DUKE CAPITAL CORP - 10-K Annual Report

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 common shares 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.

Duke Capital Corporation’s 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 the Company’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 the Company’s control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. Those factors include:

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 the Company has described. The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Duke Capital Corporation (collectively with its subsidiaries, the Company) is a wholly owned subsidiary of Duke Energy Corporation (Duke Energy) and serves as the parent of certain of Duke Energy’s non-utility and other operations. The Company provides financing and credit enhancement services for its subsidiaries and conducts its operations through six business segments described below.

Natural Gas Transmission provides transportation and storage of natural gas for customers throughout the East Coast and Southern U.S., and in Canada. Natural Gas Transmission also provides distribution service to retail customers in Ontario and Western Canada, and gas gathering and processing services to customers in Western Canada. Natural Gas Transmission does business primarily through Duke Energy Gas Transmission Corporation. The Company acquired Westcoast Energy Inc. (Westcoast) on March 14, 2002 (see Note 2 to the Consolidated Financial Statements, “Business Acquisitions and Dispositions”). Duke Energy Gas Transmission’s natural gas transmission and storage operations in the U.S. are subject to the Federal Energy Regulatory Commission’s (FERC’s) and the Texas Railroad Commission’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, the Ontario Energy Board and the British Columbia Utilities Commission.

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 the Company. Field Services gathers natural gas from production wellheads in Western Canada and 11 contiguous 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.

Duke Energy North America (DENA) develops, operates and manages merchant power generation facilities and engages in commodity sales and services related to natural gas and electric power. DENA conducts business throughout the U.S. and Canada through Duke Energy North America, LLC and Duke Energy Trading and Marketing, LLC (DETM). DETM is approximately 40% owned by ExxonMobil Corporation and approximately 60% owned by the Company.

International Energy develops, operates and manages natural gas transportation and power generation facilities, and engages in sales and marketing of natural gas and electric power outside the U.S. and Canada. It conducts operations primarily through Duke Energy International, LLC (DEI) and its activities target power generation in Latin America, power generation and natural gas transmission in Asia-Pacific and natural gas marketing in Northwest Europe.

Other Energy Services is composed of diverse energy businesses, operating primarily through Duke/Fluor Daniel (D/FD) and Energy Delivery Services (EDS). 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 the Company and Fluor Enterprises, Inc., a wholly owned subsidiary of Fluor Corporation. 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). This component was excluded from the sale of DE&S to Framatome ANP, Inc. on May 1, 2002. Other Energy Services also retained other portions of DE&S that were not part of the sale, as well as a portion of DukeSolutions, Inc. (DukeSolutions) that was not sold on May 1, 2002 to Ameresco, Inc. DE&S and

DukeSolutions were included in Other Energy Services through the dates of their sales. (See Note 2 to the Consolidated Financial Statements, “Business Acquisitions and Dispositions,” for additional information on the sales of DE&S and DukeSolutions.)

Duke Ventures is composed of other diverse businesses, operating primarily through Crescent Resources, LLC (Crescent), DukeNet Communications, LLC (DukeNet) and Duke Capital Partners, LLC (DCP). 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 selected educational, governmental, financial and health care entities. DCP, a wholly owned merchant finance company, provides debt and equity capital and financial advisory services primarily to the energy industry. In March 2003, the Company announced that it will exit the merchant finance business at DCP in an orderly manner.

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

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.

Asset Optimization. The process of maximizing the returns on a portfolio of assets through the use of hedging strategies involving energy contracts.

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. Often used to hedge risk, derivatives involve the trading of rights or obligations, but not the direct transfer of property.

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

Estimated Available Production. Estimated physical generation capability of owned generation assets as adjusted for scheduled maintenance, transmission availability and an estimate for unplanned outages.

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.

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.

Greenfield Development. The development of a new power generating facility on an undeveloped site.

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.

Integrated Logistics. The coordinated effort to optimally deliver physical product to the end user.

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

Liquid Market. A market in which selling and buying can be accomplished with minimal price change; such a market has a high level of trading activity and open interest.

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 physical positions through arbitrage, especially on contractual assets such as storage, transportation, generation and transmission.

Mark-to-Market. The process whereby derivatives or energy trading contracts are adjusted to market value, and the unrealized gain or loss is recognized in current earnings and on the balance sheet.

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 throughout the value chain.

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

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

Tolling. Process whereby a party moves 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, local distribution companies, 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.

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

Natural Gas Transmission’s significant investments include Gulfstream Natural Gas System, LLC (Gulfstream), an interstate natural gas pipeline system owned and operated jointly by the Company and The Williams Companies, Inc. The Gulfstream gas pipeline has a capacity of 1.1 billion cubic feet (Bcf) of natural gas per day and transports gas from the Mobile Bay area, across the Gulf of Mexico, to growing gas markets in south and central Florida. Gulfstream went in-service in May 2002.

Alliance Pipeline, in which Natural Gas Transmission owns a 23.6% equity interest, is a natural gas transmission pipeline with a daily transportation capacity of 1.3 Bcf of natural gas per day from northeastern British Columbia, through Alberta and Saskatchewan, to a terminus near Chicago, Illinois. In March 2003, the Company entered into an agreement to sell its 23.6% ownership interest in Alliance Pipeline, Alliance Canada Marketing and the Aux Sable natural gas liquids plant to Enbridge Inc. and Fort Chicago Energy Partners L.P. for approximately $245 million. The transaction is expected to close by April 2003, with the exception of a small ownership interest related to the U.S. segment of Alliance Pipeline, which is expected to close in October 2003. (See Note 18 to the Consolidated Financial Statements, “Subsequent Events.”)

Vector Pipeline, in which Natural Gas Transmission owns a 30% equity interest, is a natural gas transmission pipeline from a point near Chicago, Illinois to Union Gas Limited’s (Union Gas) Dawn hub in Ontario. The Vector Pipeline connects with the Alliance Pipeline and the Northern Border Pipeline near Chicago, Illinois and delivers gas into markets in Indiana, Michigan and Ontario. The Vector Pipeline has a capacity of approximately 1Bcf per day.

For 2002, Natural Gas Transmission’s proportional throughput for its pipelines totaled 3,160 trillion British thermal units (TBtu), compared to 1,781 TBtu in 2001, a 77% increase mainly due to the 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. (See natural gas delivery statistics under “Operating Statistics” in this section.) A majority of Natural Gas Transmission’s contracted transportation volumes are under long-term firm service agreements with local distribution company (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 deliveries are in Canada (primarily the Western and Atlantic regions of Canada, plus Ontario and Quebec), and the U.S. (primarily Connecticut, Maine, Massachusetts, Michigan, New Jersey, New York, Pennsylvania, Rhode Island, Tennessee and Virginia). Natural Gas Transmission provides distribution services through its Union Gas and Pacific Northern Gas (PNG) subsidiaries. Union Gas’ distribution service area encompasses approximately 400 communities and 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 20,000 miles of distribution lines serving approximately 1.17 million residential, commercial and industrial customers. PNG serves approximately 39,000 customers in west-central and northeastern British Columbia.

Natural Gas Transmission’s pipeline systems consist of over 18,000 miles of transmission pipelines. The pipeline systems receive natural gas from major North American producing regions for delivery to markets primarily in British Columbia, the Western U.S., Ontario, the Pacific Northwest, and the Mid-Atlantic, Southeastern and New England states. (For detailed descriptions of Natural Gas Transmission’s pipeline systems, see “Properties, Natural Gas Transmission.”)

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 29 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 (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 liquefied natural gas 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.

Natural Gas Transmission’s pipeline, storage and field services 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 serving the Mid-Atlantic, Northeastern, Southeastern and Pacific Northwestern states, Western Canada, Ontario and along Canada’s Atlantic coast. 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.

Union Gas’ sales to industrial customers are affected by 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 UnionGas 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.

Natural gas competes with other forms of energy available to the Company’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 capability to convert to alternative fuels, weather and other factors affect the demand for natural gas in the areas served by the Company.

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. Texas Eastern, Algonquin Gas Transmission Company (Algonquin), ETNG, Gulfstream, Alliance Pipeline, Vector Pipeline, MHP and Maritimes & Northeast Pipeline (M&N Pipeline) hold certificates of public convenience and necessity issued by the FERC, authorizing them to construct and operate pipelines, facilities and related properties, and to transport and store natural gas via interstate commerce. The MHP storage assets located in Texas are also subject to the Texas Railroad Commission’s rules and regulations.

As required by FERC Order 636, Natural Gas Transmission’s U.S. pipelines operate as open-access transporters of natural gas, providing unbundled firm and interruptible transportation and storage services on an equal basis for all gas supplies, whether purchased from the pipeline or from another gas supplier.

The FERC regulations govern access to regulated natural gas transmission customer data by non-regulated entities and to services provided between regulated and non-regulated affiliated entities. These regulations affect the activities of DENA 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 U.S. Department of Transportation (DOT) concerning pipeline safety. DOT regulations have incorporated certain provisions of the Natural Gas Pipeline Safety Act of 1968, which regulates gas pipeline

and liquefied natural gas plant safety requirements. In addition, the DOT is developing regulations that will require pipelines to implement integrity management programs, including more frequent inspections and other safety protections in areas where the consequences of potential pipeline accidents pose the greatest risk to people and their property. The Pipeline Safety Improvement Act of 2002, which was enacted on December 17, 2002, establishes mandatory inspections of high-consequence areas for all U.S. oil and natural gas pipelines within 10 years.

The natural gas gathering, processing, transmission, storage and distribution operations in Canada are subject to regulation by the National Energy Board and provincial agencies in Canada, such as the Ontario Energy Board 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 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. Field Services gathers natural gas from production wellheads in Western Canada and 11 contiguous 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 60,000 miles of natural gas gathering systems with approximately 35,000 active receipt points. Field Services conducts its operations primarily through DEFS, which is approximately 30% owned by ConocoPhillips.

The Company and ConocoPhillips are currently in discussions regarding possible changes to DEFS’ ownership. Member interests in DEFS are currently held approximately 70% by the Company and approximately 30% by ConocoPhillips. The discussions are focused on a possible change in the ownership structure that would be driven by the possible contribution by ConocoPhillips of certain midstream natural gas assets to DEFS. There is no certainty that these discussions will lead to a transaction in which ConocoPhillips would contribute these assets to DEFS or what might be the terms of such a transaction.

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 60 natural gas processing facilities that it owns and operates and at 11 third-party operated facilities in which it has an equity interest.

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 11 processing facilities that it owns and operates and at two 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 7.5 billion-cubic-foot 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. 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 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 NGL prices, which decreased approximately 16% in 2002 compared to 2001. (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. (See Field Services’ “Operating Statistics” in this section.)

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. Competition for sales to customers is based primarily upon reliability, services offered, and price of delivered natural gas and NGLs.

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, they 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 DOT and state transportation agencies. The regulations from these agencies, which incorporate certain provisions of the Natural Gas Pipeline Safety Act, control the design, installation, testing, construction, operation, replacement and management of Field Services’ pipeline operations.

In addition, Field Services’ interstate natural gas pipelines are subject to the regulations of the DOT concerning pipeline safety. The DOT is developing regulations that will require pipelines to implement integrity management programs, including more frequent inspections and other safety protections in areas where the consequences of potential pipeline accidents pose the greatest risk to people and their property. The Pipeline Safety Improvement Act of 2002, which was enacted on December 17, 2002, establishes mandatory inspections of high-consequence areas for all U.S. oil and natural gas pipelines within 10 years.

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

DENA develops, operates and manages merchant power generation facilities and engages in commodity sales and services related to natural gas and electric power. DENA conducts business throughout the U.S. and Canada through Duke Energy North America, LLC and DETM. DETM is approximately 40% owned by ExxonMobil Corporation and approximately 60% owned by the Company.

DENA is an integrated energy business that develops, owns and manages a portfolio of merchant generation facilities. Through its portfolio management strategy, DENA invests and divests in selected markets as conditions warrant. DENA captures additional value by combining its project development, commercial and risk management expertise with the technical and operational skills of other Company business units to build and manage projects with maximum efficiency. DENA also supplies competitively priced energy, integrated logistics and asset optimization services, as well as risk management products, to wholesale energy customers.

DENA currently owns or operates approximately 14,157 net megawatts (MW) of operating generation and has approximately 1,860 net MW of projects under construction, slated for completion to meet summer 2003 peak demand. In addition, in September 2002, DENA deferred construction on approximately 2,450 net MW of projects, including its Moapa, Grays Harbor and Luna plants. In March 2003, the Company entered into an agreement to sell its 50% ownership interest in Duke/UAE Ref-Fuel LLC for $306 million to Highstar

Renewable Fuels LLC. Duke/UAE Ref-Fuel LLC owns American Ref-Fuel Company LLC, a holding company for six waste-to-energy facilities in the northeastern U.S. The transaction is subject to a number of conditions including certain regulatory approvals.

DETM markets natural gas, electricity and other energy-related products to a wide range of customers across North America. The Company owns a 60% interest in DETM’s natural gas and electric power trading operations, with ExxonMobil Corporation owning a 40% minority interest.

DETM markets natural gas primarily to LDCs, electric power generators (including DENA’s generation facilities), municipalities, large industrial end-users and energy marketing companies. DETM markets electricity to investor-owned utilities, municipal power generators and other power marketers. DETM 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.

Natural gas marketing operations encompass both on-system and off-system supplies. On system, DETM generally purchases natural gas from producers connected to Field Services’ facilities and delivers the gas to an intrastate or interstate pipeline for redelivery to another customer, using Natural Gas Transmission’s pipelines when prudent. Off system, DETM purchases natural gas from producers, pipelines and other suppliers not connected with the Company’s facilities for resale to customers. DETM was previously committed to market substantially all of ExxonMobil’s U.S. and Canadian natural gas production through 2006. However, the Company and ExxonMobil subsidiaries have reached an agreement to modify DETM’s gas supply from the ExxonMobil subsidiaries, so that a substantial amount of the gas will be released to ExxonMobil beginning as early as March 2003.

DETM’s electricity marketing operations involve purchasing electricity from third-party suppliers and from DENA’s domestic generation facilities for resale to customers.

The vast majority of DETM’s portfolio of short-term and long-term sales agreements incorporates market-sensitive pricing terms. Long-term gas purchase agreements with producers also generally include market-sensitive pricing provisions. Purchase and sales commitments involving significant price and location risk are generally hedged with offsetting commitments and commodity futures, swaps and options. (For information concerning DETM’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 6 to the Consolidated Financial Statements, “Risk Management Instruments, Hedging Activities and Credit Risk.”)

DETM’s activities can fluctuate in response to seasonal demand for electricity, natural gas and other energy-related commodities. (See “Operating Statistics” in this section.)

DETM competes for natural gas supplies and in marketing natural gas, electricity and other energy-related commodities. Competitors include major integrated oil companies, major interstate pipelines and their marketing affiliates, brokers, marketers and distributors, electric utilities, certain financial institutions engaged in commodity trading 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.

DENA experiences substantial competition from utilities as well as other merchant electric generation companies in the U.S.

Most of DENA’s and DETM’s operations are subject to market-based rate regulation. However, to the extent that DENA’s generating stations in California sell electricity to the California Independent System Operator under “reliability must run” agreements, those sales are made at FERC regulated rates.

DENA’s and DETM’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.

From June 20, 2002 through October 30, 2002, the price at which DETM could sell wholesale electricity in the Western Electricity Coordinating Council was subject to a floating price cap imposed by a FERC order. However, subject to the FERC’s approval, DETM could sell at prices in excess of the cap in effect at the time if it provided justification. On October 31, 2002, the FERC imposed a soft price cap for the sale of energy throughout the Western Electricity Coordinating Council of $250 per MW hour.

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 13 to the Consolidated Financial Statements, “Commitments and Contingencies – Litigation – Western Power Disputes” 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 will purport 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. The Company 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 federal, state and local environmental regulations. (For a discussion of environmental regulation, see “Environmental Matters” in this section.)

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

From its platform of assets, International Energy provides customers with energy supply at competitive prices, manages the logistics associated with natural gas and power 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, large industrial companies, governments, gas and oil producers and mining operations. 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, optimizing the output and efficiency of its various facilities, controlling and reducing costs and divesting selected assets.

International Energy owns, operates or has substantial interests in approximately 4,792 net MW of generation facilities and 2,400 miles of pipeline systems in operation. The following map shows the locations of International Energy’s worldwide energy facilities, including projects under construction or under contract. The capacities shown in the map are gross MW values, for net MW values see “Properties, International Energy.”

International Energy’s operations are subject to country and region-specific market and competition regulations. Commonly addressed regulatory issues include rules, rates and tariffs governing open and competitive access to gas and power transmission grids, rules for merchant power plant dispatch and remuneration, and rules that support the emergence of competitive gas and power trading and marketing.

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

Other Energy Services is composed of diverse energy businesses, operating primarily through D/FD and EDS. Prior to the sales of DE&S on May 1, 2002, and DukeSolutions on May 1, 2002, those businesses were included in Other Energy Services. (For more information on the sales, see Note 2 to the Consolidated Financial Statements, “Business Acquisitions and Dispositions.”) Other Energy Services also includes other portions of DE&S and DukeSolutions that were not part of the sales.

D/FD, operating through several entities, provides full-service siting, permitting, licensing, engineering, procurement, construction, start-up, operating and maintenance services for fossil-fired plants, both domestically and internationally. Subsidiaries of the Company and Fluor Enterprises, Inc. each own 50% of D/FD.

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 DE&S and was excluded from the sale of DE&S.

D/FD competes with major companies who provide engineering, procurement, construction, start-up and maintenance services for fossil fueled power generation facilities. EDS’ competition includes companies that provide engineering, procurement, construction and maintenance services for transmission lines, distribution lines and substation facilities.

Other Energy Services 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.)

Duke Ventures is composed of other diverse businesses, primarily operating through Crescent, DukeNet and DCP.

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, 2002, Crescent owned 2.6 million square feet of commercial, industrial and retail space, with an additional 0.6 million square feet under construction. This portfolio included 1.3 million square feet of office space, 1.3 million square feet of warehouse space and 0.6 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. In 2002, Crescent had six multi-family communities, including three operating properties and three properties under development. On December 31, 2002, Crescent also managed approximately 129,000 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, provides financing, investment banking and asset management services to wholesale and commercial markets in the energy and real estate industries. In March 2003, the Company announced that it will exit the merchant finance business at DCP in an orderly manner.

The Company 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 the Company include, but are not limited to:

(For more information on environmental matters involving the Company, including possible liability and capital costs, see Note 13 to the Consolidated Financial Statements, “Commitments and Contingencies — Environmental.”)

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 the Company.

For a discussion of the Company’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 6 to the Consolidated Financial Statements, “Business Segments” and “Risk Management Instruments, Hedging Activities and Credit Risk.”

On December 31, 2002, the Company had approximately 12,000 employees. A total of 2,279 operating and maintenance employees were represented by unions. This amount consists of the following:

The officers and directors of the Company consist of certain executive officers of Duke Energy. Duke Energy has entered into employment agreements with certain key executives. Additionally, the Company’s business units maintain their own management structure.

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 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 over 100 miles into the Gulf of Mexico and include approximately 470 miles of Texas Eastern’s pipelines.

Algonquin’s 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 1,070 miles of pipeline with seven compressor stations.

ETNG’s transmission system crosses Texas Eastern’s system at two points in Tennessee and consists of two mainline systems totaling approximately 1,185 miles of pipeline in Tennessee and Virginia, with 18 compressor stations.

M&N Pipeline’s transmission system extends approximately 800 miles from producing fields in Nova Scotia through New Brunswick, Maine, New Hampshire and Massachusetts. It has two compressor stations on the system.

The British Columbia Pipeline System (BC Pipeline) consists of the field services division, with 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 at Fort Nelson, Taylor, Pine River and in the Sikanni area northwest of Fort St. John, with a total contractible capacity of approximately 1.8 Bcf of residue gas per day; and three elemental sulphur recovery plants located at Fort Nelson, Taylor and Pine River. 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 service area encompasses approximately 400 communities. Its distribution system consists of approximately 20,000 miles of distribution lines serving approximately 1.17 million residential, commercial, and industrial customers.

PNG is a gas transmission and distribution utility which serves customers in west-central and northeastern British Columbia of which the Company owns 40% of the non-voting participating stock and 100% of the voting participating stock. PNG’s transmission system connects with the BC Pipeline system near Summit Lake, British Columbia and extends approximately 370 miles to the West Coast of British Columbia. In addition, PNG owns and operates distribution facilities in various communities located throughout its service area.

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.”)

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

DENA had approximately 1,860 net MW under construction for completion to meet summer 2003 peak demands. In addition to facilities in operation or under construction, in September 2002, DENA deferred construction on approximately 2,450 net MW of projects, including its Moapa, Grays Harbor and Luna plants.

Company LLC, a holding company for six waste-to-energy facilities in the northeastern U.S. The transaction is subject to a number of conditions including certain regulatory approvals.

(For additional information and a map showing DENA’s properties, see “Business, Duke Energy North America.”)

As of December 31, 2002, International Energy’s generation portfolio in operation included:

As of December 31, 2002, DEI had approximately 165 net MW under construction in Latin America and owned approximately 1,340 miles of pipeline systems in Australia. Additionally, DEI had an 11.84% ownership interest in 855 miles of pipeline systems in Australia and a 37.83% ownership interest in 190 miles of pipeline systems in Peru. Also, as of December 31, 2002, DEI had a 25% indirect interest in National Methanol Company, which owns and operates a methanol and MTBE (methyl tertiary butyl ether) business in Jubail, Saudi Arabia. In addition, DEI had a 50% non-controlling ownership interest in the Campeche project, a natural gas compression facility in Mexico and a 30% indirect interest in the Cantarell project, a large nitrogen extraction facility in Mexico.

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

(For information regarding Duke Ventures’ properties, see “Business, Duke Ventures” earlier in this section.)

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

For information regarding legal proceedings, including regulatory and environmental matters, see Note 13 to the Consolidated Financial Statements, “Commitments and Contingencies — Litigation” and “Commitments and Contingencies — Environmental.”

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

All of the outstanding common stock of the Company is owned by Duke Energy. There is no market for the Company’s common stock. Dividends on the Company’s common stock will be paid when declared by the Board of Directors. The Company did not pay dividends on its common stock in 2002, 2001 or 2000. Currently, the Company is reviewing its dividend policy with respect to paying future dividends.

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

Management’s Discussion and Analysis should be read in connection with the Consolidated Financial Statements.

Business Segments. Duke Capital Corporation (collectively with its subsidiaries, the Company) is a wholly owned subsidiary of Duke Energy Corporation (Duke Energy) and serves as the parent of certain of Duke

Energy’s non-utility and other operations. The Company provides financing and credit enhancement services for its subsidiaries and conducts its operations through six business segments described below.

Natural Gas Transmission provides transportation and storage of natural gas for customers throughout the East Coast and Southern U.S., and in Canada. Natural Gas Transmission also provides distribution service to retail customers in Ontario and Western Canada and gas gathering and processing services to customers in Western Canada. Natural Gas Transmission does business primarily through Duke Energy Gas Transmission Corporation. The Company acquired Westcoast Energy Inc. (Westcoast) on March 14, 2002 (see Note 2 to the Consolidated Financial Statements). Duke Energy Gas Transmission’s natural gas transmission and storage operations in the U.S. are subject to the Federal Energy Regulatory Commission’s (FERC’s) and the Texas Railroad Commission’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, the Ontario Energy Board and the British Columbia Utilities Commission.

International Energy develops, operates and manages natural gas transportation and power generation facilities, and engages in sales and marketing of natural gas and electric power outside the U.S. and Canada. It conducts operations primarily through Duke Energy International, LLC and its activities target power generation in Latin America, power generation and natural gas transmission in Asia-Pacific and natural gas marketing in Northwest Europe.

governmental, financial and health care entities. DCP, a wholly owned merchant finance company, provides debt and equity capital and financial advisory services primarily to the energy industry. In March 2003, the Company announced that it will exit the merchant finance business at DCP in an orderly manner.

Business Strategy. The Company’s business strategy is to develop integrated energy businesses in targeted regions where the Company’s capabilities in developing energy assets; operating power plants, NGL plants and natural gas pipelines; optimizing commercial operations; and managing risk can provide comprehensive energy solutions for customers and create value for shareholders.

The energy industry and the Company 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, the Company is focusing on reducing risks and restructuring its business to be well positioned as the energy marketplace regains its health and vigor. The Company’s current goals include: positive net cash generation, investing in its strongest business sectors, sizing its businesses to market realities, addressing merchant energy issues, strengthening relationships with customers, and reducing regulatory and legal uncertainty. The Company’s business model provides diversification between stable, less cyclical businesses like Natural Gas Transmission and Duke Ventures and the traditionally higher-growth and more cyclical energy merchant businesses like DENA, International Energy and Field Services.

Natural Gas Transmission plans to continue earnings growth by developing expanded services and incremental projects that meet increasing customer needs. Pipeline growth will be driven by customer expansions in the current market area. Growth will also come from additions to the distribution customer base at Union Gas Limited (Union Gas), a wholly owned subsidiary of the Company and Westcoast, and through expansion of natural gas storage. Earnings for 2003 will benefit from inclusion of a full year of Westcoast earnings and the continued emphasis on operational efficiency.

Field Services has developed significant size and scope in natural gas gathering and processing and NGL marketing and plans to focus on organic growth.

DENA has invested in energy assets in U.S. and Canadian markets, and provides energy supply, structured origination, risk management and commercial optimization services to large energy customers, energy aggregators and other wholesale companies. Generation oversupply, low spark spreads and volatility, as well as the lack of an economic recovery will delay good returns for the merchant energy business in the near term. In response to market conditions, DENA will continue to seek opportunities to reduce the Company’s exposure to merchant energy, and may divest certain assets, in whole or in part, when value can be realized. DENA continues to view the energy sales and marketing business as a vital component of a healthy wholesale energy marketplace, and its energy sales and marketing activity will be focused primarily on its asset positions.

Other Energy Services will continue to provide customers with a variety of engineering, operating, procurement and construction services in areas related to energy assets.

Duke Ventures plans moderate growth, primarily through its real estate business by developing regional opportunities and by applying extensive experience to new project development.

The Company’s business strategy and growth expectations may vary significantly depending on many factors, including, but not limited to, the pace and direction of industry restructuring, regulatory constraints, acquisition and divestiture opportunities, market volatility and economic trends.

In 2002, net income was $264 million compared to $1,356 million in 2001. The decrease was due primarily to a 53% decrease in earnings before interest and taxes (EBIT), as described below, and a $318 million increase in interest expense due primarily to the debt assumed in the acquisition of Westcoast. These changes were partially offset by the prior year’s one-time net-of-tax charge of $69 million related to the cumulative effect of a change in accounting principle for the January 1, 2001 adoption of Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities” (see Note 1 to the Consolidated Financial Statements). Also offsetting the decrease in net income was a $219 million decrease in minority interest expense in 2002, as discussed in the following sections.

Net income increased $430 million in 2001 to $1,356 million from 2000 earnings of $926 million. The increase was due primarily to a 34% increase in EBIT, as described below.

Operating income for 2002 was $1,101 million, compared to $2,886 million in 2001 and $1,729 million in 2000. EBIT was $1,456 million in 2002, $3,123 million in 2001 and $2,331 million in 2000. Operating income and EBIT are affected by the same fluctuations for the Company and each of its business segments. (See Note 3 to the Consolidated Financial Statements for more information on business segments.) The following table shows the components of EBIT and reconciles EBIT to operating and net income.

Total operating revenues for the year ended December 31, 2002 decreased $3,199 million to $11,359 million from $14,558 for the year ended December 31, 2001. The decrease was due primarily to decreased trading and marketing net margins 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.

Total operating expenses for the year ended December 31, 2002 decreased $1,652 million to $10,258 million from $11,910 million for the year ended December 31, 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 current market conditions and strategic actions taken by management.

EBIT for the year ended December 31, 2002 decreased $1,667 million to $1,456 million from $3,123 million for the year ended December 31, 2001. This decrease was due primarily to decreased trading and marketing results. The decrease in EBIT was also impacted by various charges at several business units, such as asset impairments and severance costs, related to current market conditions and strategic actions taken by management. The decrease in EBIT was also attributable to a decline in the average price realized for electricity generated by the Company’s merchant plants. These decreases were partially offset by increased transportation, storage and distribution revenues from assets acquired or consolidated as a part of the acquisition of Westcoast in March 2002.

EBIT for the year ended December 31, 2001 increased $792 million to $3,123 million from $2,331 million for the year ended December 31, 2000. This increase was due primarily to increased trading and marketing margins due to significant volatility in the marketplace during 2001. This increase was also attributable to increased gains on the sales of the Company’s interests in several generating facilities at DENA. The increase was impacted, to a lesser extent, by increased earnings resulting from reporting a full year of operations in 2001 as compared to 2000 for several operating facilities.

EBIT is the primary performance measure used by management to evaluate segment performance. On a segment basis, it includes all profits (both operating and non-operating) before deducting interest and taxes, and is net of the minority interest expense related to those profits. Management believes EBIT is a good indicator of each segment’s operating performance. As an indicator of the Company’s operating performance, EBIT should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with generally accepted accounting principles (GAAP). The Company’s EBIT may not be comparable to a similarly titled measure of another company.

Management views the sale of operating assets and equity earnings from operating assets as important sources of revenue for the Company and its subsidiaries. Therefore, for internal management purposes, these items are reflected in segment revenues. For external reporting purposes, these items are excluded from revenues and appropriately reflected in separate captions on the Consolidated Statements of Income.

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

Other Operations primarily includes certain unallocated corporate costs and elimination of intersegment profits. The amounts discussed below include intercompany transactions that are eliminated in the Consolidated Financial Statements.

Operating Revenues. Operating revenues for the year ended December 31, 2002 increased $1,497 million to $2,602 million from $1,105 million for the year ended December 31, 2001. This increase resulted primarily from increased transportation, storage, and distribution revenue of $1,419 million from assets acquired or consolidated as a part of the Westcoast acquisition in March 2002. (See Note 2 to the Consolidated Financial Statements.)

Revenues also increased $35 million due to business expansion projects. Operating revenues for 2002 also included a $28 million construction fee from an unconsolidated affiliate related to the successful completion of Gulfstream Natural Gas System, LLC (Gulfstream), a 581-mile pipeline system, 50% owned by the Company which went into service in May 2002. Also contributing to the increase in operating revenues for 2002 was a $32 million gain on the sale of a portion of Natural Gas Transmission’s limited partnership units in Northern Border Partners, LP.

Operating Expenses. Operating expenses for the year ended December 31, 2002 increased $916 million to $1,420 million from $504 million for the year ended December 31, 2001. This increase was due primarily to incremental operating expenses of $877 million related to the gas transmission, storage and distribution assets acquired or consolidated in the Westcoast acquisition in March 2002. Operating expenses were impacted, to a lesser extent, as a result of severance costs of $9 million associated with a workforce reduction in 2002 and incremental operating expenses associated with business expansion projects. Partially offsetting the increase in operating expenses were the reversal of reserves of $25 million related to certain environmental issues that were resolved in 2002 and reduced goodwill amortization of $14 million in 2002 as a result of the implementation of SFAS No. 142, “Goodwill and Other Intangible Assets.”

Other Income, Net of Expenses. Other income, net of expenses increased $16 million in 2002 compared to 2001 due in part to an increase in allowance for funds used during construction related to capital projects.

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

EBIT. EBIT for the year ended December 31, 2002 increased $566 million to $1,174 million from $608 million for the year ended December 31, 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.

Operating Revenues. Operating revenues for the year ended December 31, 2001 decreased slightly to $1,105 million from $1,131 million for the year ended December 31, 2000. This decrease resulted primarily from reduced revenues of $112 million resulting from rate reductions, which became effective in December 2000 at Texas Eastern Transmission, LP (Texas Eastern) to reflect lower recovery requirements for operating costs, primarily system fuel and FERC Order 636 transition costs. These rate reductions are offset in reduced operating expenses. The decrease in revenues was partially offset by $57 million of incremental revenues from East Tennessee Natural Gas Company (ETNG) and Market Hub Partners (MHP) (acquired in March 2000 and September 2000, respectively), as a result of reporting an entire year of operations in 2001 as compared to 2000 and pre-operational earnings related to allowance for funds used during construction of $18 million from the Gulfstream project.

Operating Expenses. Operating expenses for the year ended December 31, 2001 decreased $77 million to $504 million from $581 million for the year ended December 31, 2000. This decrease was due primarily to lower operating costs of $112 million at Texas Eastern which related to the reduced rates described above. This reduction was partially offset by increased expenses of $33 million related to a full year of operations of ETNG and MHP in 2001.

EBIT. EBIT for the year ended December 31, 2001 increased $46 million to $608 million from $562 million for the year ended December 31, 2000. As discussed above, this increase resulted primarily from increased earnings at ETNG and MHP as a result of reporting an entire year of operations in 2001 as compared to 2000, and earnings from allowance for funds used during construction from the Gulfstream project.

Operating Revenues. Operating revenues for the year ended December 31, 2002 decreased $2,552 million to $5,526 million from $8,078 million for the year ended December 31, 2001. The decrease was due primarily to a $2,509 million reduction in revenues on the sale of natural gas, natural gas liquids and other petroleum products, resulting primarily from a $1.05 per MMBtu decrease in natural gas price 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 0.3 TBtu per day, and a decreased trading and marketing net margin as a result of market conditions.

Operating Expenses. Operating expenses for the year ended December 31, 2002 decreased $2,216 million to $5,365 million from $7,581 million for the year ended December 31, 2001. The decrease was due primarily to a $2,301 million reduction in expenses related to purchases of natural gas, natural liquids and other petroleum products resulting primarily from 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 a $40 million charge ($28 million at the Company’s 70% share) for asset impairments in the fourth quarter of 2002 as a result of periodic asset performance evaluations as required by the guidance of SFAS No.144, “Accounting for the Impairment or Disposal of Long-Term Assets.” (See Note 8 to the Consolidated Financial Statements for additional information on asset impairment.) It was estimated in December 2002 that certain gas plants and gathering systems will continue to generate minimal or negative cash flows in future years. Based on the results of these analyses, Field Services determined that the carrying value of these assets was impaired and, accordingly, recorded a charge to reduce the carrying value to fair value.

Field Services also recorded, as part of its internal review of balance sheet accounts, approximately $53 million of charges ($37 million at the Company’s 70% share) in 2002, which may be related to corrections of accounting errors in prior periods. 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 are immaterial to the Company’s reported results.

Minority Interest Expense. Minority interest at Field Services decreased $126 million in 2002 compared to 2001 due primarily to decreased earnings from DEFS, the Company’s joint venture with ConocoPhillips.

EBIT. EBIT for the year ended December 31, 2002 decreased $210 million to $126 million from $336 million for the year ended December 31, 2001. This decrease was due primarily to the changes in commodity prices, increases in operating and general and administrative costs, and asset impairment charges.

Field Services revenues and expenses are significantly dependent on commodity prices such as NGL’s and natural gas. Past and current trends in the price changes of these commodities may not be indicative of future trends. If negative market conditions persist over time and estimated cash flows over the lives of Field Services’ individual assets do not exceed the carrying value of those individual assets, asset impairments may occur in the future under existing accounting rules. Furthermore, a change in management’s intent about the use of individual assets (held for use versus held for sale) could also impact an impairment analysis. At December 31, 2002, Field Services had goodwill of $481 million and net property, plant and equipment of $4,642 million.

is no certainty that these discussions will lead to a transaction in which ConocoPhillips would contribute these assets to DEFS or what might be the terms of such a transaction.

Operating Revenues. Operating revenues for the year ended December 31, 2001 increased $1,913 million to $8,078 million from $6,165 million for the year ended December 31, 2000. The increase was due primarily to recognizing a full year of the results of the combination of Field Services’ natural gas gathering, processing and marketing business with Phillips (now ConocoPhillips, the Phillips combination) in March 2000, which contributed operating revenues of $1,064 million. Additional increases were attributable to increases in natural gas prices, other acquisitions, net trading margin and results of hedging activity. These increases were partially offset by lower average NGL prices that decreased $0.08 per gallon from 2000.

Operating Expenses. Operating expenses for the year ended December 31, 2001 increased $1,856 million to $7,581 million from $5,725 million for the year ended December 31, 2000. The increase was due primarily to the Phillips combination, which resulted in additional purchases of natural gas, natural gas liquids and petroleum products of $881 million. Additional increases resulted from other acquisitions and the effect of higher average natural gas prices, offset by lower NGL prices on Field Services’ natural gas and NGL purchase contracts. Operating and maintenance and general administrative cost reduction efforts of $36 million offset increases due to the Phillips combination. Increased depreciation expense as a result of the Phillips combination also contributed $44 million to the increase in operating expenses.

Minority Interest Expense. Minority interest at Field Services increased $27 million in 2001 compared to 2000 due primarily to increased income from DEFS, as a result of the Phillips combination.

EBIT. EBIT for the year ended December 31, 2001 increased $25 million to $336 million from $311 million for the year ended December 31, 2000. This increase was due primarily to recognizing a full year of operating results of the Phillips combination in March 2000, which was partially offset by lower average NGL prices from 2000. The increase in EBIT was also a result of savings from cost reduction efforts and plant consolidations.

Operating Revenues. Operating revenues for the year ended December 31, 2002 decreased $2,111 million to $2,097 million from $4,208 million for the year ended December 31, 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 $1,428 million as a result of a decrease in the trading and marketing net margin. DENA’s results reflect 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 (the difference between the value of electricity and the value of the gas required to generate the electricity), and decreased market liquidity. These negative trends are expected to continue in 2003. Also contributing to the decrease in revenues were net gains of $229 million in 2001 from the sale of interests in generating facilities.

Operating Expenses. Operating expenses for the year ended December 31, 2002 decreased $570 million to $2,098 million from $2,668 million for the year ended December 31, 2001. The decrease was due primarily to decreased gas purchases from a related party of $338 million, lower incentive compensation expense of $300 million primarily related to trading activities, decreased bad debt expense of $123 million, lower fuel costs of $88 million, and demolition reserves recorded in 2001 of $65 million. Partially offsetting the decreases were higher depreciation expense of $89 million related to the commencement of operations of nine generation facilities by mid-year 2002. Also offsetting the decreases were asset impairment, severance, and other charges of $248 million related to current market conditions and strategic actions taken by management. These charges included provisions for the termination of certain turbines on order and the write-down of other uninstalled turbines of $121 million, the write-off of site development costs (primarily in California) of $31 million, partial impairment of a merchant plant of $31 million, demobilization costs related to the deferral of three merchant power projects of $22 million, a charge of $24 million for the write-off of an information technology system, and severance costs of $19 million associated with work force reductions. (See Note 8 to the Consolidated Financial Statements for additional information on asset impairment.)

Other Income, Net of Expenses. Other income, net of expenses, increased $30 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. Increased losses at DETM, DENA’s joint venture with ExxonMobil Corporation, resulted in an $87 million decrease in minority interest expense in 2002 as compared to 2001.

EBIT. EBIT for the year ended December 31, 2002 decreased $1,424 million to $74 million from $1,498 million for the year ended December 31, 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 current market conditions and strategic actions taken by management.

As a result of Duke Energy’s findings in the course of its investigation related to the Securities and Exchange Commission’s (SEC) inquiry on “round trip” trades (see Note 13 to the Consolidated Financial Statements — Commitments and Contingencies — Litigation, Trading Matters for additional information), 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 Company business segments related to these findings.

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 under existing accounting rules. Furthermore, a change in management’s intent about the use of individual assets (held for use versus held for sale) could also impact an impairment analysis. At December 31, 2002, DENA had $254 million of goodwill ($154 million recorded at Other Operations) and $7,118 million in net property, plant and equipment.

Other Matters Impacting Future DENA Results. On October 31, 2002, the FERC imposed a soft price cap for the sale of energy throughout the Western Electricity Coordinating Council of $250 per megawatt hour.

DETM was previously committed to market substantially all of Mobil’s U.S. and Canadian natural gas production through 2006. However, the Company and ExxonMobil subsidiaries have reached an agreement to modify DETM’s gas supply from the ExxonMobil subsidiaries, so that a substantial amount of the gas will be released to ExxonMobil beginning in March 2003.

Operating Revenues. Operating revenues for the year ended December 31, 2001 increased $1,207 million to $4,208 million from $3,001 million for the year ended December 31, 2000. The increase was due primarily to increased trading and marketing net margin of $1,299 million as a result of significant increases in volatility in the marketplace during 2001. The increase in operating revenue was also impacted by $63 million of incremental gains in 2001 over 2000 due to the sale of DENA’s interest in several generating facilities. The increase was partially offset by a decrease of $127 million in operating revenues as a result of lower average prices realized for increased volumes of electricity generated and sold.

Operating Expenses. Operating expenses for the year ended December 31, 2001 increased $86 million to $2,668 million from $2,582 million for the year ended December 31, 2000. The increase was primarily the result of increased compensation expense of $100 million, primarily related to trading activities, demolition reserves of $65 million, increased gas purchases from a related party of $100 million, and higher depreciation and operating expenses of $101 million at existing plants and additional plants in operation in 2001. The increase was also due to increased operating expenses related to increased bad debts of $84 million, and increased costs associated with other trading and development activities of $167 million. These increases were partially offset by lower fuel costs of $439 million in 2001 and a $110 million charge in 2000 related to receivables for energy sales in California.

Minority Interest (Benefit) Expense. Increased losses at DETM, and increases in the ownership percentage of DENA’s waste-to-energy plants resulted in a $29 million decrease in minority interest expense in 2001 as compared to 2000.

EBIT. EBIT for the year ended December 31, 2001 increased $1,152 million to $1,498 million from $346 million for the year ended December 31, 2000. The increase was due primarily to those factors discussed above: increased trading margins and gains on sales of generating facilities during 2001.

Operating Revenues. Operating revenues for the year ended December 31, 2002 increased $107 million to $937 million from $830 million for the year ended December 31, 2001. The increase was primarily a result of the combination of increased prices, and GWh’s sold at International Energy’s Latin American operating facilities, which resulted in increased revenues of $50 million. Additionally, revenues increased $65 million due to the operating assets acquired and fully consolidated in the Company’s financial statements as a result of the Westcoast acquisition in March 2002. Assets acquired in Guatemala during 2001 contributed additional revenues of $36 million in 2002 as a result of reporting a full year of operations in 2002 compared to only two months in 2001. These increases were partially offset by decreased revenues of $34 million from International Energy’s European operations, which were negatively affected by lower trading margins and liquidity, and decreased revenues of $15 million as a result of lower sales volumes and commodity prices at International Energy’s liquid natural gas business.

Operating Expenses. Operating expenses for the year ended December 31, 2002 increased $524 million to $1,081 million from $557 million for the year ended December 31, 2001. This increase was due partly to operating expenses generated from certain assets as a result of the Westcoast acquisition in March 2002, which contributed $22 million of operating expenses. These assets were fully consolidated in the accompanying financial statements subsequent to the acquisition date of March 14, 2002. In 2001, these assets were accounted for under the equity method of accounting. The increase was also a result of $39 million of operating expenses related to increased fuel and transmission charges at the Latin American operating facilities and the effect of reporting a full year of operations in 2002 for assets acquired in Guatemala during 2001, compared to only two months in 2001.

The increase in operating expenses was further impacted by a $194 million charge for impairment of goodwill for International Energy’s European trading and marketing business. The goodwill was originally recorded in connection with International Energy’s acquisition of Mobile Europe Gas Inc in 2000. The impairment was a result of the Company’s revised market outlook for the European power and natural gas trading markets. International Energy took additional impairment charges in 2002 of $109 million related to the write-off of project and site development costs in Brazil and International Energy’s Asia Pacific businesses, along with the write-down of uninstalled turbines and office relocation charges in Australia.

The increase in operating expenses was further impacted by $75 million as a result of reserve reversals related to the Brazilian operations in 2001; the establishment of settlement provisions in 2002, primarily related to rationing of water and power generation in Brazil; and various reserves related to International Energy’s liquefied natural gas contracts and Peru based businesses.

Other Income, Net of Expenses. Other income, net of expenses increased $21 million in 2002 compared to 2001. The increase was primarily the result of an increase in interest income in International Energy’s Latin American operations as a result of higher cash and cash equivalents balances.

EBIT. EBIT for the year ended December 31, 2002 decreased $388 million to a loss of $102 million from income of $286 million for the year ended December 31, 2001. This decrease was due primarily to various impairment charges related to International Energy’s revised market outlook for its European power and natural gas trading markets, poor performance of its trading and marketing business in the weakened European power and gas markets, and charges recorded as a result of the write-off of site development costs and the write-down of uninstalled turbines, primarily related to planned energy plants in Brazil. The decrease in EBIT was partially offset by the positive effect of the Westcoast and Guatemala acquisitions.

If negative market conditions persist over time and estimated cash flows over the lives of International Energy’s individual assets do not exceed the carrying value of those individual assets, asset impairments may occur in the future under existing accounting rules. Furthermore, a change in management’s intent about the use

of individual assets (held for use versus held for sale) could also impact an impairment analysis. At December 31, 2002, International Energy had $246 million in goodwill and $2,715 million in net property, plant and equipment.

Other Matters Impacting Future International Energy Results. EBIT results for International Energy are sensitive to short term translation impacts from fluctuations in exchange rates, most notably, the Brazilian real, the Mexican peso, the Argentine peso, the European euro, the Australian dollar and the Peruvian nuevo sol.

Certain of International Energy’s long-term sales contracts contain inflation adjustment clauses. Following the recent devaluation of the Brazilian currency, inflation rates in Brazil are on the rise. While this is favorable to revenue in the long run, as International Energy’s contract prices are adjusted, there is an unfavorable impact on interest expense as a result of revaluation of International Energy’s outstanding local debt. At the current levels of inflation, this could have a significant impact on interest expense at International Energy for the year ended December 31, 2003.

Operating Revenues. Operating revenues for the year ended December 31, 2001 increased $25 million to $830 million from $805 million for the year ended December 31, 2000. The increase was primarily a result of stronger operational results in the Latin American businesses and inflation adjustment clauses in certain power purchases agreements of $72 million. Additionally, reporting a full year of operations in 2001 for the Eastern Gas Pipeline constructed in Australia, compared to only four months in 2000 contributed $13 million in revenues. This increase was partially offset by a $54 million gain recognized in 2000 from the sale of liquefied natural gas ships.

Operating Expenses. Operating expenses for the year ended December 31, 2001 increased $74 million to $557 million from $483 million for the year ended December 31, 2000. This increase was due primarily to increases in reserves of $21 million for spot purchases and spot purchase expense of electricity due to power and water rationing in Brazil. The increase in operating expenses also resulted from increases in general and administrative expenses of $31 million in International Energy’s Asia Pacific, Latin American and corporate offices. In addition, reporting a full year of operations in 2001 for the Eastern Gas Pipeline as compared to four months in 2000 contributed operating costs of $10 million.

EBIT. EBIT for the year ended December 31, 2001 decreased $55 million to $286 million from $341 million for the year ended December 31, 2001. The decrease was due primarily to a gain recognized in 2000 from the sale of liquefied natural gas ships, and the impact in 2001 of foreign currency devaluation on the earnings of international operations. This decrease was offset by inflation adjustment clauses in certain power purchase agreements and stronger Latin American operational results.

Operating Revenues. Operating revenues for the year ended December 31, 2002 decreased $168 million to $397 million from $565 million for the year ended December 31, 2001. The decrease was due primarily to the sale of DE&S and DukeSolutions in 2002, resulting in a partial year of revenues compared to a full year in 2001. The sale of these entities resulted in a decrease of $339 million of operating revenues. The sale of DE&S to Framatome ANP, Inc. was completed on May 1, 2002, and the sale of DukeSolutions to Ameresco, Inc was completed on May 1, 2002. (See Note 2 to the Consolidated Financial Statements.)

Partially offsetting the decreases in revenues as a result of the sale transactions was increased equity earnings from D/FD of $75 million, as a result of D/FD completing a number of energy plants. Most of the plants were constructed for DENA and therefore the related intercompany profit has been eliminated within the Other Operations segment. (See Note 7 to the Consolidated Financial Statements for more information on equity earnings and D/FD’s related party transactions.) EDS was formed in the second quarter of 2002, and contributed $92 million in revenues.

Operating Expenses. Operating expenses for the year ended December 31, 2002 decreased $299 million to $279 million from $578 million for the year ended December 31, 2001. The decrease was due primarily to the sale of DE&S and DukeSolutions in 2002, resulting in a partial year of expenses. The sale of these entities resulted in a decrease of $364 million in operating expenses. The decrease in operating expenses was partially offset by a $77 million increase in operating expenses as a result of the formation of EDS in the second quarter of 2002, and $17 million of severance charges in 2002 at D/FD due to the downturn in the domestic power industry.

EBIT. EBIT for the year ended December 31, 2002 increased $131 million to $118 million from a loss of $13 million for the year ended December 31, 2001. The increase was due primarily to the sale of portions of the DE&S and DukeSolutions entities in 2002, increased equity in earnings at D/FD, and earnings generated from EDS.

Operating Revenues. Operating revenues for the year ended December 31, 2001 decreased $130 million to $565 million from $695 million for the year ended December 31, 2000. The decrease was due primarily to decreased revenues at DukeSolutions of $307 million due to decreased volumes and the cessation of retail commodity trading. The decreases in revenues were partially offset by an increase in revenues of $110 million at DE&S due primarily to increased business activity and a $62 million loss in 2000 related to a D/FD project.

Operating Expenses. Operating expenses for the year ended December 31, 2001 decreased $176 million to $578 million from $754 million for the year ended December 31, 2000. The decrease was due primarily to decreased expenses at DukeSolutions of $273 million due to the cessation of retail commodity trading. The decrease in expenses was partially offset by an increase in operating expenses of $57 million as a result of increased business activity at DE&S, and charges at DE&S and DukeSolutions of $36 million for goodwill impairment.

EBIT. EBIT for the year ended December 31, 2001 increased $46 million compared to the year ended December 31, 2000. The increase was due primarily to increased earnings at DE&S as a result of new business activity. The increase was partially offset by the cessation of retail commodity trading at DukeSolutions and charges taken at DE&S and DukeSolutions for goodwill impairment.

Operating Revenues. Operating revenues for the year ended December 31, 2002 decreased $134 million to $512 million from $646 million for the year ended December 31, 2001. The decrease was primarily a result of decreased commercial project sales of $184 million and reduced rental revenue of $19 million in 2002 at Crescent due to current soft market conditions. These decreases were partially offset by an increase in residential developed lot sales in 2002 of $29 million at Crescent due to the addition of several high-end communities and an increase in surplus land sales in 2002 of $29 million.

Operating Expenses. Operating expenses for the year ended December 31, 2002 decreased $119 million to $342 million from $461 million for the year ended December 31, 2001. This decrease was due primarily to decreased costs of $155 million associated with a decrease in commercial project sales at Crescent in 2002. This decrease was partially offset by an increase in the cost of developed lot sales of $28 million at Crescent in 2002.

EBIT. EBIT for the year ended December 31, 2002 decreased $10 million to $173 million from $183 million for the year ended December 31, 2001. This decrease was due primarily to reduced earnings from commercial project sales and reduced rental revenue at Crescent. The decrease was offset by higher profit margins on properties sold by Crescent in 2002 as compared to 2001.

Operating Revenues. Operating revenues for the year ended December 31, 2001 decreased $151 million to $646 million from $797 million for the year ended December 31, 2000. The decrease was primarily a result of a gain of $407 million recorded in 2000 on DukeNet’s sale of its 20% interest in BellSouth Carolina PCS to BellSouth Corporation. The decrease in operating revenues was offset by a $215 million increase in commercial project sales at Crescent during 2001 and losses of $10 million incurred in 2000 related to DukeNet’s BellSouth Carolina PCS investment.

Operating Expenses. Operating expenses for the year ended December 31, 2001 increased $232 million to $461 million from $229 million for the year ended December 31, 2000. This increase was due primarily to increased commercial project sales at Crescent in 2001, which contributed additional operating expenses of $190 million.

EBIT. EBIT for the year ended December 31, 2001 decreased $385 million to $183 million from $568 million for the year ended December 31, 2000. This decrease was due mainly to DukeNet’s gain on sale of its 20% interest in BellSouth Carolina PCS to BellSouth Corporation in 2000, offset by increased earnings at Crescent related primarily to increased commercial project sales, and the absence of losses related to DukeNet’s BellSouth Carolina PCS investment in 2001.

In March 2003, the Company announced that it will exit the merchant finance business at DCP in an orderly manner.

Interest expense increased $318 million in 2002 as compared to 2001, due primarily to higher debt balances resulting from debt assumed in, and issued with respect to, the acquisition of Westcoast and increased financing throughout the corporation, partially offset by lower interest rates in 2002. In 2001 as compared to 2000, interest expense decreased $60 million due primarily to lower interest rates.

Minority interest expense decreased $219 million in 2002 as compared to 2001 and increased $20 million in 2001 as compared to 2000. Minority interest expense includes expense related to regular distributions on preferred securities of the Company and its subsidiaries. This expense decreased $31 million in 2002 as compared to 2001 and increased $39 million in 2001 as compared to 2000. The decrease in 2002 was due primarily to lower distributions related to Catawba River Associates, LLC (Catawba). Beginning in October 2002, subsequent costs associated with this financing have been classified as interest expense. (See Financing Cash Flows and Note 12 to the Consolidated Financial Statements for additional information related to Catawba.)

Minority interest expense as shown and discussed in the preceding business segment EBIT sections includes only minority interest expense related to EBIT of the Company’s joint ventures. It does not include minority interest expense related to interest and taxes of the joint ventures. Total minority interest expense related to the joint ventures (including the portion related to interest and taxes) decreased $189 million in 2002 as compared to 2001 and $19 million in 2001 as compared to 2000. The 2002 change was driven by decreased earnings at DETM and decreased earnings from DEFS. The 2001 decrease was due to changes in the ownership percentage of DENA’s waste-to-energy plants and decreased earnings by DETM, offset slightly by increased minority interest expense for DEFS as a result of the change in ownership due to the Phillips combination.

The effective tax rate increased to 48.5% in 2002 as compared to 37.5% in 2001 primarily as a result of a non-deductible goodwill write-off of $194 million for International Energy’s European trading and marketing business and income tax reserves related to losses in Europe and South America, which may be unrealized in the future, partially offset by favorable foreign taxes due to the acquisition of regulated Westcoast entities and a state tax settlement finalized during 2002. The effective tax rate increased to 37.5% in 2001 as compared to 36.0% in 2000.

During 2001, the Company recorded a one-time net-of-tax charge of $69 million related to the cumulative effect of a change in accounting principle for the January 1, 2001 adoption of SFAS No. 133. This charge related to contracts that either did not meet the definition of a derivative under previous accounting guidance or do not qualify as hedge positions under new accounting requirements. (See Notes 1 and 6 to the Consolidated Financial Statements.)

The selection and application of accounting policies is an important process that has developed as the Company’s operations change and accounting guidance evolves. The Company has identified a number of critical accounting policies that require the use of significant estimates and judgments and have a material impact on its consolidated financial position and results of operations. Management bases its estimates and judgments on historical experience and on other various assumptions that they believe are reasonable at the time of application. The estimates and judgments may change as time passes and more information about the Company’s environment becomes available. If estimates and judgments are different than the actual amounts recorded, adjustments are made in subsequent periods to take into consideration the new information. The Company discusses each of its critical accounting policies, in addition to certain less significant accounting policies, with

senior members of management and the audit committee, as appropriate. The Company’s critical accounting policies are listed below.

The Company uses two comprehensive accounting models for its risk management activities in reporting its consolidated financial position and results of operations as required by GAAP: a fair value model and an accrual model. For the three years ended December 31, 2002, the determination as to which model was appropriate was primarily based on accounting guidance issued by the Financial Accounting Standards Board (FASB) and the Emerging Issues Task Force (EITF). Effective January 1, 2003, the Company adopted 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.” While the implementation of such guidance will change which accounting model is used for certain of the Company’s transactions, the overall application of the model remains the same.

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 Sheets 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 Income during the current period. While DENA is the primary business segment that uses this accounting model, International Energy, Field Services, and Other Energy Services also have certain transactions subject to this model. Through December 31, 2002, the Company applied MTM accounting to its derivatives, unless subject to hedge accounting or the normal purchase and normal sale exemption (as described below) and energy trading contracts, as defined by EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.”

MTM accounting is applied within the context of an overall valuation framework. When available, quoted market prices are used to record a contract’s fair value. However, market values for energy trading contracts may not be readily determinable because the duration of a contract 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 new and existing transactions are valued using approved valuation techniques and market data, and discounted using a London Interbank Offered Rate (LIBOR) based interest rate. Valuation adjustments for performance and market risk, and administration costs are used to arrive at the fair value of the contract and the gain or loss ultimately recognized in the Consolidated Statements of Income. While the Company uses common industry practices to develop its valuation techniques, changes in the Company’s pricing methodologies or the underlying assumptions could result in significantly different fair values and income recognition.

Validation of a contract’s calculated fair value is performed by the Risk Management Group. This group performs pricing model validation, back testing and stress testing of valuation techniques, and variables and price forecasts. Validation of a contract’s fair value may be done by comparison to actual market activity and negotiation of collateral requirements with third parties.

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

Hedge accounting treatment is used when the Company contracts to buy or sell a commodity such as natural gas at a fixed price for future delivery corresponding with anticipated physical sales or purchase of natural gas (cash flow hedge). In addition, hedge accounting treatment is used when the Company holds firm commitments or asset positions and enters into transactions that “hedge” the risk that the price of natural gas or electricity 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 offsets the transaction being hedged, there is no impact to

the Consolidated Statements of Income prior to settlement of the hedge. However, as not all of the Company’s hedges relate to the exact location being hedged a certain degree of hedge ineffectiveness may be realized in the Consolidated Statements of Income.

The normal purchases and normal sales exemption, as provided in SFAS No. 133 and interpreted by Derivative Implementation Group (DIG) Issue No. C15, “Scope Exceptions: Normal Purchases and Sales Exception for Option-Type Contracts and Forward Contracts in Electricity,” indicates that no recognition of the contract’s fair value in the consolidated financial statements is required until settlement of the contract (in the Company’s case, the delivery of power). The Company has applied this exemption for certain contracts involving the purchase and sale of power in future periods.

The Company accounts for its regulated operations under the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” As a result, the Company records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections for costs that are not likely to be incurred. Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes, recent rate orders to other regulated entities and the status of any pending or potential deregulation legislation. Management believes the existing regulatory assets are probable of recovery. This determination reflects the current political and regulatory climate at the state, provincial and federal levels, and is subject to change in the future. If future recovery of costs ceases to be probable, the asset write-offs would be required to be recognized in current period earnings. Total regulatory assets were $697 million as of December 31, 2002 and $86 million as of December 31, 2001. (See Note 4 to the Consolidated Financial Statements.)

The Company has a significant investment in electric generation assets, as well as electric and natural gas transmission and distribution assets, including gathering and processing facilities. The Company capitalizes all construction-related direct labor and material costs, as well as indirect construction costs. Indirect costs include general engineering, taxes and the costs of certain funds used in construction. The cost of funds used in construction represents estimated debt and equity costs of capital funds necessary to finance the construction of new regulated facilities and interest on debt for new unregulated facilities. After construction is completed, the Company is permitted to recover these costs for regulated facilities, plus a defined return, by including them in the rate base and in the depreciation provision.

As discussed in the Notes to the Consolidated Financial Statements, depreciation on the Company’s assets is generally computed using the straight-line method over the estimated useful life of the assets. The costs of renewals and betterments that extend the useful life of property, plant and equipment are also capitalized. The cost of repairs, replacements and major maintenance projects is expensed as it is incurred.

Depreciation of regulatory assets is provided over the recovery period specified in the related legislation or regulatory agreements. Depreciation of non-regulatory assets is provided over the estimated useful life as determined by periodic studies and the technical expertise of internal consultants. The recovery period for non-regulatory assets ranges from 5 to 40 years.

The computation of depreciation expense requires judgment regarding the estimated useful lives and salvage value of assets. As circumstances warrant, depreciation estimates are reviewed to determine if any changes are needed. Such changes could involve an increase or decrease in estimated useful lives or salvage values which would impact future depreciation expense.

The Company evaluates the carrying value of long-lived assets, excluding goodwill, when circumstances indicate the carrying value of those assets may not be recoverable under the guidance of SFAS No. 144. For long-lived assets the Company determines the carrying amount is not recoverable if it exceeds the sum of estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. The Company considers various factors when determining if impairment tests are warranted, including but not limited to:

In 2002, the merchant energy portion of the Company’s business portfolio suffered from oversupply of merchant generation, low commodity pricing and volatility, and a steep decline in trading and marketing activity. These market challenges are continuing in 2003. As a result of the 2002 market conditions, the Company suspended certain projects and abandoned other projects in this sector. The culmination of these events caused the Company to evaluate the carrying values of its long-lived assets at DENA and International Energy. This analysis resulted in a $31 million impairment charge at one of DENA’s merchant power facilities. Additionally, charges of approximately $242 million were also recorded in 2002 to write-off site development costs in California and Brazil and to partially write-down uninstalled turbines, as well as, the termination of other turbines on order. Also in 2002, a decision was made to abandon an information technology system at DENA resulting in the write-off of approximately $24 million of previously capitalized software and related costs.

Judgment is exercised to estimate the future cash flows and the useful lives of these long-lived assets and to determine management’s intent to use the assets. The sum of undiscounted cash flows is primarily dependent on forecasted commodity prices for sales of power and costs of fuel. The Company incorporates current market information as well as historical, fundamental analysis and other factors into its forecasted commodity prices. While commodity prices vary from time to time, the methodology used by the Company provides the best estimate of undiscounted cash flows over the long-lived asset’s life. Revenues from merchant generation facilities are generally estimated by using probabilistic models that calculate the operating margin on the spread between the forward power prices and the marginal cost to dispatch the facility. Other operating expenses, including future escalation provisions, are factored into the calculation as well. The Company used a probability-weighted approach for developing estimates of future cash flows to test the recoverability of its merchant generation long-lived assets. The probability-weighted approach, as introduced by FASB Concepts No. 7, “Using Cash Flow Information and Present Value in Accounting Measurements” and encouraged by SFAS No. 144,

considers the likelihood of possible outcomes. Under the probability-weighted approach, alternate courses of action being considered are assigned a probability assessment with the most likely scenarios weighted higher. Alternatives include potential disposal or operation for their remaining useful lives. A change in the Company’s probability assessment for each scenario could have a significant impact on the estimated future cash flows. If the carrying value of the long-lived assets is not recoverable based on these estimated future cash flows, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. Management assesses the fair value of the long-lived assets using commonly accepted techniques including, but not limited to, recent third party comparable sales and discounted cash flow analysis.

Additionally, the Company evaluated the long-lived assets at Field Services as a result of challenging market conditions, primarily lower NGL pricing in 2002. As a result, Field Services recorded $40 million in impairment charges ($28 million at the Company’s 70% share) in the fourth quarter of 2002 related to certain operating assets.

The Company evaluates the impairment of goodwill under SFAS No. 142. The majority of the Company’s goodwill relates to the acquisition of Westcoast in March 2002 and was not impaired as of December 31, 2002. As required by SFAS No. 142, the Company performs an annual goodwill impairment test and updates 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. As described above, certain sectors of the Company, primarily merchant energy and Field Services, are operating in challenging market conditions. In 2002 the Company recorded a goodwill impairment loss of $194 million related to International Energy’s European trading and marketing business. Significant changes in the European market and recent operating results have adversely affected the Company’s outlook for this business unit. The exit of key market participants and a tightening of credit requirements are the primary drivers of this revised outlook. To determine the amount of the impairment, management estimated the fair value of the assets and operations using the present value of expected future cash flows of the reporting unit in comparison to its carrying value. As a result, substantially all of the goodwill related to the European operations was written-off. There were no other goodwill impairments recorded in 2002. As the challenging market conditions continue into 2003, in addition to performing the annual goodwill impairment analysis required by SFAS No. 142, management 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.

As of the acquisition date, the Company allocates goodwill to a reporting unit. The Company defines a reporting unit as an operating segment or one level below. (See Note 3 to the Consolidated Financial Statements.)

Unbilled and Estimated Revenues. Revenues on sales of natural gas, natural gas transportation, storage and distribution as well as sales of petroleum products are recognized when the service is provided. Revenues related to these services provided but not yet billed are estimated each month. These estimates are generally based on contract data, regulatory information, preliminary measurements and allocations, estimated distribution usage based on historical data adjusted for heating degree days, commodity prices and preliminary throughput measurements. Final bills for the current month are billed and collected in the following month.

Percentage of Completion Contracts. Long-term contracts, primarily in Other Energy Services, are accounted for using the percentage-of-completion method. Under the percentage-of-completion method, sales and gross profit are recognized as the work is performed based on the relationship between costs incurred and total estimated costs at completion. Sales and gross profit are adjusted prospectively for revisions in estimated total contract costs and contract values. When the current estimates of total contract revenue and contract cost indicate a loss, a provision for the entire loss on the contract is recorded in that period. The provision for the loss arises because estimated cost for the contract exceeds estimated revenue.

Trading and Marketing Revenues. The Company is exposed to market risks associated with commodity prices and it engages in certain transactions to mitigate this exposure. Transactions that are carried out in connection with trading activities are currently accounted for under the MTM accounting method as required by EITF Issue No. 98-10. Under this method, the Company’s trading contracts are recorded at fair value. Prior to settlement of any energy contract held for trading purposes, a favorable or unfavorable price movement is reported as Trading and Marketing Net Margin in the Consolidated Statements of Income. An offsetting amount is recorded as Unrealized Gains or Unrealized Losses on Mark-to-Market and Hedging Transactions in the Consolidated Balance Sheets. Prices used to determine fair value reflect management’s best estimates considering various factors, including quoted market prices, when available, and modeling techniques. When a contract to sell or buy is physically settled, the fair value entries are reversed and the gross amounts invoiced to the customer or due to the counterparty are included as Trading and Marketing Net Margin in the Consolidated Statements of Income. For financial settlement, the effect on the Consolidated Statements of Income is the same as physical transactions. For all contracts, the unrealized gain or loss in the Consolidated Balance Sheets is reversed and classified as a receivable or payable account until collected.

In June 2002, the EITF reached a partial consensus on Issue No. 02-03. The EITF concluded that, effective for periods ending after July 15, 2002, mark-to-market gains and losses on energy trading contracts (including those to be physically settled) must be shown on a net basis in the Consolidated Statements of Income. The Company had previously chosen to report certain of its energy trading contracts on a gross basis, as sales in operating revenues and to record the associated costs in operating expenses, in accordance with prevailing industry practice. The amounts in the Consolidated Statements of Income have been reclassified to conform to the 2002 presentation of recording all amounts on a net basis in operating revenues. In the calculation of net revenues, the Company has continued to enhance its methodologies around the application of this complex accounting literature since the third quarter 2002 when these trading revenues were first reported on a net basis. (See Note 1 to the Consolidated Financial Statements for further discussion.)

In October 2002, the EITF, as part of their further deliberations on Issue No. 02-03, rescinded the consensus reached on Issue No. 98-10. As a result, all energy trading contracts that do not meet the definition of a derivative under SFAS No. 133, and trading inventories that previously had been recorded at fair values, will be recorded at their historical cost and reported on an accrual basis, resulting in the recognition of earnings or losses at the time of contract settlement or termination. New non-derivative energy trading contracts entered into after October 25, 2002 are accounted for under the accrual accounting basis. Non-derivative energy trading contracts on the Consolidated Balance Sheets as of January 1, 2003 that existed on October 25, 2002 and trading inventories that were recorded at fair values will be adjusted to historical cost via a net-of-tax and minority interest cumulative effect adjustment of $25 million to $75 million recorded as a reduction to first quarter 2003 earnings.

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

The Company follows SFAS No. 5, “Accounting for Contingencies,” to determine accounting and disclosure requirements for contingencies. The Company operates 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 the Company’s business

operations and public reporting. Reserves are established when required in management’s judgment and disclosures are made when appropriate regarding litigation, assessments, credit worthiness of customers or counterparties, and self-insurance exposures, among others. (See Note 13 to the Consolidated Financial Statements for discussion of various contingencies.) The evaluation of these contingencies is performed by various specialists inside and outside of the Company. Accounting for contingencies requires significant judgment by management regarding the estimated probabilities and ranges of exposure to potential liability. Management’s assessment of the Company’s 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 the consolidated results of operations, cash flows and financial position of the Company. Management has applied its best judgment in applying SFAS No. 5 to these matters.

As of December 31, 2002, the Company had $814 million in cash and cash equivalents compared to $263 million as of December 31, 2001. The Company’s working capital was a $237 million deficit as of December 31, 2002, compared to an $898 million deficit as of December 31, 2001. The Company relies upon cash flows from operations, as well as, borrowings and the sale of assets to fund its liquidity and capital requirements. A material adverse change in operations or available financing may impact the Company’s ability to fund its current liquidity and capital resource requirements.

Net cash provided by operating activities was $3,504 million in 2002 compared to $2,514 million in 2001, an increase of $990 million. The increase in cash provided by operating activities was due primarily to higher cash earnings plus changes in working capital from 2001. Although net income significantly decreased in 2002 (see Results of Operation for further discussion) many of the items affecting net income were non-cash. Non-cash items affecting earnings included an increase in depreciation expense, primarily due to the acquisition of Westcoast; non-cash impairment charges for goodwill (at International Energy), project sites (primarily at DENA) and property plant and equipment; higher deferred tax expense; and an overall reduction in the mark-to-market and hedging portfolio primarily due to unrealized losses in 2002 versus unrealized gains in 2001.

Net cash provided by operating activities was $2,514 million in 2001 compared to $1,058 million in 2000, an increase of $1,456 million. The increase was due primarily to price movements in the energy commodities markets which have a direct impact on the Company’s use and generation of cash from operations. Earnings increase as natural gas and electricity prices move favorably with respect to contracts that the Company holds. In addition, counterparties may be required to post collateral in cash or letters of credit if price moves benefit the Company. This mechanism has given the Company use of the cash on a short-term basis. Conversely, negative price impacts reduce earnings and may require the Company to post collateral with its counterparties. Cash collateral posted by the Company is included in Other Current Assets and cash collateral collected by the Company is included in Other Current Liabilities in the Consolidated Balance Sheets.

The Company currently anticipates net cash provided by operating activities, plus the sale of assets, in 2003 to be approximately $2,700 million. Achievement of these projected cash flows is subject to a number of factors, including, but not limited to, industry restructuring, regulatory constraints, acquisition and divestiture opportunities, market volatility, and economic trends.

Cash used in investing activities was $5,628 million in 2002 compared to $5,135 million in 2001, an increase of $493 million. Additionally, cash used in investing activities was $5,135 million in 2001 compared to $4,185 million in 2000, an increase of $950 million. The primary use of cash for investing activities is capital and investment expenditures, which are detailed by business segment in the following table.

Capital and investment expenditures increased $120 million in 2002 compared to 2001. The increase was due primarily to cash used in the acquisition of Westcoast of $1,707 million, net of cash acquired (see Note 2 to the Consolidated Financial Statements) partially offset by decreases in capital expenditures and investment expenditures. Capital expenditures decreased when compared to 2001 due to a decrease in DENA’s investments in generating facilities, as a result of management’s revised outlook for the merchant energy portion of its business, and a decrease in acquisitions of minor businesses and assets when compared to 2001. These decreases in capital expenditures were partially offset by an increase in investments in property plant and equipment at Gas Transmission due to increased expansion projects in the Algonquin Gas Transmission Company, ETNG, Texas Eastern and Westcoast systems, along with the Maritimes & Northeast Pipeline expansion costs after its consolidation in 2002. Investment activities also decreased when compared to 2001, due primarily to reduced investments at Duke Ventures (primarily related to DCP) and Natural Gas Transmission’s 2001 investment in a 50% interest in Gulfstream.

Capital and investment expenditures increased $1,180 million in 2001 compared to 2000. The increase reflects additional expansion and development expenditures (primarily related to DENA’s generating facilities), refurbishment and upgrades to existing assets, and minor acquisitions of businesses and assets. Also in 2001, Natural Gas Transmission invested in a 50% interest in Gulfstream. These increases were partially offset by Natural Gas Transmission’s acquisition of ETNG for approximately $390 million and of MHP for approximately $250 million in cash, and International Energy’s approximately $280 million tender offer for Companhia de Geracao de Energia Elétrica Paranapanema (Paranapanema) in 2000.

The Company’s projected 2003 capital and investment expenditures are approximately $1,800 million. The Company is focusing on reducing risk and restructuring its business for future success, including opportunities to reduce further the projected capital expenditures. The Company will invest in its strongest business sectors with

an overall focus on positive net cash generation. Total projected capital and investment expenditures include approximately $450 million for maintenance and upgrades of existing plants, pipelines, and infrastructure.

The Company’s consolidated capital structure as of December 31, 2002, including short-term debt, was 54% debt, 37% common equity, 6% minority interests and 3% trust preferred securities. Fixed charges coverage ratio, calculated using SEC guidelines, was 1.4 times for 2002, 3.7 times for 2001 and 3.0 times for 2000.

The Company’s cash requirements for 2003 are expected to be funded by cash from operations, including the sale of assets, and to be adequate for funding capital expenditures and permanently retiring a portion of scheduled debt maturities. In addition, the Company expects to access the capital markets as needed. The ability to access the capital markets is dependent upon market opportunities presented, among other factors. The Company does not have any material off-balance sheet financing entities or structures, except for normal operating lease arrangements and guarantee contracts (see Notes 13 and 14 to the Consolidated Financial Statements). Management believes the Company has adequate financial flexibility and resources to meet its future needs.

Credit Ratings. In August 2002, Standard & Poor’s (S&P) downgraded its long-term ratings for the Company and its subsidiaries (with the exception of Maritimes & Northeast Pipeline, LLC and Maritimes and Northeast Pipeline, LP (collectively, M&N Pipeline) and DEFS) one ratings level, changing its outlook to Stable and leaving commercial paper ratings unchanged. S&P’s actions were based principally on a reassessment of the Company’s consolidated creditworthiness and S&P’s perceived increase in risk of energy trading and merchant generation activities. In January 2003, S&P again lowered its long-term ratings for the Company and its subsidiaries, with the exception of M&N Pipeline and DEFS. In addition, S&P lowered the short-term ratings for the Company. This action was based primarily on S&P’s determination that reductions in capital and investment expenditures and planned asset divestitures will not be sufficient to provide funds needed to lower debt and reduce interest expense quickly enough to offset the impact of decreased earnings in 2002 and anticipated lower earnings in 2003. S&P concluded this action by placing the Company and its subsidiaries, excluding M&N Pipeline and DEFS, on Negative Outlook citing the need to review the Company’s progress on its divestiture program and its need to improve certain financial measures.

In October 2002, Fitch Ratings (Fitch) downgraded its long-term and short-term ratings of the Company one ratings level, due primarily to the Company’s reduced earnings outlook for the remainder of 2002 and 2003. Fitch placed the Company and its subsidiaries, with the exception of DEFS, on Negative Outlook due to the ongoing uncertainty surrounding the merchant power industry and investigations by the FERC and the SEC. In January 2003, Fitch lowered the long-term ratings of the Company, and also lowered the ratings of Texas Eastern and PanEnergy Corp (PanEnergy) (both wholly owned subsidiaries of the Company). Those actions were based on the Company’s announcements that consolidated profits for 2002 and 2003 were expected to be well below previous estimates. Fitch concluded its actions leaving the Company and its subsidiaries, excluding DEFS, on Negative Outlook due to the continued uncertainty of ongoing FERC and SEC investigations, and the perceived execution risk in management’s plans for non-core asset dispositions over the next year.

In December 2002, Moody’s Investors Service (Moody’s) lowered its long-term ratings of the Company, Texas Eastern and PanEnergy.Moody’s actions were in response to lower actual and anticipated earnings and cash flow as a result of continued weakness in wholesale energy markets both in the U.S. and abroad. Moody’s concluded its action placing the Company and its subsidiaries, except M&N Pipeline and DEFS, on Negative Outlook, reflecting Moody’s perceived execution risk in the Company’s program to strengthen its balance sheet.

The following table summarizes the credit ratings of the Company, its principal funding subsidiaries and its trading and marketing subsidiary DETM, as of February 28, 2003.

The Company’s credit ratings are dependent on, among other factors, the ability to generate sufficient cash to fund the Company’s capital and investment expenditures, while strengthening the balance sheet through debt reductions. If, as a result of market conditions or other factors affecting the Company’s business, the Company is unable to execute its business plan, including disposition of non-core assets, or if the Company’s earnings outlook deteriorates, the Company’s ratings could be further affected.

The impacts of the credit rating downgrades to date have been minimal on the Company and its subsidiaries. If further downgrades were to occur and to the extent that these downgrades placed certain of the entities (primarily DETM and DEFS) below investment grade, there could be a negative impact on that entity’s working capital and terms of trade.

Significant Financing Activities. In 2002, the Company issued $500 million of 6.25% senior unsecured notes due in 2013 and $250 million of 6.75% senior unsecured notes due in 2032. In addition, the Company, through private placement transactions, issued $500 million of floating rate (based on the one-month LIBOR plus 0.65%) senior unsecured notes due in 2003 and $100 million of floating rate (based on the one-month LIBOR plus 0.85%) senior unsecured notes due in 2004. The proceeds from these issuances were used for general corporate purposes and to repay commercial paper. Additionally, the Company decreased its note payable to D/FD by $286 million, to $282 million as of December 31, 2002. The weighted-average interest rate on this note for 2002 was 2.5%. (See Notes 7 and 10 to the Consolidated Financial Statements.)

In 2002, a wholly owned subsidiary of the Company, Duke Australia Pipeline Finance Pty Ltd., closed a syndicated bank debt facility for 900 million Australian dollars (U.S. $450 million) with various banks to fund its pipeline and power businesses in Australia. The facility includes a Company-guaranteed tranche and a non-recourse project finance tranche that is secured by liens over existing Australian pipeline assets. Proceeds from the project finance tranche were used to repay intercompany loans.

During 2002, Texas Eastern issued $300 million of 5.25% senior unsecured notes due in 2007 and $450 million of 7.0% senior unsecured notes due in 2032. The proceeds from these issuances were used for general corporate purposes, including the repayment of debt which matured in 2002, and for pipeline expansion and maintenance projects.

In 2002, Algonquin Gas Transmission Company, a wholly owned subsidiary of the Company, through a private placement transaction, issued $300 million of 5.69% senior unsecured notes due in 2012. The proceeds from this issuance were used for general corporate purposes, including repayment of maturing debt and for pipeline expansion and maintenance projects.

In 2002, ETNG, a wholly owned subsidiary of the Company, through a private placement transaction, issued $150 million of 5.71% senior unsecured notes due in 2012. The proceeds from this issuance were used for general corporate purposes and for pipeline expansion and maintenance projects.

During 2002, Union Gas issued 200 million Canadian dollars (U.S. $128 million) of 5.19% debentures due in 2007. The proceeds from this issuance were used for general corporate purposes, including repayment of maturing debt, repayment of commercial paper and funding of capital expenditures.

In 2000, Catawba, a fully consolidated financing entity managed by a subsidiary of the Company, issued $1,025 million of preferred member interests to a third-party investor. The proceeds from the non-controlling investor were reflected on the Consolidated Balance Sheets as Minority Interest in Financing Subsidiary and were subsequently advanced to DE Power Generation, LLC (DEPG), a wholly owned subsidiary of the Company. In September 2002, Catawba distributed the receivable from DEPG to the preferred member, THOR Investors, LLC (THOR), which simultaneously withdrew its interest. As a result, the $1,025 million that DEPG previously owed to Catawba became an obligation to THOR and was reclassified on the 2002 Consolidated Balance Sheet to Long-term Debt. In October 2002, the Company purchased the equity interests in THOR and effectively reduced the debt to $994 million. Additionally, the Company financially guaranteed the $994 million in return for certain modifications to the terms of the credit agreement.

On March 14, 2002, the Company acquired Westcoast for approximately $8 billion, including the assumption of $4.7 billion of debt. The assumed debt consists of debt of Westcoast, Union Gas and various project entities that are wholly owned or consolidated by the Company. The interest rates on the assumed debt range from 1.8% to 15.0%, with maturity dates ranging from 2002 through 2031. In addition to the debt assumed, as of December 31, 2002, Westcoast and Union Gas had operating credit facilities of 450 million Canadian dollars (U.S. $285 million) and 600 million Canadian dollars (U.S. $380 million), respectively. Borrowings under the Union Gas credit facility are subject to and dependent on the senior unsecured rating of Union Gas, rated A by DBRS and A- by S&P as of February 28, 2003. For the Union Gas credit facility, no material adverse change can be declared if Union Gas maintains a rating of BBB or greater by either DBRS or S&P. Any outstanding debt would not become due and payable as a result of a change in its ratings.

In the transaction, a Company subsidiary acquired all of the outstanding common shares of Westcoast in exchange for approximately $1.7 billion in cash (net of cash acquired) and approximately 49.9 million shares of Duke Energy common stock (including exchangeable shares of a Duke Energy Canadian subsidiary that are substantially equivalent to and exchangeable on a one-for-one basis for Duke Energy common stock). The value of the Duke Energy common stock issued was approximately $1.7 billion and was determined based on the average market price of Duke Energy’s common shares over the two-day period before and after the terms of the transaction became fixed, in accordance with EITF No. 99-12, “Determination of the Measurement Date for the Market Price of Acquirer Securities Issued in a Purchase Business Combination.” Under prorating provisions of the acquisition agreement that ensured that approximately 50% of the total consideration was paid in cash and 50% in stock, each common share of Westcoast entitled the holder to elect to receive 43.80 in Canadian dollars, or either 0.7711 of a share of Duke Energy common stock or of an exchangeable share of a Duke Energy Canadian subsidiary, or a combination thereof. The cash portion of the consideration was funded with the proceeds from the issuance of $750 million in mandatory convertible securities in November 2001 (see Note 10 to the Consolidated Financial Statements) along with incremental commercial paper. The commercial paper was repaid using the proceeds from a public offering of 54.5 million shares of common stock at $18.35 per share. The shares from the public offering were issued in October 2002 and the proceeds were approximately $1.0 billion, before underwriting commissions and other offering expenses. The Westcoast acquisition was accounted for

using the purchase method of accounting, and goodwill totaling approximately $2.3 billion was recorded in the transaction. (See Note 2 to the Consolidated Financial Statements.)

Credit Facilities and Related Borrowings. The following table summarizes the Company’s credit facilities and related amounts outstanding as of December 31, 2002. The majority of the credit facilities support commercial paper programs. The issuance of commercial paper, letters of credit and other borrowings reduces the amount available under the credit facilities. Amounts related to outstanding commercial paper and other borrowings in the following table are included in the long-term debt table presented in Note 10 to the Consolidated Financial Statements.

Existing bank credit facilities as of December 31, 2002 are not subject to minimum cash requirements. In addition, in October 2002, the Company secured an option to borrow up to $500 million in February 2003 for a period ending no later than November 2003. In February 2003, this option was amended to allow the Company to borrow up to $250 million between June 30, 2003 and August 29, 2003. Any amounts borrowed would be due no later than March 31, 2004. Also, the Company is currently maintaining a minimum cash position of $500 million to be used for short-term liquidity needs. This cash position is invested in highly rated, liquid, short-term money market securities.

The Company has approximately $3,200 million of credit facilities which mature in 2003. It is the Company’s intent to reduce its need for these facilities as the year progresses and thus resyndicate less than the total $3,200 million.

The Company’s credit agreements contain various financial and other covenants. Failure to meet those covenants beyond applicable grace periods could result in acceleration of due dates of the borrowings and/or termination of the agreements. As of December 31, 2002, the Company was in compliance with those covenants. In addition, certain of the agreements contain cross-acceleration provisions that may allow acceleration of payments or termination of the agreements upon nonpayment or acceleration of other significant indebtedness of the applicable borrower or certain of its subsidiaries.

Other Financing Matters. As of December 31, 2002, the Company and its subsidiaries had effective SEC shelf registrations for up to $1,000 million in gross proceeds from debt and other securities. In addition, as of December 31, 2002, the Company had access to 950 million Canadian dollars (U.S. $602 million) available under Canadian shelf registrations for issuances in the Canadian market.

Duke Energy can also provide equity infusions to the Company. Any equity infusions to the Company are limited to cash provided by equity financing at Duke Energy.

In 2000, the Company issued $150 million senior unsecured bonds due in 2003 that may be required to be repaid if the Company’s senior unsecured debt ratings fall below BBB at S&P or Baa2 at Moody’s. As of February 28, 2003, the Company’s senior unsecured credit rating was BBB+ at S&P and Baa2 at Moody’s.

Dividends on the Company’s stock will be paid when declared by the Board of Directors. The Company did not pay dividends on its common stock in 2002, 2001 or 2000. Currently, the Company is reviewing its dividend policy with respect to paying future dividends.

Additionally, the Company anticipates that it will make a contribution of approximately $10 million to the Westcoast pension plans in 2003 for the 2003 plan year. Contributions for the 2004 plan year and beyond may vary based on the actual return on the pension plans’ assets, as well as other factors.

As part of its normal business, the Company is 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. These arrangements are largely entered into by the Company. To varying degrees, these guarantees involve elements of performance and credit risk, which are not included on the Consolidated Balance Sheets. The possibility of the Company having to honor its contingencies is largely dependent upon future operations of various subsidiaries, investees and other third parties, or the occurrence of certain future events. The Company would record a liability if events occurred that required that one be established. (See Note 14 to the Consolidated Financial Statements for more information on financial guarantees.)

In addition, the Company enters into various fixed-price, non-cancelable commitments to purchase or sell power (tolling arrangements or power purchase contracts), take-or-pay arrangements, transportation or throughput agreements and other contracts that may or may not be recognized on the Consolidated Balance Sheets. Some of these arrangements may be recognized at market value on the Consolidated Balance Sheets as trading contracts or qualifying hedge positions included in Unrealized Gains or Losses on Mark-to-Market and Hedging Transactions.

The following table summarizes the Company’s contractual cash obligations for each of the years presented.

The following table summarizes the commercial commitments in effect as of December 31, 2002 by expiration date.

The Company has guaranteed the issuance of surety bonds, which obligates itself to a surety to make payment upon the failure of another entity to honor its obligations to a third party. As of December 31, 2002, the Company had guaranteed approximately $250 million of surety and bonds outstanding related to obligations of other entities, including wholly owned subsidiaries.

The Company is exposed to market risks associated with commodity prices, credit exposure, interest rates, equity prices and foreign currency exchange rates. Management has established comprehensive risk management policies to monitor and manage these market risks. Duke Energy’s 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 periodic updates from the Chief Risk Officer (CRO) and other members of management, on market risk positions, corporate exposures, credit exposures and overall risk management activities. The CRO is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits.

See Critical Accounting Policies — Risk Management Activities for further discussion of the accounting of energy trading contracts and derivatives.

The Company, substantially through its subsidiaries, is exposed to the impact of market fluctuations in the price of natural gas, electricity and other energy-related products marketed and purchased as a result of its ownership of energy related assets and proprietary trading activities. The Company employs established policies and procedures to manage its risks associated with these market fluctuations using various energy trading contacts and commodity derivatives, including forward contracts, futures, swaps and options for trading purposes and for activity other than trading activity (primarily hedge strategies). (See Notes 1 and 6 to the Consolidated Financial Statements.)

Trading. The risk in the trading portfolio is measured and monitored on a daily basis utilizing a Value-at-Risk model to determine the potential one-day favorable or unfavorable Daily Earnings at Risk (DER) as described below. DER is monitored daily in comparison to established thresholds. Other measures are also used

to limit and monitor risk in the trading portfolio (which includes all trading contracts not designated as hedge positions) on monthly and annual bases. These measures include limits on the nominal size of positions and periodic loss limits.

DER computations are based on historical simulation, which uses price movements over an eleven day period. The historical simulation emphasizes the most recent market activity, which is considered the most relevant predictor of immediate future market movements for natural gas, electricity and other energy-related products. DER computations use several key assumptions, including a 95% confidence level for the resultant price movement and the holding period specified for the calculation. The Company’s DER amounts for instruments held for trading purposes are shown in the following table.

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

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

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 new and existing transactions are valued using approved valuation techniques and market data and discounted using a LIBOR-based interest rate. Valuation adjustments for performance and market risk, and administration costs are used to adjust the fair value of the contract to the gain or loss ultimately recognized in the Consolidated Statements of Income.

Validation of a contract’s fair value is performed by the Risk Management Group, an internal group independent of the Company’s trading areas. This group performs pricing model validation, back testing and stress testing of valuation techniques, variables and price forecasts consistent with GAAP. Validation of a contract’s fair value may be by comparison to actual market activity and through negotiation of collateral requirements with third parties. While the Company uses common industry practices to develop its valuation techniques, changes in the Company’s pricing methodologies or the underlying assumptions could result in significantly different fair values and income recognition.

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

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

The “prices based on models and other valuation methods” category includes (i) the value of options not quoted by an exchange or OTC broker, (ii) the value of transactions for which an internally developed price curve was constructed as a result of the long dated nature of the transaction or the illiquidity of the market point, and (iii) the value of structured transactions. In certain instances structured transactions can be decomposed and modeled by the Company 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. Many of the contracts in the “prices based on models and other valuation methods” category, such as transportation and storage contracts, are

not derivatives as defined by SFAS No. 133. As a result, following the adoption of EITF Issue No. 02-03 in January 2003, these contracts will be accounted for using the accrual method of accounting and a significant decrease in the reported fair value of trading contracts will occur.

The Company’s trading portfolio valuation adjustments for performance, market risk and administration costs are reflected in the above amounts.

Hedging Strategies. Some Company subsidiaries are exposed to market fluctuations in the prices of energy commodities related to their power generating and natural gas gathering, distribution, processing and marketing activities. The Company closely monitors the risks associated with these commodity price changes on its future operations and, where appropriate, uses various commodity instruments such as electricity, natural gas, crude oil and NGL forward contracts to hedge the value of its assets and operations from such price risks. In accordance with SFAS No. 133, the Company’s primary use of energy commodity derivatives is to hedge the output and production of assets it physically owns. Contract terms are up to 15 years, and contracts with terms extending several years are generally valued using models and assumptions developed internally or by industry standards. These contracts are designated and qualify as effective hedge positions of future cash flows, or fair values of assets owned by the Company.

The Company also engages in the economic hedging of other contractual assets such as transportation and storage of gas. For the three years ended December 31, 2002, such hedging activity was not recorded pursuant to SFAS No. 133 because of the broad fair value accounting model in the FASB’s and the EITF’s rules during that period. The hedge and the hedged item were both accounted for using MTM accounting. However, in connection with the adoption of EITF Issue No. 02-03 in January 2003, the Company anticipates that many of these former hedge relationships will be designated as hedges for accounting purposes in accordance with SFAS No. 133.

To the extent that the hedge instrument offsets the transaction being hedged, there is no impact to the Consolidated Statements of Income, but changes in fair values will result in changes in the Consolidated Balance Sheets and the Consolidated Statements of Common Stockholder’s Equity and Comprehensive Income. Accordingly, assumptions and valuation techniques for these contracts have no impact on reported earnings or cash flows prior to settlement. The unrealized gains or losses on these contracts are deferred in Other Comprehensive Income (OCI) for cash flow hedges and included in Other Current or Noncurrent Assets or Liabilities on the Consolidated Balance Sheets for fair value hedges of firm commitments, in accordance with SFAS No. 133. Amounts deferred in OCI are realized in earnings concurrently with the transaction being hedged. (See Notes 1 and 6 to the Consolidated Financial Statements.) However, in instances where the hedging contract no longer qualifies for hedge accounting, amounts included in OCI through the date of de-designation remain in OCI until the underlying transaction actually occurs. The derivative contract (if continued as an open position) will be marked to market currently through earnings. Several factors influence the effectiveness of a hedge contract, including counterparty credit risk and using contracts with different commodities or unmatched terms. Hedge effectiveness is monitored regularly and measured each month. To the extent hedge contracts are deemed ineffective, as defined by SFAS No. 133, the impact may increase or decrease earnings.

In addition to the hedge contracts described above and recorded on the Consolidated Balance Sheets, the Company enters into other contracts that qualify for the normal purchases and sales exemption described in Paragraph 10 of SFAS No. 133 and DIG Issue No. C15. These contracts, generally forward agreements to sell power, bear the same counterparty credit risk as the hedge contracts described above. Under the same credit risk reduction guidelines used for other contracts, normal purchases and sales contracts are also subject to collateral requirements. Income recognition and realization related to these contracts coincide with the physical delivery of power.

Based on a sensitivity analysis as of December 31, 2002, it was estimated that a difference of one cent per gallon in the average price of NGLs in 2003 would have a corresponding effect on EBIT of approximately $7 million (at the Company’s 70% ownership), after considering the effect of the Company’s commodity hedge

positions. Comparatively, the same sensitivity analysis as of December 31, 2001 estimated that EBIT would have changed by approximately $6 million in 2002. Based on a sensitivity analysis performed on DENA’s managed merchant generation fleet and associated natural gas transportation contracts, with both modeled as options, a $1 change in spark spread (defined as the price realized for power less the cost of fuel for that power) would not be expected to have a material impact on EBIT for 2003 as of December 31, 2002, or 2002 as of December 31, 2001. The effect on EBIT for 2003 or 2002 was also not expected to be material as of December 31, 2002 or 2001 for exposures to other commodities’ price changes. These hypothetical calculations consider existing hedge positions and estimated production levels, but do not consider other potential effects that might result from such changes in commodity prices.

As of December 31, 2002, the merchant generation facilities in North America owned or operated by the Company represented 12,734 net megawatts (MW), after considering other parties’ ownership interests. This excludes 1,423 net MW, associated with facilities which are not currently managed directly by DENA. Facilities scheduled for completion during 2003 represent an additional 1,860 net MW. The managed merchant generation fleet total of 14,594 net MW (inclusive of the 1,860 net megawatts related to facilities scheduled for completion during 2003) consists of 13 combined cycle units representing 10,361 net MW and seven simple cycle (peaker) units representing 4,233 net MW. For more information on the North American merchant generation facilities, see Part 1, Item 2 — Properties.

As of December 31, 2002, the estimated available production from the merchant generation fleet for 2003 was approximately 89 million megawatt hours (Mwh), which consists of approximately 70 million Mwh for the combined cycle units and approximately 19 million Mwh for the peaker units. As of December 31, 2002, estimated production from the merchant generation fleet for 2003 was approximately 27 million Mwh for the combined cycle units and approximately 1 million Mwh for the peaker units. As of December 31, 2002, the estimated production from the managed merchant generation fleet that was hedged was 102% for 2003, 79% for 2004 and 64% for 2005 at average prices per Mwh of $51 for 2003, $44 for 2004 and $39 for 2005.

The Company’s principal customers for power and natural gas marketing and transportation services are industrial end-users, marketers, local distribution companies and utilities located throughout the U.S., Canada, Asia Pacific, Europe and Latin America. The Company has concentrations of receivables from natural gas and electric utilities and their affiliates, as well as industrial customers and marketers throughout these regions. These concentrations of customers may affect the Company’s overall credit risk in that risk factors can negatively impact the credit quality of the entire sector. Where exposed to credit risk, the Company analyzes the counterparties’ financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of those limits on an ongoing basis.

The Company frequently uses master collateral agreements to mitigate certain credit exposures, primarily in its trading and marketing operations. The collateral agreements provide for a counterparty to post cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an unsecured credit limit, determined in accordance with the corporate credit policy. The collateral agreement also provides that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions.

Natural Gas Transmission and Field Services also obtain cash or letters of credit from customers, where appropriate, based on their financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each transaction.

Company may be required to return certain held collateral and post additional collateral should price movements adversely impact the value of open contracts or positions. In many cases, the Company’s and its counterparties’ publicly disclosed credit ratings impact the amounts of additional collateral to be posted. Recent downgrades in the Company’s affiliates’ credit ratings resulted in the Company posting more collateral with counterparties, and any further downgrade could require the posting of additional collateral. Likewise, downgrades in credit ratings of counterparties could require counterparties to post additional collateral to the Company. (See Liquidity and Capital Resources — Financing Cash Flows and Liquidity for additional discussion of downgrades.)

The change in market value of NYMEX-traded futures and options contracts requires daily cash settlement in margin accounts with brokers. Financial derivatives are generally cash settled periodically throughout the contract term. However, these transactions are also generally subject to margin agreements with many of the Company’s counterparties.

Following the bankruptcy of Enron, the Company terminated substantially all contracts with Enron. As a result, in 2001 the Company recorded, as a charge, a non-collateralized accounting exposure of $19 million. The $19 million non-collateralized accounting exposure was composed of charges of $12 million at DENA, $3 million at International Energy, $3 million at Field Services and $1 million at Natural Gas Transmission. These amounts were stated on a pre-tax basis as charges against the reporting segment’s earnings in 2001.

The Company’s claims made in the Enron bankruptcy case exceeded its non-collateralized accounting exposure. Bankruptcy claims that exceed this amount primarily relate to termination and settlement rights under normal purchases and normal sales contracts where Enron was the counterparty.

Substantially all contracts with Enron were completed or terminated prior to December 31, 2001. The Company has continuing contractual relationships with certain Enron affiliates, which are not in bankruptcy. In Brazil, a power purchase agreement between a Company affiliate, Paranapanema, and Elektro Eletricidade e Servicos S/A (Elektro), a distribution company approximately 100% owned by Enron, will expire December 31, 2005. The contract was executed by the Company’s predecessor in interest in Paranapanema, and obligates Paranapanema to provide energy to Elektro on an irrevocable basis for the contract period. In addition, a purchase/sale agreement expiring September 1, 2005 between a the Company affiliate and Citrus Trading Corporation (Citrus), a joint venture between Enron and El Paso Corporation, continues to be in effect. The contract requires the Company affiliate to provide natural gas to Citrus. Citrus has provided a letter of credit in favor of the Company to cover its obligations.

The Company is exposed to risk resulting from changes in interest rates as a result of its issuance of variable-rate debt and commercial paper. The Company manages its interest rate exposure by limiting its variable-rate and fixed-rate exposures to percentages of total capitalization and by monitoring the effects of market changes in interest rates. The Company also enters into financial derivative instruments, including, but not limited to, interest rate swaps, swaptions and U.S. Treasury lock agreements to manage and mitigate interest rate risk exposure. (See Notes 1, 6, 10, and 11 to the Consolidated Financial Statements.)

Based on a sensitivity analysis as of December 31, 2002, it was estimated that if market interest rates average 1% higher (lower) in 2003 than in 2002, earnings before income taxes would decrease (increase) by approximately $38 million. Comparatively, based on a sensitivity analysis as of December 31, 2001, had interest rates averaged 1% higher (lower) in 2002 than in 2001, it was estimated that earnings before income taxes would have decreased (increased) by approximately $38 million. These amounts include the effects of interest rate hedges and were determined by considering the impact of the hypothetical interest rates on the variable-rate securities outstanding as of December 31, 2002 and 2001. If interest rates changed significantly, management would likely take actions to manage its exposure to the change. However, due to the uncertainty of the specific

actions that would be taken and their possible effects, the sensitivity analysis assumes no changes in the Company’s financial structure.

The Company participates in Duke Energy’s non-contributory defined benefit retirement and postretirement benefit plans. Duke Energy’s, and therefore the Company’s, costs of providing non-contributory defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, such as the rates of return on plan assets, discount rate, the rate of increase in health care costs and contributions made to the plans. The market value of Duke Energy’s defined benefit retirement plan assets has been affected by declines in the equity market since 2000. As a result, at September 30, 2002 (Duke Energy’s measurement date), Duke Energy’s pension plan obligation, excluding Westcoast, exceeded the value of the plan assets and Duke Energy was therefore required to recognize a minimum liability as prescribed by SFAS No. 87, “Employers’ Accounting for Pensions,” and SFAS No. 132, “Employers’ Disclosures about Pensions and Postretirement Benefits.”

Pension cost and cash funding requirements could increase in future years without a substantial recovery in the equity markets. Funding requirements for defined benefit pension plans are determined by government regulations, not SFAS No. 87. Duke Energy anticipates that it will make a contribution to its defined benefit pension plan in 2004 for the 2003 plan year. The Company would be required to fund its portion to Duke Energy on a pro rata basis. The Company also anticipates that it will make a contribution of approximately $10 million to the Westcoast pension plans in 2003 for the 2003 plan year. Contributions for the 2004 plan year and beyond may vary based on the actual return on the defined benefit pension plan’s assets, as well as other factors.

The Company is exposed to foreign currency risk from investments in international affiliates and businesses owned and operated in foreign countries. To mitigate risks associated with foreign currency fluctuations, contracts may be denominated in or indexed to the U.S. dollar and/or local inflation rates, or investments may be hedged through debt denominated or issued in the foreign currency. The Company may also use foreign currency derivatives, where possible, to manage its risk related to foreign currency fluctuations. To monitor its currency exchange rate risks, the Company uses sensitivity analysis, which measures the impact of devaluation of the foreign currencies to which it has exposure.

As of December 31, 2002, the Company’s primary foreign currency rate exposures were the Canadian dollar, the Brazilian real, the Peruvian nuevo sol, the Australian dollar, the El Salvadoran colon, the European euro and the Argentine peso. A 10% devaluation in the currency exchange rate in all of these foreign currencies would be immaterial to the Company’s Consolidated Statements of Income. The Consolidated Balance Sheets would be negatively impacted by approximately $300 million currency translation through the cumulative translation adjustment in OCI.

In 1991, the Argentine peso was pegged to the U.S. dollar at a fixed 1:1 exchange ratio. In December 2001, the Argentine government imposed a restriction that limited cash withdrawals above a certain amount and foreign money transfers. Financial institutions were allowed to conduct limited activity, a holiday was announced, and currency exchange activity was essentially halted. The government also required that all dollar-denominated contracts be converted to pesos. In January 2002, the Argentine government announced the creation of a dual-currency system. Subsequently, however, the Argentine government changed to a managed free-floating currency.

The Company’s investment in Argentina was U.S. dollar functional as of December 31, 2001. Once a functional currency determination has been made, that determination must be adhered to consistently, unless significant changes in economic factors indicate that the entity’s functional currency has changed. The events in

Argentina required a change. In January 2002, the functional currency of the Company’s investment in Argentina changed from the U.S. dollar to the Argentine peso. In compliance with SFAS No. 52, “Foreign Currency Translation,” the change in functional currency was made prospectively. Management believes that the events in Argentina will have no material adverse effect on the Company’s future consolidated results of operations, cash flows or financial position.

Wholesale Competition. In 2000, the FERC issued Order 637, which revised its regulations for the intended purpose of improving the competitiveness and efficiency of natural gas markets. Order 637 effects changes in capacity segmentation, rights of first refusal (ROFR), scheduling procedures, as well as various reporting requirements intended to provide more transparent pricing information and permit more effective monitoring of the market. The FERC also required each interstate pipeline to submit individual compliance filings to implement the requirements of Order 637. Several parties, including the Company, filed appeals in the District of Columbia Court of Appeals seeking court review of various aspects of Order 637, including (i) the right of customers to segment their capacity rights in a manner that would allow both a forwardhaul and a backhaul transportation transaction to a single delivery point, and (ii) the ROFR granted to existing customers the right to extend contracts beyond the end of the contract’s primary term. In 2002, the District of Columbia Court of Appeals generally affirmed the Order but remanded certain issues to the FERC for further disposition, including the forwardhaul/backhaul and ROFR issues. These matters are still under review by the FERC. In addition to the Order 637 general rulemaking proceeding, the Company’s interstate pipelines made individual tariff filings to comply with the requirements of Order 637. These individual compliance proceedings are in different stages of the review, approval and implementation process before the FERC. Management believes that the implementation of Order 637 will have no material adverse effect on the Company’s future consolidated results of operations, cash flows or financial position.

In addition, the FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to the FERC’s jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation of the natural gas industry.

Retail Competition. Changes in regulation to allow retail competition could affect the Company’s natural gas transportation contracts with local natural gas distribution companies. Since natural gas retail deregulation is in the very early stages of development, management believes the effects of this matter will have no material adverse effect on the Company’s future consolidated results of operations, cash flows or financial position.

For information on other current issues related to the Company, see the following Notes to the Consolidated Financial Statements: Note 4, Natural Gas Transmission and Notices of Proposed Rulemaking sections and Note 13, Environmental and Litigation sections.

SFAS No. 142, “Goodwill and Other Intangible Assets.” The Company adopted SFAS No. 142 as of January 1, 2002. SFAS No. 142 requires that goodwill no longer be amortized over an estimated useful life, as previously required. Instead, goodwill amounts are subject to fair value-based impairment assessments. The Company did not recognize any material impairment due to the adoption of SFAS No. 142. (For material

impairments subsequent to the adoption of SFAS No. 142, see Note 8 to the Consolidated Financial Statements.) SFAS No. 142 also requires certain identifiable intangible assets to be recognized separately and amortized as appropriate upon adoption. No adjustments to intangibles were identified by the Company at adoption.

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

SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” The Company adopted SFAS No. 144 on January 1, 2002. The new rules supersede SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of.” The new rules retain many of the fundamental recognition and measurement provisions, but significantly change the criteria for classifying an asset as held-for-sale or as a discontinued operation. (For material impairments since the adoption of SFAS No. 144, see Note 8 to the Consolidated Financial Statements.)

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.” In June 2002, the FASB’s EITF reached a partial consensus on Issue No. 02-03. The EITF concluded that, effective for periods ending after July 15, 2002, mark-to-market gains and losses on energy trading contracts (including those to be physically settled) must be shown on a net basis in the Consolidated Statements of Income. The Company had previously chosen to report certain of its energy trading contracts on a gross basis, as sales in operating revenues, and to record the associated costs in operating expenses, in accordance with prevailing industry practice. The amounts in the Consolidated Statements of Income for 2001 and 2000 have been reclassified to conform to the 2002 presentation of recording all amounts on a net basis in operating revenues. The following table shows the impact of changing from gross to net presentation for energy trading activities on the Company’s revenues (offsetting adjustments were made to operating expenses resulting in no impact on operating income or net income).

Revenues — Implementation of Gross vs. Net Presentation in EITF Issue No. 02-03

In the calculation of net revenues, the Company has continued to enhance its methodologies around the application of this complex accounting literature since the third quarter 2002 when these trading revenues were first reported on a net basis.

earnings or losses at the time of contract settlement or termination. New non-derivative energy trading contracts entered into after October 25, 2002 are accounted for under the accrual accounting basis. Non-derivative energy trading contracts on the Consolidated Balance Sheet as of January 1, 2003 that existed on October 25, 2002 and inventories that were recorded at fair values will be adjusted to historical cost via a net-of-tax and minority interest cumulative effect adjustment of $25 million to $75 million as a reduction to first quarter 2003 earnings.

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

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

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

Certain of the Company’s regulated operations recognize some removal costs as a component of depreciation in accordance with regulatory treatment. While these amounts will remain in accumulated depreciation, to the extent these amounts do not represent SFAS No. 143 legal retirement obligations, they will be disclosed as part of the regulatory matters footnote upon adoption of SFAS No. 143.

SFAS No. 143 was effective for fiscal years beginning after June 15, 2002, and will be adopted by the Company in the first quarter of 2003. The implementation of the standard is expected to result in a net increase in total assets of approximately $35 million, consisting primarily of an increase in net property, plant and equipment of approximately $27 million and an increase in regulatory assets of approximately $10 million. Liabilities are expected to increase by approximately $47 million, which primarily represents the establishment of an asset retirement obligation liability of $58 million, reduced by negative salvage of approximately $5 million and deferred taxes of approximately $6 million. For obligations related to non-regulated operations, a net-of-tax cumulative effect of a change in accounting principle adjustment of approximately $12 million is expected to be recorded in the first quarter of 2003, as a reduction in earnings.

SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” In June 2002, the FASB issued SFAS No. 146 which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” The Company has adopted the provisions of SFAS No. 146 for any restructuring activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF Issue No. 94-3, a liability for an exit cost was recognized on the date of the Company’s commitment to an exit plan. SFAS No. 146 also establishes that the

liability should initially be measured and recorded at fair value. Accordingly, SFAS No. 146 will affect the timing of recognizing future restructuring costs as well as the amounts recognized.

FASB Interpretation No. 45 (FIN 45), “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” In November 2002, the FASB issued FIN 45 which requires a guarantor to recognize a liability for the fair value of the obligation it assumes under certain guarantees. Additionally, FIN 45 requires a guarantor to disclose certain aspects of each guarantee, or each group of similar guarantees, including the nature of the guarantee, the maximum exposure under the guarantee, the current carrying amount of any liability for the guarantee, and any recourse provisions allowing the guarantor to recover from third parties any amounts paid under the guarantee. The disclosure provisions of FIN 45 are effective for financial statements for both interim and annual periods ending after December 15, 2002. (See Note 14 for additional information.) The fair value measurement provisions of FIN 45 are to be applied on a prospective basis to guarantees issued or modified after December 31, 2002.

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

In October 2002, the Company entered into a $244 million stock purchase agreement with National Fuel Gas Company, including the assumption of approximately $58 million in debt, under which it would acquire the Company’s wholly owned Empire State Pipeline. This natural gas pipeline, which originates at the U.S./Canada border and extends into New York, was acquired by the Company as part of the Westcoast acquisition in March 2002 (see Note 2 to the Consolidated Financial Statements). The sale to National Fuel Gas Company closed in February 2003.

In March 2003, the Company entered into an agreement to sell its 50% ownership interest in Duke/UAE Ref-Fuel LLC for $306 million to Highstar Renewable Fuels LLC. Duke/UAE Ref-Fuel LLC owns American Ref-Fuel Company LLC, a holding company for six waste-to-energy facilities in the northeastern U.S. The transaction, which is subject to a number of conditions including certain regulatory approvals, is expected to be finalized later in 2003 and have a positive impact on 2003 net income.

In March 2003, the Company entered into an agreement to sell its 23.6% ownership interest in Alliance Pipeline, Alliance Canada Marketing and the Aux Sable natural gas liquids plant to Enbridge Inc. and Fort Chicago Energy Partners L.P. for approximately $245 million. The transaction is expected to close by April 2003, with the exception of a small ownership interest related to the U.S. segment of Alliance Pipeline, which is expected to close in October 2003. That ownership interest represents about $11 million of the proceeds. The interests in the Alliance Pipeline, which originates in British Columbia and extends into Chicago, Illinois, along with Alliance Canada Marketing and the Aux Sable natural gas liquids plant, located at the outlet of the Alliance Pipeline in Chicago, Illinois, were acquired by the Company as part of the Westcoast acquisition in March 2002.

On March 26, 2003, the FERC issued staff recommendations relating to the FERC’s investigation into the causes of high wholesale electricity prices in the Western U.S. during 2000 and 2001 and an order in the FERC’s refund proceeding. The recommendations and order address, among other things: modifying the presiding judge’s refund findings with respect to the gas price component and certain other components of the refund calculation; issuance of show cause orders related to certain energy trading practices; requiring trading entities to demonstrate that they have corrected their internal processes for reporting trading data to the Trade Press in order to continue selling natural gas at wholesale; and establishing a ban on prearranged “round trip” trades as a condition of blanket certificates. Duke Energy is evaluating the staff recommendations and refund order to determine what, if any, impact they might have on Duke Energy.

In a matter related to the Sonatrach arbitration, Citrus recently filed suit in March 2003 against Duke LNG in the District Court of Harris County, Texas alleging that Duke LNG breached the parties’ natural gas purchase contract (the Citrus Agreement) by failing to provide sufficient volumes of gas to Citrus. Duke LNG contends that as a result of Sonatrach’s actions, Duke LNG experienced a loss of LNG supply that affects Duke LNG’s obligations and termination rights under the Citrus Agreement. The Citrus petition seeks unspecified damages and a judicial determination that contrary to Duke LNG’s position, Duke LNG has not experienced a loss of LNG supply. This matter is in its earliest stages. The Company is currently evaluating this claim and intends to vigorously defend itself.

For information on other subsequent events related to litigation and contingencies refer to Note 13 to the Consolidated Financial Statements, Litigation section.

Forward Looking Statements. The Company’s 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 the Company’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 the Company’s control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. Those factors include:

See “Management’s Discussion and Analysis of Results of Operations and Financial Condition, Quantitative and Qualitative Disclosures About Market Risk.”

Consolidation. Duke Capital Corporation (collectively with its subsidiaries, the Company) is a wholly owned subsidiary of Duke Energy Corporation (Duke Energy). The Consolidated Financial Statements include the accounts of the Company and all majority-owned subsidiaries, after eliminating significant intercompany transactions and balances. Investments in businesses not controlled by the Company, but over which it has significant influence, are accounted for using the equity method. (See Note 7 for additional information.)

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

Cash and Cash Equivalents. All liquid investments with maturities of three months or less at the date of purchase are considered cash equivalents.

Inventory. Inventory, except inventory held for trading, consists primarily of materials and supplies, natural gas and natural gas liquid (NGL) products held in storage for transmission, processing and sales commitments. This inventory is recorded at the lower of cost or market value, primarily using the average cost method. Inventory held for trading is marked to market.

Accounting for Hedges and Trading Activities. All derivatives not qualifying for the normal purchases and sales exemption under Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and energy trading contracts as described in the Financial Accounting Standards Board’s (FASB) Emerging Issues Task Force (EITF) Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” are recorded on the Consolidated Balance Sheets at their fair value as Unrealized Gains or Unrealized Losses on Mark-to-Market and Hedging Transactions. On the date that swaps, futures, forwards, option contracts or other derivatives are entered into, the Company designates the derivative as either held for trading (trading instrument); as a hedge of a forecasted transaction or future cash flows (cash flow hedge); as a hedge of a recognized asset, liability or firm commitment (fair value hedge); as a normal purchase or sale contract; or leaves the derivative undesignated and marks it to market. All energy trading contracts, as defined by EITF Issue No. 98-10, are classified as trading instruments.

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

When available, quoted market prices or prices obtained through external sources are used to verify a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical and expected correlations with quoted market prices. As of December 31, 2002 and 2001, 55% of the trading contracts’ fair value was determined using market prices and other external sources and 45% was determined using pricing models.

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

Trading. Prior to settlement of any energy contract held for trading purposes, a favorable or unfavorable price movement is reported as Trading and Marketing Net Margin in the Consolidated Statements of Income. An offsetting amount is recorded as Unrealized Gains or Unrealized Losses on Mark-to-Market and Hedging Transactions on the Consolidated Balance Sheets. When a contract to sell or buy is physically settled, the fair value entries are reversed and the gross amounts invoiced to the customer or due to the counterparty are included as Trading and Marketing Net Margin in the Consolidated Statements of Income. For financial settlement, the effect on the Consolidated Statements of Income is the same as physical transactions. For all contracts, the unrealized gain or loss on the Consolidated Balance Sheets is reversed and classified as a receivable or payable account until collected or paid. See the New Accounting Standards section below for a discussion of the implications of the EITF Issue No. 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” on the accounting for trading activities subsequent to October 25, 2002.

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

Fair Value Hedges. The Company enters into interest rate swaps to convert some of its fixed-rate long-term debt to floating-rate long-term debt and designates such interest rate swaps as fair value hedges. The Company also enters into electricity derivative instruments such as swaps, futures and forwards to manage the fair value risk associated with some of its unrecognized firm commitments to sell generated power due to changes in the market price of power. Upon designation of such derivatives as fair value hedges, prospective changes in the fair

value of the derivative and the hedged item are recognized in current earnings. All components of each derivative gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted.

Goodwill. Goodwill is the cost of an acquisition less the fair value of the net assets of the acquired business. Prior to January 1, 2002, the Company amortized goodwill on a straight-line basis over the useful lives of the acquired assets, ranging from 10 to 40 years. The amount of goodwill reported on the Consolidated Balance Sheets as of December 31, 2001 was $1,729 million, net of accumulated amortization of $388 million. The Company implemented SFAS No. 142, “Goodwill and Other Intangible Assets,” as of January 1, 2002. For information on the impact of SFAS No. 142 on goodwill and goodwill amortization, see the New Accounting Standards section of this footnote. (See Note 2 for information on significant goodwill additions and see Note 8 for information on goodwill impairments.)

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

Property, Plant and Equipment. Property, plant and equipment are stated at historical cost less accumulated depreciation. The Company capitalizes all construction-related direct labor and material costs, as well as indirect construction costs. Indirect costs include general engineering, taxes and the cost of funds used during construction. The cost of renewals and betterments that extend the useful life of property, plant and equipment is also capitalized. The cost of repairs, replacements and major maintenance projects is expensed as it is incurred. Depreciation is generally computed over the asset’s estimated useful life using the straight-line method. The composite weighted-average depreciation rates were 3.95% for 2002, 3.83% for 2001 and 3.84% for 2000.

When the Company retires its regulated property, plant and equipment, it charges the original cost plus the cost of retirement, less salvage, to accumulated depreciation and amortization. When it sells entire regulated operating units, or retires or sells non-regulated properties, the cost is removed from the property account and the related accumulated depreciation and amortization accounts are reduced. Any gain or loss is recorded as income, unless otherwise required by the applicable regulatory body.

Impairment of Long-Lived Assets. The Company reviews the recoverability of long-lived and intangible assets, excluding goodwill, when circumstances indicate that the carrying amount of the asset may not be recoverable. This evaluation is based on various analyses, including undiscounted cash flow projections. 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. 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. (See Note 8 for additional information.)

As of the acquisition date, the Company allocates goodwill to a reporting unit. The Company defines a reporting unit as an operating segment or one level below.

Unamortized Debt Premium, Discount and Expense. Premiums, discounts and expenses incurred with the issuance of outstanding long-term debt are amortized over the terms of the debt issues. Any call premiums or unamortized expenses associated with refinancing higher-cost debt obligations to finance regulated assets and operations are amortized consistent with regulatory treatment of those items, where appropriate.

Environmental Expenditures. The Company expenses environmental expenditures related to conditions caused by past operations that do not generate current or future revenues. Environmental expenditures related to operations that generate current or future revenues are expensed or capitalized, as appropriate. Liabilities are recorded when environmental assessments and/or cleanups are probable and the costs can be reasonably estimated.

Cost-Based Regulation. The Company accounts for its regulated operations under the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” The economic effects of regulation can result in a regulated company recording costs that have been or are expected to be allowed in the rate-setting process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. Accordingly, the Company records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. These regulatory assets and liabilities are classified in the Consolidated Balance Sheets as Regulatory Assets and Deferred Debits, and Deferred Credits and Other Liabilities. (See Note 4.) The Company periodically evaluates the applicability of SFAS No. 71, and considers factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, companies may have to reduce their asset balances to reflect a market basis less than cost, and write-off their associated regulatory assets and liabilities.

Revenues. Revenues on sales of natural gas, natural gas transportation, storage and distribution as well as sales of petroleum products are recognized when the service is provided. Revenues related to these services provided but not yet billed are estimated each month. These estimates are generally based on contract data, regulatory information, preliminary measurements and allocations, estimated distribution usage based on historical data adjusted for heating degree days, commodity prices and preliminary throughput measurements. Final bills for the current month are billed and collected in the following month. The allowance for doubtful accounts was $228 million as of December 31, 2002, and $255 million as of December 31, 2001. Receivables on

the Consolidated Balance Sheets included $204 million as of December 31, 2002, and $80 million as of December 31, 2001, for natural gas transportation, storage and distribution services provided but not yet billed.

Long-term contracts, primarily in the Other Energy Services segment, are accounted for using the percentage-of-completion method. Under the percentage-of-completion method, sales and gross profit are recognized as the work is performed, based on the relationship between costs incurred and total estimated costs at completion. Sales and gross profit are adjusted prospectively for revisions in estimated total contract costs and contract values. When the current estimates of total contract revenue and contract cost indicate a loss, a provision for the entire loss on the contract is recorded in that period. The provision for the loss arises because estimated cost for the contract exceeds estimated revenue.

See Accounting for Hedges and Trading Activities — Trading presented earlier in this footnote for discussion of accounting policies for the recognition of revenues related to trading activities.

Allowance for Funds Used During Construction (AFUDC). AFUDC, recorded in accordance with SFAS No. 71, represents the estimated debt and equity costs of capital funds necessary to finance the construction of new regulated facilities. AFUDC is a non-cash item and is capitalized as a component of Property, Plant and Equipment cost, with offsetting credits to Other Income and Expenses, net and to Interest Expense. After construction is completed, the Company is permitted to recover these costs, including a fair return, through inclusion in the rate base and in the depreciation provision. The total amount of AFUDC included in Other Income and Expenses, net and Interest Expense was $25 million in 2002, $7 million in 2001 and $4 million in 2000.

Rates used for capitalization of AFUDC by the Company’s regulated operations are calculated in compliance with GAAP rules.

Foreign Currency Translation. The Company translates assets and liabilities for its international operations, where the local currency is the functional currency, at year-end exchange rates. Revenues and expenses are translated using average exchange rates during the year. Foreign currency translation adjustments are included in the Consolidated Statements of Common Stockholder’s Equity and Comprehensive Income (Loss). In the financial statements for international operations, where the U.S. dollar is the functional currency, transactions denominated in the local currency have been remeasured in U.S. dollars. Remeasurement resulting from foreign currency gains and losses is included in the Consolidated Statements of Income.

Income Taxes. The Company and its subsidiaries file a consolidated federal income tax return and other U.S. and foreign jurisdictional returns as required. Deferred income taxes have been provided for temporary differences between the GAAP and tax carrying amounts of assets and liabilities. These differences create taxable or tax-deductible amounts for future periods. Investment tax credits have been deferred and are being amortized over the estimated useful lives of the related properties.

Excise and Other Pass-Through Taxes. The Company generally presents revenues net of pass-through taxes in the Consolidated Statements of Income.

Cumulative Effect of Change in Accounting Principle. The Company adopted SFAS No. 133 as amended and interpreted on January 1, 2001. In accordance with the transition provisions of SFAS No. 133, the Company recorded a net-of-tax cumulative effect adjustment of $69 million as a reduction in earnings. The net-of-tax cumulative effect adjustment reducing OCI and Common Stockholder’s Equity was $908 million. For the year ended December 31, 2001, the Company reclassified as earnings $225 million of losses from OCI for derivatives

included in the transition adjustment related to hedge transactions that settled. The amount reclassified out of OCI will be different from the amount included in the transition adjustment due to market price changes since January 1, 2001.

Other Comprehensive Income. The components of and changes in other comprehensive income (loss) are as follows:

New Accounting Standards. SFAS No. 142, “Goodwill and Other Intangible Assets.” The Company adopted SFAS No. 142 as of January 1, 2002. SFAS No. 142 requires that goodwill no longer be amortized over an estimated useful life, as previously required. Instead, goodwill amounts are subject to fair value-based impairment assessments. The Company did not recognize any material impairment due to the adoption of SFAS No. 142. (For material impairments subsequent to the adoption of SFAS No. 142, see Note 8.) SFAS No. 142 also requires certain identifiable intangible assets to be recognized separately and amortized as appropriate upon adoption. No adjustments to intangibles were identified by the Company at adoption.

Revenues — Implementation of Gross vs. Net Presentation in EITF Issue No. 02-03

In October 2002, the EITF, as part of their further deliberations on Issue No. 02-03, rescinded the consensus reached on Issue No. 98-10. As a result, all energy trading contracts that do not meet the definition of a derivative under SFAS No. 133, and trading inventories that previously had been recorded at fair values, will be recorded at their historical cost and reported on an accrual accounting basis resulting in the recognition of earnings or losses at the time of contract settlement or termination. New non-derivative energy trading contracts entered into after October 25, 2002 are accounted for under the accrual accounting basis. Non-derivative energy trading contracts on the Consolidated Balance Sheet as of January 1, 2003 that existed on October 25, 2002 and inventories that were recorded at fair values will be adjusted to historical cost via a net-of-tax and minority interest cumulative effect adjustment of $25 million to $75 million (unaudited) as a reduction to first quarter 2003 earnings.

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

Reclassifications. Certain prior period amounts have been reclassified to conform to current classifications.

Business Acquisitions. The Company consolidates assets and liabilities from acquisitions as of the purchase date, and includes earnings from acquisitions in consolidated earnings after the purchase date. Assets acquired and liabilities assumed are recorded at estimated fair values on the date of acquisition. The purchase price minus the estimated fair value of the acquired assets and liabilities is recorded as goodwill. The allocation of the purchase price may be adjusted if additional information on asset and liability valuations becomes available within one year after the acquisition.

Acquisition of Westcoast Energy Inc. (Westcoast). On March 14, 2002, the Company acquired Westcoast for approximately $8 billion, including the assumption of $4.7 billion of debt. The assumed debt consists of debt of

Westcoast, Union Gas Limited (Union Gas) (a wholly owned subsidiary of Westcoast) and various project entities that are wholly owned or consolidated by the Company. The interest rates on the assumed debt range from 1.8% to 15.0%, with maturity dates ranging from 2002 through 2031. Westcoast, headquartered in Vancouver, British Columbia, is a North American energy company with interests in natural gas gathering, processing, transmission, storage and distribution, as well as power generation and international energy businesses.

In the transaction, a Company subsidiary acquired all of the outstanding common shares of Westcoast in exchange for approximately $1.7 billion in cash (net of cash acquired) and approximately 49.9 million shares of Duke Energy common stock (including exchangeable shares of a Duke Energy Canadian subsidiary that are substantially equivalent to and exchangeable on a one-for-one basis for Duke Energy common stock). The value of the Duke Energy common stock issued was approximately $1.7 billion and was determined based on the average market price of Duke Energy’s common shares over the two-day period before and after the terms of the transaction became fixed, in accordance with EITF No. 99-12, “Determination of the Measurement Date for the Market Price of Acquirer Securities Issued in a Purchase Business Combination.” Under prorating provisions of the acquisition agreement that ensured that approximately 50% of the total consideration was paid in cash and 50% in stock, each common share of Westcoast entitled the holder to elect to receive 43.80 in Canadian dollars, or either 0.7711 of a share of Duke Energy common stock or of an exchangeable share of a Duke Energy Canadian subsidiary, or a combination thereof. The cash portion of the consideration was funded with the proceeds from the November 2001 issuance of $750 million of Company senior notes that are a component of Duke Energy’s mandatory convertible securities (Equity Units) (see Note 10) along with incremental commercial paper. The commercial paper was repaid using the proceeds from the October 2002 public offering of Duke Energy common stock.

The acquisition of Westcoast was consistent with the Company’s natural gas pipeline strategy to expand its footprint between key supply and market areas in North America. During its evaluation, the Company identified revenue enhancement opportunities through expansion projects and business integration, cost reduction initiatives, and the divestiture of several non-strategic business lines and assets. These initiatives, when combined with the ongoing earnings contributions from Westcoast’s pipelines and distribution businesses, supported a purchase price in excess of the fair value of Westcoast’s assets, which resulted in the recognition of goodwill. The Westcoast acquisition was accounted for using the purchase method, and goodwill of approximately $2.3 billion was recorded in the transaction, of which approximately $57 million is expected to be deductible for income tax purposes. Of this amount, $52 million was allocated for tax purposes to Empire State Pipeline which was sold in February 2003 (see Note 18).

The following table summarizes the estimated fair values of the assets acquired and liabilities assumed as of the acquisitions date.

As of December 31, 2002, the Company is still awaiting additional third party information to finalize the purchase accounting.

The following unaudited pro forma consolidated financial results are presented as if the acquisition had taken place at the beginning of the periods presented.

Dispositions. Duke Engineering & Services, Inc. (DE&S). On May 1, 2002, the Company completed the sale of portions of its DE&S business unit to Framatome ANP, Inc. (a nuclear supplier) for $74 million. Some minor assets and two components of DE&S were not part of the sale and remain components of Other Energy Services. The Company established Energy Delivery Services (EDS) in the second quarter of 2002 from the transmission and distribution services component of DE&S.EDS supplies electric transmission, distribution and substation services to customers. The Company also retained its ownership interest in Duke COGEMA Stone & Webster, LLC (DCS), the prime contractor on the U.S. Department of Energy Mixed Oxide Fuel project. Operating results in 2002 include the pre-tax gain of $26 million on the sale of DE&S.

DukeSolutions, Inc. (DukeSolutions). On May 1, 2002, the Company completed the sale of portions of DukeSolutions to Ameresco, Inc. for $6 million. The portions that were not sold remain a component of Other Energy Services. Operating results in 2002 include the pre-tax loss on the sale of DukeSolutions of $25 million.

The Company, an integrated provider of energy and energy services, offers physical delivery and management of both electricity and natural gas throughout the U.S. and abroad. The Company provides these and other services through six business segments.

Natural Gas Transmission provides transportation and storage of natural gas for customers throughout the East Coast and Southern U.S., and in Canada. Natural Gas Transmission also provides distribution service to retail customers in Ontario and Western Canada and gas gathering and processing services to customers in Western Canada. Natural Gas Transmission does business primarily through Duke Energy Gas Transmission Corporation. The Company acquired Westcoast on March 14, 2002 (see Note 2). Duke Energy Gas Transmission’s natural gas transmission and storage operations in the U.S. are subject to the Federal Energy Regulatory Commission’s (FERC’s) and the Texas Railroad Commission’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), the Ontario Energy Board (OEB) and the British Columbia Utilities Commission.

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 Duke Energy Field Services, LLC (DEFS), which is approximately 30% owned by ConocoPhillips and approximately 70% owned by the Company. Field Services gathers natural gas from production wellheads in Western Canada and 11 contiguous 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.

International Energy develops, operates and manages natural gas transportation and power generation facilities, and engages in sales and marketing of natural gas and electric power outside the U.S. and Canada. It conducts operations primarily through Duke Energy International, LLC and its activities target power generation in Latin America, power generation and natural gas transmission in Asia-Pacific and natural gas marketing in Northwest Europe.

Other Energy Services is composed of diverse energy businesses, operating primarily through Duke/Fluor Daniel (D/FD) and EDS. 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 the Company and Fluor Enterprises, Inc., a wholly owned subsidiary of Fluor Corporation. 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 DE&S. This component was excluded from the sale of

DE&S to Framatome ANP, Inc. on May 1, 2002. Other Energy Services also retained other portions of DE&S that were not part of the sale, as well as a portion of DukeSolutions that was not sold on May 1, 2002 to Ameresco, Inc. DE&S and DukeSolutions were included in Other Energy Services through the date of their sales. (See Note 2 for additional information on the sales of DE&S and DukeSolutions.)

Duke Ventures is composed of other diverse businesses, operating primarily through Crescent Resources, LLC (Crescent), DukeNet Communications, LLC (DukeNet) and Duke Capital Partners, LLC (DCP). 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 selected educational, governmental, financial and health care entities. DCP, a wholly owned merchant finance company, provides debt and equity capital and financial advisory services primarily to the energy industry. In March 2003, the Company announced that it will exit the merchant finance business at DCP in an orderly manner.

The Company’s reportable segments offer different products and services and are managed separately as business units. Accounting policies for the Company’s segments are the same as those described in Note 1. Management evaluates segment performance primarily based on earnings before interest and taxes (EBIT) after deducting minority interests. The following table shows how consolidated EBIT is calculated before deducting minority interests.

EBIT is the primary performance measure used by management to evaluate segment performance. On a segment basis, it includes all profits (both operating and non-operating) before deducting interest and taxes, and is net of the minority interest expense related to those profits. Management believes EBIT is a good indicator of each segment’s operating performance. As an indicator of the Company’s 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. The Company’s EBIT may not be comparable to a similarly titled measure of another company.

In the accompanying table, EBIT includes the profit on intersegment sales at prices management believes are representative of arms’ length transactions. The table also provides information on segment assets, net of intercompany advances, intercompany notes receivable, intercompany current assets, intercompany derivative assets and investments in subsidiaries. Other Operations primarily includes certain unallocated costs.

Regulatory Assets. The Company’s regulated operations are subject to SFAS No. 71. Accordingly, the Company records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. (See Note 1.) The following table details the Company’s regulatory assets.

Natural Gas Transmission. The British Columbia Pipeline System (BC Pipeline) and the field services business in western Canada have recorded approximately $479 million of regulatory assets related to deferred income tax liabilities. Under the current NEB rate structure, income tax costs are recovered in rates based on the current income tax payable and do not include accruals for deferred income tax. However, as income taxes become payable as a result of the reversal of timing differences that created the deferred income taxes, the transportation and field services’ rates will be adjusted to recover these taxes. Since most of these timing differences are related to property, plant and equipment costs, this recovery is expected to occur over a 20 to 30 year period.

When evaluating the recoverability of these BC Pipeline and the field services’ regulatory assets, management takes into consideration the NEB regulatory environment, natural gas reserve estimates for reserves located, or expected to be located, near these assets, the ability to remain competitive in the markets served, and projected demand growth estimates for the areas served by BC Pipeline and the field services business. Based on

current evaluation of these factors, management believes that recovery of these tax costs is probable over the periods described above.

Union Gas (which provides gas distribution, transportation and storage services in Ontario, Canada) has rates that are approved by the OEB. Rates for the sale of gas are adjusted quarterly, if required, to reflect updated commodity price forecasts. The difference between the approved and the actual cost of gas incurred in the current period is deferred pending approval by the OEB. Gas purchase costs deferred by Union Gas as of December 31, 2002 were $44 million, and are expected to be recovered from customers in 2003 and 2004. These amounts represent a direct flow-through of costs to customers and, therefore, no rate of return is earned on the deferred balances. The OEB’s approval for recovery of these gas purchase costs focuses on a review of the prudence of costs incurred. Management believes that recovery of these costs is probable.

Texas Eastern Transmission, LP, which is primarily engaged in the interstate transportation and storage of natural gas, has recorded approximately $65 million of regulatory assets related to income taxes, loss on redeemed debt and environmental clean-up costs. Management believes that recovery of these costs is probable.

In 2000, the FERC issued Order 637, which revised its regulations for the intended purpose of improving the competitiveness and efficiency of natural gas markets. Order 637 effects changes in capacity segmentation, rights of first refusal (ROFR), scheduling procedures, as well as various reporting requirements intended to provide more transparent pricing information and permit more effective monitoring of the market. The FERC also required each interstate pipeline to submit individual compliance filings to implement the requirements of Order 637. Several parties, including the Company, filed appeals in the District of Columbia Court of Appeals seeking court review of various aspects of Order 637, including (1) the right of customers to segment their capacity rights in a manner that would allow both a forwardhaul and a backhaul transportation transaction to a single delivery point, and (ii) the ROFR granted to existing customers to extend contracts beyond the end of the contract’s primary term. In 2002, the District of Columbia Court of Appeals generally affirmed the Order but remanded certain issues to the FERC for further disposition, including the forwardhaul/backhaul and ROFR issues. These matters are still under review by the FERC. In addition to the Order 637 general rulemaking proceeding, the Company’s interstate pipelines made individual tariff filings to comply with the requirements of Order 637, and these individual compliance proceedings are in different stages of the review, approval and implementation process before the FERC. Management believes that the implementation of Order 637 will have no material adverse effect on the Company’s future consolidated results of operations, cash flows or financial position.

The process for OEB approval of Union Gas’ rates for 2003 is currently underway. A settlement agreement was filed with the OEB on January 20, 2003. The agreement settled many financial and operating issues for 2003, including a rate decrease of 2.3% effective January 1, 2003 pursuant to the pricing formula set by the OEB in its performance based regulation decision. The settlement agreement was approved by the OEB in February 2003. A hearing was held before the NEB in February 2003 to resolve outstanding issues and a decision is pending.

During 2002, Union Gas applied to the OEB for a change to the OEB formula used to set the return on equity (ROE). The proposed methodology has the effect of increasing the ROE awarded to Union Gas effective January 1, 2002. The OEB has decided to review the applications in a combined hearing that is expected to take place in the third quarter of 2003. With the expiration of the Performance-Based Regulation (PBR) trial period at the end of 2003, Union Gas plans on filing a cost of service rate application in the second quarter of 2003 to establish 2004 rates and expects to file a proposal for second generation PBR for 2005 in the fourth quarter of 2004.

Management believes that the effects of these matters will have no material adverse effect on the Company’s future consolidated results of operations, cash flows or financial position.

Notices of Proposed Rulemaking (NOPR). NOPR on Standards of Conduct. In September 2001, the FERC issued a NOPR announcing they would substantially modify the current standards of conduct uniformly applicable to natural gas pipelines and electric transmitting public utilities currently subject to differing standards. The proposal impacts how companies and their affiliates interact and share information by broadening the definition of “affiliate” covered by the standards of conduct. The Company filed extensive comments on the NOPR with the FERC in December 2001. In April 2002, the FERC Staff issued an analysis of all comments received which reflected important progress in several areas. With regard to corporate governance, however, the FERC Staff’s analysis recommended adoption of an automatic imputation rule which could impact parent company oversight of subsidiaries with transmission functions (pipeline and storage functions). A public conference was held in May 2002 to discuss the proposed revisions to the gas and electric standards of conduct. The Company filed supplemental comments with respect to the FERC Staff’s analysis in June 2002. The FERC is expected to take further action on the NOPR in the first half of 2003.

Valuation allowances have been established for certain foreign net operating loss carryforwards that reduce deferred tax assets to an amount that will, more likely than not, be realized. The net change in the total valuation allowance is included in the tax differential on foreign earnings line of the Statutory Rate Reconciliation.

Deferred income taxes have not been provided on the undistributed earnings of the Company’s foreign subsidiaries as such amounts are deemed to be permanently reinvested.

The Company, substantially through its subsidiaries, is exposed to the impact of market fluctuations in the price of natural gas, electricity and other energy-related products marketed and purchased. The Company employs established policies and procedures to manage its risks associated with these market fluctuations using various energy trading contracts and commodity derivatives, including forward contracts, futures, swaps and options for trading purposes and for activity other than trading activity (primarily hedge strategies). The following table shows the fair value of the Company’s energy trading and derivative portfolio as of December 31, 2002.

Commodity Cash Flow Hedges. Some Company subsidiaries are exposed to market fluctuations in the prices of various commodities related to their ongoing power generating and natural gas gathering, distribution, processing and marketing activities. The Company closely monitors the potential impacts of commodity price

changes and, where appropriate, enters into contracts to hedge the value of its assets and operations from such price risks. The Company uses commodity instruments, such as swaps, futures, forwards and collared options, as cash flow hedges for natural gas, electricity and NGL transactions. The Company is hedging exposures to the price variability of these commodities for a maximum of 15 years.

The ineffective portion of commodity cash flow hedges and the amount recognized for transactions that no longer qualified as cash flow hedges were not material in 2002 or 2001. As of December 31, 2002, $182 million of after-tax deferred net gains on derivative instruments related to commodity cash flow hedges were accumulated on the Consolidated Balance Sheet in a separate component of stockholder’s equity, in OCI, and are expected to be recognized in earnings during the next 12 months as the hedged transactions occur. However, due to the volatility of the commodities markets, the corresponding value in OCI will likely change prior to its reclassification into earnings.

Commodity Fair Value Hedges. Some Company subsidiaries are exposed to changes in the fair value of some unrecognized firm commitments to sell generated power or natural gas due to market fluctuations in the underlying commodity prices. The Company actively evaluates changes in the fair value of such unrecognized firm commitments due to commodity price changes and, where appropriate, uses various instruments to hedge its market risk. These commodity instruments, such as swaps, futures and forwards, serve as fair value hedges for the firm commitments associated with generated power and natural gas sales. The Company is hedging exposures to the market risk of such items for a maximum of 10 years. For 2002 and 2001, the ineffective portion of commodity fair value hedges was not material.

Trading Contracts. The Company provides energy supply, structured origination, trading and marketing, risk management, and commercial optimization services to large energy customers, energy aggregators and other wholesale companies. These services require the Company to use natural gas, electricity, NGL and transportation contracts that expose it to a variety of market risks. The Company manages its trading exposure with policies that limit its market risk and require daily reporting of potential financial exposure to management. These policies include statistical risk tolerance limits using historical price movements to calculate a daily earnings at risk measurement.

Interest Rate (Fair Value or Cash Flow) Hedges. Changes in interest rates expose the Company to risk as a result of its issuance of variable-rate debt and commercial paper. The Company manages its interest rate exposure by limiting its variable-rate and fixed-rate exposures to percentages of total capitalization and by monitoring the effects of market changes in interest rates. The Company also enters into financial derivative instruments, including, but not limited to, interest rate swaps, swaptions and U.S. Treasury lock agreements to manage and mitigate interest rate risk exposure. The Company’s existing interest rate derivative instruments and related ineffectiveness were not material to its consolidated results of operations, cash flows or financial position in 2002 and 2001.

Gains and losses deferred in anticipation of planned financing transactions on interest rate swap derivatives are included in OCI and amortized over the life of the underlying debt once issued. These deferred gains and losses were not material in 2002 or 2001. As a result of the interest rate swap contracts, interest expense for the relative notional amount is recognized at the weighted-average rates as depicted in the following table.

Foreign Currency (Fair Value, Net Investment or Cash Flow) Hedges. The Company is exposed to foreign currency risk from investments in international affiliates and businesses owned and operated in foreign countries. To mitigate risks associated with foreign currency fluctuations, contracts may be denominated in or indexed to the U.S. dollar and/or local inflation rates, or investments may be hedged through debt denominated or issued in the foreign currency. The Company may also use foreign currency derivatives, where possible, to manage its risk related to foreign currency fluctuations. To monitor its currency exchange rate risks, the Company uses sensitivity analysis, which measures the impact of devaluation of foreign currencies.

Financial Instruments. The fair value of financial instruments not currently carried at market value is summarized in the following table. Judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates determined as of December 31, 2002 and 2001, are not necessarily indicative of the amounts the Company could have realized in current markets.

The fair value of cash and cash equivalents, receivables, payables and commercial paper are not materially different from their carrying amounts because of the short-term nature of these instruments or because the stated rates approximate market rates.

Credit Risk. The Company’s principal customers for power and natural gas marketing and transportation services are industrial end-users, marketers, local distribution companies and utilities located throughout the U.S., Canada, Asia Pacific, Europe and Latin America. The Company has concentrations of receivables from natural gas and electric utilities and their affiliates, as well as industrial customers and marketers throughout these regions. These concentrations of customers may affect the Company’s overall credit risk in that risk factors can negatively impact the credit quality of the entire sector. Where exposed to credit risk, the Company analyzes the counterparties’ financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of those limits on an ongoing basis.

Collateral amounts held or posted may be fixed or may vary depending on the value of the underlying contracts and cover trading, normal purchases and normal sales, and hedging contracts outstanding. The Company may be required to return certain held collateral and post additional collateral should price movements adversely impact the value of open contracts or positions. In many cases, the Company’s and its counterparties’ publicly disclosed credit ratings impact the amounts of additional collateral to be posted. Recent downgrades in the Company’s affiliates’ credit ratings resulted in the Company posting more collateral with counterparties and any further downgrade could require the posting of additional collateral. Likewise, downgrades in credit ratings of counterparties could require counterparties to post additional collateral to the Company.

The change in market value of New York Mercantile Exchange-traded futures and options contracts requires daily cash settlement in margin accounts with brokers. Financial derivatives are generally cash settled periodically throughout the contract term. However, these transactions are also generally subject to margin agreements with many of the Company’s counterparties.

Following the bankruptcy of Enron Corp., the Company terminated substantially all contracts with Enron Corp. and its affiliated companies (collectively, Enron). As a result, in 2001 the Company recorded as a charge, a non-collateralized accounting exposure of $19 million. The $19 million non-collateralized accounting exposure was composed of charges of $12 million at DENA, $3 million at International Energy, $3 million at Field Services and $1 million at Natural Gas Transmission. These amounts were stated on a pre-tax basis as charges against the reporting segment’s earnings in 2001.

Substantially all contracts with Enron were completed or terminated prior to December 31, 2001. The Company has continuing contractual relationships with certain Enron affiliates, which are not in bankruptcy. In Brazil, a power purchase agreement between a Company affiliate, Companhia de Geracao de Energia Electrica Paranapanema (Paranapanema), and Elektro Eletricidade e Servicos S/A (Elektro), a distribution company approximately 100% owned by Enron, will expire December 31, 2005. The contract was executed by the Company’s predecessor in interest in Paranapanema, and obligates Paranapanema to provide energy to Elektro on an irrevocable basis for the contract period. In addition, a purchase/sale agreement expiring September 1, 2005 between a Company affiliate and Citrus Trading Corporation (Citrus), a joint venture between Enron and El Paso Corporation, continues to be in effect. The contract requires the Company affiliate to provide natural gas to Citrus. Citrus has provided a letter of credit in favor of the Company to cover its obligations.

Investments in domestic and international affiliates that are not controlled by the Company, but over which it has significant influence, are accounted for using the equity method. Those investments include undistributed earnings of $108 million in 2002 and $166 million in 2001. The Company received distributions of $369 million in 2002, $158 million in 2001 and $137 million in 2000 from those investments. The Company’s share of net income from these unconsolidated affiliates is reflected in the Consolidated Statements of Income as Equity in Earnings of Unconsolidated Affiliates.

Natural Gas Transmission. Investments primarily include a 50% interest in Gulfstream Natural Gas System, LLC (Gulfstream), a 23.6% interest in Alliance Pipeline and a 30% interest in Vector Pipeline. Gulfstream is an interstate natural gas pipeline that extends from Mississippi and Alabama across the Gulf of Mexico to Florida. Although the Company owns a significant portion of Gulfstream, it is not consolidated as the Company does not hold a majority of voting control or bear a majority of the risk of loss or return. Alliance Pipeline is an interstate natural gas pipeline that extends from eastern Canada to the Chicago, Illinois area. In March 2003, the Company entered into an agreement to sell its 23.6% ownership interest in Alliance Pipeline, Alliance Canada Marketing and the Aux Sable natural gas liquids plant to Enbridge Inc. and Fort Chicago Energy Partners L.P. (see Note 18). Vector Pipeline is a joint interstate natural gas pipeline that extends from the Chicago, Illinois area through Indiana and Michigan and into Ontario, Canada.

Field Services. Investments primarily include a 21.1% ownership interest in TEPPCO Partners, LP, a publicly traded limited partnership which owns and operates a network of pipelines for refined products and crude oil.

Duke Energy North America. Significant investments include a 50% interest in American Ref-Fuel Company, LLC and a 50% interest in Southwest Power Partners, LLC. American Ref-Fuel Company LLC owns and operates facilities that convert waste to energy. Southwest Power Partners, LLC is a gas-fired combined-cycle facility in Arizona that serves markets in Arizona, Nevada and California. Although the Company owns a significant portion of these investments, they are not consolidated as it was determined that control was not present. In March 2003, the Company entered into an agreement to sell its 50% ownership interest in American Ref-Fuel Company LLC to Highstar Renewable Fuels LLC (see Note 18).

International Energy. Significant investments include a 25% indirect interest in National Methanol Company, which owns and operates a methanol and MTBE (methyl tertiary butyl ether) business in Jubail, Saudi Arabia.

Other Energy Services. Investments include participation in various construction and support activities for fossil-fueled generating plants through D/FD.

Duke Ventures. Significant investments include various real estate development projects through Crescent.

Outstanding notes receivable from unconsolidated affiliates were $113 million as of December 31, 2002 and $25 million as of December 31, 2001. Of the notes outstanding as of December 31, 2002, $104 million related to a note from partners in a project in which International Energy had a 30% ownership and the remaining $9 million related to notes that Crescent had with partners in two of its joint ventures. These outstanding notes receivables had interest rates at or above current market rates.

The Company evaluates its long-lived assets, excluding goodwill, for impairment under SFAS No. 144 (see Note 1). SFAS No. 144 requires long-term assets to be reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of the asset may not be recoverable. In 2002, the merchant energy portion of the Company’s business portfolio suffered from oversupply of merchant generation, low commodity pricing and volatility, and a steep decline in trading and marketing activity. These market challenges are continuing in 2003. As a result of the 2002 market conditions, the Company suspended certain projects and abandoned others in this sector. The culmination of these events caused the Company to evaluate the carrying values of certain of its long-lived assets at DENA and International Energy.

This analysis resulted in a $31 million impairment charge at one of DENA’s merchant power facilities. Additionally, charges of approximately $242 million were also recorded in 2002 to write-off site development costs in California and Brazil and to partially write-down uninstalled turbines, as well as, the termination of other turbines on order. A two-step process was performed in testing the assets for impairment. The impairment loss recorded was equal to the amount by which the carrying value exceeded the fair value of the assets. Fair value was based on prices for similar assets and a discounted cash flow analysis.

In 2002, a decision was made to abandon an information technology system at DENA resulting in the write-off of approximately $24 million of previously capitalized software and related costs.

During the fourth quarter of 2002, Field Services recorded impairments of approximately $40 million ($28 million at the Company’s 70% share) related to certain gas plants and gathering systems that have recently generated cash flow losses. Field Services 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 estimates of sales value and/or cash flow models.

The Company evaluates its goodwill for impairment under SFAS No. 142 (see Note 1). In 2002, the Company recorded a goodwill impairment loss of $194 million related to International Energy’s European trading and marketing business. Significant changes in the European market and recent operating results have adversely affected the Company’s outlook for this business unit. The exit of key market participants and a tightening of credit requirements are the primary drivers of this revised outlook. The fair value of the European reporting unit was estimated using the present value of expected future cash flows.

These impairments were recorded as charges to Operating Income in the Consolidated Statements of Income.

During 2002, the Company reduced its workforce to align the business with current market conditions. The Company recorded charges totaling approximately $70 million related to these reductions. The charges were recorded consistent with applicable accounting rules including EITF Issue No. 94-3 and SFAS No. 112, “Employers’ Accounting for Postemployment Benefits — An Amendment of FASB Statements No. 5 and 43.” Substantially all of these charges will be paid in 2003.

Capitalized interest impact of $193 million for 2002, $134 million for 2001 and $51 million for 2000 is included in the Consolidated Statements of Income. (See Note 1 for additional information on accounting policies related to property, plant and equipment.)

Unsecured debt, secured debt and other debt included $3,200 million of floating-rate debt as of December 31, 2002, and $784 million as of December 31, 2001. Floating-rate debt is primarily based on a spread relative to an index such as a London Interbank Offered Rate for debt denominated in U.S. dollars, Banker’s Acceptances for debt denominated in Canadian dollars and a Bank Bill Swap reference rate for debt denominated in Australian dollars. As of December 31, 2002, the average interest rate associated with floating-rate debt was 3.3%.

Other debt included $282 million related to a loan with D/FD as of December 31, 2002, and $568 million as of December 31, 2001. As part of the D/FD partnership agreement, excess cash is loaned at current market rates to the Company and Fluor Enterprises, Inc. The weighted-average rate of this loan was 2.5% as of December 31, 2002 and 4.05% as of December 31, 2001.

As of December 31, 2002, secured debt consisted primarily of various project financings, including THOR Investors, LLC (THOR) (see Note 12), P.T. Puncakjaya Power, Duke Energy Western Australia Holdings, Duke Australia Pipeline Finance Pty Ltd., Maritimes & Northeast Pipeline, LLC, Maritimes & Northeast Pipeline, LP, Empire State Pipeline and certain projects at Crescent. A portion of the assets, ownership interest and business contracts in these various projects are pledged as collateral.

Annual maturities after 2007 include $1,278 million of long-term debt with call options, which provide the Company with the option to repay the debt early. Based on the years in which the Company may first exercise its redemption options, it could potentially repay $928 million in 2003, $250 million in 2004 and $100 million in 2005.

In 2000, the Company issued $150 million senior unsecured bonds due in 2003 that may be required to be repaid if the Company’s senior unsecured debt ratings fall below BBB at Standard & Poor’s (S&P) or Baa2 at Moody’s Investors Service (Moody’s). As of February 28, 2003, the Company’s senior unsecured credit rating was BBB+ at S&P and Baa2 at Moody’s.

The following table summarizes the Company’s credit facilities and related amounts outstanding as of December 31, 2002. The majority of the credit facilities support commercial paper programs. The issuance of commercial paper, letters of credit and other borrowings reduces the amount available under the credit facilities. Amounts related to outstanding commercial paper and other borrowings in the following table are included in the previous long-term debt table.

11. Guaranteed Preferred Beneficial Interests in Subordinated Notes of Duke Capital Corporation

The Company has formed business trusts for which it owns all the common securities. The trusts issue and sell preferred securities and invest the gross proceeds in junior subordinated notes issued by the Company.

The trust preferred securities represent preferred undivided beneficial interests in the assets of the respective trusts. Distribution payments on the preferred securities are guaranteed by the Company, but only to the extent that the trust funds are legally and immediately available to make distributions. Dividends related to the trust preferred securities were $65 million for 2002, 2001 and 2000, and have been included in the Consolidated Statements of Income as Minority Interest Expense.

In 2000, Catawba River Associates, LLC (Catawba), a fully consolidated financing entity managed by a subsidiary of the Company, issued $1,025 million of preferred member interests to a third-party investor. Catawba subsequently advanced the proceeds from the issuance to DE Power Generation, LLC (DEPG), a wholly owned subsidiary of the Company, which indirectly owns or leases six merchant power generation facilities located in California, Maine and Indiana. Catawba was a limited liability company with a separate

existence and identity from its preferred members, and the assets of Catawba were separate and legally distinct from the Company. The preferred member interests received a quarterly preferred return equal to an adjusted floating reference rate (approximately 2.85% for the full year ended December 31, 2002 and 5.20% for the full year ended December 31, 2001).

The purpose of the transaction was to reimburse the Company for a portion of its prior investment in the DEPG assets through separate venture financing with third-party investors, not requiring direct recourse to the credit of the Company. The results of operations, cash flows and financial position of Catawba were consolidated with the Company for financial reporting purposes. The preferred member interests were included in Minority Interest in Financing Subsidiary on the 2001 Consolidated Balance Sheet, and the payments made with respect to the preferred return were included in Minority Interest Expense on the 2001 Consolidated Statement of Income of the Company. The initial term of the financing ends in September 2005 and is repayable at that time unless extended by mutual consent.

In September 2002, Catawba distributed the receivable from DEPG to the preferred member, THOR, which simultaneously withdrew its interest. As a result, the $1,025 million that DEPG previously owed to Catawba became an obligation to THOR and was reclassified on the 2002 Consolidated Balance Sheet to Long-term Debt. In October 2002, the Company purchased the equity interests in THOR and effectively reduced the debt to $994 million. Additionally, the Company financially guaranteed the $994 million in return for certain modifications to the terms of the credit agreement.

In connection with the Westcoast acquisition on March 14, 2002 (see Note 2), the Company assumed $411 million of authorized and issued redeemable preferred and preference shares at Union Gas and Westcoast. These shares are included in Minority Interest on the Consolidated Balance Sheet as of December 31, 2002.

The Company carries insurance coverage consistent with companies engaged in similar commercial operations with similar type properties. The Company’s insurance coverage includes (1) commercial general public liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from our operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage, and (4) property insurance covering the replacement value of all real and personal property damage, including damages arising from boiler and machinery breakdowns, earthquake, flood damage and business interruption/extra expense. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operations.

The Company also maintains excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Limits, terms, conditions and deductibles are comparable to those carried by other energy companies of similar size. The costs of the Company’s general insurance coverage have increased significantly over the past year reflecting general conditions in the insurance markets.

The Company is subject to international, federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters.

Remediation activities. The Company and its affiliates are responsible for environmental remediation at various impacted properties or contaminated sites similar to others in the energy industry. These include some properties that are part of the Company’s ongoing operations, as well as sites formerly owned or used by Company entities and sites owned by third parties. These matters typically involve management of contaminated soils and may involve ground water remediation. They are managed in conjunction with the relevant federal, state and local agencies. These sites or matters vary, for example, with respect to site conditions and location, remedial requirements, sharing of responsibility by other entities, and complexity. Certain matters can involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, whereby the Company or its affiliates could potentially be held responsible for contamination caused by other parties. In some instances, the Company may share any liability associated with contamination with other potentially responsible parties, and the Company may benefit from insurance policies or contractual indemnities that cover some cleanup costs. All these sites generally are managed in the normal course of the respective business or affiliate operations. Management believes that completion or resolution of these matters will have no material adverse effect on consolidated results of operations, cash flows, or financial position.

Air Quality Control. In 1998, the Environmental Protection Agency (EPA) issued a final rule on regional ozone control that required 22 eastern states and the District of Columbia to revise their State Implementation Plans to significantly reduce emissions of nitrogen oxide by May 1, 2003. The EPA rule was challenged in court by various states, industry and other interests, including the Company. In 2000, the court upheld most aspects of the EPA rule. The same court subsequently extended the compliance deadline for implementation of emission reductions to May 31, 2004.

Global Climate Change. In 1997, the United Nations held negotiations in Kyoto, Japan, as part of an ongoing process to address concerns over global warming and climate change. The resulting Kyoto Protocol prescribed greenhouse gas emission reductions among developed countries equivalent to five percent below their 1990 aggregate emission levels. While the Kyoto Protocol does not mandate specific mitigation actions or approaches, most participating developed nations understood an area of focus would be on reducing green house gas emissions at their sources, including, among other sources, fossil-fueled electric power generation and natural gas operations. In 2001 President George W. Bush stated his opposition to the Kyoto Protocol, and declared that the U.S. will not ratify it. Australia, where the Company has natural gas pipeline and some electric generation assets, has also declined to ratify the Kyoto Protocol.

Over 100 other countries have, however, ratified the Kyoto Protocol and it is possible that the agreement will enter into force and effect if other nations follow suit. Canada, where the Company owns and operates natural gas pipeline assets, ratified the Kyoto Protocol in December 2002. If Russia were also to ratify the Kyoto Protocol, then the treaty would enter into force and Canada would be obligated to reduce its average greenhouse gas emissions to 6% below 1990 levels over the period 2008 to 2012. In anticipation of the entry into force of the Kyoto Protocol, Canada is developing an implementation plan contemplating a mix of sector-specific measures requiring a range of mandatory business actions to achieve emissions reductions, as well as emissions caps coupled with an emissions trading system. Targets for emissions reductions under such a Canadian scheme could be established under negotiated covenants with industry sectors, including the oil and gas sector, which encompasses most of the Company’s Canadian natural gas pipeline assets. Should the Kyoto Protocol enter into force, and depending on the nature of policies and measures adopted by the Canadian government, it is possible that the Company’s Canadian assets could be required to reduce its present emissions of greenhouse gases in some manner and/or to purchase emissions credits in the Canadian market or take other steps.

In these and other respects, the entry into force of the Kyoto Protocol, and the domestic policies and measures of countries participating in the treaty regime, could have far-reaching and significant implications for

industries in those countries, including their respective energy sectors. These developments could specifically affect the Company’s operations in those countries that are participating in the Kyoto Protocol, like Canada. It might also provide new opportunities to companies, for example, in the natural gas sector or in emissions trading and marketing arenas. There are also U.S. and Australian domestic or state-specific initiatives and proposals that could have analogous effects on segments of the energy sector on different scales. The outcome of these discussions and negotiations, like those occurring in Canada as described above, is highly uncertain, and the Company cannot estimate the effects these discussions and negotiations might have on future consolidated results of operations, cash flows or financial position. The Company stays abreast of and engaged in the Kyoto Protocol discussions and related developments concerning the climate change issue, and will continue to assess and respond to its potential implications for the Company’s business operations in the U.S., Canada and around the world.

Extended Environmental Activities, Accruals. Included in Other Current Liabilities and Other Deferred Credits and Other Liabilities were accruals related to extended environmental-related activities of $84 million at December 31, 2002 and $143 million at December 31, 2001. The accrual for extended environmental-related activities represents the Company’s provisions for costs associated with some of its current and former sites and certain other environmental matters. Management believes that completion or resolution of these matters will have no material adverse effect on consolidated results of operations, cash flows, or financial position.

Western Power Disputes. California Litigation. Duke Energy, some of the Company’s subsidiaries and three current or former executives have been named as defendants, along with numerous other corporate and individual defendants, in one or more of a total of 15 lawsuits filed in California on behalf of purchasers of electricity in the State of California, with one suit filed on behalf of a Washington state electricity purchaser. Most of these lawsuits seek class-action certification and damages and other relief, as a result of the defendants’ alleged unlawful manipulation of the California wholesale electricity markets. These lawsuits generally allege that the defendants manipulated the wholesale electricity markets in violation of state laws against unfair and unlawful business practices and, in some suits, in violation of state antitrust laws. Plaintiffs in these lawsuits seek aggregate damages of billions of dollars. The lawsuits seek the restitution and/or disgorgement of alleged unlawfully obtained revenues for sales of electricity and, in some lawsuits, an award of treble damages for alleged violations of state antitrust laws.

The first six of these lawsuits were filed in late 2000 through mid-2001 and were consolidated before a single judge in San Diego. The plaintiffs in the six lawsuits filed a joint Master Amended Complaint in March 2002, which added additional defendants. The claims against the additional defendants are similar to those in the original complaints. In April 2002, some defendants, including Duke Energy, filed cross-complaints against various market participants not named as defendants in the plaintiffs’ original and amended complaints. In May 2002, certain cross-defendants removed these actions to federal court in San Diego.

The other nine of these 15 suits were filed in mid-to-late 2002. The state court suits have been removed to federal court, and all suits have been transferred to federal court in San Diego for pre-trial consolidation with the previously filed six lawsuits. Various motions are pending before the courts, including motions concerning the jurisdiction of the courts and motions to dismiss claims of the parties. In December 2002, the court ordered the remand of the original six suits, and certain defendants and cross-defendants have appealed that ruling. In February 2003, the Court of Appeals for the 9^th Circuit issued an order accepting the appeal and stayed the remand order of the district court.

In January 2003, the federal court in San Diego granted the motion of the defendants to dismiss the suit filed by the Washington state plaintiff. The court ruled that the plaintiff’s state law claims, including alleged violations of the California antitrust and unfair business practices laws, were barred on filed rate and federal preemption grounds.

In addition to the foregoing lawsuits, in March 2003 a California state court in Los Angeles unsealed a lawsuit originally filed in August 2002 against numerous energy company defendants, including DETM. The plaintiffs, seeking to act on behalf of the State of California under the False Claims Act, made claims similar to those in other lawsuits alleging manipulation of the electricity market in California, and claims that defendants, conspiring to defraud state governmental entities, made “false records or statements.” The plaintiffs sought unspecified damages in the maximum amount allowed under the pertinent laws. On January 15, 2003, this lawsuit was dismissed without prejudice.

Related Oregon and Washington Litigation. In December 2002, plaintiffs filed class actions against Duke Energy and numerous other energy companies in state court in Oregon (now moved to federal court in Oregon) and in federal court in Washington state making allegations similar to those in the California suits. Plaintiffs allege they paid unreasonably high prices for electricity and/or natural gas during the time period from January 2000 to the present as a result of defendants’ activities which were fraudulent, negligent and in violation of each state’s business practices laws. Among other things, they seek damages, an order from the court prohibiting the defendants from engaging in the alleged unlawful acts complained of, and an accounting of the transactions entered into for the purchase and sale of wholesale energy.

Trade publications. In November 2002, the Lieutenant Governor of the State of California, on behalf of himself, the general public and taxpayers of California, filed a class action against the publisher of natural gas trade publications and numerous other defendants, including seven Company entities, in state court in Los Angeles, alleging that the defendants engaged in various unlawful acts, including artificially inflating the index prices of natural gas reported in industry publications through collusive behavior, and have thereby violated state business practices laws. The plaintiffs seek an order prohibiting the defendants from engaging in the acts complained of, restitution, disgorgement of profits acquired through defendants’ alleged unlawful acts, an award of civil fines, compensatory and punitive damages in unspecified amounts and other appropriate relief.

Other proceedings. In addition to the lawsuits, several investigations and regulatory proceedings at the state and federal levels are looking into the causes of high wholesale electricity prices in the western U.S. during 2000 and 2001. At the federal level, numerous proceedings are before the FERC. Some parties to those proceedings have made claims for billions of dollars of refunds from sellers of wholesale electricity, including DETM. Some parties have also sought to revoke the authority of DETM and other DENA-affiliated electricity marketers to sell electricity at market-based rates. The FERC is also conducting its own wholesale pricing investigation. As a result, the FERC has ordered some sellers, including DETM, to refund, or to offset against outstanding accounts receivable, amounts billed for electricity sales in excess of a FERC-established proxy price. In June 2001, DETM offset approximately $20 million against amounts owed by the California Independent System Operator (CAISO) and the California Power Exchange (CalPX) for electricity sales during January and February 2001. This offset reduced the $110 million reserve established in 2000 to $90 million. Since December 31, 2000, the Company has closely managed the balance of doubtful receivables, and believes that the current pre-tax bad debt provision of $90 million is appropriate. No additional provisions for California receivables and market risk were recorded in 2001 or 2002.

In December 2002, the presiding administrative law judge in the FERC refund proceedings issued his proposed findings with respect to the mitigated market clearing price, including his preliminary determinations of

the refund liability of each seller of electricity in the CAISO and CalPX. These proposed findings estimate that DETM has refund liability of approximately $95 million in the aggregate to both the CAISO and CalPX. This would be offset against the remaining receivables still owed to DETM by the CAISO and CalPX. The proposed findings are the presiding judge’s estimates only, and are still subject to further recalculation and adoption by the FERC in connection with its ongoing wholesale pricing investigation. On March 3, 2003, various parties (including the California attorney general) filed at the FERC seeking modification of the FERC’s refund orders alleging that DETM and others manipulated wholesale electricity prices in periods prior to the initial refund period. DETM filed a response to these allegations with the FERC on March 20, 2003. For an update on this matter, see Note 18.

At the state level, the California Public Utilities Commission is conducting formal and informal investigations to determine if power plant operators in California, including some Company entities, have improperly “withheld,” either economically or physically, generation output from the market to manipulate market prices. In addition, the California State Senate formed a Select Committee to Investigate Price Manipulation of the Wholesale Energy Market (Select Committee). The Select Committee served a subpoena on Duke Energy and some of the Company’s subsidiaries seeking data concerning their California market activities. The Select Committee heard testimony from several witnesses but no one from Duke Energy or the Company has been subpoenaed to testify.

The California Attorney General is also conducting an investigation to determine if any market participants engaged in illegal activity, including antitrust violations, in the course of their electricity sales into wholesale markets in the western U.S. The Attorneys General of Washington and Oregon are participating in the California Attorney General’s investigation. The San Diego District Attorney is conducting a separate investigation into market activities and issued subpoenas to DETM and a DENA subsidiary.

The U.S. Attorney’s Office in San Francisco served a grand jury subpoena on Duke Energy in November 2002 seeking, in general, information relating to possible manipulation of the electricity markets in California, including potential antitrust violations. As with the other ongoing investigations related to the California electricity markets, Duke Energy is cooperating with the U.S. Attorney’s Office in connection with its investigation.

Sacramento Municipal Utility District (SMUD) and City of Burbank, California FERC Complaints. In July 2002 and August 2002, respectively, the Sacramento Municipal Utility District and the City of Burbank, California filed complaints with the FERC against DETM and other providers of wholesale energy requesting that the FERC mitigate alleged unjust and unreasonable prices in sales contracts entered into between DETM and the complainants in the first quarter of 2001. The complainants, alleging that DETM had the ability to exercise market power, claim that the contract prices are unjust and unreasonable because they were entered into during a period that the FERC determined the western markets to be dysfunctional and uncompetitive and that the western markets influenced their price. In support of their request to mitigate the contract price, the complainants rely on the fact that the contract prices are higher than prices in the West following implementation of the FERC’s June 2001 price mitigation plan. The complainants request the FERC to set “just and reasonable” contract rates and to promptly set a refund effective date. In September 2002, the FERC issued an order in the Sacramento matter setting forth, in part, that the matter be set for an evidentiary hearing to be held in abeyance until the parties engage in settlement negotiations and that a refund effective date of September 22, 2002 be established. DETM participated in settlement proceedings and reached a settlement with the SMUD in February 2003. In February 2003, the SMUD filed to withdraw its FERC complaint against DETM. On March 10, 2003, the FERC issued an order in the Burbank matter setting forth, in part, that the matter be set for an evidentiary hearing to be held in abeyance until the parties engage in settlement negotiations, and that a refund effective date of October 11, 2002

be established. On March 20, 2003, the FERC issued and order requiring the parties to the Burbank proceeding attend a settlement conference on April 1, 2003.

Colorado River Commission of Nevada (CRCN) /Pioneer Companies (Pioneer). The State of Nevada, through the CRCN, filed an “interpleader” complaint in federal court in Nevada on July 9, 2002, against Pioneer and 13 vendors, including DETM, who entered into power transactions with the CRCN between January 1998 and the filing date of the suit. The CRCN alleges that it purchased power on behalf of Pioneer but that Pioneer has disavowed its contractual liability to pay for certain of those power transactions. The CRCN asserts that DETM and the other vendors may have claims for the value of their contracts with the CRCN in excess of $100 million. The CRCN asks the court to assess the competing claims of the parties and distribute the assets which it seeks to deposit into the registry of the court (cash assets of approximately $35 million allegedly held for Pioneer’s behalf as well as the value of electric power delivered or to be delivered on Pioneer’s behalf) and issue other appropriate orders to resolve the claims while prohibiting the institution or prosecution of other proceedings affecting the claims at issue. DETM and certain other parties have filed motions to dismiss the complaint on various grounds. In February 2003, the court granted the motions of DETM and other interpleader defendants by dismissing the interpleader complaint in its entirety for lack of subject matter jurisdiction.

The Western Power Disputes are in their early stages. Duke Energy continues to evaluate the facts and asserted claims in the Western Power Disputes and intends to vigorously defend itself and the Company.

ExxonMobil Corporation Arbitration. In 2000, three of the Company’s subsidiaries initiated binding arbitration against three ExxonMobil Corporation subsidiaries (the ExxonMobil entities) concerning the parties’ joint ownership of DETM and related affiliates (the Ventures). At issue was a buy-out right provision under the joint venture agreements for these entities. If there is a material business dispute between the parties, which the Company alleged had occurred, the buy-out provision gives the Company the right to purchase ExxonMobil’s 40% interest in DETM. ExxonMobil does not have a similar right under the joint venture agreements and once the Company exercises the buy-out right, each party has the right to “unwind” the buy-out under certain specific circumstances. In December 2000, the Company exercised its right to buy the ExxonMobil entities’ interest in the Ventures. The Company claimed that refusal by the ExxonMobil entities to honor the exercise was a breach of the buy-out right provision, and sought specific performance of the provision. Duke Energy and the Company also made additional claims against the ExxonMobil entities for breach of the agreements governing the Ventures. ExxonMobil also asserted breach of contract claims against Duke Energy.

In December 2002, an arbitration panel issued a binding ruling against ExxonMobil on its claims against Duke Energy and granted Duke Energy favorable declaratory relief. Duke Energy and the Company have terminated the previously exercised buy-out provision.

Trading Matters. Since April 2002, 17 shareholder class actions have been filed against Duke Energy: 13 in the United States District Court for the Southern District of New York and four in the United States District Court for the Western District of North Carolina. The 13 lawsuits pending in New York were consolidated into one action and included as co-defendants Duke Energy executives and two investment banking firms. In December 2002, the New York court granted in all respects the defendants’ motion to dismiss the plaintiffs’ claims. The four lawsuits pending in North Carolina name as co-defendants Duke Energy executives. Two of the four North Carolina suits have been consolidated and involve claims under the Employee Retirement Income and Security Act relating to Duke Energy’s Retirement Savings Plan. This consolidated action names Duke Energy board members as co-defendants. In addition, Duke Energy has received three shareholder derivative notices demanding that it commence litigation against named executives and directors of Duke Energy for alleged

breaches of fiduciary duties and insider trading. Duke Energy’s response to the derivative demands is not required until 90 days after receipt of written notice requesting a response.

The class actions and the threatened shareholder derivative claims arise out of allegations that Duke Energy improperly engaged in “round trip” trades which resulted in an alleged overstatement of revenues over a three-year period. The plaintiffs seek recovery of an unstated amount of compensatory damages, attorneys’ fees and costs for alleged violations of securities laws. In one of the lawsuits, the plaintiffs assert a common law fraud claim and seek, in addition to compensatory damages, disgorgement and punitive damages. Duke Energy intends to vigorously defend itself, the Company, and its named executives and board members against these allegations.

In 2002, Duke Energy responded to information requests and subpoenas from the FERC, the Securities and Exchange Commission (SEC), and the Commodity Futures Trading Commission (CFTC), and to grand jury subpoenas issued by the U.S. Attorney’s office in Houston, Texas. All information requests and subpoenas seek documents and information related to trading activities, including so-called “round-trip” trading. Duke Energy received notice in mid-October that the SEC formalized its investigation regarding “round-trip” trading. Duke Energy and the Company are cooperating with the respective governmental agencies. For an update of the FERC matter, see Note 18.

Duke Energy submitted a final report to the SEC based on a review of approximately 750,000 trades made by various Duke Energy subsidiaries between January 1, 1999 and June 30, 2002. Outside counsel conducted an extensive review of trading, accounting and other records, with the assistance of Duke Energy senior legal, corporate risk management and accounting personnel. Duke Energy identified 28 “round-trip” transactions done for the apparent purpose of increasing volumes on the Intercontinental Exchange and 61 “round-trip” transactions done at the direction of one of Duke Energy’s traders that did not have a legitimate business purpose and were contrary to corporate policy.

As a result of the trading review, the Company has taken appropriate disciplinary action and put in place additional risk management procedures to improve and strengthen the oversight and controls of its trading operations. The Company has also reconfirmed to employees that engaging in simultaneous or prearranged transactions that lack a legitimate business purpose, or any trading activities that lack a legitimate business purpose, is against company policy.

As a result of Duke Energy’s findings in the course of its investigation related to the SEC inquiry on “round-trip” trades, DENA identified accounting issues that justified adjustments which reduced its operating income by $11 million during 2002. An additional $2 million charge was recorded in other Company business segments related to these findings. Duke Energy completed its analysis of such round-trip trades in 2002.

In October 2002, the FERC issued a data request to the “Largest North American Gas Marketers, As Measured by 2001 Physical Sales Volumes (Bcf/d),” including DETM. In general, the data request asks for information concerning natural gas price data that was submitted by the gas marketers to entities that publish natural gas price indices. DETM responded to the FERC’s data request and is also responding to requests that the CFTC has made for similar information. Management is unable to predict what, if any, action the FERC and the CFTC will take with respect to these matters. For an update of the FERC matter, see Note 18.

Sonatrach. Duke Energy LNG Sales, Inc. (Duke LNG) initiated arbitration proceedings against Sonatrach, the Algerian state-owned energy company, alleging that Sonatrach had breached its obligations by its failure to provide shipping under certain LNG Purchase and Transportation Agreements (the Sonatrach Agreements) relating to Duke LNG’s purchase of liquefied natural gas (LNG) from Algeria and its transportation by LNG tanker to Lake Charles, Louisiana. In response to Duke LNG’s claims, Sonatrach, together with its LNG sales

and marketing subsidiary, Sonatrading Amsterdam B.V. (Sonatrading), have claimed that Duke LNG repudiated the Sonatrach Agreements as a result of, among other things, Duke LNG’s alleged failure to diligently seek commitments from customers, and to submit offers to Sonatrading based on such commitments, for the purchase of LNG from Sonatrading. By virtue of Duke LNG’s alleged breaches, Sonatrach and Sonatrading seek to terminate the Sonatrach Agreements and to recover damages from Duke LNG. The final evidentiary hearing in the liability phase of this arbitration was concluded in January 2003 in London. Briefing and oral argument on this phase will be completed in March 2003, and a ruling from the panel on issues of liability is expected by late summer 2003. The damages phase for this proceeding will be scheduled following the panel’s liability ruling. Management believes that the final disposition of the Sonatrach proceedings will have no material adverse effect on the consolidated results of operations, cash flows or financial position. For an update on related litigation, see Note 18.

Enron Bankruptcy. In December 2001, Enron filed for relief pursuant to Chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York. Additional affiliates have filed for bankruptcy since that date. Certain affiliates of the Company engaged in transactions with various Enron entities prior to the bankruptcy filings. DETM was a member of the Official Committee of Unsecured Creditors in the bankruptcy cases which are being jointly administered, but as of February 2003, DETM resigned from the Official Committee of Unsecured Creditors in the Enron bankruptcy case. The Company has taken a reserve to offset its exposure to Enron.

In mid-November 2002, various Enron trading entities demanded payment from DETM and DEM for certain energy commodity sales transactions without regard to the set-off rights of DETM and DEM and demanded that DETM detail balances due under certain master trading agreements without regard to the set-off rights of DETM. On December 13, 2002, DETM and DEM filed an adversary proceeding against Enron, seeking, among other things, a declaration affirming each plaintiff’s right to set off its respective debts to Enron. The complaint alleges that the Enron affiliates were operated by Enron as its alter ego and as components of a single trading enterprise and that DETM and DEM should be permitted to exercise their respective rights of mutual set-off against the Enron trading enterprise under the Bankruptcy Code. The complaint also seeks the imposition of a constructive trust so that any claims by Enron against DETM or DEM are subject to the respective set-off rights of DETM and DEM. Enron has filed a motion to dismiss, asserting that DETM and DEM are not entitled to the requested relief.

Management believes that the final disposition of the Enron bankruptcy will have no material adverse effect on the consolidated results of operations, cash flows or financial position.

Other Litigation and Legal Proceedings. The Company and its subsidiaries are involved in other legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding performance, contracts, royalty disputes, mismeasurement and mispayment claims (some of which are brought as class actions), and other matters arising in the ordinary course of business, some of which involve substantial amounts. Management believes that the final disposition of these proceedings will have no material adverse effect on consolidated results of operations, cash flows or financial position.

investees and other third parties, or the occurrence of certain future events. The Company would record a reserve if events occurred that required that one be established. (See Note 14.)

The following table summarizes the Company’s contractual cash obligations for the items listed below for each of the years presented.

The Company leases assets in several areas of its operations. Consolidated rental expense for operating leases was $70 million in 2002, $72 million in 2001 and $53 million in 2000. Future minimum rental payments under operating leases consisted of the following as of December 31, 2002:

The Company and certain of its subsidiaries have various financial and performance guarantees and indemnifications which are issued in the normal course of business. As discussed below, these contracts include performance guarantees, stand-by letters of credit, guarantees of debt, surety bonds, and indemnifications. The Company enters into these arrangements to facilitate a commercial transaction with a third party by enhancing the value of the transaction to the third party.

Mixed Oxide (MOX) Guarantees. DCS is the prime contractor to the Department of Energy (DOE) under a contract (the Prime Contract) in which DCS will design, construct, operate and deactivate a MOX fuel fabrication facility (MOX FFF). The domestic MOX fuel project was precipitated by the U.S. and the Russian Federation agreeing to dispose of excess plutonium in their respective nuclear weapons programs through efforts to fabricate and irradiate MOX fuel in commercial nuclear reactors. As of December 31, 2002, the Company, through its indirect wholly owned subsidiary, Duke Project Services Group, Inc. (DPSG), held a 40% ownership interest in DCS. Additionally, Duke Power, an affiliate of the Company, has entered into a subcontract (the Duke Power Subcontract) under which Duke Power has agreed to prepare its McGuire and Catawba nuclear reactors (the Nuclear Reactors) for use of the MOX fuel and to purchase MOX fuel produced at the MOX FFF for use in the Nuclear Reactors.

As required under the Prime Contract, DPSG and the other owners of DCS have issued a guarantee (the DOE Guarantee) pursuant to which the owners of DCS jointly and severally guarantee to DOE all of DCS’ payment and performance obligations under the Prime Contract. The Prime Contract consists of a “Base Contract” phase and three optional phases, with the DOE having the right to extend the term of the Prime Contract to cover the three optional phases on a sequential basis, subject to DCS and the DOE reaching agreement through good faith negotiations on certain remaining open terms applying to each of these option phases. Each of the three option phases will be negotiated separately, as the time for exercising such option phase becomes due under the Prime Contract. If the DOE does not exercise its right to extend the term of the Prime Contract to cover any or all of the optional phases, DCS’ performance obligations under the Prime Contract will end upon completion of the then current performance phase. The Base Contract phase covers the design of the MOX FFF and design modifications to the Nuclear Reactors. The Base Contract phase provides for DCS to receive cost reimbursement plus a fixed fee. The first option phase includes construction and cold startup of the MOX FFF and modification of the Nuclear Reactors. The first option phase provides for DCS to receive cost reimbursement plus an incentive fee. The second option phase provides for taking the MOX FFF from cold to hot

startup, operation of the MOX FFF, and irradiation of the MOX fuel in the Nuclear Reactors. The second option phase provides for DCS to receive a cost reimbursement plus an incentive fee through hot startup and, thereafter, cost-sharing plus a fee. The third option phase provides for the deactivation of the MOX FFF. As of December 31, 2002, DCS’ performance obligations under the Prime Contract extended only to the Base Contract phase since the DOE has not yet exercised its option to extend the term of performance under the Prime Contract to the first option phase and DCS and the DOE have not yet agreed on all open terms and conditions applicable to such phase.

Additionally, DPSG and the other owners of DCS have issued a guarantee (the Duke Power Guarantee) pursuant to which the owners of DCS jointly and severally guarantee to Duke Power all of DCS’ payment and performance obligations under the Duke Power Subcontract or any other agreement between DCS and Duke Power implementing the Prime Contract. The Duke Power Subcontract consists of a “Base Subcontract” phase and two optional phases, with DCS having the right to extend each phase of the contract on a sequential basis, subject to Duke Power and DCS reaching agreement through good faith negotiations on certain remaining open terms applying to each of these option phases. Under the Base Subcontract phase, Duke Power will perform technical and regulatory work required to prepare the Nuclear Reactors to use MOX fuel. The Base Subcontract phase provides for Duke Power to receive cost reimbursement plus a fixed fee. The first option phase provides for modification to the Nuclear Reactors as well as additional technical and regulatory work. The first option phase provides for Duke Power to receive cost reimbursement plus a fee. The second option phase provides for Duke Power to purchase from DCS MOX fuel produced at the MOX FFF for use in the Nuclear Reactors, at discounts to prices of equivalent uranium fuel, over a 15 year period commencing upon completion of the first option phase. As of December 31, 2002, DCS’ performance obligations under the Duke Power Subcontract extended only to the Base Subcontract phase since DCS has not yet exercised its option to extend the term of performance under the Duke Power Subcontract to the first option phase and DCS and Duke Power have not yet agreed on all open terms and conditions applicable to such phase.

The cost reimbursement nature of DCS’ commitment under the Prime Contract and the Duke Power Subcontract limits the exposure of DCS. Credit risk to DCS is limited by the fact the Prime Contract is with the DOE, a U.S. governmental entity. DCS is under no obligation to perform any contract work under the Prime Contract before funds have been appropriated from the U.S. Congress.

The Company is unable to estimate the maximum potential amount of future payments DPSG could be required to make under the DOE Guarantee and the Duke Power Guarantee due to the uncertainty of whether: DOE will exercise its options under the Prime Contract, the parties to the Prime Contract and the Duke Power Subcontract, respectively, will reach agreement on remaining open terms for each option phase under such contracts, and the U.S. Congress will authorize funding for DCS’ work under the Prime Contract. Any liability of DPSG under the DOE Guarantee and the Duke Power Guarantee is directly related to and limited by the Prime Contract and the Duke Power Subcontract, respectively. DPSG also has recourse to the other owners of DCS for any amounts paid under the DOE Guarantee or the Duke Power Guarantee in excess of its proportional ownership percentage of DCS.

Other Guarantees and Indemnifications. The Company has issued performance guarantees to customers and other third parties that guarantee the payment and performance of other parties, including certain unconsolidated and affiliated entities. The maximum potential amount of future payments the Company could have been required to make under these performance guarantees as of December 31, 2002 was approximately $2.6 billion. Approximately $225 million of these performance guarantees expire between 2003 and 2004, approximately $350 million expire between 2005 and 2007, with the remaining performance guarantees not having a contractual expiration. Additionally, the Company has issued joint and several guarantees to certain of

the D/FD project owners, which guarantee the performance of D/FD under its engineering, procurement and construction (EPC) contracts and other contractual commitments. These guarantees do not have a contractual expiration and do not have a stated maximum amount of future payments the Company could be required to make under these performance guarantees. Additionally, Fluor Enterprises, Inc., as 50% owner in D/FD, has also issued similar joint and several guarantees to the same D/FD project owners. In accordance with the D/FD partnership agreement, each of the partners to D/FD is responsible for 50% of any payments to be made under these guarantee contracts.

Westcoast has issued performance guarantees or indemnifications to third parties which guarantee the performance of unconsolidated entities, such as equity method projects, and entities previously sold by Westcoast to third parties. These performance guarantees require Westcoast to make payment to the guaranteed third party upon the failure of the unconsolidated entity to make payment under certain of its contractual obligations, such as debt, purchase contracts and leases. The maximum potential amount of future payments Westcoast could have been required to make under these performance guarantees as of December 31, 2002 was approximately $325 million. Of these guarantees, approximately $150 million expire in 2003 and approximately $25 million expire from 2004 to 2007. The remainder expire after 2007 or do not have a contractual expiration.

Stand-by letters of credit are conditional commitments issued to guarantee the performance of non-wholly owned and affiliated entities to a third party or customer. The Company and Westcoast have obligations to make payment under these agreements and are triggered by the failure of the non-wholly owned or affiliated entity to make payment to the third party or customer according to the terms of the underlying contract. These contracts expire in various amounts between 2003 and 2004. The maximum potential amount of future payments the Company and Westcoast could have been required to make under these contracts as of December 31, 2002 was approximately $550 million. Related to these letters of credit, the Company has received collateral from the non-wholly owned and affiliated entities in the amount of approximately $250 million at December 31, 2002.

The Company has guaranteed the issuance of surety bonds, which obligates itself to a surety to make payment upon the failure of a non-wholly owned or affiliated entity to honor its obligations to a third party. As of December 31, 2002, the Company had guaranteed approximately $200 million of surety bonds outstanding related to obligations of non-wholly owned and affiliated entities. These bonds expire in various amounts primarily between 2003 and 2004.

Field Services and Natural Gas Transmission have issued certain guarantees of debt associated with non-wholly owned entities. In the event that the non-wholly owned subsidiaries default on the debt payments, Field Services or Natural Gas Transmission would be required to perform under the guarantees and make payment on the outstanding debt balance of the non-wholly owned subsidiaries. As of December 31, 2002, Field Services was the guarantor of approximately $100 million of debt associated with non-wholly owned entities and Natural Gas Transmission was the guarantor of approximately $5 million of debt associated with the non-wholly owned entities. These guarantees expire in 2003 for Field Services and 2019 for Natural Gas Transmission.

The Company has certain guarantees issued to customers or other third parties related to the payment or performance obligations of certain entities that were previously wholly owned but which have been sold to third parties, such as DukeSolutions and DE&S. These guarantees are primarily related to payment of lease obligations, debt obligations and performance guarantees related to goods and services provided. In connection with the sale of DE&S, the Company has received back-to-back indemnification from the buyer indemnifying the Company for any amounts paid by the Company related to the DE&S guarantees. In connection with the sale of DukeSolutions, the Company received indemnification from the buyer for the first $2.5 million paid by the Company related to the DukeSolutions guarantees. Additionally, for certain performance guarantees, the

Company has recourse to subcontractors involved in providing services to a customer. These guarantees have various terms, ranging from 2003 to 2019 with others having no specific term. The Company is unable to estimate the total maximum potential amount of future payments under these guarantees since most of the underlying guaranteed agreements do not contain any limits on potential liability.

The Company has entered into various indemnification agreements related to purchase and sale agreements and other types of contractual agreements with vendors and other third parties. These indemnification agreements typically cover environmental, tax, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. Typically, claims may be made by third parties under these indemnification agreements for various periods of time depending on the nature of the claim. The maximum potential exposure of the Company under these indemnification agreements can range from a specified dollar amount to an unlimited amount depending on the nature of the claim and the particular transaction. The Company is unable to estimate the total maximum potential amount of future payments under these indemnification agreements due to several factors, including uncertainty as to whether claims will be made under these indemnities.

Retirement Plans. The Company and its subsidiaries participate in Duke Energy’s non-contributory defined benefit retirement plan. It covers most U.S. employees using a cash balance formula. Under a cash balance formula, a plan participant accumulates a retirement benefit consisting of pay credits that are based upon a percentage (which may vary with age and years of service) of current eligible earnings and current interest credits.

Duke Energy’s policy is to fund amounts on an actuarial basis to provide assets sufficient to meet benefits to be paid to plan participants. No contributions to the Duke Energy plan were necessary in 2002, 2001 or 2000. The net unrecognized transition asset, resulting from the implementation of accrual accounting, is being amortized over approximately 20 years. Investment gains or losses are amortized over five years.

The fair value of Duke Energy’s plan assets was $2,120 million as of December 31, 2002 and $2,470 million as of December 31, 2001. The projected benefit obligations were $2,671 million as of December 31, 2002 and $2,528 million as of December 31, 2001.

The Company’s net periodic pension benefit, including amounts allocated by Duke Energy, was $37 million for 2002, $30 million for 2001 and $20 million for 2000.

Duke Energy also sponsors, and the Company participates in, an employee savings plan that covers substantially all employees. The Company expensed plan contributions, including amounts allocated by Duke Energy, of $30 million in 2002, $27 million in 2001 and $27 million in 2000.

Westcoast Retirement Plans. The Company acquired Westcoast on March 14, 2002. The Westcoast benefit plans are reported separately due to assumption differences. The average remaining service period of the active employees covered by the pension plan is 17 years.

As of the measurement date, the market value of the Westcoast pension plan assets was below the accumulated benefit obligation of $341 million, and Westcoast was required to record a minimum pension liability for U.S. reporting of $22 million ($14 million after-tax) as calculated under SFAS No. 87, “Employers’ Accounting for Pensions.” This resulted in an increase in the pension liability of $22 million, a decrease in other comprehensive income of $14 million and an increase in deferred tax assets of $8 million.

Other Post-retirement Benefits. The Company and most of its subsidiaries, in conjunction with Duke Energy, provide some health care and life insurance benefits for retired employees on a contributory and non-contributory basis. Employees are eligible for these benefits if they have met age and service requirements at retirement, as defined in the plans.

These benefit costs are accrued over an employee’s active service period to the date of full benefits eligibility. The net unrecognized transition obligation, resulting from accrual accounting, is amortized over approximately 20 years. With respect to the entire plan, the fair value of the plan assets was $227 million as of December 31, 2002 and $265 million as of December 31, 2001. The accumulated post-retirement benefit obligation was $779 million as of December 31, 2002 and $712 million as of December 31, 2001.

It is the Company’s and Duke Energy’s general policy to fund accrued post-retirement health care costs. Duke Energy funds post-retirement benefits through various mechanisms, including voluntary employee’s beneficiary association trusts, 401(h) funding and retired lives reserves.

The Company’s net periodic post-retirement benefit cost, including amounts allocated by Duke Energy, was $14 million for 2002, $10 million for 2001 and $13 million for 2000.

For measurement purposes of the Duke Energy plan, the net per capita cost of covered health care benefits for employees who are not eligible for Medicare is assumed to have an initial annual rate of increase of 10.5% in 2002 that will gradually decrease to 6% in 2008. For employees who are eligible for Medicare, an initial annual rate of increase of 13.5% in 2002 will gradually decrease to 6% in 2011. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans.

Westcoast Other Post-Retirement Benefits. The average remaining service period of the active employees covered by the other retirement benefits plans is 17 years.

For measurement purposes of the Westcoast plan, the net per capita cost of covered health care benefits for employees is assumed to have an initial annual rate of increase of 10.0% in 2002 that will gradually decrease to 5% in 2008. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans.

Balances due to or due from related parties included in the Consolidated Balance Sheets as of December 31, 2002 and 2001 are as follows:

Included in the Consolidated Statements of Income are operating revenues (including Trading and Marketing net margin) and management fees of $47 million for 2002, $35 million for 2001 and $220 million for 2000 related to intercompany sales to Duke Energy. Notes receivable from related parties are classified as either Receivables, or Other under Investments and Other Assets on the Consolidated Balance Sheets, depending on whether they are current or long-term notes.

In 2002, the Company’s Natural Gas Transmission segment recognized $28 million in earnings for a construction fee received from an unconsolidated affiliate related to the successful completion of Gulfstream. (See project description in Note 7.)

As a result of the Westcoast acquisition in 2002, the Company became a partner in the Alliance Pipeline and Vector Pipeline (see project descriptions in Note 7). As a result of commitments required of Westcoast related to its original investment in these projects, the Company also acquired commitments to pay for firm capacity on these pipelines. Payments for the year ended December 31, 2002 totaled $30 million. In March 2003, the Company entered into an agreement to sell its 23.6% ownership interest in Alliance Pipeline, Alliance Canada Marketing and the Aux Sable natural gas liquids plant to Enbridge Inc. and Fort Chicago Energy Partners L.P. for approximately $245 million. The transaction is expected to close by April 2003, with the exception of a small ownership interest related to the U.S. segment of Alliance Pipeline, which is expected to close in October 2003. (See Note 18.)

The Company and Fluor Enterprises, Inc. formed the D/FD 50/50 partnership in 1989. The partnership provides full-service siting, permitting, licensing, engineering, procurement, construction, start-up, operating and maintenance services for fossil-fired plants in the U.S. and internationally. D/FD is the primary builder of DENA’s merchant generation plants currently under construction. D/FD also builds some plants for Duke Power. Fifty percent of the profit earned by D/FD for the construction of DENA’s merchant generation plants, which is associated with the Company’s ownership, is deferred in consolidation until the plant is sold as part of DENA’s portfolio management strategy. Or, once the plant becomes operational, the deferred profit is amortized over the plant’s useful life. Fifty percent of the profit earned by D/FD for operating and maintenance services, which is associated with the Company’s ownership, is eliminated in consolidation. For the year ended December 31, 2002, the Company deferred profit of $159 million for D/FD construction contracts and eliminated profit of $3 million for operating and maintenance services. For the year ended December 31, 2001, the Company deferred profit of $54 million for construction contracts and eliminated profit of $9 million for operating and maintenance services. For the year ended December 31, 2000, the Company deferred profit of $16 million for construction contracts; there was no profit from operating and maintenance services to be eliminated in 2000. In addition, as part of the D/FD partnership agreement, excess cash is loaned at current market rates to the Company and Fluor Enterprises, Inc. (See Note 10.)

In the normal course of business, the Company’s consolidated subsidiaries enter into energy trading contracts or other derivatives with one another. On a separate company basis, each subsidiary accounts for such contracts as if it were transacted with a third party and records the contract using mark-to-market or accrual accounting, as applicable. For example, DETM may enter into a contract to purchase natural gas storage from DEFS. DEFS may record this contract using accrual accounting, while DETM may mark the contract to market through its current earnings. In the consolidation process, the effects of this intercompany contract are eliminated, and not reflected in the Company’s Consolidated Financial Statements. In all cases, energy trading contracts (and any resulting mark-to-market gains or losses) between consolidated subsidiaries are eliminated in the consolidation process.

Also see Note 12, Minority Interest, and Note 14, Guarantees and Indemnifications, for additional related party information.

During the third quarter of 2002, the Company recorded the following: charges at DENA for the termination of certain turbines on order and the write-down of other uninstalled turbines of $121 million (see Note 8), the partial write-off of site development costs (primarily in California) of $31 million (see Note 8), partial impairment of a merchant plant of $31 million (see Note 8), and demobilization costs related to the deferral of DENA merchant power projects of $12 million; charges of $91 million at International Energy for the write-off of site-development costs and the write-down of uninstalled turbines, primarily related to planned energy plants in Brazil (see Note 8); and severance charges of $12 million for work force reductions.

During the fourth quarter of 2002, the Company recorded charges at DENA for information technology systems write-offs of $24 million (see Note 8), and demobilization costs related to the deferral of DENA merchant power projects of $10 million; impairment of goodwill at International Energy’s European trading and marketing business of $194 million (see Note 8); asset impairments at Field Services of $40 million ($28 million at the Company’s 70% share) (see Note 8); and severance charges of $56 million for work force reductions.

During the fourth quarter of 2001, the Company recorded a $19 million provision for non-collateralized accounting exposure to Enron.

In October 2002, the Company entered into a $244 million stock purchase agreement with National Fuel Gas Company, including the assumption of approximately $58 million in debt, under which it would acquire the Company’s wholly owned Empire State Pipeline. This natural gas pipeline, which originates at the U.S./Canada border and extends into New York, was acquired by the Company as part of the Westcoast acquisition in March 2002 (see Note 2). The sale to National Fuel Gas Company closed in February 2003.

In March 2003, the Company announced that it will exit the merchant finance business at DCP in an orderly manner. The Company expects the exit to generate positive cash flows in 2003 and 2004.

In a matter related to the Sonatrach arbitration, Citrus recently filed suit in March 2003 against Duke LNG in the District Court of Harris County, Texas alleging that Duke LNG breached the parties’ natural gas purchase contract (the Citrus Agreement) by failing to provide sufficient volumes of gas to Citrus. Duke LNG contends that as a result of Sonatrach’s actions, Duke LNG experienced a loss of LNG supply that affects Duke LNG obligations and termination rights under the Citrus Agreement. The Citrus petition seeks unspecified damages and a judicial determination that contrary to Duke LNG’s position, Duke LNG has not experienced a loss of LNG supply. This matter is in its earliest stages. The Company is currently evaluating this claim and intends to vigorously defend itself.

For information on other subsequent events related to litigation and contingencies refer to Note 13, Litigation section.

We have audited the accompanying consolidated balance sheets of Duke Capital Corporation and subsidiaries (the Company) as of December 31, 2002 and 2001, and the related consolidated statements of income, common stockholder’s equity and comprehensive income and cash flows for each of the three years in the period ended December 31, 2002. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, on January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and on January 1, 2002, the Company adopted Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets.”

The financial statements of Duke Capital Corporation and subsidiaries (the Company) are prepared by management, who are responsible for their integrity and objectivity. The statements are prepared in conformity with generally accepted accounting principles in all material respects and necessarily include judgments and estimates of the expected effects of events and transactions that are currently being reported.

The Company’s system of internal accounting control is designed to provide reasonable assurance that assets are safeguarded and transactions are executed according to management’s authorization. Internal accounting controls also provide reasonable assurance that transactions are recorded properly, so that financial statements can be prepared according to generally accepted accounting principles. In addition, accounting controls provide reasonable assurance that errors or irregularities which could be material to the financial statements are prevented or are detected by employees within a timely period as they perform their assigned functions. The Company’s accounting controls are continually reviewed for effectiveness. In addition, written policies, standards and procedures, and an internal audit program augment the Company’s accounting controls.

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

The Company’s management, including the Chief Executive Officer and Chief Financial Officer, have conducted an evaluation of the effectiveness of the Company’s disclosure controls and procedures as defined in Exchange Act Rule 13a-14 during January through March 2003. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the disclosure controls and procedures are effective in ensuring that all material information required to be filed in this annual report has been made known to them in a timely fashion. The required information was effectively recorded, processed, summarized and reported within the time period necessary to prepare this annual report. The Company’s disclosure controls and procedures are effective in ensuring that information required to be disclosed in the Company’s reports under the Exchange Act are accumulated and communicated to management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. There have been no significant changes in internal controls, or in factors that could significantly affect internal controls, subsequent to the date the Chief Executive Officer and Chief Financial Officer completed their evaluation.

In 2001, DEFS along with its external auditors, identified certain deficiencies in the design and operation of its internal control procedures that were reportable control weaknesses. These control weaknesses related to balance sheet reconciliations, including supervisory review of such reconciliations, gas imbalances, joint venture accounting, employee benefit accruals and revenue-related issues. In addition, there were identified weaknesses reported in the areas of risk management procedures, accounts receivable, revenue accrual and natural gas liquid accounting. Throughout 2002, DEFS implemented internal control enhancements in each of the areas described above. These enhancements included improved systems and processes, implementation of accounting policies related to gas imbalances and other enhancements related to joint venture accounting, risk management procedures, and revenue and natural gas liquids accounting.

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

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

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

Consolidated Statements of Common Stockholder’s Equity and Comprehensive Income (Loss) for the Years Ended December 31, 2002, 2001 and 2000

Quarterly Financial Data (unaudited, included in Note 17 to the Consolidated Financial Statements)

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

All other schedules are omitted because they are not required, or because the required information is included in the Financial Statements or Notes.

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

By:

/s/ ROBERT P. BRACE

Robert P. Brace

Chairman of the Board and President

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

/s/ KEITH G. BUTLER

Keith G. Butler

Controller and Chief Financial Officer

/s/ ROBERT P. BRACE

Robert P. Brace

Chairman of the Board and President

Exhibits filed herewith are designated by an asterisk (*). All exhibits not so designated are incorporated by reference to a prior filing, as indicated.

The total amount of securities of the registrant or its subsidiaries authorized under any instrument with respect to long-term debt not filed as an exhibit does not exceed 10% of the total assets of the registrant and its subsidiaries on a consolidated basis. The registrant agrees, upon request of the Securities and Exchange Commission, to furnish copies of any or all of such instruments to it.

Delaware		51-0282142
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

Title of each class		Name of each exchange on which registered
7³/8% Quarterly Income Preferred Securities issued by Duke Capital Financing Trust I and guaranteed by Duke Capital Corporation		New York Stock Exchange, Inc.
7³/8% Trust Originated Preferred Securities issued by Duke Capital Financing Trust II and guaranteed by Duke Capital Corporation		New York Stock Exchange, Inc.
8³/8% Trust Preferred Securities issued by Duke Capital Financing Trust III and guaranteed by Duke Capital Corporation		New York Stock Exchange, Inc.
4.32% Senior Notes due 2006		New York Stock Exchange, Inc.
5.87% Senior Notes due 2006		New York Stock Exchange, Inc.

Estimated aggregate market value of voting stock held by nonaffiliates of the registrant at June 28, 2002 and March 3, 2003		None
Number of shares of Common Stock, without par value, outstanding at June 28, 2002 and March 3, 2003		1,010

	Years Ended December 31,
	2002		2001		2000		1999		1998
Natural Gas Transmission
Proportional Throughput Volumes, TBtu(a)(b)		3,160		1,781		1,771		1,893		1,459

Field Services
Natural Gas Gathered and Processed/Transported, TBtu/d(c)		8.3		8.6		7.6		5.1		3.6
NGL Production, MBbl/d(d)		391.9		397.2		358.5		192.4		110.2
Natural Gas Marketed,TBtu/d		1.6		1.6		0.7		0.5		0.4
Average Natural Gas Price per MMBtu(e)	$	3.22	$	4.27	$	3.89	$	2.27	$	2.11
Average NGL Price per Gallon	$	0.38	$	0.45	$	0.53	$	0.34	$	0.26

Duke Energy North America
Natural Gas Marketed,TBtu/d		17.7		12.3		11.9		10.5		8.0
Electricity Marketed and Traded, GWh(f)		546,245		334,517		275,258		109,634		98,991

Duke Energy International
Sales, GWh		21,443		18,896		16,949		—		—
Natural Gas Marketed,TBtu/d		4.2		2.7		1.0		—		—
Electricity Marketed and Traded, GWh		95,591		12,719		4,208		—		—

Name	Gross MW	Net MW	Fuel	Location	Approximate Ownership Interest (percentage)
Paranapanema	2,307	2,185	Hydro	Brazil	95	%
Hidroelectrica Cerros Colorados	576	523	Hydro/Natural gas	Argentina	91
Egenor	529	528	Hydro/Diesel/HFO	Peru	100
Puncakjaya Power	385	330	Coal/Diesel	Indonesia	86
Acajutla	293	265	HFO/Diesel	El Salvador	90
Western Australia Power	250	247	Natural Gas/Diesel	Australia	100
Electroquil	180	125	Diesel	Ecuador	69
DEI Guatemala y Cia	168	168	HFO/Diesel	Guatemala	100
Aquaytia	160	61	Natural Gas	Peru	38
Empressa Electrica Corani	126	63	Hydro	Bolivia	50
Glenbrook Power Station	112	108	Natural Gas/Kiln Gases	New Zealand	100
Compagnie Thermique du Rouvray	103	103	Natural Gas	France	100
Bairnsdale	86	86	Natural Gas	Australia	100

Total	5,275	4,792

Item		Page

	PART I.

1.	Business	1
	General	1
	Natural Gas Transmission	4
	Field Services	7
	Duke Energy North America	9
	International Energy	12
	Other Energy Services	13
	Duke Ventures	13
	Environmental Matters	14
	Geographic Regions	14
	Employees and Management	14
	Operating Statistics	15
2.	Properties	16
3.	Legal Proceedings	19

	PART II.

5.	Market for Registrant’s Common Equity and Related Stockholder Matters	20
6.	Selected Financial Data	20
7.	Management’s Discussion and Analysis of Results of Operations and Financial Condition	20
7A.	Quantitative and Qualitative Disclosures About Market Risk	62
8.	Financial Statements and Supplementary Data	63
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	122

	PART III.

14.	Controls and Procedures	122

	PART IV.

15.	Exhibits, Financial Statement Schedule, and Reports on Form 8-K	123
	Signatures	124
	Exhibit Index	127

Name	Gross MW	Net MW	Fuel	Location	Ownership Interest (percentage)
Moss Landing(a)	2,538	2,538	Natural gas	CA	100	%
Morro Bay(a)	1,002	1,002	Natural gas	CA	100
Murray(a)	1,240	1,240	Natural gas	GA	100
South Bay(a)	700	700	Natural gas	CA	100
Vermillion(b)	648	648	Natural gas	IN	100
Lee(b)	640	640	Natural gas	IL	100
Enterprise Energy(b)	640	640	Natural gas	MS	100
Southhaven(b)	640	640	Natural gas	MS	100
Sandersville(b)	640	640	Natural gas	GA	100
Marshall County(b)	640	640	Natural gas	KY	100
Hot Spring(a)	620	620	Natural gas	AR	100
Washington(a)	610	610	Natural gas	OH	100
Griffith Energy(a)	600	300	Natural gas	AZ	50
Arlington Valley(a)	570	570	Natural gas	AZ	100
Hinds(a)	520	520	Natural gas	MS	100
Maine Independence(a)	520	520	Natural gas	ME	100
Bridgeport(a)	500	333	Natural gas	CT	67
St. Francis(a)	494	248	Natural gas	MO	50
New Albany Energy(b)	385	385	Natural gas	MS	100
American Ref-Fuel(c)	380	190	Waste-to-energy	CT, MA, NJ, NY, PA	50
Bayside(a)	265	199	Natural gas	NB	75
Oakland(b)	165	165	Oil	CA	100
McMahon(d)	117	59	Natural gas	BC	50
Ft. Frances(d)	110	110	Natural gas	ON	100

Total	15,184	14,157

Reconciliation of Operating Income and EBIT to Net Income
	Years Ended December 31,
	2002		2001			2000
	(In millions)
Operating income	$	1,101	$	2,886		$	1,729
Other income and expenses		355		237			602

EBIT		1,456		3,123			2,331
Interest expense		879		561			621
Minority interest expense		64		283			263

Earnings before income taxes		513		2,279			1,447
Income taxes		249		854			521

Income before cumulative effect of change in accounting principle		264		1,425			926
Cumulative effect of change in accounting principle, net of tax		—		(69	)		—

Net income	$	264	$	1,356		$	926

EBIT by Business Segment
	Years Ended December 31,
	2002			2001			2000
	(In millions)
Natural Gas Transmission	$	1,174		$	608		$	562
Field Services		126			336			311
Duke Energy North America		74			1,498			346
International Energy		(102	)		286			341
Other Energy Services		118			(13	)		(59	)
Duke Ventures		173			183			568
Other Operations		(144	)		(6	)		31
EBIT attributable to minority interests		37			231			231

Consolidated EBIT	$	1,456		$	3,123		$	2,331

	Standard and Poors		Moody’s Investor Service	Fitch Ratings	Dominion Bond Rating Service (DBRS)
Duke Capital Corporation(a)	BBB	+	Baa2	BBB	Not applicable
Duke Energy Field Services(a)	BBB		Baa2	BBB	Not applicable
Texas Eastern Transmission, LP(a)	A	–	Baa1	BBB+	Not applicable
Westcoast Energy Inc.(a)	A	–	Not applicable	Not applicable	A(low)
Union Gas Limited(a)	A	–	Not applicable	Not applicable	A
Maritimes and Northeast Pipeline, LLC(b)	A		A1	Not applicable	Not applicable
Maritimes and Northeast Pipeline, LP(b)	A		A1	Not applicable	A
Duke Energy Trading and Marketing, LLC(c)	BBB		Not applicable	Not applicable	Not applicable

		Credit Facilities Available		Amounts Outstanding
	Expiration Date	Credit Facilities Available		Commercial Paper		Letters of Credit		Other Borrowings		Total
	(In millions)
Duke Capital Corporation
$500 Temporary bilateral(a)(b)	June 2003
$700 364-Day syndicated(a)(b)(c)	August 2003
$500 364-Day syndicated letter of credit(a)(b)(c)	April 2003
$142 364-Day bilateral(a)(b)(c)	August 2003
$550 Multi-year syndicated(a)(b)(c)	August 2004
$538 Multi-year syndicated letter of credit(a)(b)	April 2004
Total Duke Capital Corporation		$	2,930	$	570	$	580	$	—	$	1,150

Westcoast Energy Inc.
$158 364-Day syndicated(a)(c)	December 2003
$127 Two-year syndicated(a)	December 2004
Total Westcoast Energy Inc.(d)			285		57		—		—		57

Union Gas Limited
$380 364-Day syndicated(e)	July 2003		380		124		—		—		124

Duke Energy Field Services, LLC
$650 364-Day syndicated(c)(f)	March 2003		650		215		—		—		215

Duke Australia Pipeline Finance Pty Ltd.
$198 364-Day syndicated(g)	February 2003
$177 Multi-year syndicated	February 2005
Total Duke Australia Pipeline Finance Pty Ltd.(h)			375		182		—		128		310

Total		$	4,620	$	1,148	$	580	$	128	$	1,856

	Payments Due
	2003		2004		2005		2006		2007		Thereafter
	(In millions)
Long-term debt(a)	$	1,134	$	1,290	$	2,457	$	2,339	$	591	$	8,720
Capital leases(a)		14		14		15		144		16		117
Preferred securities(b)		—		—		—		—		—		825
Operating leases(c)		47		37		24		17		12		36
Firm capacity payments(d)		596		396		341		285		230		1,297
Purchase commitments(e)		170		51		—		—		—		—
Other(f)		309		8		3		1		1		—

Total contractual cash obligations	$	2,270	$	1,796	$	2,840	$	2,786	$	850	$	10,995

	Total Amounts Committed		Amount of Commitment Expiring Each Period
(See Note 14)	Total Amounts Committed		2003		2004		2005		2006		2007		Thereafter
	(In millions)
Guarantees of obligations of non-wholly owned affiliates	$	3,044	$	428	$	57	$	43	$	311	$	7	$	2,198
Surety and bid bonds(a), (b)		248		225		21		—		—		2		—
Letters of credit(b)		751		707		24		20		—		—		—

	Estimated Average One-Day Impact on EBIT for 2002		Estimated Average One-Day Impact on EBIT for 2001		High One-Day Impact on EBIT for 2002		Low One-Day Impact on EBIT for 2002
	(In millions)
Calculated DER	$	11	$	18	$	22	$	6

	(In millions)
Fair value of contracts outstanding at the beginning of the year	$	977
Contracts realized or otherwise settled during the year		(128	)
Fair value of contracts when entered into during the year		97
Net premiums received for new option contracts during the period		(28	)
Changes in fair value amounts attributable to changes in valuation techniques(a)		18
Other changes in fair values(b)		(624	)

Fair value of contracts outstanding at the end of the year	$	312

Sources of Fair Value	Fair Value of Trading Contracts as of December 31, 2002
Sources of Fair Value	Maturity in 2003		Maturity in 2004			Maturity in 2005			Maturity in 2006 and Thereafter		Total Fair Value
	(In millions)
Prices supported by quoted market prices and other external sources	$	73	$	92		$	(8	)	$	14	$	171
Prices based on models and other valuation methods		4		(33	)		11			159		141

Total	$	77	$	59		$	3		$	173	$	312

	For the years ended December 31,
	2002		2001		2000
	(In millions)
Net Income
Reported net income	$	264	$	1,356	$	926
Add back: Goodwill amortization, net of tax		—		70		50

Adjusted net income	$	264	$	1,426	$	976

	December 31,
	2002		2001
	(In millions)
A S S E T S
Current Assets
Cash and cash equivalents	$	814	$	263
Receivables		6,549		5,098
Inventory		666		503
Unrealized gains on mark-to-market and hedging transactions		2,013		2,275
Other		717		411

Total current assets		10,759		8,550

Investments and Other Assets
Investments in unconsolidated affiliates		2,074		1,480
Goodwill, net of accumulated amortization		3,747		1,729
Notes receivable		589		576
Unrealized gains on mark-to-market and hedging transactions		2,173		2,824
Other		2,156		1,919

Total investments and other assets		10,739		8,528

Property, Plant and Equipment
Cost		29,238		21,147
Less accumulated depreciation and amortization		4,026		3,120

Net property, plant and equipment		25,212		18,027

Regulatory Assets and Deferred Debits		855		185


Total Assets	$	47,565	$	35,290

	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total			Total Comprehensive Income (Loss)
	(In millions)
Balance December 31, 1999	$	—	$	3,200	$	2,261		$	(2	)	$	5,459
Net income		—		—		926			—			926		$	926
Other comprehensive income:
Foreign currency translation adjustments		—		—		—			(122	)		(122	)		(122	)

Total comprehensive income		—		—		—			—			—		$	804

Capital contribution from parent		—		200		—			—			200
Other capital stock transactions, net		—		—		(2	)		—			(2	)

Balance December 31, 2000	$	—	$	3,400	$	3,185		$	(124	)	$	6,461

Net income		—		—		1,356			—			1,356		$	1,356
Other comprehensive income(a):
Cumulative effect of change in accounting principle		—		—		—			(908	)		(908	)		(908	)
Foreign currency translation adjustments		—		—		—			(186	)		(186	)		(186	)
Net unrealized gains on cash flow hedges		—		—		—			1,309			1,309			1,309
Reclassification into earnings		—		—		—			91			91			91

Total comprehensive income		—		—		—			—			—		$	1,662

Capital contribution from parent		—		650		—			—			650
Noncash adjustment to goodwill		—		124		—			—			124
Other capital stock transactions, net		—		10		(20	)		—			(10	)

Balance December 31, 2001	$	—	$	4,184	$	4,521		$	182		$	8,887

Net income		—		—		264			—			264		$	264
Other comprehensive income(a):
Foreign currency translation adjustments		—		—		—			(343	)		(343	)		(343	)
Net unrealized gains on cash flow hedges		—		—		—			68			68			68
Reclassification into earnings		—		—		—			(105	)		(105	)		(105	)
Minimum pension liability adjustment		—		—		—			(14	)		(14	)		(14	)

Total comprehensive income		—		—		—			—			—		$	(130	)

Capital contribution from parent		—		3,327		—			—			3,327
Other capital stock transactions, net		—		34		(37	)		—			(3	)

Balance December 31, 2002	$	—	$	7,545	$	4,748		$	(212	)	$	12,081

	Balance December 31, 2001		Acquired Goodwill		Impairments			Other(a)			Balance December 31, 2002
	(In millions)
Natural Gas Transmission	$	481	$	2,279	$	—		$	—		$	2,760
Field Services		571		—		—			(90	)		481
Duke Energy North America		91		—		—			9			100
International Energy		427		18		(194	)		(5	)		246
Other Energy Services		5		—		—			(5	)		—
Duke Ventures		—		—		—			6			6
Other Operations		154		—		—			—			154

Total consolidated	$	1,729	$	2,297	$	(194	)	$	(85	)	$	3,747


	Balance December 31, 2000		Acquired Goodwill		Impairments			Other(a)			Balance December 31, 2001
Natural Gas Transmission	$	299	$	—	$	—		$	182		$	481
Field Services		507		82		—			(18	)		571
Duke Energy North America		12		—		2			77			91
International Energy		457		6		—			(36	)		427
Other Energy Services		46		—		(38	)		(3	)		5
Other Operations		183		—		—			(29	)		154

Total consolidated	$	1,504	$	88	$	(36	)	$	173		$	1,729

	Foreign Currency Adjustments			Net Unrealized Gains on Cash Flow Hedges			Minimum Pension Liability Adjustment			Accumulated Other Comprehensive Income (Loss)
	(In millions)
Balance as of December 31, 1999	$	(2	)	$	—		$	—		$	(2	)
Other comprehensive income changes during the year		(122	)		—			—			(122	)

Balance as of December 31, 2000		(124	)		—			—			(124	)
Other comprehensive income changes during the year (net of taxes of $(290))		(186	)		492			—			306

Balance as of December 31, 2001		(310	)		492			—			182
Other comprehensive income changes during the year (net of taxes of $20)(a)		(343	)		(37	)		(14	)		(394	)

Balance as of December 31, 2002	$	(653	)	$	455		$	(14	)	$	(212	)

	(In millions)
Current assets	$	2,080
Investments and other assets		1,191
Goodwill		2,279
Property, plant and equipment		5,177
Regulatory assets and deferred debits		806

Total assets acquired		11,533

Current liabilities		1,635
Long-term debt		4,190
Deferred credits and other liabilities		1,662
Minority interests		560

Total liabilities assumed		8,047

Net assets acquired	$	3,486

	Unaffiliated Revenues			Intersegment Revenues			Total Revenues			EBIT			Depreciation and Amortization		Capital and Investment Expenditures			Segment Assets
	(In millions)
Year Ended December 31, 2002
Natural Gas Transmission	$	2,338		$	264		$	2,602		$	1,174		$	324	$	2,878		$	15,168
Field Services		4,389			1,137			5,526			126			299		309			6,992
Duke Energy North America		3,258			(1,161	)		2,097			74			190		2,013			16,272
International Energy		936			1			937			(102	)		86		412			5,804
Other Energy Services		230			167			397			118			8		1			159
Duke Ventures		512			—			512			173			20		459			2,157
Other Operations		—			(110	)		(110	)		(144	)		12		(23	)		2,042
Eliminations and minority interests		—			(298	)		(298	)		37			—		—			(1,029	)
Gains on sales of assets and equity investments which are included in segment revenues		(84	)		—			(84	)		—			—		—			—
Equity in earnings of unconsolidated affiliates		(220	)		—			(220	)		—			—		—			—
Cash acquired in acquisitions		—			—			—			—			—		(77	)		—

Total consolidated	$	11,359		$	—		$	11,359		$	1,456		$	939	$	5,972		$	47,565

Year Ended December 31, 2001
Natural Gas Transmission	$	967		$	138		$	1,105		$	608		$	141	$	748		$	5,027
Field Services		6,458			1,620			8,078			336			285		587			7,277
Duke Energy North America		5,699			(1,491	)		4,208			1,498			97		3,213			14,005
International Energy		815			15			830			286			97		442			5,115
Other Energy Services		389			176			565			(13	)		42		13			145
Duke Ventures		646			—			646			183			20		773			1,926
Other Operations		—			61			61			(6	)		31		93			2,754
Eliminations and minority interests		—			(519	)		(519	)		231			—		—			(959	)
Gains on sales of assets and equity investments which are included in segment revenues		(229	)		—			(229	)		—			—		—			—
Equity in earnings of unconsolidated affiliates		(187	)		—			(187	)		—			—		—			—
Cash acquired in acquisitions		—			—			—			—			—		(17	)		—

Total consolidated	$	14,558		$	—		$	14,558		$	3,123		$	713	$	5,852		$	35,290

Year Ended December 31, 2000
Natural Gas Transmission	$	998		$	133		$	1,131		$	562		$	131	$	973		$	4,995
Field Services		4,706			1,459			6,165			311			240		376			6,624
Duke Energy North America		4,246			(1,245	)		3,001			346			61		1,737			25,989
International Energy		798			7			805			341			97		980			4,551
Other Energy Services		456			239			695			(59	)		13		28			543
Duke Ventures		797			—			797			568			17		643			1,967
Other Operations		—			(111	)		(111	)		31			28		35			2,406
Eliminations and minority interests		—			(482	)		(482	)		231			—		—			(3,498	)
Gains on sales of assets and equity investments which are included in segment revenues		(621	)		—			(621	)		—			—		—			—
Equity in earnings of unconsolidated affiliates		(112	)		—			(112	)		—			—		—			—
Cash acquired in acquisitions		—			—			—			—			—		(100	)		—

Total consolidated	$	11,268		$	—		$	11,268		$	2,331		$	587	$	4,672		$	43,577

	U.S.		Canada		Latin America		Other Foreign		Consolidated
	(In millions)
2002
Consolidated revenues	$	9,178	$	1,308	$	674	$	199	$	11,359
Consolidated long-lived assets		24,559		7,895		2,118		2,234		36,806
2001
Consolidated revenues	$	12,173	$	1,771	$	197	$	417	$	14,558
Consolidated long-lived assets		22,057		516		2,573		1,594		26,740
2000
Consolidated revenues	$	9,403	$	1,613	$	166	$	86	$	11,268
Consolidated long-lived assets		18,258		900		2,823		1,222		23,203

Type of Contract	Maturity in 2003		Maturity in 2004		Maturity in 2005		Maturity in 2006 and Thereafter		Total Fair Value
	(In millions)
Trading contracts	$	77	$	59	$	3	$	173	$	312
Hedge contracts		192		177		111		211		691

Total	$	269	$	236	$	114	$	384	$	1,003

	2002				2001
	Book Value		Approximate Fair Value		Book Value		Approximate Fair Value
	(In millions)
Long-term debt(a)	$	16,851	$	17,767	$	9,378	$	9,882
Guaranteed preferred beneficial interests in subordinated notes of Duke Capital Corporation		825		864		824		850

	December 31, 2002						December 31, 2001						December 31, 2000
	Domestic		International		Total		Domestic		International		Total		Domestic		International		Total
	(In millions)
Natural Gas Transmission	$	1,044	$	191	$	1,235	$	565	$	88	$	653	$	82	$	88	$	170
Field Services		290		—		290		252		—		252		373		—		373
Duke Energy North America		296		43		339		315		—		315		610		—		610
International Energy		—		122		122		—		165		165		—		154		154
Other Energy Services		33		5		38		53		7		60		11		7		18
Duke Ventures		44		—		44		30		—		30		23		—		23
Other Operations		6		—		6		5		—		5		5		—		5

Total	$	1,713	$	361	$	2,074	$	1,220	$	260	$	1,480	$	1,104	$	249	$	1,353

	For the years ended:
	December 31, 2002									December 31, 2001								December 31, 2000
	Domestic			International			Total			Domestic			International		Total			Domestic			International		Total
	(In millions)
Natural Gas Transmission	$	87		$	19		$	106		$	38		$	7	$	45		$	13		$	4	$	17
Field Services		60			—			60			45			—		45			39			—		39
Duke Energy North America		39			5			44			54			—		54			45			—		45
International Energy		—			65			65			—			39		39			—			43		43
Other Energy Services		108			(1	)		107			49			—		49			(13	)		—		(13	)
Duke Ventures		—			—			—			2			—		2			(9	)		—		(9	)
Other Operations		(162	)(a)		—			(162	)(a)		(47	)(a)		—		(47	)(a)		(10	)(a)		—		(10	)(a)

Total	$	132		$	88		$	220		$	141		$	46	$	187		$	65		$	47	$	112

	Weighted-Average Rate		Year Due	December 31,
	Weighted-Average Rate		Year Due	2002			2001
				(In millions)
Unsecured debt(a)	6.9	%	2003—2032	$	13,058		$	8,025
Secured debt	4.2	%	2003—2027		2,654			200
Commercial paper and extendible commercial notes (ECNs)(b),(c)	2.5	%			1,148			1,900
Other debt	2.0	%	2005—2010		331			669
Capital leases	9.1	%	2006—2032		321			98
Fair value hedge carrying value adjustment(d)			2005—2025		82			32
Unamortized debt discount and premium, net					(60	)		(80	)

Total debt(e)					17,534			10,844
Current maturities of long-term debt					(1,148	)		(254	)
Short-term notes payable and commercial paper(f)					(683	)		(1,466	)

Total long-term debt				$	15,703		$	9,124

	(In millions)
2003	$	1,148
2004		1,304
2005		2,472
2006		2,483
2007		607
Thereafter		8,837

Total long-term debt(a)	$	16,851


				December 31,
Issued	Rate		Due	2002			2001
				(In millions)
1998	7.375	%	2038		350			350
1998	7.375	%	2038		250			250
1999	8.375	%	2029		250			250
Unamortized debt discount					(25	)		(26	)

				$	825		$	824

Contractual Cash Obligations
	Payments Due
	2003		2004		2005		2006		2007		Thereafter
	(In millions)
Firm capacity payments(a)	$	596	$	396	$	341	$	285	$	230	$	1,297
Purchase commitments(b)		170		51		—		—		—		—
Other(c)		309		8		3		1		1		—

Total contractual cash obligations	$	1,075	$	455	$	344	$	286	$	231	$	1,297

Components of Net Periodic Pension Costs for Westcoast	As of December 31, 2002
	(In millions)
Service cost benefit earned during the year	$	6
Interest cost on projected benefit obligation		17
Expected return on plan assets		(19	)

Net periodic pension costs	$	4

Reconciliation of Funded Status to Pre-funded Pension Cost for Westcoast
	As of December 31, 2002
	(In millions)
Change in Benefit Obligation
Benefit obligation at beginning of year	$	324	(a)
Service cost		6
Interest cost		17
Actuarial loss		6
Benefits paid		(19	)

Benefit obligation at end of year	$	334

Change in Plan Assets
Fair value of plan assets at beginning of year	$	291	(a)
Actual return on plan assets		(27	)
Benefits paid		(19	)
Employer contributions		9
Plan participants’ contributions		1

Fair value of plan assets at end of year	$	255	(a)


Funded status	$	(78	)
Unrecognized net experience loss		49
Contributions made after measurement date		2

Accrued pension costs	$	(27	)

Amounts Recognized in the Consolidated Balance Sheet for Westcoast
	As of December 31,
	2002
	(In millions)
Accrued pension liability	$	(49	)
Deferred income tax asset		8
Accumulated other comprehensive income		14

Net Balance Sheet presentation	$	(27	)