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 2003:

•		we handled an average of approximately 7.7 trillion British thermal units (“Btus”) per day of raw natural gas;
•		we produced an average of approximately 365,000 barrels per day of NGLs;
•		we marketed and traded an average of approximately 575,000 barrels per day of NGLs; and
•		we marketed an average of approximately 3.0 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, 2003, our gathering systems consisted of approximately 58,000 miles of gathering and transmission pipe, with approximately 34,000 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 56 owned and operated plants and at 10 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 individual components. We fractionate NGL raw mix at our 10 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 ChevronPhillips under an existing contract which expires January 1, 2015. 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, Marketing and Trading” 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 6.0 billion cubic foot natural gas storage facility.

     We own 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.

     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 18, “Business Segments,” of the Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplemental Data.

Our Business Strategy

     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:

•		Leverage the 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 market presence and asset base generally provide us opportunities to use our economies of scale to be a 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.
•		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.
•		Further streamline our cost structure. 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 and ensuring reliability in our plant operations.

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Natural Gas Gathering, Processing, Transportation, Marketing and Storage

Overview

     At December 31, 2003, our raw natural gas gathering and processing operations consisted of:

•		approximately 58,000 miles of gathering and transmission pipe, with connections to approximately 34,000 active receipt points; and
•		56 owned and operated processing plants and ownership interests in 10 additional third party operated plants, with a combined processing capacity of approximately 7.9 billion cubic feet per day.

     In 2003, we gathered, processed and/or transported approximately 7.7 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 1,300 additional receipt points in 2003.

     Our raw natural gas gathering and processing operations are located in 10 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. According to Hart Downstream Energy Services “Gas Processors Report” dated November 17, 2003, we are the largest NGL producer in North America.

     Raw Natural Gas Supply Arrangements. We take ownership, control or custody of raw natural gas primarily 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 purchase commitments of 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, BP, Devon, and Dominion, which together account for approximately 15% 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.

     We believe our asset base and scope of our operations provide us with opportunities to add released raw natural gas to our systems. In addition, we have unused processing capacity in the Offshore Gulf of Mexico and Rocky Mountain regions, which contain 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 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

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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 6.1 trillion Btus per day of raw natural gas and produced an average of 365,000 barrels per day of NGLs during 2003.

     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 asset based 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.

     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.

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, 2003.

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(1)

Note that while capacity is measured volumetrically (in cubic feet), inlet volumes are measured using heating value (in British thermal units).

(2)

Excludes inlet volumes of about 290 BBtu/d net for plants operated by others.

(3)

MMcf/d: million cubic feet per day; BBtu/d: billion British thermal units per day; Bbls/d: barrels per day.

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

     Regional Strategies. Continued raw natural gas supply is key to our success. Maintaining our raw natural gas supply enables us to maintain throughput volumes and asset utilization throughout our entire midstream natural gas value chain. We evaluate the nature of the opportunity that a particular region presents, including 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 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 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, 15 natural gas processing plants in this region. In addition, we own a minority interest in one natural gas processing plant that is operated by a third party. Our natural gas processing plants are strategically located to access Permian Basin production. Our plants have processing capacity net to our interest of 1.3 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. Two 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 2003, these plants operated at an overall 84% capacity utilization rate.

     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 and improve reliability.

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     Our key suppliers in this region include ExxonMobil, Occidental, Anadarko, ConocoPhillips, Dominion, ChevronTexaco, and Yates. Our principal competitors in this region include Dynegy, Sid Richardson, ConocoPhillips, Western Gas, BP, El Paso, Marathon and ChevronTexaco.

     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 12 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 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 2003, our plants operated at an overall 81% capacity utilization rate.

     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 dedicated acreage 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, ExxonMobil, Gungoll, Newfield, OXY USA, Dominion, EOG, Marathon, Chesapeake, Apache and Anadarko. Our principal competitors in this region include Oneok, Cantera, Mustang, Western Gas, Enogex., Regency, 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 five natural gas processing plants in this region. Our plants have processing capacity net to our interest of 1.1 billion cubic feet of raw natural gas per day. During 2003, these plants operated at an overall 72% capacity utilization rate.

     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 in 2003 produced approximately 33,000 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 and American Central. The complex is adjacent to our Carthage Hub, which delivers residue gas to interconnects with 11 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 gathered and processed or gathered and transported approximately 390 billion Btus per day in 2003. 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 five interstate pipelines at or near the Perryville Hub.

     Our key suppliers in this region include Anadarko, Devon and ConocoPhillips. Our principal competitors in this region include Gulf South, Regency 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 a third party. Our plants have processing capacity net to our interest of 1.1 billion cubic feet of raw natural gas per day. During 2003, the plants in this region ran at an overall 68% capacity utilization rate.

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     Our Spindletop natural gas storage facility is located near Beaumont, Texas and has current working natural gas capacity of 6.0 billion cubic feet, plus expansion potential of up to an additional 11.5 billion cubic feet. We have numerous firm and interruptible services available including daily services, 30-day services and service contracts for up to 10 years. This high deliverability storage facility interconnects with 9 interstate and intrastate pipelines and is positioned to meet the continuing changing gas demand market including 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, Dominion, Bass Enterprises and El Paso. Our principal competitors in this region include Gulfterra, Kinder Morgan, Crosstex and Houston Pipe Line.

     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 2003, 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, BP, Kerr-McGee and Anadarko. Our principal competitors in this region include Kerr-McGee, Williams and Western Gas.

     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 third parties. The plants have processing capacity net to our interest of 1.3 billion cubic feet of raw natural gas per day. During 2003, our plants in this region operated at an overall 44% 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 offshore gathering and transmission systems. 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 ChevronTexaco’s Cypress terminal.

     On May 31, 2002, we acquired 33.3% of the outstanding membership interests in Discovery Producer Services, LLC (“Discovery”). The Discovery assets, which were primarily constructed in 1997, extend from deepwater offshore Louisiana to onshore delivery points approximately 30 miles south of New Orleans. Discovery 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.

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     Our key suppliers in the Offshore Gulf of Mexico region include El Paso, ExxonMobil, Dominion and ENI. Our principal competitors in this region include BP, Shell, Williams and Gulfterra.

     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 plains and foothills area of Alberta. In total, the facilities in this region have processing capacity net to our interest of 570 million cubic feet of raw sour natural gas per day. During 2003, our processing plants in this area operated at an overall 66% capacity utilization rate. Most of 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 operations in Canada are subject to risks inherent in transactions involving foreign currencies.

     Our key suppliers in this region include Burlington, Canadian Natural Resources, EnCana and Devon. Our principal competitors in the area include Keyspan, Taylor, Enerpro and Altagas.

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 2003, we marketed and traded approximately 575,000 barrels per day of NGLs, of which approximately 64% was production for our own account.

     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. Marketing propane from these rail terminals, along with volume from TEPPCO’s Providence, Rhode Island import facility, accounts for approximately 27,000 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 10 owned and operated fractionators and four fractionators operated by others, including two at the Mont Belvieu market center, and 13 pipeline systems. Our current total fractionation capacity is approximately 166,000 barrels per day.

Strategy

     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 10 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.

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     Transportation. We use company owned NGL pipelines to transport approximately 43,000 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.

     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. Our largest sales customers are ChevronPhillips, ConocoPhillips, Dow Hydrocarbons and Formosa Plastics which accounted for approximately 24%, 18%, 5%, and 4%, respectively, of our total NGL transportation, fractionation and marketing revenues in 2003. Our principal competitors in the marketing of NGLs are Enterprise Products, Koch, Dynegy and Louis Dreyfus. In 2003, we marketed and traded an average of approximately 575,000 barrels per day.

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 4,600 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 also 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”), which owns and operates an interstate refined petroleum products pipeline extending from the upper Texas Gulf Coast to central Illinois. Marathon Ashland Petroleum LLC owns the other 50% interest. At December 31, 2003, TEPPCO’s Downstream Segment also owns a 50% interest in Mont Belvieu Storage Partners, L.P. (“MB Storage”), which serves the fractionation, refining and petroleum industries, providing substantial capacity and flexibility for the transportation, terminaling and storage of NGLs, liquefied petroleum gases and refined products. Louis Dreyfus owns the other 50% interest.

     TEPPCO’s Upstream Segment owns and operates approximately 3,650 miles of crude oil trunk line and gathering pipelines, primarily in Oklahoma, New Mexico, Texas and the Rocky Mountain region. It also owns a 50% interest in Seaway Crude Pipeline Company “(Seaway”), which owns an approximately 500 mile, large diameter crude oil pipeline that transports primarily imported

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crude oil from the Texas Gulf Coast to the mid-continent and midwest refining sectors. ConocoPhillips owns the other 50% 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 500 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 480 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 1,000 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 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 and Colorado. 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.

     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 2003 per unit distribution level, the general partner received approximately 27% of the cash distributed by TEPPCO to its partners, which consisted of 25% from the incentive cash distribution and 2% from the general partner interest. During 2003, total cash distributions to the general partner of TEPPCO were $55 million. At TEPPCO’s current per unit distribution level, we expect to receive total cash distributions of approximately $65 million in 2004.

Natural Gas Suppliers

     We purchase substantially all of our raw natural gas from producers under varying term contracts. We take ownership of raw natural gas primarily 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 2003. 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.”

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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;
•		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

     Natural Gas Transportation. We own ten natural gas intrastate pipelines that are subject to state and federal regulation. Seven of these pipelines provide service on behalf of interstate pipelines. Such service is governed by Section 311 of the Natural Gas Policy Act of 1978 and causes such pipelines to be subject to FERC regulation. FERC approves the maximum transportation rate that can be charged and approves other terms and conditions of service when these 7 intrastate pipelines receive gas from or deliver gas to interstate pipelines.

     We are the managing partner of a FERC-regulated-pipeline, Dauphin Island Gathering Partners (“DIGP”), and have a non-operating interest in another FERC-regulated pipeline, Discovery Gas Transmission, LLC (“Discovery”). The rates, terms and conditions of service and pipeline modification on these pipelines are subject to regulation by the FERC under the Natural Gas Act of 1938 (“NGA”). The NGA requires, among other things, that pipeline rates be just and reasonable and non-discriminatory.

     On November 25, 2003, the FERC issued new Standards of Conduct for interstate natural gas pipelines and their energy affiliates (“Standards of Conduct”). Under the Standards of Conduct, interstate pipeline entities cannot share pipeline operating information,

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including daily operating information, future expansion plans and shipper information, with their Energy Affiliates (as defined in the Standards of Conduct). The new Standards of Conduct will apply to us as a result of our ownership interest in DIGP and Discovery because we are considered an “Energy Affiliate” under Order 2004. Energy Affiliate has been broadly defined in the proposed rule to include any affiliate that “buy[s], sell[s] trades or administer[s] natural gas ... in U.S. energy or transmission markets.” Interstate pipelines are required to be in compliance with the rule by June 1, 2004. We do not anticipate any compliance issues with the implementation of the Standards of Conduct.

     Natural Gas Gathering and Processing. The NGA exempts natural gas gathering facilities from FERC jurisdiction. However, certain 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.

     Transportation and Sales of Natural Gas Liquids. We own non-operating interests in two pipelines that transport natural gas liquids (“NGLs”) in interstate commerce. The rates, terms and conditions of service on these pipelines are subject to FERC regulation under the Interstate Commerce Act. The Interstate Commerce Act requires, among other things, that NGL pipeline rates be just and reasonable and non-discriminatory. At this time, FERC allows NGL pipeline rates to be established on a number of bases, including historic cost, historic cost plus an index and market factors. While NGL sales prices are not currently regulated, the ability to sell NGLs and the pricing of such NGLs is often dependent on and affected by access to NGL pipelines and the rates, terms and conditions of such pipelines.

     U.S. Department of Transportation. Some of our natural gas pipelines are subject to regulation by the U.S. Department of Transportation (“DOT”) with respect to 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. The Pipeline Safety Improvement Act of 2002, which was enacted on December 17, 2002, establishes mandatory inspections for all U.S oil and natural gas transmission pipelines and some gathering lines in high-consequence areas within 10 years. The DOT has developed regulations implementing the Pipeline Safety Improvement Act that will require pipeline operators 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. At this time we are unable to estimate the expected cost of complying with these regulations.

     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. In addition to the statutes referenced above, 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. In British Columbia our assets are regulated by the BC Oil and Gas Commission. Our West Doe and Pesh Creek natural gas gathering pipeline, which crosses the Alberta/British Columbia border, falls under the jurisdiction of the National Energy Board of Canada and are 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, 2003, we had approximately 3,575 employees, which includes approximately 1,050 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 in the U.S. which covers approximately 65 of our employees and one collective bargaining agreement in Canada which covers approximately 20 employees. We believe our relations with our employees are good.

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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 15, “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, based on currently known information, 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 2003.

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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. Our LLC Agreement restricts making any distributions except by approval of both members or in an amount sufficient to pay specified tax obligations of our members that arise from their ownership of member interests. In 2003, our board of directors approved a plan to consider the payment of a quarterly dividend to our members. Our board of directors may consider net income, cash flow or any other criteria deemed appropriate for determining the amount of the quarterly dividend to be paid.

     In August 2000, we issued $300 million of preferred member’s 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. On September 9, 2002, we redeemed $100 million, on September 19, 2003, we redeemed $125 million, and on December 31, 2003, we redeemed the remaining $75 million of our preferred members’ interest by paying cash to each of our members (Duke Energy and ConocoPhillips) in proportion to their ownership interests. At December 31, 2003, we have no preferred member’s interests outstanding to Duke Energy and ConocoPhillips.

     Reference is made to Item 12 of this report regarding equity compensation plan information, which is incorporated herein by reference.

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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, 2003, 2002, 2001 and 2000 and for the periods then ended have been derived from the consolidated financial statements of the Company. The selected historical combined financial data as of December 31, 1999 and for the period then ended has 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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(a)

Includes the results of operations of ConocoPhillips’ gas gathering, processing, marketing and NGL business for the nine months ended December 31, 2000. To the extent that it existed at the time, ConocoPhillips’ gas gathering, processing, marketing and NGL business was acquired by the Predecessor Company on March 31, 2000.

(b)

Includes the results of operations of Union Pacific Fuels for the nine months ended December 31, 1999. Union Pacific Fuels was acquired by the Predecessor Company on March 31, 1999.

(c)

Based on index prices from the Mont Belvieu and Conway market hubs that are weighted by our component and location mix for the periods indicated.

(d)

Based on NYMEX prices for the periods indicated.

N/A Not applicable due to change in corporate structure as of March 31, 2000.

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

     The following discussion details the material factors that affected our historical financial condition and results of operations in 2003, 2002 and 2001. 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.

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 2003, approximately 82% of the Company’s operating revenues prior to intersegment revenue elimination and approximately 96% 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 2003, approximately 18% of the Company’s operating revenues prior to intersegment revenue elimination and approximately 4% of the Company’s gross margin were derived from this segment.
•		Intersegment activity is primarily related to the sale of NGLs from the Natural Gas Segment to the NGLs Segment at market based transfer prices.

     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.

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 contracts 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. 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 $0.01 per gallon in the price of NGLs and $0.10 per million Btus in the average price of natural gas would result in changes in annual pre-tax net income of approximately $(18) million and $1 million, respectively. In addition, a decrease of $1 per barrel in the average price of crude oil would result in a change to annual pre-tax net income of approximately $(5) million.

     During the year ended December 31, 2003, approximately 80% of our gross margin was generated by commodity sensitive arrangements and approximately 20% of our gross margin (excluding hedging and including earnings of unconsolidated affiliates) was generated by fee-based arrangements. The commodity exposure is 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, crude oil 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 and throughout 2003, this relationship reverted back toward historical trends.

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     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. Drilling activity increased in 2003 due to higher commodity prices. The average number of active oil and gas rigs drilling in the United States increased to 1,126 at December 31, 2003 from 862 at December 31, 2002. Recent significant increases in natural gas prices could result in continued increased drilling activity in 2004. However, energy market uncertainty could negatively impact the United States 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 a portion of the value of our assets and operations from such price risks. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.” We do not realize the full impact of commodity price changes because some of our sales volumes were previously hedged at prices different than actual market prices. The settlement of these hedge transactions reduced the results of operations by $115 million and $27 million in 2003 and 2002, respectively, and increased the results of operations by $6 million in 2001.

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 types of contracts permit us and the producers to share proportionately in commodity price changes. Under these contracts, we share in both the increases and decreases in natural gas prices and NGL prices. During 2003, approximately 65% of our gross margin (excluding hedging and including equity earnings of unconsolidated affiliates) 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 2003, approximately 20% of our gross margin (excluding hedging and including equity earnings of unconsolidated affiliates) from the Natural Gas Segment was generated from fee-based contracts.
•		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 2003, approximately 5% of our gross margin (excluding hedging and including equity earnings of unconsolidated affiliates) from the Natural Gas Segment was generated from keep-whole and wellhead purchase contracts.
•		In addition, during 2003 approximately 10% of the gross margin (excluding hedging and including equity earnings of unconsolidated affiliates) 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 and capital expenditures. The primary goals of our hedging program include maintaining minimum cash

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flows to fund debt service and dividends, production replacement and maintenance capital projects; and retaining a high percentage of potential upside relating to increases in prices of NGLs

Accounting Adjustments

     Certain prior period amounts have been reclassified in the Consolidated Financial Statements to conform to the current period presentation. Included in the reclassified amounts are increases in both Sales of natural gas and petroleum products and in Purchases of natural gas and petroleum products in the amount of approximately $805 million and $639 million for the years ended December 31, 2002 and 2001, respectively. This reclassification resulted from intersegment trading activities being eliminated twice from the Consolidated Statements of Operations in the years ended December 31, 2002 and 2001. In addition, Accounts receivable — Customers, net and Accounts payable — Trade were increased by $102 million at December 31, 2002 to properly present on a gross basis balances that were previously presented net in the Consolidated Balance Sheet. Management has concluded that these reclassifications are not material to the fair presentation of the Company’s financial statements.

     During 2003, we recorded an $11 million charge ($7 million to Operating and maintenance expense and $4 million to General and administrative expense) to properly account for our vacation accrual in accordance with SFAS No. 43, “Accounting for Compensated Absences”. We recorded this adjustment, which related primarily to prior periods, entirely in 2003. Management has determined that this charge, related to an error correction, is immaterial 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 our financial statements.

     We completed a comprehensive account reconciliation project to review and analyze our balance sheet accounts in 2002. As a result of this account reconciliation project, we recorded approximately $53 million of adjustments that may be related to corrections of accounting errors in prior periods. The $53 million reduced Gross Margin, as defined under “Results of Operations” below, by $33 million, increased costs and expenses by $16 million, increased depreciation by $2 million, increased other costs and expenses by $4 million and reduced interest expense by $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 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 our financial statements.

     See Notes 2 and 20 to the Consolidated Financial Statements included elsewhere in this Form 10-K and Item 9A. Controls and Procedures.

Other Factors That Significantly Affect Our Results

     Our results of operations are impacted by increases and decreases in the volume of raw natural gas that we handle through our systems, 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.

     Our revenues and expenses are significantly dependent on commodity prices such as NGLs and natural gas. Past and current trends in the price changes of these commodities may not be indicative of future trends. In addition, revenues and expenses are impacted by throughput volumes. If negative market conditions persist over time or throughput volumes decline, estimated cash flows over the lives of our assets may not exceed the carrying value of those individual assets, and asset impairments may occur in the future under existing accounting rules. Furthermore, a change in management’s intent about the use of individual assets (held for use vs. held for sale) could also impact an impairment analysis. For the years ended December 31, 2003 and 2002, we recorded asset impairments of approximately $4 million and $8 million, respectively. There were no asset impairments recorded in 2001. At December 31, 2003, the net book value of property, plant and equipment was $4,462 million.

     In 2003, we converted a portion of our keep-whole contracts to percentage-of-proceeds contracts and we converted a portion of our keep-whole contracts to add a minimum fee clause. This had the impact of reducing the Company’s exposure to natural gas prices and reducing the exposure to NGL prices on an unhedged basis.

     Risk management activities have also affected our results of operations. We do not realize the full impact of commodity price changes because some of our sales volumes were previously hedged at prices different than actual market prices. The settlement of

22

these hedge transactions reduced the results of operations by $115 million and $27 million in 2003 and 2002, respectively, and increased the results of operations by $6 million in 2001. See “Item 7A. Quantitative and Qualitative Disclosure About Market Risk.”

Results of Operations

     The following is a discussion of our historical results of operations.

(a)

Gross margin consists of total operating revenues less purchases of natural gas and petroleum products. Gross margin is a non-Generally Accepted Accounting Principles (“GAAP”) measure under the rules of the Securities and Exchange Commission (“SEC”), but is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of product sales and purchases, a key component of our operations. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.

(b)

EBIT consists of net income from continuing operations before cumulative effect of accounting change, net interest expense and income tax expense. EBIT is a non-GAAP measure under the rules of the SEC, but is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of operations without regard to financing methods or capital structure. As an indicator of our operating performance, EBIT should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our EBIT may not be comparable to a similarly titled measure of another company because other entities may not calculate EBIT in the same manner.

2003 compared with 2002

     Operating Revenues — Total operating revenues increased $2,840 million, or 47%, to $8,819 million in 2003 from $5,979 million in 2002. Approximately $2,250 million of this increase was attributable to a $2.17 per MMBtu increase in average natural gas prices and approximately $1,195 million of this increase was attributable to a $0.15 per gallon increase in average NGL prices. Lower throughput and NGL production reduced revenues by approximately $120 million related to natural gas volume and approximately $380 million related to lower NGL production. We did not realize the full impact of the above increase in NGL prices because some of our sales volumes were previously hedged at prices lower than actual market prices. The settlement of these hedge transactions reduced revenues by $115 million and $27 million in 2003 and 2002, respectively. These settlements reduced by $88 million the benefit of the 2003 NGL price increases described above. Other increases were attributable to transportation, storage and processing fees of $25 million which was primarily due to increased fee revenue associated with our Canadian operations, intrastate pipelines and storage.

     Also included in operating revenues was a decrease in trading and marketing net margin of $38 million, of which $32 million was related to the Natural Gas Segment and $6 million was related to the NGLs Segment. The trading and marketing net margin loss of $24 million for 2003 includes $14 million of income related to the NGLs Segment offset by a $38 million loss related to the Natural

23

Gas Segment. The Natural Gas Segment experienced losses of approximately $10 million due to trading activities in 2003. In addition, approximately $25 million of losses in the Natural Gas Segment is attributable to losses on mark-to-market derivatives for which the results of the related physical asset based activity is recognized on an accrual basis and not included in trading and marketing net margin. Prior to the adoption of EITF 02-03 on January 1, 2003, the gains and losses on both the mark-to-market derivatives and the related physical activity were recorded in trading and marketing net margin (see “Accounting Pronouncements” beginning on page 38).

     Purchases of Natural Gas and Petroleum Products - Purchases of natural gas and petroleum products increased $2,592 million, or 52%, to $7,544 million in 2003 from $4,952 million in 2002. The increase was due primarily to increased costs of raw natural gas and natural gas liquids supply of approximately $2,985 million, offset by lower throughput volumes of approximately $440 million. Additional increases of $48 million were related to non-recurring charges during 2002 as discussed below.

     Gross Margin — Gross margin increased $248 million, or 24% to $1,275 million in 2003 from $1,027 million in 2002. This increase was primarily due to the following factors:

•		approximately $290 million (net of hedging) was mainly the result of higher average NGLs and crude oil prices;
•		approximately $40 million not included in the pricing impacts was the result of 2003 elections to reduce levels of keep-whole processing activities from time to time through operational optionality and contract renegotiaion due to lower historical and forecasted processing profit margins; and
•		$48 million related to accounting adjustments in 2002. $25 million relates to a provisions recorded in 2002 ($12 million relating to prior periods) recorded as a result of our completion of our 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, unrecorded liabilities related to imbalances and incorrectly valued imbalances. $23 million relates to charges recorded in 2002 related to completion of our account reconciliation project, including a $6 million write-down for storage inventory. Of the $48 million total of adjustments, $33 million may be related to corrections of accounting errors in prior periods (see “Accounting Adjustments” on page 22).

     The increase in gross margin was offset by the following factors:

•		approximately $130 million was the result of higher average natural gas prices; and
•		$38 million relates to decreased trading and marketing net margin as discussed above.

     Gross margin associated with the Natural Gas Segment increased $249 million, or 26%, to $1,221 million in 2003 from $972 million in 2002, mainly as a result of the following factors:

•		approximately $225 million (net of hedging) was the result of commodity sensitive processing arrangements, mainly due to the increase in average NGLs and crude oil prices along with our election to reduce levels of keep-whole processing activities offset by the increase in average natural gas prices; and
•		$48 million related to accounting adjustments in 2002 as discussed above.

     The increase in gross margin associated with the Natural Gas Segment was offset by $32 million relating to decreased trading and marketing net margin as discussed above.

     Gross margin associated with the NGLs Segment decreased $1 million, or 2% to $54 million in 2003 from $55 million in 2002. This decrease was comprised of a $6 million decrease in trading and marketing net margin offset by increases in the northeast wholesale propane marketing and terminals margin of $2 million and from the operation of a newly constructed pipeline in south Texas of $1 million.

     NGL production during 2003 decreased 24,000 barrels per day, or 6%, to 365,000 barrels per day from 389,000 barrels per day during 2002, and natural gas transported and/or processed during 2003 decreased 0.4 trillion Btus per day, or 5%, to 7.7 trillion Btus per day from 8.1 trillion Btus per day during 2002. The primary cause of the decrease in NGL production was a reduction in keep-whole processing activity during 2003 due to marginally economic processing margins and reduced drilling activity.

     Costs and Expenses — Operating and maintenance expenses increased $17 million, or 4%, to $451 million in 2003 from $434 million in 2002. This increase was primarily due to the following factors:

•		increased facility maintenance and pipeline repair of $10 million;
•		increased environmental compliance of $7 million;
•		accretion expense associated with asset retirement obligations of $3 million related to the implementation of SFAS No.

24

143

in 2003; and

•

a charge from accounting adjustments of $7 million in 2003 offset by a benefit related to accounting adjustments of $11 million in 2002 (see “Accounting Adjustments” on page 22).

     General and administrative expenses increased $17 million, or 10%, to $184 million in 2003 from $167 million in 2002. This increase was primarily due to the following factors:

•		higher bonus and incentive compensation of $19 million; and
•		severance of $6 million in 2003.

     The increase in general and administrative expenses was offset by the following factors:

•		lower corporate overhead of $10 million; and
•		a charge from accounting adjustments of $4 million in 2003 offset by a benefit related to accounting adjustments of $5 million in 2002 (see “Accounting Adjustments” on page 22).

     Depreciation and amortization expenses increased $12 million, or 4%, to $302 million in 2003 from $290 million in 2002. This increase was due primarily to ongoing capital expenditures for well connections and facility maintenance and enhancements, and the depreciation of asset retirement costs that were capitalized in conjunction with the implementation of SFAS No. 143.

     Asset impairments were $4 million in 2003 compared to $8 million in 2002. The impairment in 2003 was related to assets located in Onshore and Offshore Gulf of Mexico. The impairment in 2002 was related to assets located in Offshore Gulf of Mexico and write-off of a leasehold interest. As part of our periodic asset performance evaluations, we determined in December 2003 and 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, 2003 and 2002, we 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, we 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 charges associated with these impairments were recorded in the Natural Gas Segment.

     Net loss (gain) on sale of assets was a loss of $4 million in 2002 related to the loss on sale of assets associated with a partnership investment. This amount relates to accounting corrections (see “Accounting Adjustments” on page 22).

     Equity in Earnings of Unconsolidated Affiliates — Equity in earnings of unconsolidated affiliates increased $11 million, or 29%, to $49 million in 2003 from $38 million in 2002. This increase is primarily the result of increased earnings from our general partnership interest in TEPPCO Partners, L.P. (“TEPPCO”) of $7 million and increased earnings from the 2002 acquisition of an interest in Discovery Producer Services, LLC (“Discovery”) located in Offshore Gulf of Mexico of $6 million.

     Interest Expense, Net — Interest expense increased $4 million, or 2%, to $170 million in 2003 from $166 million in 2002. This increase was primarily the result of the third quarter 2003 implementation of SFAS No. 150 requiring prospective reclassification as interest expense disbursements of $6 million that in previous periods were classified as dividends on our preferred members’ interest.

     Income Tax Expense — The Company is a limited liability company, which is a pass-through entity for U.S. income tax purposes. However, some of its subsidiaries are tax-paying entities. Income tax expense represents federal, state and foreign taxes associated with these entities. Income tax expense decreased $2 million to $8 million in 2003 from $10 million in 2002 due primarily to decreased earnings associated with tax-paying subsidiaries.

     Gain (Loss) From Discontinued Operations - Gain (loss) from discontinued operations was a gain of $32 million in 2003 and a loss of $33 million in 2002. The 2003 gain is primarily the result of the gain on the sale of various natural gas gathering and processing assets (see Note 10 to the Consolidated Financial Statements) and the 2002 loss represents impairment charges associated with the assets sold in 2003.

     Cumulative Effect of Changes in Accounting Principles — Cumulative effect of changes in accounting principles was a loss of $23 million in 2003. Of this amount, $18 million relates to the implementation of SFAS 143, and $5 million is due to the rescission of EITF 98-10 (see Note 2 to Consolidated Financial Statements).

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2002 compared with 2001

     Gross Margin — Gross margin decreased $234 million, or 19% to $1,027 million in 2002 from $1,261 million in 2001. This decrease was primarily due to the following factors:

•

approximately $200 million (including hedging) was the result of a $0.07 per gallon decrease in average NGL prices and volume declines;

•

$48 million related to accounting adjustments in 2002 as discussed above; and

•

$34 million was the result of decreased trading and marketing net margin.

     The decrease in gross margin was offset by approximately $45 million resulting from a $1.05 per million Btu decrease in natural gas prices.

     Gross margin associated with the Natural Gas Segment decreased $233 million, or 19%, to $972 million in 2002 from $1,205 million in 2001, mainly as a result of the following factors:

•

approximately $155 million (net of hedging) was the result of commodity sensitive processing arrangements, mainly due to the decrease in average NGL prices, partially offset by the decrease in average natural gas prices;

•

$25 million was the result of decreased trading and marketing net margin; and

•

$48 million related to accounting adjustments in 2002 as discussed above.

     Gross Margin associated with the NGLs Segment decreased $1 million, or 2% to $55 million in 2002 from $56 million in 2001. A decrease in trading and marketing net margin of $9 million was offset by a $10 million increase related to the 2001 acquisition of northeast propane terminal and marketing assets.

     NGL production during 2002 decreased 5,000 barrels per day, or 1%, to 389,000 barrels per day from 394,000 barrels per day during 2001, and natural gas transported and/or processed during 2002 decreased 0.2 trillion Btus per day, or 2%, to 8.1 trillion Btus per day from 8.3 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 $74 million, or 21%, to $434 million in 2002 from $360 million in 2001. This increase was primarily the due to the following factors:

•

increased maintenance, equipment overhauls and pipeline integrity projects of approximately $33 million;

•

increased labor costs of $7 million;

•

result of the full year impact of acquisitions for approximately $20 million (see Note 3 to the Consolidated Financial Statements); and

•

increases of $14 million due to higher spending levels, including $11 million of accounting adjustments (see “Accounting Adjustments” on page 22).

     General and administrative expenses increased $37 million, or 28%, to $167 million in 2002 from $130 million in 2001. The primary causes of this increase were $11 million for core business process improvements and $5 million of accounting adjustments (see “Accounting Adjustments” on page 22). The remaining increase was related to higher costs of services provided by Duke Energy of approximately $7 million and higher labor and outside services resulting from accounting and technology projects of approximately $9 million.

     Depreciation and amortization expenses increased $43 million (excluding $22 million of goodwill amortization in 2001), or 17%, to $290 million in 2002 from $247 million in 2001. This increase was due primarily to acquisitions, ongoing capital expenditures for well connections and facility maintenance and enhancements.

     Asset impairments were $8 million in 2002. The impairment was related to assets located in Offshore Gulf of Mexico and write-off of a leasehold interest. As part of our periodic asset performance evaluations, we 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, we 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, we 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

26

flow models. The charges associated with these impairments were recorded in the Natural Gas Segment.

     Net loss (gain) on sale of assets changed to a loss of $4 million in 2002 from a gain of $1 million in 2001. The primary reason for the change was the loss on sale of assets associated with a partnership investment of $5 million recorded in 2002. This amount relates to accounting corrections (see “Accounting Adjustments” on page 22).

     Equity in Earnings of Unconsolidated Affiliates — Equity in earnings of unconsolidated affiliates increased $8 million, or 27%, to $38 million in 2002 from $30 million in 2001. This increase is primarily the result of increased earnings from our general partnership interest in TEPPCO of $4 million and increased earnings from the 2002 acquisition of an interest in Discovery of $2 million.

     Interest Expense, Net — Interest expense remained flat at $166 million in 2002 and 2001. The Company had slightly higher debt levels in 2002, offset by lower interest rates and capitalized interest adjustments (see “Accounting Adjustments” on page 22).

     Income Tax Expense — Income tax expense represents federal, state and foreign taxes associated with the Company’s tax-paying subsidiaries. Income tax expense increased $7 million to $10 million in 2002 from $3 million in 2001 due primarily to increased earnings associated with tax-paying subsidiaries obtained through acquisitions in 2001 and prior.

     Gain (Loss) From Discontinued Operations - Gain (loss) from discontinued operations was a loss of $33 million in 2002 which represents impairment charges associated with assets sold in 2003.

Environmental Considerations

     We have various ongoing remedial matters related to historical operations, 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 is 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. We estimate that the aggregate environmental costs that we will expense or capitalize in 2004 and 2005 to maintain compliance with environmental reuglations and laws will be approximately $51 million and $42 million, respectively. In addition, at December 31, 2003, we have liabilities of $21 million recorded for environmental remediation obligations and $45 million recorded for asset retirement obligations.

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 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 and trading 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, 2003, 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 the final consensus reached in EITF Issue 02-03 (“EITF 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 changed which accounting model is used for certain of our transactions, the overall application of the models remains the same. See Note 2 to the Consolidated Financial Statements for further discussion of EITF 02-03.

     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. We apply MTM

27

accounting to our derivatives unless subject to hedge accounting or the normal purchase and normal sale exemption (as described below).

     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 commodity 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, 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 function. 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 normal sales exemption. 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 may be 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 may be used when we hold firm commitments or asset or liability 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 differences that exist in the 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 indicates that no recognition of the contract’s fair value in the consolidated financial statements is required until settlement of the contract. The Company has applied this exemption for contracts involving the purchase or sale of physical natural gas or NGLs in future periods.

     Revenue Recognition — We recognize 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, we receive fees from the producers to transport the natural gas from the wellhead to the processing plant. For processing services, we either receive fees or commodities as payment for these services, depending on the type of contract. Under the percentage-of-proceeds contract type, we are paid for our services by keeping a percentage of the NGLs produced and the residue gas resulting from processing the natural gas. Under a keep-whole contract, we keep a portion of the NGLs produced, but return the equivalent Btu content of the gas back to the producer. We also receive fees for further fractionation of the NGLs produced, and for transportation and storage of NGLs and residue gas.

     We recognize revenue for our NGL and residue gas derivative trading activities net in the Consolidated Statements of Operations as trading and marketing net margin. These activities include mark-to-market gains and losses on energy trading contracts and the financial or physical settlement of energy trading contracts.

     Revenue for goods and services provided but not invoiced is estimated each month and recorded along with related purchases of goods and services used but not invoiced. These estimates are generally based on estimated commodity prices, preliminary throughput measurements and allocations and contract data. Actual invoices for the current month are issued in the following month and differences from estimated amounts are recorded. There are no material differences from the actual amounts invoiced subsequent to year end relating to estimated revenues and purchases recorded at December 31, 2003, 2002 and 2001.

28

     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. 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. In addition, revenues and expenses are impacted by throughput volumes. If negative market conditions persist over time or throughput volumes decline, estimated cash flows over the lives of our assets may not exceed the carrying value of those individual assets, and asset impairments may occur in the future under existing accounting rules. Furthermore, a change in management’s intent about the use of individual assets (held for use vs. held for sale) could also impact an impairment analysis.

     Impairment of Goodwill - We perform an annual goodwill impairment test and update the test if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying amount. We use a discounted cash flow analysis supported by market valuation multiples to perform the assessment. Key assumptions in the analysis included the use of an appropriate discount rate, estimated future cash flows and an estimated run rate of general and administrative costs. In estimating cash flows, we incorporate current market information as well as historical factors and fundamental analysis as well as other factors into its forecasted commodity prices.

     We will continue to remain alert for any indicators that the fair value of a reporting unit could be below book value and assess goodwill for impairment as appropriate, in addition to performing the annual goodwill impairment analysis required by SFAS No. 142.

     Contingencies - We apply SFAS No. 5 (“SFAS 5”), “Accounting for Contingencies,” and related interpretations to determine accounting and disclosure requirements for contingencies. We operate in a highly regulated environment. Governmental bodies such as the FERC, the SEC, the Internal Revenue Service, the Department of Labor, the Environmental Protection Agency and others have purview over various aspects of our business operations and public reporting. Reserves are established when, in management’s judgment, the contingency is probable and able to be reasonably estimated. Disclosures regarding litigation, assessments, and credit worthiness of customers or counterparties, among others, are made when the contingency is not required to be reserved for, but there is a reasonable possibility that a liability will be incurred (see Note 15 to the Consolidated Financial Statements for discussion of various contingencies). The evaluation of these contingencies is performed by internal and external specialists. Accounting for contingencies requires significant judgment by management regarding the estimated probabilities and ranges of exposure to potential liability. Management’s assessment of our exposure to contingencies could change as new developments occur or more information becomes available. The outcome of the contingencies could vary significantly and could materially impact our consolidated results of operations, cash flows and financial position. Management has applied its best judgment in applying SFAS 5 to these matters.

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Liquidity and Capital Resources

     As of December 31, 2003, we had $43 million in cash and cash equivalents compared to $35 million as of December 31, 2002. Current liabilities exceeded current assets by $73 million and $322 million at December 31, 2003 and 2002, respectively. We rely upon cash flows from operations to fund our liquidity and capital requirements. A material adverse change in operations or available financing may impact our ability to fund our current liquidity and capital resource requirements.

     Operating Cash Flows

     During 2003, cash provided by operating activities was $475 million, an increase of $31 million from $444 million during 2002. This increase was due primarily to a $261 million increase in net income, partially offset by changes in working capital balances, unrealized mark-to-market and hedging activity, and non-cash charges. The increase in net income is due largely to higher NGLs and crude oil prices, offset by higher natural gas prices, lower volumes, increased operating expenses and increased general and administrative expenses.

     Volatility in crude oil, NGLs and natural gas prices and the structure of our commodity supply contracts have a direct impact on our generation and use of cash from operations due to its impact on net income as described in the Effects of Commodity Prices section above, along with the resulting changes in working capital.

     Investing Cash Flows

     During 2003, cash used in investing activities was $41 million, a decrease of $196 million from $237 million in 2002. The decrease is partially related to proceeds of $90 million from sales of discontinued operations. 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, 2003, we spent approximately $129 million on acquisition and capital expenditures of continuing operations compared to $297 million in 2002. The decrease is due to reduced plant expansions, well connections and plant upgrades in 2003, as compared to 2002.

     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, asset sales, our credit facility or other available sources of financing. Our capital expenditure forecast for 2004 is approximately $220 million. Depending on cash flow results, redeployment of capital from divestitures and opportunities in the marketplace, 2004 acquisition and capital expenditures may vary from the forecast.

     Investments in unconsolidated affiliates provided $65 million in cash distributions to us during 2003 compared with $54 million in 2002. There were investment expenditures of $85 million in 2003 that were made to repay the underlying debt of an unconsolidated affiliate. The only remaining debt of an unconsolidated affiliate at December 31, 2003 was $3 million that was repaid on January 31, 2004.

     Financing Cash Flows

     Bank Financing and Commercial Paper

     On March 28, 2003, we entered into a credit facility (the “Facility”). The Facility replaces a credit facility that matured on March 28, 2003. The Facility is used to support our commercial paper program and for working capital and other general corporate purposes. The Facility matures on March 26, 2004; however; any outstanding loans under the Facility at maturity may, at our option, be converted to a one-year term loan. The Facility is a $350 million revolving credit facility, of which $100 million can be used for letters of credit. The Facility requires us to maintain at all times a debt to total capitalization ratio of less than or equal to 53%; and maintain at the end of each fiscal quarter an interest coverage ratio (defined to be the ratio of adjusted EBITDA, as defined by the Facility, for the four most recent quarters to interest expense for the same period) of at least 2.5 to 1 (adjusted EBITDA is defined by the Facility to be earnings before interest, taxes and depreciation and amortization and other adjustments); and contains various restrictions applicable to dividends and other payments to our members. The Facility bears interest at a rate equal to, at our option and based on our current debt rating, either (1) LIBOR plus 1.25% per year or (2) the higher of (a) the JP Morgan Chase Bank prime rate plus 0.25% per year and (b) the Federal Funds rate plus 0.75% per year. At December 31, 2003, there were no borrowings or letters of credit drawn against the Facility. By March 26, 2004, we expect to refinance the Facility and replace it with an up to $250 million

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credit facility which will mature on March 25, 2005 and have similar terms as the Facility, with the exception that there will no longer be a restriction applicable to dividends and other payments to our members and we will be able to request letters of credit up to the full committed amount of the new credit facility. This new credit facility has been decreased from the Facility due to reduced liquidity requirements.

     On March 28, 2003, we also entered into a $100 million funded short-term loan with a bank (the “Short-Term Loan”). The Short-Term Loan was used for working capital and other general corporate purposes. The Short-Term Loan contained an original maturity of September 30, 2003, but was repaid by August 2003 with funds generated from asset sales and operations.

     On November 3, 2003, we executed a $32 million irrevocable standby letter of credit expiring on May 15, 2004 to be used to secure transaction exposure with a counterparty.

     At December 31, 2003, we had no outstanding commercial paper. 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.

     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 as supported by the Facility, which is expected to be refinanced, 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. The outstanding preferred member interests are entitled to cumulative preferential distributions of 9.5% per annum payable, unless deferred, semiannually. For the years ending December 31, 2003, 2002 and 2001, we paid preferential distributions of $9 million (represents the first half of 2003), $25 million and $29 million, respectively. On September 9, 2002, we redeemed $100 million, on September 19, 2003, we redeemed $125 million, and on December 31, 2003, we redeemed the remaining $75 million of our preferred members’ interest by paying cash to each member (Duke Energy and ConocoPhillips) in proportion to their ownership interests.

     In May 2003, the FASB issued SFAS No. 150 (“SFAS 150”), “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” SFAS 150 requires that certain financial instruments that could previously be accounted for as equity, be classified as liabilities in the balance sheets and initially recorded at fair value. Upon adoption on July 1, 2003, we reclassified our preferred members’ interest, which are mandatorily redeemable securities, of $200 million from mezzanine equity to long term debt. During 2003, subsequent to the reclassification, we redeemed the entire remaining $200 million of the securities. Beginning on July 1, 2003, accrued or paid distributions previously classified as dividends on the preferred members’ interest are prospectively classified as interest expense in the Consolidated Statements of Operations. Interest expense for 2003 on the preferred members’ interest was $6 million (represents the second half of 2003 preferential distributions).

     Debt Securities

     The following series of unsecured senior debt securities were outstanding at December 31, 2003:

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     The proceeds from the issuance of debt securities were used to repay a portion of our outstanding commercial paper. 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. At the respective due dates, we expect to either refinance the debt with long term debt or a combination of short term and long term debt or repay a portion of the debt and refinance the remainder with long term debt or a combination of short term and long term debt.

     In October 2001, we entered into an interest rate swap to convert the fixed interest rate of $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 a six-month London Interbank Offered Rate (“LIBOR”), which is re-priced semiannually through 2005. In August 2003, we entered into two additional interest rate swaps to convert the fixed interest rate of $100 million of debt securities issued on August 16, 2000 to floating rate debt. These interest rate fair value hedges also bear a floating rate based on six-month LIBOR, which is re-priced semiannually through 2030. The swaps meet conditions which permit the assumption of no ineffectiveness. As such, for the life of the swaps no ineffectiveness will be recognized. As of December 31, 2003, the fair value of the interest rate swaps of $15 million asset 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, 2003 and 2002, there were no distributions payable based on taxable income allocated to the members. We expect that we will pay tax distributions to our members in 2004.

     In 2003, our board of directors approved a plan to consider the payment of a quarterly dividend to our members. Our board of directors may consider net income, cash flow or any other criteria deemed appropriate for determining the amount of the quarterly dividend to be paid. Our LLC Agreement restricts making distributions, which would include these dividends, except with the approval of both members.

     Contractual Obligations, Commercial Commitments and Off-Balance Sheet Arrangements

     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 in 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, 2003, we were the guarantor of approximately $3 million of debt associated with unconsolidated subsidiaries. Assets of the unconsolidated subsidiaries are pledged as collateral for the debt. This debt was subsequently repaid in January 2004. At December 31, 2003, we had no liability recorded for the guarantees of the debt associated with the unconsolidated subsidiaries.

     At December 31, 2003, 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, 2003, we had a liability of $1 million recorded for these outstanding indemnification provisions.

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     The following table summarizes our payments due under material cash contractual obligations as of December 31, 2003 (in millions):

(a)

Debt includes debt securities of $2,250 million and long term notes payable of $10 million. Debt also includes interest payments of $1,370 million ($59 million of which is recognized as accrued interest payable on the 2003 Consolidated Balance Sheet) of future interest payments based upon current outstanding long term debt.

(b)

Purchase commitments include $353 million of various non-cancelable commitments to purchase physical quantities of commodities in future periods. Amount includes certain normal purchases, commodity derivatives and hedges. For contracts where the price paid is based on an index, the amount is based on the forward market prices at December 31, 2003. Purchase commitments exclude $906 million of accounts payable and $150 million of other current liabilities recognized on the 2003 Consolidated Balance Sheet. Purchase commitments also exclude $153 million of current and $24 million of long term unrealized losses on trading and hedging transactions included in the Consolidated Balance Sheets. These amounts represent the current fair value of various derivative contracts and do not represent future cash purchase commitments. These contracts may be settled financially at the difference between the future market price and the contractual price and may result in cash payments or cash receipts in the future, but generally do not require delivery of physical quantities. In addition, many of our gas purchase contracts include short and long term commitments to purchase produced gas at market prices. These contracts, which have no minimum quantities, are excluded from the table.

(c)

Other long term liabilities include $17 million of deferred income taxes and $45 million of asset retirement obligations recognized on the 2003 Consolidated Balance Sheet.

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 beginning on page 27 — 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, futures and options. (See Notes 2 and 13 to the Consolidated Financial Statements.)

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     Commodity Derivatives — Mark-to-Market — The risk in the commodity mark-to-market 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 Value at Risk (“DVaR”) as described below. DVaR is monitored daily in comparison to established thresholds. Other measures are also used to limit and monitor the risk in the commodity mark-to-market portfolio (which includes all trading and non-trading derivatives 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.

     DVaR computations are based on a historical simulation, which uses price movements over an 11 day period 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, natural gas and other energy-related products. DVaR 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 DVaR amounts for commodity mark-to-market derivatives instruments and related activities are shown in the following table:

Daily Value at Risk (millions)

     DVaR is an estimate based on historical price volatility. Actual volatility can exceed predicted results. DVaR also assumes a normal distribution of price changes, thus if the actual distribution is not normal, the DVaR may understate or overstate actual results. DVaR 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 DVaR to measure risk where market data information is limited. In the current DVaR 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. Effective January 1, 2003, in connection with the implementation of EITF 02-03, the Company designates each commodity derivative as either trading or non-trading. Certain non-trading derivatives are further designated as either a hedge of a forecasted transaction or future cash flow (cash flow hedge), a hedge of a recognized asset, liability or firm commitment (fair value hedge), or a normal purchase or sale contract, while certain non-trading derivatives, which are related to our asset based marketing, are non-trading mark-to-market derivatives. For each of the Company’s derivatives, the accounting method and presentation of gains and losses or revenue and expense in the Consolidated Statements of Income are as follows:

^a Mark-to-market- An accounting method whereby the change in the fair value of the asset or liability is recognized in the Consolidated Statements of Income in Trading and marketing net margin during the current period.

^b Hedge method- An accounting method whereby the effective portion of the change in the fair value of the asset or liability is recorded in the Consolidated Balance Sheets and there is no recognition in the Consolidated Statements of Income for the effective portion until the service is provided or the associated delivery period occurs.

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^c Accrual method- An accounting method whereby there is no recognition in the Consolidated Statements of Income for normal purchases and sales derivatives for changes in fair value of a contract until the service is provided or the associated delivery period occurs.

     The following table illustrates the movements in the fair value of our mark-to-market instruments during 2003:

Changes in Fair Value of Mark-to-Market Contracts (millions)

     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.

     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, 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 mark-to-market portfolio as of December 31, 2003:

     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 and (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. 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 has 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, may 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. 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 and capital expenditures. The primary goals of the hedging program include maintaining minimum cash flows to fund debt service, production replacement and maintenance capital projects, and retaining a high percentage of potential upside relating to price increases of NGLs.

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     Our primary use of commodity derivatives is to hedge the output and production of assets we physically own. Current contract terms are up to one year; however, our risk management guidelines allow for contract terms up to three years. Since these contracts are designated and qualify as effective hedge positions of future cash flows, or fair values of assets, liabilities or firm commitments, 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 Accumulated Other Comprehensive Income (Loss) (“AOCI”) 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. Amounts in AOCI 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 AOCI through the date of de-designation remain in AOCI 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. However, as mentioned previously, the effective portion of the gains and losses for these contracts are not recognized in earnings until settlement at their future 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. The following table show the fair value of our hedging contracts, including both commodity hedges and interest rate hedges, as of December 31, 2003:

     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 $0.01 per gallon in the price of NGLs and $0.10 per million Btus in the average price of natural gas would result in changes in annual pre-tax net income of approximately $(18) million and $1 million, respectively. In addition, a decrease of $1 per barrel in the average price of crude oil would result in a change to annual pre-tax net income of approximately $(5) million.

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 range from 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 ChevronPhillips, under an existing 15-year contract which expires in 2015. 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.

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     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, 2003, we had cash or letters of credit of $65 million to secure future performance by counterparties, and had deposited with counterparties $39 million of such collateral to secure our obligations to provide future services or to perform under financial contracts. 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.

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 debt. Our primary goals include: (1) maintaining an appropriate ratio of fixed-rate debt to total debt for our 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, 2003, the fair value of our interest rate swaps was an asset of $15 million. (See Notes 2 and 13 to the Consolidated Financial Statements.)

     As of December 31, 2003, we had no outstanding commercial paper. As a result of our debt and interest rate swaps, 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 0.5% in interest rates would result in an increase in annual interest expense of approximately $2 million.

Foreign Currency Risk

     Our primary foreign currency exchange rate exposure at December 31, 2003 was the Canadian dollar. Foreign currency risk associated with this exposure was not material.

Accounting Pronouncements

     In May 2003, the FASB issued SFAS 150 which requires that certain financial instruments that could previously be accounted for as equity, be classified as liabilities in the Consolidated Balance Sheets and initially recorded at fair value. In addition to its requirements for the classification and measurement of financial instruments in its scope, SFAS 150 also requires disclosures about the nature and terms of the financial instruments and about alternative ways of settling the instruments. The provisions of SFAS 150 are effective for all financial instruments entered into or modified after May 31, 2003, and are otherwise effective at the beginning of the first interim period beginning after June 15, 2003. Upon adoption on July 1, 2003, we reclassified our preferred members’ interest, which are mandatorily redeemable securities, of $200 million from mezzanine equity to long term debt and prospectively classified accrued or paid distributions on the preferred members’ interest, which had previously been classified as dividends, as interest expense. Interest expense recorded in 2003 on the preferred members’ interest was $6 million. During 2003, we redeemed the remaining $200 million of the securities in cash.

     In April 2003, the FASB issued SFAS No. 149 (“SFAS 149”), “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” which amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS 133. SFAS 149 clarifies the discussion around initial net investment, clarifies when a derivative contains a financing component, and amends the definition of an underlying to conform to language used in FASB Interpretation No. 45 (“FIN 45”), “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” In addition, SFAS 149 also incorporates certain of the Derivative Implementation Group Implementation Issues. The provisions of SFAS 149 are effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The guidance is to be applied to hedging relationships on a prospective basis. The adoption of the new interpretation had no material effect on our consolidated results of operations, cash flows or financial position.

     In January 2003, the FASB issued Interpretation No. 46 (“FIN 46”), “Consolidation of Variable Interest Entities” which requires the primary beneficiary of a variable interest entity’s activities to consolidate the variable interest entity. FIN 46 defines a variable interest entity as an entity in which the equity investors do not have substantive voting rights and there is not sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. The primary beneficiary is the party that absorbs a majority of the expected losses and/or receives a majority of the expected residual returns of the variable interest entity’s activities. In December 2003, the FASB issued FIN 46R, which supercedes and amends certain provisions of FIN 46. While FIN 46R retains many of the concepts and provisions of FIN 46, it also provides additional guidance related to the application of FIN 46,

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provides for certain additional scope exceptions, and incorporates several FASB Staff Positions issued related to the application of FIN 46.

     The provisions of FIN 46 are immediately applicable to variable interest entities created, or interests in variable interest entities obtained, after January 31, 2003 and the provisions of FIN 46R are required to be applied to such entities by the end of the first reporting period ending after March 15, 2004 (March 31, 2004 for us). For variable interest entities created, or interests in variable interest entities obtained, on or before January 31, 2003, FIN 46 or FIN 46R is required to be applied to special-purpose entities by the end of the first reporting period ending after December 15, 2003 (December 31, 2003 for calendar-year entities) and is required to be applied to all other non-special purpose entities by the end of the first reporting period ending after March 15, 2004 (March 31, 2004 for calendar-year entities). FIN 46 and FIN 46R 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 and FIN 46R also require certain disclosures of an entity’s relationship with variable interest entities.

     We have not identified any material variable interest entities created, or interests in variable entities obtained, after January 31, 2003 which require consolidation or disclosure under FIN 46 and continue to assess the existence of any interests in variable interest entities created on or prior to January 31, 2003. We currently anticipate one non-special purpose entity, previously accounted for under the equity method of accounting, will be consolidated by us in the first quarter of 2004 under the provisions of FIN 46R. This entity, which is a substantive entity, has total assets of approximately $92 million as of December 31, 2003 and total revenue of approximately $43 million for the year ended December 31, 2003. Our maximum exposure to loss as a result of our involvement with this entity is approximately $82 million as of December 31, 2003. We continue to assess FIN 46R but do not anticipate that it will have a material impact on our consolidated results of operations, cash flows or financial position.

     In November 2002, the FASB issued FIN 45 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 adopted the initial recognition and measurement provisions of FIN 45 effective January 1, 2003. The adoption of the new interpretation had no material effect on our consolidated results of operations, cash flows or financial position.

     In June 2002, the EITF reached a partial consensus on EITF 02-03. EITF 02-03 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. We had previously chosen to report certain energy trading contracts on a gross basis, as sales in operating revenues and the associated costs recorded as purchases in costs and expenses, in accordance with prevailing industry practice. The amounts in the comparative 2001 Consolidated Statements of Operations have been reclassified to conform to the 2003 and 2002 presentation of all amounts on a net basis. Revenues were adjusted downward by $931 million from the previously reported amount, with offsetting adjustments made to operating expenses resulting in no impact on net income.

     In October 2002, the EITF, as part of their further deliberations on EITF 02-03, rescinded the consensus reached in Issue No. 98-10 (“EITF 98-10”), “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” 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, must now be recorded at the lower of cost or market and are 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 should be accounted for under the accrual accounting basis. Non-derivative energy trading contracts on the Consolidated Balance Sheet as of January 1, 2003 that existed at October 25, 2002 and inventories that were recorded at fair values have been adjusted to the lower of historical cost or market, resulting in a $5 million charge recorded in 2003 in Cumulative effect of accounting change in the Consolidated Statements of Operations. In connection with the consensus reached on Issue No. 02-03, the FASB staff observed that, effective July 1, 2002, an entity should not recognize unrealized gains or losses at the inception of a derivative instrument unless the fair value of that instrument is evidenced by quoted market prices or current market transactions.

     In October 2002, the EITF also reached a consensus on EITF 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 Consolidated Statements of Operations. 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 other than for energy trading contracts that were shown on a net basis under EITF 98-10. Accordingly, for 2003, derivative instruments that are held for trading and marketing purposes and are accounted for under mark-to-market accounting are included in Trading and

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marketing net margin in the Consolidated Statements of Operations. As noted above, for 2002 and 2001, Trading and marketing net margin also includes the net margin on non-derivative energy trading contracts (primarily gas storage inventories and the related physical purchases and sales). The gross revenue presentation requirements had no impact on gross margin or net income.

     In July 2003, the EITF reached consensus in EITF Issue No. 03-11 (“EITF 03-11”), “Reporting Realized Gains and Losses on Derivative Instruments that are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes,” that determining whether realized gains and losses on derivative contracts not held for trading purposes should be reported on a net or gross basis is a matter of judgment that depends on the relevant facts and circumstances. In analyzing the facts and circumstances, EITF Issue No. 99-19 and Opinion No. 29, “Accounting for Nonmonetary Transactions,” should be considered. EITF 03-11 is effective for transactions or arrangements entered into after September 30, 2003. The adoption of EITF 03-11 had no material effect on our consolidated results of operations, cash flows or financial position as we continue to net non-trading mark-to-market activity.

     On June 25, 2003, the FASB cleared the guidance contained in DIG Issue C20, “Scope Exceptions: Interpretation of the Meaning of ‘Not Clearly and Closely Related’ in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature.” DIG Issue C20, which applies only to the guidance in paragraph 10(b) of FASB 133 and not in reference to embedded derivatives, describes three circumstances in which the underlying in a price adjustment incorporated into a contract that otherwise satisfies the requirements for the normal purchases and normal sales exception would be considered to be “not clearly and closely related to the asset being sold or purchased.” The guidance in DIG Issue C20 was effective for us on October 1, 2003. The adoption of this Issue had no material impact on our consolidated results of operations, cash flows or financial position.

     We adopted SFAS No. 142 (“SFAS 142”), “Goodwill and Other Intangible Assets,” on January 1, 2002 which 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 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 income (loss) would have been if amortization related to goodwill that is no longer being amortized had been excluded from prior periods:

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

     In June 2001, the FASB issued SFAS No. 143 (“SFAS 143”), “Accounting for Asset Retirement Obligations,” which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability increases due to the passage of time based on the time value of money until the obligation is settled. We adopted the provisions of SFAS 143 as of January 1, 2003. In accordance with the transition provisions of SFAS 143, we recorded an $18 million charge in 2003 in Cumulative effect of accounting change in the Consolidated Statements of Operations.

     In May 2003, the EITF reached consensus in EITF Issue No. 01-08 (“EITF 01-08”), “Determining Whether an Arrangement Contains a Lease,” to clarify the requirements of identifying whether an arrangement should be accounted for as a lease at its

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inception. The guidance in the consensus is designed to mandate reporting revenue as rental or leasing income that otherwise would be reported as part of product sales or service revenue. EITF 01-08 requires both parties to an arrangement to determine whether a service contract or similar arrangement is or includes a lease within the scope of SFAS No. 13, “Accounting for Leases.” The consensus is to be applied prospectively to arrangements agreed to, modified, or acquired in business combinations in fiscal periods beginning on July 1, 2003. The adoption of EITF 01-08 had no material effect on our consolidated results of operations, cash flows or financial position.

Subsequent Events

     In August 2003, we entered into a purchase and sale agreement to sell gas gathering and processing plant assets in West Texas to a third party purchaser for a sales price of approximately $62 million. The transaction was to be closed on September 30, 2003; however, the purchaser was unable to meet the conditions of closing. In October 2003, we entered into a new purchase and sale agreement for the sale of these assets to a party related to the original third party purchaser for a sales price of approximately $62 million. The transaction was to be closed in December 2003; however, the purchaser was again unable to meet the conditions of closing. In February 2004, we entered into a new purchase and sale agreement for the sale of these assets to a party related to the original third party purchaser for a sales price of approximately $62 million. The transaction closed in the first quarter of 2004 with no significant book gain or loss.

     On March 10, 2004, we entered into an agreement to acquire gathering, processing and transmission assets in Southeast New Mexico from ConocoPhillips for approximately $75 million. Pending approvals from governmental authorities, the transaction is scheduled to close in the second quarter of 2004. The assets to be acquired include three natural gas processing plants with capacity of 112 MMcf/d, over 1,000 miles of gathering lines and associated compression, and a 75 mile intrastate natural gas pipeline.

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ITEM 8. Financial Statements and Supplementary Data.

DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED STATEMENTS OF OPERATIONS
Years Ended December 31, 2003, 2002 and 2001
(millions)

See Notes to Consolidated Financial Statements.

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DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
Years Ended December 31, 2003, 2002 and 2001
(millions)

See Notes to Consolidated Financial Statements.

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DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31, 2003, 2002 and 2001
(millions)

See Notes to Consolidated Financial Statements.

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DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED BALANCE SHEETS
As of December 31, 2003 and 2002
(millions)