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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

FOR ANNUAL AND TRANSITION REPORTS

PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

(Mark One)

For the fiscal year ended December 31, 2003 or

For the transition period from  __________________  to  __________________

Commission file number 0-23977

DUKE CAPITAL LLC

(Exact name of registrant as specified in its charter)

704-594-6200

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:

Title of class

Limited Liability Company Member Interests

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 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 in Rule 12b-2 of the Securities Exchange Act of 1934).  Yes  ¨  No  x

The registrant meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format. Items 4, 10, 11, 12 and 13 have been omitted in accordance with Instruction I(2)(c).

All of the registrant’s limited liability company member interests are directly owned by Duke Energy Corporation (File No. 1-4928), which files reports and proxy material pursuant to the Securities Exchange Act of 1934, as amended.

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DUKE CAPITAL LLC

FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2003

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SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

Duke Capital LLC’s (Duke Capital) reports, filings and other public announcements may contain or incorporate by reference 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,” “will,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “continue,” “potential,” “plan,” “forecast” and other similar words. Those statements represent Duke Capital’s intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors. Many of those factors are outside Duke Capital’s control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. Those factors include:

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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 Duke Capital has described. Duke Capital undertakes 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.

GENERAL

Duke Capital LLC (collectively with its subsidiaries, Duke Capital), a wholly owned subsidiary of Duke Energy Corporation, is a leading energy company located in the Americas with an affiliated real estate operation. Duke Capital provides its services through the business segments described below. On March 1, 2004, Duke Capital changed its form of organization from a corporation to a Delaware limited liability company by effecting a conversion pursuant to Section 266 of the General Corporation Law of the State of Delaware and Section 18-214 of the Delaware Limited Liability Company Act. Pursuant to the conversion, all rights and liabilities of Duke Capital in its previous corporate form vested in Duke Capital as a limited liability company.

Duke Capital operates the following business units: Natural Gas Transmission, Field Services, Duke Energy North America (DENA), International Energy and Other Operations. Duke Capital’s chief operating decision maker regularly reviews financial information about each of these business units in deciding how to allocate resources and evaluate performance. The entities under each business unit, except for Other Operations, have similar economic characteristics, services, production processes, distribution methods and regulatory concerns. All of the Duke Capital business units are considered reportable segments under Statement of Financial Accounting Standards No. 131, “Disclosures about Segments of an Enterprise and Related Information,” except for Other Operations, which is related to other business activities and operating segments that are not reportable.

Natural Gas Transmission provides transportation and storage of natural gas for customers throughout the East Coast and Southern U.S., the Pacific Northwest, and in Canada. Natural Gas Transmission also provides natural gas sales and distribution service to retail customers in Ontario, and gas transportation and processing services to customers in Western Canada. Natural Gas Transmission does business primarily through Duke Energy Gas Transmission Corporation. Duke Energy Gas Transmission Corporation’s natural gas transmission and storage operations in the U.S. are subject to the Federal Energy Regulatory Commission’s (FERC), the Texas Railroad Commission’s, and the U.S. Department of Transportation’s (DOT’s) rules and regulations, while natural gas gathering, processing, transmission, distribution and storage operations in Canada are subject to the rules and regulations of the National Energy Board (NEB) or the Ontario Energy Board (OEB).

Field Services gathers, compresses, treats, processes, transports, trades and markets, and stores natural gas; and produces, transports, trades and markets, and stores natural gas liquids (NGLs). It conducts operations primarily through Duke Energy Field Services, LLC (DEFS), which is approximately 30% owned by ConocoPhillips and approximately 70% owned by Duke Capital. Field Services gathers natural gas from production wellheads in Western Canada and 10 states in the U.S. Those systems serve major natural gas-producing regions in the Western Canadian Sedimentary Basin, Rocky Mountain, Permian Basin, Mid-Continent and East Texas-Austin Chalk-North Louisiana areas, as well as onshore and offshore Gulf Coast areas.

DENA operates and manages merchant power generation facilities and engages in commodity sales and services related to natural gas and electric power around its generation assets and contractual positions. DENA conducts business throughout the U.S. and Canada generally through Duke Energy North America, LLC and Duke Energy Trading and Marketing, LLC (DETM). DETM is 40% owned by Exxon Mobil Corporation and 60% owned by Duke Capital. In 2003, Duke Energy discontinued the proprietary trading business at DENA, commenced actions to unwind DETM, and announced its intent to reduce its investment in merchant power generation facilities by selling its facilities in the Southeast U.S. and reducing its interests in partially constructed facilities in the Western U.S.

International Energy develops, operates and manages power generation facilities, and engages in sales and marketing of electric power and natural gas outside the U.S. and Canada. It conducts operations primarily

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through Duke Energy International, LLC (DEI) and its activities target power generation in Latin America. During 2003, International Energy began the process to discontinue proprietary trading and is in the process of exiting its European and Australian operations.

Beginning in 2003, the business segments formerly known as Other Energy Services and Duke Ventures were combined and have been presented as Other Operations. Other Operations is composed of diverse businesses, operating through Crescent Resources, LLC (Crescent), DukeNet Communications, LLC (DukeNet), and Duke/Fluor Daniel (D/FD). Crescent develops high-quality commercial, residential and multi-family real estate projects, and manages land holdings primarily in the Southeastern and Southwestern U.S. DukeNet develops and manages fiber optic communications systems for wireless, local and long-distance communications companies; and for selected educational, governmental, financial and health care entities. D/FD provides comprehensive engineering, procurement, construction, commissioning and operating plant services for fossil-fueled electric power generating facilities worldwide. D/FD is a 50/50 partnership between subsidiaries of Duke Capital and Fluor Corporation. On July 9, 2003, Duke Capital and Fluor Corporation announced that the D/FD partnership will be dissolved. The D/FD partners have adopted a plan for an orderly wind-down of the business targeted for completion in July 2005. Other Operations also included Energy Delivery Services (EDS), an engineering, construction, maintenance and technical services firm specializing in electric transmission and distribution lines and substation projects, until its sale in December 2003. Additionally, Duke Capital Partners, LLC (DCP), a wholly owned merchant finance company that provided debt and equity capital and financial advisory services primarily to the merchant energy industry, had been included as part of Other Operations but is now classified as discontinued operations.

Duke Capital is a Delaware limited liability company. Its principal executive offices are located at 526 South Church Street, Charlotte, North Carolina 28202-1803. The telephone number is 704-594-6200.

Terms used to describe Duke Capital’s business are defined below.

Allowance for Funds Used During Construction. A non-cash accounting convention of regulatory utilities that represents the estimated composite interest costs of debt and a return on equity funds used to finance construction. The allowance is capitalized in the property accounts and included in income.

British Thermal Unit (Btu). A standard unit for measuring thermal energy or heat commonly used as a gauge for the energy content of natural gas and other fuels.

Cubic Foot (cf). The most common unit of measurement of gas volume; the amount of natural gas required to fill a volume of one cubic foot under stated conditions of temperature, pressure and water vapor.

Derivative. A contract in which its price is based on the value of underlying securities, equity indices, debt instruments, commodities or other benchmarks or variable. Often used to hedge risk, derivatives involve the trading of rights or obligations, but not the direct transfer of property and gains or losses are often settled net.

Distribution. The system of lines, transformers, switches and mains that connect electric and natural gas transmission systems to customers.

Federal Energy Regulatory Commission (FERC). The U.S. agency that regulates the transportation of electricity and natural gas in interstate commerce and authorizes the buying and selling of energy commodities at market-based rates.

Forward Contract. A contract in which the buyer is obligated to take delivery, and the seller is obligated to deliver a fixed amount of a commodity at a predetermined price on a specified future date, at which time payment is due in full.

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Fractionation/Fractionate. The process of separating liquid hydrocarbons from natural gas into propane, butane, ethane, etc.

Gathering System. Pipeline, processing and related facilities that access production and other sources of natural gas supplies for delivery to mainline transmission systems.

Generation. The process of transforming other forms of energy, such as nuclear or fossil fuels, into electricity. Also, the amount of electric energy produced, expressed in megawatt-hours.

Independent System Operator (ISO). An entity that ensures non-discriminatory access to a regional transmission system, providing all customers access to the power exchange and clearing all bilateral contract requests for use of the electric transmission system. Also responsible for maintaining bulk electric system reliability.

Liquefied Natural Gas (LNG). Natural gas that has been converted to a liquid by cooling it to –260 degrees Fahrenheit.

Local Distribution Company (LDC). A company that obtains the major portion of its revenues from the operations of a retail distribution system for the delivery of electricity or gas for ultimate consumption.

Logistics & Optimization. The act of maximizing returns from physical positions through arbitrage, especially on contractual assets such as storage, transportation, generation and transmission.

Mark-to-Market. The process whereby an asset or liability is recognized at fair value and the change in the fair value of that asset or liability is recognized in revenues in the Consolidated Statements of Operations or in Other Comprehensive Income within equity during the current period.

Natural Gas. A naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in porous geological formations beneath the earth’s surface, often in association with petroleum. The principal constituent is methane.

Natural Gas Liquids (NGLs). Liquid hydrocarbons extracted during the processing of natural gas. Principal commercial NGLs include butanes, propane, natural gasoline and ethane.

No-notice Bundled Service. A pipeline delivery service which allows customers to receive or deliver gas on demand without making prior nominations to meet service needs and without paying daily balancing and scheduling penalties.

Origination. Identification and execution of physical energy related transactions, generally with customized provisions to meet the needs of the customer or supplier, throughout the value chain.

Peak Load. The amount of electricity required during periods of highest demand. Peak periods fluctuate by season, generally occurring in the morning hours in winter and in late afternoon during the summer.

Regional Transmission Organization (RTO). An independent entity which is established to have “functional control” over utilities’ transmission systems, in order to expedite transmission of electricity.

Reliability Must Run. Generation that the California ISO determines is required to be on-line to meet applicable reliability criteria requirements.

Residue Gas. Gas remaining after the processing of natural gas.

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Spark Spread. The difference between the value of electricity and the value of the gas required to generate the electricity at a specified heat rate.

Throughput. The amount of natural gas or natural gas liquids transported through a pipeline system.

Tolling. Process whereby a party provides fuel to a power generator and receives kilowatt hours in return for a pre-established fee.

Transmission System (Electric). An interconnected group of electric transmission lines and related equipment for moving or transferring electric energy in bulk between points of supply and points at which it is transformed for delivery over a distribution system to customers, or for delivery to other electric transmission systems.

Transmission System (Natural Gas). An interconnected group of natural gas pipelines and associated facilities for transporting natural gas in bulk between points of supply and delivery points to industrial customers, LDCs, or for delivery to other natural gas transmission systems.

Volatility. An annualized measure of the fluctuation in the price of an energy contract. Implied volatility is a measure of what the market values volatility to be, as reflected in the option’s price.

Watt. A measure of power production or usage equal to one joule per second.

The following sections describe the business and operations of each of Duke Capital’s business segments. (For more information on the operating outlook of Duke Capital and its segments, see “Management’s Discussion and Analysis of Results of Operations and Financial Condition, Introduction—Overview of Business Strategy and Economic Factors.” For financial information on Duke Capital’s business segments, see Note 3 to the Consolidated Financial Statements, “Business Segments.”)

NATURAL GAS TRANSMISSION

Natural Gas Transmission provides transportation and storage of natural gas for customers throughout the East Coast and Southern U.S., the Pacific Northwest, and in Canada. Natural Gas Transmission also provides natural gas sales and distribution service to retail customers in Ontario, and gas transportation and processing services to customers in Western Canada. Natural Gas Transmission does business primarily through Duke Energy Gas Transmission Corporation.

For 2003, Natural Gas Transmission’s proportional throughput for its pipelines totaled 3,362 trillion British thermal units (TBtu), compared to 3,160 TBtu in 2002, a 6% increase mainly due to the Westcoast Energy Incorporated (Westcoast) acquisition. This includes throughput on Natural Gas Transmission’s wholly owned U.S. and Canadian pipelines and its proportional share of throughput on pipelines that are not wholly owned. The operations purchased in the Westcoast acquisition contributed 1,396 TBtu in 2003, compared to 1,229 TBtu in 2002. A majority of Natural Gas Transmission’s contracted transportation volumes are under long-term firm service agreements with LDC customers in the pipelines’ market areas. Firm transportation services are also provided to gas marketers, producers, other pipelines, electric power generators and a variety of end-users. In addition, the pipelines provide both firm and interruptible transportation to various customers on a short-term or seasonal basis. Demand on Natural Gas Transmission’s pipeline systems is seasonal, with the highest throughput occurring during colder periods in the first and fourth calendar quarters. Natural Gas Transmission’s pipeline systems consist of more than 17,500 miles of transmission pipelines. The pipeline systems receive natural gas from major North American producing regions for delivery to markets primarily in the Mid-Atlantic, New England and Southeastern states, Ontario, British Columbia, and the Pacific Northwest. (For detailed descriptions of Natural Gas Transmission’s pipeline systems, see “Properties—Natural Gas Transmission”)

Natural Gas Transmission provides retail distribution services through its subsidiary, Union Gas Limited (Union Gas). Union Gas owns and operates natural gas transmission, distribution and storage facilities in Ontario. Union Gas distributes natural gas to customers in northern, southwestern and eastern Ontario and provides storage, transportation and related services to utilities and other industry participants in the gas

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markets of Ontario, Quebec and the Central and Eastern U.S. Union Gas’ distribution service area extends throughout northern Ontario from the Manitoba border to the North Bay/Muskoka area, through southern Ontario from Windsor to just west of Toronto, and across eastern Ontario from Port Hope to Cornwall. Union Gas’ distribution system consists of approximately 21,000 miles of distribution pipelines serving approximately 1.2 million residential, commercial and industrial customers.

Natural Gas Transmission, through Market Hub Partners (MHP), wholly owns natural gas salt cavern facilities in south Texas and Louisiana with a total storage capacity of approximately 31 billion cubic feet (Bcf). MHP markets natural gas storage services to pipelines, LDCs, producers, end users and natural gas marketers. Texas Eastern Transmission, LP (Texas Eastern) and East Tennessee Natural Gas Company (ETNG) also provide firm and interruptible open-access storage services. Storage is offered as a stand-alone unbundled service or as part of a no-notice bundled service with transportation. Texas Eastern has two joint-venture storage facilities in Pennsylvania and one wholly owned and operated storage field in Maryland. Texas Eastern’s certificated working capacity in these three fields is 75 Bcf. ETNG has a LNG storage facility in Tennessee with a certificated working capacity of 1.2 Bcf. Union Gas owns approximately 150 Bcf of natural gas storage capacity in 20 underground facilities located in depleted gas fields near Sarnia, Ontario.

Competition

Natural Gas Transmission’s pipeline, storage and gas gathering and processing businesses compete with other pipeline and storage facilities in the transportation, processing and storage of natural gas. Natural Gas Transmission competes directly with other pipelines and storage facilities serving its market areas. Natural Gas Transmission also competes directly with other natural gas storage facilities in south Texas, Louisiana and Ontario. The principal elements of competition are rates, terms of service, and flexibility and reliability of service.

Natural gas competes with other forms of energy available to Natural Gas Transmission’s customers and end-users, including electricity, coal and fuel oils. The primary competitive factor is price. Changes in the availability or price of natural gas and other forms of energy, the level of business activity, conservation, legislation, governmental regulations, the ability to convert to alternative fuels, weather and other factors affect the demand for natural gas in the areas served by Natural Gas Transmission.

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Union Gas’ distribution sales to industrial customers are affected by weather, economic conditions and the price of competitive energy sources. Most of Union Gas’ industrial and commercial customers, and a portion of residential customers, purchase their natural gas supply directly from suppliers or marketers. As Union Gas earns income from the distribution of natural gas and not the sale of the natural gas commodity, the gas distribution margin is not affected by the source of the customer’s gas supply.

Regulation

Most of Natural Gas Transmission’s pipeline and storage operations in the U.S. are regulated by the FERC. The FERC has authority to regulate rates and charges for natural gas transported or stored for U.S. interstate commerce or sold by a natural gas company via interstate commerce for resale. (For more information on rate matters, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters—Natural Gas Transmission.”) The FERC also has authority over the construction and operation of U.S. pipelines and related facilities used in the transportation, storage and sale of natural gas in interstate commerce, including the extension, enlargement or abandonment of such facilities. In addition, certain operations are subject to state regulatory commissions.

The FERC regulations restrict access to U.S. interstate pipeline natural gas transmission customer and other data by affiliated gas marketing entities, and place certain conditions on services provided by the U.S. interstate pipelines to their affiliated gas marketing entities. These regulations affect the activities of non-regulated affiliates with Natural Gas Transmission.

Natural Gas Transmission’s U.S. operations are subject to the jurisdiction of the Environmental Protection Agency (EPA) and state environmental agencies. (For a discussion of environmental regulation, see “Environmental Matters” in this section.) Natural Gas Transmission’s interstate natural gas pipelines are subject to the regulations of the DOT concerning pipeline safety. DOT regulations have incorporated certain provisions of the Natural Gas Pipeline Safety Act of 1968 (and subsequent acts). The DOT has developed new regulations, effective February 14, 2004, that establish mandatory inspections for all natural gas transmission pipelines in high-consequence areas within 10 years. The new regulations 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 life and property. Management believes that compliance with these new DOT regulations for Natural Gas Transmission will not have a material adverse effect on the consolidated results of operations, cash flows or financial position of Duke Capital.

The natural gas gathering, processing, transmission, storage and distribution operations in Canada are subject to regulation by the NEB and provincial agencies in Canada, such as the OEB and the British Columbia Utilities Commission. These agencies have authorization similar to the FERC for setting rates, regulating the operations of facilities and construction of any additional facilities.

FIELD SERVICES

Field Services gathers, compresses, treats, processes, transports, trades and markets, and stores natural gas; and produces, transports, trades and markets, and stores NGLs. It conducts operations primarily through DEFS, which is approximately 30% owned by ConocoPhillips and approximately 70% owned by Duke Capital. Field Services gathers natural gas from production wellheads in Western Canada and ten states in the U.S. Those systems serve major gas-producing regions in the Western Canadian Sedimentary Basin, Rocky Mountain, Permian Basin, Mid-Continent and East Texas-Austin Chalk-North Louisiana areas, as well as onshore and offshore Gulf Coast areas. Field Services owns and operates approximately 58,000 miles of natural gas gathering systems with approximately 34,000 active receipt points.

Field Services’ natural gas processing operations separate raw natural gas that has been gathered on its systems and third-party systems into condensate, NGLs and residue gas. Field Services processes the raw natural gas at the 56 natural gas processing facilities that it owns and operates and at ten third-party operated facilities in which it has an equity interest.

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The NGLs separated from the raw natural gas are either sold and transported as NGL raw mix, or further separated through a fractionation process into their individual components (ethane, propane, butanes and natural gasoline) and then sold as components. Field Services fractionates NGL raw mix at ten processing facilities that it owns and operates and at four third-party-operated facilities in which it has an equity interest. In addition, Field Services operates a propane wholesale marketing business. Field Services sells NGLs to a variety of customers ranging from large, multinational petrochemical and refining companies to small regional retail propane distributors. Substantially all of its NGL sales are at market-based prices.

The residue gas separated from the raw natural gas is sold at market-based prices to marketers or end-users, including large industrial customers and natural gas and electric utilities serving individual consumers. Field Services markets residue gas directly or through its wholly owned gas marketing company and its affiliates. Field Services also stores residue gas at its 6 Bcf natural gas storage facility.

Field Services uses NGL trading and storage at the Mont Belvieu, Texas and Conway, Kansas NGL market centers to manage its price risk and to provide additional services to its customers. Asset based gas trading and marketing activities are supported by ownership of the Spindletop storage facility and various intrastate pipelines which provide access to market centers/hubs such as Waha, Texas; Katy, Texas and the Houston Ship Channel. Field Services undertakes these NGL and gas trading activities through the use of fixed forward sales, basis and spread trades, storage opportunities, put/call options, term contracts and spot marketing trading. Field Services believes there are additional opportunities to grow its services with its customer base.

The following map includes Field Services’ natural gas gathering systems, intrastate pipelines, regional offices and supply areas. The map also shows Natural Gas Transmission’s interstate pipeline systems.

Field Services also owns Texas Eastern Products Pipeline Company, LLC (TEPPCO), the general partner of TEPPCO Partners, L.P., a publicly traded limited partnership which owns one of the largest common carrier

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pipelines of refined petroleum products and liquefied petroleum gases in the U.S., as well as, natural gas gathering systems, petrochemical and natural gas liquid pipelines, and is engaged in crude oil transportation, storage, gathering and marketing. TEPPCO is responsible for the management and operations of TEPPCO Partners, L.P.

Field Services’ operating results are significantly impacted by changes in average NGL prices, which increased approximately 39% in 2003 compared to 2002. (See “Management’s Discussion and Analysis of Results of Operations and Financial Condition, Quantitative and Qualitative Disclosures About Market Risk” for a discussion of Field Services’ exposure to changes in commodity prices.)

Field Services’ activities can fluctuate in response to seasonal demand for natural gas.

Competition

Field Services competes with major integrated oil companies, major interstate and intrastate pipelines, national and local natural gas gatherers, and brokers, marketers and distributors for natural gas supplies, in gathering and processing natural gas and in marketing and transporting natural gas and NGLs. Competition for natural gas supplies is based primarily on the reputation, efficiency and reliability of operations, the availability of gathering and transportation to high-demand markets, the pricing arrangement offered by the gatherer/processor and the ability of the gatherer/processor to obtain a satisfactory price for the producer’s residue gas and extracted NGLs; whereas, competition for sales to customers is based primarily upon reliability, services offered, and price of delivered natural gas and NGLs.

Regulation

The intrastate pipelines owned by Field Services are subject to state regulation. To the extent they provide services under Section 311 of the Natural Gas Policy Act of 1978, the pipelines are also subject to FERC regulation. However, most of Field Services’ natural gas gathering activities are not subject to FERC regulation.

Field Services is subject to the jurisdiction of the EPA and state environmental agencies. (For more information, see “Environmental Matters” in this section.) Some of Field Services’ operations are subject to the jurisdiction of the Federal and state transportation agencies.

Recently, the DOT has developed new regulations, effective February 14, 2004, that require gas transmission pipeline operators to develop and implement integrity management programs for gas transmission pipelines located where a leak or rupture could have the greatest impact to life and property in areas referred to as “high consequence areas.” The regulations require gas pipeline transmission operators to perform ongoing assessments of pipeline integrity and to implement preventative and mitigative actions. Baseline integrity assessments are required to be completed by December 2012. Reassessments are to be conducted at prescribed intervals. Field Services is presently developing its implementation program to address these new DOT requirements, and is also evaluating the effects of complying with this new DOT regulatory program.

Field Services’ Canadian assets are regulated by the Alberta Energy and Utilities Board and the NEB.

DUKE ENERGY NORTH AMERICA

DENA operates and manages merchant power generation facilities and engages in commodity sales and services related to natural gas and electric power around its generation and contractual positions. DENA conducts business throughout the U.S. and Canada through Duke Energy North America and DETM. DETM is 40% owned by Exxon Mobil Corporation and 60% owned by Duke Capital. As discussed below, during 2003 certain key events led DENA to undertake a number of actions to change its existing business strategy.

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As an active participant in the North American wholesale energy market, DENA has redefined its business strategy primarily in response to:

As a result of these market developments DENA:

In the fourth quarter 2003, management decided to: a) exit the Southeast region through a contemplated disposition of its merchant generation plants located in that region, b) not use Duke Capital funds to complete construction and reduce DENA’s interest in deferred plants, and c) wind-down DETM. These actions negatively impacted operating income by approximately $3.1 billion.

Previously, DETM was committed to market substantially all of ExxonMobil’s U.S. and Canadian natural gas production through 2006. Beginning in March 2003, most of this natural gas production was no longer made available to be marketed by DETM. This change in gas supply along with the other key market events described above prompted the wind-down of DETM. As stated above, the majority of DETM’s commodity contracts have been eliminated or sold to third parties during 2003 and the remaining actions to wind down DETM’s operations will continue in 2004.

In June 2003, DENA sold its 50% ownership interest in Duke/UAE Ref-Fuel for $325 million to Highstar Renewable Fuels LLC. DENA recorded a gain on the sale of approximately $178 million, which is included in Gains on Sales of Equity Investments in the Consolidated Statements of Operations.

Generation Assets

DENA currently owns or operates approximately 15,820 net megawatts (MW) of operating generation and has approximately 2,402 net MW of operating generation under construction. During 2003, DENA determined that the partially constructed power generation facilities, Moapa, Grays Harbor, and Luna (collectively the “deferred plants”), will not be completed with Duke Capital funds. DENA will look to sell and/or solicit funding for completion of the deferred plants in 2004. Additionally, DENA has decided to sell all of its power generation facilities in the Southeast U.S.

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The following map shows DENA’s power generation facilities.

Marketing Portfolio

The majority of DENA’s portfolio of purchase and sales agreements incorporate market-sensitive pricing terms. Physical purchase and sales commitments involving significant price and location risk are generally hedged with financial derivatives. DENA’s results may also fluctuate in response to seasonal demand for electricity, natural gas and other energy-related commodities. Additionally, weather has a significant impact on electricity and natural gas demand. (For information concerning DENA’s risk-management activities, see “Management’s Discussion and Analysis of Results of Operations and Financial Condition, Quantitative and Qualitative Disclosures About Market Risk” and Note 7 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk and Financial Instruments.”)

Customers

DENA markets electricity to investor-owned utilities, municipal power generators and other power marketers. DENA markets natural gas primarily to LDCs, electric power generators, municipalities, large industrial end-users and energy marketing companies. DENA also provides energy management services, such as supply and market aggregation, peaking services, dispatching, balancing, transportation, storage, tolling, contract negotiation and administration, as well as energy commodity risk management products and services.

Competition

DENA’s competitors include utilities, other merchant electric generation companies in North America, certain financial institutions engaged in commodity trading, major integrated oil companies, major interstate pipelines and their marketing affiliates, brokers, marketers and distributors, and other domestic and international electric power and natural gas marketers. The price of commodities and services delivered, along with the quality and reliability of services provided, drive competition in the energy marketing business.

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Over the past two years, there has been a significant reduction in number of market participants due to the profitability decline resulting from oversupply of generation, increase in regulation, cost of capital to maintain generation facilities, collateral requirements, and bankruptcies. With fewer market participants, liquidity has been further depressed.

Regulation

DENA’s energy marketing activities are, in some circumstances, subject to the jurisdiction of the FERC. Current FERC policies permit DENA’s trading and marketing entities to market natural gas, electricity and other energy-related commodities at market-based rates, subject to FERC jurisdiction. DENA continues to monitor the varied pace of wholesale electricity market restructuring.

Certain of DENA’s generating stations in California sell electricity to the California ISO under “reliability must run” agreements; those sales are made at FERC regulated rates. In addition, several legal and regulatory proceedings at the state and federal levels are ongoing related to DENA’s activities in California during the electricity supply situation and related to trading activities. (See Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies—Litigation” for further discussion.)

The operation and maintenance of DENA’s power plants in California will be subject to regulation pursuant to rules that are currently being promulgated by state authorities. The new rules are intended to increase the reliability of the generation supply in California by setting maintenance standards and regulating when plants may be taken out of service for routine maintenance. Duke Capital does not believe that the new rules, when finalized, will have a material impact on the operation of its power plants in California.

DENA is subject to the jurisdiction of the EPA and state environmental agencies. (For a discussion of environmental regulation, see “Environmental Matters” in this section.)

INTERNATIONAL ENERGY

International Energy develops, operates and manages power generation facilities, and engages in sales and marketing of electric power and natural gas outside the U.S. and Canada. It conducts operations primarily through DEI and its activities target power generation in Latin America.

During 2003, International Energy sold its interest in P.T. Puncakjaya Power in Indonesia as well as decided to exit the European market and sell its Australian assets. As a result, these operations are not included in International Energy’s results but have been reclassified to discontinued operations for current and prior years. As of December 31, 2003, the European and Australian assets and liabilities are classified as Assets Held for Sale, and Liabilities Associated with Assets Held for Sale, respectively, on the Consolidated Balance Sheet. (See Note 11 to the Consolidated Financial Statements, “Assets Held for Sale and Discontinued Operations” for further discussion.)

From its platform of assets, International Energy provides customers with energy supply at competitive prices, manages the logistics associated with power and natural gas delivery, and offers services that allow customers to improve energy efficiency and hedge their commodity price exposure. International Energy’s customers include retail distributors, electric utilities, independent power producers and large industrial companies. International Energy is committed to building integrated regional businesses that provide customers with a full range of innovative and competitively priced energy services.

International Energy’s current strategy is focused on maximizing the returns and cash flow from its current portfolio of energy businesses by creating organic growth through its sales and marketing efforts in all regions in which it currently does business, optimizing the output and efficiency of its various facilities, controlling and reducing costs and divesting selected assets.

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International Energy’s continuing operations owns, operates or has substantial interests in approximately 4,121 net MW of generation facilities. The following map shows the locations of International Energy’s facilities, including projects under construction. The capacities shown in the map are gross MW values (for net MW values see “Properties—International Energy”).

Competition and Regulation

International Energy’s sales and marketing of electric power and natural gas competes directly with other generators and marketers serving its market areas. Competitors are country and region-specific but include government owned electric generating companies, LDC’s with self-generation capability and other privately owned electric generating companies. The principal elements of competition are price and availability, terms of service, flexibility and reliability of service.

A high percentage of International Energy’s portfolio is base-load hydro electric generation facilities which compete with other forms of electric generation available to International Energy’s customers and end-users, including natural gas and fuel oils. Economic activity, conservation, legislation, governmental regulations, weather and other factors affect the supply and demand for electricity in the regions served by International Energy.

International Energy’s operations are subject to international environmental regulations. (See “Environmental Matters” in this section.)

OTHER OPERATIONS

Beginning in 2003, the business segments formerly known as Other Energy Services and Duke Ventures were combined and have been presented as Other Operations. Other Operations is composed of diverse businesses, operating primarily through Crescent, DukeNet, DCP, D/FD and EDS.

Crescent develops high-quality commercial, residential and multi-family real estate projects, and manages land holdings, primarily in the Southeastern and Southwestern U.S. On December 31, 2003, Crescent owned 1.3

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million square feet of commercial, industrial and retail space, with an additional 0.9 million square feet under construction. This portfolio included 1.4 million square feet of office space, 0.4 million square feet of warehouse space and 0.4 million square feet of retail space. Crescent’s residential developments include high-end country club and golf course communities, with individual lots sold to custom builders and tract developments sold to national builders. Crescent had four multi-family communities at December 31, 2003, including two operating properties and two properties under development. On December 31, 2003, Crescent also managed approximately 134,000 acres of land.

DukeNet provides telecommunications bandwidth capacity for industrial and commercial customers through its fiber optic network. It owns and operates a fiber optic communications network centered in North Carolina and South Carolina and is interconnected with a fiber optic communications network through affiliate agreements with third parties.

DCP, a wholly owned merchant finance company, provided financing, investment banking and asset management services to wholesale and commercial markets in the energy and real estate industries. In 2003, Duke Capital announced that it will exit the merchant finance business at DCP in an orderly manner. DCP’s operating results have been classified as discontinued operations in the Consolidated Statements of Operations.

D/FD, operating through several entities, provides full-service siting, permitting, licensing, engineering, procurement, construction, start-up, operating and maintenance services for fossil-fueled electric power plants, both domestically and internationally. Subsidiaries of Duke Capital and Fluor Corporation each own 50% of D/FD. In 2003, Duke Capital and Fluor Corporation announced that the D/FD partnership will be dissolved. The partners of D/FD have adopted a plan for an orderly wind-down of the D/FD business targeted for completion in July 2005.

EDS is an engineering, construction, maintenance and technical services firm specializing in electric transmission and distribution lines and substation projects. It was formed in the second quarter of 2002 from the transmission and distribution services component of Duke Engineering Services, Inc. (DE&S) and was excluded from the sale of DE&S. On December 31, 2003, Duke Capital completed the sale of EDS to the Shaw Group Inc.

Competition and Regulation

Crescent competes with multiple regional and national real estate developers across its various business lines in the Southeastern and Southwestern U.S. Crescent’s residential division sells developed lots to regional and national home builders and retail buyers, competing with other developers and home builders with an inventory of developed lots. Crescent’s commercial division leases office, industrial and retail space, competing with other public and private developers and owners of commercial property including national real estate investment trusts (REITs). Similarly, Crescent’s multi-family division leases apartment units primarily to individuals, competing with other private developers and multi-family REITs.

Other Operations is subject to the jurisdiction of the EPA and international, state and local environmental agencies. (For a discussion of environmental regulation, see “Environmental Matters” in this section.)

ENVIRONMENTAL MATTERS

Duke Capital is subject to international, federal, state and local regulations with regard to air and water quality, hazardous and solid waste disposal and other environmental matters. Environmental regulations affecting Duke Capital include, but are not limited to:

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(For more information on environmental matters involving Duke Capital, including possible liability and capital costs, see Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies—Environmental.”)

Except to the extent discussed in Note 4 and Note 16 to the Consolidated Financial Statements, compliance with international, federal, state and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is not expected to have a material adverse effect on the competitive position, consolidated results of operations, cash flows or financial position of Duke Capital.

GEOGRAPHIC REGIONS

For a discussion of Duke Capital’s foreign operations and the risks associated with them, see “Management’s Discussion and Analysis of Results of Operations and Financial Condition, Quantitative and Qualitative Disclosures About Market Risk—Foreign Currency Risk,” and Notes 3 and 7 to the Consolidated Financial Statements, “Business Segments” and “Risk Management and Hedging Activities, Credit Risk and Financial Instruments.”

EMPLOYEES

On December 31, 2003, Duke Capital had approximately 13,600 employees. A total of 1,787 operating and maintenance employees were represented by unions. This amount consists of the following:

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Item 2. Properties.

NATURAL GAS TRANSMISSION

Texas Eastern’s gas transmission system extends approximately 1,700 miles from producing fields in the Gulf Coast region of Texas and Louisiana to Ohio, Pennsylvania, New Jersey and New York. It consists of two parallel systems, one with three large-diameter parallel pipelines and the other with one to three large-diameter pipelines. Texas Eastern’s onshore system consists of approximately 8,600 miles of pipeline and 73 compressor stations.

Texas Eastern also owns and operates two offshore Louisiana pipeline systems, which extend approximately 100 miles into the Gulf of Mexico and include approximately 500 miles of Texas Eastern’s pipeline system.

Algonquin Gas Transmission Company’s (Algonquin) transmission system connects with Texas Eastern’s facilities in New Jersey, and extends approximately 250 miles through New Jersey, New York, Connecticut, Rhode Island and Massachusetts. The system consists of approximately 1,100 miles of pipeline with six compressor stations. Algonquin is a wholly owned subsidiary of Duke Energy.

ETNG’s transmission system crosses Texas Eastern’s system at two points in Tennessee and consists of two mainline systems totaling approximately 1,400 miles of pipeline in Tennessee, Georgia, North Carolina and Virginia, with 18 compressor stations.

Maritimes and Northeast Pipeline’s transmission system (approximately 75% owned by Duke Capital) extends approximately 900 miles from producing fields in Nova Scotia through New Brunswick, Maine, New Hampshire and Massachusetts, connecting to Algonquin in Beverly, Massachusetts. It has two compressor stations on the system.

The British Columbia Pipeline System consists of two divisions. The field services division operates more than 1,840 miles of gathering pipelines in British Columbia, Alberta, the Yukon Territory and the Northwest Territories, as well as 22 field compressor stations; four gas processing plants located in British Columbia near Fort Nelson, Taylor, Chetwynd and in the Sikanni area northwest of Fort St. John, and three elemental sulphur recovery plants located at Fort Nelson, Taylor and Chetwynd. Total contractible capacity of approximately 1.8 Bcf of residue gas per day. The pipeline division has approximately 1,740 miles of transmission pipelines in British Columbia and Alberta, as well as 18 mainline compressor stations.

Union Gas owns and operates natural gas transmission, distribution and storage facilities in Ontario. Union Gas distributes natural gas to customers in northern, southwestern and eastern Ontario and provides storage, transportation and related services to utilities and other industry participants in the gas markets of Ontario, Quebec and the Central and Eastern U.S. Union Gas’ underground natural gas storage facilities have a working capacity of approximately 150 Bcf in 20 underground facilities located in depleted gas fields. Its transmission system consists of approximately 3,000 miles of pipeline and six mainline compressor stations. Union Gas’ distribution system consists of approximately 21,000 miles of distribution.

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MHP owns and operates two natural gas storage facilities: Moss Bluff and Egan. The Moss Bluff facility consists of three storage caverns located in Liberty and Chambers counties near Houston, Texas and has access to five pipelines. The Egan facility consists of three storage caverns located in Acadia Parish in the south central part of Louisiana and has access to seven pipeline facilities.

(For a map showing natural gas transmission and storage properties and additional information on Natural Gas Transmission’s properties, see “Business—Natural Gas Transmission” earlier in this section.)

FIELD SERVICES

(For information and a map showing Field Services’ properties, see “Business—Field Services” earlier in this section.)

DUKE ENERGY NORTH AMERICA

The following table provides information about DENA’s generation portfolio in operation as of December 31, 2003.

(For a map showing DENA’s properties, see “Business—Duke Energy North America” earlier in this section.)

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INTERNATIONAL ENERGY

The following table provides information about International Energy’s generation portfolio in operation as of December 31, 2003.

(For additional information and a map showing International Energy’s properties, see “Business—International Energy” earlier in this section.)

OTHER OPERATIONS

(For information regarding Other Operations’ properties, see “Business—Other Operations” earlier in this section.)

OTHER

None of the properties used in Duke Capital’s other business activities are considered material to Duke Capital’s operations as a whole.

Item 3. Legal Proceedings.

For information regarding legal proceedings, including regulatory and environmental matters, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters” and Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies—Litigation” and “Commitments and Contingencies— Environmental.”

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PART II.

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

All of the outstanding limited liability company member interests of Duke Capital are owned by Duke Energy. There is no market for Duke Capital’s limited liability company member interests. Distributions on Duke Capital’s limited liability company member interests will be paid when declared by the Board of Directors. Duke Capital did not pay distributions on its common equity in 2003, 2002 or 2001. Duke Capital continues to review its policy with respect to paying future distributions.

Item 6. Selected Financial Data.(a)

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

INTRODUCTION

Management’s Discussion and Analysis should be read in connection with the Consolidated Financial Statements. When appropriate, the discussion of Duke Capital’s results of operations and financial condition reflects its status as a corporation, not a limited liability company, as of December 31, 2003.

Overview of Business Strategy and Economic Factors.    Duke Capital’s business strategy is to develop integrated energy businesses in targeted regions where Duke Capital’s capabilities in developing energy assets; operating power plants, natural gas liquid (NGL) plants and natural gas pipelines; optimizing commercial operations (including its affiliated real estate operation); and managing risk can provide comprehensive energy solutions for customers and create value for its parent company.

The energy industry and Duke Capital are experiencing a number of challenges, including the substantial imbalance between supply and demand for electricity, the pace of economic recovery, and regulatory and legal uncertainties. In response to these current challenges, Duke Capital is focusing on reducing risks and restructuring its business to be well positioned as the energy marketplace regains its health and vigor. In 2003, Duke Capital established a platform for future growth by selling certain non-strategic assets, cutting expenses and paying down debt, while still funding capital expenditures at its core regulated Natural Gas Transmission business. Duke Capital also resolved many outstanding legal and regulatory issues; reduced the scope of its international operations by announcing its intention to exit the Australian and European markets; and repositioned Duke Energy North America (DENA) to be a more focused, asset-backed merchant business. The repositioning of DENA included discontinuing proprietary trading and announcing its intentions to exit the merchant generation business in the Southeast region.

Duke Capital’s current goals for 2004 include: positive net cash generation; investing in its strongest businesses such as Natural Gas Transmission and Crescent Resources, LLC (Crescent); continuing to size its businesses to market realities; addressing merchant energy issues; strengthening relationships with customers; and further reducing regulatory and legal uncertainty. A major focus for 2004 will be to complete the execution of the plans Duke Capital announced for its merchant and international business, including the sale of its assets in the Southeastern U.S and Australia, and its exit from Europe. Duke Capital also plans to continue to pay down debt in 2004 by $2.3 to $2.8 billion to further strengthen its balance sheet. (Included in the expected 2004 debt reduction amount is approximately $900 million of Australian dollar denominated debt related to International Energy’s Australian operations.) Duke Capital believes it is well-positioned to generate cash in 2004 from asset sales and operations to meet its goals of reducing debt and providing for maintenance and modest expansion.

Duke Capital’s business model provides diversification between stable, less cyclical businesses like Natural Gas Transmission and the traditionally higher-growth and more cyclical energy businesses like DENA, International Energy and Field Services. Additionally, Crescent’s portfolio strategy is diversified between residential, commercial, and multi-family development. Although Duke Capital expects to return to profitability in 2004, all of its businesses can be negatively affected by sustained downturns or sluggishness in the economy, including low market price of commodities, all of which are beyond Duke Capital’s control, and could impair Duke Capital’s ability to meet its goals for 2004.

Declines in demand for electricity as a result of economic downturns would reduce overall electricity sales and lessen Duke Capital’s cash flows; especially as industrial customers reduce production and, thus, consumption of electricity. Natural Gas Transmission is subject to mandated tariff rates and recovery of certain fuel costs. Lower economic output would also cause the Natural Gas Transmission and Field Services businesses to experience a decline in the volume of natural gas shipped through their pipelines, or gathered and processed at their plants, or distributed by their local distribution company, resulting in lower revenue and cash flows. Natural Gas Transmission continues to experience positive renewals of its customer contracts as they expire.

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If negative market conditions persist over time and estimated cash flows over the lives of Duke Capital’s individual assets do not exceed the carrying value of those individual assets, asset impairments may occur in the future under existing accounting rules and diminish results of operations. Furthermore, a change in management’s intent about the use of individual assets (held for use versus held for sale) or a change in fair value of assets held for sale could also result in an impairment. The largest impairments over the past two years have been related to DENA and International Energy and it is estimated that the most significant future risk of impairments also resides within these segments. There is also risk that DENA may not be able to execute its plans to sell its Southeast region merchant plants and that International Energy may not be able to execute its plans to sell the Australian assets, or would obtain lower prices than planned, thus diminishing future cash flow and negatively impacting results of operation.

Duke Capital and its goals for 2004 can also be substantially at risk due to the regulation of its businesses. Duke Capital’s businesses in North America are subject to regulations on the federal and state level. The majority of Duke Capital’s Canadian natural gas assets is also subject to various degrees of federal or provincial regulation and are subject to the same risks. Regulations, applicable to the electric power industry and gas transmission and storage industry, have a significant impact on the nature of the businesses and the manner in which they operate. Changes to regulations are ongoing and Duke Capital cannot predict the future course of changes in the regulatory environment or the ultimate effect that any future changes will have on its business.

Additionally, Duke Capital’s investments and projects located outside of the U.S. expose it to risks related to laws of other countries, taxes, economic conditions, fluctuations in currency rates, political conditions and policies of foreign governments. Changes in these factors are difficult to predict and may impact Duke Capital’s future results. Duke Capital’s recent restructuring, which focuses its non-U.S. operations on only Latin America and Canada, will help mitigate this exposure.

Duke Capital also relies on access to both short-term money markets and longer-term capital markets as a source of liquidity for capital requirements not satisfied by the cash flow from its operations. If Duke Capital is not able to access capital at competitive rates, its ability to implement its strategy could be adversely affected. Market disruptions or a downgrade of Duke Capital’s credit rating may increase its cost of borrowing or adversely affect its ability to access one or more sources of liquidity.

RESULTS OF OPERATIONS

Overview of Drivers and Variances for 2003 and 2002

Year Ended December 31, 2003 as Compared to December 31, 2002.    For 2003, Duke Capital had a net loss of $1,798 million, compared to net income of $321 million in 2002. For Duke Capital, 2003 was a year of transition and one of Duke Capital’s key goals was to establish a platform for future growth by cutting costs, selling non-strategic assets and exiting businesses that were not profitable or were not part of the core business. As a result, Duke Capital incurred significant charges in 2003 related to these activities; including wind-down costs, asset impairments and other charges related to current market conditions and strategic actions taken by management. Significant charges that contributed to the lower results in 2003 included:

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Partially offsetting these 2003 charges were net gains of $279 million on equity investment sales during the year, and when compared to 2002, $612 million of charges in 2002 related to severance, goodwill impairment for International Energy’s European trading and marketing business, the termination of certain turbines on order, impairments of other uninstalled turbines, write-off of project and site development costs, demobilization costs related to deferred plants and a partial impairment of a merchant plant. (For additional information on goodwill impairments, other impairments and related charges, assets held for sale and discontinued operations, see Notes 8, 10 and 11 to the Consolidated Financial Statements)

Other key drivers of the 2003 lower results included:

The above decreases in earnings were partially offset by additional earnings in 2003 from the Westcoast acquisition in March 2002.

Year Ended December 31, 2002 as Compared to December 31, 2001.    In 2002, Duke Capital’s net income was $321 million, compared to $1,350 million in 2001. The decrease was due primarily to:

The above drivers were partially offset by:

For additional information on specific business unit related items, see the segment discussions that follow. For a detailed discussion of interest, taxes and the change in accounting principles, see “Other Impacts on Net Income” at the end of this section.

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Consolidated Operating Revenues

Year Ended December 31, 2003 as Compared to December 31, 2002.    Consolidated operating revenues for 2003 increased $5,106 million, compared to 2002. This change was driven by a $4,364 million increase in Non-regulated Electric, Natural Gas, Natural Gas Liquids and Other revenues, due primarily to increased NGL pricing, and due to the adoption of the final consensus on Emerging Issues Task Force (EITF) Issue No. 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and for Contracts Involved in Energy Trading and Risk Management Activities,” on January 1, 2003. As of that date, Duke Capital began to report revenues and expenses for certain derivative and non-derivative gas and other contracts on a gross basis instead of a net basis. Adopting the final consensus on EITF Issue No. 02-03 did not require a change to prior periods, which had already been changed in 2002 to report amounts on a net basis in accordance with earlier provisions of EITF Issue No. 02-03.

Regulated Natural Gas revenues also increased $742 million due primarily to increased transportation, storage and distribution revenues from assets acquired or consolidated as a part of the acquisition of Westcoast in March 2002.

Year Ended December 31, 2002 as Compared to December 31, 2001.    Consolidated operating revenues for 2002 decreased $2,509 million, compared to 2001. The decrease was due primarily to decreased trading and marketing net margins (included in Non-regulated Electric, Natural Gas, Natural Gas Liquids, and Other Revenues on the Consolidated Statements of Operations) as a result of the negative impacts of a prolonged economic weakness, low commodity prices, continued low volatility levels, reduced spark spreads and decreased market liquidity. The decrease was also a result of decreased revenues on the sale of natural gas, NGLs and other petroleum products. The decrease was partially offset by increased transportation, storage and distribution revenue from assets acquired or consolidated as part of the Westcoast acquisition in March 2002.

For a more detailed discussion of operating revenues, see the segment discussions that follow.

Consolidated Operating Expenses

Year Ended December 31, 2003 as Compared to December 31, 2002.    Consolidated operating expenses for 2003 increased $8,159 million, compared to 2002. Changes in consolidated operating expenses were driven primarily by asset impairments and related charges, and by the same drivers that affected consolidated operating revenues: increased purchase costs for NGLs and the adoption of the final consensus on EITF Issue No. 02-03, and additional expenses due to the acquisition of Westcoast.

Year Ended December 31, 2002 as Compared to December 31, 2001.    Consolidated operating expenses for 2002 decreased $1,330 million, compared to 2001. The decrease was due primarily to a reduction in expenses related to the purchases of natural gas, NGLs and other petroleum products. The decrease was partially offset by increased operating expenses from assets acquired or consolidated as part of the Westcoast acquisition in March 2002, and various asset impairment and severance charges related to market conditions and strategic actions taken by management.

For a more detailed discussion of operating expenses, see the segment discussions that follow.

Consolidated (Losses) Gains on Sales of Other Assets, net

Consolidated (losses) gains on sales of other assets, net was a loss of $203 million for 2003, zero for 2002, and a gain of $238 million for 2001. The loss for 2003 was comprised of a $208 million loss at DENA primarily related to charges on DETM contracts ($127 million) resulting from the wind-down of DETM’s operations, and impairments recorded on assets held for sale, including a 25% undivided interest in the wholly-owned Duke Capital Vermillion facility ($18 million), and stored turbines and related equipment ($66 million). The gain for 2001 was primarily comprised of gains on sales of DENA’s interests in several merchant energy facilities.

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Consolidated Operating Income

Year Ended December 31, 2003 as Compared to December 31, 2002.    For 2003, consolidated operating income decreased $3,256 million, compared to 2002. Lower operating income was driven by decreased operating income at DENA of $3,699 million, due primarily to asset impairments and related charges, as discussed above.

Year Ended December 31, 2002 as Compared to December 31, 2001.    Consolidated operating income for 2002 decreased $1,417 million, compared to 2001. The decrease was driven by a $1,430 million decrease at DENA due to decreased trading and marketing results (as previously described), decreased average prices realized on electric generation, and certain charges taken as a result of 2002 market conditions and strategic actions by management. Also contributing to the decrease was a $318 million decrease at Field Services due to decreased commodity prices such as NGLs and natural gas. Slightly offsetting these decreases was a $488 million increase at Natural Gas Transmission due primarily to the acquisition of Westcoast in March 2002.

For a more detailed discussion of these variances, see segment discussions below.

Consolidated Earnings Before Interest and Taxes From Continuing Operations (EBIT)

Changes in consolidated EBIT were primarily driven by the same changes as consolidated operating income, as discussed above. Consolidated EBIT also includes Other Income and Expenses, which increased $133 million for the year ended December 31, 2003 and $128 million for the year ended December 31, 2002. The increase for 2003 was driven primarily by DENA’s $178 million gain on the sale of its 50% ownership interest in Duke/UAE Ref-Fuel LLC (Ref-Fuel) in June 2003 and Natural Gas Transmission’s $90 million gain on sales of various investments in 2003, offset by foregone earnings from the sale of those investments. The increase for 2002 was driven by Natural Gas Transmission’s $32 million gain on the sale of a portion of its partnership interests in Northern Border Partners L.P. in 2002.

For a more detailed discussion of EBIT, see segment discussions below.

Consolidated EBIT is viewed as a non-Generally Accepted Accounting Principles (GAAP) measure under the rules of the Securities and Exchange Commission (SEC). Duke Capital includes consolidated EBIT in its disclosures because it is one of the measures used by management to evaluate total company and segment performance for continuing operations. On a segment basis, EBIT excludes discontinued operations and represents all profits from continuing operations (both operating and non-operating) before deducting interest and taxes, and is net of the minority interest expense related to those profits. Cash and cash equivalents are managed centrally by Duke Capital. Since the business units do not manage those items, the gains and losses on foreign currency remeasurement associated with cash balances, and third-party interest income on those balances, are generally excluded from the segments’ EBIT. Management considers segment EBIT to be a good indicator of each segment’s operating performance from its continuing operations, as it represents the results of Duke Capital’s ownership interest in operations without regard to financing methods or capital structures.

On a consolidated basis, EBIT is also used as a performance measure and represents the combination of operating income, and other income and expenses as presented on the Consolidated Statements of Operations. The use of EBIT on a consolidated basis follows its use for assessing segment performance, and is consistent with the approach used by its parent, Duke Energy.

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Components of EBIT and Reconciliation of Operating (Loss) Income to Net (Loss) Income

EBIT should not be considered an alternative to, or more meaningful than, net income or operating cash flow as determined in accordance with GAAP. Duke Capital’s EBIT may not be comparable to a similarly titled measure of another company because other entities may not calculate EBIT in the same manner.

Business segment EBIT is summarized in the following table, and detailed discussions follow.

EBIT by Business Segment

The amounts discussed below include intercompany transactions that are eliminated in the Consolidated Financial Statements.

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Natural Gas Transmission

Year Ended December 31, 2003 as Compared to December 31, 2002

Operating Revenues.    Operating revenues for 2003 increased $733 million, compared to 2002. This increase was driven primarily by:

Operating Expenses.    Operating expenses for 2003 increased $549 million, compared to 2002. This increase was driven primarily by:

For the year ended December 31, 2003, Natural Gas Transmission’s operating expenses increased approximately 39% when compared to the same period in 2002, while operating revenues increased approximately 30%. The difference was due to the Westcoast operations that were acquired in March 2002. The operating expenses, as a percentage of operating revenues, of the acquired Westcoast natural gas distribution

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business, are greater than the previously owned natural gas transmission business. Gas commodity costs related to the Westcoast distribution business are recovered from customers by increasing revenues by the amount of gas commodity costs expensed (i.e. flowed through to customers with no incremental profit).

Other Income, net of expenses.    Other income, net of expenses decreased $23 million for 2003, compared to 2002. This decrease was driven primarily by:

Minority Interest Expense.    Minority interest expense increased $12 million for 2003, compared to 2002. This resulted from the recognition of a full year of minority interest expense in 2003, versus only ten months during 2002, from less than 100% owned subsidiaries acquired in the March 2002 acquisition of Westcoast.

EBIT.    EBIT for 2003 increased $156 million, compared to 2002, due primarily to incremental EBIT related to assets acquired or consolidated as part of the March 2002 acquisition of Westcoast, gains on asset sales, and business expansion projects in the U.S. These items were partially offset by earnings in 2002 from operations that were sold in the fourth quarter of 2002 and during 2003, and 2003 severance charges in excess of 2002 amounts.

Matters Impacting Future Natural Gas Transmission’s Results

Natural Gas Transmission plans to continue earnings growth through capital efficient expansions in existing markets, optimization of existing systems, and organizational efficiencies and cost control. Natural Gas Transmission expects modest annual EBIT growth over the next three years from its 2003 EBIT. The average contract life for the U.S. pipelines is nine years. Changes in the Canadian dollar, weather, throughput and the ability to renew service contracts would impact future financial results at Natural Gas Transmission.

Year Ended December 31, 2002 as Compared to December 31, 2001

Operating Revenues.    Operating revenues for 2002 increased $1,404 million, compared to 2001. This increase resulted primarily from increased transportation, storage, and distribution revenue of $1,380 million from assets acquired or consolidated as a part of the Westcoast acquisition in March 2002. Revenues also increased $35 million due to business expansion projects.

Operating Expenses.    Operating expenses for 2002 increased $916 million, compared to 2001. This increase was driven primarily by:

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Other Income, net of expenses.    Other income, net of expenses increased $97 million in 2002, compared to 2001, partly as a result of a $28 million construction fee from an unconsolidated affiliate related to the successful completion of the Gulfstream project in 2002 and associated incremental earnings of $19 million. Also contributing to the increase in other income was a $32 million gain in 2002 on the sale of a portion of Natural Gas Transmission’s limited partnership units in Northern Border Partners, L.P. and an increase in allowance for funds used during construction related to capital projects.

Minority Interest Expense.    Minority interest expense for 2002 resulted from consolidating less than 100% owned subsidiaries acquired in the March 2002 acquisition of Westcoast.

EBIT.    EBIT for 2002 increased $554 million, compared to 2001. As discussed above, this increase resulted primarily from incremental EBIT related to assets acquired or consolidated as part of the acquisition of Westcoast in March 2002. EBIT was also impacted by a construction fee from an unconsolidated affiliate related to the successful completion of Gulfstream, and incremental earnings from Gulfstream which went into service in May 2002. EBIT was impacted, to a lesser extent, by the reversal of reserves as a result of the resolution of certain environmental issues during 2002 and the implementation of SFAS No. 142, resulting in the elimination of goodwill amortization.

Field Services

Year Ended December 31, 2003 as Compared to December 31, 2002

Operating Revenues.    Operating revenues for 2003 increased $2,723 million, compared to 2002. The increase was due primarily to a $2.17 per MMBtu increase in average natural gas prices of approximately $2,250 million and a $0.15 per gallon increase in average NGL prices of approximately $1,195 million. Lower throughput and NGL production partially offset higher revenues by approximately $120 million related to natural gas volume and approximately $380 million related to lower NGL production. The results of cash flow hedging also partially offset higher revenues by approximately $179 million, as hedge contracts locked in an average MMBtu price below market.

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Operating Expenses.    Operating expenses for 2003 increased $2,615 million, compared to 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. Other factors contributing to higher operating expenses included severance charges in 2003 and other employee related expenditure increases totaling approximately $36 million.

Offsetting increases in operating expenses were 2002 charges related to Field Services internal review of balance sheet accounts of approximately $53 million ($37 million at Duke Capital’s 70% share), which may be related to corrections of accounting errors in periods prior to 2002. These adjustments were made in the following five categories: operating expense accruals; gas inventory valuations; gas imbalances; joint venture and investment account reconciliations; and other balance sheet accounts and were immaterial to Duke Capital’s reported results.

Minority Interest Expense.    Minority interest expense at Field Services increased $67 million in 2003, compared to 2002, due to increased earnings from Duke Energy Field Services, LLC (DEFS), Duke Capital’s joint venture with ConocoPhillips. The increase in minority interest expense was not proportionate to the increase in Field Services’ earnings as the Field Services segment includes the results of incremental hedging activities contracted at the Duke Capital corporate level that are not included in DEFS.

EBIT.    EBIT for 2003 increased $44 million compared to the same period in 2002, as a result of better pricing and other factors discussed above.

Matters Impacting Future Field Services’ Results

Field Services has developed significant size and scope in natural gas gathering and processing and NGL marketing and plans to focus on organic growth. Field Services estimates 8% to 10% compounded annual EBIT growth over the next three years. However, Field Services’ revenues and expenses are significantly dependent on prevailing commodity prices for NGLs and natural gas, and past and current trends in price changes of these commodities may not be indicative of future trends.

In 2003, DEFS converted a portion of their keep whole contracts to add a minimum fee clause to the keep whole contract and/or converted the contracts to percent of proceeds contracts. This had the impact of reducing DEFS’ exposure to natural gas prices and reducing the exposure to NGL prices on an unhedged basis. After considering the impacts of hedging, DEFS’ exposure to a one cent per gallon change in the average price of NGLs is $6 million for 2004 and $7 million for 2003.

Year Ended December 31, 2002 as Compared to December 31, 2001

Operating Revenues.    Operating revenues for 2002 decreased $2,375 million, compared to 2001. The decrease was due primarily to a $1.05 per MMBtu decrease in average natural gas prices and a decrease in average NGL prices of approximately $0.07 per gallon. Other factors contributing to lower operating revenues were reduced levels of natural gas gathered and processed/transported (throughput) of 0.2 TBtu per day, and a lower trading and marketing net margin as a result of market conditions.

Operating Expenses.    Operating expenses for 2002 decreased $2,057 million, compared to 2001. The decrease was due primarily to a decrease in average natural gas prices of $1.05 per MMBtu, a $0.07 per gallon decrease in average NGL prices and lower throughput levels. Partially offsetting these decreases were increases in operating and maintenance costs and general administrative costs of $113 million, resulting from increased maintenance on equipment, pipeline integrity and core business process improvements. Additionally, Field Services recorded, as part of its internal review of balance sheet accounts, approximately $53 million of charges ($37 million at Duke Capital’s 70% share) in 2002, as described above.

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Minority Interest Expense.    Minority interest at Field Services decreased $116 million in 2002, compared to 2001, due primarily to decreased earnings from DEFS, Duke Capital’s joint venture with ConocoPhillips. The decrease in minority interest expense was not proportionate to the decrease in Field Services’ earnings as the Field Services segment includes the results of incremental hedging activities contracted at the Duke Capital corporate level that are not included in DEFS.

EBIT.    EBIT for 2002 decreased $187 million, compared to 2001, primarily as a result of the changes in commodity prices and increases in operating, and general and administrative costs.

Duke Energy North America(a)

Year Ended December 31, 2003 as Compared to December 31, 2002

Operating Revenues.    Operating revenues for 2003 increased $2,769 million, compared to 2002. The increase was driven primarily by:

Operating Expenses and Impairments.    Operating expenses and impairments for 2003 increased $6,260 million, compared to 2002. The increase was driven primarily by:

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Losses on Sales of Other Assets, net.    Losses on sales of other assets for 2003 were $208 million due primarily to an $18 million loss on the anticipated sale of the 25% net interest in Vermillion, a $66 million loss on the anticipated sale of turbines and DETM charges related to the sale of contracts of $127 million.

Other Income, net of expenses.    Other income, net of expenses increased $125 million for 2003, compared to 2002. The increase was driven primarily by:

Minority Interest Expense.    Minority interest benefit increased $64 million for 2003 compared to 2002 due to increased losses at DETM.

EBIT.    EBIT for 2003 decreased $3,510 million, compared to 2002. The decrease was due primarily to those factors discussed above: plant impairments, disqualification of certain hedges, the wind-down of DETM, the write-off of goodwill, narrowed spark spreads, and increases in 2002 related to the appreciation of the fair value of the mark-to-market portfolio.

Matters Impacting Future DENA Results

Power generation oversupply in certain regions in the U.S. has resulted in reduced spark spread in many markets. In addition the reduction of major wholesale marketing and trading participants has resulted in a decrease in overall power and gas market liquidity. DENA has reduced its merchant exposure and has simplified its business strategy to reposition DENA to maximize the value of its assets focusing on natural gas and power.

If negative market conditions persist over time and estimated cash flows over the lives of DENA’s individual assets do not exceed the carrying value of those individual assets, asset impairments may occur in the future. Furthermore, a change in management’s intent about the use of individual assets (held for use versus held for sale) or a change in fair value of assets held for sale could also impact an impairment analysis. As of

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December 31, 2003, DENA had written off all of its goodwill but had $4,386 million in total net property, plant and equipment (including the Southeastern U.S. plants), and $164 million in assets held for sale.

Due to the current depressed spark spread environment and the resulting lack of opportunities to capture value in the marketplace above the power production already sold, DENA expects to incur an EBIT loss of approximately $300 million in 2004.

Year Ended December 31, 2002 as Compared to December 31, 2001

Operating Revenues. Operating revenues for 2002 decreased $1,462 million, compared to 2001. Significant increases in the megawatt capacity of generation assets in operation were more than offset by decreases in the average price realized for electricity generated, resulting in a reduction in operating revenue of $415 million. In addition, revenues decreased $1,017 million as a result of a decrease in the trading and marketing net margin. DENA’s results reflected the negative impacts of a prolonged economic weakness, low commodity prices, continued low volatility levels (measures of the fluctuation in the prices of energy commodities or products), reduced spark spreads, and decreased market liquidity

Operating Expenses and Impairments.    Operating expenses for 2002 decreased $261 million, compared to 2001. The decrease was driven primarily by:

Gains on Sales of Other Assets, net.    Gains on sales of other assets of $229 million in 2001 resulted from the sale of interests in several generating facilities.

Other Income, net of expenses.    Other income, net of expenses, increased $25 million in 2002 compared to 2001. The increase was due primarily to settlements received on disputed items at two generating facilities and interest income related to a note receivable associated with the sale of an interest in a generating facility.

Minority Interest (Benefit) Expense.    Minority interest benefit increased $87 million for 2002 compared to 2001, due to increased losses at DETM.

EBIT.    EBIT for 2002 decreased $1,318 million compared to 2001. The decrease was due primarily to those factors discussed above: decreased trading margins, a decrease in the average price realized on electric generation, a decrease in the number of generation facilities sold in 2002, and certain charges taken as a result of market conditions in 2002 and strategic actions taken by management.

As a result of Duke Capital’s findings in the course of its investigation related to the SEC inquiry on “round trip” trades (see Note 16 to the Consolidated Financial Statements), DENA identified accounting issues that justified adjustments which reduced its EBIT by $11 million during 2002. An additional $2 million charge was recorded in other Duke Capital business segments related to these findings.

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International Energy