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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

FOR ANNUAL AND TRANSITION REPORTS

PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

(Mark One)

DUKE ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

704-594-6200

(Registrant’s telephone number, including area code)

SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:

SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:

Title of class

Preferred Stock, par value $100

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. ¨

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 x No ¨

DOCUMENTS INCORPORATED BY REFERENCE:

The registrant is incorporating herein by reference certain sections of the proxy statement relating to the 2005 annual meeting of shareholders to provide information required by Part III, Items 10, 11, 12 and 14 of this annual report.

TABLE OF CONTENTS

DUKE ENERGY CORPORATION

FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2004

SAFE HARBOR STATEMENT UNDER THE PRIVATE

SECURITIES LITIGATION REFORM ACT OF 1995

Duke Energy 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 Duke Energy’s intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors. Many of those factors are outside Duke Energy’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 Duke Energy has described. Duke Energy undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

PART I

Item 1. Business.

GENERAL

Duke Energy Corporation (collectively with its subsidiaries, Duke Energy) is a leading energy company located in the Americas with a real estate subsidiary. Duke Energy provides its services through the business units described below.

Duke Energy operates the following business units: Franchised Electric, Natural Gas Transmission, Field Services, Duke Energy North America (DENA), International Energy and Crescent Resources, LLC (Crescent). Duke Energy’s chief operating decision maker regularly reviews financial information about each of these business units in deciding how to allocate resources and evaluate performance. The entities under each business unit have similar economic characteristics, services, production processes, distribution methods and regulatory concerns. All of the Duke Energy business units are considered reportable segments under Statement of Financial Accounting Standards (SFAS) No. 131, “Disclosures about Segments of an Enterprise and Related Information.”

Franchised Electric generates, transmits, distributes and sells electricity in central and western North Carolina and western South Carolina. It conducts operations through Duke Power. These electric operations are subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC), the North Carolina Utilities Commission (NCUC) and the Public Service Commission of South Carolina (PSCSC).

Natural Gas Transmission provides transportation and storage of natural gas for customers along the U.S. East Coast, the Southeast, and in Canada. Natural Gas Transmission also provides natural gas sales and distribution service to retail customers in Ontario, and natural gas processing services to customers in Western Canada. Natural Gas Transmission does business primarily through Duke Energy Gas Transmission, LLC. Duke Energy Gas Transmission, LLC’s natural gas transmission and storage operations in the U.S. are primarily subject to the FERC’s and the U.S. Department of Transportation’s (DOT’s) rules and regulations, while natural gas gathering, processing, transmission, distribution and storage operations in Canada are primarily subject to the rules and regulations of the National Energy Board (NEB) and the Ontario Energy Board (OEB). Texas Eastern Transmission LP (Texas Eastern) is an indirect subsidiary of Natural Gas Transmission and was also a separate Securities and Exchange Commission (SEC) reporting entity. On December 15, 2004 Texas Eastern announced that it filed a Form 15 with the SEC to suspend its reporting obligations under the Securities Exchange Act of 1934. Texas Eastern is eligible to suspend its reporting obligation under the 1934 Act because it has fewer than 300 holders of record of any class of its securities.

Field Services gathers, compresses, treats, processes, transports, trades and markets, and stores natural gas; and fractionates, transports, trades and markets, and stores natural gas liquids (NGLs). It conducts operations primarily through Duke Energy Field Services, LLC (DEFS), which is approximately 30% owned by ConocoPhillips and approximately 70% owned by Duke Energy. Field Services gathers raw natural gas through gathering systems located in eight major natural gas producing regions: Permian Basin, Mid-Continent, ArklaTex, Gulf Coast, South, Central, Rocky Mountains and Western Canada. DEFS, which previously was a separate SEC reporting entity, announced January 31, 2005 that it filed a Form 15 with the SEC to suspend its reporting obligations under the Securities Exchange Act of 1934. DEFS is eligible to suspend its reporting obligations under the 1934 Act because it has fewer than 300 holders of record of any class of its securities.

In February 2005, Duke Energy executed an agreement with ConocoPhillips whereby Duke Energy has agreed to transfer a 19.7 percent interest in DEFS to ConocoPhillips for direct and indirect monetary and non-monetary consideration of approximately $1.1 billion. Upon completion of this transaction, DEFS will be owned 50% by Duke Energy and 50% by ConocoPhillips. As a result, Duke Energy expects to account for its investment in DEFS using the equity method subsequent to closing of the transaction. This transaction, which is subject to customary U.S. and Canadian regulatory approvals, is expected to close in the latter half of 2005. Additionally, in February 2005, DEFS sold its wholly-owned subsidiary, Texas Eastern Products Pipeline Company LLC (TEPPCO), the general partner of TEPPCO Partners L.P., for approximately $1.1 billion and Duke Energy sold its limited partner interest in TEPPCO Partners, L.P. for approximately $100 million, in each case to Enterprise GP Holdings L.P. (EPCO), an unrelated third party. TEPPCO Partners, L.P. is a publicly traded master limited partnership which owns one of the largest common-carrier pipelines of refined petroleum products and liquefied petroleum gases in the United States, as well as natural gas gathering systems, petrochemical and NGL 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.

DENA operates and manages power plants and markets electric power and natural gas related to these plants and other contractual positions. DENA conducts business throughout the U.S. and Canada through Duke Energy North America, LLC and its 100% owned affiliates Duke Energy Marketing America, LLC and Duke Energy Marketing Canada Corp. DENA also participates in Duke Energy Trading and Marketing, LLC (DETM). DETM is 40% owned by Exxon Mobil Corporation and 60% owned by Duke Energy.

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International Energy operates and manages power generation facilities, and engages in sales and marketing of electric power and natural gas outside the U.S. and Canada. It conducts operations primarily through Duke Energy International, LLC (DEI) and its activities target power generation in Latin America. Additionally, International Energy owns an equity investment in National Methanol Company, located in Saudi Arabia, which is a leading regional producer of methanol and methyl tertiary butyl ether (MTBE).

Crescent develops and manages high-quality commercial, residential and multi-family real estate projects primarily in the southeastern and southwestern United States. Some of these projects are developed and managed through joint ventures. Crescent also manages “legacy” land holdings in North and South Carolina.

The remainder of Duke Energy’s operations is presented as “Other”. While it is not considered a business segment, Other primarily includes certain unallocated corporate costs, DukeNet Communications, LLC (DukeNet), Duke Energy Merchants, LLC (DEM), Bison Insurance Company Limited (Bison), Duke Energy’s wholly owned, captive insurance subsidiary, and Duke Energy’s 50% interest in Duke/Fluor Daniel (D/FD). DukeNet develops, owns and operates a fiber optic communications network primarily in the Carolinas, serving wireless, local and long-distance communications companies, Internet service providers and other businesses and organizations. During 2003, Duke Energy determined that it would exit the refined products business at DEM in an orderly manner, and continues to unwind its portfolio of contracts. As of December 31, 2004, DEM had exited the majority of its business. Bison’s principle activities, as a captive insurance entity, include the insurance and reinsurance of various business risks and losses, such as workers compensation, property, business interruption and general liability of subsidiaries and affiliates of Duke Energy. Bison also participates in reinsurance activities with certain third parties, on a limited basis. D/FD is a 50/50 partnership between subsidiaries of Duke Energy and Fluor Corporation. During 2003, Duke Energy and Fluor Corporation announced that they would dissolve the D/FD partnership. The D/FD partners adopted a plan for an orderly wind-down of the business which is expected to be completed by December 2005. Previously, D/FD provided comprehensive engineering, procurement, construction, commissioning and operating plant services for fossil-fueled electric power generating facilities worldwide. During 2003, Duke Energy decided to exit the merchant finance business conducted by Duke Capital Partners, LLC (DCP). DCP had been previously included in Other. At December 31, 2004 Duke Energy had exited the merchant finance business, and all of the results of operations for DCP have been classified as discontinued operations in the accompanying Consolidated Statements of Operations.

Duke Energy is a North Carolina corporation. Its principal executive offices are located at 526 South Church Street, Charlotte, North Carolina 28202-1803. The telephone number is 704-594-6200. Duke Energy electronically files reports with the SEC, including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxies and amendments to such reports. The public may read and copy any materials that Duke Energy files with the SEC at the SEC’s Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov. Additionally, information about Duke Energy, including its reports filed with the SEC, is available through Duke Energy’s web site at http://www.duke-energy.com. Such reports are accessible at no charge through Duke Energy’s web site and are made available as soon as reasonably practicable after such material is filed with or furnished to the SEC.

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

Accrual Model of Accounting (Accrual Model). An accounting term used by Duke Energy to refer to contracts for which there is generally no recognition in the Consolidated Statements of Operations for any changes in fair value until the service is provided or the associated delivery period occurs or there is hedge ineffectiveness. As discussed further in Note 1 to the Consolidated Financial Statements, this term is applied to derivative contracts that are accounted for as cash flow hedges, fair value hedges, and normal purchases or sales, as well as to non-derivative contracts used for commodity risk management purposes. As this term is not explicitly defined within U.S. Generally Accepted Accounting Principles (GAAP), Duke Energy’s application of this term could differ from that of other companies.

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

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

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

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Decommissioning. The process of closing down a nuclear facility and reducing the residual radioactivity to a level that permits the release of the property and termination of the license. Nuclear power plants are required by the Nuclear Regulatory Commission (NRC) to set aside funds for their decommissioning costs during operation.

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

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

Duke Capital LLC (Duke Capital). Duke Capital LLC (formerly known as Duke Capital Corporation), a wholly owned subsidiary of Duke Energy that provides financing and credit enhancement services for its subsidiaries.

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

Environmental Protection Agency (EPA). The U.S. agency that is responsible for researching and setting national standards for a variety of environmental programs, and delegates to states the responsibility for issuing permits and for monitoring and enforcing compliance.

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 specified amount of a commodity with a predetermined price formula 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 and other related products.

Futures Contract. A contract, usually exchange traded, 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.

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

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

Independent System Operator (ISO). An entity that acts as the transmission provider for a regional transmission system, providing customers access to the system and clearing all bilateral contract requests for use of the electric transmission system. An ISO also shares responsibility for maintaining bulk electric system reliability.

Light-off Fuel. Fuel oil used to light the coal prior to generating electricity.

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

Liquidity. The ease with which assets or products can be traded without dramatically altering the current market price.

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

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

Mark-to-Market Model of Accounting (MTM Model). An accounting term used by Duke Energy to refer to derivative contracts for which an asset or liability is recognized at fair value and the change in the fair value of that asset or liability is recognized in the Consolidated Statements of Operations. As discussed further in Note 1 to the Consolidated Financial Statements, this term is applied to trading and undesignated non-trading derivative contracts. As this term is not explicitly defined within U.S. GAAP, Duke Energy’s application of this term could differ from that of other companies.

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.

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

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

Option. A contract that gives the buyer a right but not the obligation to purchase or sell an underlying asset at a specified price at a specified time.

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

Portfolio. A collection of assets, liabilities, transactions, or trades.

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

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

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

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

Swap. A contract to exchange cash flows in the future according to a prearranged formula.

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

Tolling. Arrangement whereby a buyer provides fuel to a power generator and receives generated power in return for a specified fee.

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

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

Volatility. An annualized measure of the fluctuation in the price of an energy contract.

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

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

FRANCHISED ELECTRIC

Service Area and Customers

Franchised Electric generates, transmits, distributes and sells electricity. It conducts operations through Duke Power. Its service area covers about 22,000 square miles with an estimated population of 5.9 million in central and western North Carolina and western South Carolina. Franchised Electric supplies electric service to approximately 2.2 million residential, commercial and industrial customers over 94,000 miles of distribution lines and a 13,000-mile transmission system. Electricity is also sold wholesale to incorporated municipalities and to public and private utilities. In addition, municipal and cooperative customers who purchased portions of the Catawba Nuclear Station may also buy power from a variety of suppliers including Franchised Electric, through contractual agreements. (For more information on the Catawba Nuclear Station joint ownership, see Note 5 to the Consolidated Financial Statements, “Joint Ownership of Generating Facilities.”)

Industrial and commercial development in Franchised Electric’s service area is highly diversified. The textile industry, machinery and equipment manufacturing, and chemical industries are of major significance to the area’s economy. Other industries operating in the area include rubber and plastic products, paper and related products, and other manufacturing and service businesses. The textile industry, while in decline, is the largest industry served by Franchised Electric and accounted for approximately $293 million of Franchised Electric’s revenues for 2004, representing 6% of total electric revenues and 28% of industrial revenues. In 2004, Franchised Electric implemented business development strategies to leverage the competitive advantages of North Carolina and South Carolina to attract pharmaceutical, biotechnology, plastics, medical equipment and other industries.

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Franchised Electric’s costs and revenues are influenced by seasonal patterns. Peak sales occur during the summer and winter months, resulting in higher revenue and cash flows during those periods. By contrast, fewer sales occur during the spring and fall allowing for scheduled plant maintenance during those periods.

Energy Capacity and Resources

Electric energy for Franchised Electric’s customers is generated by three nuclear generating stations with a combined net capacity of 5,020 megawatts (MW) (including Duke Energy’s 12.5% ownership in the Catawba Nuclear Station), eight coal-fired stations with a combined capacity of 7,754 MW, 31 hydroelectric stations (including two pumped-storage facilities) with a combined capacity of 2,810 MW and seven combustion turbine stations with a combined capacity of 2,447 MW. Energy and capacity are also supplied through contracts with other generators and purchased on the open market. Franchised Electric has interconnections and arrangements with its neighboring utilities to facilitate planning, emergency assistance, sale and purchase of capacity and energy, and reliability of power supply. Franchised Electric expects that current generation capabilities plus additional construction, purchased power contracts and open market purchases will meet customers’ energy needs in the future.

Franchised Electric’s generation portfolio is a balanced mix of energy resources having different operating characteristics and fuel sources designed to provide energy at the lowest possible cost to meet its obligation to serve native-load customers. All options including owned generation resources and purchased power opportunities are continually evaluated on a real-time basis to select and dispatch the lowest-cost resources available to meet system load requirements. The vast majority of customer energy needs are met by Franchised Electric’s large, low-energy-production-cost nuclear and coal-fired generating units that operate almost continuously (or at baseload levels). In 2004, approximately 98% of the total generated energy came from Franchised Electric’s low-cost, efficient nuclear and coal units (45.9% nuclear and 52.2% coal). The remainder of energy needs was supplied by hydroelectric and combustion-turbine generation or economical purchases from the wholesale market.

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Hydroelectric (both conventional and pumped storage) and gas/oil combustion-turbine stations operate during the peak-hour load periods (at peaking levels) when customer loads are rapidly changing. Combustion turbines produce energy at higher production costs than either nuclear or coal, but are less expensive to build and maintain, and can be rapidly started or stopped as needed to meet changing customer loads. Hydroelectric units produce low-cost energy, but their operations are limited by the availability of water flow. Since hydroelectric units can also be rapidly started or stopped, they are also used in periods of rapidly changing customer loads so that system operators can match loads with the appropriate amount of generation.

Franchised Electric’s two major pumped-storage hydroelectric facilities offer the added flexibility of using low-cost off-peak energy to pump water that will be stored for later generation use during times of higher-cost on-peak generation periods. These plants allow Franchised Electric to maximize the value spreads between different high- and low-cost generation periods.

Fuel Supply

Franchised Electric relies principally on coal and nuclear fuel for its generation of electric energy. The following table lists Franchised Electric’s sources of power and fuel costs for the three years ended December 31, 2004.

Coal. Franchised Electric meets its coal demand through purchase supply contracts and spot agreements. Large amounts of coal are obtained under supply contracts with mining operators who mine both underground and at the surface. Franchised Electric has an adequate supply of coal to fuel its current operations. Expiration dates for its supply contracts, which have price adjustment provisions, range from 2005 to 2007. Franchised Electric expects to renew these contracts or enter into similar contracts with other suppliers for the quantities and quality of coal required, though prices will fluctuate over time. The coal purchased under these contracts is produced from mines in eastern Kentucky, southern West Virginia and southwestern Virginia. Franchised Electric uses spot-market purchases to meet coal requirements not met by supply contracts. During 2004, Franchised Electric experienced coal delivery difficulties from railroads that deliver coal to its power plants. Coal supplies were sufficient to fuel generation needed to meet the demand of retail customers but were limited for wholesale sales. Coal deliveries have since improved and Franchised Electric expects to have increased wholesale opportunities as coal inventories increase.

The average sulfur content of coal purchased by Franchised Electric is approximately 1%. Coupled with the use of available sulfur dioxide emission allowances on the open market, this satisfies the current emission limitation for sulfur dioxide for existing facilities.

Nuclear. Developing nuclear generating fuel generally involves the mining and milling of uranium ore to produce uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride gas, enrichment of that gas, and then the fabrication of the enriched uranium hexafluoride into usable fuel assemblies.

Franchised Electric has contracted for uranium materials and services required to fuel Oconee, McGuire and Catawba Nuclear Stations. Uranium concentrates, conversion services and enrichment services are primarily met through a diversified portfolio of long-term supply contracts. The contracts are diversified by supplier, country of origin and pricing. Franchised Electric staggers its contracting so that its portfolio of long-term contracts covers the majority of its fuel requirements at Oconee, McGuire and Catawba in the near term, but so that its level of coverage decreases each year into the future. Due to the technical complexities of changing suppliers of fuel fabrication services, Franchised Electric generally sole sources these services to a single domestic supplier on a plant-by-plant basis using multi-year contracts.

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Based on current projections, Franchised Electric’s existing portfolio of contracts will meet the requirements of Oconee, McGuire and Catawba Nuclear Stations through the following years:

After the years indicated above, a portion of the fuel requirements at Oconee, McGuire and Catawba are covered by long-term contracts. For requirements not covered under long-term contracts, Duke Energy believes it will be able to renew contracts as they expire, or enter into similar contractual arrangements with other suppliers of nuclear fuel materials and services. Near-term requirements not met by long-term supply contracts have been and are expected to be fulfilled with uranium spot market purchases.

Duke Power has entered into a contract under which it has agreed to prepare the McGuire and Catawba nuclear reactors for use of mixed-oxide fuel and to purchase mixed-oxide fuel for use in such reactors. Mixed-oxide fuel will be fabricated by Duke COGEMA Stone & Webster, LLC from the U.S. government’s excess plutonium from its nuclear weapons programs and is similar to conventional uranium fuel. Before using the fuel, Duke Power must apply for and obtain amendments to the facilities’ operating licenses from the NRC. On March 3, 2005, the NRC issued amendments to Catawba Nuclear Station’s operating licenses to allow the receipt and use of four mixed oxide fuel lead assemblies. (See Note 18 to the Consolidated Financial Statements, “Guarantees and Indemnifications,” for additional information.)

Inventory

Generation of electricity is capital-intensive. Franchised Electric must maintain an adequate stock of fuel, materials and supplies in order to ensure continuous operation of generating facilities and reliable delivery to customers. As of December 31, 2004, the inventory balance for Franchised Electric was approximately $405 million. (See Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” for additional information.)

Insurance and Decommissioning

Duke Energy owns and operates McGuire and Oconee Nuclear Stations and operates and has a partial ownership interest in Catawba Nuclear Station. McGuire and Catawba have two nuclear reactors each and Oconee has three. Nuclear insurance includes: liability coverage; property, decontamination and premature decommissioning coverage; and business interruption and/or extra expense coverage. The other joint owners of the Catawba Nuclear Station reimburse Duke Energy for certain expenses associated with nuclear insurance premiums. The Price-Anderson Act requires Duke Energy to insure against public liability claims resulting from nuclear incidents to the full limit of liability, approximately $10.8 billion. (See Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies—Nuclear Insurance,” for more information.)

In October 2004, Duke Power filed the results of a funding study for nuclear decommissioning costs with the NCUC, and in December 2004, Duke Power notified the PSCSC of the results of the funding study (filing of the study is not required by the PSCSC). The funding study, which was based on the updated nuclear decommissioning cost estimate and renewal of the nuclear operating licenses, indicates that an annual cash contribution to the Nuclear Decommissioning Trust Funds (NDTF) of $48 million (compared to a current level of approximately $70 million), which are invested in debt and equity securities as discussed in Note 7 to the Consolidated Financial Statements, “Asset Retirement Obligations,” is now required to fully cover the estimated nuclear decommissioning costs. Duke Power anticipates that the NCUC will rule later in 2005 on whether any change in Duke Power’s decommissioning expense is necessary.

Estimated site-specific nuclear decommissioning costs, including the cost of decommissioning plant components not subject to radioactive contamination, total approximately $2.3 billion in 2003 dollars, based on a decommissioning study completed in 2004. This includes costs related to Duke Energy’s 12.5% ownership in Catawba Nuclear Station. The other joint owners of Catawba Nuclear Station are responsible for decommissioning costs related to their ownership interests in the station. The previous study, conducted in 1999, estimated a decommissioning cost of $1.9 billion ($2.2 billion in 2003 dollars at 3% inflation). The estimated increase is due primarily to inflation and cost increases for the size of the organization needed to manage the decommissioning project (based on current industry experience at facilities undergoing decommissioning). Both the NCUC and the PSCSC have allowed Duke Energy to recover estimated decommissioning costs through retail rates over the expected remaining service periods of Duke Energy’s nuclear stations. Management believes that the decommissioning costs being recovered through rates, when coupled with expected fund earnings, are sufficient to provide for the cost of decommissioning.

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After spent fuel is removed from a nuclear reactor, it is cooled in a spent-fuel pool at the nuclear station. Under provisions of the Nuclear Waste Policy Act of 1982, Duke Energy has contracted with the U.S. Department of Energy (DOE) for the disposal of spent nuclear fuel. The DOE failed to begin accepting spent nuclear fuel on January 31, 1998, the date specified by the Nuclear Waste Policy Act and in Duke Energy’s contract with the DOE. In 1998, Duke Energy filed a claim with the U.S. Court of Federal Claims against the DOE related to the DOE’s failure to accept commercial spent nuclear fuel by the required date. Damages claimed in the lawsuit are based upon Duke Energy’s costs incurred as a result of the DOE’s partial material breach of its contract, including the cost of securing additional spent fuel storage capacity. Duke Energy will continue to safely manage its spent nuclear fuel until the DOE accepts it. Payments made to the DOE for disposal costs are based on nuclear output and are included in the Consolidated Statements of Operations as Fuel Used in Electric Generation and Purchased Power.

Duke Energy has experienced numerous claims relating to damages for personal injuries alleged to have arisen from the exposure to or use of asbestos in connection with construction and maintenance activities conducted by Duke Power on its electric generation plants during the 1960s and 1970s. Duke Energy has third-party insurance to cover losses related to these asbestos-related injuries and damages above a certain aggregate deductible. This insurance policy, including the policy deductible, provides for coverage to Duke Energy up to an aggregate of $1.6 billion. Probable insurance recoveries related to this policy are classified in the Consolidated Balance Sheets as Other within noncurrent assets. Amounts recognized as reserves in the Consolidated Balance Sheets are classified in Other Deferred Credits and Other Liabilities and Other Current Liabilities and are based upon Duke Energy’s best estimate of the probable liability for future asbestos claims. These reserves are based upon current estimates and are subject to uncertainty. Factors such as the frequency and magnitude of future claims could change the current estimates of the related reserves and claims for recoveries reflected in the accompanying Consolidated Financial Statements. However, management of Duke Energy does not currently anticipate that any changes to these estimates will have any material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position.

Competition

Duke Energy continues to monitor electric industry restructuring; however, movement toward retail deregulation has virtually stopped.

Franchised Electric competes in some areas with government-owned power systems, municipally owned electric systems, rural electric cooperatives and other private utilities. By statute, the NCUC and the PSCSC assign all service areas outside municipalities in North Carolina and South Carolina to regulated electric utilities and rural electric cooperatives. Substantially all of the territory comprising Franchised Electric’s service area has been assigned in this manner. In unassigned areas, Franchised Electric’s business remains subject to competition. A decision of the North Carolina Supreme Court limits, in some instances, the right of North Carolina municipalities to serve customers outside their corporate limits. In South Carolina, competition continues between municipalities and other electric suppliers outside the municipalities’ corporate limits, subject to the regulation of the PSCSC. Franchised Electric also competes with other utilities and marketers in the wholesale electric business. In addition, Franchised Electric continues to compete with natural gas providers.

Regulation

The NCUC and the PSCSC approve rates for retail electric sales within their respective states. The FERC approves Franchised Electric’s rates for electric sales to regulated wholesale customers. (For more information on rate matters, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters—Franchised Electric.”) The FERC, the NCUC and the PSCSC also have authority over the construction and operation of Franchised Electric’s facilities. Certificates of public convenience and necessity issued by the FERC, the NCUC and the PSCSC authorize Franchised Electric to construct and operate its electric facilities, and to sell electricity to retail and wholesale customers. Prior approval from the NCUC and the PSCSC is required for Duke Energy to issue securities.

NCUC, PSCSC and FERC regulations govern access to regulated electric customer and other data by non-regulated entities, and services provided between regulated and non-regulated energy affiliates. These regulations affect the activities of non-regulated affiliates with Franchised Electric.

The Energy Policy Act of 1992 and subsequent rulemaking by FERC initiated an opening of wholesale energy market to competition. Open-access transmission for wholesale customers, as defined by FERC rules, provides energy suppliers, including Franchised Electric, with opportunities to sell and deliver capacity and energy at market-based prices. Franchised Electric is also able to purchase at market rates a portion of its capacity and energy requirements resulting in lower overall costs to customers. Open access also provides wholesale customers geographically located in Franchised Electric’s control area with competitive opportunities to seek other suppliers for their capacity and energy requirements.

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The FERC continues to advocate for independent functioning of transmission grids, including through a variety of rulemakings and policy proposals, and has supported the development of Regional Transmission Organizations (RTOs) across the U.S. As a result of these rulemakings, Duke Power and the franchised electric units of Carolina Power & Light Company (now Progress Energy Carolinas) and South Carolina Electric & Gas Company, planned to establish GridSouth Transco, LLC (GridSouth), as an RTO responsible for the functional control of the companies’ combined transmission systems. As of December 31, 2003, Duke Energy had invested $41 million in GridSouth, including carrying costs calculated through December 31, 2002. This amount is included in Other Regulatory Assets and Deferred Debits on the Consolidated Balance Sheets. Due to regulatory uncertainty, development of the GridSouth implementation project was suspended in 2002. Duke Energy continues to examine options in support of the FERC’s transmission policy goals. Management expects it will recover its investment in GridSouth.

Franchised Electric is subject to the NRC jurisdiction for the design, construction and operation of its nuclear generating facilities. In 2000, the NRC renewed the operating license for Duke Energy’s three Oconee nuclear units through 2033 and 2034. In 2003, the NRC renewed the operating licenses for all units at Duke Energy’s McGuire and Catawba stations. The two McGuire units are licensed through 2041 and 2043, while the two Catawba units are licensed through 2043. Franchised Electric’s hydroelectric generating facilities are licensed by the FERC under Part I of the Federal Power Act, with license terms expiring from 2005 to 2036. The FERC has authority to extend hydroelectric generating licenses. Other hydroelectric facilities whose licenses expire between 2005 and 2008 are in various stages of relicensing.

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

NATURAL GAS TRANSMISSION

Natural Gas Transmission provides transportation and storage of natural gas for customers along the U.S. East Coast, the Southeast, and in Canada. Natural Gas Transmission also provides natural gas sales and distribution service to retail customers in Ontario, and gas processing services to customers in western Canada. Natural Gas Transmission does business primarily through Duke Energy Gas Transmission LLC.

For 2004, Natural Gas Transmission’s proportional throughput for its pipelines totaled 3,332 trillion British thermal units (TBtu), compared to 3,362 TBtu in 2003. 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. A majority of Natural Gas Transmission’s contracted transportation volumes are under long-term firm service agreements with LDC customers in the pipelines’ market areas. Firm transportation services are also provided to gas marketers, producers, other pipelines, electric power generators and a variety of end-users. In addition, the pipelines provide both firm and interruptible transportation to various customers on a short-term or seasonal basis. Demand on Natural Gas Transmission’s pipeline systems is seasonal, with the highest throughput occurring during colder periods in the first and fourth calendar quarters. Natural Gas Transmission’s pipeline systems consist of more than 17,500 miles of transmission pipelines. The pipeline systems receive natural gas from major North American producing regions for delivery to markets primarily in the Mid-Atlantic, New England and Southeastern states, Ontario, Alberta, and British Columbia. (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 storage facilities in southeast Texas and Louisiana. MHP markets natural gas storage services to pipelines, LDCs, producers, end users and natural gas marketers. Texas Eastern and East Tennessee Natural Gas, LLC (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.

Natural Gas Transmission provides retail distribution services through its subsidiary, Union Gas Limited (Union Gas). Union Gas owns and operates natural gas transmission, distribution and storage facilities in Ontario. Union Gas distributes natural gas to approximately 1.2 million residential, commercial and industrial 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 United States.

Natural Gas Transmission’s processing plants in western Canada provide services primarily to natural gas producers to remove impurities from the raw gas stream including water, carbon dioxide, hydrogen sulphide and other substances. In addition, where required the facilities remove liquid hydrocarbons including propane, butane and pentanes plus. Natural Gas Transmission receives a volume based fee for these processing services under contracts that have an average duration of one to three years.

In February 2005, Duke Energy executed an agreement with ConocoPhillips whereby Duke Energy has agreed to transfer a 19.7% interest in DEFS to ConocoPhillips for direct and indirect monetary and non-monetary consideration of approximately $1.1 billion. Upon closing of

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this transaction, Natural Gas Transmission expects to receive Canadian assets being transferred from DEFS and assets in Alberta and Saskatchewan, Canada from ConocoPhillips, which will allow Natural Gas Transmission to continue building scope, scale and diversity within its Canadian asset portfolio.

Competition

Natural Gas Transmission’s transportation, storage and gas gathering and processing businesses compete with other pipeline and storage facilities that serve its market areas in the transportation, processing and storage of natural gas. The principal elements of competition are rates, terms of service, and flexibility and reliability of service.

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

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

Regulation

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

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

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, which 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.

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

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

FIELD SERVICES

Field Services gathers, compresses, treats, processes, transports, trades and markets, and stores natural gas; and fractionates, transports, trades and markets, and stores NGLs. It conducts operations primarily through DEFS, which is approximately 30% owned by ConocoPhillips and approximately 70% owned by Duke Energy. In February 2005, Duke Energy executed an agreement with ConocoPhillips whereby Duke Energy has agreed to transfer a 19.7% interest in DEFS to ConocoPhillips for direct and indirect monetary and non-monetary consideration of approximately $1.1 billion. Upon closing of this transaction, DEFS expects to transfer its Canadian assets to Duke Energy’s Natural Gas Transmission segment and receive certain U.S. Midstream assets or cash from ConocoPhillips. Upon completion of this transaction, DEFS will be owned 50% by Duke Energy and 50% by ConocoPhillips. As a result, Duke Energy expects to account for its investment in DEFS using the equity method subsequent to closing of the transaction. This transaction, which is subject to customary U.S. and Canadian regulatory approvals, is expected to close in the latter half of 2005. Additionally, in February 2005, DEFS sold its wholly-owned subsidiary, TEPPCO, the general partner of TEPPCO Partners L.P., for approximately $1.1 billion and Duke Energy sold its limited partner interest in TEPPCO Partners, L.P. for approximately $100 million, in each case to EPCO, an unrelated third party.

Field Services gathers raw natural gas through gathering systems located in eight major natural gas producing regions: Permian Basin, Mid-Continent, ArklaTex, Gulf Coast, South, Central, Rocky Mountains and Western Canada. Field Services owns and operates approximately 59,000 miles of gathering and transmission pipe, with approximately 34,000 active receipt points.

Field Services’ natural gas processing operations separate raw natural gas that has been gathered on its own systems and third-party systems into condensate, NGLs and residue gas. Field Services processes the raw natural gas at 57 natural gas processing facilities that it owns and operates and at nine 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 ten processing facilities that it owns and operates and at four third-party-operated facilities in which it has an equity interest. In addition, Field Services operates a propane wholesale marketing business. Field Services sells NGLs to a variety of customers ranging from large, multinational petrochemical and refining companies to small regional retail propane distributors. Substantially all of its NGL sales are at market-based prices.

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

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Field Services uses NGL trading and storage at the Mont Belvieu, Texas and Conway, Kansas NGL market centers to manage its price risk and to provide additional services to its customers. Asset-based gas trading and marketing activities are supported by ownership of the Spindletop storage facility and various intrastate pipelines which provide access to market centers/hubs such as 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 market 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’ operating results are significantly impacted by changes in average NGL prices, which increased approximately 28% in 2004 compared to 2003. Field Services closely monitors the risks associated with these price changes, using NGL and crude forward contracts to mitigate the effect of such fluctuations on operating results. (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.)

Competition

In gathering and processing natural gas and in marketing and transporting natural gas and NGLs, Field Services competes with major integrated oil companies, major interstate and intrastate pipelines, national and local natural gas gatherers, and brokers, marketers and distributors of natural gas supplies. 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.

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Regulation

The intrastate natural gas and NGL pipelines owned by Field Services are subject to state regulation. To the extent that the natural gas intrastate pipelines provide services under Section 311 of the Natural Gas Policy Act of 1978, they are also subject to FERC regulation. The interstate natural gas pipeline owned and operated by Field Services is subject to FERC regulation, but its natural gas gathering and processing 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.) Field Services’ natural gas transmission pipelines and some gathering pipelines are subject to the regulations of the DOT, and in some cases, state agencies, concerning pipeline safety. DOT regulations have incorporated certain provisions of the Natural Gas Pipeline Safety Act of 1968 (and subsequent acts). The DOT has developed new regulations, effective February 14, 2004, that establish mandatory inspections for all natural gas transmission pipelines in high-consequence areas within ten years, with reassessments at prescribed intervals thereafter. The new regulations require pipeline operators to implement integrity management programs, including more frequent inspections, and other safety protections in areas where the consequences of potential pipeline accidents pose the greatest risk to life and property, Management believes that compliance with these new DOT regulations will not have a material adverse effect on the consolidated results of operations, cash flows or financial position of Duke Energy.

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

DENA

DENA operates and manages power plants and markets electric power and natural gas related to these plants and other contractual positions. DENA conducts business throughout the U.S. and Canada through Duke Energy North America, LLC and its 100% owned affiliates Duke Energy Marketing America, LLC and Duke Energy Marketing Canada Corp. DENA also participates in DETM. DETM is 40% owned by Exxon Mobil Corporation and 60% owned by Duke Energy. The following summarizes certain key events from 2004.

Generation Assets

DENA currently owns or operates approximately 9,890 net MW of operating generation. In August 2004, DENA completed the sale of the Southeast Plants. DENA also completed the sales of its partially completed power plants in Moapa, Nevada in October 2004 and Luna, New Mexico in November 2004. DENA also entered into an agreement in December 2004 to divest of its interests in the partially completed Grays Harbor (Washington) power plant and associated contracts. (See Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions” for further discussion.)

On September 21, 2004 DENA signed a purchase and sale agreement to sell DENA’s 75% interests in Bayside Power L.P. (Bayside). (See Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale,” for further discussion.)

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The following map shows DENA’s power generation facilities.

Marketing Portfolio

Much of DENA’s portfolio of purchase and sales agreements incorporate market-sensitive pricing terms. To minimize the impact of changing market conditions to DENA, physical purchases and sales are generally hedged with financial derivatives. Additionally, DENA continues to sell fixed capacity contracts in addition to volume based sales and purchases. (For information concerning DENA’s risk-management activities, see “Management’s Discussion and Analysis of Results of Operations and Financial Condition, Quantitative and Qualitative Disclosures About Market Risk” and Note 8 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments.”)

DENA is active in the Western (California and Southwest), Northeast and Midwest power markets including the associated gas supply, transport and storage in those markets. DENA has a strong focus on increasing its percentage of contracted energy ($/MWh) and capacity ($/kW/month) versus energy/capacity sold into the spot/non-contracted markets. Additionally, DENA continues to sell fixed capacity contracts in addition to volume based sales and purchases.

Competition

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

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Regulation

DENA’s energy marketing activities are subject to the jurisdiction of the FERC in some circumstances. Current FERC policies permit DENA’s trading and marketing entities to market natural gas, electricity and other energy-related commodities at market-based rates. Ongoing regulatory initiatives at both state and federal levels addressing market design,such as the development of capacity markets and real-time electricity markets, impact financial results from DENA’s marketing and generation activities.

Litigation at the state level is ongoing related to DENA’s activities in California during the electricity supply situation in 2000 and 2001. (See Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies—Litigation,” for further discussion.)

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

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

INTERNATIONAL ENERGY

International Energy operates and manages power generation facilities, and engages in sales and marketing of electric power and natural gas outside the U.S. and Canada. It conducts operations primarily through DEI and its activities target power generation in Latin America. Additionally, International Energy owns an equity investment in National Methanol Company, located in Saudi Arabia, which is a leading regional producer of methanol and MTBE.

International Energy’s customers include retail distributors, electric utilities, independent power producers, marketers and large industrial companies. International Energy is committed to building integrated regional businesses that provide customers with a full range of innovative and competitively priced energy services.

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

International Energy owns, operates or has substantial interests in approximately 4,139 net MW of generation facilities. The following map shows the locations of International Energy’s facilities, including projects under construction and non-generation facilities in Mexico and Saudi Arabia. The capacities shown in the map are gross MW values (for net MW values see “Properties—International Energy”).

During 2004, Duke Energy completed the sale of the Asia-Pacific power generation and natural gas transmission business (the Asia-Pacific Business) to Alinta Ltd. All gains related to this transaction and the results of operations for these assets are included in Discontinued Operations, net of tax, in the Consolidated Statements of Operations. (See Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale,” for further discussion.)

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Also in 2004, International Energy completed the sale of its 30% equity interest in Compañia de Nitrógeno de Cantarell, S.A. de C.V. (Cantarell) a nitrogen production and delivery facility in the Bay of Campeche, Gulf of Mexico. (See Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions,” for further discussion.)

Competition and Regulation

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

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

International Energy’s operations are subject to both country-specific and international laws and regulations. (See “Environmental Matters” in this section.)

CRESCENT

Crescent develops and manages high-quality commercial, residential and multi-family real estate projects, and manages land holdings, primarily in the Southeastern and Southwestern U.S. As of December 31, 2004, Crescent owned 0.5 million square feet of commercial, industrial and retail space, with an additional 1.2 million square feet under construction. This portfolio included 0.9 million square feet of office space, 0.5 million square feet of warehouse space and 0.3 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 develop - -

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ments sold to national builders. Crescent had three multi-family communities at December 31, 2004, including one operating property and two properties under development. As of December 31, 2004, Crescent also managed approximately 132,000 acres of land.

Competition and Regulation

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

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

OTHER

During 2004, Other primarily included certain unallocated corporate costs, DukeNet, DEM, Duke Energy’s 50% interest in D/FD, and Bison. DCP had been previously included in Other, however at December 31, 2004 Duke Energy had exited the merchant finance business, and all of the results of operations for DCP for the years ended December 31, 2004, 2003 and 2002 have been classified as discontinued operations.

DukeNet develops, owns and operates a fiber optic communications network, primarily in the Carolinas serving wireless, local and long-distance communications companies, Internet service providers and other businesses and organizations.

DEM engages in commodity buying and selling, and risk management and financial services in non-regulated energy commodity markets other than physical natural gas and power (such as petroleum products). DEM’s activities can fluctuate in response to seasonal demand for other energy-related commodities. During 2003, Duke Energy determined that it would exit the refined products business at DEM in an orderly manner, and continues to unwind its portfolio of contracts. As of December 31, 2004, DEM had exited the majority of its business.

D/FD is a 50/50 partnership between subsidiaries of Duke Energy and Fluor Corporation. During 2003, Duke Energy and Fluor Corporation announced that they would dissolve the D/FD partnership. The D/FD partners adopted a plan for an orderly wind-down of the business which is expected to be completed by December 2005. Previously, D/FD provided comprehensive engineering, procurement, construction, commissioning and operating plant services for fossil-fueled electric power generating facilities worldwide.

Bison’s principle activities, as a captive insurance entity, include the insurance and reinsurance of various business risks and losses, such as workers compensation, property, business interruption, and general liability of subsidiaries and affiliates of Duke Energy. Bison also participates in reinsurance activities with certain third parties, on a limited basis.

Competition and Regulation

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

ENVIRONMENTAL MATTERS

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

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(For more information on environmental matters involving Duke Energy, including possible liability and capital costs, see Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies—Environmental.”)

Except to the extent discussed in Note 4 to the Consolidated Financial Statements, “Regulatory Matters,” and Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies,” compliance with international, federal, state and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is not expected to have a material adverse effect on the competitive position, consolidated results of operations, cash flows or financial position of Duke Energy.

GEOGRAPHIC REGIONS

For a discussion of Duke Energy’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 8 to the Consolidated Financial Statements, “Business Segments” and “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments.”

EMPLOYEES

On December 31, 2004, Duke Energy had approximately 21,500 employees. A total of 3,238 operating and maintenance employees were represented by unions. This amount consists of the following:

EXECUTIVE OFFICERS OF DUKE ENERGY

PAUL M. ANDERSON, 59, Chairman of the Board and Chief Executive Officer. Mr. Anderson was named to his current position in November 2003. Mr. Anderson most recently served as Managing Director and Chief Executive Officer of BHP Billiton Ltd and BHP Billiton PLC, from which he retired in July 2002. Prior to joining BHP, Mr. Anderson had a career that spanned more than 20 years at Duke Energy and its predecessor companies, including serving as Chief Executive Officer of PanEnergy Corp (PanEnergy).

KEITH G. BUTLER, 44, Vice President and Controller. Mr. Butler was named Senior Vice President and Chief Financial Officer of Duke Energy Global and its affiliated companies in February 1998, Senior Vice President and Chief Financial Officer of DENA in July 1998, and Chief Operating Officer of DukeSolutions, Inc. in September 1999 before he assumed his current position in August 2001.

MYRON L. CALDWELL, 47, Vice President and Treasurer. Mr. Caldwell was named to his current position in December 2003. He previously served as Vice President of Corporate Finance since October 2000, and Managing Director of Corporate Finance since Sep - -

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tember 1999. Mr. Caldwell held various other positions since joining Duke Energy in 1981, including Controller of Duke Power and Senior Vice President and Chief Financial Officer of Duke Engineering & Services, Inc.

FRED J. FOWLER, 59, President and Chief Operating Officer. Mr. Fowler assumed his current position in November 2002. Mr. Fowler served as Group Vice President of PanEnergy from 1996 until the PanEnergy merger in 1997, when he was named Group President, Energy Transmission.

DAVID L. HAUSER, 53, Group Vice President and Chief Financial Officer. Mr. Hauser assumed his current position in March 2004, but served as Acting Chief Financial Officer since December 2003. He previously served as Senior Vice President and Treasurer. Mr. Hauser held various positions, including Controller of Duke Power before being named Senior Vice President, Global Asset Development in 1997.

JIM W. MOGG, 56, Group Vice President and Chief Development Officer. Mr. Mogg assumed his current position in January 2004. He previously served as President and Chief Executive Officer of DEFS since December 1994 and Chairman, President and Chief Executive Officer of DEFS since 1999.

A.R. MULLINAX, 50, Group Vice President and Chief Information Officer. Mr. Mullinax assumed his current position in October 2004. He previously served as Vice President of Business Services. Mr. Mullinax has held various positions including Senior Vice President of Shared Services, Global Sourcing, and Duke Ventures as well as President and Chief Executive Officer of DukeNet.

THOMAS C. O’CONNOR, 49, Group Vice President (Executive Officer effective March 1, 2005). Mr. O’Connor assumed his current position in March 2005. He previously served as President and Chief Executive Officer of Duke Energy Gas Transmission since December 2002. He has also served in leadership positions with Duke Energy’s pipeline operations since 1994. Mr. O’Connor joined Duke Energy in 1987 as Supervisor of Environmental Compliance for Algonquin Gas Transmission LLC (Algonquin) in New England.

RICHARD J. OSBORNE, 54, Group Vice President, Public and Regulatory Policy. Mr. Osborne assumed his current position in January 2004. He previously served as Executive Vice President and Chief Risk Officer. He also served as Executive Vice President and Chief Financial Officer since 1997 and Senior Vice President and Chief Financial Officer since 1994.

RUTH G. SHAW, 57, President and Chief Executive Officer, Duke Power. Dr. Shaw assumed her current position in February 2003. Dr. Shaw served as Senior Vice President, Corporate Resources, from 1994 until the PanEnergy merger in 1997, when she was named Executive Vice President and Chief Administrative Officer.

B. KEITH TRENT, 45, Group Vice President, General Counsel and Secretary, in an acting capacity (Executive Officer effective March 1, 2005). Mr. Trent assumed his current position in March 2005. He previously served as General Counsel, Litigation since May 2002 when he joined Duke Energy. He previously served as a partner in the law firm Snell, Brannian & Trent since October 1991.

MARTHA B. WYRSCH, 47, President and Chief Executive Officer of Duke Energy Gas Transmission (Executive Officer until March 1, 2005). Ms. Wyrsch assumed her current position in March 2005. She previously served as Group Vice President, General Counsel and Secretary since January 2004. She also served as Senior Vice President of Legal Affairs. Ms. Wyrsch joined Duke Energy in September 1999 as Senior Vice President, General Counsel and Secretary for DEFS.

Executive officers are elected annually by the Board of Directors. They serve until the first meeting of the Board of Directors following the annual meeting of shareholders and until their successors are duly elected.

There are no family relationships between any of the executive officers, nor any arrangement or understanding between any executive officer and any other person involved in officer selection.

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Item 2. Properties.

FRANCHISED ELECTRIC

As of December 31, 2004, Franchised Electric operated three nuclear generating stations with a combined net capacity of 5,020 MW (including a 12.5% ownership in the Catawba Nuclear Station), eight coal-fired stations with a combined capacity of 7,754 MW, 31 hydroelectric stations (including two pumped-storage facilities) with a combined capacity of 2,810 MW and seven combustion turbine stations with a combined capacity of 2,447 MW. All of the stations are located in North Carolina or South Carolina.

In addition, as of December 31, 2004, Franchised Electric owned approximately 13,000 conductor miles of electric transmission lines, including 600 miles of 525 kilovolts, 2,600 miles of 230 kilovolts, 6,600 miles of 100 to 161 kilovolts, and 3,200 miles of 13 to 66 kilovolts. Franchised Electric also owned approximately 94,000 conductor miles of electric distribution lines, including 49,800 miles of rural overhead lines, 16,100 miles of urban overhead lines, 15,400 miles of rural underground lines and 12,700 miles of urban underground lines. As of December 31, 2004, the electric transmission and distribution systems had approximately 1,600 substations.

Substantially all of Franchised Electric’s electric plant in service is mortgaged under the indenture relating to Duke Energy’s various series of First and Refunding Mortgage Bonds.

(For a map showing Franchised Electric’s properties, see “Business—Franchised Electric” earlier in this section.)

NATURAL GAS TRANSMISSION

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

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

Texas Eastern has two joint-venture storage facilities in Pennsylvania and one wholly owned and operated storage field in Maryland. Texas Eastern’s total working capacity in these three fields is 75 Bcf.

Algonquin transmission system connects with Texas Eastern’s facilities in New Jersey, and extends approximately 250 miles through New Jersey, New York, Connecticut, Rhode Island and Massachusetts. The system consists of approximately 1,100 miles of pipeline with six compressor stations.

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

ETNG has an LNG storage facility in Tennessee with a total working capacity of 1.2 Bcf.

Maritimes & Northeast Pipeline, LLC and Maritimes & Northeast Pipeline, LP (collectively, Maritimes & Northeast) transmission system (approximately 78% owned by Duke Energy) extends approximately 900 miles from producing fields in Nova Scotia through New Brunswick, Maine, New Hampshire and Massachusetts, connecting to Algonquin in Beverly, Massachusetts. It has two compressor stations on the system.

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

Union Gas owns and operates natural gas transmission, distribution and storage facilities in Ontario. Union Gas’ distribution system consists of approximately 22,000 miles of distribution pipelines. 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.

MHP owns and operates two natural gas storage facilities, Moss Bluff and Egan, with a total storage capacity of approximately 31 Bcf. The Moss Bluff facility consists of three storage caverns located in southeast Texas and has access to five pipeline systems. The Egan facility consists of three storage caverns located in south central Louisiana and has access to eight pipeline systems.

Natural Gas Transmission also has an investment in Gulfstream National Gas System, LLC (Gulfstream), a 691-mile interstate natural gas pipeline system owned and operated jointly by Duke Energy and The Williams Company, Inc. The Gulfstream gas pipeline has a capacity of 1.1 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 began initial service in May 2002.

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

FIELD SERVICES

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

DENA

The following table provides information about DENA’s generation portfolio in continuing operations as of December 31, 2004.

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

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INTERNATIONAL ENERGY

The following table provides information about International Energy’s generation portfolio in continuing operations as of December 31, 2004.

In addition to those generating facilities, International Energy owns a 25% equity interest in National Methanol Company (NMC), located in Saudi Arabia, which is a leading producer of methanol and MTBE. In 2004, the NMC produced approximately 900 thousand metric tons of methanol and one million metric tons of MTBE. International Energy also owns a 50% equity interest in Compañía de Servicios de Compresión de Campeche, S.A. de C.V. (Campeche), located in the Cantarell oil field in the Bay of Campeche, Mexico, which compresses and dehydrates natural gas and extracts NGLs. Campeche has an installed processing capacity of 270 Mmcf/d. (For additional information and a map showing International Energy’s properties, see “Business—International Energy” earlier in this section.)

CRESCENT

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

OTHER

(For information regarding the properties of the business unit now known as Other, see “Business—Other” earlier in this section.)

Item 3. Legal Proceedings.

In July 2003, a fire occurred at the Moss Landing Power Plant in California, operated by Duke Energy Moss Landing LLC (DEML), a subsidiary of DENA, when fuel oil was ignited by a contractor performing tank clean out and dismantling activities. The Monterey County District Attorney initiated civil enforcement action against DEML alleging violations of the California Health and Safety Code and the Business and Professions Code. The alleged violations concerned the handling of hazardous materials at the site and unlawful release of hazardous materials into the environment. DEML denied the allegations but agreed to settle the civil enforcement action by committing to expend a total of $752,287, the majority of which entails reimbursement of costs to the county and expenditures for safety/environmental training efforts by the company, but also includes a $100,000 civil penalty payment. The district attorney also settled a related action against DEML’s contractor for alleged violations in the incident. Both settlements were announced on September 22, 2004.

(For information regarding legal proceedings, including regulatory and environmental matters, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters” and Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies—Litigation” and “Commitments and Contingencies—Environmental.”)

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

No matters were submitted to a vote of Duke Energy’s security holders during the fourth quarter of 2004.

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

Duke Energy’s common stock is listed for trading on the New York Stock Exchange. As of February 28, 2005, there were approximately 143,800 common stockholders of record.

Common Stock Data by Quarter

On December 17, 1998, Duke Energy’s Board of Directors adopted a shareholder rights plan. Under the terms of the plan, one preference stock purchase right was distributed for each share of common stock outstanding on February 12, 1999, and for each share issued thereafter, subject to adjustment as specified. The NCUC and the PSCSC approved this distribution. The plan is intended to ensure the fair treatment of all shareholders in the event of a hostile takeover attempt and to encourage a potential acquirer to negotiate with the Board of Directors a fair price for all shareholders before attempting a takeover. The adoption of the plan was not in response to any takeover offer or threat. The Corporate Governance Committee of the Board of Directors evaluates the plan at least once every three years, and most recently evaluated the plan in October 2004.

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Item 6. Selected Financial Data.

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

INTRODUCTION

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

Overview of Business Strategy. Duke Energy’s business strategy is to create value for customers, employees, communities and shareholders through the production, conversion, delivery and sale of energy and energy services. Duke Energy’s plan is to emphasize income for its shareholders, with modest growth.

For the past few years, the energy industry including Duke Energy experienced 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 challenges, Duke Energy’s focus for 2004 was to reduce risks and restructure its business. By selling assets such as Duke Energy North America’s (DENA’s) eight natural gas-fired merchant power plants: Hot Spring (Arkansas); Murray and Sandersville (Georgia); Marshall (Kentucky); Hinds, Southaven, Enterprise and New Albany (Mississippi) in the southeastern United States; (collectively, the Southeast Plants) and International Energy’s Asia-Pacific power generation and natural gas transmission business (the Asia-Pacific Business), Duke Energy eliminated some of its lowest return assets. These asset sales provided cash proceeds allowing Duke Energy to pay down debt and strengthen its balance sheet. Progress was also made in 2004 in resolving some critical legal and regulatory issues.

As a result of the efforts in 2004, Duke Energy’s objectives for 2005 include establishing industry-leading positions in core businesses and identifying new energy-related growth strategies, focused in the Americas. Increased demand for natural gas supplies in the United States and changing logistics among source of supply are providing opportunities for growth. To capitalize on this market dynamic, Natural Gas Transmission is evaluating longer-term opportunities to provide pipeline capacity and storage facilities for the expected expansion of the liquefied natural gas (LNG) market. Additionally, the strength of the natural gas market provides incentives for producers to increase exploration and production, which in turn, provides business sustainability and growth opportunities for Field Services. Duke Power and International Energy are expected to grow organically for the near term.

In February 2005, Duke Energy Field Services LLC (DEFS) sold Texas Eastern Products Pipeline Company LLC (TEPPCO) for approximately $1.1 billion and Duke Energy sold its limited partner interest in TEPPCO Partners, L.P. for approximately $100 million, in each case to EPCO, an unrelated third party. These transactions closed in the first quarter of 2005.

In February 2005, Duke Energy executed an agreement with ConocoPhillips whereby Duke Energy has agreed to transfer a 19.7% interest in DEFS to ConocoPhillips for direct and indirect monetary and non-monetary consideration of approximately $1.1 billion. Upon completion of this transaction, DEFS will be owned 50% by Duke Energy and 50% by ConocoPhillips. As a result, Duke Energy expects to account for its investment in DEFS using the equity method subsequent to closing of the transaction, which is expected to occur in the latter half of 2005.

Duke Energy believes merchant energy will play a vital role in meeting the United States’ energy demand. Another key objective for 2005 is to position DENA to be a successful merchant operator. During 2004, DENA’s business model changed to focus on selling fixed capacity contracts in addition to volume based sales and purchases. Duke Energy is pursuing various options to create a sustainable business model for DENA, including consideration of potential business partners. A sustainable business model will include fuel and geographic diversity, sufficient size and scope for a substantial market presence and will enable DENA to better withstand the cyclical nature of the industry. Depending on the option selected, there is a risk that material impairments or losses could be recorded, including the potential disqualification of certain contracts and the recognition of unrealized losses associated with DENA power forward sales contracts designated under the normal purchases and normal sales exemption, which totaled approximately $900 million (pre-tax) as of December 31, 2004. This unrealized loss represents the difference in the normal purchases and normal sales contract prices compared to the forward market prices of power and is partially offset by unrealized gains on natural gas positions of approximately $800 million (pretax) as of December 31, 2004. (For more information see Commodity Price Risk discussion under Quantitative and Qualitative Disclosures About Market Risk).

With cash, cash equivalents and short-term investments on hand at December 31, 2004 of approximately $1.9 billion and a more stable business environment, Duke Energy has financial flexibility to buy back common stock, invest incrementally or pay down additional debt. Duke Energy is evaluating these options and will determine the best economic decisions to meet the needs of shareholders and ensure the long-term financial strength of Duke Energy. In connection with the TEPPCO and DEFS transactions discussed above, Duke Energy has announced plans to periodically repurchase up to an aggregate $2.5 billion of its common stock over the next three years.

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Other key objectives for Duke Energy in 2005 are to build stakeholder relationships through effective leadership on key policy issues related to energy, regulation and the environment, and also to focus on safety, inclusion and diversity, employee development, business structure and process simplification.

These objectives, along with delivering on Duke Energy’s financial plan, are set with the intent to provide superior total shareholder return.

Economic Factors for Duke Energy’s Business. Duke Energy’s business model provides diversification between stable, less cyclical businesses like Franchised Electric and Natural Gas Transmission, and the traditionally higher-growth and more cyclical energy businesses like DENA, International Energy and Field Services. Additionally, Crescent Resources LLC’s (Crescent’s) portfolio strategy is diversified between residential, commercial and multi-family development. All of Duke Energy’s businesses can be negatively affected by sustained downturns or sluggishness in the economy, including low market price of commodities, all of which are beyond Duke Energy’s control, and could impair Duke Energy’s ability to meet its goals for 2005 and beyond.

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

If negative market conditions persist over time and estimated cash flows over the lives of Duke 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 and diminish results of operations. Furthermore, a change in management’s intent about the use of individual assets (held for use versus held for sale) or a change in fair value of assets held for sale could also result in impairments or losses.

Duke Energy’s goals for 2005 can also be substantially at risk due to the regulation of its businesses. Duke Energy’s businesses in North America are subject to regulations on the federal and state level. The majority of Duke Energy’s Canadian natural gas assets is also subject to various degrees of federal or provincial regulation and is subject to the same risks. Regulations, applicable to the electric power industry and gas transmission and storage industry, have a significant impact on the nature of the businesses and the manner in which they operate. Changes to regulations are ongoing and Duke Energy cannot predict the future course of changes in the regulatory environment or the ultimate effect that any future changes will have on its business.

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

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

RESULTS OF OPERATIONS

Overview of Drivers and Variances for 2004 and 2003

Year Ended December 31, 2004 as Compared to December 31, 2003. For 2004, earnings available for common stockholders were $1,481 million, or $1.59 per basic share and $1.54 per diluted share. For 2003, earnings available for common stockholders were a loss of $1,338 million, or a loss of $1.48 per basic and diluted share. Significant items that contributed to the improved results in 2004 included:

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Partially offsetting these increases and prior year charges were:

For additional information on specific business unit related items, see the segment discussions that follow. For a detailed discussion of interest, taxes and the impact of changes in accounting principles, see “Other Impacts on Earnings Available for Common Stockholders” at the end of this section.

Consolidated Operating Revenues

Year Ended December 31, 2004 as Compared to December 31, 2003. Consolidated operating revenues for 2004 increased $423 million, compared to 2003. This change was driven by:

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Year Ended December 31, 2003 as Compared to December 31, 2002. Consolidated operating revenues for 2003 increased $6,220 million, compared to 2002. This change was primarily driven by:

Consolidated Operating Expenses

Year Ended December 31, 2004 as Compared to December 31, 2003. Consolidated operating expenses for 2004 decreased $3,362 million, compared to 2003. The change was primarily driven by:

Year Ended December 31, 2003 as Compared to December 31, 2002. Consolidated operating expenses for 2003 increased $9,560 million, compared to 2002. The increase in consolidated operating expenses was driven primarily by impairments and other related charges, and by the same drivers that affected consolidated operating revenues: increased purchase costs for NGLs and the adoption of the final consensus on EITF Issue No. 02-03, and additional expenses due to the acquisition of Westcoast.

Consolidated Gains on Sales of Investments in Commercial and Multi-Family Real Estate

Consolidated gains on sales of investments in commercial and multi-family real estate were $192 million in 2004, $84 million in 2003, and $106 million in 2002. For a detailed discussion of this item see the Crescent segment discussion below.

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

Consolidated (losses) gains on sales of other assets, net was a loss of $225 million for 2004, a loss of $199 million for 2003, and a gain of $32 million for 2002. The loss in 2004 was due primarily to pre-tax losses on the sale of the Southeast Plants (approximately $360 million) at DENA, and the termination and sale of DETM contracts ($65 million) offset by gains on the sales of two partially completed plants, Moapa ($140 million) and Luna ($40 million) at DENA. The loss for 2003 was primarily comprised of a $208 million loss at DENA primarily related to charges on DETM contracts ($127 million) resulting from the wind-down of DETM’s operations, and impairments recorded on assets held for sale, including a 25% undivided interest in the wholly-owned Vermillion facility ($18 million), and stored turbines and related equipment ($66 million). The gain for 2002 was primarily comprised of a $33 million gain on the sale of Duke Energy’s remaining water operations.

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Consolidated Operating Income

Year Ended December 31, 2004 as Compared to December 31, 2003. For 2004, consolidated operating income increased $3,867 million, compared to 2003. Increased operating income was driven primarily by increased operating income at DENA, as a result of impairments and other related charges in 2003.

Year Ended December 31, 2003 as Compared to December 31, 2002. For 2003, consolidated operating income decreased $3,593 million, compared to 2002. Lower operating income was driven primarily by asset impairments and related charges at DENA of $2,903 million, as discussed above.

Consolidated Other Income and Expenses

Consolidated other income and expenses decreased $282 million for the year ended December 31, 2004 as compared to December 31, 2003. The decrease primarily resulted from the $178 million pre-tax gain on the sale of DENA’s 50% interest in Ref-Fuel in 2003 and Natural Gas Transmission’s $90 million gain on sales of various investments in 2003, offset by foregone earnings from those investments. The increase in 2003 compared to 2002 was also a result of the gain from the Ref-Fuel sale as discussed above.

Segment Results

Management evaluates segment performance primarily based on earnings before interest and taxes from continuing operations, after deducting minority interest expense related to those profits (EBIT). On a segment basis, EBIT represents all profits from continuing operations (both operating and non-operating) before deducting interest and taxes, and is net of the minority interest expense related to those profits. EBIT excludes discontinued operations. Cash, cash equivalents and short-term investments are managed centrally by Duke Energy, so the gains and losses on foreign currency remeasurement associated with cash balances, and interest income on those balances, are excluded from the segments’ EBIT. Management considers segment EBIT to be a good indicator of each segment’s operating performance from its continuing operations, as it represents the results of Duke Energy’s ownership interest in operations without regard to financing methods or capital structures.

Duke Energy’s segment EBIT may not be comparable to a similarly titled measure of another company because other entities may not calculate EBIT in the same manner. Business segment EBIT is summarized in the following table, and detailed discussions follow.

EBIT by Business Segment

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

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Franchised Electric