Exhibit 99.1

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.

In May 2005, Duke Energy and Cinergy announced they entered into a definitive merger agreement. Closing of the transaction occurred in the second quarter of 2006. The merger combined the Duke Energy and Cinergy regulated franchises as well as deregulated generation in the Midwest United States.

In conjunction with Duke Energy’s merger with Cinergy, effective with the second quarter ended June 30, 2006, Duke Energy adopted new business segments that management believes properly align the various operations of Duke Energy with how the chief operating decision maker views the business. Duke Energy operates the following business units: U.S. Franchised Electric and Gas, Natural Gas Transmission, Field Services, Commercial Power, International Energy and Crescent Resources, LLC (Crescent). While decisions made in 2006 as part of the merged business is the rationale for this segment change, the information contained herein is as of December 31, 2005, and accordingly, segment disclosures herein do not include any balances or results of operations of businesses acquired as part of the merger with Cinergy. 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. 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.” (See Note 3 to the Consolidated Financial Statements, “Business Segments,” for additional information, including financial information about each business unit and geographic areas.)

Prior to the September, 2005 announcement of the plan to exit the majority of Duke Energy North America’s (DENA) businesses (see below), DENA’s operations were considered a separate reportable segment. The term DENA, as used throughout this filing, refers to operations in the Western and Eastern U.S., as well as operations in the Midwest and Southeast. Under Duke Energy’s new segment structure, the operations of the Midwest and Southeast are presented as a component of the Commercial Power segment for all periods presented. These operations had previously been included in Other in 2005 and as a component of the DENA segment in all prior periods. The Western and Eastern operations, which Duke Energy has exited, are presented as a component of discontinued operations within Other for all periods presented. These operations had previously been included in the DENA segment in all periods.

U.S. Franchised Electric and Gas generates, transmits, distributes and sells electricity in central and western North Carolina and western South Carolina. It conducts operations primarily through Duke Energy’s Franchised Electric business (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 in the Eastern and Southeastern U.S. and in Ontario and British Columbia in Canada. Natural Gas Transmission also provides natural gas sales and distribution service to retail customers in Ontario, natural gas gathering and processing services to customers in Western Canada and other energy related services. Natural Gas Transmission does business primarily through Duke Energy Gas Transmission, LLC (DEGT). DEGT’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).

In June 2006, the Board of Directors of Duke Energy authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas businesses to Duke Energy shareholders. The new natural gas company, which would be named Spectra Energy, would principally consist of Duke Energy’s Natural Gas Transmission business segment, which would include Union Gas, and would also include Duke Energy’s 50-percent ownership interest in DEFS. Approximately $9 billion of debt currently at Duke Capital and its consolidated subsidiaries is anticipated to transfer to the new natural gas company at the time of the spin-off. If completed, the decision to spin off the natural gas business is expected to deliver long-term value to shareholders. While the actual timing of the spin-off, if it occurs, is dependent upon the resolution of certain regulatory and other matters, Duke Energy is currently targeting a January 1, 2007 effective date for the transaction. The results of the natural gas businesses are expected to be treated as discontinued operations in the period the spin-off is consummated. The primary businesses remaining in Duke Energy post-spin are anticipated to be principally the U.S. Franchised Electric and Gas business segment, the Commercial Power business segment, the International Energy business segment and Duke Energy’s 50% interest in the Crescent JV (see below).

Field Services includes Duke Energy’s investment in Duke Energy Field Services, LLC (DEFS), which gathers, compresses, treats, processes, transports, trades and markets, and stores natural gas; and fractionates, transports, trades and markets, and stores natural gas liquids (NGLs). DEFS is 50% owned by ConocoPhillips and 50% owned by Duke Energy. DEFS gathers raw natural gas through gather -

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ing systems located in seven major natural gas producing regions: Permian Basin, Mid-Continent, ArklaTex, Gulf Coast, South, Central and the Rocky Mountains.

In February 2005, DEFS sold its wholly owned subsidiary Texas Eastern Products Pipeline Company, LLC (TEPPCO GP), which is the general partner of TEPPCO Partners, LP (TEPPCO LP), and Duke Energy sold its limited partner interest in TEPPCO LP, in each case to Enterprise GP Holdings LP (EPCO), an unrelated third party. Additionally, in July 2005, Duke Energy completed the previously announced agreement with ConocoPhillips, Duke Energy’s co-equity owner in DEFS, to reduce Duke Energy’s ownership interest in DEFS from 69.7% to 50% (the DEFS disposition transaction), which resulted in Duke Energy and ConocoPhillips becoming equal 50% owners in DEFS. The DEFS disposition transaction includes the transfer to Duke Energy of DEFS’ Canadian natural gas gathering and processing facilities. As a result of the DEFS disposition transaction, Duke Energy deconsolidated its investment in DEFS and subsequently has accounted for it as an investment utilizing the equity method of accounting.

Commercial Power (formerly a portion of DENA) operates and manages power plants and markets electric power and natural gas related to these plants and other contractual positions. Commercial Power’s operations consist primarily of five Midwestern generating plants, representing a mix of combined cycle and peaking plants consisting of approximately 3,600 megawatts of power generation, and certain contracts related to the Midwestern generating facilities, and eight natural gas-fired merchant power plants in the Southeastern United States and certain other power and gas contracts, which were formerly a portion of DENA and were substantially disposed of in 2004.

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 (NMC), 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.

On September 7, 2006, an indirect wholly owned subsidiary of Duke Energy closed an agreement to create a joint venture of Crescent (the Crescent JV) with Morgan Stanley Real Estate Fund V U.S., L.P. (MSREF) and other affiliated funds controlled by Morgan Stanley (collectively the “MS Members”). Under the agreement, the Duke Energy subsidiary contributed all of the membership interests in Crescent to a newly-formed joint venture, which was ascribed an enterprise value of approximately $2.1 billion as of December 31, 2005. In conjunction with the formation of the Crescent JV, the joint venture, Crescent and Crescent’s subsidiaries entered into a credit agreement with third party lenders under which Crescent borrowed approximately $1.23 billion, of which approximately $1.19 billion was immediately distributed to Duke Energy. Immediately following the debt transaction, the MS Members collectively acquired a 49% membership interest in the Crescent JV from Duke Energy for a purchase price of approximately $415 million. The MS Members 49% interest reflects a 2% interest in the Crescent JV issued by the joint venture to the President and Chief Executive Officer of Crescent which is subject to forfeiture if the executive voluntarily leaves the employment of the Crescent JV within a three year period. Additionally, this interest can be put back to the Crescent JV after three years or possibly earlier upon the occurrence of certain events at an amount equal to 2% of the fair value of the Crescent JV’s equity as of the put date. Therefore, the Crescent JV will accrue the obligation related to the put as a liability over the three year forfeiture period. Accordingly, Duke Energy has an effective 50% ownership in the equity of Crescent JV for financial reporting purposes. Duke Energy’s investment in the Crescent JV has been accounted for as an equity method investment for periods after September 7, 2006.

The remainder of Duke Energy’s operations is presented as “Other”. While it is not considered a business segment, Other primarily includes the following:

• The remaining portion of Duke Energy’s business formerly known as DENA, including 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. During the third quarter of 2005, Duke Energy’s Board of Directors authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. The exit plan was completed in the second quarter of 2006 (see Note 24 to the Consolidated Financial Statements, “Subsequent Events”). In addition, management will continue to wind down the limited remaining operations of DETM. The results of operations for most of DENA’s businesses which Duke Energy has exited have been reflected as discontinued operations in the accompanying Consolidated Statements of Operations for all years presented.

• Other also includes certain unallocated corporate costs, certain discontinued hedges, 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

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service providers and other businesses and organizations. Following Duke Energy’s decision in 2003 to exit the refined products business at DEM in an orderly manner, as of December 31, 2005, DEM had exited the majority of its business. Bison’s principal 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 (Fluor). During 2003, Duke Energy and Fluor announced that they would dissolve D/FD, and adopted a plan for an orderly wind-down of D/FD’s business. The wind-down has been substantially completed as of December 31, 2005, and is expected to be finalized by December 2006. Previously, D/FD provided comprehensive engineering, procurement, construction, commissioning and operating plant services for fossil-fueled electric power generating facilities worldwide.

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 Securities and Exchange Commission (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 100 F Street, N.E., 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, “Summary of Significant Accounting Policies,” 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). An accounting convention of regulators 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.

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.

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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 bi-lateral 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.

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, “Summary of Significant Accounting Policies,” 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.

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.

Novation. The substitution of a new obligation or contract for an old one by the mutual agreement of all parties concerned.

Nuclear Regulatory Commission (NRC). The U.S. agency responsible for regulating the Nation’s civilian use of byproduct, source, and special nuclear materials to ensure adequate protection of public health and safety, to promote the common defense and security, and to protect the environment. The NRC’s scope of responsibility includes regulation of: commercial nuclear power reactors, including nonpower research, test and training reactors; fuel cycle facilities, including medical, academic and industrial uses of nuclear materials; and the transport, storage and disposal of nuclear materials and waste.

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.

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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—Executive Overview 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.”)

U.S. FRANCHISED ELECTRIC AND GAS

Service Area and Customers

U.S. Franchised Electric and Gas generates, transmits, distributes and sells electricity. It conducts operations primarily through Duke Energy Carolinas. Its service area covers about 22,000 square miles with an estimated population of 6 million in Central and Western North Carolina and Western South Carolina. U.S. Franchised Electric and Gas supplies electric service to approximately 2.3 million residential, commercial and industrial customers over 96,000 miles of distribution lines and a 13,200-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 U.S. Franchised Electric and Gas, 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 U.S. Franchised Electric and Gas’ service area is diversified. The textile industry, rubber and plastic products, chemicals and paper products are of major significance to the area’s economy. Other significant industries operating in the area include machinery and equipment manufacturing, primary metals, electronics, and other manufacturing and service businesses. The textile industry, while in decline, is the largest industry served by U.S. Franchised Electric and Gas and accounted for approximately $277 million of U.S. Franchised Electric and Gas’ revenues for 2005, representing 5% of total electric revenues and 25% of industrial revenues.

In 2005, U.S. Franchised Electric and Gas implemented business development strategies to leverage the competitive advantages of North Carolina and South Carolina to attract new advanced manufacturing business to Duke Energy Carolinas’ service territory. These competitive advantages, including a quality workforce, strong educational institutions and superior transportation infrastructure, were key factors in attracting significant new customers in the financial sector and electronics manufacturing industry. The ability to attract new industry to the service territory coupled with growth in the plastics, biopharmaceuticals, medical equipment and automotive parts industries continues to significantly offset the sales declines in the textile industry.

The number of residential and commercial customers within the U.S. Franchised Electric and Gas service territory continues to increase. Sales to these customers are increasing due to the growth in these sectors. As sales to residential and commercial customers increase, the consistent level of sales to industrial customers becomes a smaller, yet still significant, portion of U.S. Franchised Electric and Gas sales.

U.S. Franchised Electric and Gas’ 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.

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Energy Capacity and Resources

Electric energy for U.S. Franchised Electric and Gas’ 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 3,169 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. U.S. Franchised Electric and Gas 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.

U.S. Franchised Electric and Gas’ 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 U.S. Franchised Electric and Gas’ large, low-energy-production-cost nuclear and coal-fired generating units that operate almost continuously (or at baseload levels). In 2005, approximately 98% of the total generated energy came from U.S. Franchised Electric and Gas’ low-cost, efficient nuclear and coal units (45.7% nuclear and 52.5% coal). The remaining energy needs were supplied by hydroelectric and combustion-turbine generation or economical purchases from the wholesale market.

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.

U.S. Franchised Electric and Gas’ 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 facilities allow U.S. Franchised Electric and Gas to maximize the value spreads between different high- and low-cost generation periods.

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U.S. Franchised Electric and Gas is engaged in planning efforts to meet projected load growth in its service territory. Long-term projections indicate a need for significant capacity additions, which may include new nuclear and coal facilities. Because of the long lead times required to develop such assets, U.S. Franchised Electric and Gas is taking steps now to ensure those options are available. For example, U.S. Franchised Electric and Gas is preparing an application for a Combined Construction and Operating License from the NRC, with the objective of potentially bringing a new nuclear facility on line by 2016. Steps are also being taken to maintain the option to bring a new coal facility on line as early as 2011. Although U.S. Franchised Electric and Gas is progressing with these preliminary steps, final decisions regarding the development of new power facilities will be driven by realized demand, market conditions and other strategic considerations.

In March 2006, Duke Energy Carolinas announced that it has entered into an agreement with Southern Company to evaluate potential construction of a new nuclear plant at a site jointly owned in Cherokee County, South Carolina. With selection of the Cherokee County site, Duke Energy Carolinas is moving forward with previously announced plans to develop an application to the U.S. Nuclear Regulatory Commission (NRC) for a combined construction and operating license (COL) for two Westinghouse AP1000 (advanced passive) reactors. Each reactor is capable of producing approximately 1,117 MW. The COL application submittal to the NRC is anticipated in late 2007 or early 2008. Submitting the COL application does not commit Duke Energy Carolinas to build nuclear units. On September 20, 2006, Duke Energy Carolinas filed an application with the NCUC for authority to recover certain expenses related to its development and evaluation of the proposed nuclear generation facility (the William States Lee III Nuclear Station). Specifically, Duke Energy Carolinas requests an NCUC order (1) finding that work performed by Duke Energy Carolinas to ensure the availability of nuclear generation by 2016 for its customers is prudent and consistent with the promotion of adequate, reliable, and economical utility service to the citizens of North Carolina and the polices expressed in North Carolina General Statute 62-2, and (2) providing expressly that Duke Energy Carolinas may recover in rates, in a timely fashion, the North Carolina allocable portion of its share of costs prudently incurred to evaluate and develop a new nuclear generation facility through December 31, 2007, whether or not a new nuclear facility is constructed. The application is pending.

Fuel Supply

U.S. Franchised Electric and Gas relies principally on coal and nuclear fuel for its generation of electric energy. The following table lists U.S. Franchised Electric and Gas’ sources of power and fuel costs for the three years ended December 31, 2005.

	Generation by Source (Percent)			Cost of Delivered Fuel per Net Kilowatt-hour Generated (Cents)
	2005	2004	2003	2005	2004	2003
Coal	52.5	52.2	50.7	2.14	1.84	1.59
Nuclear(a)	45.7	45.9	46.7	0.41	0.41	0.42
Oil and gas(b)	0.1	0.2	0.1	28.83	16.79	15.52
All fuels (cost based on weighted average)(a)	98.3	98.3	97.5	1.36	1.20	1.05
Hydroelectric(c)	1.7	1.7	2.5
	100.0	100.0	100.0

(a) Statistics related to nuclear generation and all fuels reflect U.S. Franchised Electric and Gas’ 12.5% ownership interest in the Catawba Nuclear Station.

(b) Cost statistics include amounts for light-off fuel at U.S. Franchised Electric and Gas’ coal-fired stations.

(c) Generating figures are net of output required to replenish pumped storage facilities during off-peak periods.

Coal. U.S. Franchised Electric and Gas 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. U.S. Franchised Electric and Gas has an adequate supply of coal to fuel its current operations. Expiration dates for its supply contracts, which have price adjustment provisions, range from 2006 to 2008. U.S. Franchised Electric and Gas 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 primarily produced from mines in Eastern Kentucky, Southern West Virginia and Southwestern Virginia. U.S. Franchised Electric and Gas uses spot-market purchases to meet coal requirements not met by supply contracts.

The average sulfur content of coal purchased by U.S. Franchised Electric and Gas 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.

U.S. Franchised Electric and Gas 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. U.S. Franchised Electric and Gas staggers its contracting so that its portfolio of long-term contracts covers the majority of its fuel requirements at Oconee, McGuire and

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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, U.S. Franchised Electric and Gas generally sole sources these services to a single domestic supplier on a plant-by-plant basis using multi-year contracts.

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

Nuclear Station	Uranium Material	Conversion Service	Enrichment Service	Fabrication Service
Oconee	2009	2009	2007	2011
McGuire	2009	2009	2007	2012
Catawba	2009	2009	2007	2012

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 Energy Carolinas has entered into a contract with Duke COGEMA Stone & Webster, LLC (DCS) under which Duke Energy Carolinas 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 DCS 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 Energy Carolinas 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. These four lead assemblies are currently operating in Unit 1 of the Catawba Nuclear Station. (See Note 18 to the Consolidated Financial Statements, “Guarantees and Indemnifications,” for additional information.)

Inventory

Generation of electricity is capital-intensive. U.S. Franchised Electric and Gas 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, 2005, the inventory balance for U.S. Franchised Electric and Gas was approximately $419 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 2005, the NCUC and PSCSC approved a $48 million annual amount for contributions and expense levels for decommissioning. During 2005, Duke Energy expensed approximately $48 million and contributed approximately $48 million of cash to the Nuclear Decommissioning Trust Funds (NDTF) for decommissioning costs; these amounts are presented in the Consolidated Statements of Cash Flows in Purchases of available-for-sale securities within Cash Flows from Investing Activities. The $48 million was contributed entirely to the funds reserved for contaminated costs. Contributions were discontinued to the funds reserved for non-contaminated costs since the current estimates indicate existing funds to be sufficient to cover projected future costs. The balance of the external funds was $1,504 million as of December 31, 2005 and $1,374 million as of December 31, 2004. These amounts are reflected in the Consolidated Balance Sheets as Nuclear Decommissioning Trust Funds (asset).

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 expected future 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 Energy Carolinas 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 in North Carolina and South Carolina.

U.S. Franchised Electric and Gas 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 service areas outside municipalities in North Carolina and South Carolina to regulated electric utilities and rural electric cooperatives. Substantially all of the territory comprising U.S. Franchised Electric and Gas’ service area has been assigned in this manner. In unassigned areas, U.S. Franchised Electric and Gas’ 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. U.S. Franchised Electric and Gas also competes with other utilities and marketers in the wholesale electric business. In addition, U.S. Franchised Electric and Gas 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 U.S. Franchised Electric and Gas’ cost based rates for electric sales to certain wholesale customers. (For more information on rate matters, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters—U.S. Franchised Electric and Gas.”) The FERC, the NCUC and the PSCSC also have authority over the construction and operation of U.S. Franchised Electric and Gas’ facilities. Certificates of public convenience and necessity issued by the FERC, the NCUC and the PSCSC authorize U.S. Franchised Electric and Gas 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 U.S. Franchised Electric and Gas.

The Energy Policy Act of 2005 was signed into law in August 2005. The legislation directs specified agencies to conduct a significant number of studies on various aspects of the energy industry and to implement other provisions through rulemakings. Among the key provisions, the Energy Policy Act of 2005 repeals the Public Utility Holding Company Act (PUHCA) of 1935, directs FERC to establish a self-regulating electric reliability organization governed by an independent board with FERC oversight, extends the Price Anderson Act for 20 years (until 2025), provides loan guarantees, standby support and production tax credits for new nuclear reactors, gives FERC enhanced merger approval authority, provides FERC new backstop authority for the siting of certain electric transmission projects, streamlines the processes for approval and permitting of interstate pipelines, and reforms hydropower relicensing. FERC’s enhanced

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merger authority will not apply to transactions pending with the FERC as of August 8, 2005, such as the anticipated Duke Energy and Cinergy merger, as discussed in Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions.” In late 2005 and early 2006, FERC initiated several rulemakings as directed by the Energy Policy Act of 2005. Duke Energy is currently evaluating these proposals and does not anticipate that these rulemakings will have a material adverse effect on its consolidated results of operations, cash flows or financial position.

The Energy Policy Act of 1992 and subsequent rulemakings and events initiated the opening of wholesale energy markets to competition. Open access transmission for wholesale transmission provides energy suppliers and load serving entities, including U.S. Franchised Electric and Gas and wholesale customers located in the U.S. Franchised Electric and Gas service area, with opportunities to purchase, sell and deliver capacity and energy at market based prices, which can lower overall costs to retail customers.

As a result of previous FERC rulemakings related to RTOs, Duke Energy Carolinas and the U.S. Franchised Electric and Gas 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, 2005, Duke Energy had a net investment of $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. In 2005, the companies notified the FERC that they had discontinued the GridSouth project. Management expects it will recover its investment in GridSouth.

On December 19, 2005, the FERC approved a plan filed by Duke Energy Carolinas to establish an “Independent Entity” (IE) to serve as a coordinator of certain transmission functions and an “Independent Monitor” (IM) to monitor the transparency and fairness of the operation of Duke Energy Carolinas’ transmission system. Under the proposal, Duke Energy Carolinas will remain the owner and operator of the transmission system with responsibility for the provision of transmission service under Duke Energy Carolinas’ Open Access Transmission Tariff. Duke Energy Carolinas has retained the Midwest Independent Transmission System Operator, Inc. to act as the IE and Potomac Economics, Ltd. to act as the IM. Duke Energy Carolinas intends to implement the plan by November 1, 2006. Duke Energy Carolinas is not at this time seeking adjustments to its transmission rates to reflect the incremental cost of the proposal, which is not projected to have a material adverse effect on Duke Energy’s future consolidated results of operations, cash flows or financial position.

U.S. Franchised Electric and Gas 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. All but one of U.S. Franchised Electric and Gas’ 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 issue new hydroelectric generating licenses. Hydroelectric facilities whose licenses expired in 2005 are operating under annual extensions of the current license until FERC issues a new license. Other hydroelectric facilities whose licenses expire between 2008 and 2016 are in various stages of relicensing. Duke Energy expects to receive new licenses for all hydroelectric facilities.

U.S. Franchised Electric and Gas 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.)

NATURAL GAS TRANSMISSION

Natural Gas Transmission provides transportation and storage of natural gas for customers in the Eastern and Southeastern U.S. and in Ontario and British Columbia in Canada. Natural Gas Transmission also provides natural gas sales and distribution service to retail customers in Ontario, and natural gas gathering and processing services to customers in Western Canada and other energy related services. Natural Gas Transmission does business primarily through DEGT.

For 2005, Natural Gas Transmission’s proportional throughput for its pipelines totaled 3,410 trillion British thermal units (TBtu), compared to 3,332 TBtu in 2004. 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, and both firm and interruptible transportation services are provided to various customers on a short-term or seasonal basis. In the course of providing transportation services, Natural Gas Transmission also processes natural gas on its U.S. system. 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”.)

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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 Transmission, L.P. (Texas Eastern) and East Tennessee Natural Gas, LLC (ETNG), subsidiaries of Natural Gas Transmission, 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. ETNG also connects to Saltville Gas Storage Company and Virginia Gas Storage Company, subsidiaries of Natural Gas Transmission. These natural gas storage fields are located in the state of Virginia.

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 BC Pipeline owns and operates processing plants in Western Canada that provide services primarily to natural gas producers to remove impurities from the raw gas stream including water, carbon dioxide, hydrogen sulphide and other substances. Where required, the facilities remove various NGLs. Natural Gas Transmission’s Empress Midstream assets, acquired in August 2005 from ConocoPhillips, are located in Western Canada and provide extraction, storage, transportation, distribution and marketing of NGLs in Canada and the U.S.

As discussed further under the Field Services description of the DEFS disposition transactions, the Canadian Midstream business was transferred from Field Services to Natural Gas Transmission in July 2005. These operations are located in Western Canada and provide gathering and processing services. In December 2005, Duke Energy reduced its ownership percentage in these operations as a result of the creation of a Canadian income trust fund, the Duke Energy Income Fund (Income Fund), which sold approximately 40% ownership to the public through a Canadian initial public offering (IPO) for proceeds, net of underwriting discount, of approximately $110 million. In January 2006, a subsequent greenshoe sale of additional ownership interests, pursuant to an overallotment option, in the Income Fund were sold for approximately $10 million. Duke Energy retains an approximate 58% ownership interest in the Income Fund and will continue to operate and manage this business.

Competition

Natural Gas Transmission’s transportation, storage and gas gathering and processing businesses compete with similar 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, 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. Several factors influence the demand for natural gas including price changes, the availability of natural gas and

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other forms of energy, the level of business activity, conservation, legislation, governmental regulations, the ability to convert to alternative fuels, weather and other factors.

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 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. (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 oversight by state regulatory commissions.

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 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 and local environmental agencies. (For a discussion of environmental regulation, see “Environmental Matters” in this section.) Natural Gas Transmission’s interstate natural gas pipelines are also subject to the regulations of the DOT concerning pipeline safety.

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. However, Natural Gas Transmission’s field services business operates under a light-handed regulatory model where rates are commercially negotiated. The Midstream and Empress NGL businesses are not under any form of rate regulation.

The Energy Policy Act of 2005 was signed into law in August 2005. See discussion above under “Franchised Electric—Regulation” for details on the impacts of the Energy Policy Act of 2005.

FIELD SERVICES

Field Services includes Duke Energy’s investment in DEFS, which gathers, compresses, treats, processes, transports, trades and markets, and stores natural gas; and fractionates, transports, trades and markets and stores NGLs. In July 2005, Duke Energy completed the disposition of its 19.7% interest in DEFS, which resulted in Duke Energy and ConocoPhillips becoming equal 50% owners in DEFS. The DEFS disposition transaction included the transfer to Duke Energy of DEFS’ Canadian Midstream business. Additionally, the disposition transaction included the acquisition of ConocoPhillips’ interest in the Empress System. Subsequent to the closing of the DEFS disposition transaction, effective on July 1, 2005, DEFS was no longer consolidated into Duke Energy’s consolidated financial statements and is accounted for by Duke Energy as an equity method investment. The Canadian Midstream business, which is owned by Natural Gas Transmission’s BC Pipeline, and the Empress System have been transferred to the Natural Gas Transmission segment. Additionally, in February 2005, DEFS sold its wholly-owned subsidiary, TEPPCO, the general partner of TEPPCO Partners L.P., and Duke Energy sold its limited partner interest in TEPPCO Partners, L.P., in each case to EPCO, an unrelated third party.

In 2005, DEFS formed DCP Midstream Partners, LP (a master limited partnership). DCP Midstream Partners, LP (DCPLP) completed an IPO transaction in December. As a result, DEFS has a 42 percent ownership interest in DCPLP, consisting of a 40 percent limited partner ownership interest and a 2 percent general partner ownership interest. DEFS owns 100 percent of the general partner of DCPLP.

DEFS’ operates in sixteen states in the United States (Alabama, Arkansas, Colorado, Kansas, Louisiana, Maine, Massachusetts, Mississippi, New Mexico, New York, Oklahoma, Pennsylvania, Texas, Rhode Island, Vermont and Wyoming). DEFS’ gathering systems include connections to several interstate and intrastate natural gas and NGL pipeline systems and one natural gas storage facility. DEFS gathers raw natural gas through gathering systems located in seven major natural gas producing regions: Permian Basin, Mid-Continent, ArklaTex, Gulf Coast, South, Central and Rocky Mountains. DEFS owns or operates approximately 56,000 miles of gathering and transmission pipe, with approximately 34,000 active receipt points.

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DEFS’ 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. DEFS processes the raw natural gas at 54 natural gas processing facilities.

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, butane and natural gasoline) and then sold as components. DEFS fractionates NGL raw mix at eight processing facilities that it owns and operates and at four third-party-operated facilities in which it has an ownership interest. In addition, DEFS operates a propane wholesale marketing business. DEFS sells NGLs to a variety of customers ranging from large, multi-national 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. DEFS markets residue gas directly or through its wholly owned gas marketing company and its affiliates. DEFS also stores residue gas at its 9 billion-cubic-foot (Bcf) natural gas storage facility.

DEFS 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. DEFS 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. DEFS believes there are additional opportunities to grow its services with its customer base.

The following map includes DEFS’ natural gas gathering systems, intrastate pipelines, regional offices and supply areas.

DEFS’ operating results are significantly impacted by changes in average NGL prices, which increased approximately 25% in 2005 compared to 2004. DEFS 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 DEFS’ exposure to changes in commodity prices.)

Competition

In gathering and processing natural gas and in marketing and transporting natural gas and NGLs, DEFS 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/

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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.

Regulation

The intrastate natural gas and NGL pipelines owned by DEFS 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 DEFS is subject to FERC regulation, but its natural gas gathering and processing activities are not subject to FERC regulation.

DEFS is subject to the jurisdiction of the EPA and state and local environmental agencies. (For more information, see “Environmental Matters” in this section.) DEFS’ natural gas transmission pipelines and some gathering pipelines are also subject to the regulations of the DOT, and in some cases, state agencies, concerning pipeline safety.

COMMERCIAL POWER

Commercial Power (formerly a portion of DENA) operates and manages power plants and markets electric power and natural gas related to these plants and other contractual positions.

Commercial Power’s operations consist primarily of five Midwestern generating plants, representing a mix of combined cycle and peaking plants consisting of approximately 3,600 megawatts of power generation, and certain contracts related to the Midwestern generating facilities, and eight natural gas-fired merchant power plants in the Southeastern United States and certain other power and gas contracts, which were formerly a portion of DENA and were substantially disposed of in 2004.

The following map shows Commercial Power’s power generation facilities.

Competition

The price of commodities and services, along with the quality and reliability of services provided, drive competition in the energy marketing business. Commercial Power’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.

Regulation

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 Commercial Power’s marketing and generation activities.

Commercial Power 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.)

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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 NMC, 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’s current strategy is focused on optimizing the value of its current Latin American Portfolio.

International Energy owns, operates or has substantial interests in approximately 3,937 net MW of generation facilities. The following map shows the locations of International Energy’s facilities, including non-generation facilities in Mexico and Saudi Arabia.

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, LDCs 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, 2005, Crescent owned 0.4 million square feet of commercial, industrial and retail space, with an additional 1.5 million square feet under construction. This portfolio included 0.9 million square feet of office space, 0.7 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 developments sold to national builders. Crescent had three multi-family communities at December 31, 2005, including one operating property and two properties under development. As of December 31, 2005, Crescent also managed approximately 131,000 acres of land.

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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

The remainder of Duke Energy’s operations is presented as “Other.” While it is not considered a business segment, Other primarily includes the operations discussed below.

Other includes the remaining portion of Duke Energy’s business formerly known as DENA, including 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. During the third quarter of 2005, Duke Energy’s Board of Directors authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. Management retained DENA’s Midwestern generation assets (which are included in the Commercial Power segment), consisting of approximately 3,600 megawatts of power generation, and certain contracts related to the Midwestern generating facilities, as the merger with Cinergy provided a sustainable business model for those assets. The exit plan was completed in the second quarter of 2006. In addition, management will continue to wind down the limited remaining operations of DETM. The DENA assets that were divested include:

• Approximately 6,100 megawatts of power generation located primarily in the Western and Eastern United States, including all of the commodity contracts (primarily forward gas and power contracts) related to these facilities,

• All remaining commodity contracts related to DENA’s Southeastern generation operations, which were substantially disposed of in 2004, and certain commodity contracts related to DENA’s Midwestern power generation facilities, and

• Contracts related to DENA’s energy marketing and management activities, which include gas storage and transportation, structured power and other contracts.

During the fourth quarter of 2005, Duke Energy reached an agreement to sell to Barclays Bank PLC (Barclays) substantially all of its power and financial gas contracts, excluding commodity contracts associated with the near-term value of DENA’s West and Northeastern generation assets and remaining gas transportation and structured power contracts related to the Southeastern generation operations, which were substantially disposed of in 2004, certain commodity contracts related to DENA’s Midwestern power generation facilities, and certain contracts related to DENA’s energy marketing and management activities. In addition, the Ft. Frances generation facility was sold to a third party during the fourth quarter of 2005 for proceeds which approximate the carrying value of the sold assets.

In January 2006, Duke Energy announced the sale of its remaining fleet of power generation assets outside the Midwest to a subsidiary of LS Power Equity Partners (LS Power). This transaction closed in the second quarter of 2006. See Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held For Sale,” and Note 24 to the Consolidated Financial Statements, “Subsequent Events,” for additional information.

The results of operations of DENA’s Western and Eastern United States generation assets, including related commodity contracts, the divested Ft. Frances generation assets, contracts related to DENA’s energy marketing and management activities and certain general and administrative costs, are required to be presented as discontinued operations classification for current and prior periods in the accompanying Consolidated Statements of Operations. In addition, the results for DETM will continue to be reported in continuing operations until the wind down of these operations is complete.

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The following map shows DENA’s power generation facilities, which are included in Other and were sold to LS Power in May 2006.

During 2005, Other also included certain unallocated corporate costs, DukeNet, DEM, Duke Energy’s 50% interest in D/FD, and Bison. As of December 31, 2005, Duke Energy had exited the merchant finance business at Duke Capital Partners LLC (DCP), and all of the results of operations for DCP for the years ended December 31, 2005, 2004 and 2003 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.

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, 2005, DEM has exited the majority of its business. DEM previously engaged 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).

D/FD is a 50/50 partnership between subsidiaries of Duke Energy and Fluor Corporation. During 2003, Duke Energy and Fluor announced that they would dissolve D/FD, and adopted a plan for an orderly wind-down of D/FD’s business. The wind-down has been substantially completed as of December 31, 2005, and is expected to be finalized by December 2006. Previously, D/FD provided comprehensive engineering, procurement, construction, commissioning and operating plant services for fossil-fueled electric power generating facilities worldwide.

Bison’s principal 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:

• The Clean Air Act, as well as state laws and regulations impacting air emissions, including State Implementation Plans related to existing and new national ambient air quality standards for ozone and particulate matter. Owners and/or operators of air emission sources are responsible for obtaining permits and for annual compliance and reporting.

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• The Clean Water Act which requires permits for facilities that discharge wastewaters into the environment.

• The Comprehensive Environmental Response, Compensation and Liability Act, which can require any individual or entity that currently owns or in the past may have owned or operated a disposal site, as well as transporters or generators of hazardous substances sent to a disposal site, to share in remediation costs.

• The Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act, which requires certain solid wastes, including hazardous wastes, to be managed pursuant to a comprehensive regulatory regime.

• The National Environmental Policy Act, which requires federal agencies to consider potential environmental impacts in their decisions, including siting approvals.

• The North Carolina clean air legislation that freezes electric utility rates from June 20, 2002 to December 31, 2007 (rate freeze period), subject to certain conditions, in order for North Carolina electric utilities, including Duke Energy, to significantly reduce emissions of sulfur dioxide (SO₂) and nitrogen oxides (NOx) from coal-fired power plants in the state. The legislation allows electric utilities, including Duke Energy, to accelerate the recovery of compliance costs by amortizing them over seven years (2003-2009). Based upon current estimates on file with the NCUC, Franchised Electric estimates total cost of complying with the clean air legislation to be approximately $1.7 billion.

(For more information on environmental matters involving Duke Energy, including possible liability and capital costs, see Notes 4 and 17 to the Consolidated Financial Statements, “Regulatory Matters,” and “Commitments and Contingencies—Environmental,” respectively.)

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 incorporated into the routine cost structure of our various business units and 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,” respectively.

EMPLOYEES

On December 31, 2005, Duke Energy had approximately 20,400 employees. A total of 3,236 operating and maintenance employees were represented by unions. This amount consists of the following:

• 1,391 employees represented by the International Brotherhood of Electrical Workers

• 1,035 employees represented by the Communications, Energy and Paperworkers of Canada

• 211 employees represented by the Canadian Pipeline Employees Association

• 210 employees represented by the United Steelworkers of America

• 85 employees represented by Sindicato dos Trabalhadores na Industria da Energia Hidroeletrica de Ipaussu

• 79 employees represented by Sindicato de Trabajadores del Sector Electrico

• 61 employees represented by the International Union of Operating Engineers

• 38 employees represented by Sindicato Unico de Centrales de Generacion Electrica—Canon del Pato

• 30 employees represented by Sindicato dos Trabalhadores na Industria de Energia Eletrica de Campinas

• 29 employees represented by Asociacion del Personal Jerarquico del Agua y la Energia

• 17 employees represented by Sindicato Corani

• 15 employees represented by Sindicato Unico de Generacion Electrica—Carhuaquero

• 14 employees represented by Federacion Argentina de Trabajadores de Luz y Fuerza

• 13 employees represented by Utility Workers Union of America

• 6 employees represented by Sindicato dos Trabalhadores nas Industrias de Energia Eletrica de Sao Paulo

• 2 employees represented by the United Association of Journeymen and Apprentices of the Plumbing and Pipe Fitting Industries of the U.S. and Canada

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EXECUTIVE OFFICERS OF DUKE ENERGY

PAUL M. ANDERSON, 60, 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).

FRED J. FOWLER, 60, 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, 54, 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 Energy Carolinas before being named Senior Vice President, Global Asset Development in 1997.

JIM W. MOGG, 57, 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, 51, Group Vice President, Duke Energy Business Services 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, 50, Group Vice President, Corporate Strategy (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, 55, 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, 58, President and Chief Executive Officer, Duke Energy Carolinas. 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, 46, Group Vice President, General Counsel and Secretary. 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.

STEVEN K. YOUNG, 47, Vice President and Controller. Mr. Young assumed his current position in June 2005. Mr. Young previously served as Senior Vice President and Chief Financial Officer for Duke Energy Carolinas and as Duke Energy Carolinas’s Vice President of Rates and Regulatory Affairs.

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.

U.S. FRANCHISED ELECTRIC AND GAS

As of December 31, 2005, U.S. Franchised Electric and Gas 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 3,169 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.

Name	Gross MW	Net MW	Fuel	Location	Ownership Interest (percentage)
Oconee	2,538	2,538	Nuclear	SC	100	%
Catawba	2,258	282	Nuclear	SC	12.5
Belews Creek	2,270	2,270	Coal	NC	100
McGuire	2,200	2,200	Nuclear	NC	100
Marshall	2,110	2,110	Coal	NC	100
Lincoln CT	1,267	1,267	Natural gas/Fuel Oil	NC	100
Allen	1,145	1,145	Coal	NC	100
Bad Creek	1,360	1,360	Hydro	SC	100
Cliffside	760	760	Coal	NC	100
Jocassee	680	680	Hydro	SC	100
Riverbend	454	454	Coal	NC	100
Lee	370	370	Coal	SC	100
Buck	369	369	Coal	NC	100
Cowans Ford	325	325	Hydro	NC	100
Mill Creek CT	596	596	Natural gas/Fuel Oil	SC	100
Dan River	276	276	Coal	NC	100
Buzzard Roost CT	196	196	Natural gas/Fuel Oil	SC	100
Keowee	152	152	Hydro	SC	100
Riverbend CT	120	120	Natural gas/Fuel Oil	NC	100
Buck CT	93	93	Natural gas/Fuel Oil	NC	100
Lee CT	90	90	Natural gas/Fuel Oil	SC	100
Dan River CT	85	85	Natural gas/Fuel Oil	NC	100
Other small hydro (27 plants)	652	652	Hydro	NC/SC	100
Total	20,366	18,390

In addition, as of December 31, 2005, U.S. Franchised Electric and Gas owned approximately 13,200 conductor miles of electric transmission lines, including 600 miles of 525 kilovolts, 2,700 miles of 230 kilovolts, 6,700 miles of 100 to 161 kilovolts, and 3,200 miles of 13 to 66 kilovolts. Franchised Electric also owned approximately 96,000 conductor miles of electric distribution lines, including 48,300 miles of rural overhead lines, 17,800 miles of urban overhead lines, 17,400 miles of rural underground lines and 12,500 miles of urban underground lines. As of December 31, 2005, the electric transmission and distribution systems had approximately 1,600 substations.

Substantially all of U.S. Franchised Electric and Gas’ 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 U.S. Franchised Electric and Gas’ properties, see “Business—U.S. Franchised Electric and Gas” 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 and has an ownership interest in a processing plant in Southern Louisiana.

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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 connects with Texas Eastern’s facilities in New Jersey, and extends approximately 250 miles through New Jersey, New York, Connecticut, Rhode Island and Massachusetts where it connects to Maritimes & Northeast Pipeline. The system consists of approximately 1,100 miles of pipeline with six compressor stations.

ETNG’s transmission system crosses Texas Eastern’s system at two points in Tennessee and consists of two mainline systems totaling approximately 1,400 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. East Tennessee also connects to Saltville Gas Storage Company and Virginia Gas Storage Company. These natural gas storage fields are located in the state of Virginia and have a working gas capacity of approximately 5 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.

The Empress system is a collection of midstream assets involved in the extraction, storage, transportation, distribution and marketing of NGLs in Canada and the U.S. Assets include, among other things, an ownership interest in an NGL extraction plant on the TransCanada Alberta system, a liquids transmission pipeline, seven terminals along the pipe, two storage facilities, a fractionation facility, and an integrated NGL marketing and gas supply business. Total processing capacity of the Empress system is 2.4 Bcf of gas per day. The Empress system is located in Western Canada.

The DEGT Midstream operations are located in Western Canada and include nine natural gas processing plants and over 870 miles of natural gas gathering pipelines located in Western Canada.

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 a 50 percent investment in Gulfstream Natural Gas System, LLC (Gulfstream), a 691-mile interstate natural gas pipeline system owned and operated jointly by Duke Energy and The Williams Company, Inc.

(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.)

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COMMERCIAL POWER

The following table provides information about Commercial Power’s generation portfolio as of December 31, 2005.

Name	Gross MW	Net MW	Plant Type	Primary Fuel	Location	Approximate Ownership Interest (percentage)
Hanging Rock	1,240	1,240	Combined Cycle	Natural Gas	OH	100
Lee	640	640	Simple Cycle	Natural Gas	IL	100
Vermillion	640	480	Simple Cycle	Natural Gas	IN	75
Fayette	620	620	Combined Cycle	Natural Gas	PA	100
Washington	620	620	Combined Cycle	Natural Gas	OH	100
Total	3,760	3,600

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

INTERNATIONAL ENERGY

The following table provides information about International Energy’s generation portfolio in continuing operations as of December 31, 2005.

Name	Gross MW	Net MW	Fuel	Location	Approximate Ownership Interest (percentage)
Paranapanema	2,307	2,111	Hydro	Brazil	95	%
Hidroelectrica Cerros Colorados	576	523	Hydro/Natural Gas	Argentina	91
Egenor	509	508	Hydro/Diesel/Oil	Peru	100
DEI Guatemala	250	250	Orimulsion/Oil/Diesel	Guatemala	100
DEI El Salvador	291	263	Oil/Diesel	El Salvador	90
Electroquil	181	144	Diesel	Ecuador	80
Aguaytia	169	64	Natural Gas	Peru	38
Empressa Electrica Corani	147	74	Hydro	Bolivia	50
Total	4,430	3,937

International Energy also owns a 25% equity interest in NMC, located in Saudi Arabia, which is a leading producer of methanol and MTBE. In 2005, the NMC produced approximately 960 thousand metric tons of methanol and one million metric tons of MTBE. In addition, International Energy 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.)

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OTHER

As discussed in the Business—Other section above, during the third quarter of 2005, Duke Energy’s Board of Directors authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets outside the Midwestern United States. As a result of this exit plan, the results of operations of DENA’s Western and Eastern United States generation assets, including related commodity contracts, are accounted for as discontinued operations for current and prior periods in the accompanying Consolidated Statements of Operations. The following table provides information about those assets included in discontinued operations as of December 31, 2005.

Name	Gross MW	Net MW	Plant Type	Primary Fuel	Location	Approximate Ownership Interest (percentage)
Moss Landing	2,538	2,538	Combined Cycle and Conventional Steam	Natural Gas	CA	100
Morro Bay	1,002	1,002	Combined Cycle	Natural Gas	CA	100
South Bay	700	700	Conventional Steam	Natural Gas	CA	100
Griffith Energy	600	300	Combined Cycle	Natural Gas	AZ	50
Arlington Valley	570	570	Combined Cycle	Natural Gas	AZ	100
Maine Independence	520	520	Combined Cycle	Natural Gas	ME	100
Bridgeport	490	326	Combined Cycle	Natural Gas	CT	67	(a)
Oakland	165	165	Simple Cycle	Oil	CA	100
Total	6,585	6,121

(a) Duke Energy and United Bridgeport Energy LLC (UBE) have finalized a settlement for the purchase price of UBE’s ownership interest in Bridgeport. Upon closing of this transaction, Duke Energy will own 100% of Bridgeport.

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

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

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 and Notes for the years ended December 31, 2005, 2004 and 2003.

In conjunction with Duke Energy’s merger with Cinergy (see Note 24 to the Consolidated Financial Statements, “Subsequent Events”), Duke Energy adopted new business segments, effective with the second quarter of 2006 (see Note 3 to the Consolidated Financial Statements, “Business Segments”).

EXECUTIVE OVERVIEW

During 2005, Duke Energy delivered on its financial plan with reported earnings available to common stockholders of $1,812 million and basic and diluted earnings per share (EPS) of $1.94 and $1.88, respectively.

• U. S. Franchised Electric and Gas delivered strong results in 2005 primarily due to warmer weather experienced in North Carolina and South Carolina and to bulk power marketing results;

• Natural Gas Transmission’s earnings grew during 2005 as a result of U.S. pipeline expansion projects and favorable foreign exchange rate impacts from the strengthening Canadian currency;

• Field Services benefited from strong commodity prices and operational improvements in 2005, offset by the reduction in ownership percentage by Duke Energy as a result of the DEFS disposition transaction discussed below;

• International Energy had solid results in 2005 due to favorable hydrological conditions and foreign exchange rate impacts in Latin America as well as increased equity earnings from its investment in NMC;

• Crescent had another outstanding year in 2005 with strong commercial, residential and multifamily real estate transactions and continues to reinvest in the real estate market, as opportunities arise; and

• As a result of the announced exit plan of DENA, discontinued operations recorded pre-tax losses of approximately $1.1 billion related to the wind-down of the business outside the Midwest region.

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Consistent with its portfolio management strategy, during 2005 Duke Energy finalized a transaction with ConocoPhillips, Duke Energy’s co-equity owner in DEFS, to reduce Duke Energy’s ownership interest in DEFS from 69.7% to 50%, which resulted in Duke Energy and ConocoPhillips becoming equal 50% owners in DEFS. As a result, Duke Energy recognized a pre-tax gain of approximately $575 million while receiving direct and indirect cash and assets from ConocoPhillips as consideration. Additionally, in February 2005, DEFS sold its wholly owned subsidiary TEPPCO GP, which was the general partner of TEPPCO LP, and Duke Energy sold its limited partner interest in TEPPCO LP, which resulted in Duke Energy recognizing pre-tax gains of approximately $0.9 billion (net of minority interest of approximately $0.3 billion). These transactions provided liquidity to Duke Energy to facilitate the accelerated share repurchase program discussed below and allowed Natural Gas Transmission to increase the scope, scale and diversity of its Canadian operations.

In connection with its effort to establish industry-leading positions in core businesses, in May 2005, Duke Energy and Cinergy announced they entered into a definitive merger agreement. The merger agreement has been unanimously approved by both companies’ Boards of Directors. Closing of the transaction occurred in April 2006. The merger combined the Duke Energy and Cinergy regulated franchises as well as deregulated generation in the Midwestern United States. Additionally, the merger is anticipated to provide more regulatory, geographic and weather diversity to Duke Energy’s earnings.

A key goal for 2005 was to position DENA to be a successful merchant operator with a sustainable business model. However, management determined that its objective of break-even earnings for DENA by 2006 was no longer realistic without taking on additional risk. As a result, during the third quarter of 2005, Duke Energy’s Board of Directors authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets, resulting in pre-tax charges of approximately $1.3 billion in the third quarter of 2005. Management intends to retain DENA’s Midwestern generation assets, consisting of approximately 3,600 megawatts of power generation, and certain contracts related to the Midwestern generating facilities, as the anticipated merger with Cinergy provides a sustainable business model for those assets. Duke Energy has made substantial progress in completing the exit plan, transferring substantially all of DENA’s portfolio of derivative contracts to Barclays and agreeing to sell DENA’s remaining fleet of power generation assets outside the Midwest to LS Power for approximately $1.5 billion. The LS Power transaction resulted in a pre-tax gain of approximately $380 million in the fourth quarter of 2005, reducing the charge recognized in the third quarter of 2005. This sale of the assets to LS Power was completed in May 2006.

In February 2005, Duke Energy announced plans to execute up to approximately $2.5 billion in common stock repurchases over the next three years. In connection with these plans, in March 2005, Duke Energy entered into an accelerated share repurchase transaction whereby Duke Energy repurchased and retired 30 million shares of its common stock. Duke Energy also entered into a separate open market purchase plan in March 2005 to repurchase up to an additional 20 million shares of its common stock through December 27, 2005. As of May 2005, Duke Energy had repurchased approximately 2.6 million shares of its common stock pursuant to this plan. In May 2005, in connection with the anticipated merger with Cinergy, Duke Energy announced plans to suspend additional repurchases under the open market purchase plan, pending further assessment. Such suspension shall continue at least until the shareholder vote on the Cinergy merger is completed. Duke Energy may conduct further common stock repurchases before or after the closing of the merger with Cinergy. For the year ended December 31, 2005, a total of 32.6 million shares were repurchased under both share repurchase plans for approximately $933 million.

In September and December 2005, Duke Energy paid a quarterly cash dividend on its common stock of $0.31 per share, an increase of $0.035 cents per share above its previous level.

Management has established the following objectives for Duke Energy in 2006:

• Establish an industry-leading electric power platform through successful execution of the merger with Cinergy

• Deliver on the 2006 financial objectives and position Duke Energy for growth in 2007 and beyond

• Complete the DENA exit and pursue strategic portfolio opportunities

• Build a high-performance culture focused on safety, diversity and inclusion, employee development, leadership and results, and

• Build credibility through leadership on key policy issues, transparent communications and excellent customer service.

Economic Factors for Duke Energy’s Business. Duke Energy’s business model provides diversification between stable, less cyclical businesses like U. S. Franchised Electric and Gas and Natural Gas Transmission, and the traditionally higher-growth and more cyclical energy businesses like International Energy and Field Services. Additionally, 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 prices of commodities, all of which are beyond Duke Energy’s control, and could impair Duke Energy’s ability to meet its goals for 2006 and beyond.

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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 U. S. Franchised Electric and Gas’s business risk is mitigated by its regulated allowable rates of return and recovery of fuel costs under fuel adjustment clauses. A significant portion of Natural Gas Transmission’s revenues are based on regulated tariff rates, which include the recovery of certain fuel costs. However, lower economic output would 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 Natural Gas Transmission’s distribution company, resulting in lower earnings and cash flows. For Natural Gas Transmission, this decline would primarily affect the distribution revenues in the short-term. Transmission revenues could be impacted by long-term economic declines that could result in the turnback of long-term contracts. Natural Gas Transmission’s customers continue to renew most contracts as they expire.

If negative market conditions should 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. 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 2006 goals 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. 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.

Duke Energy’s earnings are impacted by fluctuations in commodity prices. Exposure to commodity prices generates higher earnings volatility in the unregulated businesses as no mechanism exists to recover those costs in rates. To mitigate these risks, Duke Energy has typically entered into derivative instruments to effectively hedge known exposures. The upcoming sale of DENA’s assets outside the Midwestern United States, including substantially all the derivative portfolio, should result in a less volatile earnings pattern for Duke Energy going forward.

Additionally, Duke Energy’s investments and projects located outside of the United States expose Duke Energy 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 limits its non-U.S. operations to primarily 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 cash flow from operations. An inability to access capital at competitive rates could adversely affect Duke Energy’s ability to implement its strategy. 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.

For further information related to management’s assessment of Duke Energy’s risk factors, see Item 1A. “Risk Factors.”

RESULTS OF OPERATIONS

Consolidated Operating Revenues

Year Ended December 31, 2005 as Compared to December 31, 2004. Consolidated operating revenues for 2005 decreased $3.8 billion, compared to 2004. This change was driven by:

• A $5.4 billion decrease due to the deconsolidation of DEFS, effective July 1, 2005

• A $465 million decrease in revenue as a result of the continued wind-down of DEM, and

• An approximate $130 million decrease resulting from mark-to-market losses, primarily unrealized, due to increased commodity prices as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk (see Note 8 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments”) from February 22, 2005 to June 30, 2005. Effective with the deconsolidation of DEFS on July 1, 2005, mark-to-market changes related to these discontinued hedges are classified in Other income and expenses, net on the Consolidated Statements of Operations

Partially offsetting these decreases in revenues were:

• An approximate $850 million increase at Field Services, excluding the impact of those hedges which were discontinued as cash flow hedges and the impact of the deconsolidation of DEFS, due primarily to higher average commodity prices, primarily NGL and natural gas in the first six months of 2005

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• A $704 million increase at Natural Gas Transmission due primarily to new Canadian assets, primarily the Empress System, favorable foreign exchange rates as a result of the strengthening Canadian dollar (partially offset by currency impacts to expenses), higher natural gas prices that are passed through to customers, an increase related to U.S. business operations driven by higher rates and contracted volumes and increased gas distribution revenues, resulting from higher gas usage in the power market

• A $363 million increase at U. S. Franchised Electric and Gas due primarily to increased sales to retail and wholesale customers as a result of warmer weather, more efficient performance of the generation fleet, and customer growth, coupled with an increase in fuel rates primarily as a result of higher coal costs in 2005 and increased market prices for wholesale power

• An $126 million increase at International Energy due primarily to favorable foreign exchange rate changes in Brazil, and higher energy prices and volumes, and

• A $58 million increase at Crescent due primarily to higher residential developed lot sales.

Year Ended December 31, 2004 as Compared to December 31, 2003. Consolidated operating revenues for 2004 increased $2.5 billion, compared to 2003. This change was driven by:

• A $2.1 billion increase in Non-regulated Electric, Natural Gas, Natural Gas Liquids, and Other revenues due to higher average NGL and natural gas prices at Field Services, partially offset by the continued wind-down of DETM and DEM

• A $190 million increase in Regulated Electric revenues, due primarily to increased fuel rates charged to retail customers as a result of increased coal costs and increased sales resulting from favorable weather at U. S. Franchised Electric and Gas. The increase was also attributable to the continued growth in the number of U. S. Franchised Electric and Gas residential and general service customers, and

• A $194 million increase in Regulated Natural Gas revenues, due primarily to the strengthening Canadian dollar at Natural Gas Transmission.

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

Consolidated Operating Expenses

Year Ended December 31, 2005 as Compared to December 31, 2004. Consolidated operating expenses for 2005 decreased $3.5 billion, compared to 2004. The change was primarily driven by:

• A $5.1 billion decrease due to the deconsolidation of DEFS, effective July 1, 2005

• A $455 million decrease due to the continued wind-down of DEM, and

• An approximate $100 million decrease in operating expenses at Commercial Power, mainly resulting from the sale of the Southeast Plants

Partially offsetting these decreases in expenses were:

• An approximate $675 million increase in operating expenses at Field Services driven primarily by higher average NGL and natural gas prices in the first six months of 2005

• A $640 million increase at Natural Gas Transmission due primarily to new Canadian assets, primarily gas purchase costs associated with the Empress System, increased natural gas prices at Union Gas (offset in revenues), foreign exchange impacts as discussed above (offset by currency impacts to revenues), and increased gas purchases for distribution primarily due to higher gas usage in the power market

• A $346 million increase in operating expenses at U. S. Franchised Electric and Gas due primarily to increased fuel expenses, driven by higher coal costs and increased generation to meet customer demand, and increased operating and maintenance expenses due primarily to increased planned outage and maintenance at generating plants, planned maintenance to improve reliability of distribution and transmission equipment, and higher storm charges in 2005 driven primarily by an ice storm in December 2005

• An approximate $120 million increase related to the recognition of unrealized losses in accumulated other comprehensive income (AOCI) as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, which were previously accounted for as cash flow hedges (see Note 8 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments”)

• An approximate $75 million charge to increase liabilities associated with mutual insurance companies

• A $74 million increase at International Energy due primarily to higher fuel prices, increased fuel volumes purchased, higher maintenance costs and the impact of foreign exchange rate changes in Brazil, offset by decreased power purchase obligations in Brazil, and

• A $64 million increase as a result of the 2004 correction of an immaterial accounting error in prior periods related to reserves at Bison.

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Year Ended December 31, 2004 as Compared to December 31, 2003. Consolidated operating expenses for 2004 increased $289 million, compared to 2003. The change was primarily driven by:

• A $1,677 million increase in Natural Gas and Petroleum Products Purchased due primarily to higher average NGL and natural gas prices at Field Services

• A $111 million increase in Fuel Used in Electric Generation and Purchased Power, primarily due to increased coal costs and increased sales at U. S. Franchised Electric and Gas

Partially offsetting this increase in expenses was:

• A $1,155 million decrease in Impairments and Other Charges due primarily to charges of $1,106 in 2003 resulting from strategic actions taken at Commercial Power which led to the recording of impairments primarily related to the Southeast Plants, charges of $113 million in Other primarily related to a $60 million charge on the sale of Bayside and a $51 million charge in Other related to the abandonment of a corporate risk management information system, offset by $64 million of impairments in 2004 at Field Services and Crescent

• A $179 million decrease in operating expenses due primarily to severance costs accrued in Other in 2003 related to workforce reductions, decreased operating expenses at Other resulting from cost reduction efforts and decreased operating expenses at Commercial Power due to the sale of plants in 2004, partially offset by increased costs at Crescent related to increased residential developed lot sales, and

• A $254 million decrease due to the 2003 write off of goodwill, most of which related to DETM’s trading and marketing business, which is recorded in Other.

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

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 $191 million in 2005, $192 million in 2004, and $84 million in 2003. The gain in 2005 was driven primarily by pre-tax gains from the sales of surplus legacy land, particularly a large sale in Lancaster, South Carolina, commercial land sales, including a large sale near Washington, D.C. and multi-family project sales in North Carolina and Florida. The gain in 2004 was driven primarily by pre-tax gains from commercial land and project sales in the Washington D.C. area and pre-tax gains from the sales of surplus legacy land. The gain in 2003 was driven primarily by pre-tax gains from the sales of surplus legacy land and pre-tax gains from commercial land and project sales, including the initial sales of land at the Potomac Yards project in the Washington D.C. area.

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

Consolidated gains (losses) on sales of other assets, net was a gain of $534 million for 2005, a loss of $404 million for 2004, and a loss of $199 million for 2003. The gain in 2005 was due primarily to the pre-tax gain resulting from the DEFS disposition transaction (approximately $575 million), partially offset by net pre-tax losses at Commercial Power, principally the termination of DENA structured power contracts in the Southeast region (approximately $75 million). The loss in 2004 was due primarily to pre-tax losses on the sale of the Southeast Plants (approximately $360 million) at Commercial Power, and the termination and sale of DETM contracts ($65 million) in Other. The loss for 2003 was 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) at Commercial Power, and stored turbines and related equipment ($66 million) in Other.

Consolidated Operating Income

Year Ended December 31, 2005 as Compared to December 31, 2004. For 2005, consolidated operating income increased $655 million, compared to 2004. Increased operating income was due primarily to the gain resulting from the DEFS disposition transaction, the charge in 2004 associated with the sale of the Southeast Plants, increased income from DEFS resulting from higher commodity prices, lower operating expenses at Commercial Power, mainly resulting from the sale of the Southeast Plants, favorable results at Natural Gas Transmission driven by higher earnings from business operations and expansion projects in the U.S. and favorable foreign exchange rate from the strengthening Canadian currency, favorable results at International Energy driven primarily by higher volumes and prices and favorable foreign exchange rate changes, and increased income at Crescent resulting from an increase in residential developed lot sales, partially offset by a net decrease to operating income due to the deconsolidation of DEFS, charges in 2005 related to the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, charges in 2005 related to the termination of structured power contracts in the Southeast region and increased liabilities associated with mutual insurance companies.

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Year Ended December 31, 2004 as Compared to December 31, 2003. For 2004, consolidated operating income increased $2,142 million, compared to 2003. Increased operating income was driven primarily by increased operating income at Commercial Power and Other, as a result of impairments and other related charges in 2003.

Other drivers to operating income are discussed above. For more detailed discussions, see the segment discussions that follow.

Consolidated Other Income and Expenses

Year Ended December 31, 2005 as Compared to December 31, 2004. For 2005, consolidated other income and expenses increased approximately $1.5 billion, compared to 2004. The increase was due primarily to the gains associated with the sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP, equity income for the investment in DEFS subsequent to the deconsolidation of DEFS, effective July 1, 2005, income related to a distribution from an interest in a portfolio of office buildings, and increased earnings from International Energy’s NMC investment driven by higher product margins, slightly offset by the realized and unrealized pre-tax losses recognized in 2005 on certain 2005 and 2006 derivative contracts hedging Field Services commodity price risk which were discontinued as cash flow hedges as a result of the deconsolidation of DEFS by Duke Energy and an impairment charge related to Campeche. Effective with the deconsolidation of DEFS on July 1, 2005, mark-to-market changes related to the Field Services discontinued hedges are classified in Other income and expenses, net on the Consolidated Statements of Operations, while from February 22, 2005 to June 30, 2005 these mark-to-market changes were classified in Non-regulated electric, natural gas, natural gas liquids and other revenues on the Consolidated Statements of Operations.

Year Ended December 31, 2004 as Compared to December 31, 2003. Consolidated other income and expenses decreased $245 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 in Other related to the sale of a 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.

Consolidated Interest Expense

Year Ended December 31, 2005 as Compared to December 31, 2004. For 2005, consolidated interest expense decreased $219 million, compared to 2004. This decrease was due primarily to Duke Energy’s debt reduction efforts in 2004 (an approximate $140 million impact) and the deconsolidation of DEFS (an approximate $80 million impact).

Year Ended December 31, 2004 as Compared to December 31, 2003. For 2004, consolidated interest expense decreased $49 million, compared to 2003. The decrease was due primarily to:

• A $131 million decrease from net debt reduction and refinancing activities

• A $16 million write-off in 2003 as a result of an order by the PSCSC to write off regulatory assets related to debt issuance costs through interest expense, partially offset by

• $40 million of lower capitalized interest due to decreased construction activity

• $26 million of expenses related to financial instruments with characteristics of both liabilities and equity whose related distributions are now classified as interest expense instead of minority interest expense. Those instruments were classified as debt as of July 1, 2003, in accordance with SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity” (SFAS No. 150)

• A $20 million increase associated with Canadian exchange rates, and

• $17 million higher interest costs in Brazil, due to Duke Energy’s Brazilian debt being indexed annually to inflation and unfavorable impact of exchange rates.

Consolidated Minority Interest Expense

Year Ended December 31, 2005 as Compared to December 31, 2004. For 2005, consolidated minority interest expense increased $338 million, compared to 2004. This increase was driven primarily by increased earnings at DEFS in the first six months of 2005 as a result of the sale of TEPPCO GP and higher commodity prices, offset by the impact of the deconsolidation of DEFS effective July 1, 2005.

Year Ended December 31, 2004 as Compared to December 31, 2003. For 2004, consolidated minority interest expense increased $138 million, compared to 2003. This increase was driven by increased earnings at Field Services and improved results in Other as a result of the continued wind-down of DETM. Through June 30, 2003, minority interest expense included expense related to regular distributions on trust preferred securities of Duke Energy and its subsidiaries. As of July 1, 2003, those distributions were accounted for as interest expense on a prospective basis in accordance with the adoption of SFAS No. 150. As a result of this accounting change, minority interest expense decreased $55 million for 2004 and $75 million for 2003.

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Minority interest expense as shown and discussed in the following business segment EBIT sections includes only minority interest expense related to EBIT of Duke Energy’s joint ventures. It does not include minority interest expense related to interest and taxes of the joint ventures.

Consolidated Income Tax Expense (Benefit) from Continuing Operations

Year Ended December 31, 2005 as Compared to December 31, 2004. For 2005, consolidated income tax expense from continuing operations increased $750 million, compared to 2004. The increase in income tax expense from continuing operations is primarily a result of approximately $2.0 billion in higher pre-tax earnings, due primarily to the gains associated with the sale of TEPPCO GP, Duke Energy’s limited partner interest in TEPPCO LP and the DEFS disposition transaction (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”). Other than the increase from higher pre-tax earnings, the increase in income tax expense from continuing operations is due to an increase in the effective tax rate, which was approximately 34% in 2005, as compared to approximately 30% in 2004. The increase in the effective tax rate was due primarily to the release of approximately $52 million of income tax reserves, resulting from the resolution of various outstanding income tax issues and changes in estimates in 2004 and a $20 million tax benefit in 2004 recognized in connection with the prior year formation of Duke Energy Americas, LLC, partially offset by the $45 million taxes recorded in 2004 on the repatriation of foreign earnings that was expected to occur in 2005 associated with the American Jobs Creation Act of 2004.

Year Ended December 31, 2004 as Compared to December 31, 2003. For 2004, consolidated income tax expense (benefit) from continuing operations increased $627 million, compared to 2003. The increase was due primarily to the $1,808 million increase in earnings from continuing operations and the $45 million taxes recorded in 2004 on the repatriation of foreign earnings that was expected to occur in 2005 associated with the American Jobs Creation Act of 2004. These increases were partially offset by the release of approximately $52 million of income tax reserves, resulting from the resolution of various outstanding income tax issues and changes in estimates in 2004 and a $20 million tax benefit recognized in connection with the formation of DEA in 2004 (see Note 6 to the Consolidated Financial Statements, “Income Taxes”).

Consolidated (Loss) Income from Discontinued Operations, net of tax

(Loss) income from discontinued operations was ($705) million for 2005, $238 million for 2004, and ($1,232) million for 2003. These amounts represent results of operations and gains (losses) on dispositions related primarily to DENA’s assets and contracts outside the Midwestern and Southeastern United States, which are included in Other, International Energy’s Asia-Pacific Business and European Business, DCP, Field Services, Crescent and DEM (see Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”). The 2005 amount is primarily comprised of an approximate $550 million non-cash, after-tax charge (approximately $900 million pre-tax) for the impairment of assets, and the discontinuance of hedge accounting and the discontinuance of the normal purchase/normal sale exception for certain positions at DENA, as a result of the decision to exit substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. Additionally, during 2005, Other recognized after-tax losses of approximately $250 million (approximately $400 million pre-tax) as the result of selling certain gas transportation and structured contracts. These charges were offset by the recognition of after-tax gains of approximately $125 million (approximately $200 million pre-tax) related to the recognition of deferred gains in AOCI related to discontinued cash flow hedges.

The 2004 amount is primarily comprised of a $273 million after-tax gain resulting from the sale of International Energy’s Asia-Pacific Business, and an approximate $117 million after-tax gain on the sale of two partially constructed DENA plants offset by operating losses at DENA. DENA’s 2004 gain related to the settlement of the Enron bankruptcy proceedings was entirely offset by a charge related to the California and Western U.S. energy markets settlement.

The 2003 amount is primarily comprised of $1.7 billion in pre-tax impairment charges related to DENA’s partially completed Western plants, related forward power and gas contracts that were de-designated as normal purchases and sales and cash flow hedges, a generation plant in Maine and the Morro Bay plant in California. Also contributing to the 2003 amount was a $223 million after tax charge for International Energy’s impairment charges incurred as a result of classifying its Asia-Pacific assets as held for sale and exiting the European market.

Consolidated Cumulative Effect of Change in Accounting Principle, net of tax and minority interest

During 2005, Duke Energy recorded a net-of-tax and minority interest cumulative effect adjustment for a change in accounting principle of $4 million as a reduction in earnings. The change in accounting principle related to the implementation of FIN 47, “Accounting for Conditional Asset Retirement Obligations,” in which the timing or method of settlement are conditional on a future event that may or may not be within the control of Duke Energy.

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During 2003, Duke Energy recorded a net-of-tax and minority interest cumulative effect adjustment for a change in accounting principles of $162 million, or $0.18 per basic share, as a reduction in earnings. The change in accounting principles included an after-tax and minority interest charge of $151 million, or $0.17 per basic share, related to the implementation of EITF 02-03 and an after-tax charge of $11 million, or $0.01 per basic share, related to the implementation of SFAS No. 143.

Segment Results

Management evaluates segment performance 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 excludes discontinued operations, represents all profits from continuing operations (both operating and non-operating) before deducting interest and taxes, and is net of the minority interest expense related to those profits. Cash, cash equivalents and short-term investments are managed centrally by Duke Energy, so the gains and losses on foreign currency remeasurement, and interest and dividend 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.

As discussed in Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale” during the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. As a result of this exit plan, DENA’s continuing operations (which primarily include the operations of the Midwestern generation assets, DENA’s remaining Southeastern operations related to assets which were disposed of in 2004, the remaining operations of DETM, and certain general and administrative costs) have been reclassified to Commercial Power, except for DETM, which is in Other. Previously, DENA’s continuing operations were included as a component of Other in 2005 and the DENA segment in prior periods. Additionally, in connection with this exit plan, DENA transferred its 50% investment in the McMahon facility in British Columbia, Canada to Natural Gas Transmission. Prior period segment results for Natural Gas Transmission have been retrospectively adjusted to include the results of operations of the McMahon facility.

In July 2005, Duke Energy completed the agreement with ConocoPhillips to reduce Duke Energy’s ownership interest in DEFS from 69.7% to 50% (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”). In connection with the DEFS disposition transaction, DEFS transferred its Canadian natural gas gathering and processing facilities to Natural Gas Transmission. Prior period segment results for Field Services have been retrospectively adjusted to exclude the results of operations of these Canadian gathering and processing facilities, while prior period segment results for Natural Gas Transmission have been retrospectively adjusted to include the results of operations of these Canadian gathering and processing facilities.

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

EBIT by Business Segment

	Years Ended December 31,
	2005			2004			Variance 2005 vs 2004			2003			Variance 2004 vs 2003
	(in millions)
U. S. Franchised Electric and Gas	$	1,495		$	1,467		$	28		$	1,403		$	64
Natural Gas Transmission		1,388			1,329			59			1,333			(4	)
Field Services(a)		1,946			367			1,579			176			191
Commercial Power(c)		(118	)		(479	)		361			(1,288	)		809
International Energy		314			222			92			215			7
Crescent		314			240			74			134			106
Total reportable segment EBIT		5,339			3,146			2,193			1,973			1,173
Other(c)		(527	)		(183	)		(344	)		(660	)		477
Total reportable segment and other EBIT		4,812			2,963			1,849			1,313			1,650
Interest expense		(1,062	)		(1,281	)		219			(1,330	)		49
Interest income and other(b)		66			103			(37	)		(6	)		109
Consolidated earnings (loss) from continuing operations before income taxes	$	3,816		$	1,785		$	2,031		$	(23	)	$	1,808

(a) In July 2005, Duke Energy transferred 19.7% of its ownership interest in DEFS to ConocoPhillips. Field Services segment data includes DEFS as a consolidated entity for periods prior to July 1, 2005 and an equity method investment for periods after June 30, 2005.

(b) Other includes foreign currency transaction gains and losses, and additional minority interest expense not allocated to the segment results.

(c) Amounts associated with former DENA’s operations are included in Other for all periods presented, except for the Midwestern generation and Southeast operations, which are reflected in Commercial Power.

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

U. S. Franchised Electric and Gas

	Years Ended December 31,
	2005		2004		Variance 2005 vs 2004		2003		Variance 2004 vs 2003
	(in millions)
Operating revenues	$	5,432	$	5,069	$	363	$	4,875	$	194
Operating expenses		3,959		3,613		346		3,525		88
Gains on sales of other assets, net		7		3		4		6		(3	)
Operating income		1,480		1,459		21		1,356		103
Other income, net of expenses		15		8		7		47		(39	)
EBIT	$	1,495	$	1,467	$	28	$	1,403	$	64
Sales, Gigawatt-hours (GWh)		85,277		82,708		2,569		82,828		(120	)

The following table shows the percentage changes in GWh sales and average number of customers for U. S. Franchised Electric and Gas for the past two years.

Increase (decrease) over prior year	2005		2004		2003
Residential sales(a)	3.7	%	5.1	%	(2.3	)%
General service sales(a)	1.9	%	3.5	%	0.4	%
Industrial sales(a)	1.1	%	1.8	%	(5.7	)%
Wholesale sales	38.0	%	(26.1	)%	5.1	%
Total U. S. Franchised Electric and Gas sales(b)	3.1	%	(0.1	)%	(1.1	)%
Average number of customers	2.0	%	1.7	%	2.0	%

(a) Major components of U. S. Franchised Electric and Gas’ retail sales.

(b) Consists of all components of U. S. Franchised Electric and Gas’ sales, including retail sales, and wholesale sales to incorporated municipalities and to public and private utilities and power marketers.

Year Ended December 31, 2005 as Compared to December 31, 2004

Operating Revenues. The increase was driven primarily by:

• A $146 million increase in wholesale power revenues, due primarily to increased sales volumes and higher market prices, approximately $42 million and $104 million, respectively. Wholesale mega-watt (MWh) sales increased by approximately 40% due to strong demand driven by favorable weather, more efficient performance by the generation fleet in 2005 and alleviation of coal constraints that limited wholesale sales opportunities in 2004. Gross margin increased by $11 per MWh, an 80% increase, due to higher average market rates for power resulting primarily from energy supply disruptions and record natural gas prices in 2005

• A $137 million increase in fuel revenues, due primarily to increased MWh sales to retail and wholesale customers and increased fuel rates for retail customers due primarily to increased coal costs. Sales to retail customers increased by approximately 2%, while sales to wholesale customers increased by approximately 40% resulting in significantly more fuel revenue collections from those customers. The delivered cost of coal in 2005 is approximately $7 per ton higher than in 2004

• A $55 million increase in MWh sales to retail customers due to favorable weather conditions during the latter half of the year. Weather statistics in 2005 for cooling degree days were approximately 7% better than normal as compared to 1% below normal in 2004

• A $27 million increase related to demand from retail customers, due primarily to continued growth in the number of residential and general service customers in U. S. Franchised Electric and Gas’ service territory. The number of customers in 2005 has increased by approximately 43,000 compared to 2004, partially offset by

• A $37 million decrease related to the sharing of profits from wholesale power sales with industrial customers in North Carolina in 2005. For the year ended December 31, 2005, the sharing of profits was $55 million, while for the same period in 2004, sharing of profits was $18 million. The increased sharing is due to increased wholesale power revenues in 2005.

Operating Expenses. The increase was driven primarily by:

• A $176 million increase in fuel expenses, due primarily to higher coal costs and increased generation to meet the strong demand of retail and wholesale customers. Total generation increased by 4% compared to 2004 and generation fueled by coal accounted for more than 50 percent of total generation during both periods. The delivered cost of coal in 2005 is approximately $7 per ton higher than the same period in 2004

• A $134 million increase in operating and maintenance expenses, due primarily to increased planned outage and maintenance at generating plants, planned maintenance to improve the reliability of distribution and transmission equipment and employee wages and benefits

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• A $29 million increase due to higher storm charges in 2005. The increase is primarily due to a December 2005 ice storm ($46 million), which resulted in outages for approximately 700,000 customers. This is partially offset by charges for Hurricane Ivan in September 2004 ($11 million) and a wind storm in March 2004 ($7 million)

• A $14 million increase in donations related to sharing of profits from wholesale power sales with charitable, educational and economic development programs in North Carolina and South Carolina. For the year ended December 31, 2005, donations totaled $28 million, while for the same period in 2004, donations totaled $14 million.

EBIT. The increase in 2005 EBIT is primarily due to increased sales to wholesale customers, net of sharing, increased sales to retail customers due to favorable weather in 2005, and continued growth in the number of residential and general service customers in 2005. These changes were partially offset by increased operating and maintenance expenses, including storm costs.

Matters Impacting Future U. S. Franchised Electric and Gas Results

U. S. Franchised Electric and Gas continues to increase its customer base, maintain low costs and deliver high-quality customer service in the Carolinas. The residential and general service sectors are expected to continue to grow. Wholesale power sales were strong in 2005, driven by favorable power prices. However, wholesale pricing has dropped in early 2006 based on current market conditions. U. S. Franchised Electric and Gas will continue to provide strong cash flows to Duke Energy. Changes in weather, wholesale power market prices, generation availability and changes to the regulatory environment would impact future financial results for U. S. Franchised Electric and Gas. In addition, U. S. Franchised Electric and Gas’ results will be affected by its flexibility to vary the amortization expenses associated with the North Carolina clean air legislation. U. S. Franchised Electric and Gas’ amortization expense related to this clean air legislation totals $637 million from inception, with $311 million recorded in 2005 and $211 million recorded in 2004. For the periods beyond 2005, due in part to costs and synergies that could result from the anticipated merger with Cinergy, U. S. Franchised Electric and Gas is not able to estimate reported segment EBIT. U. S. Franchised Electric and Gas has agreed to a one-time $40 million customer rate reduction in South Carolina, for a period of twelve months beginning two months after the merger closing. The negotiations with North Carolina continue but a one-time customer rate reduction of less than $120 million is expected. Savings from the merger are expected to exceed costs to achieve the merger in total for Duke Energy.

Year Ended December 31, 2004 as Compared to December 31, 2003

Operating Revenues. The increase was driven primarily by:

• A $138 million increase in billed and unbilled fuel revenues driven by increased fuel rates for retail customers, due primarily to increased coal costs

• A $68 million increase in GWh sales to retail customers, due to favorable weather during the period

• A $33 million increase due to continued growth in the number of residential and general service customers in U. S. Franchised Electric and Gas’ service territory

• A $30 million increase due to a rate decrement ordered by the PSCSC and recorded during the third quarter of 2003, partially offset by

• A $50 million decrease in wholesale power revenues, due primarily to lower sales volumes due to limited generation availability resulting from a shortage of coal and increased outages at certain U. S. Franchised Electric and Gas generation facilities, and

• An $18 million decrease due to sharing of profits from wholesale power sales with customers in North Carolina in 2004.

Operating Expenses. The increase was driven primarily by:

• Increased fuel expenses of $127 million, due primarily to increased coal costs and increased sales to retail customers

• Increased nuclear and fossil outage costs of $24 million, driven by increased scope and duration of 2004 nuclear outages compared to 2003 and seven planned maintenance/turbine outages across the fossil fleet in 2004 as compared to two planned maintenance/turbine outages in 2003

• Increased depreciation expense of $16 million, primarily due to additional capital spending and assets placed in service

• Increased donations of $14 million, due to sharing of profits from wholesale power sales with charitable, educational and economic development programs in North Carolina and South Carolina as agreed to with the state utility commission, partially offset by

• Decreased severance expenses of $78 million due to workforce reductions in 2003, and

• Decreased operating and maintenance expenses of $9 million, primarily due to a charge in 2003 for right-of-way maintenance costs, partially offset by increased governance costs in 2004.

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Other Income, net of expenses. The decrease was driven primarily by:

• A $25 million decrease in the AFUDC, due primarily to large maintenance capital projects that were completed and placed in service in 2003, reducing the basis on which AFUDC is calculated, and

• A $15 million decrease in the return on deferred costs related to the purchase of capacity from the joint owners of the Catawba Nuclear Station.

EBIT. The increase in 2004 EBIT resulted primarily from increased sales to retail customers due to favorable weather in 2004, continued growth in the number of residential and general service customers in 2004, and severance and right-of-way maintenance charges coupled with the one year rate decrement ordered by the PSCSC during 2003. These changes were partially offset by lower sales to wholesale customers, sharing of profits from wholesale power sales, increased fossil and nuclear outages and increased depreciation expense.

Natural Gas Transmission

	Years Ended December 31,
	2005		2004		Variance 2005 vs 2004			2003		Variance 2004 vs 2003
	(in millions)
Operating revenues	$	4,055	$	3,351	$	704		$	3,253	$	98
Operating expenses		2,715		2,075		640			2,009		66
Gains on sales of other assets, net		13		17		(4	)		7		10
Operating income		1,353		1,293		60			1,251		42
Other income, net of expenses		65		63		2			130		(67	)
Minority interest expense		30		27		3			48		(21	)
EBIT	$	1,388	$	1,329	$	59		$	1,333	$	(4	)
Proportional throughput, TBtu(a)		3,410		3,332		78			3,362		(30	)

(a) Trillion British thermal units. Revenues are not significantly impacted by pipeline throughput fluctuations since revenues are primarily composed of demand charges.

Year Ended December 31, 2005 as Compared to December 31, 2004

Operating Revenues. The increase was driven primarily by:

• A $269 million increase due to new Canadian assets, primarily the Empress System

• A $153 million increase due to foreign exchange rates favorably impacting revenues from the Canadian operations as a result of the strengthening Canadian dollar (partially offset by currency impacts to expenses)

• A $152 million increase from recovery of higher natural gas commodity costs, resulting from higher natural gas prices that are passed through to customers without a mark-up at Union Gas. This revenues increase is offset in expenses

• A $60 million increase for U.S. business operations driven by higher rates at Maritimes & Northeast Pipeline, LLC and Maritimes & Northeast Pipeline, LP (collectively, M & N Pipeline) and favorable commodity prices on natural gas processing activities

• A $36 million increase in gas distribution revenues, primarily due to higher gas usage in the power market, and

• A $20 million increase from completed and operational pipeline expansion projects in the U.S.

Operating Expenses. The increase was driven primarily by:

• A $272 million increase due to new Canadian assets, primarily gas purchase costs associated with the Empress System

• A $152 million increase related to increased natural gas prices at Union Gas. This amount is offset in revenues

• A $118 million increase caused by foreign exchange impacts (offset by currency impacts to revenues, as discussed above)

• A $43 million increase in gas purchases for distribution, primarily due to higher gas usage in the power market, and

• A $23 million increase related to the 2004 resolution of ad valorem tax issues in various states.

Other Income, net of expenses. The increase was driven primarily by the successful completion of the Gulfstream Phase II project which went into service in February 2005 and increased volumes at Gulfstream, resulting in a $11 million increase in Gas Transmission’s 50% equity earnings and a $5 million construction fee received from an affiliate. These increases were partially offset by a $16 million gain in 2004 on the sale of equity investments, primarily due to the resolution of contingencies related to prior year sales.

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EBIT. The increase in EBIT was due primarily to earnings from U.S. business expansion projects, improved U.S. operations and favorable foreign exchange rate impacts from the strengthening Canadian currency, partially offset by the 2004 resolution of ad valorem tax issues.

Matters Impacting Future Natural Gas Transmission Results

Natural Gas Transmission plans to continue earnings growth through capital efficient expansions in existing markets, optimization of existing systems, and organizational efficiencies and cost control. Over time, Natural Gas Transmission expects continued modest annual EBIT growth from its 2005 EBIT. Demand for natural gas is expected to grow two to three percent in DEGT’s key markets. Changes in the Canadian dollar, weather, throughput and regulatory stability, commodity prices and the ability to renew service contracts would impact future financial results at Natural Gas Transmission.

In June 2006, the Board of Directors of Duke Energy authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas businesses to Duke Energy shareholders. The new natural gas company, which would be named Spectra Energy, would principally consist of Duke Energy’s Natural Gas Transmission business segment, which would include Union Gas, and would also include Duke Energy’s 50-percent ownership interest in DEFS. Approximately $9 billion of debt currently at Duke Capital and its consolidated subsidiaries is anticipated to transfer to the new natural gas company at the time of the spin-off. If completed, the decision to spin off the natural gas business is expected to deliver long-term value to shareholders. While the actual timing of the spin-off, if it occurs, is dependent upon the resolution of certain regulatory and other matters, Duke Energy is currently targeting a January 1, 2007 effective date for the transaction. The results of the natural gas businesses are expected to be treated as discontinued operations in the period the spin-off is consummated.

Year Ended December 31, 2004 as Compared to December 31, 2003

Operating Revenues. The increase was driven primarily by:

• A $175 million increase due to foreign exchange rates favorably impacting revenues from the Canadian operations as a result of the strengthening Canadian dollar (partially offset by currency impacts to expenses)

• A $62 million increase from recovery of higher natural gas commodity costs, resulting from higher natural gas prices that are passed through to customers without a mark-up at Union Gas. This revenues increase is offset in expenses

• A $40 million increase from completed and operational pipeline expansion projects in the United States, partially offset by

• A $95 million decrease as a result of the sale of Empire State Pipeline in February 2003 and Pacific Natural Gas (PNG) in December 2003, and

• An $80 million decrease in gas distribution revenues at Union Gas resulting from lower gas usage in the power market due to unfavorable weather.

Operating Expenses. The increase was driven primarily by:

• A $127 million increase caused by foreign exchange impacts (offset by currency impacts to revenues)

• A $62 million increase related to increased natural gas prices at Union Gas. This amount is offset in revenues

• A $52 million increase resulting from the favorable resolution in 2003 of various contingencies primarily related to a capital project and outstanding ad valorem and franchise tax issues from prior state audits

• A $17 million increase associated with the pipeline expansion projects placed in service

• A $14 million increase in depreciation primarily due to an increase in the depreciation rate and the addition of two major projects in the Western Canadian operations, partially offset by

• An $80 million decrease as a result of operations sold in 2003 as discussed above

• A $63 million decrease in the cost of gas sold for distribution at Union Gas, due primarily to reduced volumes

• A $29 million decrease due to severance costs in 2003, and

• A $23 million decrease primarily related to the 2004 resolution of ad valorem tax issues in various states.

Other Income, net of expenses. The decrease was driven primarily by:

• A $90 million decrease as a result of prior year gains on sales, primarily the gain on the sale of Natural Gas Transmission’s interests in Northern Border Partners L.P. in January 2003, Alliance Pipeline and the Aux Sable liquids plants in April 2003, and Foothills Pipe Lines Ltd in August 2003

• A $22 million decrease in AFUDC (equity component) due to lower capital spending in 2004

• An $18 million decrease in equity earnings as a result of investments sold in 2003, partially offset by

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• A $36 million increase resulting from the 2003 negative settlement of hedges related to foreign currency exposure

• An increase of $16 million in equity earnings of Gulfstream, resulting from higher revenues and volumes due to fuel switching during the unusually active hurricane season in Florida in 2004, and

• A $16 million increase from 2004 gains on the sale of equity investments, primarily due to resolution of contingencies related to prior year sales.

Minority Interest Expenses. The decrease was driven primarily by the sale of PNG in December 2003, as well as lower earnings on Maritimes & Northeast Pipeline.

EBIT. EBIT decreased primarily as a result of gains from sales of equity investments recorded in the prior year and foregone earnings from the investments sold. Those decreases were mostly offset by earnings from expansion projects and foreign exchange EBIT impacts from the strengthening Canadian currency.

Field Services

	Years Ended December 31,
	2005		2004		Variance 2005 vs 2004			2003			Variance 2004 vs 2003
	(in millions)
Operating revenues	$	5,530	$	10,044	$	(4,514	)	$	8,538		$	1,506
Operating expenses		5,215		9,489		(4,274	)		8,320			1,169
Gains (Losses) on sales of other assets, net		577		2		575			(4	)		6
Operating income		892		557		335			214			343
Equity in earnings of unconsolidated affiliates(a)		292		—		292			—			—
Other income, net of expenses		1,259		37		1,222			68			(31	)
Minority interest expense		497		227		270			106			121
EBIT	$	1,946	$	367	$	1,579		$	176		$	191
Natural gas gathered and processed/transported, TBtu/d(b)		6.8		6.8		—			7.0			(0.2	)
NGL production, MBbl/d(c)		353		356		(3	)		346			10
Average natural gas price per MMBtu(d)	$	8.59	$	6.14	$	2.45		$	5.39		$	0.75
Average NGL price per gallon(e)	$	0.85	$	0.68	$	0.17		$	0.53		$	0.15

(a) Includes Duke Energy’s 50% equity in earnings of DEFS net income subsequent to the deconsolidation of DEFS effective July 1, 2005. Duke Energy’s equity in earnings was $292 million for the year ended December 31, 2005. Results of DEFS prior to July 1, 2005 are presented on a consolidated basis.

(b) Trillion British thermal units per day

(c) Thousand barrels per day

(d) Million British thermal units

(e) Does not reflect results of commodity hedges

In July 2005, Duke Energy completed the transfer of a 19.7% interest in DEFS to ConocoPhillips, Duke Energy’s co-equity owner in DEFS, which reduced Duke Energy’s ownership interest in DEFS from 69.7% to 50% (the DEFS disposition transaction) and resulted in Duke Energy and ConocoPhillips becoming equal 50% owners in DEFS. As a result of the DEFS disposition transaction, Duke Energy deconsolidated its investment in DEFS and subsequently has accounted for DEFS as an investment utilizing the equity method of accounting (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”).

Year Ended December 31, 2005 as Compared to December 31, 2004

Operating Revenues. The decrease was due to the DEFS disposition transaction and subsequent deconsolidation of DEFS. This decrease was partially offset by increased revenues of approximately $850 million during the six months ended June 30, 2005 versus the comparable period in the prior year which was primarily attributable to a $0.14 per gallon increase in average NGL prices and a $0.66 per MMBtu increase in average natural gas prices. Subsequent to June 2005, Duke Energy’s 50% of equity in earnings related to its investment in DEFS are included in Equity in Earnings of Unconsolidated Affiliates.

Operating Expenses. The decrease was due to the DEFS disposition transaction and subsequent deconsolidation of DEFS. Subsequent to June 2005, the results of DEFS are included in Equity in Earnings of Unconsolidated Affiliates in the accompanying Consolidated Statements of Operations. This decrease was partially offset by:

• Increased operating expense of approximately $675 million during the six months ended June 30, 2005 versus the comparable period in the prior year which was primarily attributable to higher average costs of raw natural gas supply, due primarily to an increase in average NGL and natural gas prices, and

• An approximate $120 million increase due to the reclassification of pre-tax unrealized losses in AOCI during the first quarter as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, which were

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previously accounted for as cash flow hedges (see Note 8 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments”). After the discontinuance of these hedges, changes in their fair value are being recognized in Other results, as management considers the discontinuance to be an event which disassociates the contracts from the Field Services’ results.

Gain on sales of other assets, net. The increase was primarily due to an approximate pre-tax gain of $575 million on the DEFS disposition transaction.

Equity in earnings of unconsolidated affiliates. The increase was driven by the equity in earnings of $292 million for Duke Energy’s investment in DEFS subsequent to the completion of the DEFS disposition transaction and related deconsolidation. DEFS earnings during the six months ended December 31, 2005 have continued to be favorably impacted by increased commodity prices. These increases were partially offset by higher operating costs and pipeline integrity work as well as lower volumes due in part to hurricane interruptions.

Other Income, net of expenses. The increase was driven primarily by an approximate $1.1 billion pre-tax gain in 2005 on the sale of DEFS’ wholly-owned subsidiary, TEPPCO GP, the general partner of TEPPCO LP, and the pre-tax gain on the sale of Duke Energy’s limited partner interest in TEPPCO LP of approximately $100 million. TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP were each sold to Enterprise GP Holdings LP, an unrelated third party. The gain was partially offset by a $33 million decrease in earnings from equity method investments, primarily as a result of the sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP in the first quarter of 2005.

Minority Interest Expense. The increase was due primarily to the minority interest impact of the gain on the sale of TEPPCO GP to Enterprise GP Holdings LP for approximately $1.1 billion as well as increased earnings at DEFS during the six months ended June 30, 2005 due to commodity price increases. This increase was partially offset by the DEFS disposition transaction and the related deconsolidation of Duke Energy’s investment in DEFS effective July 1, 2005.

EBIT. The increase was primarily driven by the gain on sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP, the gain as a result of the DEFS disposition transaction and favorable effects of commodity price increases, partially offset by the impact of Duke Energy’s decreased ownership percentage resulting from the completion of the DEFS disposition transaction. Also, during the first three months of 2005, Duke Energy discontinued certain cash flow hedges entered into to hedge Field Services’ commodity price risk (see Note 8 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments”). As a result of the discontinuance of these cash flow hedges and hedge accounting treatment, approximately $120 million of pre-tax unrealized losses in AOCI related to these contracts have been recognized by Field Services during the year ended December 31, 2005. Field Services’ future results are subject to volatility for factors such as commodity price changes.

Matters Impacting Future Field Services Results

Field Services, through its 50 percent investment in DEFS, has developed significant size and scope in natural gas gathering and processing and NGL marketing and plans to focus on operational excellence and organic growth. DEFS’ revenues and expenses are significantly dependent on prevailing commodity prices for NGLs and natural gas, and past and current trends in price changes of these commodities may not be indicative of future trends. DEFS anticipates that current price levels will continue to stimulate drilling and help to offset declining raw natural gas supplies. Although the prevailing price of natural gas has less short term significance to its operating results than the price of NGLs, in the long term, the growth and sustainability of DEFS’ business depends on natural gas prices being at levels sufficient to provide incentives and capital for producers to increase natural gas exploration and production.

Future equity in earnings of unconsolidated affiliates will continue to be sensitive to commodity prices that have historically been cyclical and volatile. DEFS’ operating and general and administrative costs increased in 2005, primarily due to asset integrity work and financial process improvement costs incurred during the year.

There are many important factors that could cause actual results to differ materially from the expectations expressed. Management can provide no assurances regarding the impact of future commodity prices or drilling activity.

As previously mentioned, in June 2006, the Board of Directors of Duke Energy authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas businesses to Duke Energy shareholders. The new natural gas company, which would be named Spectra Energy, would principally consist of Duke Energy’s Natural Gas Transmission business segment, which would include Union Gas, and would also include Duke Energy’s 50-percent ownership interest in DEFS. If completed, the decision to spin off the natural gas business is expected to deliver long-term value to shareholders. While the actual timing of the spin-off, if it occurs, is dependent upon the resolution of certain regulatory and other matters, Duke Energy is targeting a January 1, 2007 effective date for the transaction. The results of the natural gas businesses are expected to be treated as discontinued operations in the period the spin-off is consummated.

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In July 2006, the State of New Mexico Environment Department issued Compliance Order to DEFS that list air quality violations during the past five year at three DEFS owned or operated facilities in New Mexico. DEFS intends to contest these allegations. Management of DEFS does not believe this matter will result in a material impact on DEFS’ future consolidated results of operations, cash flows or financial position.

Year Ended December 31, 2004 as Compared to December 31, 2003

Operating Revenues. The increase was primarily driven by:

• An $870 million increase due primarily to a $0.15 per gallon increase in average NGL prices

• A $590 million increase due primarily to a $0.75 per MMBtu increase in average natural gas prices

• A $51 million increase from trading and marketing net margin, due primarily to natural gas asset based trading and marketing price volatility

• A $45 million increase attributable to a $10.29 per barrel increase in average condensate prices to $41.37 during 2004 from $31.08 during 2003

• A $30 million increase related to higher transportation, storage and processing fees which was primarily due to higher fees from processing contracts, partially offset by

• A $44 million decrease related to the impact of cash flow hedging, which reduced revenues by approximately $242 million for the year ended December 31, 2004 and by $198 million for the year ended December 31, 2003, as compared to what revenue would have been without any hedging, and

• A $30 million decrease related to lower NGL and raw natural gas sales volume, partially offset by an increase in wholesale propane marketing activity primarily due to higher propane prices, and the acquisition of gathering, processing and transmission assets in Southeast New Mexico from ConocoPhillips (“COP Acquisition”). Although production volumes increased as a result of processing economics and the COP Acquisition, sales volumes decreased as a result of producers marketing their NGLs on their own behalf.

Operating Expenses. The increase was driven primarily by:

• A $1,175 million increase due to higher average costs of raw natural gas supply which was due primarily to an increase in average NGL and natural gas prices

• A $20 million increase related primarily to an increase in wholesale propane marketing activity and the COP Acquisition partially offset by lower purchased raw natural gas supply volume

• An $18 million increase related to impairment charges associated with a planned shut down of a specific plant and a disposal of certain assets, partially offset by

• A $25 million decrease in operating, and general and administrative expenses, primarily due to severance charges and other employee related expenditures in 2003 not experienced in 2004, lower repairs and maintenance, and environmental expenses in 2004, partially offset by an increase related to Field Services’ Sarbanes-Oxley compliance costs.

Other Income, net of expenses. The decrease was driven primarily by:

• A $23 million decrease due to impairment charges in 2004 related to management’s assessment of the recoverability of certain equity method investments

• A $13 million decrease due to the gains on sales of equity method investments in 2003, partially offset by

• A $7 million increase in equity earnings primarily due to increased earnings from equity method investments.

Minority Interest Expense. Minority interest expense increased in 2004 compared to 2003 due to increased earnings from DEFS. The increase was not proportionate to the increase in Field Services’ earnings, as the Field Services segment includes the results of incremental hedging activities contracted at the Duke Energy corporate level that are not included in DEFS’ results.

EBIT. The increase in EBIT in 2004 compared to 2003 resulted primarily from the favorable effects of commodity prices and improved results from trading and marketing activities, partially offset by NGL and raw natural gas sales volume declines and impairments. The full impact from the effects of commodity prices were not realized as some sales volumes were previously hedged at prices different than actual market prices at settlement.

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Supplemental Data

Below is supplemental information for DEFS operating results subsequent to deconsolidation on July 1, 2005:

(in millions)	Six Months Ended December 31, 2005
Operating revenues	$	7,463
Operating expenses		6,814
Operating income		649
Other income, net of expenses		1
Interest expense, net		62
Income tax expense		4
Net income	$	584

Commercial Power

	Years Ended December 31,
	2005			2004			Variance 2005 vs 2004			2003			Variance 2004 vs 2003
	(in millions)
Operating revenues	$	148		$	179		$	(31	)	$	167		$	12
Operating expenses		200			302			(102	)		1,436			(1,134	)
Losses on sales of other assets, net		(70	)		(359	)		289			(19	)		(340	)
Operating loss		(122	)		(482	)		360			(1,288	)		806
Other income, net of expenses		4			3			1			—			3
EBIT	$	(118	)	$	(479	)	$	361		$	(1,288	)	$	809
Actual plant production, GWh(a)(b)		1,759			3,343			(1,584	)		6,084			(2,741	)
Net proportional megawatt capacity in operation		3,600			3,600			—			9,085			(5,485	)

(a) Includes plant production from plants accounted for under the equity method

(b) Excludes discontinued operations

During the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. As a result of this exit plan, Commercial Power includes the operations of DENA’s Midwestern generation assets and remaining Southeastern operations related to the assets which were disposed of in 2004. The results of DENA’s discontinued operations, which are comprised of assets sold to LS Power, are presented in (Loss) Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations, and are discussed in consolidated Results of Operations section titled “Consolidated (Loss) Income from Discontinued Operations, net of tax.”

Year Ended December 31, 2005 as compared to December 31, 2004

Operating Revenues. The decrease was driven primarily by the sale of the Southeast plants in 2004, including losses in 2005 associated with structured power contracts in the Southeast.

Operating Expenses. The decrease was driven primarily by the sale of the Southeast plants in 2004 and lower operating expenses in the Midwest, including:

• $61 million decrease in operations and maintenance costs, including general and administrative expenses, and depreciation expenses, and

• $38 million decrease in fuel costs.

Losses on Sales of Other Assets, net. The 2005 loss was due primarily to an approximate $75 million pre-tax charge related to the termination of structured power contracts in the Southeastern Region. The 2004 results include pre-tax losses of approximately $360 million associated with the sale of the Southeast Plants.

EBIT. EBIT loss decreased primarily as a result of the sale of the Southeast plants in 2004, driven by the loss recognized in 2004 on the sale of the Southeast Plants and decreased operating costs and lower general and administrative expense, as outlined above.

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Year Ended December 31, 2004 as Compared to December 31, 2003

Operating Revenues. The increase was driven primarily by an increase in power generation revenues, due primarily to increased average power prices, partially offset by lower volumes due to the sale of the Southeast Plants in the second quarter of 2004.

Operating Expenses. The decrease was driven primarily by:

• A $1,139 million decrease in asset impairments and other related charges primarily in connection with DENA’s exit from the Southeast region and the related discontinuance of the Southeast region hedges

• A $58 million decrease in depreciation expense, primarily due to the sale of the Southeast Plants in 2004, and

• A $13 million decrease in operations and maintenance expense, due primarily to the sale of the Southeast Plants in 2004 and reduced costs from renegotiated outsourcing agreements, partially offset

• A $75 million increase in plant fuel costs due primarily to higher average gas prices, offset by lower volumes as a result of the sale of the Southeast Plants.

Losses on Sales of Other Assets, net. Losses on sales of other assets for the year ended December 31, 2004 were due primarily to an approximate $360 million pre-tax loss associated with the sale of DENA’s Southeast Plants. Losses on sales of other assets for 2003 were primarily due to an $18 million pre-tax loss on the sale of the 25% net interest in the Vermillion facility.

EBIT. EBIT loss decreased primarily as a result of the decreased losses from impairments and other related charges and lower plant depreciation and operating expenses from the 2004 sale of the Southeast Plants.

International Energy

	Years Ended December 31,
	2005		2004			Variance 2005 vs 2004			2003		Variance 2004 vs 2003
	(in millions)
Operating revenues	$	745	$	619		$	126		$	597	$	22
Operating expenses		536		462			74			426		36
Losses on sales of other assets, net		—		(3	)		3			—		(3	)
Operating income		209		154			55			171		(17	)
Other income, net of expenses		117		78			39			57		21
Minority interest expense		12		10			2			13		(3	)
EBIT	$	314	$	222		$	92		$	215	$	7
Sales, GWh		18,213		17,776			437			16,374		1,402
Net proportional megawatt capacity in operation(a)		3,937		4,139			(202	)		4,121		18

(a) Excludes discontinued operations

Year Ended December 31, 2005 as Compared to December 31, 2004

Operating Revenues. The increase was driven primarily by:

• A $32 million increase in Brazil due to favorable exchange rates, higher average energy prices, partially offset by lower sales volumes

• A $31 million increase in El Salvador due to higher power prices and a favorable change in regulatory price bid methodology

• A $28 million increase in Argentina due primarily to higher power prices and hydroelectric generation

• A $14 million increase in Ecuador mainly due to higher volumes resulting from a lack of water for hydro competitors

• A $12 million increase in Guatemala due to higher power prices, and

• An $8 million increase in Peru due to favorable hydrological conditions and higher power prices.

Operating Expenses. The increase was driven primarily by:

• A $29 million increase in El Salvador due primarily to higher fuel oil prices, increased fuel oil volumes purchased and increased transmission costs

• A $26 million increase in Ecuador due to higher maintenance, higher diesel fuel prices, increased diesel fuel volumes purchased and a prior year credit related to long term service contract termination

• A $15 million increase in Guatemala due to higher fuel prices and increased fuel volumes purchased, in addition to higher operations and maintenance costs

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• A $14 million increase in Brazil due to unfavorable exchange rates and an increase in regulatory and transmission fees, partially offset by lower power purchase obligations

• A $14 million increase in Argentina due to higher power purchase volumes and prices, partially offset by

• A $13 million decrease related to a 2004 charge for the disposition of the ownership share in Compania de Nitrogeno de Cantarell, S.A. de C.V. (Cantarell), a nitrogen production and delivery facility in the Bay of Campeche, Gulf of Mexico in 2004, and

• A $10 million decrease in general and administrative expenses primarily due to lower corporate overhead allocations and compliance costs.

Other Income, net of expenses. The increase was driven primarily by a $55 million increase in equity earnings from the NMC investment driven by higher product margins, offset by a $20 million equity investment impairment related to Campeche in 2005.

EBIT. The increase was due primarily to favorable pricing and hydrological conditions in Peru and Argentina, favorable exchange rates in Brazil and higher equity earnings from NMC, absence of a charge associated with the disposition of the ownership share in Cantarell recorded in 2004, partially offset by an equity investment impairment related to Campeche in 2005.

Matters Impacting Future International Energy Results

International Energy’s current strategy is focused on selectively growing its Latin American power generation business while continuing to maximize the returns and cash flow from its current portfolio. EBIT results for International Energy are sensitive to changes in hydrology, power supply, power demand and fuel prices. Regulatory matters can also impact EBIT results, as well as impacts from fluctuations in exchange rates, most notably the Brazilian Real.

Certain of International Energy’s long-term sales contracts and long-term debt in Brazil contain inflation adjustment clauses. While this is favorable to revenue in periods of inflation in the long run, as International Energy’s contract prices are adjusted, there is an unfavorable impact on interest expense resulting from revaluation of International Energy’s outstanding local currency debt. In periods of deflation, revenue is negatively impacted and interest expense is positively impacted.

International Energy owns a 50% joint venture interest in Campeche. Campeche operates a natural gas compression facility in the Cantarell oil field in the Gulf of Mexico. Campeche project revenues are generated from the gas compression services agreement (GCSA) with the Mexican national oil company (PEMEX). As a result of ongoing discussions between Campeche and PEMEX to either sell the Campeche investment or renew the GCSA, an other than temporary impairment in value of the Campeche occurred during 2005 and a $20 million impairment charge was recorded to write down the investment to its estimated fair value. In the second quarter of 2006, International Energy recorded an additional $55 million other-than-temporary impairment charge. The current GCSA expired on October 26, 2006 and a nine month extension was executed on November 2, 2006. In the second quarter of 2006, based on ongoing discussions with PEMEX, it was determined that there was a limited future need for Campeche’s gas compression services. Management of International Energy determined that it is probable that the Campeche investment will ultimately be sold or the GCSA will be renewed for a significantly lower rate. An other-than-temporary impairment loss was recorded to reduce the carrying value to management’s best estimate of realizable value. The charges consist of a $17 million impairment of the carrying value of the equity method investment and a $38 million reserve against notes receivable from Campeche. The facility ownership will transfer to PEMEX in August 2007. The carrying value of the note at September 30, 2006 was $17 million, which is management’s best estimate of the net realizable value of the note receivable from Campeche. An additional impairment charge could be recognized in the future if the outcome of the above discussions is materially different than management’s current expectations.

The Bolivian government has announced plans to nationalize its energy infrastructure. As a result, management is currently monitoring the potential impact on its 50 percent interest in Corani. Depending upon future actions of the Bolivian government, Duke Energy’s investment in Corani could become impaired. Additionally, Duke Energy is evaluating various options related to certain of its operations, principally in Bolivia and Ecuador, which could include the sale or other disposition of these operations. Impairments or losses could be recognized in future periods if Duke Energy decides to pursue such a sale or disposition of any of these operations.

Year Ended December 31, 2004 as Compared to December 31, 2003

Operating Revenues. The increase was driven primarily by:

• A $32 million increase due to the fourth quarter 2003 completion of the 160 MW Planta Arizona expansion in Guatemala

• A $22 million increase in volumes due to higher electricity dispatch in Ecuador as a result of unplanned outages at competing generators

• A $20 million increase in Brazil resulting from higher contracted sales prices of $26 million which were positively impacted by inflation adjustments primarily offset by the impact of a 2003 regulatory audit revenue adjustment

• A $12 million increase due to higher electricity prices caused by low water availability in Peru

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• A $12 million increase due to favorable exchange rates primarily in Brazil, partially offset by

• A $48 million decrease in Guatemala and El Salvador due to decreased cross border power marketing activity resulting from unfavorable market conditions, and

• A $33 million decrease in natural gas sales due to the termination of a natural gas sales contract from the liquefied natural gas business in 2003.

Operating Expenses. The increase was driven primarily by:

• A $23 million increase due to the fourth quarter 2003 completion of the 160 MW Planta Arizona expansion in Guatemala as discussed above

• A $21 million increase in electricity generation costs resulting from higher levels of dispatch in Ecuador as described above

• An $18 million increase due to a reserve reduction in 2003 related to the early termination of a natural gas sales contract from the liquefied natural gas business

• A $17 million increase in Peru power purchases to satisfy sale contract requirements caused by decreased generation as a result of low water availability

• A $14 million increase due to general and administrative expenses primarily due to higher corporate allocations and Sarbanes-Oxley compliance costs

• A $12 million increase in Brazil due primarily to increased transmission fees and other costs offset by an environmental charge recorded in 2003 and a reduction in the environmental reserves in 2004, partially offset by

• A $42 million decrease in spot market purchases in Guatemala and El Salvador due to decreased cross border power marketing activity

• A $37 million decrease in natural gas sales purchases due to the termination of a natural gas sales contract from the LNG business in 2003, and

• A $13 million charge associated with the disposition of the ownership share in the Cantarell nitrogen facility in Mexico.

Other Income, net of expenses. The increase was primarily the result of:

• An $11 million increase due to a 2003 adjustment related to revenue recognition for the Cantarell equity investment, and

• A $6 million increase due to favorable netback pricing at NMC.

EBIT. EBIT increased modestly in 2004 compared to 2003. The slight increase was due to the factors described above.

Crescent

	Years Ended December 31,
	2005		2004			Variance 2005 vs 2004			2003		Variance 2004 vs 2003
	(in millions)
Operating revenues	$	495	$	437		$	58		$	284	$	153
Operating expenses		399		393			6			231		162
Gains on sales of investments in commercial and multi-family real estate		191		192			(1	)		84		108
Operating income		287		236			51			137		99
Other income, net of expenses		44		3			41			—		3
Minority interest (benefit) expense		17		(1	)		18			3		(4	)
EBIT	$	314	$	240		$	74		$	134	$	106

Year Ended December 31, 2005 as Compared to December 31, 2004

Operating Revenues. The increase was driven primarily by a $64 million increase in residential developed lot sales, due to increased sales at the Palmetto Bluff project in Bluffton, South Carolina and the LandMar affiliate in Northeastern and Central Florida.

Operating Expenses. The increase was driven primarily by a $30 million increase in the cost of residential developed lot sales, due to increased developed lot sales at the projects noted above along with an $11 million increase in corporate administrative expense as a result of increased incentive compensation tied to increased operating results. The increases were offset by a $16 million impairment charge in 2005 related to the Oldfield residential project near Beaufort, South Carolina as compared to $50 million in impairment and bad debt charges in 2004 related to the Twin Creeks residential project in Austin, Texas and The Rim project in Payson, Arizona.

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Gains on Sales of Investments in Commercial and Multi-Family Real Estate. The decrease was driven primarily by:

• A $37 million increase in multi-family sales primarily due to the $15 million gain on a land sale in Charlotte, North Carolina and a $19 million gain on a project sale in Jacksonville, Florida

• A $32 million increase in surplus land sales primarily due to a $42 million gain from a large land sale in Lancaster County, South Carolina, partially offset by

• A $37 million decrease in real estate land sales primarily due to the $45 million gain on the sale of the Alexandria tract in the Washington, D.C. area in 2004, and

• A $33 million decrease in commercial project sales primarily due to the $20 million gain on the sale of a commercial project in the Washington, D.C. area in 2004.

Other Income, net of expenses. The increase was primarily due to $45 million in income related to a distribution from an interest in a portfolio of commercial office buildings in the third quarter of 2005.

Minority Interest (Benefit) Expense. The increase in minority interest (benefit) expense is primarily due to increased earnings from the LandMar affiliate.

EBIT. The increase was primarily due to income related to a distribution from an interest in a portfolio of commercial office buildings, a large land sale in Lancaster County, South Carolina, increased multi-family and residential developed lot sales offset by a decrease in commercial land and project sales due primarily to the sale of a commercial project and the Alexandria tract in the Washington, D.C. area in 2004.

Matters Impacting Future Crescent Results

While Crescent regularly refreshes its property holdings, 2005 results reflected opportunistic real estate sales which resulted in strong earnings during 2005. While future results are difficult to predict, Crescent expects segment EBIT in 2006 to return to a level approximating 2004 segment EBIT. Segment results at Crescent are ultimately subject to volatility as a result of management’s portfolio allocation decisions, the strength of the real estate markets, the cost of construction materials, and changes in interest rates. When property management or other significant continuing involvement is not retained by Crescent after the sale of an operating property, the transaction is recorded in discontinued operations.

In September 2006, Duke Energy closed an agreement to create a joint venture of Crescent and sold an effective 50% interest in Crescent to the MS Members. In conjunction with the formation of the Crescent JV, the joint venture, Crescent and Crescent’s subsidiaries entered into a credit agreement with third party lenders under which Crescent borrowed approximately $1.23 billion, of which $1.19 billion was immediately distributed to Duke Energy. Subsequent to the sale, Duke Energy deconsolidated its investment in the Crescent JV and has accounted for the investment under the equity method of accounting. The combination of Duke Energy’s reduction in ownership and the increased interest expense at Crescent JV as a result of the debt transaction, the impacts of which will be reflected in Duke Energy’s future equity earnings, will likely significantly impact the amount of equity earnings of the Crescent JV that Duke Energy will recognize in future periods. Since the Crescent JV will capitalize interest as a component of project costs, the impacts of the interest expense on Duke Energy’s equity earnings will be recognized as projects are sold by the Crescent JV.

Year Ended December 31, 2004 as Compared to December 31, 2003

Operating Revenues. The increase was driven primarily by a $160 million increase in residential developed lot sales, due to increased sales at the LandMar division in Northeastern and Central Florida, the Palmetto Bluff project in Bluffton, South Carolina, The Sanctuary project near Charlotte, North Carolina, the Lake James projects in Northwestern North Carolina and the Lake Keowee projects in Northwestern South Carolina.

Operating Expenses. The increase was driven primarily by a $101 million increase in the cost of residential developed lot sales, due to increased developed lot sales at the projects noted above, $50 million in impairments and other related charges (net of $12 million minority interest as discussed below) related to Twin Creeks, Texas and Payson, Arizona residential development projects and a $26 million increase in corporate administrative expense as a result of increased incentive compensation tied to increased operating results. (See Note 12 to the Consolidated Financial Statements, “Impairments, Severance, and Other Charges” for further discussion of Crescent’s impairments.)

Gains on Sales of Investments in Commercial and Multi-Family Real Estate. The increase was driven primarily by:

• A $63 million increase in real estate land sales due primarily to the sale of the Alexandria and Arlington land tracts in the Washington, D.C. area in 2004,

• A $31 million increase in commercial project sales, resulting primarily from the sale of a commercial project in the Washington, D.C. area in March 2004, and

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• A $16 million increase in land management or “legacy” land sales, due to several large sales closed in the first quarter of 2004.

Minority Interest (Benefit) Expense. The increase in minority interest (benefit) expense is primarily due to $12 million of benefit related to impairment and bad debt charges at the Payson, Arizona project as noted above offset by an additional $8 million in minority interest expense related to increased earnings from the LandMar division.

EBIT. As discussed above, the increase in EBIT was driven primarily by an increase in residential developed lot sales and commercial project sales, the sale of the Washington, D.C. area land tracts and an increase in “legacy” land sales.

Other

	Years Ended December 31,
	2005			2004			Variance 2005 vs 2004			2003			Variance 2004 vs 2003
	(in millions)
Operating revenues	$	557		$	1,134		$	(577	)	$	1,627		$	(493	)
Operating expenses		1,041			1,319			(278	)		2,435			(1,116	)
(Losses) gains on sales of other assets, net		8			(64	)		72			(190	)		126
Operating loss		(476	)		(249	)		(227	)		(998	)		749
Other (loss) income, net of expenses		(48	)		41			(89	)		232			(191	)
Minority interest expense		3			(25	)		28			(106	)		81
EBIT	$	(527	)	$	(183	)	$	(344	)	$	(660	)	$	477

Year Ended December 31, 2005 as Compared to December 31, 2004

Operating Revenues. The decrease was driven primarily by:

• A $465 million decrease in revenues as a result of the continued wind-down of DEM, and

• An approximate $130 million decrease as a result of the realized and unrealized mark-to-market impact of certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk (see Note 8 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments”).

Operating Expenses. The decrease was driven primarily by:

• A $455 million decrease in expenses as a result of the continued wind-down of DEM, partially offset by

• An approximate $75 million charge to increase liabilities associated with mutual insurance companies in 2005

• A $64 million increase as a result of the 2004 correction of an immaterial accounting error in prior periods related to reserves at Bison attributable to property losses at several Duke Energy subsidiaries, and

• A $26 million increase in corporate governance costs in 2005.

(Losses) Gains on Sales of Other Assets, net. The 2004 loss was due primarily to approximately $65 million ($39 million net of minority interest expense) of pre-tax losses associated with the sale and terminations of DETM contracts, partially offset by an approximate $13 million gain on the sale of DEM’s 15% investment in Caribbean Nitrogen Company (an ammonia plant in Trinidad) in 2004.

Other (Loss) Income, net of expenses. The decrease was driven primarily by an approximate $64 million decrease as a result of the realized and unrealized mark-to-market impact on discontinued hedges related to the DEFS disposition transaction. (See Note 8 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments.”)

Minority Interest Expense. The change was due primarily to the continued wind-down of DETM.

EBIT. The decrease was due primarily to the realized and unrealized mark-to-market impact of certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk, the reversal of insurance reserves at Bison in 2004 and the increase in liabilities associated with mutual insurance companies.

Matters Impacting Future Other Results

Future Other results will be subject to volatility as a result of the change in mark-to-market of certain Field Services commodity price risk contracts subsequent to the discontinuance of hedge accounting in the first quarter of 2005. The fair value of these contracts as of December 31, 2005 was a liability of approximately $130 million. As these contracts settle, principally in 2006, Duke Energy will realize an offset to equity in earnings of unconsolidated affiliates at Field Services. Additionally, future impacts due to losses insured by Bison and changes in liabilities associated with mutual insurance companies, and the impact of former DENA’s continuing operations (primarily DETM) could impact future earnings for Other.

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Year Ended December 31, 2004 as Compared to December 31, 2003

Operating Revenues. The decrease was driven primarily by:

• A $337 million decrease in revenues as a result of the continued wind-down of DEM, and

• A $162 million decrease due to the sale of Energy Delivery Services (EDS) in December 2003.

Operating Expenses. The decrease was driven primarily by:

• A $405 million decrease in expense as a result of the continued wind-down of DEM

• A $221 million goodwill impairment charge recognized in 2003 related to the trading and marketing business

• An approximate $190 million decrease in general and administrative expense, primarily due to the impact of workforce reductions and associated office costs, travel and other benefits, reduced consulting costs and lower governance costs. A 2003 $28 million Commodity Futures Trading Commission (CFTC) settlement ($17 million net of minority interest expense) and 2003 severance costs

• A $150 million decrease as a result of the sale of EDS in December 2003

• A $113 million decrease related primarily to 2003 impairments associated with a plan to sell Bayside, an unconsolidated affiliate (approximately $60 million) and a write-off related to a corporate risk management information system that was abandoned (approximately $51 million), and

• A $64 million decrease in 2004 as a result of the correction of an immaterial accounting error in prior periods related to reserves at Bison attributable to property losses at several Duke Energy subsidiaries

(Losses) Gains on Sales of Other Assets, net. The 2004 loss was due primarily to an approximately $65 million ($39 million net of minority interest expense) of pre-tax losses related to the liquidation of contractual positions in connection with the continued wind-down of DETM’s operations, partially offset by an approximate $13 million gain on the sale of DEM’s 15% investment in Caribbean Nitrogen Company (an ammonia plant in Trinidad). The 2003 loss was due primarily to approximately $127 million of DETM pre-tax charges related the sale of contracts and an approximate $66 million pre-tax loss on the sale of turbines.

Other (Loss) Income, net of expenses. The decrease was driven primarily by an approximate $178 million pre-tax gain in 2003 from the sale of a 50% interest in Ref-Fuel and the associated foregone equity earnings of $22 million.

Minority Interest Expense. The change was due primarily to the continued wind-down of DETM.

EBIT. EBIT increased in 2004 compared to 2003 primarily due to the wind-down of DEM and DETM, the reversal of insurance reserves at Bison, and other reductions in operating expense.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The application of accounting policies and estimates is an important process that continues to evolve as Duke Energy’s operations change and accounting guidance evolves. Duke Energy has identified a number of critical accounting policies and estimates that require the use of significant estimates and judgments.

Management bases its estimates and judgments on historical experience and on other various assumptions that they believe are reasonable at the time of application. The estimates and judgments may change as time passes and more information about Duke Energy’s environment becomes available. If estimates and judgments are different than the actual amounts recorded, adjustments are made in subsequent periods to take into consideration the new information. Duke Energy discusses its critical accounting policies and estimates and other significant accounting policies with senior members of management and the audit committee, as appropriate. Duke Energy’s critical accounting policies and estimates are listed below.

Risk Management Accounting

Duke Energy uses two comprehensive accounting models for its risk management activities in reporting its consolidated financial position and results of operations: the MTM Model and the Accrual Model. As further discussed in Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” the MTM Model is applied to trading and undesignated non-trading derivative contracts, and the Accrual Model 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. For the three years ended December 31, 2005, the determination as to which model was appropriate was primarily based on accounting guidance issued by the Financial Accounting Standards Board (FASB) and the EITF. Effective January 1, 2003, Duke Energy adopted EITF 02-03. While the implementation of such guidance changed the accounting model used for certain of Duke Energy’s transactions, especially non-derivative energy trading contracts, the overall application of the models remained the same.

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As a result of the September, 2005 decision to pursue the sale or other disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States, Duke Energy discontinued hedge accounting for forward natural gas and power contracts accounted for as cash flow hedges and disqualified other forward power contracts previously designated under the normal purchases normal sales exception effective September, 2005.

Under the MTM Model, an asset or liability is recognized at fair value on the Consolidated Balance Sheets and the change in the fair value of that asset or liability is recognized in the Consolidated Statements of Operations during the current period. While DENA was the primary business that used this accounting model, the U.S. Franchised Electric and Gas and Field Services segments, as well as Other, also have certain transactions subject to this model. For the years ended December 31, 2005, 2004 and 2003, Duke Energy applied the MTM Model to its derivative contracts, unless subject to hedge accounting or the normal purchase and normal sale exemption (as described below).

The MTM Model is applied within the context of an overall valuation framework. All new and existing transactions are valued using approved valuation techniques and market data, and discounted using a London Interbank Offered Rate (LIBOR) based interest rate. When available, quoted market prices are used to measure a contract’s fair value. However, market quotations for certain energy contracts may not be available for illiquid periods or locations. If no active trading market exists for a commodity or for a contract’s duration, holders of these contracts must calculate fair value using internally developed valuation techniques or models. Key components used in these valuation techniques include price curves, volatility, correlation, interest rates and tenor. While volatility and correlation are the most subjective components, the price curve is generally the most significant component affecting the ultimate fair value for a contract subject to the MTM Model, especially after implementation of EITF 02-03 due to the discontinuation of the MTM Model for certain energy trading contracts, such as transportation agreements. Prices for illiquid periods or locations are established by extrapolating prices for correlated products, locations or periods. These relationships are routinely re-evaluated based on available market data, and changes in price relationships are reflected in price curves prospectively. Consideration may also be given to the analysis of market fundamentals when developing illiquid prices. A deviation in any of the components affecting fair value may significantly affect overall fair value.

Valuation adjustments for performance and market risk, and administration costs are used to arrive at the fair value of the contract and the gain or loss ultimately recognized in the Consolidated Statements of Operations. While Duke Energy uses common industry practices to develop its valuation techniques, changes in Duke Energy’s pricing methodologies or the underlying assumptions could result in significantly different fair values and income recognition. However, due to the nature and number of variables involved in estimating fair values, and the interrelationships among these variables, sensitivity analysis of the changes in any individual variable is not considered to be relevant or meaningful.

Validation of a contract’s calculated fair value is performed by an internal group independent of Duke Energy’s trading areas. This group performs pricing model validation, back testing and stress testing of valuation techniques, prices and other variables. Validation of a contract’s fair value may be done by comparison to actual market activity and negotiation of collateral requirements with third parties.

For certain derivative instruments Duke Energy applies either hedge accounting or the normal purchase and normal sales exemption in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” The use of hedge accounting and the normal purchase and normal sales exemption provide effectively for the use of the Accrual Model. Under this model, there is generally no recognition in the Consolidated Statements of Operations for changes in the fair value of a contract until the service is provided or the associated delivery period occurs (settlement).

Hedge accounting treatment is used when Duke Energy contracts to buy or sell a commodity such as natural gas at a fixed price for future delivery corresponding with anticipated physical sales or purchase of natural gas (cash flow hedge). In addition, hedge accounting treatment is used when Duke Energy holds firm commitments or asset positions and enters into transactions that “hedge” the risk that the price of a commodity, such as natural gas or electricity, may change between the contract’s inception and the physical delivery date of the commodity (fair value hedge). To the extent that the fair value of the hedge instrument offsets the transaction being hedged, there is no impact to the Consolidated Statements of Operations prior to settlement of the hedge. However, as not all of Duke Energy’s hedges relate to the exact location being hedged, a certain degree of hedge ineffectiveness may be recognized in the Consolidated Statements of Operations.

The normal purchases and normal sales exception, as provided in SFAS No. 133 as amended and interpreted by Derivative Implementation Group (DIG) Issue C15, “Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity,” and amended by SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” indicates that no recognition of the contract’s fair value in the Consolidated Financial Statements is required until settlement of the contract (in Duke Energy’s case, the delivery of power). Previously, Duke Energy applied this exception for certain contracts involving the sale of power in future periods. SFAS No. 149 includes certain modifications and changes to the applicability of the normal purchase and normal sales scope exception for contracts to deliver electricity. As a result, Duke Energy reevaluated its policy for accounting for forward power sale contracts and determined that the majority of all forward contracts to sell power entered into after July 1, 2003 will be designated as cash flow hedges. However, on a limited basis, Duke Energy Carolinas applies the normal purchase and normal sales

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exception to certain contracts. To the extent that the hedge is perfectly effective, income statement recognition for the contract will be the same under either model.

In addition to derivative contracts that are accounted for as cash flow hedges, fair value hedges, and normal purchases or sales, the Accrual Model also encompasses non-derivative contracts used for commodity risk management purposes. For these non-derivative contracts, there is no recognition in the Consolidated Statements of Operations until the service is provided or delivery occurs.

For additional information regarding risk management activities, see Quantitative and Qualitative Disclosures about Market Risk. The Quantitative and Qualitative Disclosures about Market Risk include daily earnings at risk information related to commodity derivatives recorded using the MTM Model and an operating income sensitivity analysis related to hypothetical changes in certain commodity prices recorded using the Accrual Model.

Regulatory Accounting

Duke Energy accounts for certain of its regulated operations (primarily U.S. Franchised Electric and Gas and Natural Gas Transmission) under the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” As a result, Duke Energy records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections for costs that either are not likely to or have yet to be incurred. Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes, recent rate orders to other regulated entities, and the status of any pending or potential deregulation legislation. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. This assessment reflects the current political and regulatory climate at the state, provincial and federal levels, and is subject to change in the future. If future recovery of costs ceases to be probable, the asset write-offs would be required to be recognized in operating income. Total regulatory assets were $2,319 million as of December 31, 2005 and $2,146 million as of December 31, 2004. Total regulatory liabilities were $2,338 million as of December 31, 2005 and $2,375 million as of December 31, 2004. (See Note 4 to the Consolidated Financial Statements, “Regulatory Matters.”)

Long-Lived Asset Impairments and Assets Held For Sale

Duke Energy evaluates the carrying value of long-lived assets, excluding goodwill, when circumstances indicate the carrying value of those assets may not be recoverable. For long-lived assets, impairment would exist when the carrying value exceeds the sum of estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset is impaired, the asset’s carrying value is adjusted to its estimated fair value. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, a probability-weighted approach is used for developing estimates of future cash flows.

Duke Energy uses the best information available to estimate fair value of its long-lived assets and may use more than one source. Judgment is exercised to estimate the future cash flows, the useful lives of long-lived assets and to determine management’s intent to use the assets. The sum of undiscounted cash flows is primarily dependent on forecasted commodity prices for sales of power, natural gas or NGL, costs of fuel over periods of time consistent with the useful lives of the assets or changes in the real estate market. Management’s intent to use or dispose of assets is subject to re-evaluation and can change over time.

A change in Duke Energy’s plans regarding, or probability assessments of, holding or selling an asset could have a significant impact on the estimated future cash flows. Duke Energy considers various factors when determining if impairment tests are warranted, including but not limited to:

• Significant adverse changes in legal factors or in the business climate;

• A current-period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset;

• An accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;

• Significant adverse changes in the extent or manner in which an asset is used or in its physical condition or a change in business strategy;

• A significant change in the market value of an asset; and

• A current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.

Judgment is also involved in determining the timing of meeting the criteria for classification as an asset held for sale under SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” (SFAS No. 144)

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During 2005, Duke Energy recorded impairments on several of its long-lived assets. (For additional discussion of these impairments, see Note 12 to the Consolidated Financial Statements, “Impairments, Severance and Other Charges.”)

Duke Energy may dispose of certain other assets in addition to the assets classified as held for sale at December 31, 2005. Accordingly, based in part on current market conditions in the merchant energy industry, it is reasonably possible that Duke Energy’s current estimate of fair value of its long-lived assets being considered for sale at December 31, 2005 and its other long-lived assets, could change and that change may impact the consolidated results of operations. In addition, Duke Energy could decide to dispose of additional assets in future periods, at prices that could be less than the book value of the assets.

Duke Energy uses the criteria in SFAS No. 144 and EITF 03-13, “Applying the Conditions in Paragraph 42 of FAS 144 in Determining Whether to Report Discontinued Operations,” to determine whether components of Duke Energy that are being disposed of or are classified as held for sale are required to be reported as discontinued operations in the Consolidated Statements of Operations. To qualify as a discontinued operation under SFAS No. 144, the component being disposed of must have clearly distinguishable operations and cash flows. Additionally, pursuant to EITF 03-13, Duke Energy must not have significant continuing involvement in the operations after the disposal (i.e. Duke Energy must not have the ability to influence the operating or financial policies of the disposed component) and cash flows of the assets sold must have been eliminated from Duke Energy’s ongoing operations (i.e. Duke Energy does not expect to generate significant direct cash flows from activities involving the disposed component after the disposal transaction is completed). Assuming both preceding conditions are met, the related results of operations for the current and prior periods, including any related impairments, are reflected as (Loss) Income From Discontinued Operations, net of tax, in the Consolidated Statements of Operations. If an asset held for sale does not meet the requirements for discontinued operations classification, any impairments and gains or losses on sales are recorded in continuing operations as Gains (Losses) on Sales of Other Assets, net, in the Consolidated Statements of Operations. Impairments for all other long-lived assets, other than goodwill, are recorded as Impairment and Other Charges in the Consolidated Statements of Operations.

Impairment of Goodwill

At December 31, 2005 and 2004, Duke Energy had goodwill balances of $3,775 million and $4,148 million, respectively. Duke Energy evaluates the impairment of goodwill under SFAS No. 142, “Goodwill and Other Intangible Assets.” The majority of Duke Energy’s goodwill at December 31, 2005 relates to the acquisition of Westcoast in March 2002, whose assets were primarily included within the Natural Gas Transmission segment. The remainder relates to International Energy’s Latin American operations and Crescent. As of the acquisition date, Duke Energy allocates goodwill to a reporting unit, which Duke Energy defines as an operating segment or one level below an operating segment. As required by SFAS No. 142, Duke Energy performs an annual goodwill impairment test and updates the test if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Key assumptions used in the analysis include, but are not limited to, the use of an appropriate discount rate, estimated future cash flows and estimated run rates of operation, maintenance, and general and administrative costs. In estimating cash flows, Duke Energy incorporates expected growth rates, regulatory stability and ability to renew contracts as well as other factors into its revenue and expense forecasts. As a result of the 2005 impairment test required by SFAS No. 142, Duke Energy did not record any impairment on its goodwill. Had the discount rate used to determine fair value of the reporting units been 1% lower, there would still not have been any impairment recorded in 2005. In the third quarter of 2003, Duke Energy recorded a $254 million goodwill impairment charge to write off all of the goodwill related to the former DENA operations, most of which related to certain aspects of the trading and marketing business, and was recorded as a component of continuing operations. This impairment charge reflected the reduction in scope and scale of DETM’s business and the continued deterioration of market conditions affecting merchant generation operations during 2003. Duke Energy used a discounted cash flow analysis utilizing the key assumptions described above to perform the analysis.

Management continues to remain alert for any indicators that the fair value of a reporting unit could be below book value and will assess goodwill for impairment as appropriate.

Revenue Recognition

Unbilled and Estimated Revenues. Revenues on sales of electricity, primarily at U.S. Franchised Electric and Gas, are recognized when the service is provided. Unbilled revenues are estimated by applying an average revenue/kilowatt hour for all customer classes to the number of estimated kilowatt hours delivered but not billed. Differences between actuals and estimates are immaterial and are a result of customer mix.

Revenues on sales of natural gas, natural gas transportation, storage and distribution as well as sales of petroleum products, primarily at Natural Gas Transmission and Field Services (prior to deconsolidation on July 1, 2005), are recognized when either the service is provided or the product is delivered. Revenues related to these services provided or products delivered but not yet billed are estimated each month. These estimates are generally based on contract data, regulatory information, estimated distribution usage based on histor -

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ical data adjusted for heating degree days, commodity prices and preliminary throughput and allocation measurements. Final bills for the current month are billed and collected in the following month. Differences between actuals and estimates are immaterial.

Trading and Marketing Revenues. The recognition of income in the Consolidated Statements of Operations for derivative activity is primarily dependent on whether the Accrual Model or MTM Model is applied. Prior to January 1, 2003, Duke Energy applied the MTM Model to certain derivative contracts and certain contracts classified as energy trading pursuant to EITF 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” With the implementation of EITF 02-03, use of the MTM Model has been restricted to contracts classified as derivatives pursuant to SFAS No. 133. Contracts classified previously as energy trading that do not meet the definition of a derivative are subject to the Accrual Model. While the MTM Model is the default method of accounting for all SFAS No. 133 derivatives, SFAS No. 133 allows for the use of the Accrual Model for derivatives designated as hedges and certain scope exceptions, including the normal purchase and normal sale exception. Duke Energy designates a derivative as a hedge or a normal purchase or normal sale contract in accordance with internal hedge guidelines and the requirements provided by SFAS No. 133. (For further information regarding the Accrual Model or MTM Model, see Risk Management Accounting above. For further information regarding the presentation of gains and losses or revenue and expense in the Consolidated Statements of Operations, see Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies”.)

Pension and Other Post-Retirement Benefits

Duke Energy and its subsidiaries maintain a non-contributory defined benefit retirement plan. It covers most U.S. employees using a cash balance formula. Under a cash balance formula, a plan participant accumulates a retirement benefit consisting of pay credits that are based upon a percentage (which may vary with age and years of service) of current eligible earnings and current interest credits. Duke Energy and most of its subsidiaries also provide some health care and life insurance benefits for retired employees on a contributory and non-contributory basis. Employees are eligible for these benefits if they have met age and service requirements at retirement, as defined in the plans.

Westcoast and its subsidiaries maintain contributory and non-contributory defined benefit (DB) and defined contribution (DC) retirement plans covering substantially all employees. The DB plans provide retirement benefits based on each plan participant’s years of service and final average earnings. Under the DC plans, company contributions are determined according to the terms of the plan and based on each plan participant’s age, years of service and current eligible earnings. Westcoast also provides health care and life insurance benefits for retired employees on a non-contributory basis. Employees are eligible for these benefits if they have met age and service requirements at retirement, as defined in the plans. Effective December 31, 2003, a new plan was implemented for all non bargaining employees and the majority of bargaining employees. The new plan will apply to employees retiring on and after January 1, 2006. The new plan is predominantly a defined contribution plan as compared to the existing defined benefit program.

Duke Energy accounts for its defined benefit pension plans using SFAS No. 87, “Employers’ Accounting for Pensions,” (SFAS No. 87). Under SFAS No. 87, pension income/expense is recognized on an accrual basis over employees’ approximate service periods. Other post-retirement benefits are accounted for using SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” (SFAS No. 106). (See Note 22 to the Consolidated Financial Statements, “Employee Benefit Plans.”)

Funding requirements for defined benefit plans are determined by government regulations, not SFAS No. 87. No contributions to the Duke Energy plan were necessary in 2005. Duke Energy made voluntary contributions of $250 million in 2004 and $181 million in 2003 to its U.S. defined benefit retirement plan. Duke Energy does not anticipate making a contribution to the plan in 2006. Duke Energy made contributions to the Westcoast DB plans of approximately $42 million in 2005, $26 million in 2004 and $10 million in 2003. Duke Energy anticipates that it will make contributions of approximately $40 million to the Westcoast DB plans in 2006. Duke Energy made contributions to the Westcoast DC plans of approximately $3 million in 2005, $3 million in 2004 and $3 million in 2003. Duke Energy anticipates that it will make contributions of approximately $4 million to the Westcoast DC plans in 2006.

The calculation of pension expense, other post-retirement expense and Duke Energy’s pension and other post-retirement liabilities require the use of assumptions. Changes in these assumptions can result in different expense and reported liability amounts, and future actual experience can differ from the assumptions. Duke Energy believes that the most critical assumptions for pension and other post-retirement benefits are the expected long-term rate of return on plan assets and the assumed discount rate. Additionally, the health care trend rate assumption is critical for other post-retirement benefits.

Duke Energy recognized pre-tax pension cost of $23 million and pre-tax other post-retirement benefits expense of $57 million in 2005. Westcoast recognized pre-tax pension expense of $16 million and pre-tax other post-retirement benefits expense of $9 million in 2005. In 2006, Duke Energy’s U.S. pension expense is expected to be approximately $47 million due to lower than expected asset returns from 2001 and 2002 being amortized into expense over a five year period elected as allowed under SFAS No. 87. Westcoast’s pension expense is expected to be $22 million in 2006. Duke Energy’s other U.S. and other Westcoast plans do not expect material changes from the expense of 2005.

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For both pension and other post-retirement plans, Duke Energy assumed that its U.S. plan’s assets would generate a long-term rate of return of 8.5% as of September 30, 2005. The assets for Duke Energy’s U.S. pension and other post retirement plans are maintained by a master trust. The investment objective of the master trust is to achieve reasonable returns on trust assets, subject to a prudent level of portfolio risk, for the purpose of enhancing the security of benefits for plan participants. The asset allocation target was set after considering the investment objective and the risk profile with respect to the trust. U.S. equities are held for their high expected return. Non-U.S. equities, debt securities, and real estate are held for diversification. Investments within asset classes are to be diversified to achieve broad market participation and reduce the impact of individual managers or investments. Duke Energy regularly reviews its actual asset allocation and periodically rebalances its investments to its targeted allocation when considered appropriate.

The expected long-term rate of return of 8.5% for the Duke Energy U.S. assets was developed using a weighted average calculation of expected returns based primarily on future expected returns across asset classes considering the use of active asset managers. The weighted average returns expected by asset classes were 4.2% for U.S. equities, 1.9% for Non U.S. equities, 2.0% for fixed income securities, and 0.4% for real estate.

If Duke Energy had used a long-term rate of 8.25% in 2005, pre-tax pension expense would have been higher by approximately $7 million and pre-tax other post-retirement expense would have been higher by approximately $1 million. If Duke Energy had used a long-term rate of 8.75% pre-tax pension expense would have been lower by approximately $7 million and pre-tax other post-retirement expense would have been lower by approximately $1 million.

The expected long-term rate of return for the Westcoast plans assets was 7.25% as of September 30, 2005. The Westcoast plans assets for registered pension plans are maintained by a master trust. The investment objective of the master trust is to achieve reasonable returns on trust assets, subject to a prudent level of portfolio risk, for the purpose of enhancing the security of benefits for plan participants. The asset allocation target was set after considering the investment objective and the risk profile with respect to the trust. Canadian equities are held for their high expected return. Non-Canadian equities are held for their high expected return as well as diversification relative to Canadian equities and debt securities. Debt securities are also held for diversification.

The expected long-term rate of return of 7.25% and 7.5% as of September 30, 2005 and 2004, respectively, for the Westcoast assets was developed using a weighted average calculation of expected returns based primarily on future expected returns across asset classes considering the use of active asset managers. The weighted average returns expected by asset classes were 2.7% for Canadian equities, 1.4% for U.S. equities, 1.45% for Europe, Australasia and Far East equities, and 1.7% for fixed income securities. For 2005, the expected long-term rate of return used to calculate pension expense was 7.5%. Lowering the expected rate of return on assets by 0.25% (from 7.5% to 7.25%) would have increased Westcoast’s 2005 pre-tax pension expense by approximately $1 million. Increasing the expected rate of return by 0.25% (from 7.5% to 7.75%) would have decreased Westcoast’s 2005 pre-tax pension expense by approximately $1 million. The Westcoast other post-retirement plan does not hold any assets.

Duke Energy discounted its future U.S. pension and other post-retirement obligations using a rate of 5.50% as of September 30, 2005 and 6.00% as of September 30, 2004. Duke Energy determines the appropriate discount based on a AA bond yield curve. The yield is selected based on bonds with cash flows that match the timing and amount of the expected benefit payments under the plan. For 2005, the discount rate used to calculate pension and other post-retirement expense was 6.00%. Lowering the discount rate by 0.25% (from 6.00% to 5.75%) would have decreased Duke Energy’s 2005 pre-tax pension expense by approximately $3 million. Increasing the discount rate by 0.25% (from 6.00% to 6.25%) would have increased Duke Energy’s 2005 pre-tax pension expense by approximately $3 million. Lowering the discount rate by 0.25% from (6.00% to 5.75%) would have increased Duke Energy’s 2005 pre-tax other post-retirement expense by approximately $1 million. Increasing the discount rate by 0.25% (from 6.00% to 6.25%) would have decreased Duke Energy’s 2005 pre-tax other post-retirement expense by approximately $1 million.

Westcoast discounted its future pension and other post-retirement obligations using a rate of 5.00% as of September 30, 2005 compared to 6.25% as of September 30, 2004. For Westcoast the discount rate used to determine the pension and other post-retirement obligations is prescribed as the yield on Canadian corporate AA bonds at the measurement date of September 30. The yield is selected based on bonds with cash flows that match the timing and amount of the expected benefit payments under the plan. For 2005, the discount rate used to calculate pension expense was 6.25%. Lowering the discount rate by 0.25% (from 6.25% to 6.00%) would have increased Duke Energy’s 2005 pre-tax pension expense by approximately $2 million. Increasing the discount rate by 0.25% (from 6.25% to 6.50%) would have decreased Duke Energy’s 2005 pre-tax pension expense by approximately $2 million. Lowering the discount rate by 0.25% (from 6.25% to 6.00%) would have increased Duke Energy’s 2005 pre-tax other post-retirement expense by approximately $1 million. Increasing the discount rate by 0.25% (from 6.25% to 6.50%) would have decreased Duke Energy’s 2005 pre-tax other post-retirement expense by approximately $1 million.

Duke Energy’s U.S. post-retirement plan uses a health care trend rate which reflects the near and long-term expectation of increases in medical costs. As of September 30, 2005, the health care trend rates were 8.50%, which grades to 5.50% by 2009 for employees who are not eligible for Medicare and 11.5%, which grades to 5.50% by 2012 for employees who are eligible for Medicare. If Duke Energy had used a health care trend rate one percentage point higher, pre-tax other post-retirement expense would have been higher by

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$3 million. If Duke Energy had used a health care trend rate one percentage point lower, pre-tax other post-retirement expense would have been lower by $2 million.

The Westcoast post-retirement plans use a health care trend rate which reflects the near and long-term expectation of increases in medical costs. As of September 30, 2005, the health care trend rates were 7.00%, which grades to 5.00% by 2008. If Westcoast had used a health care trend rate one percentage point higher, pre-tax other post-retirement expense would have been higher by $1 million. If Westcoast had used a health care trend rate one percentage point lower, pre-tax other post-retirement expense would have been lower by less than $1 million.

Future changes in plan asset returns, assumed discount rates and various other factors related to the participants in Duke Energy’s pension and post-retirement plans will impact Duke Energy’s future pension expense and liabilities. Management cannot predict with certainty what these factors will be in the future.

LIQUIDITY AND CAPITAL RESOURCES

Known Trends and Uncertainties

Duke Energy will rely primarily upon cash flows from operations to fund its liquidity and capital requirements for 2006. Also Duke Energy expects net positive cash flows from asset sales and other transaction settlements related to exiting the former DENA operations. The cash flows from these transactions along with current cash, cash equivalents and short-term investments and future cash generated from operations may be used by Duke Energy to continue with its February 2005 announced plan to periodically repurchase up to an aggregate of $2.5 billion of common stock over a three year period. In May 2005, in connection with the anticipated merger with Cinergy, Duke Energy announced plans to suspend additional repurchases under the open market purchase plan, pending further assessment. Such suspension shall continue at least the shareholder vote on the Cinergy merger is completed. Duke Energy may conduct further common stock repurchases before or after the closing of the merger with Cinergy. A material adverse change in operations or available financing may impact Duke Energy’s ability to fund its current liquidity and capital resource requirements.

Duke Energy currently anticipates net cash provided by operating activities in 2006 to be impacted by the following:

• The return of collateral as a result of finalizing the transaction with Barclays to transfer or novate a significant portion of DENA’s derivative portfolio to Barclays compared to significant collateral outflows in 2005;

• Payment of approximately $600 million to Barclays, which was made in January 2006, as a result of settling the transaction to transfer or novate a significant portion of DENA’s derivative portfolio to Barclays;

• Costs incurred related to the anticipated merger with Cinergy;

• Operating results of Cinergy subsequent to closing the merger; and,

• Tax benefits realized from losses on the DENA asset sales to LS Power and the Barclays transaction as compared to significant tax payments in 2005.

Ultimate cash flows from operations are subject to a number of factors, including, but not limited to, regulatory constraints, economic trends, and market volatility (see Risk Factors for details).

Duke Energy projects 2006 capital and investment expenditures of approximately $4.3 billion, primarily consisting of approximately:

• $1.7 billion at U.S. Franchised Electric and Gas, including $0.4 billion of North Carolina Clean Air Expenditures

• $950 million at Natural Gas Transmission

• $650 million at Crescent, including $0.5 billion of residential real estate capital expenditures

• $950 million at Cinergy

Duke Energy continues to focus on reducing risk and restructuring its business for future success and will invest principally in its strongest business sectors with an overall focus on positive net cash generation. Based on this goal, approximately 80 percent of total projected 2006 capital expenditures are allocated to Natural Gas Transmission, U.S. Franchised Electric and Gas and Crescent, and 20 percent are expected to be allocated to Cinergy subsequent to the closing of the anticipated merger. Total projected 2006 capital and investment expenditures include approximately $3.1 billion for maintenance and upgrades of existing plants, pipelines and infrastructure to serve load growth, which includes approximately $0.9 billion of environmental expenditures, and approximately $1.2 billion of expansion capital expenditures allocated primarily to Crescent and Natural Gas Transmission. Duke Energy received approximately $1.6 billion in pre-tax proceeds from the sale of DENA’s facilities outside of the Midwest to LS Power in 2006.

Duke Energy anticipates its debt to total capitalization ratio to be 46% by the end of 2006, which includes the effect of the Cinergy merger. Duke Energy does not expect its debt balance to change significantly in 2006, excluding the effect of the Cinergy merger, and is considering restarting its stock repurchase program.

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Duke Energy monitors compliance with all debt covenants and restrictions, and does not currently believe that it will be in violation or breach of its debt covenants. However, circumstances could arise that may alter that view. If and when management had a belief that such potential breach could exist, appropriate action would be taken to mitigate any such issue. Duke Energy also maintains an active dialogue with the credit rating agencies, and believes that the current credit ratings have stabilized.

Operating Cash Flows

Net cash provided by operating activities was $2,801 million in 2005 compared to $4,168 million in 2004, a decrease of $1,367 million. The decrease in cash provided by operating activities was due primarily to approximately $750 million of additional net cash collateral posted by Duke Energy during 2005 attributable to increased crude oil prices, as well as increases to the forward market prices of power, an approximate $900 million increase in taxes paid, net of refunds, in 2005, and the impacts of the deconsolidation of DEFS effective July 1, 2005. These decreases were offset by an increase in cash provided due to an approximate $200 million decrease in contributions to company-sponsored pension plans in 2005.

Net cash provided by operating activities was $4,168 million in 2004 compared to $3,404 million in 2003, an increase of $764 million. The increase in cash provided by operating activities was due primarily to higher cash settlements from trading and hedging activities, increased earnings related to Field Services, and increased cash flows in 2004 from changes in working capital related primarily to a cash refund received related to income taxes, which were partially offset by $86 million of increased pension plan contributions in 2004. Duke Energy made a voluntary contribution of $250 million to its U.S. defined benefit pension plan (U.S. plan) and a $28 million voluntary contribution to its Westcoast retirement plans (Westcoast plans) in 2004.

Investing Cash Flows

Net cash used in investing activities was $109 million in 2005 compared to $793 million in 2004, a decrease in cash used of $684 million. Net cash used in investing activities was $793 million in 2004 compared to $676 million in 2003, an increase in cash used of $117 million.

The primary use of cash related to investing activities is capital and investment expenditures, detailed by business segment in the following table.

Capital and Investment Expenditures by Business Segment

	Years Ended December 31,
	2005		2004		2003
	(in millions)
U.S. Franchised Electric and Gas(a)	$	1,332	$	1,126	$	1,015
Natural Gas Transmission		930		544		773
Field Services(d)		86		202		204
Commercial Power		2		7		334
International Energy		23		28		71
Crescent(b)		599		568		290
Other(c)		29		54		(78	)
Total consolidated	$	3,001	$	2,529	$	2,609

(a) Amounts include capital expenditures associated with North Carolina clean-air legislation of $301 in 2005, $106 million in 2004 and $18 million in 2003 which are included in Capital Expenditures within Cash Flows from Investing Activities on the accompanying Consolidated Statements of Cash Flows.

(b) Amounts include capital expenditures associated with residential real estate of $355 million in 2005, $322 million in 2004, and $196 million in 2003 which are included in Capital Expenditures for Residential Real Estate within Cash Flows from Operating Activities on the accompanying Consolidated Statements of Cash Flows.

(c) Amount for 2003 include deferral of the consolidation of 50% of the profit earned by D/FD for the construction of DENA’s merchant generation plants, which is associated with Duke Energy’s share of ownership.

(d) As a result of the deconsolidation of DEFS, effective July 1, 2005, Field Services amounts for 2005 only include DEFS capital and investment expenditures for periods prior to July 1, 2005.

Capital and investment expenditures, including Crescent’s residential real estate investments, increased $472 million in 2005 compared to 2004. The increase was due primarily to the approximate $230 million acquisition of the Empress System at Natural Gas Transmission and an increase of $195 million in expenditures associated with North Carolina clean-air legislation at U.S. Franchised Electric and Gas.

The decrease in cash used in 2005 when compared to 2004 was also impacted by proceeds from the sale of TEPPCO GP and Duke Energy’s interest in TEPPCO LP for approximately $1.2 billion and DEFS disposition transaction proceeds of approximately $1.0 billion received in 2005, offset by the approximate $1.4 billion in proceeds received in 2004 primarily from the sales of the Asia-Pacific Business, Southeast Plants and Moapa and Luna partially completed facilities. Additionally, approximately $383 million of distributions from equity investees (approximately $310 million for Gulfstream and approximately $73 million for DEFS) were considered returns of equity. Also, during 2004, additional amounts of cash were invested in short-term investments.

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Capital and investment expenditures, including Crescent’s residential real estate investments, decreased $80 million in 2004 compared to 2003. The decrease was due primarily to decreased investments in generating facilities at DENA due to the continuing downturn in the merchant energy portion of its business that began in 2002 and decreased investments at Natural Gas Transmission due to the completion of infrastructure projects in Western Canada and New England in 2003 partially offset by an increase in capital expenditures associated with North Carolina clean-air legislation at U.S. Franchised Electric and Gas.

The increase in net cash used in 2004 when compared to 2003 was also impacted by a $292 million increase in proceeds from the sales of commercial and multi-family real estate at Crescent, due primarily to sales of the Potomac Yard retail center and the Alexandria land tract in 2004.

These increases in net cash used were partially offset by a $357 million decrease in net proceeds received from the sales of equity investments and other assets, primarily related to large sales activity in 2003 partially offset by the sale of International Energy’s Asia-Pacific Business, Commercial Power’s sale of its Southeast Plants and former DENA’s sale of the Moapa and Luna partially completed facilities, and Commercial Power’s sale of the Vermillion facilities, in 2004.

Financing Cash Flows and Liquidity

Duke Energy’s consolidated capital structure as of December 31, 2005, including short-term debt, was 48% debt, 50% common equity and 2% minority interests. The fixed charges coverage ratio, calculated using SEC guidelines, was 4.7 times for 2005, which includes a pre-tax gain on the sale of TEPPCO GP and LP of approximately $0.9 billion, net of minority interest, and 2.4 times for 2004. Earnings were inadequate to cover fixed charges by $19 million for the year ended December 31, 2003.

Net cash used in financing activities decreased $561 million for the year ended December 31, 2005, compared to 2004. The change was due primarily to approximately $3.0 billion of higher redemptions, net of paydowns, of long-term debt, commercial paper, notes payable, preferred and preference stock, and preferred stock of a subsidiary during 2004 in connection with an effort to reduce debt balances. This decrease was partially offset by approximately $2.6 billion of lower proceeds from common stock transactions during 2005, primarily driven by the settlement of the forward purchase contract component of Duke Energy’s Equity Units in May and November 2004 for total proceeds of $1.7 billion and the repurchase of 32.6 million shares of common stock for $933 million in 2005.

Net cash used in financing activities increased $621 million for the year ended December 31, 2004, compared to 2003. This change was due primarily to approximately $1.9 billion of higher net paydowns of long-term debt, commercial paper and notes payable in 2004 as compared to 2003, offset by approximately $1.4 billion of higher proceeds from common stock issuances during 2004, driven by the settlement of the forward purchase contract component of Duke Energy’s Equity Units in May and November 2004. Total debt reductions of approximately $4.6 billion in 2004 consisted of $3.9 billion in cash redemptions and approximately $840 million of debt retired (as a non-cash financing activity) as part of the sale of International Energy’s Asia-Pacific Business, which were partially offset by minimal issuances of long-term debt. The $840 million does not include the approximately $50 million of Asia-Pacific debt which was placed in trust and fully funded in connection with the closing of the sale transaction and repaid in September 2004. The assets held in the consolidated trust were received from Alinta, Ltd. as part of the sale of the Asia-Pacific Business.

With cash, cash equivalents and short-term investments on hand at December 31, 2005 of approximately $1.1 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 decision to meet the needs of shareholders and the long-term financial strength of Duke Energy.

Significant Financing Activities. In December 2004, Duke Energy reached an agreement to sell its partially completed Gray’s Harbor power generation facility (Grays Harbor) to an affiliate of Invenergy LLC. In 2004, Duke Energy terminated its capital lease with the dedicated pipeline which would have transported natural gas to Grays Harbor. As a result of this termination, approximately $94 million was paid by Duke Energy in January 2005.

On March 1, 2005, redemption notices were sent to the bondholders of the $100 million PanEnergy 8.625% bonds due in 2025. These bonds were redeemed on April 15, 2005 at a redemption price of 104.03 or approximately $104 million.

During the first quarter of 2005, Duke Energy increased the portion of outstanding commercial paper balances classified as long-term debt from $150 million to $300 million. This non-current classification is due to the existence of long-term credit facilities which back-stop these commercial paper balances along with Duke Energy’s intent to refinance such balances on a long-term basis.

In August 2005, DEI issued project-level debt in Peru, of which $75 million is denominated in U.S. dollars and approximately $34 million (in U.S. dollar equivalents as of the issuance date) is denominated in Peru Nuevos Soles. This debt has terms ranging from four to six years as well as variable or fixed interest rate terms, as applicable.

On September 21, 2005, Union Gas entered into a fixed-rate financing agreement denominated in 200 million Canadian dollars (approximately $171 million in U.S. dollar equivalents as of the issuance date) due in 2016 with an interest rate of 4.64%.

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In November 2005, International Energy issued floating rate debt in Guatemala for $87 million (in USD) and in El Salvador for $75 million (in USD). These debt issuances have variable interest rate terms and mature in 2015.

In connection with the up to $2.5 billion share repurchase program announced in February 2005, Duke Energy entered into an accelerated share repurchase transaction. Duke Energy repurchased and retired 30 million shares of its common stock from an investment bank at the March 18, 2005 closing price of $27.46 per share. The final settlement with the investment bank occurred on September 22, 2005 for approximately $25 million in cash. The final settlement price was the difference between the initial settlement price of $27.46 per share and the volume weighted average price per share of actual shares purchased by the investment bank of $28.42 per share. Duke Energy also entered into a separate open-market purchase plan with the investment bank on March 18, 2005 to repurchase up to an additional 20 million shares of its common stock through December 27, 2005. As of May 9, 2005 (the date Duke and Cinergy announced a merger agreement), Duke Energy had already repurchased 2.6 million shares of its common stock through the separate open-market purchase plan at a weighted average price of $28.97 per share. In May 2005, in connection with the anticipated merger with Cinergy, Duke Energy announced plans to suspend additional repurchases under the open market purchase plan, pending further assessment. Such suspension shall continue at least until the shareholder vote on the Cinergy merger is completed. Duke Energy may conduct further common stock repurchases before or after the closing of the merger with Cinergy. For the year ended December 31, 2005 a total of 32.6 million shares of common stock were repurchased under both share repurchase programs for approximately $933 million.

In December 2005, the Income Fund, a Canadian income trust fund, was created which sold approximately 40% ownership in the Canadian Midstream operations for proceeds, net of underwriting discount, of approximately $110 million. In January 2006, a subsequent greenshoe sale of additional ownership interests, pursuant to an overallotment option, in the Income Fund were sold for approximately $10 million. Duke Energy retains an ownership interest in the Income Fund of approximately 58% and will continue to operate and manage this business.

Preferred and Preference Stock of Duke Energy. In December 2005, Duke Energy redeemed all Preferred and Preference stock without Sinking Fund Requirements for approximately $137 million and recognized an immaterial loss on the redemption.

Available Credit Facilities and Restrictive Debt Covenants. Duke Energy’s credit agreements contain various financial and other covenants. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements. As of December 31, 2005, Duke Energy was in compliance with those covenants. In addition, some credit agreements may allow for acceleration of payments or termination of the agreements due to nonpayment, or to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the debt or credit agreements contain material adverse change clauses.

(For information on Duke Energy’s credit facilities as of December 31, 2005, see Note 15 to the Consolidated Financial Statements, “Debt and Credit Facilities.”)

Duke Energy has approximately $1,750 million of credit facilities which expire in 2006. It is Duke Energy’s intent to resyndicate less than the total expiring amount of credit facilities in 2006.

Credit Ratings. The most recent change to the credit ratings of Duke Energy and its subsidiaries (with the exception of M & N Pipeline) occurred in February 2004, when Standard and Poor’s (S&P) lowered its long-term ratings of Duke Energy and its subsidiaries (with the exception of M&N Pipeline, DEFS and DETM) one ratings level. S&P’s actions were based upon Duke Energy’s weaker than anticipated financial performance in 2003 and the execution risk associated with Duke Energy’s 2004 debt reduction plans S&P concluded this action by placing Duke Energy and its subsidiaries on Stable Outlook, with the exception of DETM, which remained on Negative Outlook until changed to Stable Outlook in July 2004. In December 2004, S&P changed the outlook of Duke Energy and its subsidiaries (with the exception of M&N Pipeline) from Stable to Positive and then from Positive to Stable in February 2005. The S&P and Dominion Bond Rating Service (DBRS) credit ratings and outlooks for M&N Pipeline have remained unchanged during 2004 and 2005. S&P last affirmed its rating for M&N Pipeline in August 2004 and DBRS last confirmed its rating for M&N Pipeline in March 2005. The DBRS credit ratings for Union Gas remained unchanged during 2004 and 2005 and were last confirmed in June 2005.

In February 2005, Moody’s Investors Service (Moody’s) changed the outlook of Duke Capital from Stable to Negative and placed the ratings of M&N Pipeline under Review for Possible Downgrade. Moody’s concluded their review of M&N Pipeline in August 2005 and downgraded the credit ratings from A1 to A2. Moody’s actions were primarily as a result of their concerns over the downward revisions in the reserve estimates for the Sable Offshore Energy Project (SOEI) and reduced production by SOEI producers. Moody’s concluded their action placing the ratings outlook for M&N Pipeline on Stable.

In May 2005, following the announcement of Duke Energy’s merger with Cinergy, S&P placed the credit ratings of Duke Energy and its subsidiaries (excluding M&N Pipeline) on “CreditWatch with negative implications.” In addition, Moody’s Investors Service revised the ratings outlook of Duke Energy, Duke Capital and Texas Eastern Transmission LP to “Developing” and DBRS placed the credit ratings of Westcoast Energy Inc. “Under Review with Developing Implications.”

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In September, 2005 S&P affirmed the credit ratings of Duke Energy and its subsidiaries (excluding M&N Pipeline) with a Stable outlook removing them from “CreditWatch with negative implications.” In addition, DBRS confirmed the credit rating of Westcoast Energy Inc. with a Stable trend removing them from “Under Review with Developing Implications.”

The following table summarizes the February 28, 2006 credit ratings from the agencies retained by Duke Energy to rate its securities, its principal funding subsidiaries and its trading and marketing subsidiary DETM.

Credit Ratings Summary as of February 28, 2006

	Standard and Poor’s	Moody’s Investor Service	Dominion Bond Rating Service
Duke Energya	BBB	Baa1	Not applicable
Duke Capital LLCa	BBB-	Baa3	Not applicable
Texas Eastern Transmission, LPa	BBB	Baa2	Not applicable
Westcoast Energy Inc.a	BBB	Not applicable	A(low)
Union Gasa	BBB	Not applicable	A
Maritimes & Northeast Pipeline, LLCb	A	A2	A
Maritimes & Northeast Pipeline, LPb	A	A2	A
Duke Energy Trading and Marketing, LLCc	BBB-	Not applicable	Not applicable

a Represents senior unsecured credit rating

b Represents senior secured credit rating

c Represents corporate credit rating

Duke Energy’s credit ratings are dependent on, among other factors, the ability to generate sufficient cash to fund capital and investment expenditures and dividends, and a disciplined execution for the potential continuation of the stock repurchase program announced in February 2005, while maintaining the strength of its current balance sheet. If, as a result of market conditions or other factors, Duke Energy is unable to maintain its current balance sheet strength, or if its earnings and cash flow outlook materially deteriorates, Duke Energy’s credit ratings could be negatively impacted. In addition, the completion of the merger with Cinergy and the resulting corporate structure as well as the completion of the exit from the former DENA business could impact the credit ratings of Duke Energy or its subsidiaries. Duke Energy believes that it is positioned for possible credit ratings improvement.

Duke Energy and its subsidiaries are required to post collateral under derivatives and other marketing contracts. Typically, the amount of the collateral is dependent upon Duke Energy’s economic position at points in time during the life of a contract and the credit rating of the subsidiary (or its guarantor, if applicable) obligated under the collateral agreement. Prior to the completion of the exit plan, business activity by former DENA generated the majority of Duke Energy’s collateral requirements. DENA conducted business throughout the United States and Canada through Duke Energy North America LLC and its 100% owned affiliates Duke Energy Marketing America, LLC (DEMA) and Duke Energy Marketing Canada Corp (DEMC). DENA also participated in DETM. During the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States, which was completed in May 2006.

On November 18, 2005, Duke Energy announced it signed an agreement to transfer substantially all of the DENA portfolio of derivatives contracts to Barclays. Under the agreement, Barclays will acquire substantially all of DENA’s outstanding gas and power derivatives contracts which essentially eliminates Duke Energy’s credit, collateral, market and legal risk associated with DENA’s derivative trading positions effective on the date of signing. The underlying contracts will transfer to Barclays over a period of months.

A reduction in DETM’s credit rating to below investment grade as of December 31, 2005 would have resulted in Duke Capital posting additional collateral of up to approximately $170 million. Additionally, in the event of a reduction in DETM’s credit rating to below investment grade, collateral agreements may require the segregation of cash held as collateral to be placed in escrow. As of December 31, 2005, Duke Capital would have been required to escrow approximately $350 million of such cash collateral held if DETM’s credit rating had been reduced to below investment grade. Amounts above reflect Duke Energy’s 60% ownership of DETM and the allocation of collateral to DENA for contracts executed by DETM on its behalf.

A reduction in the credit rating of Duke Capital to below investment grade as of December 31, 2005 would have resulted in Duke Capital posting additional collateral of up to approximately $365 million. Additionally, in the event of a reduction in Duke Capital’s credit rating to below investment grade, certain interest rate and foreign exchange swap agreements may require settlement payments due to termination of the agreements. As of December 31, 2005, Duke Capital could have been required to pay up to $5 million in such settlement payments if Duke Capital’s credit rating had been reduced to below investment grade. Duke Capital would fund any additional collateral requirements through a combination of cash on hand and the use of credit facilities. Subsequent to December 31, 2005, in connection with the sale to Barclays of contracts related to DENA’s energy marketing and management activities, Barclays provided Duke Energy cash equal to the net cash collateral posted by Duke Energy under the contracts. As the underlying contracts are transferred to

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Barclays, the downgrade impact will continue to change until the exit is completed. Duke Energy expects a majority of the negative impact of the collateral position to reverse within the next twelve months, upon completion of the exit plan.

If credit ratings for Duke Energy or its affiliates fall below investment grade there is likely to be a negative impact on its working capital and terms of trade that is not possible to quantify fully in addition to the posting of additional collateral and segregation of cash described above.

Clauses. Duke Energy may be required to repay certain debt should its credit ratings fall to a certain level at S&P or Moody’s. As of December 31, 2005, Duke Energy had $15 million of senior unsecured notes which mature serially through 2012 that may be required to be repaid if Duke Energy’s senior unsecured debt ratings fall below BBB- at S&P or Baa3 at Moody’s, and $26 million of senior unsecured notes which mature serially through 2016 that may be required to be repaid if Duke Energy’s senior unsecured debt ratings fall below BBB at S&P or Baa2 at Moody’s. As of February 28, 2006, Duke Energy’s senior unsecured credit rating was BBB at S&P and Baa1 at Moody’s.

Other Financing Matters. As of December 31, 2005, Duke Energy and its subsidiaries had effective SEC shelf registrations for up to $1,542 million in gross proceeds from debt and other securities. The total amount available under effective shelf registrations decreased $500 million as compared to December 31, 2004, resulting from the de-registering of DEFS on January 31, 2005. Additionally, as of December 31, 2005, Duke Energy had access to 200 million Canadian dollars (approximately U.S. $172 million) available under the Canadian shelf registrations for issuances in the Canadian market. This amount represents a decrease of 500 million Canadian dollars as compared to December 31, 2004, resulting from the November 2005 expiration of a 500 million shelf registration. In the first quarter of 2006, management has plans to renew the 500 million Canadian dollar shelf registration that expired in November 2005. A shelf registration is effective in Canada for a 25-month period. The 200 million Canadian dollars that is available as of December 31, 2005 will expire in July 2006.

Duke Energy’s Board of Directors adopted a dividend policy in 2005 that increased the quarterly dividend rate to $0.31 per share. Duke Energy has paid quarterly cash dividends for 79 consecutive years. Dividends on common and preferred stocks in 2006 are expected to be paid on March 16, June 16, September 16 and December 16, subject to the discretion of the Board of Directors.

Prior to June 2004, Duke Energy’s Investor Direct Choice Plan allowed investors to reinvest dividends in common stock and to purchase common stock directly from Duke Energy. In June 2004, Duke Energy changed the method of dividend reinvestment to open market purchases. There were no issuances of common stock under the plan in 2005. Issuances of common stock under the plan were $36 million in 2004 and $111 million in 2003.

Duke Energy also sponsors an employee savings plan that covers substantially all U.S. employees. In April 2004, Duke Energy stopped issuing shares under the plan and the plan began making open market purchases with cash provided by Duke Energy. There were no issuances of common stock under the plan in 2005. Issuances of common stock under the plan were $51 million in 2004 and $156 million in 2003. Duke Energy also issues shares of its common stock to meet other employee benefit requirements. Issuances of common stock to meet other employee benefit requirements were approximately $39 million for 2005, approximately $12 million for 2004 and approximately $20 million for 2003.

Off-Balance Sheet Arrangements

Duke Energy and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include financial and performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. These arrangements are largely entered into by Duke Capital. (See Note 18 to the Consolidated Financial Statements, “Guarantees and Indemnifications,” for further details of the guarantee arrangements.)

Most of the guarantee arrangements entered into by Duke Energy enhance the credit standing of certain subsidiaries, non-consolidated entities or less than wholly owned entities, enabling them to conduct business. As such, these guarantee arrangements involve elements of performance and credit risk, which are not included on the Consolidated Balance Sheets. The possibility of Duke Energy or Duke Capital having to honor its contingencies is largely dependent upon the future operations of the subsidiaries, investees and other third parties, or the occurrence of certain future events.

Issuance of these guarantee arrangements is not required for the majority of Duke Energy’s operations. Thus, if Duke Energy discontinued issuing these guarantee arrangements, there would not be a material impact to the consolidated results of operations, cash flows or financial position.

Duke Energy does not have any material off-balance sheet financing entities or structures, except for normal operating lease arrangements and guarantee arrangements. (For additional information on these commitments, see Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies” and Note 18 to the Consolidated Financial Statements, “Guarantees and Indemnifications.”)

On March 18, 2005, Duke Energy entered into an accelerated share repurchase transaction for 30 million shares as part of its publicly announced share repurchase program that allows Duke Energy to purchase up to $2.5 billion of its common stock over the next

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three years. In connection with this transaction, Duke Energy simultaneously entered into a forward sale contract with an investment bank that is indexed to and potentially settled in its own common stock. The forward sale contract is a derivative instrument and is classified as equity and is therefore considered to be an off-balance sheet arrangement (see Note 21 to the Consolidated Financial Statements, “Common Stock”). The forward sale contract was settled during the third quarter of 2005.

Contractual Obligations

Duke Energy enters into contracts that require payment of cash at certain specified periods, based on certain specified minimum quantities and prices. The following table summarizes Duke Energy’s contractual cash obligations for each of the periods presented. The table below excludes all amounts classified as current liabilities on the Consolidated Balance Sheets, other than current maturities of long-term debt. It is expected that the majority of current liabilities on the Consolidated Balance Sheets will be paid in cash in 2006.

Contractual Obligations as of December 31, 2005

	Payments Due By Period
	Total		Less than 1 year (2006)		2-3 Years (2007 & 2008)		4-5 Years (2009 & 2010)		More than 5 Years (Beyond 2010)
	(in millions)
Long-term debt(a)	$	24,916	$	2,319	$	3,971	$	4,110	$	14,516
Capital leases(a)		21		10		5		3		3
Operating leases(b)		454		79		130		119		126
Purchase Obligations:(g)
Firm capacity payments(c)		1,481		305		310		263		603
Energy commodity contracts(d)		16,699		5,930		6,488		3,336		945
Other purchase obligations(e)		2,565		1,237		508		172		648
Other long-term liabilities on the Consolidated Balance Sheets(f)		536		104		96		96		240
Total contractual cash obligations	$	46,672	$	9,984	$	11,508	$	8,099	$	17,081

(a) See Note 15 to the Consolidated Financial Statements, “Debt and Credit Facilities”. Amount includes interest payments over life of debt or capital lease.

(b) See Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies”.

(c) Includes firm capacity payments that provide Duke Energy with uninterrupted firm access to natural gas transportation and storage, electricity transmission capacity, refining capacity and the option to convert natural gas to electricity at third-party owned facilities (tolling arrangements) in some natural gas and power locations throughout North America. Also includes firm capacity payments under electric power agreements entered into to meet U.S. Franchised Electric Gas’ native load requirements.

(d) Includes contractual obligations to purchase physical quantities of electricity, natural gas, NGLs, coal and nuclear fuel. Amount includes certain normal purchases, energy derivatives and hedges per SFAS No. 133. For contracts where the price paid is based on an index, the amount is based on forward market prices at December 31, 2005. For certain of these amounts, Duke Energy may settle on a net cash basis since Duke Energy has entered into payment netting agreements with counterparties that permit Duke Energy to offset receivables and payables with such counterparties. A significant portion of these amounts pertain to DENA’s physical purchase commitments of electricity. Since DENA primarily markets electricity, consideration should be given to DENA’s forward sales of electricity, which exceed their forward purchases, when assessing the potential implications of these physical purchase commitments. (See Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale,” for more information regarding DENA’s exit plan.)

(e) Includes purchase commitments for outsourcing of certain real estate services, contracts for software, telephone, data and consulting or advisory services. Amount also includes contractual obligations for engineering, procurement and construction costs for nuclear plant refurbishments, environmental projects on fossil facilities, pipeline and real estate projects, and major maintenance of certain merchant plants. Amount excludes certain open purchase orders for services that are provided on demand, and the timing of the purchase can not be determined.

(f) Includes expected retirement plan contributions for 2006 (see Note 22 to the Consolidated Financial Statements, “Employee Benefit Plans”), certain estimated executive benefits, Department of Energy assessment fee (see Note 4 to the Consolidated Financial Statements, “Regulatory Matters”), and contributions to the NDTF (see Note 7 to the Consolidated Financial Statements, “Asset Retirement Obligations”). The amount of cash flows to be paid to settle the asset retirement obligations is not known with certainty as Duke Energy may use internal resources or external resources to perform retirement activities. As a result, cash obligations for asset retirement activities are excluded. Asset retirement obligations recognized on the Consolidated Balance Sheets total $2,058 million and the fair value of the NDTF, which will be used to help fund these obligations, is $1,504 million at December 31, 2005. Amount excludes reserves for litigation, environmental remediation, asbestos-related injuries and damages claims and self-insurance claims (see Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies”) because Duke Energy is uncertain as to the timing of when cash payments will be required. Additionally, amount excludes annual insurance premiums that are necessary to operate the business, including nuclear insurance (see Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies”), funding of other post-employment benefits (see Note 22 to the Consolidated Financial Statements, “Employee Benefit Plans”) and regulatory credits (see Note 4 to the Consolidated Financial Statements, “Regulatory Matters”) because the amount and timing of the cash payments are uncertain. Also amount excludes Deferred Income Taxes and Investment Tax Credits on the Consolidated Balance Sheets since cash payments for income taxes are determined based primarily on taxable income for each discrete fiscal year. Liabilities Associated with Assets Held for Sale (see Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”) are also excluded as Duke Energy expects these liabilities will be assumed by the buyer upon sale of the assets.

(g) Purchase obligations reflected in the Consolidated Balance Sheets have been excluded from the above table, including approximately $600 million of amounts due to Barclays (see Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held For Sale”) which were paid in January 2006.

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OTHER ISSUES

Merger with Cinergy. On May 9, 2005, Duke Energy and Cinergy announced they entered into a definitive merger agreement. Upon consummation of the transaction set forth in the merger agreement, each common share of Cinergy was converted into 1.56 shares of common stock of a newly-created holding company (to be renamed Duke Energy Corporation) and each common share of Duke Energy was converted into one share of the holding company. Based on Cinergy shares outstanding at the merger date, the holding company issued approximately 313 million shares to convert the Cinergy common shares. The merger was accounted for under the purchase method of accounting with Duke Energy treated as the acquirer, for accounting purposes. Based on the market price of Duke Energy common stock during the period including the two trading days before through the two trading days after May 9, 2005, the date Duke Energy and Cinergy announced the merger, the transaction was valued at approximately $9 billion and resulted in incremental goodwill to Duke Energy of approximately $4 billion. The merger agreement was unanimously approved by both companies’ Boards of Directors. Closing of the transaction occurred in the second quarter of 2006. Completion of the merger was subject to a number of conditions, including the approval of shareholders of both companies and a number of federal and state governmental authorities. Special meetings of the Duke Energy and Cinergy shareholders approving the merger were held on March 10, 2006. (For further discussion of the status of regulatory filings see Note 4 to the Consolidated Financial Statements, “Regulatory Matters”.) The merger agreement contained certain cross-approval provisions whereby Duke Energy and Cinergy are required to continue to operate their businesses in the ordinary course of business and must obtain the other party’s consent prior to making new investments or disposing of businesses above specified thresholds, entering into new debt above specified thresholds, issuing new common stock (other than under employee compensation arrangements) or making dividend changes, among other provisions.

Plan to Separate Duke Energy’s Natural Gas and Electric Power Businesses. In June 2006, the Board of Directors of Duke Energy authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas businesses to Duke Energy shareholders. The new natural gas company, which would be named Spectra Energy, would principally consist of Duke Energy’s Natural Gas Transmission business segment, which includes Union Gas, and Duke Energy’s 50-percent ownership interest in DEFS. The primary businesses remaining in Duke Energy post-spin are anticipated to principally be the U.S. Franchised Electric and Gas business segment, the Commercial Power business segment, the International Energy business segment and Duke Energy’s 50% interest in the Crescent JV. It is anticipated that approximately $9 billion of debt currently at Duke Capital and its consolidated subsidiaries would transfer to the new natural gas company at the time of the spin-off. While the actual timing of the spin-off, if it occurs, is dependent upon the resolution of certain regulatory and other matters, Duke Energy is currently targeting a January 1, 2007 effective date for the transaction. Duke Energy expects the transaction to qualify for tax-free treatment for U.S. federal income tax purposes to both Duke Energy and its shareholders and is still evaluating other income tax impacts of the transaction. The transaction required Virginia State Corporation Commission approval, which was received during the third quarter of 2006. In addition, approval from the Federal Communications Commission is required for the indirect change in control over various licenses from Duke Energy to the new gas company. Duke Energy made the requisite applications in the third quarter 2006. The results of the natural gas businesses are expected to be treated as discontinued operations in the period the spin-off is consummated.

In connection with the distribution, pursuant to the terms of the indenture governing Duke Energy’s 13/4% Convertible Senior Notes due 2023, holders of record of such notes will participate in the distribution. As of December 1, 2006, there was approximately $110 million principal amount outstanding of such notes. Accordingly, pursuant to the terms of the indenture, approximately 2.3 million shares of Spectra Energy common stock is expected to be distributed in respect of such outstanding principal amount of such notes.

Energy Policy Act of 2005. The Energy Policy Act of 2005 was signed into law in August 2005. The legislation directs specified agencies to conduct a significant number of studies on various aspects of the energy industry and to implement other provisions through rulemakings. Among the key provisions, the Energy Policy Act of 2005 repeals the PUHCA of 1935, directs FERC to establish a self-regulating electric reliability organization governed by an independent board with FERC oversight, extends the Price Anderson Act for 20 years (until 2025), provides loan guarantees, standby support and production tax credits for new nuclear reactors, gives FERC enhanced merger approval authority, provides FERC new backstop authority for the siting of certain electric transmission projects, streamlines the processes for approval and permitting of interstate pipelines, and reforms hydropower relicensing. FERC’s enhanced merger authority will not apply to transactions pending with the FERC as of August 8, 2005, such as the anticipated Duke Energy and Cinergy merger, as discussed in Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions.” In late 2005 and early 2006, FERC initiated several rulemakings as directed by the Energy Policy Act of 2005. Duke Energy is currently evaluating these proposals and does not anticipate that these rulemakings will have a material adverse effect on its consolidated results of operations, cash flows or financial position.

Global Climate Change. The United Nations-sponsored Kyoto Protocol, which prescribes specific greenhouse gas emission-reduction targets for developed countries, became effective February 16, 2005. Of the countries where Duke Energy has assets, Canada is presently the only one that has a greenhouse gas reduction obligation under the Kyoto Protocol. That obligation is to reduce average greenhouse gas emissions to 6 percent below their 1990 level over the period 2008 to 2012. The Canadian Government’s strategy for achieving its Kyoto reduction target includes, among other things, an emissions intensity-based greenhouse gas cap-and-trade program

57

for large final emitters (LFE). A final LFE rule could be issued sometime in 2006. If an LFE program is ultimately enacted, then all of Duke Energy’s Canadian operations would likely be subject to the program beginning in 2008, with compliance options ranging from the purchase of greenhouse gas credits to actual emission reductions at the source, or a combination of strategies.

The United States is not a party to the Kyoto Protocol. Instead, the U.S. greenhouse gas policy currently favors voluntary actions, continued research, and technology development over near-term mandatory greenhouse gas reduction requirements. Although several bills have been introduced in Congress that would compel carbon dioxide (CO₂) emission reductions, none have advanced through the legislature and presently there are no federal mandatory greenhouse gas reduction requirements. The likelihood of a federally mandated CO₂ emissions reduction program being enacted in the near future, or the specific requirements of any such regime, is highly uncertain. Several states have taken legislative or regulatory steps to manage greenhouse gas emissions; none of which will impact Duke Energy’s operations. A number of U.S. states in the Northeast and far West are discussing the enactment of either state-specific or regional programs that could mandate future reductions in greenhouse gas emissions, or otherwise manage those emissions, although the outcome of those state discussions is highly uncertain.

Duke Energy supports the enactment of U.S. federal legislation that would encourage a gradual transition to a lower-carbon-intensive economy. Legislation preferably would be in the form of a federal-level carbon tax or other market based mechanism that provides the policy advantages of a carbon tax approach and also applies to all sectors of the economy. Duke Energy, believing that it is in the best interest of its investors and customers to do so, is actively participating in the evolution of federal policy on this important issue.

Duke Energy’s proactive role in climate change policy debates in the United States does not change the uncertainty around climate change policy. Due to the speculative outlook regarding any U.S. federal and state policies and the uncertainty of the Canadian policy, Duke Energy cannot estimate the potential effect of either nation’s greenhouse gas policy on its future consolidated results of operations, cash flows or financial position. Duke Energy will assess and respond to the potential implications of greenhouse gas policies for its business operations in the United States and Canada if policies become sufficiently developed and certain to support a meaningful assessment.

Hurricane Damage. Duke Energy continues to assess and monitor damage assessments related to Hurricanes Katrina and Rita in the Gulf Coast. Duke Energy has recorded all losses known to date, and is currently not aware of any additional damages incurred which will have a material adverse impact on its consolidated results of operations, cash flows, or financial position. During 2005, Duke Energy incurred net expenses of approximately $50 million (net of reinsurance receivables) related to Hurricanes Katrina and Rita.

(For additional information on other issues related to Duke Energy, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters” and Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies.”)

New Accounting Standards

The following new accounting standards were issued, but have not yet been adopted by Duke Energy as of December 31, 2005:

SFAS No. 123 (Revised 2004), “Share-Based Payment” (SFAS No. 123R). In December of 2004, the FASB issued SFAS No. 123R, which replaces SFAS No. 123, “Accounting for Stock Based Compensation,” and supersedes Accounting Principles Board (APB) Opinion 25, “Accounting for Stock Issued to Employees.” SFAS No. 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values. For Duke Energy, timing for implementation of SFAS No. 123R is January 1, 2006. The pro forma disclosures previously permitted under SFAS No. 123 will no longer be an acceptable alternative. Instead, Duke Energy will be required to record compensation expense in the Consolidated Statements of Operations for stock options. Under SFAS No. 123R, Duke Energy must determine an appropriate expense for stock options and the transition method to be used effective January 1, 2006. The transition methods include prospective and retroactive adoption options. Both methods record compensation expense for all unvested awards beginning January 1, 2006. Under the retroactive method, prior periods presented are also restated for awards which have vested prior to January 1, 2006.

Duke Energy currently also has retirement eligible employees with outstanding share-based payment awards (restricted stock awards, stock based performance awards and phantom stock awards). Compensation cost related to those awards is currently expensed over the stated vesting period or until actual retirement occurs. Effective January 1, 2006, Duke Energy will recognize compensation cost for new awards granted to employees over the requisite service period, which generally begins on the date the award is granted through the earlier of the date the award vests or the date the employee becomes retirement eligible. Awards, including stock options, granted to employees that are already retirement eligible will be deemed to have vested immediately upon issuance, and therefore, compensation cost for those awards will be recognized on the date such awards are granted.

The impact on EPS for the years ended December 31, 2005, 2004 and 2003 had Duke Energy followed the expensing provisions of SFAS No. 123 is disclosed in the Pro Forma Stock-Based Compensation table included in Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies.” Duke Energy plans to implement SFAS No. 123R using the prospective transition method and currently there are no plans to change the option-pricing model used for share-based compensation awards issued to employees in future periods. SFAS No. 123R, which was adopted by Duke Energy effective January 1, 2006, is not anticipated to have a

58

material impact on its consolidated results of operations, cash flows or financial position in 2006 based on awards outstanding as of the implementation date. However, the impact to Duke Energy in periods subsequent to adoption of SFAS No. 123R will be largely dependent upon the nature of any new share-based compensation awards issued to employees.

Staff Accounting Bulletin (SAB) No. 107, “Share-Based Payment” (SAB 107). On March 29, 2005, the SEC staff issued SAB 107 to express the views of the staff regarding the interaction between SFAS No. 123R and certain SEC rules and regulations and to provide the staff’s views regarding the valuation of share-based payment arrangements for public companies. Duke Energy has considered the additional guidance provided by SAB 107 in connection with the implementation of SFAS No. 123R.

FASB Staff Position (FSP) No. FAS 115-1 and 124-1, “The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments.” The FASB issued FSP No. FAS 115-1 and 124-1 in November 2005, which is effective for Duke Energy beginning January 1, 2006. This FSP addresses the determination as to when an investment is considered impaired, whether that impairment is other than temporary, and the measurement of an impairment loss. This FSP also includes accounting considerations subsequent to the recognition of an other-than-temporary impairment and requires certain disclosures about unrealized losses that have not been recognized as other-than-temporary impairments. The guidance in this FSP amends SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” and No. 124, “Accounting for Certain Investments Held by Not-for-Profit Organizations,” and APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.” The adoption of FSP No. FAS 115-1 and 124-1 will not have a material impact on Duke Energy’s consolidated results of operations, cash flows or financial position.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Duke Energy Corporation:

We have audited the accompanying consolidated balance sheets of Duke Energy Corporation and subsidiaries (Duke Energy) as of December 31, 2005 and 2004, and the related consolidated statements of operations, common stockholders’ equity, and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of Duke Energy’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Duke Energy at December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in Note 1, Duke Energy adopted the provisions of Statement of Financial Accounting Standards No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” as of July 1, 2003. As discussed in Note 1, Duke Energy adopted the provisions of Emerging Issues Task Force No. 02-3, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” as of January 1, 2003.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Duke Energy’s internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 3, 2006 expressed an unqualified opinion on management’s assessment of the effectiveness of Duke Energy’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

DELOITTE & TOUCHE LLP

Charlotte, North Carolina

March 3, 2006

(December 8, 2006 as to the segment change described in Note 3 and the references to subsequent events in Note 24)

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DUKE ENERGY CORPORATION

Consolidated Statements of Operations

(In millions, except per-share amounts)

	Years Ended December 31,
	2005			2004			2003
Operating Revenues
Non-regulated electric, natural gas, natural gas liquids, and other	$	7,661		$	12,232		$	10,088
Regulated electric		5,406			5,041			4,851
Regulated natural gas and natural gas liquids		3,679			3,276			3,082
Total operating revenues		16,746			20,549			18,021
Operating Expenses
Natural gas and petroleum products purchased		6,279			10,156			8,479
Operation, maintenance and other		3,553			3,317			3,496
Fuel used in electric generation and purchased power		1,584			1,576			1,465
Depreciation and amortization		1,728			1,750			1,675
Property and other taxes		571			513			499
Impairments and other charges		140			64			1,219
Impairment of goodwill		—			—			254
Total operating expenses		13,855			17,376			17,087
Gains on Sales of Investments in Commercial and Multi-Family Real Estate		191			192			84
Gains (Losses) on Sales of Other Assets, net		534			(404	)		(199	)
Operating Income		3,616			2,961			819
Other Income and Expenses
Equity in earnings of unconsolidated affiliates		479			161			123
Gains (Losses) on sales and impairments of equity method investments		1,225			(4	)		279
Other income and expenses, net		96			148			148
Total other income and expenses		1,800			305			550
Interest Expense		1,062			1,281			1,330
Minority Interest Expense		538			200			62
Earnings (Loss) From Continuing Operations Before Income Taxes		3,816			1,785			(23	)
Income Tax Expense (Benefit) from Continuing Operations		1,283			533			(94	)
Income From Continuing Operations		2,533			1,252			71
(Loss) Income From Discontinued Operations, net of tax		(705	)		238			(1,232	)
Income (Loss) Before Cumulative Effect of Change in Accounting Principle		1,828			1,490			(1,161	)
Cumulative Effect of Change in Accounting Principle, net of tax and minority interest		(4	)		—			(162	)
Net Income (Loss)		1,824			1,490			(1,323	)
Dividends and Premiums on Redemption of Preferred and Preference Stock		12			9			15
Earnings (Loss) Available For Common Stockholders	$	1,812		$	1,481		$	(1,338	)
Common Stock Data
Weighted-average shares outstanding
Basic		934			931			903
Diluted		970			966			904
Earnings per share (from continuing operations)
Basic	$	2.69		$	1.33		$	0.06
Diluted	$	2.61		$	1.29		$	0.06
(Loss) Earnings per share (from discontinued operations)
Basic	$	(0.75	)	$	0.26		$	(1.36	)
Diluted	$	(0.73	)	$	0.25		$	(1.36	)
Earnings (Loss) per share (before cumulative effect of change in accounting principle)
Basic	$	1.94		$	1.59		$	(1.30	)
Diluted	$	1.88		$	1.54		$	(1.30	)
Earnings (Loss) per share
Basic	$	1.94		$	1.59		$	(1.48	)
Diluted	$	1.88		$	1.54		$	(1.48	)
Dividends per share	$	1.17		$	1.10		$	1.10

See Notes to Consolidated Financial Statements

61

DUKE ENERGY CORPORATION

Consolidated Balance Sheets

(In millions)

	December 31,
	2005		2004
ASSETS
Current Assets
Cash and cash equivalents	$	511	$	533
Short-term investments		632		1,319
Receivables (net of allowance for doubtful accounts of $127 at December 31, 2005 and $135 at December 31, 2004)		2,580		3,184
Inventory		863		942
Assets held for sale		1,528		40
Unrealized gains on mark-to-market and hedging transactions		87		962
Other		1,756		938
Total current assets		7,957		7,918
Investments and Other Assets
Investments in unconsolidated affiliates		1,933		1,292
Nuclear decommissioning trust funds		1,504		1,374
Goodwill		3,775		4,148
Notes receivable		138		232
Unrealized gains on mark-to-market and hedging transactions		62		1,379
Assets held for sale		3,597		84
Investments in residential, commercial and multi-family real estate (net of accumulated depreciation of $17 at December 31, 2005 and $15 at December 31, 2004)		1,281		1,128
Other		2,743		1,949
Total investments and other assets		15,033		11,586
Property, Plant and Equipment
Cost		40,574		46,806
Less accumulated depreciation and amortization		11,374		13,000
Net property, plant and equipment		29,200		33,806
Regulatory Assets and Deferred Debits
Deferred debt expense		269		297
Regulatory assets related to income taxes		1,338		1,269
Other		926		894
Total regulatory assets and deferred debits		2,533		2,460
Total Assets	$	54,723	$	55,770

See Notes to Consolidated Financial Statements

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DUKE ENERGY CORPORATION

Consolidated Balance Sheets—(Continued)

(In millions)

	December 31,
	2005		2004
LIABILITIES AND COMMON STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable	$	2,431	$	2,414
Notes payable and commercial paper		83		68
Taxes accrued		327		273
Interest accrued		230		287
Liabilities associated with assets held for sale		1,488		30
Current maturities of long-term debt		1,400		1,832
Unrealized losses on mark-to-market and hedging transactions		204		819
Other		2,255		1,779
Total current liabilities		8,418		7,502
Long-term Debt		14,547		16,932
Deferred Credits and Other Liabilities
Deferred income taxes		5,253		5,228
Investment tax credit		144		154
Unrealized losses on mark-to-market and hedging transactions		10		971
Liabilities associated with assets held for sale		2,085		14
Asset retirement obligations		2,058		1,926
Other		5,020		4,982
Total deferred credits and other liabilities		14,570		13,275
Commitments and Contingencies
Minority Interests		749		1,486
Preferred and preference stock without sinking fund requirements		—		134
Common Stockholders' Equity
Common stock, no par, 2 billion shares authorized; 928 million and 957 million shares outstanding at December 31, 2005 and December 31, 2004, respectively		10,388		11,252
Retained earnings		5,335		4,539
Accumulated other comprehensive income		716		650
Total common stockholders' equity		16,439		16,441
Total Liabilities and Common Stockholders' Equity	$	54,723	$	55,770

See Notes to Consolidated Financial Statements

63

DUKE ENERGY CORPORATION

Consolidated Statements of Cash Flows

(In millions)

	Years Ended December 31,
	2005			2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	1,824		$	1,490		$	(1,323	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization (including amortization of nuclear fuel)		1,884			2,037			1,987
Cumulative effect of change in accounting principle		4			—			162
Gains on sales of investments in commercial and multi-family real estate		(191	)		(201	)		(103	)
Gains on sales of equity investments and other assets		(1,646	)		(193	)		(86	)
Impairment charges		36			194			3,495
Deferred income taxes		282			867			(534	)
Minority Interest		538			195			61
Equity in earnings of unconsolidated affiliates		(479	)		(161	)		(123	)
Purchased capacity levelization		(14	)		92			194
Contribution to company-sponsored pension plans		(45	)		(279	)		(194	)
(Increase) decrease in
Net realized and unrealized mark-to-market and hedging transactions		468			216			(15	)
Receivables		(255	)		(231	)		1,188
Inventory		(80	)		(48	)		(30	)
Other current assets		(944	)		(33	)		(104	)
Increase (decrease) in
Accounts payable		81			(5	)		(1,047	)
Taxes accrued		53			188			(168	)
Other current liabilities		622			91			70
Capital expenditures for residential real estate		(355	)		(322	)		(196	)
Cost of residential real estate sold		294			268			167
Other, assets		191			(155	)		(162	)
Other, liabilities		533			158			165
Net cash provided by operating activities		2,801			4,168			3,404
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(2,309	)		(2,161	)		(2,260	)
Investment expenditures, net of refund		(43	)		(46	)		(153	)
Acquisitions, net of cash acquired		(294	)		—			—
Purchases of available-for-sale securities		(41,073	)		(65,929	)		(40,451	)
Proceeds from sales and maturities of available-for-sale securities		40,887			65,098			40,004
Net proceeds from the sales of and distributions from equity investments and other assets, and sales of and collections on notes receivable		2,375			1,619			1,976
Proceeds from the sales of commercial and multi-family real estate		372			606			314
Settlement of net investment hedges and other investing derivatives		(321	)		—			—
Distributions from equity investments		383			—			—
Other		(86	)		20			(106	)
Net cash used in investing activities		(109	)		(793	)		(676	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the:
Issuance of long-term debt		543			153			3,009
Issuance of common stock and common stock related to employee benefit plans		41			1,704			277
Payments for the redemption of:
Long-term debt		(1,346	)		(3,646	)		(2,849	)
Preferred stock of a subsidiary		—			(176	)		(38	)
Preferred and preference stock		(134	)		—			—
Guaranteed preferred beneficial interests in subordinated notes		—			—			(250	)
Notes payable and commercial paper		165			(67	)		(1,702	)
Distributions to minority interests		(861	)		(1,477	)		(2,508	)
Contributions from minority interests		779			1,277			2,432
Dividends paid		(1,105	)		(1,065	)		(1,051	)
Repurchase of common shares		(933	)		—			—
Proceeds from Duke Energy Income Fund		110			—			—
Other		24			19			23
Net cash used in financing activities		(2,717	)		(3,278	)		(2,657	)
Changes in cash and cash equivalents included in assets held for sale		3			39			(55	)
Net (decrease) increase in cash and cash equivalents		(22	)		136			16
Cash and cash equivalents at beginning of period		533			397			381
Cash and cash equivalents at end of period	$	511		$	533		$	397
Supplemental Disclosures
Cash paid for interest, net of amount capitalized	$	1,089		$	1,323		$	1,324
Cash paid (refunded) for income taxes	$	546		$	(339	)	$	(18	)
Significant non-cash transactions:
Transfer of DEFS Canadian facilities	$	97		$	—		$	—
AFUDC—equity component	$	30		$	25		$	74
Conversion of convertible notes to stock	$	28		$	—		$	—
Debt retired in connection with disposition of businesses	$	—		$	840		$	387
Note receivable from sale of southeastern plants	$	—		$	48		$	—
Remarketing of senior notes	$	—		$	1,625		$	—

See Notes to Consolidated Financial Statements

64

DUKE ENERGY CORPORATION

Consolidated Statements of Common Stockholders' Equity

and Comprehensive Income (Loss)

(In millions)

									Accumulated Other Comprehensive Income (Loss)
	Common Stock Shares		Common Stock			Retained Earnings			Foreign Currency Adjustments			Net Gains (Losses) on Cash Flow Hedges			Minimum Pension Liability Adjustment			Other		Total
Balance December 31, 2002	895		$	9,236		$	6,417		$	(647	)	$	422		$	(484	)	$	—	$	14,944
Net loss	—			—			(1,323	)		—			—			—			—		(1,323	)
Other Comprehensive Loss
Foreign currency translation adjustments(a)	—			—			—			986			—			—			—		986
Foreign currency translation adjustments reclassified into earnings as a result of the sale of European operations	—			—			—			(24	)		—			—			—		(24	)
Net unrealized gains on cash flow hedges(b)	—			—			—			—			116			—			—		116
Reclassification into earnings from cash flow hedges(c)	—			—			—			—			(240	)		—			—		(240	)
Minimum pension liability adjustment(d)	—			—			—			—			—			40			—		40
Total comprehensive loss																					(445	)
Dividend reinvestment and employee benefits	16			283			(6	)		—			—			—			—		277
Common stock dividends	—			—			(993	)		—			—			—			—		(993	)
Preferred and preference stock dividends	—			—			(15	)		—			—			—			—		(15	)
Other capital stock transactions, net	—			—			(20	)		—			—			—			—		(20	)
Balance December 31, 2003	911		$	9,519		$	4,060		$	315		$	298		$	(444	)	$	—	$	13,748
Net income	—			—			1,490			—			—			—			—		1,490
Other Comprehensive Income
Foreign currency translation adjustments	—			—			—			279			—			—			—		279
Foreign currency translation adjustments reclassified into earnings as a result of the sale of Asia-Pacific Business	—			—			—			(54	)		—			—			—		(54	)
Net unrealized gains on cash flow hedges(b)	—			—			—			—			311			—			—		311
Reclassification into earnings from cash flow hedges(c)	—			—			—			—			(83	)		—			—		(83	)
Minimum pension liability adjustment(d)	—			—			—			—			—			28			—		28
Total comprehensive income																					1,971
Dividend reinvestment and employee benefits	5			108			20			—			—			—			—		128
Equity offering	41			1,625			—			—			—			—			—		1,625
Common stock dividends	—			—			(1,018	)		—			—			—			—		(1,018	)
Preferred and preference stock dividends	—			—			(9	)		—			—			—			—		(9	)
Other capital stock transactions, net	—			—			(4	)		—			—			—			—		(4	)
Balance December 31, 2004	957		$	11,252		$	4,539		$	540		$	526		$	(416	)	$	—	$	16,441
Net income	—			—			1,824			—			—			—			—		1,824
Other Comprehensive Income
Foreign currency translation adjustments	—			—			—			306			—			—			—		306
Net unrealized gains on cash flow hedges(b)	—			—			—			—			413			—			—		413
Reclassification into earnings from cash flow hedges(c)	—			—			—			—			(1,026	)		—			—		(1,026	)
Minimum pension liability adjustment (d)	—			—			—			—			—			356			—		356
Other(e)	—			—			—			—			—			—			17		17
Total comprehensive income																					1,890
Dividend reinvestment and employee benefits	3			41			44			—			—			—			—		85
Stock repurchase	(33	)		(933	)		—			—			—			—			—		(933	)
Conversion of debt	1			28			—			—			—			—			—		28
Common stock dividends	—			—			(1,093	)		—			—			—			—		(1,093	)
Preferred and preference stock dividends	—			—			(12	)		—			—			—			—		(12	)
Other capital stock transactions, net	—			—			33			—			—			—			—		33
Balance December 31, 2005	928		$	10,388		$	5,335		$	846		$	(87	)	$	(60	)	$	17	$	16,439

(a) Foreign currency translation adjustments, net of $62 tax benefit in 2005 and $114 tax benefit in 2003. The 2005 tax benefit related to the settled net investment hedges (see Note 8). Substantially all of the 2005 tax benefit is an immaterial correction of an accounting error related to prior periods.

(b) Net unrealized gains on cash flow hedges, net of $233 tax expense in 2005, $170 tax expense in 2004, and $49 tax expense in 2003.

(c) Reclassification into earnings from cash flow hedges, net of $583 tax benefit in 2005, $45 tax benefit in 2004, and $130 tax benefit in 2003. Reclassification into earnings from cash flow hedges for the year ended December 31, 2005, is due primarily to the recognition of unrealized net gains related to hedges on forecasted transactions which will no longer occur as a result of the plan to sell or otherwise dispose of substantially all of DENA's assets and contracts outside of the Midwestern United States and certain contractual positions related to the Midwestern assets (see Notes 8 and 13).

(d) Minimum pension liability adjustment, net of $228 tax expense in 2005, $18 tax expense in 2004, and $27 tax expense in 2003.

(e) Net of $10 tax expense in 2005.

See Notes to Consolidated Financial Statements

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DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements

For the Years Ended December 31, 2005, 2004 and 2003

1. Summary of Significant Accounting Policies

Nature of Operations and Basis of Consolidation. Duke Energy Corporation (collectively with its subsidiaries, Duke Energy), is a leading energy company located in the Americas with a real estate subsidiary. These Consolidated Financial Statements include, after eliminating intercompany transactions and balances, the accounts of Duke Energy and all majority-owned subsidiaries where Duke Energy has control, and those variable interest entities where Duke Energy is the primary beneficiary. These Consolidated Financial Statements also reflect Duke Energy’s 12.5% undivided interest in the Catawba Nuclear Station.

Effective July 1, 2005, Duke Energy has deconsolidated Duke Energy Field Services, LLC (DEFS) due to a reduction in ownership and its inability to exercise control over DEFS (see Note 2). DEFS has been subsequently accounted for as an equity method investment.

Recasting of Previously Issued Financial Statements. In conjunction with Duke Energy’s merger with Cinergy Corp. (Cinergy), Duke Energy adopted new business segments effective with the second quarter ended June 30, 2006. See Note 3 for the impacts of this segment change on the Notes to Consolidated Financial Statements.

Use of Estimates. To conform to generally accepted accounting principles (GAAP) in the United States, management makes estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and Notes. Although these estimates are based on management’s best available knowledge at the time, actual results could differ.

Reclassifications and Revisions. Certain prior period amounts have been reclassified to conform to current year presentation.

In 2005, Duke Energy recorded a prior period reclassification adjustment of approximately $300 million related to removal costs for property within the natural gas operations. The impact of this adjustment on the Consolidated Balance Sheet as of December 31, 2004 was a decrease in accumulated depreciation and a corresponding increase in regulatory liabilities, which are included in Other within Deferred Credits and Other Liabilities.

Additionally, the accompanying Consolidated Statements of Cash Flows for the years ended December 31, 2004 and 2003 reflect a change in the classification of expenditures for equipment related to clean air legislation in the state of North Carolina from cash flows from operating activities to cash flows from investing activities. As a result, net cash provided by operating activities for the years ended December 31, 2004 and 2003 have increased by $106 million and $18 million, respectively, while net cash used in investing activities for the years ended December 31, 2004 and 2003 increased by the same amount.

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

Short-term Investments. Duke Energy actively invests a portion of its available cash balances in various financial instruments, such as tax-exempt debt securities that frequently have stated maturities of 20 years or more and tax-exempt money market preferred securities. These instruments provide for a high degree of liquidity through features such as daily and seven day notice put options and 7, 28, and 35 day auctions which allow for the redemption of the investments at their face amounts plus earned income. As Duke Energy intends to sell these instruments within one year or less, generally within 30 days from the balance sheet date, they are classified as current assets. Duke Energy has classified all short-term investments that are debt securities as available-for-sale under Statement of Financial Accounting Standards (SFAS) No. 115, “Accounting For Certain Investments in Debt and Equity Securities,” (SFAS No. 115), and they are carried at fair market value. Investments in money-market preferred securities that do not have stated redemptions are accounted for at their cost, as the carrying values approximate market values due to their short-term maturities and no credit risk. Realized gains and losses and dividend and interest income related to these securities, including any amortization of discounts or premiums arising at acquisition, are included in earnings as incurred. Purchases and sales of available-for-sale securities are presented on a gross basis within Investing Cash Flows in the accompanying Consolidated Statements of Cash Flows.

Inventory. Inventory consists primarily of materials and supplies and natural gas held in storage for transmission, processing and sales commitments; and coal held for electric generation. This inventory is recorded at the lower of cost or market value, primarily using the average cost method. At December 31, 2004, inventory contained $46 million of natural gas liquid (NGL) products related to DEFS, which was deconsolidated effective July 1, 2005.

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DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Components of Inventory

	December 31,
	2005		2004
	(in millions)
Materials and supplies	$	434	$	445
Natural gas		269		312
Coal held for electric generation		115		104
Petroleum products		45		81
Total inventory	$	863	$	942

Accounting for Risk Management and Hedging Activities and Financial Instruments. Duke Energy uses a number of different derivative and non-derivative instruments in connection with its commodity price, interest rate and foreign currency risk management activities and its trading activities, including forward contracts, futures, swaps, options and swaptions. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133), as amended, are recorded on the Consolidated Balance Sheets at their fair value as Unrealized Gains or Unrealized Losses on Mark-to-Market and Hedging Transactions. Cash inflows and outflows related to derivative instruments, except those that contain financing elements and those related to net investment hedges and other investing activities, are a component of operating cash flows in the accompanying Consolidated Statements of Cash Flows. Cash inflows and outflows related to derivative instruments containing financing elements are a component of financing cash flows in the accompanying Consolidated Statements of Cash Flows while cash inflows and outflows related to net investment hedges and derivatives related to other investing activities are a component of investing cash flows in the accompanying Consolidated Statements of Cash Flows.

Effective January 1, 2003, in connection with the implementation of the remaining provisions of Emerging Issues Task Force (EITF) 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-03), Duke Energy designated all energy commodity derivatives as either trading or non-trading. Gains and losses for all derivative contracts that do not represent physical delivery contracts are reported on a net basis in the Consolidated Statements of Operations. For each of the Duke Energy’s physical delivery contracts that are derivatives, the accounting model and presentation of gains and losses, or revenue and expense in the Consolidated Statements of Operations is shown below.

Classification of Contract	Duke Energy Accounting Model	Presentation of Gains & Losses or Revenue & Expense
Trading derivatives	Mark-to-market(a)	Net basis in Non-regulated Electric, Natural Gas, NGL, and Other
Non-trading derivatives:
Cash flow hedge	Accrual(b)	Gross basis in the same income statement category as the related hedged item
Fair value hedge	Accrual(b)	Gross basis in the same income statement category as the related hedged item
Normal purchase or sale	Accrual(b)	Gross basis upon settlement in the corresponding income statement category based on commodity type
Undesignated	Mark-to-market(a)	Net basis in the related income statement category for interest rate, currency and commodity derivatives

(a) 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, with the exception of Union Gas Limiteds’ (Union Gas) regulated business, which is recognized as a regulatory asset or liability. This term is applied to trading and undesignated non-trading derivative contracts. As this term is not explicitly defined within GAAP, Duke Energy’s application of this term could differ from that of other companies.

(b) 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, the associated delivery period occurs or there is hedge ineffectiveness. As discussed further below, 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 GAAP, Duke Energy’s application of this term could differ from that of other companies.

Where Duke Energy’s derivative instruments are subject to a master netting agreement and the criteria of the Financial Accounting Standards Board (FASB) Interpretation No. 39, “Offsetting of Amounts Related to Certain Contracts—An Interpretation of Accounting Principles Board (APB) Opinion No. 10 and FASB Statement No. 105” (FIN 39), are met, Duke Energy presents its derivative assets and liabilities, and accompanying receivables and payables, on a net basis in the accompanying Consolidated Balance Sheets.

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DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Cash Flow and Fair Value Hedges. Qualifying energy commodity and other derivatives may be designated as either a hedge of a forecasted transaction or future cash flows (cash flow hedge) or a hedge of a recognized asset, liability or firm commitment (fair value hedge). For all hedge contracts, Duke Energy provides formal documentation of the hedge in accordance with SFAS No. 133. In addition, at inception and on a quarterly basis Duke Energy formally assesses whether the hedge contract is highly effective in offsetting changes in cash flows or fair values of hedged items. Duke Energy documents hedging activity by transaction type (futures/swaps) and risk management strategy (commodity price risk/interest rate risk).

Changes in the fair value of a derivative designated and qualified as a cash flow hedge, to the extent effective, are included in the Consolidated Statements of Common Stockholders’ Equity and Comprehensive Income (Loss) as Accumulated Other Comprehensive Income (Loss) (AOCI) until earnings are affected by the hedged transaction. Duke Energy discontinues hedge accounting prospectively when it has determined that a derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative is subject to the Mark-to-Market Model of Accounting (MTM Model) prospectively. Gains and losses related to discontinued hedges that were previously accumulated in AOCI will remain in AOCI until the underlying contract is reflected in earnings; unless it is probable that the hedged forecasted transaction will not occur at which time associated deferred amounts in AOCI are immediately recognized in current earnings.

For derivatives designated as fair value hedges, Duke Energy recognizes the gain or loss on the derivative instrument, as well as the offsetting loss or gain on the hedged item in earnings, to the extent effective, in the current period. All derivatives designated and accounted for as hedges are classified in the same category as the item being hedged in the Consolidated Statements of Cash Flows. In addition, all components of each derivative gain or loss are included in the assessment of hedge effectiveness.

Normal Purchases and Normal Sales. From July 1, 2001 through June 30, 2003, Duke Energy applied the normal purchase and normal sale scope exception in Derivative Implementation Group (DIG) Issue C15, “Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity” to certain forward sale contracts to deliver electricity. In connection with the adoption of SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” on July 1, 2003, Duke Energy has elected to designate the majority of all forward contracts to sell power entered into after July 1, 2003 as cash flow hedges. However, on a limited basis, Duke Energy Carolinas applies the normal purchase and normal sales exception to certain contracts. Certain remaining contracts that were being accounted for under the normal purchases and normal sales exception under SFAS No. 133 as of June 30, 2003 continue to be accounted for under the normal purchases and normal sales exception as long as the requirements for applying the exception are met. If contracts cease to meet this exception, the fair value of the contracts is recognized on the Consolidated Balance Sheets and the contracts are accounted for using the MTM Model unless immediately designated as a cash flow or fair value hedge.

As a result of the September 2005 decision to pursue the sale or other disposition of substantially all of Duke Energy North America’s (DENA’s) remaining physical and commercial assets outside the Midwestern United States, DENA discontinued hedge accounting for forward natural gas and power contracts accounted for as cash flow hedges and disqualified other forward power contracts previously designated under the normal purchases normal sales exception effective September 2005.

Valuation. When available, quoted market prices or prices obtained through external sources are used to measure a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on internally developed valuation techniques or models. For derivatives recognized under the MTM Model, valuation adjustments are also recognized in the Consolidated Statements of Operations.

Goodwill. Duke Energy evaluates goodwill for potential impairment under the guidance of SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142). Under this provision, goodwill is subject to an annual test for impairment. Duke Energy has designated August 31 as the date it performs the annual review for goodwill impairment for its reporting units. Under the provisions of SFAS No. 142, Duke Energy performs the annual review for goodwill impairment at the reporting unit level, which Duke Energy has determined to be an operating segment or one level below.

Impairment testing of goodwill consists of a two-step process. The first step involves a comparison of the implied fair value of a reporting unit with its carrying amount. If the carrying amount of the reporting unit exceeds its fair value, the second step of the process involves a comparison of the fair value and carrying value of the goodwill of that reporting unit. If the carrying value of the goodwill of a

68

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

reporting unit exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess. Additional impairment tests are performed between the annual reviews if events or changes in circumstances make it more likely than not that the fair value of a reporting unit is below its carrying amount.

Duke Energy uses a discounted cash flow analysis to determine fair value. Key assumptions in the determination of fair value include the use of an appropriate discount rate, estimated future cash flows and an estimated run rates of operation, maintenance, and general and administrative costs. In estimating cash flows, Duke Energy incorporates expected growth rates, regulatory stability and ability to renew contracts as well as other factors into its revenue and expense forecasts.

Other Long-term Investments. Other long-term investments, primarily marketable securities held in the Nuclear Decommissioning Trust Funds (NDTF) and the captive insurance investment portfolio, are classified as available-for-sale securities as management does not have the intent or ability to hold the securities to maturity, nor are they bought and held principally for selling them in the near term. The securities are reported at fair value on Duke Energy’s Consolidated Balance Sheets. Unrealized and realized gains and losses, net of tax, on the NDTF are reflected in regulatory assets or liabilities on Duke Energy’s Consolidated Balance Sheets as Duke Energy expects to recover all costs for decommissioning its nuclear generation assets through regulated rates. Unrealized holding gains and losses, net of tax, on all other available-for-sale securities are reflected in AOCI in Duke Energy’s Consolidated Balance Sheets until they are realized and reflected in net income. Cash flows from purchases and sales of long-term investments (including the NDTF) are presented on a gross basis within investing cash flows in the accompanying Consolidated Statements of Cash Flows.

Property, Plant and Equipment. Property, plant and equipment are stated at the lower of historical cost less accumulated depreciation or fair value, if impaired. Duke Energy capitalizes all construction-related direct labor and material costs, as well as indirect construction costs. Indirect costs include general engineering, taxes and the cost of funds used during construction. The cost of renewals and betterments that extend the useful life of property, plant and equipment is also capitalized. The cost of repairs, replacements and major maintenance projects, which do not extend the useful life or increase the expected output of property, plant and equipment, is expensed as it is incurred. Depreciation is generally computed over the asset’s estimated useful life using the straight-line method. The composite weighted-average depreciation rates, excluding nuclear fuel, were 3.34% for 2005, 3.49% for 2004 and 3.67% for 2003. Also, see “Deferred Returns and Allowance for Funds Used During Construction (AFUDC),” discussed below.

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

Duke Energy recognizes asset retirement obligations (ARO’s) in accordance with SFAS No. 143, “Accounting For Asset Retirement Obligations” (SFAS No. 143), for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and FIN 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), for conditional ARO’s in which the timing or method of settlement are conditional on a future event that may or may not be within the control of Duke Energy. Both SFAS No. 143 and FIN 47 require that the fair value of a liability for an ARO be recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the estimated useful life of the asset. The implementation of FIN 47 did not have a material impact on the balance sheet or income statement of Duke Energy.

Investments in Residential, Commercial, and Multi-Family Real Estate. Investments in residential, commercial and multi-family real estate are carried at cost, net of any related depreciation, except for any properties meeting the criteria in SFAS No. 144, “Accounting for the Impairment or Disposal of Long-lived Assets” (SFAS No. 144), to be presented as Assets Held for Sale in the Consolidated Balance Sheets. Proceeds from sales of residential properties are presented within Operating Revenues and the cost of properties sold are included in Operation, Maintenance and Other in the Consolidated Statements of Operations. Cash flows related to the acquisition, development and disposal of residential properties are included in Cash Flows from Operating Activities in the Consolidated Statements of Cash Flows. Gains and losses on sales of commercial and multi-family properties as well as “legacy” land sales are presented as such in the Consolidated Statements of Operations, and cash flows related to these activities are included in Cash Flows from Investing Activities in the Consolidated Statements of Cash Flows.

69

PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Long-Lived Asset Impairments, Assets Held For Sale and Discontinued Operations. Duke Energy evaluates whether long-lived assets, excluding goodwill, have been impaired when circumstances indicate the carrying value of those assets may not be recoverable. For such long-lived assets, an impairment exists when its carrying value exceeds the sum of estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, a probability-weighted approach is used for developing estimates of future undiscounted cash flows. If the carrying value of the long-lived asset is not recoverable based on these estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying value over its fair value, such that the asset’s carrying value is adjusted to its estimated fair value.

Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one source. Sources to determine fair value include, but are not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as changes in commodity prices or the condition of an asset, or a change in management’s intent to utilize the asset would generally require management to re-assess the cash flows related to the long-lived assets.

Duke Energy uses the criteria in SFAS No. 144 to determine when an asset is classified as “held for sale.” Upon classification as “held for sale,” the long-lived asset or asset group is measured at the lower of its carrying amount or fair value less cost to sell, depreciation is ceased and the asset or asset group is separately presented on the Consolidated Balance Sheets. When an asset or asset group meets the SFAS No. 144 criteria for classification as held for sale within the Consolidated Balance Sheets, Duke Energy does not retrospectively adjust prior period balance sheets to conform to current year presentation.

Duke Energy uses the criteria in SFAS No. 144 and EITF 03-13, “Applying the Conditions in Paragraph 42 of FAS 144 in Determining Whether to Report Discontinued Operations” (EITF 03-13), to determine whether components of Duke Energy that are being disposed of or are classified as held for sale are required to be reported as discontinued operations in the Consolidated Statements of Operations. To qualify as a discontinued operation under SFAS No. 144, the component being disposed of must have clearly distinguishable operations and cash flows. Additionally, pursuant to EITF 03-13, Duke Energy must not have significant continuing involvement in the operations after the disposal (i.e. Duke Energy must not have the ability to influence the operating or financial policies of the disposed component) and cash flows of the assets sold must have been eliminated from Duke Energy’s ongoing operations (i.e. Duke Energy does not expect to generate significant direct cash flows from activities involving the disposed component after the disposal transaction is completed). Assuming both preceding conditions are met, the related results of operations for the current and prior periods, including any related impairments, are reflected as (Loss) Income From Discontinued Operations, net of tax, in the Consolidated Statements of Operations. If an asset held for sale does not meet the requirements for discontinued operations classification, any impairments and gains or losses on sales are recorded in continuing operations as Gains (Losses) on Sales of Other Assets, net, in the Consolidated Statements of Operations. Impairments for all other long-lived assets, other than goodwill, are recorded as Impairment and Other Charges in the Consolidated Statements of Operations.

Captive Insurance Reserves. Duke Energy has captive insurance subsidiaries which provide insurance coverage to Duke Energy entities as well as certain third parties, on a limited basis, for various business risks and losses, such as workers compensation, property, business interruption and general liability. Liabilities include provisions for estimated losses incurred, but not yet reported (IBNR), as well as provisions for known claims which have been estimated on a claims-incurred basis. IBNR reserve estimates involve the use of assumptions and are primarily based upon historical loss experience, industry data and other actuarial assumptions. Reserve estimates are adjusted in future periods as actual losses differ from historical experience. Intercompany balances and transactions are eliminated in consolidation.

Duke Energy’s captive insurance entities also have reinsurance coverage, which provides reimbursement to Duke Energy for certain losses above a per incident and/or aggregate retention. Duke Energy’s captive insurance entities also have an aggregate stop-loss insurance coverage, which provides reimbursement from third parties to Duke Energy for its paid losses above certain per line of coverage aggregate amounts during a policy year. Duke Energy recognizes a reinsurance receivable for recovery of incurred losses under its captive’s reinsurance and stop-loss insurance coverage once realization of the receivable is deemed probable by its captive insurance companies.

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

During 2004, Duke Energy eliminated intercompany reserves at its captive insurance subsidiaries of approximately $64 million which was a correction of an immaterial accounting error related to prior periods.

Unamortized Debt Premium, Discount and Expense. Premiums, discounts and expenses incurred with the issuance of outstanding long-term debt are amortized over the terms of the debt issues. Any call premiums or unamortized expenses associated with refinancing higher-cost debt obligations to finance regulated assets and operations are amortized consistent with regulatory treatment of those items, where appropriate. Certain debt costs were expensed on an accelerated basis in 2003 as required by the Public Service Commission of South Carolina (PSCSC) under the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71). (See Cost-Based Regulation below for further discussion of SFAS No. 71.)

Environmental Expenditures. Duke Energy expenses environmental expenditures related to conditions caused by past operations that do not generate current or future revenues. Environmental expenditures related to operations that generate current or future revenues are expensed or capitalized, as appropriate. Liabilities are recorded when the necessity for environmental remediation becomes probable and the costs can be reasonably estimated, or when other potential environmental liabilities are reasonably estimable and probable.

Cost-Based Regulation. Duke Energy accounts for certain of its regulated operations under the provisions of SFAS No. 71. The economic effects of regulation can result in a regulated company recording assets for costs that have been or are expected to be approved for recovery from customers or recording liabilities for amounts that are expected to be returned to customers in the rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, Duke Energy records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. Management continually assesses whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes, recent rate orders applicable to other regulated entities and the status of any pending or potential deregulation legislation. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. These regulatory assets and liabilities are primarily classified in the Consolidated Balance Sheets as Regulatory Assets and Deferred Debits, and Deferred Credits and Other Liabilities. Duke Energy periodically evaluates the applicability of SFAS No. 71, and considers factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, companies may have to reduce their asset balances to reflect a market basis less than cost and write-off their associated regulatory assets and liabilities. (For further information see Note 4.)

Guarantees. Duke Energy accounts for guarantees and related contracts, for which it is the guarantor, under FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45). In accordance with FIN 45, upon issuance or modification of a guarantee on or after January 1, 2003, Duke Energy recognizes a liability at the time of issuance or material modification for the estimated fair value of the obligation it assumes under that guarantee. Fair value is estimated using a probability-weighted approach. Duke Energy reduces the obligation over the term of the guarantee or related contract in a systematic and rational method as risk is reduced under the obligation. Any additional contingent loss for guarantee contracts is accounted for and recognized in accordance with SFAS No. 5, “Accounting for Contingencies” (SFAS No. 5).

Duke Energy has entered into various indemnification agreements related to purchase and sale agreements and other types of contractual agreements with vendors and other third parties. These agreements typically cover environmental, tax, litigation and other matters, as well as breaches of representations, warranties and covenants. Typically, claims may be made by third parties for various periods of time, depending on the nature of the claim. Duke Energy’s potential exposure under these indemnification agreements can range from a specified to an unlimited dollar amount, depending on the nature of the claim and the particular transaction.

Stock-Based Compensation. Through December 31, 2005, Duke Energy accounted for its stock-based compensation arrangements under the intrinsic value recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and FIN 44, “Accounting for Certain Transactions Involving Stock Compensation (an Interpretation of APB Opinion No. 25).” Since the exercise price for all options granted under those plans was equal to the market value of the underlying common stock on the date of grant, no compensation cost is recognized in the accompanying Consolidated Statements of Operations. Restricted stock grants, phantom stock awards and certain stock-based performance awards are recorded over the required vesting period as compensation cost, based on the market value on the date of the grant. Other stock-based performance awards are recorded over the vesting period

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For the Years Ended December 31, 2005, 2004 and 2003

as compensation cost, and are adjusted for increases and decreases in market value up to the measurement date. Compensation expense for awards with pro-rata vesting is recognized in accordance with FASB Interpretation No 28 (FIN 28), “Accounting for Stock Appreciation Rights and Other Variable Stock Option or Award Plans.”

The following table shows what earnings available for common stockholders, basic earnings per share and diluted earnings per share (EPS) would have been if Duke Energy had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” and provisions of SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure (an amendment of FASB Statement No. 123),” to all stock-based compensation awards.

Pro Forma Stock-Based Compensation

	For the years ended December 31,
	2005			2004			2003
	(in millions, except per share amounts)
Earnings (loss) available for common stockholders, as reported	$	1,812		$	1,481		$	(1,338	)
Add: stock-based compensation expense included in reported net income (loss), net of related tax effects		30			16			6
Deduct: total stock-based compensation expense determined under fair value-based method for all awards, net of related tax effects		(32	)		(27	)		(30	)
Pro forma earnings (loss) available for common stockholders, net of related tax effects	$	1,810		$	1,470		$	(1,362	)
Earnings (loss) per share
Basic—as reported	$	1.94		$	1.59		$	(1.48	)
Basic—pro forma	$	1.94		$	1.58		$	(1.51	)
Diluted—as reported	$	1.88		$	1.54		$	(1.48	)
Diluted—pro forma	$	1.87		$	1.53		$	(1.51	)

Effective January 1, 2006, Duke Energy adopted the provisions of SFAS No. 123 (Revised 2004), “Share Based Payment” (SFAS No. 123R). See “New Accounting Standards” below for impact of adoption.

Revenue Recognition. Revenues on sales of electricity, primarily at Franchised Electric, are recognized when the service is provided. Unbilled revenues are estimated by applying an average revenue/kilowatt hour for all customer classes to the number of estimated kilowatt hours delivered, but not billed. Differences between actuals and estimates are immaterial.

Revenues on sales of natural gas, natural gas transportation, storage and distribution as well as sales of petroleum products, primarily at Natural Gas Transmission and Field Services (prior to deconsolidation on July 1, 2005), are recognized when either the service is provided or the product is delivered. Revenues related to these services provided or products delivered, but not yet billed, are estimated each month. These estimates are generally based on contract data, regulatory information, estimated distribution usage based on historical data adjusted for heating degree days, commodity prices and preliminary throughput and allocation measurements. Final bills for the current month are billed and collected in the following month. Differences between actuals and estimates are immaterial.

Crescent LLC (Crescent) sells residential developed lots in North Carolina, South Carolina, Georgia, Florida, Texas and Arizona. Crescent recognizes revenues from the sale of residential developed lots at closing. Profit is recognized under the full accrual method using estimates of average gross profit per lot within a project or phase of a project based on total estimated project costs. Land and land development costs are allocated to land sold based on relative sales values. Crescent recognizes revenues from commercial and multi-family project sales at closing, or later using a deferral method when the criteria for sale accounting have not been met at closing. Profit is recognized based on the difference between the sales price and the carrying cost of the project. Crescent develops and sells condominium units in Florida, and revenue is recognized under the percentage-of-completion method.

Nuclear Fuel. Amortization of nuclear fuel purchases is included in the Consolidated Statements of Operations as Fuel Used in Electric Generation and Purchased Power. The amortization is recorded using the units-of-production method.

Deferred Returns and Allowance for Funds Used During Construction (AFUDC). Deferred returns, recorded in accordance with SFAS No. 71, represent the estimated financing costs associated with funding certain regulatory assets or liabilities of Franchised Electric. Those costs arise primarily from the funding of purchased capacity costs collected in rates. Deferred returns are non-cash items

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For the Years Ended December 31, 2005, 2004 and 2003

and are primarily recognized as an addition to purchased capacity costs, which are included in Other Current Liabilities and Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets, with an offsetting debit or credit to Other Income and Expenses, net. The amount of deferred returns included in Other Income and Expenses, net was ($13) million in 2005, ($9) million in 2004 and $6 million in 2003.

AFUDC, which represents the estimated debt and equity costs of capital funds necessary to finance the construction of new regulated facilities, consists of two components, an equity component and an interest component. The equity component is a non-cash item. AFUDC is capitalized as a component of Property, Plant and Equipment Cost, with offsetting credits to the Consolidated Statements of Operations. After construction is completed, Duke Energy is permitted to recover these costs through inclusion in the rate base and in the depreciation provision. The total amount of AFUDC included in the Consolidated Statements of Operations was $48 million in 2005, which consisted of an after-tax equity component of $30 million and a before-tax interest expense component of $18 million. The total amount of AFUDC included in the Consolidated Statements of Operations was $39 million in 2004, which consisted of an after-tax equity component of $25 million and a before-tax interest expense component of $14 million. The total amount of AFUDC included in the Consolidated Statements of Operations was $108 million in 2003, which consisted of an after-tax equity component of $74 million and a before-tax interest expense component of $34 million.

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

Management evaluates and records contingent tax liabilities and related interest based on the probability of ultimately sustaining the tax deductions or income positions. Management assesses the probabilities of successfully defending the tax deductions or income positions based upon statutory, judicial or administrative authority.

Excise and Other Pass-Through Taxes. Duke Energy presents revenues net of pass-through taxes on the Consolidated Statements of Operations.

Emission Allowances. Duke Energy accounts for emission allowances in the Consolidated Balance Sheets as intangible assets, which are included in Other within Investments and Other Assets in the accompanying Consolidated Balance Sheets. Emission allowances are initially recorded on a historical cost basis. The cost of emission allowances is charged to income as the allowances are used. Cash flows associated with emission allowances are presented as investing activities within the Consolidated Statements of Cash Flows.

Segment Reporting. SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information” (SFAS No. 131), establishes standards for a public company to report financial and descriptive information about its reportable operating segments in annual and interim financial reports. Operating segments are components of an enterprise about which separate financial information is available and evaluated regularly by the chief operating decision maker in deciding how to allocate resources and evaluate performance. Two or more operating segments may be aggregated into a single reportable segment provided aggregation is consistent with the objective and basic principles of SFAS No. 131, if the segments have similar economic characteristics, and the segments are considered similar under criteria provided by SFAS No. 131. There is no aggregation within Duke Energy’s defined business segments. SFAS No. 131 also establishes standards and related disclosures about the way the operating segments were determined, products and services, geographic areas and major customers, differences between the measurements used in reporting segment information and those used in the company’s general-purpose financial statements, and changes in the measurement of segment amounts from period to period. The description of Duke Energy’s reportable segments, consistent with how business results are reported internally to management and the disclosure of segment information in accordance with SFAS No. 131, are presented in Note 3.

Foreign Currency Translation. The local currencies of Duke Energy’s foreign operations have been determined to be their functional currencies, except for certain foreign operations whose functional currency has been determined to be the U.S. Dollar, based on an assessment of the economic circumstances of the foreign operation, in accordance with SFAS No. 52, “Foreign Currency Translation.” Assets and liabilities of foreign operations, except for those whose functional currency is the U.S. Dollar, are translated into U.S. Dollars at current exchange rates. Translation adjustments resulting from fluctuations in exchange rates are included as a separate component of AOCI. Revenue and expense accounts of these operations are translated at average exchange rates prevailing during the year. Transaction gains and losses, which were not material for all periods presented, are included in the results of operations of the period in which

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

they occur. Deferred taxes are not provided on translation gains and losses where Duke Energy expects earnings of a foreign operation to be permanently reinvested. Gains and losses relating to derivatives designated as hedges of the foreign currency exposure of a net investment in foreign operations are reported in foreign currency translation as a separate component of AOCI.

Distributions from Equity Investees. Duke Energy considers dividends received from equity investees which do not exceed cumulative equity in earnings subsequent to the date of investment a return on investment and classifies these amounts as operating activities within the accompanying Consolidated Statements of Cash Flows. Cumulative dividends received in excess of cumulative equity in earnings subsequent to the date of investment are considered a return of investment and are classified as investing activities within the accompanying Consolidated Statements of Cash Flows.

Cumulative Effect of Changes in Accounting Principles. As of December 31, 2005, Duke Energy adopted the provisions of FIN 47. In accordance with the transition guidance of this standard, Duke Energy recorded a net-of-tax cumulative effect adjustment of approximately $4 million. The cumulative effect adjustment had an immaterial impact on EPS.

As of January 1, 2003, Duke Energy adopted the remaining provisions of EITF 02-03 and SFAS No. 143. In accordance with the transition guidance for these standards, Duke Energy recorded a net-of-tax and minority interest cumulative effect adjustment for change in accounting principles of $162 million, or $0.18 per basic share, as a reduction in earnings.

In October 2002, the EITF reached a final consensus on EITF 02-03. Primarily, the final consensus provided for (1) the rescission of the consensus reached on EITF 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” (2) the reporting of gains and losses on all derivative instruments considered to be held for trading purposes to be shown on a net basis in the income statement, and (3) gains and losses on non-derivative energy trading contracts to be similarly presented on a gross or net basis, in connection with the guidance in EITF 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.”

As a result of the consensus on EITF 02-03, Duke Energy recorded a cumulative effect adjustment of $151 million (net of tax and minority interest) in the first quarter 2003 as a reduction to earnings. The recorded value on January 1, 2003 of all non-derivative energy trading contracts that existed on October 25, 2002 were written-off and inventories that were recorded at fair values were adjusted to historical cost.

In June 2001, the FASB issued SFAS No. 143, which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the related asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. For obligations related to non-regulated operations, a cumulative effect adjustment of $11 million (net of tax and minority interest) was recorded in the first quarter of 2003, as a reduction in earnings.

New Accounting Standards. The following new accounting standards were adopted by Duke Energy during the year ended December 31, 2005 and the impact of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:

SFAS No. 153, “Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29” (SFAS No. 153). In December 2004, the FASB issued SFAS No. 153 which amends APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” by eliminating the exception to the fair-value principle for exchanges of similar productive assets, which were accounted for under APB Opinion No. 29 based on the book value of the asset surrendered with no gain or loss recognition. SFAS No. 153 also eliminates APB Opinion No. 29’s concept of culmination of an earnings process. The amendment requires that an exchange of nonmonetary assets be accounted for at fair value if the exchange has commercial substance and fair value is determinable within reasonable limits. Commercial substance is assessed by comparing the entity’s expected cash flows immediately before and after the exchange. If the difference is significant, the transaction is considered to have commercial substance and should be recognized at fair value. SFAS No. 153 is effective for nonmonetary transactions occurring on or after July 1, 2005. The adoption of SFAS No. 153 did not have a material impact on Duke Energy’s consolidated results of operations, cash flows or financial position.

FASB Interpretation No. 47 “Accounting for Conditional Asset Retirement Obligations” (FIN 47). In March 2005, the FASB issued FIN 47, which clarifies the accounting for conditional asset retirement obligations as used in SFAS No. 143. A conditional asset retirement obligation is an unconditional legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. Therefore, an entity is required to recognize a liability

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

for the fair value of a conditional asset retirement obligation under SFAS No. 143 if the fair value of the liability can be reasonably estimated. The provisions of FIN 47 were effective for Duke Energy as of December 31, 2005. See Note 7.

FASB Staff Position (FSP) No. APB 18-1, “Accounting by an Investor for Its Proportionate Share of Accumulated Other Comprehensive Income of an Investee Accounted for under the Equity Method in Accordance with APB Opinion No. 18 upon a Loss of Significant Influence” (FSP No. APB 18-1). In July of 2005, the FASB staff issued FSP No. APB 18-1 which provides guidance for how an investor should account for its proportionate share of an investee’s equity adjustments for other comprehensive income (OCI) upon a loss of significant influence. APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock” (APB Opinion No. 18), requires a transaction of an equity method investee of a capital nature be accounted for as if the investee were a consolidated subsidiary, which requires the investor to record its proportionate share of the investee’s adjustments for OCI as increases or decreases to the investment account with corresponding adjustments in equity. FSP No. APB 18-1 requires that an investor’s proportionate share of an investee’s equity adjustments for OCI should be offset against the carrying value of the investment at the time significant influence is lost and equity method accounting is no longer appropriate. However, to the extent that the offset results in a carrying value of the investment that is less than zero, an investor should (a) reduce the carrying value of the investment to zero and (b) record the remaining balance in income. The guidance in FSP No. APB 18-1 was effective for Duke Energy beginning October 1, 2005. The adoption of FSP No. APB 18-1 did not have a material impact on Duke Energy’s consolidated results of operations, cash flows or financial position.

The following new accounting standards were adopted by Duke Energy during the year ended December 31, 2004 and the impact of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:

FASB Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46). In January 2003, the FASB issued FIN 46 which requires the primary beneficiary of a variable interest entity’s activities to consolidate the variable interest entity. FIN 46 defines a variable interest entity as an entity in which the equity investors do not have substantive voting rights and there is not sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. The primary beneficiary absorbs a majority of the expected losses and/or receives a majority of the expected residual returns of the variable interest entity’s activities. In December 2003, the FASB issued FIN 46 (Revised December 2003), “Consolidation of Variable Interest Entities—An Interpretation of ARB No. 51” (FIN 46R), which supersedes and amends the provisions of FIN 46. While FIN 46R retains many of the concepts and provisions of FIN 46, it also provides additional guidance and additional scope exceptions, and incorporates FASB Staff Positions related to the application of FIN 46.

The provisions of FIN 46 applied immediately to variable interest entities created, or interests in variable interest entities obtained, after January 31, 2003, while the provisions of FIN 46R were required to be applied to those entities, except for special purpose entities, by the end of the first reporting period ending after March 15, 2004 (March 31, 2004 for Duke Energy). For variable interest entities created, or interests in variable interest entities obtained, on or before January 31, 2003, FIN 46 or FIN 46R was required to be applied to special-purpose entities by the end of the first reporting period ending after December 15, 2003 (December 31, 2003 for Duke Energy), and was required to be applied to all other non-special purpose entities by the end of the first reporting period ending after March 15, 2004 (March 31, 2004 for Duke Energy).

Duke Energy has not identified any material variable interest entities created, or interests in variable entities obtained, after January 31, 2003, which require consolidation or disclosure under FIN 46R. Under the provisions of FIN 46R, effective March 31, 2004, Duke Energy has consolidated certain non-special purpose operating entities, previously accounted for under the equity method of accounting. These entities, which are substantive entities, had an immaterial amount of total assets as of December 31, 2005 and approximately $230 million as of December 31, 2004. In addition, as of December 31, 2005 and 2004, Duke Energy has recorded Net Property, Plant and Equipment of $109 million and $112 million, respectively, and Long-term Debt of $173 million and $168 million, respectively, on the Consolidated Balance Sheets, associated with a variable interest entity that is consolidated by Duke Energy. Duke Energy leases a natural gas processing plant from this entity, and retains all rights and obligations associated with the operations of this plant. This variable interest entity was consolidated on Duke Energy’s Consolidated Financial Statements prior to March 31, 2004 (the effective date of FIN 46R) primarily due to Duke Energy’s guarantee of the residual value of the assets. The impact of consolidating these entities on Duke Energy’s consolidated financial statements was not material.

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Various changes and clarifications to the provisions of FIN 46 have been made by the FASB since its original issuance in January 2003. While not anticipated at this time, any additional clarifying guidance or further changes to these complex rules could have an impact on Duke Energy’s Consolidated Financial Statements.

SFAS No. 132 (Revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits” (SFAS No. 132R). In December 2003, the FASB revised the provisions of SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits—an amendment of FASB Statements No. 87, 88, and 106,” to include additional disclosures related to defined-benefit pension plans and other defined-benefit post-retirement plans, such as the following:

• The long-term rate of return on plan assets, along with a narrative discussion on the basis for selecting the rate of return used

• Information about plan assets for each major asset category (i.e. equity securities, debt securities, real estate, etc.) along with the targeted allocation percentage of plan assets for each category and the actual allocation percentages at the measurement date

• The amount of benefit payments expected to be paid in each of the next five years and the following five-year period in the aggregate

• The current best estimate of the range of contributions expected to be made in the following year

• The accumulated benefit obligation for defined-benefit pension plans

• Disclosure of the measurement date utilized.

Additionally, interim reports require additional disclosures related to the components of net periodic pension costs and the amounts paid or expected to be paid to the plan in the current fiscal year, if materially different than amounts previously disclosed. The provisions of SFAS No. 132R do not change the measurement or recognition provisions of defined-benefit pension and post-retirement plans as required by previous accounting standards. The provisions of SFAS No. 132R were applied by Duke Energy effective December 31, 2003 with the interim period disclosures applied beginning with the quarter ended March 31, 2004, except for the disclosure provisions of estimated future benefit payments which were effective for Duke Energy for the year ended December 31, 2004. (See Note 22 for the additional related disclosures).

FSP No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP No. FAS 106-2). In May 2004, the FASB staff issued FSP No. FAS 106-2, which superseded FSP FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” FSP No. FAS 106-2 provides accounting guidance for the effects of the Medicare Prescription Drug Improvement and Modernization Act of 2003 (the Modernization Act). The Modernization Act introduced a prescription drug benefit under Medicare, as well as a federal subsidy to sponsors of retiree health care benefit plans that include prescription drug benefits. FSP No. FAS 106-2 requires a sponsor to determine if its prescription drug benefits are actuarially equivalent to the drug benefit provided under Medicare Part D as of the date of enactment of the Modernization Act, and if it is therefore entitled to receive the subsidy. If a sponsor determines that its prescription drug benefits are actuarially equivalent to the Medicare Part D benefit, the sponsor should recognize the expected subsidy in the measurement of the accumulated postretirement benefit obligation (APBO) under SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” Any resulting reduction in the APBO is to be accounted for as an actuarial experience gain. The subsidy’s reduction, if any, of the sponsor’s share of future costs under its prescription drug plan is to be reflected in current-period service cost.

The provisions of FSP No. FAS 106-2 were effective for the first interim period beginning after June 15, 2004. Duke Energy adopted FSP No. FAS 106-2 retroactively to the date of enactment of the Modernization Act, December 8, 2003, as allowed by the FSP. (See Note 22 for discussion of the effects of adopting this FSP).

FSP No. FAS 109-1, “Application of FASB Statement No. 109, ‘Accounting for Income Taxes,’ to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004” (FSP No. FAS 109-1). On October 22, 2004, the President signed the American Jobs Creation Act of 2004 (the Act). The Act provides a deduction for income from qualified domestic production activities, which will be phased in from 2005 through 2010.

Under the guidance in FSP No. FAS 109-1, which was issued in December 2004, the deduction will be treated as a “special deduction” as described in SFAS No. 109, “Accounting for Income Taxes” (SFAS No. 109). As such, for Duke Energy, the special deduction had no material impact on deferred tax assets and liabilities existing at the enactment date. Rather, the impact of this

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For the Years Ended December 31, 2005, 2004 and 2003

deduction is reported in the periods in which the deductions are claimed on the tax returns. For the year ended December 31, 2005, Duke Energy recognized a benefit of approximately $9 million relating to the deduction from qualified domestic activities.

FSP No. FAS 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004” (FSP No. FAS 109-2). In addition to the qualified domestic production activities deduction discussed above, the Act creates a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing an 85 percent dividends received deduction for certain dividends from controlled foreign corporations. FSP No. FAS 109-2, which was issued in December 2004, states that a company is allowed time beyond the financial reporting period of enactment to evaluate the effect of the Act on its plan for reinvestment or repatriation of foreign earnings, as it applies to the application of SFAS No. 109. Although the deduction is subject to a number of limitations and some uncertainty remains as to how to interpret numerous provisions in the Act, Duke Energy believes that it has the information necessary to make an informed decision on the impact of the Act on its repatriation plans. Based on that decision, Duke Energy has repatriated approximately $500 million in extraordinary dividends, as defined in the Act, and accordingly has recorded a corresponding tax liability of $39 million as of December 31, 2005. However, Duke Energy has not provided for U.S. deferred income taxes or foreign withholding tax on basis differences in our non-U.S. subsidiaries that result primarily from undistributed earnings of approximately $290 million as of December 31, 2005, which Duke Energy intends to reinvest indefinitely. Determination of the deferred tax liability on these basis differences is not practicable because such liability, if any, is dependent on circumstances existing if and when remittance occurs.

EITF 04-08, “The Effect of Contingently Convertible Debt on Diluted Earnings per Share” (EITF 04-08). In September 2004, the EITF reached a consensus on Issue No. 04-8. The consensus requires that the potential common stock related to contingently convertible securities (Co-Cos) with market price contingencies be included in diluted earnings per share calculations using the if-converted method specified in SFAS No. 128, “Earnings per Share” (SFAS No. 128), whether the market price contingencies have been met or not. Co-Cos generally require conversion into a company’s common stock if certain specified events occur, such as a specified market price for the company’s common stock. Prior to the issuance of EITF 04-08, Co-Cos were treated as contingently issuable shares under SFAS No. 128, and therefore, the contingencies, must have been met in order for the potential common shares to be included in diluted EPS. Therefore, Co-Cos were only included in diluted EPS during periods in which the contingencies had been met. The consensus is effective for fiscal years ended after December 15, 2004 and is required to be applied retroactively to all periods in which any Co-Cos were outstanding, resulting in restatement of diluted EPS if the impact of the Co-Cos was dilutive.

As discussed in Note 15, Duke Energy issued $770 million par value of contingently convertible notes in May of 2003, bearing an interest rate of 1.75% per annum that contain several contingencies, including a market price contingency that, if met, may require conversion of the notes into Duke Energy common stock. Conversion may be required, at the option of the holder, if any one of the contingencies is met. During 2005, these convertible senior notes became convertible into shares of Duke Energy common stock due to the market price of Duke Energy common stock. Holders of the convertible senior notes were allowed to exercise their right to convert on or prior to December 31, 2005. During 2005, approximately 1.2 million shares of common stock were issued related to this conversion, which resulted in the retirement of approximately $28 million of convertible senior notes. Therefore, as discussed in Note 19, Duke Energy has included potential common shares of approximately 32 million and 33 million for the years ended December 31, 2005 and 2004, respectively, in the calculation of diluted EPS.

The following new accounting standards were issued, but have not yet been adopted by Duke Energy as of December 31, 2005:

SFAS No. 123R. In December of 2004, the FASB issued SFAS No. 123R, which replaces SFAS No. 123 and supersedes APB Opinion No. 25. SFAS No. 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values. For Duke Energy, timing for implementation of SFAS No. 123R is January 1, 2006. The pro forma disclosures previously permitted under SFAS No. 123 will no longer be an acceptable alternative. Instead, Duke Energy will be required to record compensation expense in the Consolidated Statements of Operations for stock options. Under SFAS No. 123R, Duke Energy must determine an appropriate expense for stock options and the transition method to be used effective January 1, 2006. The transition methods include prospective and retroactive adoption options. Both methods record compensation expense for all unvested awards beginning January 1, 2006. Under the retroactive method, prior periods presented are also restated for awards which have vested prior to January 1, 2006.

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For the Years Ended December 31, 2005, 2004 and 2003

Duke Energy currently also has retirement eligible employees with outstanding share-based payment awards (restricted stock awards, stock based performance awards and phantom stock awards). Compensation cost related to those awards is currently expensed over the stated vesting period or until actual retirement occurs. Effective January 1, 2006, Duke Energy will recognize compensation cost for new awards granted to employees over the requisite service period, which generally begins on the date the award is granted through the earlier of the date the award vests or the date the employee becomes retirement eligible. Awards, including stock options, granted to employees that are already retirement eligible will be deemed to have vested immediately upon issuance, and therefore, compensation cost for those awards will be recognized on the date such awards are granted.

The impact on EPS for the years ended December 31, 2005, 2004 and 2003 had Duke Energy followed the expensing provisions of SFAS No. 123 is disclosed above in the Pro Forma Stock-Based Compensation table. Duke Energy plans to implement SFAS No. 123R using the prospective transition method and currently there are no plans to change the option-pricing model used for share-based compensation awards issued to employees in future periods. SFAS No. 123R, which was adopted by Duke Energy effective January 1, 2006, is not anticipated to have a material impact on its consolidated results of operations, cash flows or financial position in 2006 based on awards outstanding as of the implementation date. However, the impact to Duke Energy in periods subsequent to adoption of SFAS No. 123R will be largely dependent upon the nature of any new share-based compensation awards issued to employees.

Staff Accounting Bulletin (SAB) No. 107, “Share-Based Payment” (SAB 107). On March 29, 2005, the Securities and Exchange Commission (SEC) staff issued SAB 107 to express the views of the staff regarding the interaction between SFAS No. 123R and certain SEC rules and regulations and to provide the staff’s views regarding the valuation of share-based payment arrangements for public companies. Duke Energy is currently in the process of implementing SFAS No. 123R, effective as of January 1, 2006, and will take into consideration the additional guidance provided by SAB 107 in connection with the implementation of SFAS No. 123R.

FSP No. FAS 115-1 and 124-1, “The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments.” The FASB issued FSP No. FAS 115-1 and 124-1 in November 2005 which is effective for Duke Energy beginning January 1, 2006. This FSP addresses the determination as to when an investment is considered impaired, whether that impairment is other than temporary, and the measurement of an impairment loss. This FSP also includes accounting considerations subsequent to the recognition of an other-than-temporary impairment and requires certain disclosures about unrealized losses that have not been recognized as other-than-temporary impairments. The guidance in this FSP amends SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities, and SFAS No. 124, Accounting for Certain Investments Held by Not-for-Profit Organizations, and APB Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock. The adoption of FSP No. FAS 115-1 and 124-1 will not have a material impact on Duke Energy’s consolidated results of operations, cash flows or financial position.

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For the Years Ended December 31, 2005, 2004 and 2003

2. Acquisitions and Dispositions

Acquisitions. Duke Energy consolidates assets and liabilities from acquisitions as of the purchase date, and includes earnings from acquisitions in consolidated earnings after the purchase date. Assets acquired and liabilities assumed are recorded at estimated fair values on the date of acquisition. The purchase price minus the estimated fair value of the acquired assets and liabilities meeting the definition of a business as defined in EITF 98-3, “Determining Whether a Nonmonetary Transaction Involves Receipt of Productive Assets or of a Business” (EITF 98-3), is recorded as goodwill. The allocation of the purchase price may be adjusted if additional information on known contingencies existing at the date of acquisition becomes available within one year after the acquisition, and longer for certain income tax items.

On May 9, 2005, Duke Energy and Cinergy Corp. (Cinergy) announced they entered into a definitive merger agreement. Upon consummation of the transaction set forth in the merger agreement, each common share of Cinergy will be converted into 1.56 shares of common stock of a newly-created holding company (to be renamed Duke Energy Corporation) and each common share of Duke Energy will be converted into one share of the holding company. Based on Cinergy shares outstanding at December 31, 2005, the holding company would issue approximately 310 million shares to convert the Cinergy common shares. The merger will be accounted for under the purchase method of accounting with Duke Energy treated as the acquirer for accounting purposes. Based on the market price of Duke Energy common stock during the period including the two trading days before through the two trading days after May 9, 2005, the date Duke Energy and Cinergy announced the merger, had the transaction closed at December 31, 2005, it would have been valued approximately as follows:

Pro forma Cinergy Merger Transaction Value (unaudited)

Value of common stock and other consideration provided	$	9 billion
Fair value of net assets acquired		5 billion
Incremental goodwill from Cinergy acquisition	$	4 billion

The merger agreement has been unanimously approved by both companies’ Boards of Directors. Closing of the transaction is currently anticipated for the second quarter of 2006. Completion of the merger is subject to a number of conditions, including the approval of shareholders of both companies and a number of federal and state governmental authorities. Special meetings of the Duke Energy and Cinergy shareholders to vote on the merger are scheduled for March 10, 2006. See further discussion of regulatory filings in Note 4. The merger agreement contains certain cross-approval provisions whereby Duke Energy and Cinergy are required to continue to operate their businesses in the ordinary course of business and must obtain the other party’s consent prior to making new investments or disposing of businesses above specified thresholds, entering into new debt above specified thresholds, issuing new common stock (other than under employee compensation arrangements) or making dividend changes, among other provisions.

In August 2005, Natural Gas Transmission acquired natural gas storage and pipeline assets in Southwest Virginia and an additional 50% interest in Saltville Gas Storage LLC (Saltville Storage) from units of AGL Resources for approximately $62 million. This transaction increased Natural Gas Transmission’s ownership percentage of Saltville Storage to 100%. No goodwill was recorded as a result of this acquisition.

In August 2005, Natural Gas Transmission acquired the Empress System natural gas processing and NGL marketing business from ConocoPhillips for approximately $230 million as part of the Field Services ConocoPhillips transaction discussed further in the Dispositions section below. No goodwill was recorded as a result of this acquisition.

In the second quarter of 2005, United Bridgeport Energy LLC (UBE), the owner of a 33 ¹/3% interest in Bridgeport Energy LLC (Bridgeport), exercised its “put right” requiring Duke Energy to purchase UBE’s interest in Bridgeport as provided for in the LLC Agreement. Duke Energy and UBE have finalized a settlement for the purchase price of UBE’s ownership interest. This settlement will not have a material adverse effect on Duke Energy’s future consolidated results of operations, cash flows or financial position. Upon closing of this transaction, Duke Energy will own 100% of Bridgeport. The assets and liabilities of Bridgeport have been classified as Assets Held for Sale in the accompanying Consolidated Balance Sheet as of December 31, 2005, and will be included as part of DENA’s power generation assets to be sold to a subsidiary of LS Power Equity Partners (LS Power) (see Note 13).

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For the Years Ended December 31, 2005, 2004 and 2003

In the second quarter of 2004, Field Services acquired gathering, processing and transmission assets in southeast New Mexico from ConocoPhillips for a total purchase price of approximately $80 million, consisting of $74 million in cash and the assumption of approximately $6 million of liabilities. As the acquired assets were not considered businesses under the guidance in EITF 98-3, no goodwill was recognized in connection with this transaction.

In the third quarter of 2004, Field Services acquired additional interest in three separate entities (for which DEFS owned less than 100%, but had been consolidating) for a total purchase price of $4 million, and the exchange of some Field Services’ assets. Two of these acquisitions, Mobile Bay Processing Partners (MBPP) and Gulf Coast NGL Pipeline, LLC (GC), resulted in 100% ownership by Field Services. The MBPP transaction involved MBPP transferring certain long-lived assets to El Paso Corporation for El Paso Corporation’s interest in MBPP. As a result of this non-monetary transaction, the assets transferred were written-down to their estimated fair value which resulted in Duke Energy recognizing a pre-tax impairment of approximately $13 million, which was approximately $4 million net of minority interest. An additional 12% interest in Dauphin Island Gathering Partners (DIGP) was also purchased for $2 million, which resulted in 84% ownership by Field Services. MBPP owns processing assets in the Onshore Gulf of Mexico. GC owns a 16.67% interest in two equity investments. DIGP owns gathering and transmission assets in the Offshore Gulf of Mexico.

The pro forma results of operations for Duke Energy as if those acquisitions which closed prior to December 31, 2005 occurred as of the beginning of the periods presented do not materially differ from reported results.

Dispositions. For the year ended December 31, 2005, the sale of other assets, businesses and equity investments resulted in approximately $2.3 billion in proceeds, pre-tax gains of $534 million recorded in Gains (Losses) on Sales of Other Assets, net, on the accompanying Consolidated Statements of Operations and pre-tax gains of $1,225 million recorded in Gains (Losses) on Sales and Impairments of Equity Method Investments on the accompanying Consolidated Statements of Operations. These sales exclude assets that were held for sale and reflected in discontinued operations, both of which are discussed in Note 13, and commercial and multi-family real estate sales by Crescent which are discussed separately below. Significant sales of other assets and equity investments during 2005 are detailed as follows:

• In February 2005, DEFS sold its wholly owned subsidiary Texas Eastern Products Pipeline Company, LLC (TEPPCO GP), which is the general partner of TEPPCO Partners, LP (TEPPCO LP), for approximately $1.1 billion and Duke Energy sold its limited partner interest in TEPPCO LP for approximately $100 million, in each case to Enterprise GP Holdings LP, an unrelated third party. These transactions resulted in pre-tax gains of $1.2 billion, which were recorded in Gains (Losses) on Sales and Impairments of Equity Method Investments in the Consolidated Statements of Operations. Minority Interest Expense of $343 million was recorded in the accompanying Consolidated Statements of Operations to reflect ConocoPhillips’ proportionate share in the pre-tax gain on sale of TEPPCO GP.

Additionally, in July 2005, Duke Energy completed the previously announced agreement with ConocoPhillips, Duke Energy’s co-equity owner in DEFS, to reduce Duke Energy’s ownership interest in DEFS from 69.7% to 50% (the DEFS disposition transaction), which results in Duke Energy and ConocoPhillips becoming equal 50% owners in DEFS. Duke Energy has received, directly and indirectly through its ownership interest in DEFS, a total of approximately $1.1 billion from ConocoPhillips and DEFS, consisting of approximately $1.0 billion in cash and approximately $0.1 billion of assets. The DEFS disposition transaction resulted in a pre-tax gain of approximately $575 million, which was recorded in Gains (Losses) on Sales of Other Assets, net, in the accompanying Consolidated Statements of Operations. The DEFS disposition transaction includes the transfer to Duke Energy of DEFS’ Canadian natural gas gathering and processing facilities. Additionally, the DEFS disposition transaction included the acquisition of ConocoPhillips’ interest in the Empress System. Subsequent to the closing of the DEFS disposition transaction, effective on July 1, 2005, DEFS is no longer consolidated into Duke Energy’s consolidated financial statements and is accounted for by Duke Energy as an equity method investment. See Note 8 for the impacts of this transaction on certain cash flow hedges. The Canadian natural gas gathering and processing facilities and the Empress System are included in the Natural Gas Transmission segment.

• In December 2005, the Duke Energy Income Fund (Income Fund), a Canadian income trust fund, was created to acquire all of the common shares of Duke Energy Midstream Services Canada Corporation (Duke Midstream) from a subsidiary of Duke Energy. The Income Fund sold an approximate 40% ownership interest in Duke Midstream for approximately $110 million, which was included in Proceeds from Duke Energy Income Fund within Cash Flows from Financing activities on the Consolidated Statements of Cash Flows. In January 2006, a subsequent greenshoe sale of additional ownership interests, pursuant to an overallotment option, in the

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For the Years Ended December 31, 2005, 2004 and 2003

Income Fund were sold for approximately $10 million. Duke Energy retains an ownership interest in the Income Fund of approximately 58% and will continue to operate and manage this business. Duke Energy continues to consolidate the results of this business.

• In December 2005, Commercial Power recorded a $75 million charge related to the termination of structured power contracts in the Southeast, which was recorded in Gains (Losses) on Sales of Other Assets, net on the accompanying Consolidated Statements of Operations.

For the year ended December 31, 2005, Crescent’s commercial and multi-family real estate sales resulted in $372 million of proceeds and $191 million of net pre-tax gains recorded in Gains on Sales of Investments in Commercial and Multi-Family Real Estate on the Consolidated Statements of Operations. Sales included a large land sale in Lancaster County, South Carolina that resulted in $42 million of pre-tax gains, and several other “legacy” land sales. Additionally, Crescent had $45 million in pre-tax income related to a distribution from an interest in a portfolio of commercial office buildings which was recognized in Other Income and Expenses, net, in the accompanying Consolidated Statements of Operations (see Note 23).

For the year ended December 31, 2004, the sale of other assets and businesses (which excludes assets held for sale as of December 31, 2004 and discontinued operations, both of which are discussed in Note 13, and sales by Crescent which are discussed separately below) resulted in approximately $784 million in cash proceeds plus a $48 million note receivable from the buyers, and net pre-tax losses of $404 million recorded in Gains (Losses) on Sales of Other Assets, net and pre-tax losses of $4 million recorded in Gains (Losses) on Sales and Impairments of Equity Method Investments on the Consolidated Statements of Operations. Gains (Losses) on Sales and Impairments of Equity Method Investments included a $23 million impairment charge, which is discussed in Note 12. Significant sales of other assets in 2004 are detailed as follows:

• Natural Gas Transmission’s asset sales totaled $25 million in net proceeds. Those sales resulted in total pre-tax gains of approximately $33 million, of which $17 million was recorded in Gains (Losses) on Sales of Other Assets, net and $16 million was recorded in Gains (Losses) on Sales and Impairments of Equity Method Investments in the Consolidated Statements of Operations. Significant sales included the sale of storage gas related to the Canadian distribution operations, the sale of Natural Gas Transmission’s interest in the Millennium Pipeline, and the sale of land.

• Field Services asset sales totaled $13 million in net proceeds. Those sales resulted in gains of $2 million which were recorded in Gains (Losses) on Sales of Other Assets, net in the Consolidated Statements of Operations. These sales consisted of multiple small sales.

• Commercial Power’s asset sales totaled approximately $464 million in net proceeds and a $48 million note receivable. Those sales resulted in pre-tax losses of $360 million which were recorded in Gains (Losses) on Sales of Other Assets, net in the Consolidated Statements of Operations. Significant sales included:

• Commercial Power’s eight natural gas-fired merchant power plants in the Southeastern United States: Hot Spring (Arkansas); Murray and Sandersville (Georgia); Marshall (Kentucky); Hinds, Southaven, Enterprise and New Albany (Mississippi); and certain other power and gas contracts (collectively, the Southeast Plants). Duke Energy decided to sell the Southeast Plants in 2003, and recorded an impairment charge of $1.3 billion in 2003 since the assets’ carrying values exceeded their estimated fair values (see Note 12). The sale of those assets to KGen Partners LLC (KGen) obtained all required regulatory approvals and consents and closed on August 5, 2004. This transaction resulted in a pre-tax loss of approximately $360 million recorded in Gains (Losses) on Sales of Other Assets, net in the 2004 Consolidated Statement of Operations. Nearly all of the loss was recognized in the first quarter of 2004 to reduce the assets’ carrying values to their estimated fair values, and approximately $4 million of the loss was recognized in the third quarter of 2004 upon closing. The fair value of the plants used for recording the loss in the first quarter was based on the sales price of approximately $475 million, as announced on May 4, 2004. The actual sales price consisted of $420 million of cash and a $48 million note receivable from KGen, which bears variable interest at the London Interbank Offered Rate (LIBOR) plus 13.625% per annum, compounded quarterly. The note is secured by a fourth lien on (i) substantially all of KGen’s assets and (ii) stock of KGen LLC (KGen’s owner), each subject to certain permitted liens and a first lien on cash in certain KGen accounts. The note was repaid in full during 2005.

Duke Capital LLC (Duke Capital) retained certain guarantees related to the sold assets. In conjunction with the sale, Duke Capital arranged a letter of credit with a face amount of $120 million in favor of Georgia Power Company, to secure obligations of a

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For the Years Ended December 31, 2005, 2004 and 2003

KGen subsidiary under a seven-year power sales agreement, commencing in May 2005, under which KGen will provide power from one of the plants to Georgia Power. Duke Capital is the primary obligor to the letter of credit provider, but KGen has an obligation to reimburse Duke Capital for any payments made by it under the letter of credit, as well as expenses incurred by Duke Capital in connection with the letter of credit. Duke Energy will continue to provide services under a long-term operating agreement for one of the plants. As a result of Duke Energy’s significant continuing involvement in the operations of the plants, this transaction did not qualify for discontinued operations presentation, as prescribed by SFAS No. 144. However, this continuing involvement did not prohibit sale accounting under SFAS No. 66, “Accounting for Sales of Real Estate.”

• During 2004, a 25% undivided interest in Commercial Power’s Vermillion facility was sold for proceeds of approximately $44 million. This sale was anticipated in 2003 and, therefore, an $18 million loss on sale was recorded during 2003.

• 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 on September 8, 2004. The sale resulted in $60 million in net proceeds and an approximate $2 million pre-tax gain recorded to Gains (Losses) on Sales and Impairments of Equity Method Investments on the Consolidated Statements of Operations. A $13 million non-cash charge to Operation, Maintenance and Other expenses on the Consolidated Statements of Operations, related to a note receivable from Cantarell, was recorded in the first quarter of 2004.

• Additional asset and business sales in 2004 totaled $222 million in net proceeds. Those sales resulted in net pre-tax losses of $62 million, of which $63 million was recorded in Gains (Losses) on Sales of Other Assets, net and a $1 million gain was recorded in Gains (Losses) on Sales and Impairments of Equity Method Investments in the Consolidated Statements of Operations. These sales primarily related to some contracts at Duke Energy Trading and Marketing, LLC (DETM). DETM held a net liability position in certain contracts and, as part of the sale, DETM paid a third party net cash payments of $99 million related to the sale of these assets which are included in Cash Flows from Operating Activities. This resulted in a net loss of $65 million recorded in Gains (Losses) on Sales of Other Assets, net in the 2004 Consolidated Statement of Operations. Other significant sales included Duke Energy Royal LLC’s interest in six energy service agreements and DukeSolutions Huntington Beach, LLC, and Duke Energy Merchant LLC’s (DEM’s) 15% ownership interest in Caribbean Nitrogen Company. DEM also sold its refined products operation in the Eastern United States.

For the year ended December 31, 2004, Crescent’s commercial and multi-family real estate sales resulted in $606 million of proceeds, and $192 million of net gains recorded in Gains on Sales of Investments in Commercial and Multi-Family Real Estate on the Consolidated Statements of Operations. Significant sales included commercial project sales, resulting primarily from the sale of a commercial project in the Washington, D.C. area in March; real estate sales due primarily to the sale of the Alexandria and Arlington land tracts in the Washington, D.C. area; and several large land tract sales.

The sale of other assets and businesses for approximately $1,120 million in proceeds plus the assumption of $70 million of debt by the buyers for 2003 resulted in net losses of $199 million recorded in Gains (Losses) on Sales of Other Assets, net on the Consolidated Statements of Operations, and gains of $279 million recorded in Gains (Losses) on Sales and Impairments of Equity Method Investments in the Consolidated Statements of Operations. Significant sales of other assets and businesses in 2003 (other than discontinued operations as presented in Note 13) are detailed by business segment as follows:

• Natural Gas Transmission’s sales of assets and businesses totaled $610 million in proceeds, and the assumption of $70 million of debt by the buyers. Those sales resulted in gains of $90 million which were recorded in Gains (Losses) on Sales and Impairments of Equity Method Investments in the Consolidated Statements of Operations, and gains of $7 million which were recorded in Gains (Losses) on Sales of Other Assets, net in the Consolidated Statements of Operations. Significant sales included the sale of its remaining limited partnership interests in Northern Border Partners L.P.; the sale of its investments in the Alliance Pipeline and the associated Aux Sable NGL plant, Foothills Pipe Lines Ltd., and Vector Pipeline LP (Vector); the sale of Pacific Northern Gas Ltd., and the sale of two office buildings.

• Field Services sales of assets totaled $141 million in proceeds. Those sales resulted in gains of $11 million which were recorded in Gains (Losses) on Sales and Impairments of Equity Method Investments in the Consolidated Statements of Operations. Significant sales included Field Services’ Class B units of TEPPCO Partners, L.P.

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

• DENA’s asset sales, which is recorded in Other, totaled $372 million in proceeds. The sale of DENA’s 50% ownership interest in Duke/UAE Ref-Fuel LLC (Ref-Fuel) resulted in a gain of $178 million, which was recorded in Gains (Losses) on Sales and Impairments of Equity Method Investments in the Consolidated Statements of Operations.

• Impairment charges and net losses on sales in Other, primarily related to the sale of DETM contracts, resulted in a net loss of $124 million, which was recorded in Gains (Losses) on Sales of Other Assets, net in the Consolidated Statements of Operations. Impairment charges and losses on the DETM contracts resulted from Duke Energy’s decision to wind-down DETM’s operations. As a result, Duke Energy and Exxon Mobil, its partner, are executing a reduction of DETM business in scope and scale and soliciting interest from selected parties for a significant portion of DETM’s contract portfolio. The ultimate financial impact to Duke Energy of the reduction in the scope and sale of DETM and related liquidation of its contract portfolio cannot be reasonably estimated. However, it is possible that Other will incur additional losses as a result of liquidating the DETM contracts.

• Some turbines and surplus equipment in Other. This sale was anticipated in 2003 and therefore a loss of $66 million was recorded in Gains (Losses) on Sales of Other Assets, net in the 2003 Consolidated Statement of Operations.

• A 25% undivided interest in Commercial Power’s Vermillion facility. This sale was anticipated in 2003 and therefore losses of $18 million were recorded in Gains (Losses) on Sales of Other Assets, net in the 2003 Consolidated Statement of Operations. The sale occurred in 2004 and resulted in proceeds of approximately $44 million. Duke Energy still owns the remaining 75% interest in the Vermillion facility.

3. Business Segments

In conjunction with Duke Energy’s merger with Cinergy, effective with the second quarter ended June 30, 2006, Duke Energy adopted new business segments that management believes properly align the various operations of Duke Energy with how the chief operating decision maker views the business. Duke Energy operates the following business units: U.S. Franchised Electric and Gas, Natural Gas Transmission, Field Services, Commercial Power, International Energy and 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. All of the Duke Energy business units are considered reportable segments under SFAS No. 131. Prior to the September, 2005 announcement of the exiting of the majority of DENA’s businesses (see below), DENA’s operations were considered a separate reportable segment. The term DENA, as used throughout the Notes to Consolidated Financial Statements, refers to the former merchant generation operations in the Western and Eastern U.S., as well as operations in the Midwest and Southeast. Under Duke Energy’s new segment structure, the merchant generation operations of the Midwest and Southeast are presented as a component of the Commercial Power segment for all periods presented and the Western and Eastern operations are presented as a component of discontinued operations within Other for all periods presented. Prior to the change in business segments, former DENA’s continuing operations were included in Other in 2005 and as a component of the DENA segment in all prior periods, and discontinued operations were included in the DENA segment for all periods. There is no aggregation within Duke Energy’s defined business segments.

While decisions made in 2006 as part of the merged business is the rationale for this segment change, the information contained herein is as of December 31, 2005 and, accordingly, segment disclosures do not include any balances or results of operations of business acquired as part of the merger with Cinergy. The change in segments, as discussed above, has been reflected herein and in Notes 1, 2, 3, 4, 11, 12 and 13 to the Consolidated Financial Statements.

U.S. Franchised Electric and Gas generates, transmits, distributes and sells electricity in Central and Western North Carolina and Western South Carolina. It conducts operations primarily through Duke Energy Carolinas. These electric operations are subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC), the North Carolina Utilities Commission (NCUC), the PSCSC and the Nuclear Regulatory Commission (NRC).

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, natural gas processing services to customers in Western Canada and other energy related services. 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 regu -

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For the Years Ended December 31, 2005, 2004 and 2003

lations of the National Energy Board (NEB) and the Ontario Energy Board (OEB). Prior period segment results for Natural Gas Transmission have been retrospectively adjusted to include the results of operations of the McMahon facility and the Canadian gathering and processing facilities transferred to Natural Gas Transmission from DENA and Field Services, respectively, during 2005.

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 owned 50 percent by ConocoPhillips and 50 percent by Duke Energy. Field Services gathers raw natural gas through gathering systems located in seven major natural gas producing regions: Permian Basin, Mid-Continent, ArklaTex, Gulf Coast, South, Central and the Rocky Mountains.

In February 2005, DEFS sold its wholly owned subsidiary TEPPCO GP, which is the general partner of TEPPCO LP, and Duke Energy sold its limited partner interest in TEPPCO LP, in each case to Enterprise GP Holdings LP, an unrelated third party. As a result of the DEFS disposition transaction discussed in Note 2, Duke Energy deconsolidated its investment in DEFS effective July 1, 2005 and subsequently has accounted for it as an investment utilizing the equity method of accounting. In connection with the DEFS disposition transaction, DEFS transferred its Canadian natural gas gathering and processing facilities to Duke Energy’s Natural Gas Transmission segment. Prior period segment results for Field Services have been retrospectively adjusted to exclude the results of operations of these Canadian gathering and processing facilities, while prior period segment results for Natural Gas Transmission have been retrospectively adjusted to include the results of operations of these Canadian gathering and processing facilities.

Commercial Power consists of a portion of Duke Energy’s operations formerly known as Duke Energy North America (DENA). Commercial Power’s operations consist primarily of five Midwestern generating plants, representing a mix of combined cycle and peaking plants consisting of approximately 3,600 megawatts of power generation, and certain contracts related to the Midwestern generating facilities, and eight natural gas-fired merchant power plants in the Southeastern United States and certain other power and gas contracts, which were formerly a portion of DENA and were substantially disposed of in 2004.

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 the following:

• The remaining portion of Duke Energy’s business formerly known as DENA, including 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. During the third quarter of 2005, Duke Energy’s Board of Directors authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. The exit plan was completed in the second quarter of 2006 (see Note 24). In addition, management will continue to wind down the limited remaining operations of DETM. As a result of this exit plan, the results of operations for most of DENA’s businesses which Duke Energy will be exiting have been reflected as discontinued operations in the accompanying Consolidated Statements of Operations for all years presented. Continuing operations related to former DENA within Other consist primarily of DETM, which management continues to wind down.

• Other also includes certain unallocated corporate costs, certain discontinued hedges, DukeNet, DEM, Bison, Duke Energy’s wholly owned, captive insurance subsidiary and Duke Energy’s 50% interest in 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, 2005, DEM had exited the majority of its business. Duke Energy’s wholly owned captive insurance subsidiary’s principal activities 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. This subsidiary also participates in reinsurance activities with cer -

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For the Years Ended December 31, 2005, 2004 and 2003

tain third parties, on a limited basis. D/FD is a 50/50 partnership between subsidiaries of Duke Energy and Fluor Corporation (Fluor). During 2003, Duke Energy and Fluor announced that they would dissolve D/FD and adopted a plan for an orderly wind-down of the D/FD business. The wind-down has been substantially completed as of December 31, 2005 and is expected to be finalized by December 2006. 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, 2005, 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.

• During the first quarter of 2005, Duke Energy recognized a charge to increase liabilities associated with mutual insurance companies of $28 million in Other, which was an immaterial correction of an accounting error related to prior periods.

• During the first quarter of 2005, Duke Energy discontinued hedge accounting for certain contracts related to Field Services’ commodity price risk and changes in the fair value of these contracts subsequent to hedge discontinuance have been classified in Other. See Note 8 for further discussion.

Duke Energy’s reportable segments offer different products and services and are managed separately as business units. Accounting policies for Duke Energy’s segments are the same as those described in Note 1. Management evaluates segment performance 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 excludes discontinued operations, represents all profits from continuing operations (both operating and non-operating) before deducting interest and taxes, and is net of the minority interest expense related to those profits. Cash, cash equivalents and short-term investments are managed centrally by Duke Energy, so the associated realized and unrealized gains and losses from foreign currency transactions and interest and dividend income on those balances are excluded from the segments’ EBIT.

Transactions between reportable segments are accounted for on the same basis as revenues and expenses in the accompanying Consolidated Financial Statements.

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For the Years Ended December 31, 2005, 2004 and 2003

Business Segment Data^(a)

	Unaffiliated Revenues			Intersegment Revenues			Total Revenues			Segment EBIT/ Consolidated Earnings (Loss) from Continuing Operations before Income Taxes			Depreciation and Amortization		Capital and Investment Expenditures			Segment Assets(b)
	(in millions)
Year Ended December 31, 2005
U.S. Franchised Electric and Gas	$	5,413		$	19		$	5,432		$	1,495		$	962	$	1,332		$	18,739
Natural Gas Transmission		3,955			100			4,055			1,388			458		930			18,823
Field Services(f)		5,470			60			5,530			1,946			143		86			1,377
Commercial Power(e)		102			46			148			(118	)		60		2			1,619
International Energy		745			—			745			314			64		23			2,962
Crescent(c)		495			—			495			314			1		599			1,507
Total reportable segments		16,180			225			16,405			5,339			1,688		2,972			45,027
Other(e)		566			(9	)		557			(527	)		40		29			9,402
Eliminations and reclassifications		—			(216	)		(216	)		—			—		—			294
Interest expense		—			—			—			(1,062	)		—		—			—
Interest income and other(d)		—			—			—			66			—		—			—
Total consolidated	$	16,746		$	—		$	16,746		$	3,816		$	1,728	$	3,001		$	54,723
Year Ended December 31, 2004
U.S. Franchised Electric and Gas	$	5,045		$	24		$	5,069		$	1,467		$	863	$	1,126		$	18,199
Natural Gas Transmission		3,239			112			3,351			1,329			431		544			17,798
Field Services(f)		10,172			(128	)		10,044			367			285		202			6,436
Commercial Power(e)		(25	)		204			179			(479	)		69		7			1,434
International Energy		619			—			619			222			58		28			3,329
Crescent(c)		437			—			437			240			2		568			1,315
Total reportable segments		19,487			212			19,699			3,146			1,708		2,475			48,511
Other(e)		1,062			72			1,134			(183	)		42		54			7,457
Eliminations and reclassifications		—			(284	)		(284	)		—			—		—			(198	)
Interest expense		—			—			—			(1,281	)		—		—			—
Interest income and other(d)		—			—			—			103			—		—			—
Total consolidated	$	20,549		$	—		$	20,549		$	1,785		$	1,750	$	2,529		$	55,770
Year Ended December 31, 2003
U.S. Franchised Electric and Gas	$	4,854		$	21		$	4,875		$	1,403		$	748	$	1,015		$	17,240
Natural Gas Transmission		3,025			228			3,253			1,333			404		773			16,987
Field Services(f)		7,921			617			8,538			176			281		204			6,095
Commercial Power(e)		(54	)		221			167			(1,288	)		127		334			2,990
International Energy		597			—			597			215			57		71			4,550
Crescent(c)		284			—			284			134			6		290			1,653
Total reportable segments		16,627			1,087			17,714			1,973			1,623		2,687			49,515
Other(e)		1,394			233			1,627			(660	)		52		(78	)		9,200
Eliminations and reclassifications		—			(1,320	)		(1,320	)		—			—		—			(1,230	)
Interest expense		—			—			—			(1,330	)		—		—			—
Interest income and other(d)		—			—			—			(6	)		—		—			—
Total consolidated	$	18,021		$	—		$	18,021		$	(23	)	$	1,675	$	2,609		$	57,485

(a) Segment results exclude results of entities classified as discontinued operations

(b) Includes assets held for sale

(c) Capital expenditures for residential real estate are included in operating cash flows and were $355 million in 2005, $322 million in 2004 and $196 million in 2003.

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For the Years Ended December 31, 2005, 2004 and 2003

(d) Other includes foreign currency transaction gains and losses, and additional minority interest expense not allocated to the segment results.

(e) Amounts associated with former DENA’s operations are included in Other for all periods presented, except for the Midwestern generation and Southeast operations, which are reflected in Commercial Power.

(f) In July 2005, Duke Energy completed the previously announced agreement with ConocoPhillips to reduce Duke Energy’s ownership interest in DEFS from 69.7% to 50%. Field Services segment data includes DEFS as a consolidated entity for periods prior to July 1, 2005 and an equity method investment for periods after June 30, 2005.

Geographic Data

	U.S.		Canada		Latin America		Other Foreign		Consolidated
	(in millions)
2005
Consolidated revenues	$	12,649	$	3,313	$	741	$	43	$	16,746
Consolidated long-lived assets		33,141		10,790		2,432		403		46,766
2004
Consolidated revenues	$	16,584	$	3,297	$	612	$	56	$	20,549
Consolidated long-lived assets		34,918		10,163		2,399		372		47,852
2003
Consolidated revenues	$	12,403	$	4,935	$	556	$	127	$	18,021
Consolidated long-lived assets		36,240		9,532		2,449		1,589		49,810

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For the Years Ended December 31, 2005, 2004 and 2003

4. Regulatory Matters

Regulatory Assets and Liabilities. Duke Energy’s regulated operations are subject to SFAS No. 71. Accordingly, Duke Energy records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. (For further information see Note 1.)

Duke Energy’s Regulatory Assets and Liabilities:

	As of December 31,				Recovery/ Refund Period Ends
	2005		2004
	(in millions)
Regulatory Assets(a)
Net regulatory asset related to income taxes(b)	$	1,338	$	1,269	(l	)
Asset retirement obligation (ARO) costs(c)		546		519	2043
Deferred debt expense(d)		166		181	2039
Vacation accrual(c)		80		73	2006
Regional Transmission Organization (RTO)(r)		41		—	(p	)
Project costs(c)(d)(e)		40		16	2024
Gas purchase costs(c)		34		—	2006
Demand-side management costs—NC(c)(e)		29		38	(m	)
U.S. Department of Energy (DOE) assessment fee(c)		12		23	2007
Environmental cleanup costs(c)		7		8	2017
Hedge costs and other deferrals(c)		—		10	2005
Under-recovery of fuel costs(f)(i)		—		9	2006
Other(c)		26		—	(q	)
Total Regulatory Assets	$	2,319	$	2,146
Regulatory Liabilities(a)
Removal costs(d)(h)(o)(s)	$	1,670	$	1,575	(n	)
Nuclear property and liability reserves(d)(h)		167		162	2043
North Carolina clean air compliance(d)(h)		164		199	2011
Purchased capacity costs (For further information see Note 5)(e)(j)		121		135	(k	)
Over-recovery of fuel costs(f)(g)		76		—	2007
Demand-side management costs—SC(e)(h)		59		43	(m	)
Pipeline rate credit(h)		37		38	2041
Storage and transportation liability(g)		9		16	2006
Earnings sharing liability(g)		9		11	2006
Other deferred tax credits(d)(f)(h)		8		164	(f	)
Gas purchase costs(g)		—		32	2005
Other(h)		18		—	(q	)
Total Regulatory Liabilities	$	2,338	$	2,375

(a) All regulatory assets and liabilities are excluded from rate base unless otherwise noted.

(b) Natural Gas Transmission’s amounts of $954 million at December 31, 2005 and $893 million at December 31, 2004 are expected to be included in future rate filings. U.S. Franchised Electric and Gas’ amounts of $384 million at December 31, 2005 and $376 million at December 31, 2004 are included in rate base.

(c) Included in Other Regulatory Assets and Deferred Debits on the Consolidated Balance Sheets.

(d) Included in rate base.

(e) Earns a return.

(f) Duke Energy Carolinas has reduced the previously recorded excess deferred tax liability by approximately $150 million. Duke Energy Carolinas received approval from the NCUC to credit approximately $100 million against fuel rates for North Carolina retail customers. Similarly, the PSCSC granted approval to credit approximately $40 million against fuel rates for South Carolina retail customers. The remaining reduction was achieved by crediting fuel rates for certain wholesale customers and writing off a portion of the balance against income.

(g) Included in Accounts Payable on the Consolidated Balance Sheets.

(h) Included in Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets.

(i) Included in Receivables on the Consolidated Balance Sheets.

(j) Included in Other Current Liabilities and Other Deferred Credits and Other Liabilities.

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For the Years Ended December 31, 2005, 2004 and 2003

(k) Incurred costs were deferred and are being recovered in rates. U.S. Franchised Electric and Gas is currently over-recovered for these costs and is refunding the liability through retail rates. Refund period will be determined by the volume of sales.

(l) Recovery/refund is over the life of the associated asset or liability.

(m) Incurred costs were deferred and are being recovered in rates. U.S. Franchised Electric and Gas’s currently over-recovered for these costs in the South Carolina jurisdiction. Refund period is dependent on volume of sales and cost incurrence.

(n) Liability is extinguished over the lives of the associated assets.

(o) 2004 amounts reflect reclassification of approximately $300 million related to removal costs for property within the natural gas operations (see Note 1) and approximately $290 million of contributions to the NDTF for non-legally obligated decommissioning costs related to plant components not subject to radioactive contamination.

(p) To be recovered through future transmission rates. Recovery period currently unknown.

(q) Recovery/Refund period currently unknown.

(r) Investment in RTO reclassified as regulatory asset from Other Deferred Credits during 2005 after termination of GridSouth Transco project.

(s) 2005 amounts include approximately $42 million of asbestos related asset retirement obligations recorded as regulatory liabilities.

Merger with Cinergy. As discussed in Note 2, on May 9, 2005, Duke Energy and Cinergy announced they entered into a definitive merger agreement. Approval of the merger by several federal and state agencies is required. Approval of the merger has been obtained by the following parties:

• The Public Utilities Commission of Ohio (PUCO) approved the planned merger with certain conditions which included a rate credit of approximately $15 million for one year to mitigate increases from Cincinnati Gas & Electric Company’s (CG&E) pending electric distribution rate application and its rate stabilization plan and a credit of approximately $21 million to CG&E gas and electric customers in Ohio in the first year following the closing of the merger.

• In July 2005, Duke Energy and Cinergy filed an application for approval of the merger with the FERC. The FERC approved the merger without conditions in an order issued on December 20, 2005.

• The PSCSC approved the planned merger with certain conditions which included a $40 million rate reduction for one year and a three-year extension to the Bulk Power Marketing profit sharing arrangement.

• The Kentucky Public Service Commission (KPSC) approved the planned merger with conditions which included a $7.6 million rate credit over 5 years.

• The Nuclear Regulatory Commission (NRC) approved Duke Energy’s License Amendment Request; and,

• The Federal Trade Commission and U.S. Department of Justice granted early termination of the waiting period imposed by the Hart-Scott-Rodino Act.

All of the approved state settlements include a most favored nations clause related to merger savings sharing in other jurisdictions.

Approval of the merger is still pending with the Indiana Utility Regulatory Commission (IURC) and the NCUC. The status of these matters is as follows:

• During the second quarter of 2005, Cinergy filed a petition for approval of the merger with the IURC. On December 15, 2005, PSI Energy filed a settlement agreement reached with the PSI Industrial Group, the IURC staff and the Indiana Office of Utility Consumer Counselor. The settlement includes a $40 million merger savings rate credit paid out over 1 year and a $5 million contribution for low income energy assistance and clean coal technology paid out in $1 million increments over 5 years starting in 2006. The IURC hearing concluded January 26, 2006; and,

• In July 2005, Duke Energy filed an application for the approval of the merger with the NCUC. On November 30, 2005, Duke Energy reached a settlement agreement with the North Carolina Public Staff on conditions to be imposed in connection with NCUC’s approval of the application. Such conditions are subject to approval of the NCUC, and include the sharing of merger savings with North Carolina retail customers in the amount of approximately $118 million. The NCUC concluded its evidentiary hearing on December 15, 2005. The NCUC held an oral argument on January 18, 2006.

Closing of the merger is anticipated for the second quarter of 2006. Special meetings of the Duke Energy and Cinergy shareholders to vote on the merger are scheduled for March 10, 2006.

Spent Nuclear Fuel. Under provisions of the Nuclear Waste Policy Act of 1982, Duke Energy contracted with the 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.

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For the Years Ended December 31, 2005, 2004 and 2003

Payments made to the DOE for expected future 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.

U.S. Franchised Electric and Gas. Rate Related Information. The NCUC and the PSCSC approve rates for retail electric sales within their states. The FERC approves U.S. Franchised Electric and Gas’ rates for electric sales to regulated wholesale customers.

As of December 31, 2005 and December 31, 2004, U.S. Franchised Electric and Gas had recorded approximately $1.3 billion and $1.2 billion, respectively, of regulatory assets and $1.9 billion and $2.0 billion of regulatory liabilities, respectively. Management estimates that current rates are sufficient to recover the recorded regulatory assets, in addition to providing a reasonable return for shareholders. Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes, recent rate orders to other regulated entities, and the status of any pending or potential deregulation legislation. This assessment reflects the current political and regulatory climate in the states in which U.S. Franchised Electric and Gas operates, and is subject to change in the future. If future recovery of costs ceases to be probable, the asset write-offs would be required to be recognized in operating income. The majority of these regulatory assets, including deferred debt expense and the regulatory asset related to income taxes, are amortized and recovered over the lives of the related assets/debt instruments.

Fuel costs are reviewed semiannually by the FERC. The NCUC and PSCSC review fuel costs in rates annually and during general rate case proceedings. All jurisdictions allow U.S. Franchised Electric and Gas to adjust electric rates for past over- or under-recovery of fuel costs. The difference between actual fuel costs incurred for electric operations and fuel costs recovered through rates is reflected in revenues.

In 2002, the state of North Carolina passed clean air legislation that freezes electric utility rates from June 20, 2002 to December 31, 2007 (rate freeze period), subject to certain conditions, in order for North Carolina electric utilities, including Duke Energy, to significantly reduce emissions of sulfur dioxide (SO₂) and nitrogen oxides (NOx) from coal-fired power plants in the state. The legislation allows electric utilities, including Duke Energy, to accelerate the recovery of compliance costs by amortizing them over seven years (2003-2009). The legislation provides for significant flexibility in the amount of annual amortization recorded, allowing utilities to vary the amount amortized, within limits, although the legislation does require that a minimum of 70% of the originally estimated total cost of $1.5 billion be amortized within the rate freeze period (2002 to 2007). U.S. Franchised Electric and Gas’ amortization expense related to this clean air legislation totals $637 million from inception, with approximately $311 million, $211 million and $115 million recorded during the years ended December 31, 2005, 2004 and 2003, respectively. As of December 31, 2005, cumulative expenditures totaled $425 million, with $301 million, $106 million and $18 million incurred during the years ended December 31, 2005, 2004 and 2003, respectively, and are included in Net Cash Used in Investing Activities on the Consolidated Statements of Cash Flows. Duke Energy has changed the classification of these expenditures for clean air legislation from cash flows used in operating activities to cash flows used in investing activities, as discussed in Note 1. Based upon current estimates on file with the NCUC, U.S. Franchised Electric and Gas estimates total cost of complying with the clean air legislation to be approximately $1.7 billion, which is an increase of $200 million from the previous estimate of approximately $1.5 billion.

Bulk Power Marketing Profit Sharing. In June 2004, the NCUC approved Duke Energy’s proposal to share 50% of the North Carolina retail allocation of the profits from certain wholesale sales of bulk power from Duke Energy Carolinas generating units at market based rates (BPM Profits). Duke Energy also informed the NCUC that it would no longer include BPM profits in calculating its North Carolina retail jurisdictional rate of return for its quarterly reports to the NCUC. As approved by the NCUC, the sharing arrangement provides for 50% of the North Carolina allocation of BPM Profits to be distributed through various public assistance programs, up to a maximum of $5 million per year. Any amounts exceeding the maximum will be used to reduce rates for industrial customers in North Carolina.

In June 2004, Duke Energy informed the PSCSC that it would no longer include BPM Profits in calculating its South Carolina retail jurisdictional rate of return for its quarterly reports to the PSCSC. Duke Energy has since established an unconsolidated entity, Advance SC LLC, a South Carolina limited liability company, to receive 50% of the South Carolina retail allocation of the BPM Profits to be distributed through various public assistance programs, and to support certain education programs that promote economic development, and programs to promote the attraction and retention of industrial customers in Duke Energy Carolinas’ South Carolina service area. Advance SC LLC is managed by a board of directors that will act independently of Duke Energy. The board consists of representatives from Duke Energy Carolinas’ service area, including representatives from industrial customers, educational institutions, governmental and economic development agencies, and Duke Energy.

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For the Years Ended December 31, 2005, 2004 and 2003

The sharing agreement in both states applies to BPM Profits from January 1, 2004 until the earlier of December 31, 2007, or the effective date of any rates approved by the respective commission after a general rate case. Profits that have been or that will be shared have been recorded as an offset to revenue or an expense in the Consolidated Statements of Operations. On November 1, 2005, the PSCSC approved the anticipated merger with Cinergy, which included adoption of a stipulation upon which Duke Energy agreed to a three-year extension to the Bulk Power Marketing profit sharing arrangement. However, the PSCSC has not directly addressed the change in reporting BPM Profits.

Depreciation and Decommissioning Studies. The operating licenses for Duke Energy’s nuclear units are subject to renewal. In December 2003, Duke Energy was granted renewed operating licenses for the Catawba and McGuire Nuclear Stations until 2041 and 2043 (license expirations vary by nuclear unit). In 2000, Duke Energy was granted renewed operating licenses for the Oconee Nuclear Station until 2033 and 2034 (license expirations vary by nuclear unit).

In March 2005, Duke Energy Carolinas filed the results of a depreciation rate study with the NCUC and PSCSC. Duke Energy Carolinas adopted new depreciation rates for all functions effective January 1, 2005. The new depreciation rates adopted in 2005 resulted in an immaterial change in depreciation expense in 2005.

In June 2004 Duke Energy Carolinas filed with the NCUC and PSCSC the results of a 2003 nuclear decommissioning study, which indicates an estimated cost of $2.3 billion (in 2003 dollars) to decommission the nuclear facilities. 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).

In October 2004, Duke Energy Carolinas filed the results of a funding study for nuclear decommissioning costs with the NCUC and in December 2004, Duke Energy Carolinas notified the PSCSC of the results of the funding study. A NCUC decision on the appropriate level of decommissioning funding was received in July 2005 at the requested $48 million annual amount. The PSCSC issued a requested accounting order in August 2005 for Duke Energy Carolinas to implement the new decommissioning funding levels. (For further information see Note 7.)

Regional Transmission Organizations (RTOs). As a result of previous FERC rulemakings related to RTO’s, Duke Energy Carolinas 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, 2005, Duke Energy had a net investment of $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. In 2005, the companies notified the FERC that they had discontinued the GridSouth project. Management expects it will recover its investment in GridSouth.

Over-Accrued Deferred Taxes. On March 9, 2005, Duke Energy Carolinas filed with the NCUC a proposed fuel rate increase, for rates effective July 1, 2005 for a 12-month period. To reduce the impact of the increased cost of fuel, Duke Energy Carolinas requested approval in the fuel case proceeding to flow to customers approximately a $100 million revenue reduction for previously recorded excess deferred tax liabilities in the form of a rate decrement. On June 15, 2005, the NCUC approved Duke Energy Carolinas’ proposed fuel rate and deferred tax decrement. Duke Energy Carolinas proposed a similar action to the PSCSC in its fuel rate adjustment filing in July 2005 for the South Carolina portion of approximately a $40 million revenue reduction which was approved by the PSCSC on September 15, 2005. These deferred tax revenue reductions are recorded as regulatory liabilities until paid to the customers.

Market-Based Rate Authority. FERC instituted a rulemaking process to modify its methodology to assess generation market power. In the interim, FERC has established certain market screens. Failure to satisfy any of those screens requires an applicant for market-based rates to submit additional tests and information to FERC to demonstrate that it does not have generation market power in the region in which it fails the screens. Some of the screens which do not subtract obligations to serve native load are difficult for a franchised utility such as Duke Energy Carolinas to pass. In an order issued on June 30, 2005, the FERC revoked the authority for Duke Energy Carolinas to make wholesale power sales within its control area at market-based rates based on the FERC’s determination that Duke Energy Carolinas had failed one of the applicable market screens. Under the FERC’s order, Duke Energy Carolinas may make wholesale power sales within its control area only at cost-based rates. Duke Energy Carolinas has filed a cost-based tariff for such sales. The

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For the Years Ended December 31, 2005, 2004 and 2003

FERC did not initially approve all aspects of Duke Energy Carolinas’s filing. As a result of a FERC-mandated settlement procedure, Duke Energy Carolinas has filed an Offer of Settlement to resolve the issues in this docket. The FERC’s orders are not expected to have a material adverse effect on Duke Energy’s future consolidated results of operations, cash flows or financial position. Pursuant to a previous order, Duke Energy Carolinas may continue to make wholesale sales at market-based rates to customers outside of its control area.

Duke Energy Carolinas “Independent Entity” to Perform Transmission Functions. On December 19, 2005 the FERC approved a plan filed by Duke Energy Carolinas to establish an “Independent Entity” (IE) to serve as a coordinator of certain transmission functions and an “Independent Monitor” (IM) to monitor the transparency and fairness of the operation of Duke Energy Carolinas’ transmission system. Under the proposal, Duke Energy Carolinas will remain the owner and operator of the transmission system with responsibility for the provision of transmission service under Duke Energy Carolinas’ Open Access Transmission Tariff. Duke Energy Carolinas has retained the Midwest Independent Transmission System Operator, Inc. to act as the IE and Potomac Economics, Ltd. to act as the IM. Duke Energy Carolinas intends to implement the plan by November 1, 2006. Duke Energy Carolinas is not at this time seeking adjustments to its transmission rates to reflect the incremental cost of the proposal, which is not projected to have a material adverse effect on Duke Energy’s future consolidated results of operations, cash flows or financial position.

Natural Gas Transmission. Rate Related Information. The British Columbia Pipeline System’s (BC Pipeline) pipeline and field services businesses in Western Canada recorded regulatory assets related to deferred income tax liabilities of approximately $640 million as of December 31, 2005 and $612 million as of December 31, 2004. Under the current NEB-authorized rate structure, income tax costs are recovered in tolls based on the current income tax payable and do not include accruals for deferred income tax. However, as income taxes become payable as a result of the reversal of timing differences that created the deferred income taxes, it is expected that the transportation and field services tolls will be adjusted to recover these taxes. Since most of these timing differences are related to property, plant and equipment costs, this recovery is expected to occur over a 20 to 30 year period.

When evaluating the recoverability of the BC Pipeline and field services’ regulatory assets, management takes into consideration the NEB regulatory environment, natural gas reserve estimates for reserves located, or expected to be located, near these assets, the ability to remain competitive in the markets served, and projected demand growth estimates for the areas served by BC Pipeline and field services business. Based on current evaluation of these factors, management believes that recovery of these tax costs is probable over the periods described above.

In November 2005, BC Pipeline filed an application with the NEB for interim and final tolls for 2006. In December 2005, the NEB approved the 2006 interim tolls as filed. BC Pipeline has started negotiations with its shippers to reach a settlement on final tolls for years 2006, 2007 and 2008. Union Gas has rates that are approved by the OEB. Rates for the sale of gas are adjusted quarterly to reflect updated commodity price forecasts. The difference between the approved and the actual cost of gas incurred in the current period is deferred for future recovery from or return to customers, subject to approval by the OEB. These differences are directly flowed through to customers and, therefore, no rate of return is earned on the related deferred balances. The OEB’s review and approval of these gas purchase costs primarily considers the prudence of the costs incurred.

The OEB also implemented an asymmetrical earnings sharing mechanism for Union Gas, effective January 1, 2005. Earnings in 2005, above the 9.63% benchmark return on equity (ROE), normalized for weather, were shared equally between ratepayers and Union Gas. No rate relief will be provided if Union Gas earns below the allowed ROE, normalized for weather. This earnings sharing mechanism reduced Union Gas’ earnings by approximately $9 million during the year ended December 31, 2005.

In December 2005, the OEB approved the 2006 rates for Union Gas implementing items previously approved by the OEB, incorporating an earnings sharing mechanism for 2006 with the characteristics similar to those ordered by the OEB for 2005.

On March 30, 2005, the OEB issued a report containing plans for refining natural gas sector regulation. The OEB has endorsed the concept of a multi-year incentive regulation plan. It has scheduled a series of proceedings over the next three years to establish key parameters underpinning this framework. Union Gas will participate in these proceedings.

Effective January 1, 2005, new rates for Maritimes & Northeast Pipeline L.L.C. (M&N) took effect, subject to refund, as a result of a rate case filed by M&N in 2004. In June 2005, a settlement agreement to resolve the proceeding was reached with customers that would provide for a rate increase over rates charged prior to January 1, 2005. This settlement agreement has been filed with FERC for its review and approval.

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For the Years Ended December 31, 2005, 2004 and 2003

On November 1, 2005, East Tennessee Natural Gas, LLC placed into effect new rates approved by FERC as a result of a rate settlement with customers. The settlement agreement includes a five year rate moratorium and certain operational changes.

FERC Accounting Order. In June 2005, FERC issued an Order on Accounting for Pipeline Assessment Costs that requires most pipeline inspection and integrity assessment activities to be recognized as expenses, as incurred. In the Order, FERC confirmed that pipeline betterments and replacements, including those resulting from integrity inspections, will continue to be capitalized when appropriate. This FERC Order is effective for pipeline inspection and integrity assessment costs incurred on or subsequent to January 1, 2006 and is expected to increase annual expenses within Natural Gas Transmission by approximately $15 million to $20 million. Pipeline inspection and integrity assessment costs capitalized prior to the effective date of the rule are not impacted.

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

International Energy. Brazil Regulatory Environment. In 2004, a new energy law enacted in Brazil changed the electricity sector’s regulatory framework. The new energy law created a regulated and non-regulated market that coexist. The regulated market consists of auctions conducted by the government for the sale of power to distribution companies, who are required to fully contract their estimated electricity demand, principally through the regulated auctions. In the non-regulated market, generators, traders and non-regulated customers are permitted to enter into bi-lateral electricity purchase and sale contracts. The first regulated auction was held December 7, 2004, and the second on April 2, 2005. In those auctions, distribution companies contracted for their estimated electricity demand for the period from 2005 to 2016. The contracts offered in the auctions were eight-year contracts with delivery periods commencing in each of the years 2005 through 2008. Duke Energy’s Brazilian affiliate, Duke Energy International, Geracao Paranapanema S.A. (Paranapanema), participated in these auctions as a seller of electricity and elected to commit to eight-year contracts for delivery of 214 Megawatts (MW) beginning in 2005, 58 MW for delivery beginning in 2006, and 218 MW for delivery beginning in 2007. Paranapanema elected not to commit any capacity to the 2008 contract, and withheld some available capacity from the 2006 and 2007 contracts, due to low pricing and in order to preserve the capability to capture higher value alternatives in the future.

5. Joint Ownership of Generating Facilities

Joint Ownership of Catawba Nuclear Station—Facility operated by Duke Energy

Owner	Ownership Interest
North Carolina Municipal Power Agency Number 1	37.5	%
North Carolina Electric Membership Corporation	28.1	%
Duke Energy Corporation	12.5	%
Piedmont Municipal Power Agency	12.5	%
Saluda River Electric Cooperative, Inc.(a)	9.4	%
	100.0	%

(a) Saluda River Electric Cooperative, Inc. has notified Duke Energy of its intention to sell its ownership interest in the Catawba Nuclear Station and has given a Notice of Termination to its Interconnection Agreement, effective September 30, 2008.

As of December 31, 2005, $557 million of property, plant and equipment and $298 million of accumulated depreciation and amortization represented Duke Energy’s undivided interest in Catawba Nuclear Station Units 1 and 2. Duke Energy’s share of revenues and operating costs are included within the corresponding line on the Consolidated Statements of Operations. As of December 31, 2004, $561 million of property, plant and equipment and $295 million of accumulated depreciation and amortization represented Duke Energy’s undivided interest in Catawba Nuclear Station Units 1 and 2. Each participant must provide its own financing.

Contractual agreements to purchase declining percentages of the station’s generating capacity and energy through the year 2000 made purchased capacity costs subject to rate levelization and deferral. For the North Carolina jurisdiction, all deferred costs were fully recovered as of June 30, 2004. In the South Carolina rate jurisdiction, Duke Energy is currently overcollected on purchased capacity costs. The amount of the overcollection is a regulatory liability and is included in Other Current Liabilities and Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets. The liability related to the South Carolina jurisdiction was $121 million as of

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For the Years Ended December 31, 2005, 2004 and 2003

December 31, 2005 and $135 million as of December 31, 2004. Duke Energy is currently reducing the liability amounts annually through a rate decrement.

6. Income Taxes

The following details the components of income tax expense (benefit) from continuing operations:

Income Tax Expense (Benefit) from Continuing Operations

	For the Years Ended December 31,
	2005			2004			2003
	(in millions)
Current income taxes
Federal	$	845		$	(58	)	$	(178	)
State		138			34			(42	)
Foreign		100			84			127
Total current income taxes		1,083			60			(93	)
Deferred income taxes
Federal		173			504			30
State		(37	)		(63	)		(6	)
Foreign		74			43			(13	)
Total deferred income taxes		210			484			11
Investment tax credit amortization		(10	)		(11	)		(12	)
Total income tax expense (benefit) from continuing operations		1,283			533			(94	)
Total income tax expense (benefit) from discontinued operations		(432	)		26			(738	)
Total income tax benefit from cumulative effect of change in accounting principle		(1	)		—			(94	)
Total income tax expense (benefit) presented in Consolidated Statements of Operations	$	850		$	559		$	(926	)

Earnings (Loss) from Continuing Operations before Income Taxes

	For the Years Ended December 31,
	2005		2004		2003
	(in millions)
Domestic	$	3,225	$	1,327	$	(368	)
Foreign		591		458		345
Total earnings (loss) from continuing operations before income taxes	$	3,816	$	1,785	$	(23	)

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For the Years Ended December 31, 2005, 2004 and 2003

Reconciliation of Income Tax Expense (Benefit) at the US Federal Statutory Tax Rate to the Actual Tax Expense (Benefit) from Continuing Operations (Statutory Rate Reconciliation)

	For the Years Ended December 31,
	2005			2004			2003
	(in millions)
Income tax expense (benefit), computed at the statutory rate of 35%	$	1,336		$	625		$	(8	)
State income tax, net of federal income tax effect		66			(19	)		(31	)
Tax differential on foreign earnings		(33	)		(33	)		(7	)
Employee stock ownership plan dividends		(22	)		(19	)		(20	)
US tax on repatriation of foreign earnings		(2	)		36			—
Other items, net		(62	)		(57	)		(28	)
Total income tax expense (benefit) from continuing operations	$	1,283		$	533		$	(94	)
Effective tax rate		33.6	%		29.9	%		408.7	%

During 2005, Duke Energy reorganized various entities and reestimated its liability which enabled it to reduce the $45 million tax liability to $39 million. The reduction in 2005 is included in the Statutory Rate Reconciliation as follows: Federal income taxes of $2 million are included in “US tax on repatriation of foreign earnings” and $4 million of state taxes are included in “State income tax, net of federal income tax effect.”

During 2004, Duke Energy recorded a $52 million income tax benefit from the reduction of state and federal income tax reserves based on the resolution in the second quarter of 2004 of several tax issues. The $52 million benefit is included in the Statutory Rate Reconciliation as follows: a $39 million state benefit is included in “State income tax, net of federal income tax effect” and a $13 million federal benefit is included in “Other items, net”.

During 2004, Duke Energy recorded a $20 million income tax benefit from the change in state tax rates relating to deferred taxes as a result of a reorganization of certain subsidiaries. The $20 million benefit is included in “State income tax, net of federal income tax effect” in the Statutory Rate Reconciliation.

During 2004, Duke Energy recorded a $45 million income tax expense for the repatriation of foreign earnings which occurred during 2005 related to the American Jobs Creation Act of 2004. The $45 million is included in the Statutory Rate Reconciliation as follows: Federal income taxes of $36 million are included in “US tax on repatriation of foreign earnings,” $4 million of state taxes are included in “State income tax, net of federal income tax effect,” and $5 million of foreign taxes are included in “Tax differential on foreign earnings.”

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For the Years Ended December 31, 2005, 2004 and 2003

Net Deferred Income Tax Liability Components

	December 31,
	2005			2004
	(in millions)
Deferred credits and other liabilities	$	1,364		$	1,733
Other		60			297
Total deferred income tax assets		1,424			2,030
Valuation allowance		(26	)		(38	)
Net deferred income tax assets		1,398			1,992
Investments and other assets		(1,444	)		(990	)
Accelerated depreciation rates		(3,233	)		(4,291	)
Regulatory assets and deferred debits		(1,692	)		(1,566	)
Total deferred income tax liabilities		(6,369	)		(6,847	)
Total net deferred income tax liabilities	$	(4,971	)	$	(4,855	)

The above amounts have been classified in the Consolidated Balance Sheets as follows:

Deferred Tax Liabilities

	December 31,
	2005			2004
	(in millions)
Current deferred tax assets, included in other current assets	$	68		$	217
Non-current deferred tax assets, included in other investments and other assets		254			159
Current deferred tax liabilities, included in other current liabilities		(40	)		(3	)
Non-current deferred tax liabilities		(5,253	)		(5,228	)
Total net deferred income tax liabilities	$	(4,971	)	$	(4,855	)

As of December 31, 2005, Duke Energy has net operating loss carryforwards of approximately $75 million relating to state income taxes which mostly expire in years 2019 and later.

Although the outcome of tax audits is uncertain, management believes that adequate provisions for income and other taxes have been made for potential liabilities resulting from such matters. As of the year ended December 31, 2005, Duke Energy has total provisions, including interest, of approximately $141 million for uncertain tax positions, as compared to $149 million as of December 31, 2004. Duke Energy is also negotiating for Federal Income Tax refunds, including interest, that are not reflected in the financial statements. Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position.

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

On October 22, 2004, the President of the United States signed the Act. The Act provides a deduction for income from qualified domestic production activities, which will be phased in from 2005 to 2010.

Under the guidance in FSP No. FAS 109-1, which was issued in December 2004, the deduction will be treated as a “special deduction” as described in SFAS No. 109. As such, for Duke Energy, the special deduction had no material impact on deferred tax assets and liabilities existing at the enactment date. Rather, the impact of this special deduction will be reported in the periods in which the deductions are claimed on the tax returns. For the year ended December 31, 2005, Duke Energy recognized a benefit of approximately $9 million relating to the deduction from qualified domestic activities.

In addition to the qualified domestic production activities deduction discussed above, the Act creates a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing an 85 percent dividends received deduction for certain divi -

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For the Years Ended December 31, 2005, 2004 and 2003

dends from controlled foreign corporations. FSP No. FAS 109-2, which was issued in December 2004, states that a company is allowed time beyond the financial reporting period of enactment to evaluate the effect of the Act on its plan for reinvestment or repatriation of foreign earnings, as it applies to the application of SFAS No. 109. Although the deduction is subject to a number of limitations and some uncertainty remains as to how to interpret numerous provisions in the Act, Duke Energy recorded a $45 million tax liability at December 31, 2004 based upon Duke Energy’s plans that it would repatriate approximately $500 million in extraordinary dividends in 2005. In 2005, Duke Energy repatriated approximately $500 million in extraordinary dividends. During this process, Duke Energy reorganized various entities and reduced its liability from $45 million to $39 million. There is no remaining liability as of December 31, 2005.

Deferred income taxes and foreign withholding taxes have not been provided on the remaining undistributed earnings of Duke Energy’s foreign subsidiaries as such amounts are deemed to be permanently reinvested. The cumulative undistributed earnings as of December 31, 2005 on which Duke Energy has not provided deferred income taxes and foreign withholding taxes, is approximately $290 million.

7. Asset Retirement Obligations

In June 2001, the FASB issued SFAS No. 143 which addresses financial accounting and reporting for legal obligations associated with the retirement of tangible long-lived assets and the related asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. Asset retirement obligations at Duke Energy relate primarily to the decommissioning of nuclear power facilities, the retirement of certain gathering pipelines and processing facilities, the retirement of some gas-fired power plants, obligations related to right-of-way agreements, asbestos removal and contractual leases for land use. SFAS No. 143 was effective for fiscal years beginning after June 15, 2002, and was adopted by Duke Energy on January 1, 2003.

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

In accordance with SFAS No. 143, Duke Energy identified certain assets that have an indeterminate life, and thus the fair value of the retirement obligation is not reasonably estimable. These assets included on-shore and some off-shore pipelines, certain processing plants

and distribution facilities and some gas-fired power plants. A liability for these asset retirement obligations will be recorded when a fair value is determinable.

Upon adoption of SFAS No. 143, Duke Energy’s regulated electric and regulated natural gas operations classified removal costs for property that does not have an associated legal retirement obligation as a regulatory liability, in accordance with regulatory treatment. The total amount of removal costs included in Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets was $1,670 million and $1,575 million as of December 31, 2005 and 2004, respectively, which consisted of $1,278 million and $1,258 million, respectively, related to regulated electric operations and $350 million and $317 million, respectively, related to regulated natural gas operations. As discussed further in Note 1, Duke Energy recorded a prior period reclassification adjustment of approximately $300 million related to removal costs for property within the natural gas operations. The impact of this adjustment on the accompanying Consolidated Balance Sheets as of December 31, 2004 was a decrease in accumulated depreciation and a corresponding increase in regulatory liabilities, which are included in Other within Deferred Credits and Other Liabilities on the accompanying Consolidated Balance Sheets.

The adoption of SFAS No. 143 had no impact on the income of the regulated electric operations, as the effects were offset by the establishment of a regulatory assets and liabilities pursuant to SFAS No. 71. Duke Energy has received approval from both the NCUC and PSCSC to defer all cumulative and future income statement impacts related to SFAS No. 143. For obligations related to non-regulated operations, a net-of-tax cumulative effect of a change in accounting principle adjustment of $11 million was recorded in the first quarter of 2003 as a reduction in earnings.

In March 2005, the FASB issued FIN 47. As a result of the adoption of FIN 47 in 2005, an increase in total assets of $31 million was recorded, consisting of an increase in regulatory assets of $24 million, an increase in net property, plant and equipment of $7 million and an increase in ARO liabilities of approximately $35 million. The adoption of FIN 47 had no impact on the income of the regulated electric

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For the Years Ended December 31, 2005, 2004 and 2003

operations, as the effects were offset by the establishment of regulatory assets and liabilities pursuant to SFAS No. 71. Duke Energy has received approval from both the NCUC and PSCSC to defer all cumulative and future income statement impacts related to SFAS No. 143. For obligations related to other operations, a net-of-tax cumulative effect adjustment of approximately $4 million was recorded in the fourth quarter of 2005 as a reduction in earnings (see Note 1).

The pro forma effects of adopting FIN 47, including the impact on the balance sheet, net income and related basic and diluted earnings per share, are not presented due to the immaterial impact.

The asset retirement obligation is adjusted each period for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows.

Reconciliation of Asset Retirement Obligation Liability

	Years Ended December 31,
	2005			2004
	(in millions)
Balance as of January 1,	$	1,926		$	1,707
Liabilities incurred due to new acquisitions		—			8
Liabilities settled(a)		(46	)		(2	)
Accretion expense		131			125
Revisions in estimated cash flows		12			86
Adoption of FIN 47		35			—
Foreign currency adjustment		—			2
Balance as of December 31,	$	2,058		$	1,926

(a) Primarily represents a decrease in ARO liabilities during 2005 due to the deconsolidation of DEFS on July 1, 2005.

Accretion expense for the year ended December 31, 2005 included approximately $130 million related to Duke Energy’s regulated electric operations which has been deferred as regulatory assets and liabilities in accordance with SFAS No. 71, as discussed above. Accretion expense for the year ended December 31, 2004 included approximately $120 million related to Duke Energy’s regulated electric operations and has also been deferred as a regulatory asset in accordance with SFAS No. 71. The fair value of assets legally restricted for the purpose of settling asset retirement obligations associated with nuclear decommissioning was $1,194 million as of December 31, 2005 and $1,082 million as of December 31, 2004.

Revisions in estimated cash flows changed significantly during 2004 due primarily to the new nuclear decommissioning study performed during the year at U.S. Franchised Electric and Gas. As a result of that study, Duke Energy increased the liability recorded for the decommissioning asset retirement obligation.

Nuclear Decommissioning Costs. Pursuant to an order issued by the NCUC on February 5, 2004, Duke Energy was required to contribute amounts reserved for non-contaminated costs of decommissioning to the NDTF over a ten-year period. In April 2004, Duke Energy contributed its entire reserve of $262 million in cash to the NDTF. This contribution is presented in the Consolidated Statements of Cash Flows in Purchases of Available-For-Sale Securities within Cash Flows from Investing Activities.

In 2005, the NCUC and PSCSC approved a $48 million annual amount for contributions and expense levels for decommissioning. During 2005 and 2004, Duke Energy expensed approximately $48 million and $70 million, respectively, and contributed cash of approximately $48 million and $70 million, respectively, to the NDTF for decommissioning costs; these amounts are presented in the Consolidated Statements of Cash Flows in Purchases of Available-For-Sale Securities within Cash Flows from Investing Activities. The $48 million was contributed entirely to the funds reserved for contaminated costs. Contributions were discontinued to the funds reserved for non-contaminated costs since the current estimates indicate existing funds to be sufficient to cover projected future costs. The balance of the external funds was $1,504 million as of December 31, 2005 and $1,374 million as of December 31, 2004. These amounts are reflected in the Consolidated Balance Sheets as Nuclear Decommissioning Trust Funds (asset).

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, as discussed in Note 4. This includes costs related to Duke Energy’s 12.5% ownership in the Catawba Nuclear Station. The other joint own -

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For the Years Ended December 31, 2005, 2004 and 2003

ers of the Catawba Nuclear Station are responsible for decommissioning costs related to their ownership interests in the station. 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.

The operating licenses for Duke Energy’s nuclear units are subject to extension. In December 2003, Duke Energy was granted renewed operating licenses for the Catawba and McGuire Nuclear Stations until 2041 and 2043 (license expirations vary by nuclear unit). In 2000, Duke Energy was granted a license renewal for the Oconee Nuclear Station until 2033 and 2034 (license expirations vary by nuclear unit).

Current Operating Licenses for Duke Energy’s Nuclear Units

Unit	Expiration Year
McGuire 1	2041
McGuire 2	2043
Catawba 1	2043
Catawba 2	2043
Oconee 1 and 2	2033
Oconee 3	2034

A provision in the Energy Policy Act of 1992 established a fund for the decontamination and decommissioning of the DOE’s uranium enrichment plants (the D&D Fund). Licensees are subject to an annual assessment for 15 years based on their pro rata share of past enrichment services. The annual assessment is recorded in the Consolidated Statements of Operations as Fuel Used in Electric Generation and Purchased Power. Duke Energy has paid $140 million into the D&D Fund, including $11 million each year during 2005, 2004 and 2003. The remaining liability and regulatory assets of $12 million as of December 31, 2005 and $23 million as of December 31, 2004 are reflected in the Consolidated Balance Sheets as Deferred Credits and Other Liabilities, and Regulatory Assets and Deferred Debits.

8. Risk Management and Hedging Activities, Credit Risk, and Financial Instruments

Duke Energy is exposed to the impact of market fluctuations in the prices of natural gas, electricity and other energy-related products marketed and purchased as a result of its ownership of energy related assets, interests in structured contracts and remaining proprietary trading activities. Exposure to interest rate risk exists as a result of the issuance of variable and fixed rate debt and commer cial paper. Duke Energy is exposed to foreign currency risk from investments in international affiliate businesses owned and operated in foreign countries and from certain commodity-related transactions within domestic operations. Duke Energy employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity and financial derivative instruments, including forward contracts, futures, swaps, options and swaptions.

Duke Energy’s Derivative Portfolio Carrying Value as of December 31, 2005

Asset/(Liability)	Maturity in 2006			Maturity in 2007		Maturity in 2008		Maturity in 2009 and Thereafter		Total Carrying Value
	(in millions)
Hedging	$	(23	)	$	—	$	—	$	6	$	(17	)
Trading		—			2		1		2		5
Undesignated		(94	)		16		9		16		(53	)
Total	$	(117	)	$	18	$	10	$	24	$	(65	)

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For the Years Ended December 31, 2005, 2004 and 2003

The amounts in the table above represent the combination of amounts presented as assets and (liabilities) for unrealized gains and losses on mark-to-market and hedging transactions on Duke Energy’s Consolidated Balance Sheets, excluding approximately $3.3 billion of derivative assets and $3.5 billion of derivative liabilities which were transferred to assets and liabilities held for sale, as a result of the plan to exit DENA’s operations outside of the Midwestern United States (see Note 13).

During the third quarter of 2005, Duke Energy’s Board of Directors authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States, approximately 6,100 megawatts of power generation, and certain contractual positions related to the Midwestern assets (see Note 13). As a result, DENA recognized a pre-tax loss of approximately $1.9 billion in the third quarter of 2005 for the disqualification of its power and gas forward sales contracts previously designated under the normal purchases normal sales exception. This loss is partially offset by the recognition of a pre-tax gain of approximately $1.2 billion for the discontinuance of hedge accounting for natural gas and power cash flow hedges. As of December 31, 2005, there are approximately $20 million of pre-tax deferred net losses in AOCI related to DENA cash flow hedges, which will be recognized within the next twelve months. Duke Energy plans to retain the Midwestern generation assets of DENA, representing approximately 3,600 megawatts of power generation, and combined with Cinergy’s commercial operations, upon completion of the merger with Cinergy, currently expected in the second quarter of 2006, will provide a sustainable business model for these assets in the region (see Note 2 for further details on the anticipated Cinergy merger).

As a result of the transfer of 19.7% interest in DEFS to ConocoPhillips and the third quarter 2005 deconsolidation of its investment in DEFS (see Note 2), Duke Energy discontinued hedge accounting for certain contracts held by Duke Energy related to Field Services’ commodity price risk, which were previously accounted for as cash flow hedges. These contracts were originally entered into as hedges of forecasted future sales by Field Services, and have been retained as undesignated derivatives. Since discontinuance of hedge accounting, these contracts have been marked-to-market in the Consolidated Statements of Operations. As a result, approximately $314 million of realized and unrealized pre-tax losses related to these contracts were recognized in earnings by Duke Energy as of December 31, 2005. These charges have been classified in the accompanying Consolidated Statements of Operations for the year ended December 31, 2005 as follows: upon the discontinuance of hedge accounting approximately $120 million of pre-tax losses were recognized as a component of Impairments and Other Charges while approximately $130 million of losses recognized subsequent to the discontinuance of hedge accounting prior to the deconsolidation of DEFS were recognized as a component of Non-Regulated Electric, Natural Gas, Natural Gas Liquids, and Other Revenues and $64 million of losses recognized subsequent to discontinuance of hedge accounting after the deconsolidation of DEFS were recognized as a component of Other Income and Expenses. Cash settlements on these contracts since the deconsolidation of DEFS on July 1, 2005 of approximately $160 million are classified as a component of net cash used in investing activities in the accompanying Consolidated Statements of Cash Flows.

Commodity Cash Flow Hedges. Some Duke Energy subsidiaries are exposed to market fluctuations in the prices of various commodities related to their ongoing power generating and natural gas gathering, distribution, processing and marketing activities. Duke Energy closely monitors the potential impacts of commodity price changes and, where appropriate, enters into contracts to protect margins for a portion of future sales and generation revenues and fuel expenses. Duke Energy uses commodity instruments, such as swaps, futures, forwards and options, as cash flow hedges for natural gas, electricity and natural gas liquid transactions. Duke Energy is hedging exposures to the price variability of these commodities for a maximum of 1 year.

The ineffective portion of commodity cash flow hedges resulted in pre-tax losses of $12 million in 2005, a pre-tax gain of $3 million in 2004 and a pre-tax gain of $7 million in 2003, and are reported primarily in (Loss) Income From Discontinued Operations, net of tax in the Consolidated Statements of Operations. The amount recognized for transactions that no longer qualified as cash flow hedges was a gain of approximately $1.2 billion in 2005 and is reported in (Loss) Income From Discontinued Operations, net of tax in the Consolidated Statements of Operations, not material in 2004, and was a gain of $285 million in 2003, pre-tax. Additionally, as a result of the DENA exit plan discussed in Note 13, during 2005 approximately $200 million of pre-tax deferred gains in AOCI have been recognized in earnings, as a component of (Loss) Income From Discontinued Operations, net of tax. The 2003 disqualified cash flow hedges were primarily associated with gas hedges related to DENA’s Southeast Plants and partially completed plants.

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

As of December 31, 2005, $42 million of the pre-tax deferred net losses on derivative instruments related to commodity cash flow hedges that were accumulated on the Consolidated Balance Sheets in a separate component of stockholders’ equity, in AOCI, and are expected to be recognized in earnings during the next twelve months as the hedged transactions occur. This amount includes approximately $10 million pre-tax deferred net losses related to the DENA exit plan discussed in Note 13. However, due to the volatility of the commodities markets, the corresponding value in AOCI will likely change prior to its reclassification into earnings.

Commodity Fair Value Hedges. Some Duke Energy subsidiaries are exposed to changes in the fair value of some unrecognized firm commitments to sell generated power or natural gas due to market fluctuations in the underlying commodity prices. Duke Energy actively evaluates changes in the fair value of such unrecognized firm commitments due to commodity price changes and, where appropriate, uses various instruments to hedge its market risk. These commodity instruments, such as swaps, futures and forwards, serve as fair value hedges for the firm commitments associated with generated power. The ineffective portion of commodity fair value hedges resulted in a pre-tax loss of $4 million in 2005 and was not material in 2004 or 2003, and is reported primarily in (Loss) Income From Discontinued Operations, net of tax on the Consolidated Statements of Operations.

Normal Purchases and Normal Sales Exception. Duke Energy has applied the normal purchases and normal sales scope exception, as provided in SFAS No. 133 and interpreted by DIG Issue C15, to certain contracts involving the purchase and sale of electricity at fixed prices in future periods. These contracts, which relate primarily to the delivery of electricity over the next 9 years, are not included in the table above. As discussed above, during 2005, Duke Energy recognized a pre-tax loss of approximately $1.9 billion for the disqualification of its power and gas forward sales contracts. As discussed in the following paragraph, a portion of the charge in DENA in 2003 related to contracts that were being accounted for as normal purchases and sales.

Certain forward power contracts related to DENA’s Southeast Plants and the deferred plants had been primarily designated as normal purchases and sales in accordance with SFAS No. 133. In addition, certain forward gas contracts related to the long-lived assets had been designated as cash flow hedges in accordance with SFAS No. 133. As a result of the change in management intent for the long-lived assets, the related forward power and gas contracts were de-designated as normal purchases and sales and hedges. As a result, a net pre-tax charge of $262 million was recorded in 2003, of which a pre-tax charge of $452 million was recognized in (Loss) Income From Discontinued Operations, net of tax. (See Note 13). The amount recognized for transactions that no longer qualified as hedged firm commitments was not material in 2004.

Interest Rate (Fair Value or Cash Flow) Hedges. Changes in interest rates expose Duke Energy to risk as a result of its issuance of variable-rate debt and commercial paper. Duke Energy manages its interest rate exposure by limiting its variable-rate and fixed-rate exposures to percentages of total capitalization and by monitoring the effects of market changes in interest rates. Duke Energy also enters into financial derivative instruments, including, but not limited to, interest rate swaps, swaptions and U.S. Treasury lock agreements to manage and mitigate interest rate risk exposure. Duke Energy’s existing interest rate derivative instruments and related ineffectiveness were not material to its consolidated results of operations, cash flows or financial position in 2005, 2004, and 2003.

Foreign Currency (Fair Value, Net Investment or Cash Flow) Hedges. Duke Energy is exposed to foreign currency risk from investments in international affiliate businesses owned and operated in foreign countries and from certain commodity-related transactions within domestic operations. To mitigate risks associated with foreign currency fluctuations, contracts may be denominated in or indexed to the U.S. dollar and/or local inflation rates, or investments may be hedged through debt denominated or issued in the foreign currency. Duke Energy may also use foreign currency derivatives, where possible, to manage its risk related to foreign currency fluctuations. Net losses of $1 million, $43 million and $113 million were included in the cumulative translation adjustment for hedges of net investments in foreign operations, during 2005, 2004, and 2003, respectively. To monitor its currency exchange rate risks, Duke Energy uses sensitivity analysis, which measures the impact of devaluation of foreign currencies.

During the first quarter of 2005, Duke Energy settled certain hedges which were documented and designated as net investment hedges of the investment in Westcoast Energy, Inc. (Westcoast) on their scheduled maturity and paid approximately $162 million. These settlements are classified as a component of net cash used in investing activities in the accompanying Consolidated Statements of Cash Flows. Losses recognized on this net investment hedge have been classified in AOCI as a component of foreign currency adjustments and will not be recognized in earnings unless the complete or substantially complete liquidation of Duke Energy’s investment in Westcoast occurs.

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Other Derivative Contracts. Trading. Duke Energy is exposed to the impact of market fluctuations in the prices of natural gas, electricity and other energy-related products marketed and purchased as a result of proprietary trading activities. During 2003, Duke Energy prospectively discontinued proprietary trading and therefore the fair value of trading contracts as of December 31, 2005 relates to contracts entered into prior to the announced discontinuation of proprietary trading activities. Duke Energy’s exposure to commodity price risk is influenced by a number of factors, including contract size, length, market liquidity, location and unique or specific contract terms.

Undesignated. In addition, Duke Energy uses derivative contracts to manage the market risk exposures that arise from energy supply, structured origination, marketing, risk management, and commercial optimization services to large energy customers, energy aggregators and other wholesale companies, and to manage interest rate and foreign currency exposures. This category includes changes in fair value for derivatives that no longer qualify for the normal purchase and normal sales scope exception and disqualified hedge contracts, unless the derivative contract is subsequently re-designated as a hedge. The contracts in this category are primarily associated with forward power sales and gas purchases for the DENA exit activity announced in 2005 (see Note 13), hedges related to the DENA Southeast Plants, hedges related to the partially completed plants which were disqualified in 2003 and certain contracts held by Duke Energy related to Field Services commodity price risk.

In connection with the Barclays Bank PLC (Barclays) transaction discussed in Note 13, Duke Energy entered into a series of Total Return Swaps (TRS) with Barclays, which are accounted for as mark-to-market derivatives. The TRS offsets the net fair value of the contracts being sold to Barclays. The fair value of the TRS as of December 31, 2005 is an asset of approximately $553 million, which offsets the net fair value of the underlying contracts, which is a liability of approximately $553 million. The TRS will be cancelled as the underlying contracts are transferred to Barclays.

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

Duke Energy’s industry has historically operated under negotiated credit lines for physical delivery contracts. Duke Energy frequently uses master collateral agreements to mitigate certain credit exposures, primarily in its trading and marketing and risk management operations. The collateral agreements provide for a counterparty to post cash or letters of credit to the exposed party for exposure in excess of an established threshold. The threshold amount represents an unsecured credit limit, determined in accordance with the corporate credit policy. Collateral agreements also provide that the inability to post collateral is sufficient cause to terminate contracts and liquidate all positions.

Collateral amounts held or posted may be fixed or may vary depending on the terms of the collateral agreement and the nature of the underlying exposure and generally covers trading, normal purchases and normal sales, and hedging contracts outstanding. Duke Energy may be required to return certain held collateral and post additional collateral should price movements adversely impact the value of open contracts or positions. In many cases, Duke Energy’s and its counterparties’ publicly disclosed credit ratings impact the amounts of additional collateral to be posted. Likewise, downgrades in credit ratings of counterparties could require counterparties to post additional collateral to Duke Energy and its affiliates.

The change in market value of New York Mercantile Exchange (NYMEX)-traded futures and options contracts requires daily cash settlement in margin accounts with brokers.

Duke Energy also obtains cash or letters of credit from customers to provide credit support outside of collateral agreements, where appropriate, based on its financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each transaction.

Included in Other Current Assets in the Consolidated Balance Sheets as of December 31, 2005 and December 31, 2004 are collateral assets of approximately $1,279 million and $300 million, respectively, which represents cash collateral posted by Duke Energy with other third parties. This increase in cash collateral posted by Duke Energy is primarily due changes in commodity prices. Included in

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Other Current Liabilities in the Consolidated Balance Sheets as of December 31, 2005 and December 31, 2004 are collateral liabilities of approximately $664 million and $523 million, respectively, which represents cash collateral posted by other third parties to Duke Energy. Subsequent to December 31, 2005, in connection with the sale to Barclays of contracts related to DENA’s energy marketing and management activities, Barclays provided DENA cash equal to the net cash collateral posted by DENA under the contracts. Net cash collateral received by Duke Energy from Barclays in January 2006 was approximately $540 million based on current market prices of the contracts (see Note 13).

Financial Instruments. The fair value of financial instruments, excluding derivatives included in Notes 8 and 13, is summarized in the following table. Judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates determined as of December 31, 2005 and 2004, are not necessarily indicative of the amounts Duke Energy could have realized in current markets.

Financial Instruments

	Years Ended December 31,
	2005				2004
	Book Value		Approximate Fair Value		Book Value		Approximate Fair Value
	(in millions)
Long-term debt(a)	$	15,947	$	17,014	$	18,764	$	20,448
Preferred stock		—		—		134		133
Long-term SFAS 115 securities		1,735		1,735		1,559		1,559

(a) Includes current maturities.

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

9. Marketable Securities

Short-term investments. At December 31, 2005 and 2004 Duke Energy had $632 million and $1,319 million, respectively, of short-term investments consisting primarily of highly liquid tax-exempt debt securities. These instruments are classified as available-for-sale securities under SFAS No. 115 as management does not intend to hold them to maturity nor are they bought and sold with the objective of generating profits on short-term differences in price. The carrying value of these instruments approximates their fair value as they contain floating rates of interest. During 2005, Duke Energy purchased approximately $38,535 million and received proceeds on sale of approximately $38,386 million of short-term investments. During 2004, Duke Energy purchased approximately $63,879 million and received proceeds on sale of approximately $63,323 million of short-term investments. During 2003, Duke Energy purchased approximately $38,908 million and received proceeds on sale of approximately $38,638 million of short-term investments. The weighted-average maturity of these debt securities is less than 1 year.

Other Long-term investments. Duke Energy also invests in debt and equity securities that are held in the NDTF (see Note 4 for further information on the nuclear decommissioning trust funds) and the captive insurance investment portfolio that are classified as available-for-sale under SFAS No. 115 and therefore are carried at estimated fair value based on quoted market prices. These investments are classified as long-term as management does not intend to use them in current operations. Duke Energy’s NDTF ($1,504 million at December 31, 2005) consists of approximately of 70% equity securities, 28% debt securities, and 2% cash and cash equivalents with a weighted-average maturity of the debt securities of approximately 9 years. Duke Energy’s captive insurance investment portfolio ($203 million at December 31, 2005) consists of approximately 87% debt securities and 13% equity securities with a weighted-average maturity of the debt securities of approximately 17 years. The cost of securities sold is determined using the specific identification method. During 2005, Duke Energy purchased approximately $2,538 million and received proceeds on sales of approximately $2,501 million on other long-term investments. During 2004, Duke Energy purchased approximately $2,050 million and received proceeds on sales of approximately $1,775 million on other long-term investments. During 2003, Duke Energy purchased approximately $1,543 million and received proceeds on sales of approximately $1,366 million on other long-term investments. Most of these purchases and sales relate to the NDTF.

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

The estimated fair values of short-term and long-term investments classified as available-for-sale are as follows (in millions):

	As of December 31,
	2005						2004
	Gross Unrealized Holding Gains		Gross Unrealized Holding Losses		Estimated Fair Value		Gross Unrealized Holding Gains		Gross Unrealized Holding Losses		Estimated Fair Value
Short-term Investments	$	—	$	—	$	632	$	—	$	—	$	1,319
Total short-term investments	$	—	$	—	$	632	$	—	$	—	$	1,319
Equity Securities	$	333	$	18	$	1,098	$	261	$	17	$	960
Corporate Debt Securities		—		1		61		1		—		40
Municipal Bonds		1		2		203		3		—		193
U.S. Government Bonds		13		1		230		14		1		252
Other		—		1		143		1		—		114
Total long-term investments	$	347	$	23	$	1,735	$	280	$	18	$	1,559

For the years ended December 31, 2005, 2004, and 2003 gains of approximately $3 million, $3 million and $4 million, respectively, were reclassified out of AOCI into earnings.

Duke Energy contributed approximately $48 million in 2005, $329 million in 2004, and $56 million in 2003 to the NDTF. These contributions are presented in Purchases of available-for-sale securities within Cash Flows From Investing Activities on the Consolidated Statements of Cash Flows. Realized and unrealized gains and losses on sales of investments within the NDTF are recorded in Other within Regulatory Assets and Deferred Debits and Other within Deferred Credits and Other Liabilities on the Consolidated Balance Sheets. At December 31, 2005, gross unrealized holding gains and losses related to the NDTF amounted to $316 million and $21 million, respectively. At December 31, 2004, gross unrealized holding gains and losses related to the NDTF amounted to $274 million and $18 million, respectively.

10. Goodwill

Duke Energy evaluates the impairment of goodwill under the guidance of SFAS No. 142. As a result of the annual impairment tests required by SFAS No. 142, no charge for the impairment of goodwill was recorded in 2005 or 2004.

In 2003, Duke Energy recorded a goodwill impairment charge of $254 million to write off all DENA goodwill, most of which related to DENA’s trading and marketing business. This impairment charge reflected the reduction in scope and scale of DETM’s business and the continued deterioration of market conditions affecting DENA during 2003. Duke Energy used a discounted cash flow analysis to determine fair value. Key assumptions in the analysis included the use of an appropriate discount rate, estimated future cash flows and an estimated run rate of general and administrative costs. In estimating cash flows, Duke Energy incorporated current market information, historical factors and fundamental analysis, and other factors into its forecasted commodity prices. This charge is recorded in the Consolidated Statements of Operations as Impairment of Goodwill.

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Changes in the Carrying Amount of Goodwill

	Balance December 31, 2004		Impairments		Dispositions		Other(a)(b)			Balance December 31, 2005
	(in millions)
Natural Gas Transmission	$	3,416	$	—	$	—	$	96		$	3,512
Field Services		480		—		—		(480	)		—
International Energy		245		—		—		11			256
Crescent		7		—		—		—			7
Total consolidated	$	4,148	$	—	$	—	$	(373	)	$	3,775
	Balance December 31, 2003		Impairments		Dispositions		Other(b)			Balance December 31, 2004
	(in millions)
Natural Gas Transmission	$	3,241	$	—	$	—	$	175		$	3,416
Field Services		476		—		—		4			480
International Energy		238		—		—		7			245
Crescent		7		—		—		—			7
Total consolidated	$	3,962	$	—	$	—	$	186		$	4,148

(a) As a result of the deconsolidation of DEFS in July 2005 goodwill decreased by a net amount of $462 million, which includes the effects of an $18 million transfer of goodwill between Field Services and Natural Gas Transmission as a result of the transfer of Canadian assets in connection with the DEFS disposition transaction. (see Note 2).

(b) Except as noted in (a), other amounts consist primarily of foreign currency translation.

11. Investments in Unconsolidated Affiliates and Related Party Transactions

Investments in domestic and international affiliates that are not controlled by Duke Energy, but over which it has significant influence, are accounted for using the equity method. Duke Energy received distributions of $856 million in 2005 from those investments. Of these distributions, $473 million are included in Other, assets within Cash Flows from Operating Activities on the accompanying Consolidated Statements of Cash Flows and $383 million are included in Distributions from Equity Investments within Cash Flows from Investing Activities on the accompanying Consolidated Statements of Cash Flows. Duke Energy received distributions of $139 million in 2004 and $263 million in 2003 from those investments. These amounts are included in Other, assets within Cash Flows from Operating Activities on the accompanying Consolidated Statements of Cash Flows. Duke Energy’s share of net earnings from these unconsolidated affiliates is reflected in the Consolidated Statements of Operations as Equity in Earnings of Unconsolidated Affiliates. (See Note 2 for 2005 dispositions.)

As of December 31, 2005, the carrying amount of investments in affiliates approximated the amount of underlying equity in net assets. As of December 31, 2004, investments in affiliates were carried at approximately $91 million less than the amount of underlying equity in net assets (7% as of December 31, 2004). This amount is related to the difference in the carrying amount and the underlying net assets of investments owned by Field Services. Such difference has been fully allocated to the respective investee’s long-lived assets and the amounts are being amortized into income over the life of the underlying related long-lived assets. In July 2005, as a result of the DEFS disposition transactions (see below), Duke Energy deconsolidated the investments owned by Field Services.

Natural Gas Transmission. As of December 31, 2005, investments primarily included a 50% interest in Gulfstream Natural Gas System, LLC (Gulfstream). Gulfstream is an interstate natural gas pipeline that extends from Mississippi and Alabama across the Gulf of Mexico to Florida. Although Duke Energy owns a significant portion of Gulfstream, it is not consolidated as Duke Energy does not hold a majority of voting control or have the ability to exercise control over Gulfstream.

Field Services. In July 2005, Duke Energy completed the transfer of a 19.7% interest in DEFS to ConocoPhillips, Duke Energy’s co-equity owner in DEFS, which reduced Duke Energy’s ownership interest in DEFS from 69.7% to 50% (the DEFS disposition transactions) and resulted in Duke Energy and ConocoPhillips becoming equal 50% owners in DEFS. As a result of the DEFS disposition transaction, Duke Energy deconsolidated its investment in DEFS and subsequently has accounted for as an investment utilizing the equity

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

method of accounting (see Note 2). Additionally, in February 2005, DEFS sold its wholly owned subsidiary TEPPCO GP, which is the general partner of TEPPCO LP, for approximately $1.1 billion and Duke Energy sold its limited partner interest in TEPPCO LP for approximately $100 million, in each case to Enterprise GP Holdings LP, an unrelated third party. These transactions resulted in pre-tax gains of approximately $1.8 billion.

International Energy. As of December 31, 2005, investments primarily included a 25% indirect interest in National Methanol Company, which owns and operates a methanol and MTBE business in Jubail, Saudi Arabia. International Energy also has a 50% ownership in Compañia de Servicios de Compresión de Campeche, S.A. de C.V. (Campeche), a natural gas compression facility in the Cantarell oil field in the Gulf of Mexico, and a 38% ownership in Aguaytia, a natural gas facility in Peru.

Campeche project revenues are generated from the gas compression services agreement (GCSA) with the Mexican national oil company (PEMEX). The current five year GCSA expires on November 7, 2006 and PEMEX has the option to renew the GCSA for an additional four years. See Note 12 for a discussion of the impairment recognized on the Campeche investment.

Crescent. As of December 31, 2005, investments included various real estate development projects.

Other. As of December 31, 2005, investments primarily included a 50% interest in Southwest Power Partners, LLC. Southwest Power Partners, LLC is a gas-fired combined-cycle facility (Griffith Energy) in Arizona that serves markets in Arizona, Nevada and California. Although Duke Energy owns a significant portion of this investment, it is not consolidated as it does not hold a majority of voting control or have the ability to exercise control over this investment. Southwest Power Partners, LLC is included in DENA’s Western United States generation assets that qualify for discontinued operations classification for current and prior periods (see Note 13). As a result, the investment is classified as Assets Held for Sale in the accompanying Consolidated Balance Sheets as of December 31, 2005 and earnings and losses from this investment are classified as Discontinued Operations, net of tax in the accompanying Consolidated Statements of Operations.

Additionally, as of December 31, 2005, investments included participation in various construction and support activities for fossil-fueled generating plants through D/FD.

Investments in Unconsolidated Affiliates

	As of:
	December 31, 2005						December 31, 2004
	Domestic		International		Total		Domestic		International		Total
	(in millions)
U.S. Franchised Electric and Gas	$	2	$	—	$	2	$	—	$	—	$	—
Natural Gas Transmission		428		20		448		769		21		790
Field Services(a)		1,290		—		1,290		157		—		157
International Energy		—		155		155		—		167		167
Crescent		17		—		17		20		—		20
Other		14		7		21		151		7		158
Total	$	1,751	$	182	$	1,933	$	1,097	$	195	$	1,292

(a) Includes Duke Energy’s 50 percent interest in DEFS subsequent to deconsolidation of DEFS on July 1, 2005.

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Equity in Earnings of Unconsolidated Affiliates

	For the Years Ended:
	December 31, 2005								December 31, 2004						December 31, 2003
	Domestic			International		Total			Domestic		International		Total		Domestic		International			Total
	(in millions)
Natural Gas Transmission	$	42		$	5	$	47		$	26	$	4	$	30	$	19	$	13		$	32
Field Services(a)		308			—		308			60		—		60		56		—			56
International Energy		—			114		114			—		51		51		—		27			27
Crescent		(1	)		—		(1	)		3		—		3		—		—			—
Other(b)		11			—		11			16		1		17		13		(5	)		8
Total	$	360		$	119	$	479		$	105	$	56	$	161	$	88	$	35		$	123

(a) Includes Duke Energy’s 50 percent equity in earnings of DEFS subsequent to deconsolidation on July 1, 2005.

(b) Includes equity investments at the corporate level.

Summarized Combined Financial Information of Unconsolidated Affiliates

	As of December 31,
	2005			2004
	(in millions)
Balance Sheet
Current assets	$	3,414		$	1,413
Non-current assets		7,744			6,028
Current liabilities		(3,395	)		(1,118	)
Non-current liabilities		(3,237	)		(2,078	)
Net assets	$	4,526		$	4,245

	For the Years Ended December 31,
	2005		2004		2003
	(in millions)
Income Statement
Operating revenues	$	8,830	$	7,326	$	6,253
Operating expenses		7,683		6,872		5,526
Net income		1,075		415		550

Related Party Transactions. Outstanding notes receivable from unconsolidated affiliates were $50 million as of December 31, 2005 and $89 million as of December 31, 2004. Amounts are included in Notes Receivable on the Consolidated Balance Sheets. The balance outstanding as of December 31, 2005 represents International Energy’s note receivable from the Campeche project, a 50% owned joint venture. The outstanding note receivable had an interest rate at current market rates.

International Energy loaned money to Campeche to assist in the costs to build. During 2005, International Energy received principal and interest payments of approximately $5 million from Campeche, a 50% owned DEI affiliate. Payments from Campeche in 2004 and 2003 were $7 million and $8 million, respectively.

Natural Gas Transmission has a 50% ownership in two pipeline companies, Gulfstream, an operating pipeline, and Islander East, LLC, a development stage pipeline as well as a 50% ownership in a power plant, McMahon Cogeneration Plant, a cogeneration natural gas fired facility transferred to Natural Gas Transmission from DENA during 2005. Natural Gas Transmission provides certain administrative and other services to the pipeline companies and the power plant. Natural Gas Transmission recorded recoveries of costs from these affiliates of $12 million, $8 million, and $12 million during 2005, 2004, and 2003, respectively. The outstanding receivable from these affiliates was $2 million and $1 million for 2005 and 2004, respectively.

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

In October 2005, Gulfstream issued $500 million aggregate principal amount of 5.56% Senior Notes due 2015 and $350 million aggregate principal amount of 6.19% Senior Notes due 2025. The proceeds were used by Gulfstream to pay off a construction loan and the balance of the proceeds, net of transaction costs, of approximately $620 million was distributed to the partners based upon their ownership percentage (approximately $310 million was received by Natural Gas Transmission and are included in Distributions from Equity Investments within Cash Flows from Investing Activities in the accompanying Consolidated Statements of Cash Flows).

Advance SC LLC, which provides funding for economic development projects, educational initiatives, and other programs, was formed during 2004. U.S. Franchised Electric and Gas made donations of approximately $3 million and $6 million to the nonconsolidated subsidiary in 2005 and 2004, respectively. Additionally, at December 31, 2005, U.S. Franchised Electric and Gas had a trade payable to Advance SC LLC of approximately $24 million.

Field Services sells a portion of its residue gas and NGLs to, purchases raw natural gas and other petroleum products from, and provides gathering and transportation services to unconsolidated affiliates (primarily TEPPCO GP, which was sold in February 2005). Total revenues from these affiliates were approximately $98 million for the six months ended June 30, 2005, and $278 million and $166 million for the years ended December 31, 2004 and 2003, respectively. Total purchases from these affiliates were approximately $77 million for the six months ended June 30, 2005, and $125 million and $98 million for the years ended December 31, 2004 and 2003, respectively. Total operating expenses were approximately $1 million for the six months ended June 30, 2005, and $4 million and $4 million for the years ended December 31, 2004 and 2003, respectively. Reductions in revenues and purchases in 2005 as compared to 2004 are principally due to the sale of TEPPCO GP and deconsolidation of DEFS, effective July 1, 2005.

In July 2005, DEFS was deconsolidated due to the transfer of a 19.7% interest to ConocoPhillips and has been subsequently accounted for as an equity investment (see Note 2). Duke Energy’s 50% of equity in earnings of DEFS for the period of July 1, 2005 to December 31, 2005 was $292 million and Duke Energy’s investment in DEFS as of December 31, 2005 was $1,286 million, which is included in Investments in Unconsolidated Affiliates in the accompanying Consolidated Balance Sheets. Between July 1, 2005 and December 31, 2005, Duke Energy had gas sales to, purchases from, and other operating revenues from affiliates of DEFS of approximately $67 million, $65 million and $12 million, respectively. As of December 31, 2005, Duke Energy had trade receivables from and trade payables to DEFS amounting to approximately $18 million and $47 million, respectively. Additionally, Duke Energy received approximately $360 million for its share of distributions paid by DEFS in 2005. Additionally, Duke Energy has recognized an approximate $90 million receivable as of December 31, 2005 due to its share of quarterly tax distributions declared by DEFS in 2005 to be paid in 2006. Of these distributions, $287 million was included in Other, assets within Cash Flows from Operating Activities and approximately $73 million was included in Distributions from Equity Investments within Cash Flows from Investing Activities, within the accompanying Consolidated Statements of Cash Flows. Summary financial information for DEFS, which has been accounted for under the equity method since July 1, 2005 is as follows:

	Six-months Ended December 31, 2005
	(in millions)
Operating revenues	$	7,463
Operating expenses	$	6,814
Operating income	$	649
Net income	$	584

	December 31 2005
	(in millions)
Current assets	$	2,706
Non-current assets	$	5,005
Current liabilities	$	3,068
Non-current liabilities	$	2,050
Minority interest	$	83

As of December 31, 2005, there was an immaterial basis difference between Duke Energy’s carrying value of the investment in DEFS and the value of Duke Energy’s proportionate share of the underlying net assets in DEFS.

DEFS is a limited liability company which is a pass-through entity for U.S. income tax purposes. DEFS also owns corporations who file their own respective, federal, foreign and state income tax returns and income tax expense related to these corporations is included

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

in the income tax expense of DEFS. Therefore, DEFS’ net income does not include income taxes for earnings which are pass-through to the members based upon their ownership percentage and Duke Energy recognizes the tax impacts of its share of DEFS’ pass-through earnings in its income tax expense from continuing operations in the accompanying Consolidated Statements of Operations.

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 D/FD and have adopted a plan for an orderly wind-down D/FD’s business. The wind-down has been substantially completed as of December 31, 2005 and is expected to be finalized by December 2006. Previously, D/FD provided comprehensive engineering, procurement, construction, commissioning and operating plant services for fossil-fueled electric power generating facilities worldwide. D/FD was the primary builder of DENA’s merchant generation plants. D/FD has built some plants for Duke Energy Carolinas. Fifty percent of the profit earned by D/FD for the construction of affiliates’ generation plants, which is associated with Duke Energy’s ownership, is either deferred in consolidation until the plant is sold or, once the plant becomes operational, the deferred profit is amortized over the plant’s useful life or on an accelerated basis if the plants are impaired. Fifty percent of the profit earned by D/FD for operating and maintenance services for Duke Energy owned plants is eliminated in consolidation. For the year ended December 31, 2005, Duke Energy did not record deferred profit for D/FD construction contracts and did not eliminate any profit for operating and maintenance services. For the year ended December 31, 2004, Duke Energy deferred profit of $2 million for construction contracts and did not eliminate any profit for operating and maintenance services. In addition, as part of the D/FD partnership agreement, excess cash is loaned at current market rates to Duke Energy and Fluor Enterprises, Inc. (See Note 15.)

In 2005, DEFS formed DCP Midstream Partners, LP (a master limited partnership). DCP Midstream Partners, LP (DCPLP) completed an initial public offering (IPO) transaction in December that resulted in net proceeds of approximately $210 million. As a result, DEFS has a 42 percent ownership interest in DCPLP, consisting of a 40 percent limited partner ownership interest and a 2 percent general partner ownership interest. DEFS’ ownership interest in the general partner of DCPLP is 100 percent. The gain on the IPO transaction has been deferred by DEFS until DEFS converts its subordinated units in DCP to common units, which will occur no earlier than December 31, 2008.

In the normal course of business, Duke Energy’s consolidated subsidiaries enter into energy trading contracts or other derivatives with one another. On a separate company basis, each subsidiary accounts for such contracts as if they were transacted with a third party and records the contracts using the MTM Model or the Accrual Model of Accounting, as applicable. In the consolidation process, the effects of these intercompany contracts are eliminated, and not reflected in Duke Energy’s Consolidated Financial Statements.

Also see Note 15, Note 17, and Note 18 for additional related party information.

12. Impairments, Severance, and Other Charges

	For the Years Ended December 31,
	2005		2004		2003
	(in millions)
Field Services	$	125	$	22	$	—
Commercial Power		—		—		1,106
Crescent		15		42		—
Other		—		—		113
Total Impairment and other charges	$	140	$	64	$	1,219

Field Services. See Note 8 for a discussion of the impacts of the DEFS disposition transaction on certain cash flow hedges.

In the third quarter of 2004, Field Services recorded impairments of approximately $22 million related to some of Field Services’ operating assets.

Additionally, in the third quarter of 2004, Field Services recorded an impairment of approximately $23 million related to equity method investments at Field Services. The impairment is included in Gains (Losses) on Sales and Impairments of Equity Method Investments on the Consolidated Statements of Operations. The impairment charge was related to management’s assessment of the recoverability of some equity method investments. Field Services determined that these assets, which are located in the Gulf Coast, were impaired; therefore they were written down to fair value. Fair value was determined based on management’s best estimates of sales value and/or discounted future cash flow models.

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

International Energy. International Energy owns a 50% joint venture interest in Campeche. Campeche project revenues are generated from the GCSA with PEMEX. The current five year GCSA expires on November 7, 2006 and PEMEX has the option to renew the GCSA for an additional four years. As a result of ongoing discussions between Campeche and PEMEX to either sell the Campeche investment or renew the GCSA, a $20 million other than temporary impairment in value of the Campeche investment was recognized during the third quarter of 2005 to write down the investment to its estimated fair value. This impairment is classified as a component of Gains (Losses) on Sales and Impairments of Equity Method Investments in the accompanying Consolidated Statements of Operations. An additional impairment charge could be recognized if the ultimate outcome of the above discussions is materially different than management’s current expectations.

Crescent. In the third quarter of 2005, Crescent recognized pre-tax impairment charges of approximately $16 million related to a residential community near Hilton Head Island, South Carolina, that includes both residential lots and a golf club, to reduce the carrying value of the community to its estimated fair value. This impairment was recognized as a component of Impairment and Other Charges in the accompanying Consolidated Statements of Operations. This community has incurred higher than expected costs and has been impacted by lower than anticipated sales volume. The fair value of the remaining community assets was determined based upon management’s estimate of discounted future cash flows generated from the development and sale of the community.

In the fourth quarter of 2004, Crescent recorded impairment charges of approximately $42 million related to two residential developments in Payson, Arizona, the Rim and Chaparral Pines, and one residential development in Austin, Texas, Twin Creeks. The impairment charges were related to long lived assets at the three properties. The developments have suffered from slower than anticipated absorption of available inventory. Fair value of the assets was determined based on management’s assessment of current operating results and discounted future cash flow models. Crescent also recorded bad debt charges of $8 million related to notes receivable due from Rim Golf Investor, LLC and Chaparral Pines Investor, LLC. This amount is recorded in Operation, Maintenance and Other on the Consolidated Statements of Operations.

Commercial Power. In the fourth quarter of 2003, as a result of deteriorating market conditions in the merchant energy industry, Duke Energy decided to exit the merchant power generation business in the Southeastern U.S. The carrying value of the Southeast Plants exceeded the fair value, resulting in an impairment charge in 2003 of approximately $1.3 billion. The fair value of the Southeast Plants was estimated primarily based on third party comparable sales, analysis from outside advisors and information available from efforts to sell certain of these assets. These assets were subsequently sold in the second quarter of 2004 (see Note 2).

Certain forward power contracts related to the Southeast Plants had been primarily designated as normal purchases and sales in accordance with SFAS No. 133. In addition, certain forward gas contracts related to the long-lived assets had been designated as cash flow hedges in accordance with SFAS No. 133. As a result of the change in management intent for the long-lived assets, the related forward power and gas contracts were de-designated as normal purchases and sales and hedges. As a result, a benefit of $190 million was recorded as an offset to the impairment charge.

As a result of the decisions discussed above, Commercial Power recorded impairment charges in 2003 of approximately $1.1 billion, primarily related to electric generation plants which are classified as Property, Plant and Equipment on the Consolidated Balance Sheets and to mark the derivative contracts to market value and reclassify the hedge amounts previously included in AOCI in accordance with SFAS No. 133.

Other. See Note 8 for a discussion of the impacts of the DENA exit plan on certain cash flow hedges.

Duke Energy recorded additional impairment charges of $60 million in 2003, primarily associated with a plan to sell an investment in Bayside, an unconsolidated affiliate. Fair value of these assets was estimated based primarily on discounted cash flow analysis.

The 2003 charges also included the abandonment of a corporate risk management information system, primarily due to Duke Energy exiting the proprietary trading business and the reduction of scope and scale of DETM’s business.

Severance. As discussed further in Note 13, during the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. As a result of this exit plan, during the year ended December 31, 2005, Other recorded a severance accrual of approximately $22 million, under its ongoing severance plan, related to the anticipated involuntary termination of approximately 400 employees by the end of the second quarter of 2006. Approximately $2 million of the related pre-tax expense is reflected in Operation, Maintenance and Other and approximately $20 million is reflected in (Loss)

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Income from Discontinued Operations, net of tax in the accompanying Consolidated Statements of Operations for the year ended December 31, 2005. Additionally, Duke Energy is also offering certain enhanced severance benefits to employees expected to be involuntarily terminated in connection with the DENA disposition plan, which are being recognized over the remaining service period. Approximately $3 million of enhanced severance benefits were accrued during the fourth quarter of 2005. Management anticipates future severance costs incurred related to this exit plan will be approximately $20 million to $25 million.

During 2002, Duke Energy communicated a voluntary and involuntary severance program across all segments to align the business with market conditions during that period. Severance plans related to the program were amended effective August 1, 2004 and applied to individuals notified of layoffs between that date and January 1, 2006.

Severance Reserve	Balance at January 1, 2005		Provision/ Adjustments		Noncash Adjustments			Cash Reductions			Balance at December 31, 2005
	(in millions)
U.S. Franchised Electric and Gas	$	4	$	—	$	(2	)	$	(2	)	$	—
Natural Gas Transmission		6		1		(1	)		(3	)		3
Field Services(c)		—		1		(1	)		—			—
International Energy		1		—		(1	)		—			—
Other(d)		4		26		—			(2	)		28
Total(a)	$	15	$	28	$	(5	)	$	(7	)	$	31
	Balance at January 1, 2004		Provision/ Adjustments		Noncash Adjustments			Cash Reductions			Balance at December 31, 2004
	(in millions)
U.S. Franchised Electric and Gas	$	60	$	—	$	(6	)	$	(50	)	$	4
Natural Gas Transmission		29		1		(6	)		(18	)		6
Field Services(c)		6		1		—			(7	)		—
International Energy		6		—		(4	)		(1	)		1
Other(d)		49		3		(5	)		(43	)		4
Total(a)	$	150	$	5	$	(21	)	$	(119	)	$	15
	Balance at January 1, 2003		Provision/ Adjustments		Noncash Adjustments			Cash Reductions			Balance at December 31, 2003
U.S. Franchised Electric and Gas	$	29	$	65	$	—		$	(34	)	$	60
Natural Gas Transmission		33		20		1			(25	)		29
Field Services(c)		—		6		—			—			6
International Energy		4		6		(4	)		—			6
Other(b)(d)		47		37		(2	)		(33	)		49
Total(a)(b)	$	113	$	134	$	(5	)	$	(92	)	$	150

(a) Substantially all expected severance costs will be applied to the reserves within one year.

(b) Provision in 2003 excludes $22 million of curtailment costs related to other post-retirement benefits.

(c) Includes minority interest.

(d) Severance expense included in (Loss) Income From Discontinued Operations, net of tax in the Consolidated Statements of Operations was $22 million, $1 million and $7 million for 2005, 2004 and 2003, respectively.

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

13. Discontinued Operations and Assets Held for Sale

The following table summarizes the results classified as (Loss) Income from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.

Discontinued Operations (in millions)

	Operating Revenues		Operating Income (Loss)									Net Gain (Loss) on Dispositions									(Loss) Income from Discontinued Operations, Net of Tax
			Pre-tax Operating Income (Loss)			Income Tax Expense (Benefit)			Operating Income (Loss), Net of Tax			Pre-tax Gain (Loss) on Dispositions			Income Tax Expense (Benefit)			Gain (Loss) on Dispositions, Net of Tax
Year Ended December 31, 2005
Field Services	$	4	$	—		$	—		$	—		$	—		$	—		$	—		$	—
International Energy		—		(3	)		1			(4	)		—			—			—			(4	)
Crescent		2		1			—			1			10			4			6			7
Other		2,192		(664	)		(245	)		(419	)		(481	)		(192	)		(289	)		(708	)
Total consolidated	$	2,198	$	(666	)	$	(244	)	$	(422	)	$	(471	)	$	(188	)	$	(283	)	$	(705	)
Year Ended December 31, 2004
Field Services	$	79	$	3		$	1		$	2		$	(17	)	$	(6	)	$	(11	)	$	(9	)
International Energy		85		(13	)		(1	)		(12	)		295			22			273			261
Crescent		2		—			—			—			9			4			5			5
Other		2,300		(14	)		6			(20	)		1			—			1			(19	)
Total consolidated	$	2,466	$	(24	)	$	6		$	(30	)	$	288		$	20		$	268		$	238
Year Ended December 31, 2003
Field Services	$	345	$	9		$	3		$	6		$	19		$	7		$	12		$	18
International Energy		759		(34	)		(4	)		(30	)		(242	)		(119	)		(123	)		(153	)
Crescent		5		—			—			—			18			7			11			11
Other		4,176		(1,691	)		(614	)		(1,077	)		(49	)		(18	)		(31	)		(1,108	)
Total consolidated	$	5,285	$	(1,716	)	$	(615	)	$	(1,101	)	$	(254	)	$	(123	)	$	(131	)	$	(1,232	)

The following table presents the carrying values of the major classes of assets and associated liabilities held for sale in the accompanying Consolidated Balance Sheets as of December 31, 2005 and 2004.

Summarized Balance Sheet Information for Assets and Associated Liabilities Held for Sale

	December 31, 2005		December 31, 2004
	(in millions)
Current assets	$	1,528	$	40
Investments and other assets		2,059		12
Property, plant and equipment, net		1,538		72
Total assets held for sale	$	5,125	$	124
Current liabilities	$	1,488	$	30
Long-term debt		61		14
Deferred credits and other liabilities		2,024		—
Total liabilities associated with assets held for sale	$	3,573	$	44

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Field Services

In December 2004, based upon management’s assessment of the probable disposition of some plant and transportation assets in Wyoming, Field Services classified these assets as Assets Held for Sale in the Consolidated Balance Sheets as of December 31, 2004. The book value of those assets was written down by $4 million ($3 million net of minority interest) to $10 million in December 2004, which represents the estimated fair value less cost to sell. The after tax loss and results of operations related to these assets were included in (Loss) Income from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations. In February 2005, these assets were exchanged for certain gathering assets in Oklahoma of equivalent fair value.

In December 2004, Field Services sold gas system and treating plant assets in Southeast New Mexico and South Texas, respectively. Field Services sold these assets for proceeds of approximately $6 million, with the carrying value being approximately equal to the sales price. The after tax loss and related results of operations were included in (Loss) Income from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.

In September 2004, Field Services recorded a pre-tax impairment charge of approximately $23 million ($16 million net of minority interest) related to management’s current assessment of some additional gathering, processing, compression and transportation assets in Wyoming being held for sale. The estimated fair value of these assets less cost to sell was $27 million and classified as Assets Held for Sale in the Consolidated Balance Sheets as of December 31, 2004. The after tax loss and results of operations were included in (Loss) Income from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations. In the first quarter of 2005, Field Services sold these assets for proceeds of $28 million, with the carrying value being approximately equal to the sales price.

In February 2004, Field Services sold gas gathering and processing plant assets in West Texas to a third party purchaser for a sales price of approximately $62 million, which approximated these assets’ carrying value. The after tax gain and results of operations related to these assets were included in (Loss) Income from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.

In 2003, Field Services sold two packages of assets for a total sales price of $90 million. The after tax gain on these sales of $12 million and related operating results were included in (Loss) Income from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations. The assets sold consisted of various gas processing plants and gathering pipelines in Mississippi, Texas, Alabama, Louisiana and Oklahoma.

Other

During the third quarter of 2005, Duke Energy’s Board of Directors authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. The DENA assets to be divested include:

• Approximately 6,100 MW of power generation located primarily in the Western and Eastern United States, including all of the commodity contracts (primarily forward gas and power contracts) related to these facilities,

• All remaining commodity contracts related to DENA’s Southeastern generation operations, which were substantially disposed of in 2004, and certain commodity contracts related to DENA’s Midwestern power generation facilities, and

• Contracts related to DENA’s energy marketing and management activities, which include gas storage and transportation, structured power and other contracts.

Management intends to retain DENA’s Midwestern generation assets, consisting of approximately 3,600 MW of power generation, and certain contracts related to the Midwestern generating facilities, as the anticipated merger with Cinergy provides a sustainable business model for those assets (see Notes 2 and 4 for further details on the anticipated Cinergy merger). The exit plan is expected to be completed by the end of the second quarter of 2006. In addition, management will continue to wind down the limited remaining operations of DETM. The financial statement presentation for the assets and contracts to be sold, and the related results of operations, are discussed below.

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

In connection with this exit plan, Duke Energy recognized pre-tax losses of approximately $1.1 billion in 2005 in (Loss) Income From Discontinued Operations, net of tax, in the Consolidated Statement of Operations. These losses principally related to:

• The discontinuation of the normal purchase/normal sale exception for certain forward power and gas contracts (an approximate $1.9 billion pre-tax charge)

• The reclassification of approximately $1.2 billion of pre-tax deferred net gains in AOCI for cash flow hedges of forecasted gas purchase and power sale transactions that will no longer occur as a result of the exit plan

• Pre-tax impairments of approximately $0.2 billion to reduce the carrying value of the plants that are expected to be sold to their estimated fair value less cost to sell. Fair value of the assets that are expected to be sold was estimated based upon the signed agreement with LS Power, as discussed below.

• Pre-tax losses of approximately $400 million as the result of selling certain gas transportation and structured contracts (as discussed further below), and

• Pre-tax deferred gains in AOCI of approximately $200 million related to the discontinued cash flow hedges of forecasted gas purchase and power sale transactions, which were recognized as the forecasted transactions occurred.

Additionally, approximately $10 million of pre-tax deferred net losses remain in AOCI at December 31, 2005 related to hedges of forecasted transactions that are expected to occur prior to the anticipated disposal of the generation assets. This amount will be reclassified to earnings during 2006 as the forecasted transactions occur. In addition, as of the September 2005 exit announcement date, management anticipated that additional charges would be incurred related to the exit plan, including termination costs for gas transportation, storage, structured power and other contracts of approximately $600 million to $800 million, which includes approximately $40 million to $60 million of severance, retention and other transaction costs (see Note 12). Approximately $500 million was incurred as of December 31, 2005, approximately $400 million of which was recognized in (Loss) Income From Discontinued Operations, net of tax. The actual amount of future additional charges related to the DENA exit plan will vary depending upon changes in market conditions and other factors, and could differ materially from the original estimate. Duke Energy may also realize future potential gains on sales of certain plants which will be recognized when sold.

During 2005, Duke Energy has entered into agreements to sell or terminate certain of its contract portfolio, including certain transportation contracts. The total cash paid by Duke Energy under such contract sales or terminations during 2005 was approximately $400 million, excluding approximately $100 million of cash paid to Barclays, as discussed hereafter. These transactions resulted in pre-tax losses on sale of approximately $400 million, which are included in the $600 million to $800 million range of additional anticipated charges, as discussed above. Included in these amounts are the effects of DENA’s November 2005 agreement to sell substantially all of its commodity contracts related to the Southeastern generation operations, which were substantially disposed of in 2004, certain commodity contracts related to DENA’s Midwestern power generation facilities, and contracts related to DENA’s energy marketing and management activities. Excluded from the contracts sold to Barclays are commodity contracts associated with the near-term value of DENA’s West and Northeastern generation assets and with remaining gas transportation and structured power contracts. Among other things, the agreement provides that effective immediately all economic benefits and burdens under the contracts were transferred to Barclays. Cash consideration paid to Barclays amounted to approximately $100 million in 2005 and approximately $600 million in January 2006. Additionally, in January 2006 Barclays provided Duke Energy with cash equal to the net cash collateral posted by Duke Energy under the contracts of approximately $540 million. Duke Energy will continue to service the contracts until novation or assignment for a monthly fee. The novation or assignment of physical power contracts was subject to FERC approval, which has been received in January 2006.

In January 2006, Duke Energy signed an agreement to sell to LS Power DENA’s entire fleet of power generation assets outside the Midwest, representing approximately 6,100 megawatts of power generation located in the Western and Northeast United States, for approximately $1.5 billion. Duke Energy recognized a pre-tax gain of approximately $380 million in the fourth quarter of 2005, which offsets a portion of the impairment of approximately $0.6 billion recognized in the third quarter of 2005. The transaction is subject to FERC and Hart-Scott-Rodino approvals and is expected to close in the second quarter of 2006.

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

The net impairments of approximately $0.2 billion have been classified as a component of (Loss) Income from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations. See Note 8 for further details on the hedge accounting implications of this exit activity. The charge for the discontinuance of the normal purchase/normal sale exception and the reclassification of deferred gains in AOCI for cash flow hedges have been classified as a component of (Loss) Income from Discontinued Operations, net of tax, in the Consolidated Statements of Operations.

As of December 31, 2005, DENA’s assets and liabilities to be disposed of under the exit plan were classified as Assets Held for Sale in the Consolidated Balance Sheets, except the Ft. Frances generation facility which was sold in October 2005 for proceeds approximating carrying value.

The results of operations of DENA’s Western and Eastern United States generation assets, including related commodity contracts, certain contracts related to DENA’s energy marketing and management activities and certain general and administrative costs, are required to be classified as discontinued operations for current and prior periods in the accompanying Consolidated Statements of Operations. GAAP requires an ongoing assessment of the continued qualification for discontinued operations presentation for the period up through one year following disposal. While this assessment requires judgment, management is not currently aware of any matters or events that are likely to occur that would impact the presentation of these operations as discontinued operations.

DENA’s Midwestern generation assets are being retained and, therefore, the results of operations for these assets, including related commodity contracts, do not qualify for discontinued operations classification and remain in continuing operations. Additionally, as discussed further in Note 2, DENA’s Southeastern generation operations, including related commodity contracts do not meet the requirements for discontinued operations classification due to Duke Energy’s continuing involvement with these operations. In addition, the results for DETM will continue to be reported in continuing operations until the wind down of these operations is complete.

See Note 3 for a discussion of the impacts of this exit activity on Duke Energy’s segment presentation.

In the first quarter of 2005, DENA’s Grays Harbor facility was sold to an affiliate of Invenergy LLC, resulting in a pre-tax gain of approximately $21 million (excludes any potential contingent consideration).

In the third quarter of 2005, Duke Energy completed the sale of Bayside Power L.P. (Bayside) to affiliates of Irving Oil Limited (Irving), under which Irving would purchase DENA’s 75% interest in Bayside. The after tax gain on this sale is included in (Loss) Income from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations. Bayside was consolidated with the adoption of FIN 46R on March 31, 2004. Therefore, Bayside’s operating results after March 31, 2004 are included in (Loss) Income from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations. Prior operating results are not included in Discontinued Operations, as Bayside was previously accounted for as an equity method investment.

For the year ended December 31, 2004, Other incurred net operating losses on its discontinued operations. Discontinued operations also included sales and impairments of merchant power plants located in Washington (“Grays Harbor” plant), Nevada (“Moapa” plant) and New Mexico (“Luna” plant) (collectively, the deferred plants). The deferred plants were a component of DENA’s Western United States generation assets that meets the requirements for discontinued operations classification for current and prior periods in the accompanying Consolidated Statements of Operations. Details are as follows:

• The partially completed Moapa facility was sold to Nevada Power Company and resulted in $186 million in net proceeds and a pre-tax gain of approximately $140 million recorded in (Loss) Income from Discontinued Operations, net of tax, in the 2004 Consolidated Statement of Operations.

• The partially completed Luna facility was sold to PNM Resources, Tucson Electric Power and Phelps Dodge Corporation. This sale resulted in net proceeds of $40 million and a pre-tax gain of $40 million recorded in (Loss) Income from Discontinued Operations, net of tax, in the 2004 Consolidated Statements of Operations.

• In December 2004, Duke Energy agreed to sell the partially completed Grays Harbor facility to an affiliate of Invenergy LLC. Also, effective December 31, 2004, Duke Energy terminated it capital lease associated with the dedicated pipeline which would have transported natural gas to the plant. This termination resulted in a $20 million pre-tax charge recorded in (Loss) Income from Discontinued Operations, net of tax, in the 2004 Consolidated Statements of Operations. As discussed above, in the first quarter of 2005, Grays Harbor was sold.

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

For the year ended December 31, 2003, Other’s net operating loss from discontinued operations was due primarily to the following:

• In the fourth quarter of 2003, Duke Energy decided not to fund completion of construction of three DENA deferred plants. The carrying value of these assets exceeded the fair value, resulting in an impairment charge of approximately $1.1 billion pre-tax ($515 million for Moapa, $270 million for Luna and $362 million for Grays Harbor) which was recorded in (Loss) Income from Discontinued Operations, net of tax, in the 2003 Consolidated Statement of Operations. The fair value of the deferred plants was estimated based primarily on analysis from outside advisors and information available from efforts to sell certain of these assets.

• Certain forward power contracts related to the deferred plants had been primarily designated as normal purchases and normal sales in accordance with SFAS No. 133. In addition, certain forward gas contracts related to the long-lived assets had been designated as cash flow hedges in accordance with SFAS No. 133. As a result of the change in management intent for the long-lived assets, the related forward power and gas contracts were de-designated as normal purchases and sales and hedges. As a result, a pre-tax charge of $452 million was recorded.

• A power generation plant in Maine. During 2003, Duke Energy agreed to sell this plant and recorded a pre-tax impairment charge of $72 million for the portion of the carrying value in excess of the negotiated sales price for the plant. The sale that was anticipated did not occur. This plant was a component of DENA’s Eastern United States generation assets that meet the requirements for discontinued operations classification for current and prior periods in the accompanying Consolidated Statements of Operations.

• An impairment charge of $64 million in 2003 associated with a change in the expected dispatch of Morro Bay, a plant in California. Fair value of this asset was estimated based primarily on discounted cash flow analysis.

During 2004, Duke Energy received approximately $58 million from the sale or collection of all of DCP’s notes receivable. An immaterial after tax gain related to this transaction was included in (Loss) Income from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.

During 2003, Duke Energy decided to exit the merchant finance business conducted by DCP. As a result, Duke Energy recorded an approximately $17 million after tax loss, which represents the excess of the carrying value of the notes receivable over the fair value, less costs to sell. Fair value of the notes receivable was estimated based primarily on discounted cash flow analysis. The after tax loss was included in (Loss) Income from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations. The sale or collection of substantially all of DCP’s notes receivable was completed during 2004. DCP’s operating results are included in (Loss) Income from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.

During 2003, Duke Energy sold Duke Energy Hydrocarbons LLC for approximately $83 million. Duke Energy recorded an approximate $14 million after tax loss on the sale, which was included in (Loss) Income from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.

International Energy

In order to eliminate exposure to international markets outside of Latin America and Canada, International Energy decided in 2003 to pursue a possible sale or IPO of International Energy’s Asia-Pacific power generation and natural gas transmission business (the Asia-Pacific Business). As a result of this decision, International Energy recorded an after tax loss of $233 million during the fourth quarter of 2003, which represented the excess of the carrying value over the estimated fair value of the business, less estimated costs to sell. Fair value of the business was estimated based primarily on comparable third party sales and analysis from outside advisors. This after tax loss was included in (Loss) Income from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.

In the first quarter of 2004, International Energy determined it was likely that a bid in excess of the originally determined fair value would be accepted and thus recorded a $238 million after tax gain related to International Energy’s Asia-Pacific Business. The after tax gain was included in (Loss) Income from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations and restored the loss recorded during the fourth quarter of 2003.

In the second quarter of 2004, International Energy completed the sale of the Asia-Pacific Business to Alinta Ltd. for a gross sales price of approximately $1.2 billion. This resulted in recording an additional $40 million after tax gain in the second quarter of 2004. The after tax gain was included in (Loss) Income from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Operations. International Energy received approximately $390 million of cash proceeds, net of approximately $840 million of debt retired (as a non-cash financing activity) as part of the Asia-Pacific Business.

In 2003, International Energy restructured and began exiting its operations in Europe. International Energy sold its Dutch gas marketing business for $84 million and sold a power generation plant in France for $79 million. An after tax net gain of $11 million on these sales was included in (Loss) Income from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations. An income tax benefit of approximately $101 million was also recorded in 2003, primarily associated with the $194 million goodwill impairment recognized in 2002 for the gas marketing business in Europe, the 2003 sale of that business and certain other exit costs. This tax benefit was included in (Loss) Income from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.

Associated with the sale of the European Business, International Energy holds a receivable from Norsk Hydro ASA with a fair value of $42 million as of December 31, 2005 and $54 million as of December 31, 2004. This balance is included in Receivables in the Consolidated Balance Sheets as of December 31, 2005 and 2004. In 2004, International Energy recorded a $14 million ($9 million after tax) allowance against the carrying value of the note based on management’s assessment of the probability of not collecting the entire note. The after tax loss was included in (Loss) Income from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.

In 2003, International Energy completed the sale of its 85.7% majority interest in P.T. Puncakjaya Power (PJP) in Indonesia for $78 million. The sale resulted in a reduction to Duke Energy’s consolidated indebtedness of $259 million. International Energy recorded an immaterial after tax loss on the sale, which was included in (Loss) Income from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations. The operating results related to these operations were included in (Loss) Income from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.

Crescent

Crescent routinely develops real estate projects and operates those facilities until they are substantially leased and a sales agreement is finalized. If Crescent does not retain any significant continuing involvement after the sale, Crescent classifies the project as “discontinued operations” as required by SFAS No. 144.

In 2005, Crescent sold three commercial properties resulting in sales proceeds of approximately $44 million. The $6 million after tax gain on these sales was included in (Loss) Income from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.

In 2004, Crescent sold one multi-family, two residential and two commercial properties resulting in sales proceeds of approximately $52 million. The $5 million after tax gain on these sales was included in (Loss) Income from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.

In 2003, Crescent sold three retail centers and one apartment complex, all located in Florida, for a total sales price of approximately $77 million. The $11 million after tax gain on these sales was included in (Loss) Income from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

14. Property, Plant and Equipment

	Estimated Useful Life	December 31,
		2005			2004
	(Years)	(in millions)
Land	—	$	571		$	566
Plant—Regulated
Electric generation, distribution and transmission	20 – 125		18,935			18,265
Natural gas transmission and distribution	20 – 82		10,561			10,178
Gathering and processing facilities	20 – 25		1,570			1,465
Other buildings and improvements	16 – 90		388			362
Plant—Unregulated
Electric generation, distribution and transmission(a)	20 – 125		3,869			5,672
Natural gas transmission and distribution	20 – 82		32			1,224
Gathering and processing facilities(a)	20 – 25		678			4,878
Other buildings and improvements(a)	16 – 90		27			78
Nuclear fuel	4		890			821
Equipment(a)	3 – 40		669			1,150
Vehicles	3 – 25		125			136
Construction in process	—		946			715
Other(a)	5 – 122		1,313			1,296
Total property, plant and equipment			40,574			46,806
Total accumulated depreciation—regulated(b), (c)			(10,472	)		(10,335	)
Total accumulated depreciation—unregulated(c)			(902	)		(2,665	)
Total net property, plant and equipment		$	29,200		$	33,806

(a) Includes capitalized leases: $48 million for 2005 and $87 million for 2004.

(b) Includes accumulated amortization of nuclear fuel: $583 million for 2005 and $550 million for 2004.

(c) Includes accumulated amortization of capitalized leases: $19 million for 2005 and $33 million for 2004.

Capitalized interest, which includes the interest expense component of AFUDC, amounted to $23 million for 2005, $18 million for 2004 and $58 million for 2003.

15. Debt and Credit Facilities

Summary of Debt and Related Terms

	Weighted- Average Rate		Year Due	December 31,
				2005			2004
	(in millions)
Unsecured debt	6.4	%	2006 – 2032	$	12,600		$	15,516
Secured debt	6.1	%	2006 – 2024		1,570			1,414
First and refunding mortgage bonds	4.6	%	2008 – 2027		1,214			1,215
Capital leases	8.2	%	2006 – 2025		10			195
Other debt(a)	3.4	%	2006 – 2017		208			213
Commercial paper(b)	4.1	%			383			218
Fair value hedge carrying value adjustment			2006 – 2032		58			80
Unamortized debt discount and premium, net					(13	)		(19	)
Total debt(c)					16,030			18,832
Current maturities of long-term debt					(1,400	)		(1,832	)
Short-term notes payable and commercial paper(d)					(83	)		(68	)
Total long-term debt(e)				$	14,547		$	16,932

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

(a) Includes $172 million of Duke Energy pollution control bonds as of December 31, 2005 and 2004. As of December 31, 2005 and 2004, $40 million was secured by first and refunding mortgage bonds and $77 million was secured by a letter of credit which in turn is secured by first and refunding mortgage bond.

(b) Includes $300 million as of December 31, 2005 and $150 million as of December 31, 2004 that was classified as Long-term Debt on the Consolidated Balance Sheets. The weighted-average days to maturity were 18 days as of December 31, 2005 and 8 days as of December 31, 2004.

(c) As of December 31, 2005, $501 million of debt was denominated in Brazilian Reals and $3,917 million of debt was denominated in Canadian dollars. As of December 31, 2004, $485 million of debt was denominated in Brazilian Reals and $3,720 million of debt was denominated in Canadian dollars.

(d) Weighted-average rates on outstanding short-term notes payable and commercial paper was 3.3% as of December 31, 2005 and 2.5% as of December 31, 2004.

(e) The current and non-current portions of DEFS’ long-term debt balances of approximately $600 million and approximately $1,650 million, respectively, as of December 31, 2004, are no longer included in Duke Energy’s consolidated debt balance due to the deconsolidation of DEFS in July 2005.

Unsecured Debt. In November 2005, DEI issued floating rate debt in Guatemala for $87 million (in USD) and in El Salvador for $75 million (in USD). These debt issuances have variable interest rate terms and mature in 2015.

On September 21, 2005, Union Gas entered into a fixed-rate financing agreement denominated in 200 million Canadian dollars (approximately $171 million in U.S. dollar equivalents as of the issuance date) due in 2016 with an interest rate of 4.64%.

In August 2005, DEI issued project-level debt in Peru, of which $75 million is denominated in U.S. dollars and approximately $34 million (in U.S. dollar equivalents as of the issuance date) is denominated in Peru Nuevos Soles. This debt has terms ranging from four to six years as well as variable or fixed interest rate terms, as applicable.

On March 1, 2005, redemption notices were sent to the bondholders of the $100 million PanEnergy 8.625% bonds due in 2025. These bonds were redeemed on April 15, 2005 at a redemption price of 104.03 or approximately $104 million.

During the first quarter of 2005, Duke Energy increased the portion of outstanding commercial paper balances classified as long-term debt from $150 million to $300 million. This non-current classification is due to the existence of long-term credit facilities which back-stop these commercial paper balances along with Duke Energy’s ability and intent to refinance those balances on a long-term basis.

In May 2004, Duke Energy redeemed its Series C 6.60% senior notes due in 2038, at a $200 million face value. As the securities were redeemed at par, security holders received $25 per each note held, plus accrued interest to the redemption date.

In February 2004, Duke Capital remarketed $875 million of senior notes due in 2006, underlying its 8.25% Equity Units and reset the interest rate from 5.87% to 4.302%. As this action was contemplated in the original Equity Units issuance, the transaction had no immediate accounting implications. Subsequently, Duke Capital exchanged $475 million of the remarketed senior notes for $200 million of 4.37% senior unsecured notes due in 2009, and $288 million of 5.5% senior unsecured notes due in 2014. In accordance with EITF 96-19, “Debtors Accounting for a Modification or Exchange of Debt Instruments,” the $475 million of remarketed senior notes issued earlier at 4.302% was extinguished. This exchange transaction resulted in an approximate $11 million loss, which was included in Interest Expense in the Consolidated Statements of Operations for the year ended December 31, 2004. Proceeds from the remarketed notes were used to purchase U.S. Treasury securities that were held by the collateral agent and, upon maturity, were used to satisfy the forward stock purchase contract component of the 8.25% Equity Units in May of 2004.

Additionally, Duke Capital remarketed $750 million of its 4.32% senior notes due in 2006, underlying Duke Energy’s 8.00% Equity Units on August 11, 2004. As a result of the remarketing, the interest rate on the notes was reset to 4.331%, effective August 16, 2004. Duke Capital subsequently exchanged $400 million of the 4.331% notes for $408 million of 5.668% notes due in 2014. This transaction resulted in an approximate $6 million loss, which was included in Interest Expense in the Consolidated Statements of Operations for the year end December 31, 2004. Proceeds from the remarketed notes were used to purchase U.S. Treasury securities held by the collateral agent and, upon maturity, were used to satisfy the forward stock purchase contract component of the 8% Equity Units in November 2004.

Convertible Debt. As of December 31, 2005 and 2004, unsecured debt included $742 million and $770 million, respectively, of 1.75% convertible senior notes due in 2023. These senior notes, which were issued in May 2003, are convertible to Duke Energy common stock at a premium of 40% above the May 1, 2003 closing common stock market price of $16.85 per share. The senior notes outstanding as of December 31, 2005 are potentially convertible into approximately 31.4 million shares of common stock which are included as outstanding shares in the diluted EPS calculation (see Note 19). The conversion of these senior notes into shares of Duke Energy common stock is contingent upon the occurrence of certain events during specified periods. These events include whether the price of Duke Energy common stock reaches specified thresholds, the credit rating of Duke Energy falls below certain thresholds, the convertible notes are called for redemption by Duke Energy, or specified transactions have occurred. In addition to the aforementioned events that could trigger early redemption, holders of the senior notes may require Duke Energy to purchase all or a portion of their senior notes for

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

cash on May 15, 2007, May 15, 2012, and May 15, 2017, at a price equal to the principal amount of the senior notes plus accrued interest, if any. Duke Energy may redeem for cash all or a portion of the senior notes at any time on or after May 20, 2007, at a price equal to the sum of the issue price plus accrued interest, if any, on the redemption date. During 2005, these convertible senior notes became convertible into shares of Duke Energy common stock due to the market price of Duke Energy common stock. Holders of the convertible senior notes were allowed to exercise their right to convert on or prior to December 31, 2005. During 2005, approximately 1.2 million shares of common stock were issued related to this conversion, which resulted in the retirement of approximately $28 million of convertible senior notes.

Secured Debt. Accounts Receivable Securitization. During 2003, Duke Energy completed a securitization of certain accounts receivable through Duke Energy Receivables Finance Company, LLC (DERF), a newly formed, bankruptcy remote, special purpose subsidiary. DERF is a wholly owned limited liability company with a separate legal existence from its parent, and its assets are not intended to be generally available to creditors of Duke Energy. As a result of the securitization, Duke Energy sold, and will continue to sell on a daily basis to DERF, certain accounts receivable arising from the sale of electricity and/or related services as part of Duke Energy’s franchised electric business. The proceeds from the initial sale of the accounts receivable to DERF were used for general corporate purposes in its franchised electric business, which included the repayment of outstanding commercial paper. In order to fund its purchases of accounts receivable, DERF entered into a two-year $300 million secured credit facility, with a commercial paper conduit administered by Citicorp North America, Inc. The credit facility has been subsequently amended to terminate in September 2007. The credit facility and related securitization documentation contain several covenants, including covenants with respect to the accounts receivable held by DERF as well as a covenant requiring that the ratio of Duke Energy consolidated indebtedness to Duke Energy consolidated capitalization not exceed 65%. As of December 31, 2005, the interest rate associated with the credit facility, which is based on commercial paper rates, was 4.8% and $300 million was outstanding under the credit facility. The securitization transaction was not structured to meet the criteria for sale treatment under SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” and accordingly is reflected as a secured borrowing in the Consolidated Financial Statements. As of December 31, 2005 and 2004, the $300 million outstanding balance of the credit facility was secured by approximately $489 million and $447 million, respectively, of accounts receivable held by DERF. The obligations of DERF under the credit facility are non-recourse to Duke Energy.

In December 2004, Duke Energy reached an agreement to sell its partially completed Grays Harbor power generation facility to an affiliate of Invenergy LLC. In 2004, Duke Energy also terminated its capital lease with the dedicated pipeline which would have transported natural gas to Grays Harbor. As a result of this termination, approximately $94 million was paid by Duke Energy in January 2005.

Other Assets Pledged as Collateral. As of December 31, 2005, secured debt also consisted of various project financings, including Maritimes & Northeast Pipeline, LLC, Maritimes & Northeast Pipeline, LP (collectively, M&N Pipeline) and certain projects at Crescent. A portion of the assets, ownership interest and business contracts in these various projects are pledged as collateral. Additionally, as of December 31, 2005, substantially all of Franchised Electric’s electric plant in service was subject to a mortgage lien securing the first and refunding mortgage bonds.

Floating Rate Debt. Unsecured debt, secured debt and other debt included approximately $1.7 billion of floating-rate debt as of December 31, 2005, and $1.5 billion as of December 31, 2004. As of December 31, 2005 and 2004, $488 million and $462 million of Brazilian debt that is indexed annually to Brazilian inflation was included in floating rate debt. Floating-rate debt is primarily based on commercial paper rates or a spread relative to an index such as a London Interbank Offered Rate for debt denominated in U.S. dollars, and Banker’s Acceptances for debt denominated in Canadian dollars. As of December 31, 2005, the average interest rate associated with floating-rate debt was 6.4%.

Related Party Debt. Other debt included $4 million related to a loan with D/FD as of December 31, 2005, and $17 million as of December 31, 2004. As part of the D/FD partnership agreement, excess cash has been loaned, without stated repayment terms, at current market rates to Duke Energy and Fluor Enterprises, Inc. The weighted-average rate of this loan was 3.47% as of December 31, 2005 and 1.98% as of December 31, 2004. D/FD is a 50/50 partnership between subsidiaries of Duke Energy and Fluor. During 2003, Duke Energy and Fluor announced that they would dissolve D/FD and adopted a plan for an orderly wind-down of D/FD’s business. The wind-down has been substantially completed as of December 31, 2005 and is expected to be finalized by December 2006. The entire outstanding balance of the loan with D/FD has been classified as Current Maturities of Long-term Debt on the December 31, 2005 and 2004 Consolidated Balance Sheets.

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Maturities, Call Options and Acceleration Clauses.

Annual Maturities as of December 31, 2005

	(in millions)
2006	$	1,400
2007		1,054
2008		1,245
2009		1,300
2010		1,386
Thereafter		9,562
Total long-term debt(a)	$	15,947

(a) Excludes short-term notes payable and commercial paper of $83 million.

Annual maturities after 2010 include $361 million of long-term debt with call options, which provide Duke Energy with the option to potentially repay the debt early. Based on the years in which Duke Energy may first exercise its redemption options, it could potentially repay $250 million in 2006 and $111 million in 2007.

Duke Energy may be required to repay certain debt should its credit ratings fall to a certain level at Standard & Poor’s (S&P) or Moody’s Investor Service (Moody’s). As of December 31, 2005, Duke Energy had $15 million of senior unsecured notes which mature serially through 2012 that may be required to be repaid if Duke Energy’s senior unsecured debt ratings fall below BBB- at S&P or Baa3 at Moody’s, and $26 million of senior unsecured notes which mature serially through 2016 that may be required to be repaid if Duke Energy’s senior unsecured debt ratings fall below BBB at S&P or Baa2 at Moody’s. As of February 28, 2006, Duke Energy’s senior unsecured credit rating was BBB at S&P and Baa1 at Moody’s.

Available Credit Facilities and Restrictive Debt Covenants. During the year ended December 31, 2005, Duke Energy’s consolidated credit capacity increased by approximately $425 million compared to December 31, 2004. Duke Energy renewed an expiring $150 million bi-lateral credit facility for an additional 364-day period. Duke Capital, a wholly owned subsidiary of Duke Energy, added two new $100 million, 364-day bi-lateral credit facilities to provide additional letter of credit issuing capacity and at renewal increased its expiring 364-day letter of credit facility by $200 million. In addition, Duke Capital added three new 364-day credit facilities totaling $260 million to provide additional credit support. Westcoast and Union Gas renewed and replaced their credit facilities at existing levels. Duke Energy and Duke Capital amended their respective multi-year syndicated facilities to extend the expiration dates. The credit facilities of DEFS ($250 million at December 31, 2004) are no longer included in Duke Energy’s consolidated available credit facilities due to the deconsolidation of Duke Energy’s investment in DEFS in July 2005 (see Note 2). In February 2006, Duke Capital cancelled the $100 million 364-day bi-lateral credit facility and the $100 million one year bi-lateral credit facility.

The issuance of commercial paper, letters of credit and other borrowings reduces the amount available under the available credit facilities.

Duke Energy’s credit agreements contain various financial and other covenants. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements. As of December 31, 2005, Duke Energy was in compliance with those covenants. In addition, some credit agreements may allow for acceleration of payments or termination of the agreements due to nonpayment, or to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the debt or credit agreements contain material adverse change clauses.

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Credit Facilities Summary as of December 31, 2005 (in millions)

		Amounts Outstanding
	Expiration Date	Credit Facilities Capacity		Commercial Paper		Letters of Credit		Total
Duke Energy
$500 multi-year syndicated(a), (b)	June 2010
$150 364-day bi-lateral(a), (b)	September 2006
Total Duke Energy		$	650	$	300	$	—	$	300
Duke Capital LLC
$800 364-day syndicated(a), (b)	June 2006
$600 multi-year syndicated(a), (b)	June 2009
$130 three-year bi-lateral(b)	October 2007
$120 multi-year bi-lateral(b)	July 2009
$100 one-year bi-lateral(b)	June 2006
$260 364-day bi-lateral(a), (b)	June 2006
$100 364-day bi-lateral(b)	October 2006
Total Duke Capital LLC			2,110		—		857		857
Westcoast Energy Inc.
$86 364-day syndicated (b), (c)	June 2006
$172 multi-year syndicated (b), (d)	June 2010
Total Westcoast Energy Inc.			258		—		—		—
Union Gas
$258 364-day syndicated(e), (f)	June 2006		258		83		—		83
Total		$	3,276	$	383	$	857	$	1,240

(a) Credit facility contains an option allowing borrowing up to the full amount of the facility on the day of initial expiration for up to one year.

(b) Credit facility contains a covenant requiring the debt-to-total capitalization ratio to not exceed 65%.

(c) Credit facility is denominated in Canadian dollars totaling 100 million Canadian dollars.

(d) Credit facility is denominated in Canadian dollars totaling 200 million Canadian dollars.

(e) Credit facility contains a covenant requiring the debt-to-total capitalization ratio to not exceed 75%. Credit facility is denominated in Canadian dollars totaling 300 million Canadian dollars.

(f) Credit facility contains an option at maturity allowing for the conversion of all outstanding loans to a term loan repayable up to one year after maturity date but not exceeding 18 months from the date of draw.

Duke Energy has approximately $1,750 million of credit facilities which expire in 2006. It is Duke Energy’s intent to resyndicate less than the total amount of expiring credit facilities.

Other Loans. During 2005 and 2004, Duke Energy had loans outstanding against the cash surrender value of the life insurance policies that it owns on the lives of its executives. The amounts outstanding were $552 million as of December 31, 2005 and $508 million as of December 31, 2004. The amounts outstanding were carried as a reduction of the related cash surrender value that is included in Other Assets on the Consolidated Balance Sheets.

16. Preferred and Preference Stock at Duke Energy

Authorized Shares of Duke Energy Preferred and Preference Stock as of December 31, 2005 and 2004

	Par Value		Shares
			(in millions)
Preferred Stock	$	100	12.5
Preferred Stock A	$	25	10.0
Preference Stock	$	100	1.5

As of December 31, 2005 and 2004, there were no shares of preference stock outstanding at Duke Energy.

Preferred Stock without Sinking Fund Requirements. The following table details Preferred Stock without Sinking Fund Requirements, which are not mandatorily redeemable financial instruments under the provisions of SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” (SFAS No. 150), as of December 31, 2005 and 2004.

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For the Years Ended December 31, 2005, 2004 and 2003

Preferred Stock without Sinking Fund Requirements

		Shares Issued and Outstanding at December 31, 2005	December 31,
Rate/Series	Year Issued		2005		2004
			(dollars in millions)
4.50% C	1964	—	$	—	$	18
7.85% S	1992	—		—		30
7.00% W	1993	—		—		25
7.04% Y	1993	—		—		30
6.375% (Preferred Stock A)	1993	—		—		31
Total			$	—	$	134

In December 2005, Duke Energy redeemed all Preferred and Preference stock without Sinking Fund Requirements for approximately $137 million and recognized an immaterial loss on the redemption.

Preferred and Preference Stock of Duke Energy’s Subsidiaries. In connection with the Westcoast acquisition in 2002, Duke Energy assumed approximately $411 million of authorized and issued redeemable preferred and preference shares at Westcoast and Union Gas. These preferred and preference shares at Westcoast and Union Gas totaled $225 million at both December 31, 2005 and 2004. Since these preferred and preference shares are redeemable at the option of holder, as well as Westcoast and Union Gas, these preferred and preference shares do not meet the definition of a mandatorily redeemable instrument under SFAS No. 150. As such, these preferred and preference shares are considered contingently redeemable shares and are included in Minority Interests on the Consolidated Balance Sheets.

17. Commitments and Contingencies

General Insurance

Duke Energy carries, through its captive insurance company, Bison, and its affiliates, insurance and reinsurance coverages consistent with companies engaged in similar commercial operations with similar type properties. Duke Energy’s insurance coverage includes (1) commercial general public liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from Duke Energy’s operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage; (4) financial services insurance policies in support of the indemnification provisions of the company’s by-laws and (5) property insurance covering the replacement value of all real and personal property damage, excluding electric transmission and distribution lines, including damages arising from boiler and machinery breakdowns, earthquake, flood damage and business interruption/extra expense. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operations.

Bison is a member of Oil Insurance Limited (OIL) and sEnergy Insurance Limited (sEnergy), which provides property and business interruption reinsurance coverage respectively for Duke Energy’s non-nuclear facilities, and accounts for its membership under the cost method, as Duke Energy does not have the ability to exert significant influence. Should Bison terminate its membership in either OIL, sEnergy or both, it could be liable for additional premium assessments. Bison continues to be a member of OIL and sEnergy in 2006 and purchases coverages provided by both companies.

Duke Energy also maintains excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Limits, terms, conditions and deductibles are comparable to those carried by other energy companies of similar size.

The cost of Duke Energy’s general insurance coverages continued to fluctuate over the past year reflecting the changing conditions of the insurance markets.

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Nuclear Insurance

Duke Energy owns and operates the McGuire and Oconee Nuclear Stations and operates and has a partial ownership interest in the Catawba Nuclear Station. The McGuire and Catawba Nuclear Stations 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.

Primary Liability Insurance. Duke Energy has purchased the maximum available private primary liability insurance as required by law. As of January 1, 2003, the maximum amount of available private primary insurance increased from $200 million to $300 million and Duke Energy increased coverages on both nuclear liability and certain worker tort claim insurance to $300 million.

Excess Liability Insurance. This policy currently provides approximately $10.5 billion of coverage through the Price-Anderson Act’s mandatory industry-wide excess secondary insurance program of risk pooling. The $10.5 billion is the sum of the current potential cumulative retrospective premium assessments of $101 million per licensed commercial nuclear reactor. This would be increased by $101 million for each additional commercial nuclear reactor licensed, or reduced by $101 million for nuclear reactors no longer operational and may be exempted from the risk pooling insurance program. Under this program, licensees could be assessed retrospective premiums to compensate for damages in the event of a nuclear incident at any licensed facility in the U.S. If such an incident should occur and public liability damages exceed primary insurances, licensees may be assessed up to $101 million for each of their licensed reactors, payable at a rate not to exceed $15 million a year per licensed reactor for each incident. The $101 million is subject to indexing for inflation and may be subject to state premium taxes.

Duke Energy is a member of Nuclear Electric Insurance Limited (NEIL), which provides property and business interruption insurance coverage for Duke Energy’s nuclear facilities under three policy programs:

Primary Property Insurance. This policy provides $500 million of primary property damage coverage for each of Duke Energy’s nuclear facilities.

Excess Property Insurance. This policy provides excess property, decontamination and decommissioning liability insurance: $2.25 billion for the Catawba Nuclear Station and $2.0 billion each for the Oconee and McGuire Nuclear Stations.

Business Interruption Insurance. This policy provides business interruption and/or extra expense coverage resulting from an accidental outage of a nuclear unit. Each McGuire and Catawba unit is insured for up to $3.5 million per week, and the Oconee units are insured for up to $2.8 million per week. Coverage amounts decline if more than one unit is involved in an accidental outage. Initial coverage begins after a 12-week deductible period and continues at 100% for 52 weeks and 80% for the next 110 weeks.

If NEIL’s losses exceed its reserves for any of the above three programs, Duke Energy is liable for assessments of up to 10 times its annual premiums. The current potential maximum assessments are: Primary Property Insurance—$38 million, Excess Property Insurance—$44 million and Business Interruption Insurance—$29 million.

The other joint owners of the Catawba Nuclear Station are obligated to assume their pro rata share of liability for retrospective premiums and other premium assessments resulting from the Price-Anderson Act’s excess secondary insurance program of risk pooling, or the NEIL policies.

Environmental

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

Remediation activities. Like others in the energy industry, Duke Energy and its affiliates are responsible for environmental remediation at various contaminated sites. These include some properties that are part of ongoing Duke Energy operations, sites formerly owned or used by Duke Energy entities, and sites owned by third parties. Remediation typically involves management of contaminated soils and may involve groundwater remediation. Managed in conjunction with relevant federal, state and local agencies, activities vary with site conditions and locations, remedial requirements, complexity and sharing of responsibility. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, Duke Energy or its affiliates

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could potentially be held responsible for contamination caused by other parties. In some instances, Duke Energy may share liability associated with contamination with other potentially responsible parties, and may also benefit from insurance policies or contractual indemnities that cover some or all cleanup costs. All of these sites generally are managed in the normal course of business or affiliate operations. Management believes that completion or resolution of these matters will have no material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position.

Clean Water Act. The U. S. Environmental Protection Agency’s (EPA’s) final Clean Water Act Section 316(b) rule became effective July 9, 2004. The rule establishes aquatic protection requirements for existing facilities that withdraw 50 million gallons or more of water per day from rivers, streams, lakes, reservoirs, estuaries, oceans, or other U.S. waters for cooling purposes. Eight of Duke Energy’s eleven coal and nuclear-fueled generating facilities in North Carolina and South Carolina, and its three natural gas-fired generating facilities in California are affected sources under the rule. The three California facilities are part of the DENA business and are expected to be divested by the second quarter of 2006 as part of the transaction announced in January 2006 (see Note 13). The rule requires a Comprehensive Demonstration Study (CDS) for each affected facility to provide information needed to determine necessary facility-specific modifications and cost estimates for implementation. These studies will be completed over the next three to five years. Once compliance measures are determined and approved by regulators, a facility will typically have five or more years to implement the measures. Due to the wide range of measures potentially applicable to a given facility, and since the final selection of compliance measures will be at least partially dependent upon the CDS information, Duke Energy is not able to estimate its cost for complying with the rule at this time.

Clean Air Mercury Rule. The EPA’s final Clean Air Mercury Rule (CAMR) was published in the Federal Register May 18, 2005. The rule limits total annual mercury emissions from coal-fired power plants across the United States through a two-phased cap-and-trade program. Phase 1 begins in 2010 and Phase 2 begins in 2018. The rule gives states the option of participating in the national trading program. If a state chooses not to participate, then the rule sets a fixed limit on that state’s annual emissions. The emission controls Duke Energy is installing to comply with North Carolina clean air legislation will contribute significantly to achieving compliance with the CAMR requirements. Duke Energy currently estimates that the additional cost of complying with Phase 1 of the CAMR will have no material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position, and is currently unable to estimate the cost of complying with Phase 2 of the CAMR.

Clean Air Interstate Rule. The EPA’s final Clean Air Interstate Rule (CAIR) was published in the Federal Register May 12, 2005. The rule limits total annual SO₂ and NOx emissions from electric generating facilities across the Eastern United States through a two-phased cap-and-trade program. Phase 1 begins in 2009 for NOx and in 2010 for SO₂. Phase 2 begins in 2015 for both NOx and SO₂. The rule gives states the option of participating in the national trading program. If a state chooses not to participate, then the rule sets a fixed limit on that state’s annual emissions. The emission controls Duke Energy is installing to comply with North Carolina clean air legislation will contribute significantly to achieving compliance with the CAIR requirements. Duke Energy currently estimates that the additional cost of complying with Phase 1 of the CAIR will have no material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position, and is currently unable to estimate the cost of complying with Phase 2 of the CAIR. On July 11, 2005, Duke Energy and others filed petitions with the U.S. Court of Appeals for the District of Columbia Circuit requesting the Court to review certain elements of the EPA’s CAIR. Duke Energy is seeking to have the EPA revise the method of allocating SO₂ emission allowances to entities under the rule.

Extended Environmental Activities, Accruals. Included in Other Current Liabilities and Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets were total accruals related to extended environmental-related activities of approximately $55 million as of December 31, 2005 and $83 million as of December 31, 2004. These accruals represent Duke Energy’s provisions for costs associated with remediation activities at some of its current and former sites, as well as other relevant environmental contingent liabilities. Management believes that completion or resolution of these matters will have no material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position.

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For the Years Ended December 31, 2005, 2004 and 2003

Litigation

New Source Review (NSR)/EPA Litigation. In 2000, the U.S. Justice Department, acting on behalf of the EPA, filed a complaint against Duke Energy in the U.S. District Court in Greensboro, North Carolina, for alleged violations of the Clean Air Act (CAA). The EPA claims that 29 projects performed at 25 of Duke Energy’s coal-fired units were major modifications, as defined in the CAA, and that Duke Energy violated the CAA when it undertook those projects without obtaining permits and installing emission controls for SO₂, NOx and particulate matter. The complaint asks the Court to order Duke Energy to stop operating the coal-fired units identified in the complaint, install additional emission controls and pay unspecified civil penalties.

Duke Energy asserts that there were no CAA violations because the applicable regulations do not require permitting in cases where the projects undertaken are “routine” or otherwise do not result in a net increase in emissions. In August 2003, the trial Court issued a summary judgment opinion adopting Duke Energy’s legal positions, and on April 15, 2004, the Court entered Final Judgment in favor of Duke Energy. The government appealed the case to the U.S. Fourth Circuit Court of Appeals. On June 15, 2005, the Fourth Circuit ruled in favor of Duke Energy and effectively adopted Duke Energy’s view that permitting of projects is not required unless the work performed implicates a net increase in the hourly rate of emissions. The EPA filed a request for rehearing with the Fourth Circuit, which was denied. The EPA decided not to petition the U.S. Supreme Court to hear an appeal of the matter. Some environmental groups who intervened in the early stages in the case have filed their own appeal. The Supreme Court has not yet determined whether it would hear the matter. Based on the current rulings, Duke Energy does not believe the outcome of this matter will have a material adverse effect on its consolidated results of operations, cash flows or financial position.

Western Energy Litigation and Regulatory Matters. Since 2000, plaintiffs have filed 50 lawsuits in four Western states against Duke Energy affiliates, current and former Duke Energy executives, and other energy companies. Most of the suits seek class-action certification on behalf of electricity and/or natural gas purchasers. The plaintiffs allege that the defendants manipulated the electricity and/or natural gas markets in violation of state and/or federal antitrust, unfair business practices and other laws. Plaintiffs in some of the cases further allege that such activities, including engaging in “round trip” trades, providing false information to natural gas trade publications and unlawfully exchanging information, resulted in artificially high energy prices. Plaintiffs seek aggregate damages or restitution of billions of dollars from the defendants.

• To date, one suit has been voluntarily dismissed by plaintiffs. Fourteen suits have been dismissed on filed rate and/or federal preemption grounds. The plaintiffs in these dismissed suits have appealed or are expected to appeal, and the U.S. Ninth Circuit Court of Appeals has affirmed the dismissals of eight of these lawsuits. The plaintiff in one of the dismissed actions affirmed by the Ninth Circuit petitioned the U.S. Supreme Court for certiorari, and, on June 27, 2005, the U.S. Supreme Court denied certiorari.

• In July 2004, Duke Energy reached an agreement in principle resolving class-action litigation involving the purchase of electricity filed on behalf of ratepayers and other electricity consumers in California, Washington, Oregon, Utah and Idaho. This agreement is part of a more comprehensive settlement involving FERC refunds and other proceedings related to the Western energy markets during 2000-2001 (the California Settlement). The California Settlement resolved issues that arose under several investigations and regulatory proceedings at the state and federal levels involving Duke Energy, along with other energy suppliers and producers, that looked into the causes of high wholesale electricity prices in the Western United States during 2000 and 2001. FERC approved all provisions of the California Settlement (except for the class action portion which was subject to court approval) in December 2004. In December 2004, Duke Energy tendered all of the settlement proceeds except for $7 million relating to the class-action settlement. On December 14, 2005, the court issued an order giving final approval to the settlement of these class action lawsuits with respect to Duke Energy, and these remaining funds were paid in 2005.

• Suits filed on behalf of electricity ratepayers in other Western states, on behalf of entities that purchased electricity directly from a generator and on behalf of natural gas purchasers, remain pending. It is not possible to predict with certainty whether Duke Energy will incur any liability or to estimate the damages, if any, that Duke Energy might incur in connection with these lawsuits, but Duke Energy does not presently believe the outcome of these matters will have a material adverse effect on its consolidated results of operations, cash flows or financial position.

In 2002, Southern California Edison Company (SCE) initiated arbitration proceedings regarding disputes with DETM relating to amounts owed in connection with the termination of bi-lateral power contracts between the parties in early 2001. SCE disputes DETM’s termination calculation and seeks in excess of $86 million plus interest. This matter proceeded to hearing in November 2005. In January

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2006, the parties reached an agreement in principle to resolve the matters at issue in the arbitration. The agreement will require regulatory approval. Based on the level of damages claimed by the plaintiff, Duke Energy’s assessment of possible outcomes in this matter, and the referenced agreement in principle, Duke Energy does not expect that the resolution of this matter will have a material adverse effect on its consolidated results of operations, cash flows or financial position.

Trading Related Litigation. By letter dated April 16, 2004, Duke Energy received notice that a shareholder reactivated a litigation demand sent to Duke Energy in 2002. Arising out of the same “round trip” trades issues raised in the shareholder lawsuits dismissed by the courts in 2003 and affirmed on appeal, the notice stated that the shareholder intended to initiate derivative shareholder litigation within 90 days from the date of the letter if Duke Energy did not initiate litigation within the stated timeframe. Duke Energy’s Board of Directors appointed a special committee to review the demand. The committee determined that there are no grounds supporting the allegations made in the derivative demand to commence or maintain an action on behalf of Duke Energy against the individuals named in the derivative demand, and that, accordingly, it would not be in the best interests of Duke Energy to bring such claims. By letter dated January 21, 2005, another shareholder reactivated a 2002 litigation demand. The reactivated demand arises out of the same issues that were raised in the April 16 reactivated demand as well as matters that were the subject of the California Settlement. On March 16, 2005, the special committee determined that there are no grounds supporting the allegations made in the derivative demand to commence or maintain an action on behalf of Duke Energy against the individuals named in the derivative demand, and that, accordingly, it would not be in the best interests of Duke Energy to bring such claims.

Commencing August 2003, plaintiffs filed three class-action lawsuits in the U.S. District Court for the Southern District of New York on behalf of entities who bought and sold natural gas futures and options contracts on the New York Mercantile Exchange during the years 2000 through 2002. DETM, along with numerous other entities, is named as a defendant. The plaintiffs claim that the defendants violated the Commodity Exchange Act by reporting false and misleading trading information to trade publications, resulting in monetary losses to the plaintiffs. Plaintiffs seek class action certification, unspecified damages and other relief. On September 24, 2004, the court denied a motion to dismiss the plaintiffs’ claims filed on behalf of DETM and other defendants, and on September 30, 2005, the court certified the class. Duke Energy has reached an agreement with the plaintiffs in these consolidated cases to resolve all issues and on February 8, 2006, the court granted preliminary approval of this settlement. The agreement is subject to final court approval after notification to all class members. Duke Energy does not expect that the resolution of this matter will have a material adverse effect on its consolidated results of operations, cash flows or financial position.

On January 28, 2005, four plaintiffs filed suit in Tennessee Chancery Court against Duke Energy affiliates and other energy companies seeking class action certification on behalf of indirect purchasers of natural gas who allege that they have been harmed by defendants’ manipulation of the natural gas markets by various means, including providing false information to natural gas trade publications and unlawfully exchanging information, resulting in artificially high natural gas prices paid by plaintiffs in the State of Tennessee. Alleging that defendants violated state antitrust laws and other laws, plaintiffs seek unspecified damages and other relief. Defendants removed this case to the United States District Court for the Western District of Tennessee in March 2005, and the case was transferred to a federal judge in Nevada in Multidistrict Litigation (MDL) proceeding 1566. Plaintiffs filed a motion to remand the case to state court, and the defendants filed motions to dismiss the complaint on various grounds, including the filed rate doctrine and federal preemption. The court has yet to rule on these motions. Duke Energy is unable to express an opinion regarding the probable outcome of these matters at this time.

On August 8, 2005, a plaintiff filed a lawsuit in state court in Kansas against Duke Energy and DETM, as well as other energy companies, claiming that the plaintiff was harmed by the defendants’ alleged manipulation of the natural gas markets by various means, including providing false information to natural gas trade publications and entering into unlawful arrangements and agreements. Duke Energy removed this case to the United States District Court for the District of Kansas on September 8, 2005, and the case was subsequently transferred to a federal judge in the MDL 1566 proceeding. On September 26, 2005, a class action petition was filed by two plaintiffs in state court in Kansas against various defendants including Duke Energy and DETM, based on substantially similar allegations. This matter also was moved to federal court, and defendants are seeking to have the case transferred to the MDL 1566 proceeding. Plaintiffs have filed a motion to remand the case to state court. The plaintiffs in the foregoing cases claim the defendants violated Kansas’ antitrust laws and seek damages in unspecified amounts. Duke Energy is unable to express an opinion regarding the probable outcome of these matters at this time.

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For the Years Ended December 31, 2005, 2004 and 2003

Trading Related Investigations. In 2002 and 2003, Duke Energy responded to information requests and subpoenas from the Securities and Exchange Commission (SEC) and to grand jury subpoenas issued by the U.S. Attorney’s office in Houston, Texas. The information requests and subpoenas sought documents and information related to trading activities, including so-called “round-trip” trading. Duke Energy received notice in 2002 that the SEC formalized its trading-related investigation. In July 2005 the SEC approved Duke Energy’s offer of settlement to resolve the issues that were the subject of the SEC’s investigation regarding conduct that occurred in 2000 through June 2002. The terms of the settlement included the issuance of an order to Duke Energy to cease and desist from violating internal controls and books and records requirements under Sections 13(b)(2)(A) and 13(b)(2)(B) of the Securities Exchange Act of 1934, but did not include a penalty or finding of fraud. Prior to 2005, Duke Energy took actions to remediate the issues that were raised in the SEC’s investigation regarding internal controls.

In April 2004, the Houston-based federal grand jury issued indictments for three former employees of DETMI Management Inc. (DETMI), which is one of two members of DETM. The indictments state that the employees “did knowingly devise, intend to devise, and participate in a scheme to defraud and to obtain money and property from Duke Energy by means of materially false and fraudulent pretenses, representations and promises, and material omissions, and to deprive Duke Energy and its shareholders of the intangible right to the honest services of employees of Duke Energy.” They further state that the alleged conduct was purportedly motivated, in part, by a desire to increase individual bonuses. Statements made by the U.S. Attorney’s office characterized Duke Energy as a victim in this activity and commended Duke Energy for its cooperation with the investigation. The alleged conduct was identified in the spring and summer of 2002 and was related to DETM’s Eastern Region trading activities. In 2002, Duke Energy recorded the appropriate financial adjustments associated with the cited activities, and did not consider the financial effect to be material. In February 2005, one of the three indicted former DETMI employees pled guilty to a “books and records” violation, and a superseding indictment was filed against the other two former employees, providing more detail and adding an allegation that the former employees intentionally circumvented internal accounting controls. After trial of the two remaining former DETMI employees in the fall of 2005, one was acquitted of all charges and the other was acquitted of seven out of nineteen charges. The trial judge declared a mistrial on the remaining counts and subsequently granted the U.S. Attorney’s request to dismiss the remaining counts against the former employee. In addition, the former employee who pled guilty to a “books and records” violation was permitted to withdraw his guilty plea.

Beginning in February 2004, Duke Energy has received requests for information from the U.S. Attorney’s office in Houston focused on the natural gas price reporting activities of certain individuals involved in DETM trading operations. Duke Energy has cooperated with the government in this investigation and is unable to express an opinion regarding the probable outcome at this time.

In February 2005, the Commodity Futures Trading Commission initiated a civil action against a former DETM trader asserting charges of delivering false reports and attempted manipulation of prices through index price reporting. Duke Energy is not named in this action.

Sonatrach/Sonatrading Arbitration. Duke Energy LNG Sales Inc. (Duke LNG) claims in an arbitration commenced in January 2001 in London that Sonatrach, the Algerian state-owned energy company, together with its subsidiary, Sonatrading Amsterdam B.V. (Sonatrading), breached their shipping obligations under a liquefied natural gas (LNG) purchase agreement and related transportation agreements (the LNG Agreements) relating to Duke LNG’s purchase of LNG from Algeria and its transportation by LNG tanker to Lake Charles, Louisiana. Duke LNG seeks damages of approximately $27 million. Sonatrading and Sonatrach counter claim that Duke LNG repudiated the LNG Agreements by allegedly failing to diligently perform LNG marketing obligations. Sonatrading and Sonatrach seek damages in the amount of approximately $250 million. In 2003, an arbitration tribunal issued a Partial Award on liability issues, finding that Sonatrach and Sonatrading breached their obligations to provide shipping. The tribunal also found that Duke LNG breached the LNG Purchase Agreement by failing to perform marketing obligations. The hearing on damages issues commenced in September 2005 and will continue through the first quarter of 2006.

Citrus Trading Corporation (Citrus) Litigation. In conjunction with the Sonatrach LNG Agreements, Duke LNG entered into a natural gas purchase contract (the Citrus Agreement) with Citrus. Citrus filed a lawsuit in March 2003 in the U.S. District Court for the Southern District of Texas against Duke LNG and PanEnergy Corp alleging that Duke LNG breached the Citrus Agreement by failing to provide sufficient volumes of gas to Citrus. Duke LNG contends that Sonatrach caused Duke LNG to experience a loss of LNG supply that affected Duke LNG’s obligations and termination rights under the Citrus Agreement. Citrus seeks monetary damages and a judicial determination that Duke LNG did not experience such a loss. After Citrus filed its lawsuit, Duke LNG terminated the Citrus Agreement and filed a counterclaim asserting that Citrus had breached the agreement by, among other things, failing to provide sufficient security under a letter

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of credit for the gas transactions. Citrus denies that Duke LNG had the right to terminate the agreement and contends that Duke LNG’s termination of the agreement was itself a breach, entitling Citrus to terminate the agreement and recover damages in the amount of approximately $187 million. The parties filed cross motions for partial summary judgment regarding the letter of credit issue which were subsequently denied by the Court. Other motions for partial summary judgment remain pending. No trial date has been set. It is not possible to predict with certainty whether Duke Energy will incur any liability or to estimate the damages, if any, that Duke Energy might incur in connection with the Sonatrach and Citrus matters.

Exxon Mobil Disputes. In April 2004, Mobil Natural Gas, Inc. (MNGI) and 3946231 Canada, Inc. (3946231, and collectively with MNGI, Exxon Mobil) filed a Demand for Arbitration against Duke Energy, DETMI, DTMSI Management Ltd. (DTMSI) and other affiliates of Duke Energy. MNGI and DETMI are the sole members of DETM. DTMSI and 3946231 are the sole beneficial owners of Duke Energy Marketing Limited Partnership (DEMLP, and with DETM, the Ventures). Among other allegations, Exxon Mobil alleges that DETMI and DTMSI engaged in wrongful actions relating to affiliate trading, payment of service fees, expense allocations and distribution of earnings in breach of agreements and fiduciary duties relating to the Ventures. Exxon Mobil seeks to recover actual damages, plus attorneys’ fees and exemplary damages; aggregate damages were not specified in the arbitration demand. Duke Energy denies these allegations, and has filed counterclaims asserting that Exxon Mobil breached its Ventures obligations and other contractual obligations. By order dated May 2, 2005, the arbitrators granted Duke Energy’s Motion for Partial Summary Judgment, effectively eliminating a significant portion of Exxon Mobil’s claims. Exxon Mobil filed a motion for reconsideration of the ruling as well as for an extension of the date for the arbitration hearing. Exxon Mobil also filed a motion to dismiss certain of Duke Energy’s counterclaims. Following a hearing in December 2005 on the motion for reconsideration, the arbitrators issued their ruling on January 26, 2006, generally reaffirming the original order, with a limited exception with respect to affiliate trades that is not expected to have a significant impact on the case. The panel also dismissed one of Duke Energy’s counterclaims. In response to a request from Exxon Mobil, the arbitration panel has postponed the commencement date of the arbitration hearing from January 2006 to October 2006 in Houston, Texas. On February 28, 2006, Duke Energy filed an expert report in support of its claims. On the same date, Exxon Mobil also filed a Second Amended Statement of Claim and various expert reports in support of its claims. Duke Energy is evaluating Exxon Mobil’s filings and expects to respond by August 2006. In August 2004, DEMLP initiated arbitration proceedings in Canada against certain Exxon Mobil entities asserting that those entities wrongfully terminated two gas supply agreements with the Ventures and wrongfully failed to assume certain related gas supply agreements with other parties. A hearing in the Canadian arbitration, originally scheduled to commence in August 2005 in Calgary, Canada, has been rescheduled for March 2006. It is not possible to predict with certainty the damages that might be incurred by Duke Energy or any of its affiliates as a result of these matters.

Duke Energy Retirement Cash Balance Plan. A class action lawsuit has been filed in federal court in South Carolina against Duke Energy and the Duke Energy Retirement Cash Balance Plan, alleging violations of Employee Retirement Income Security Act (“ERISA”) and the Age Discrimination in Employment Act. These allegations arise out of the conversion of the Duke Energy Carolinas Company Employees’ Retirement Plan into the Duke Energy Carolinas Company Retirement Cash Balance Plan. The case also raises some Plan administration issues, alleging errors in the application of Plan provisions (e.g., the calculation of interest rate credits in 1997 and 1998 and the calculation of lump-sum distributions). The plaintiffs seek to represent present and former participants in the Duke Energy Retirement Cash Balance Plan. This group is estimated to include approximately 36,000 persons. The plaintiffs also seek to divide the putative class into sub-classes based on age. Six causes of action are alleged, ranging from age discrimination, to various alleged ERISA violations, to allegations of breach of fiduciary duty. The plaintiffs seek a broad array of remedies, including a retroactive reformation of the Duke Energy Retirement Cash Balance Plan and a recalculation of participants’/ beneficiaries’ benefits under the revised and reformed plan. Duke Energy is currently assessing its response and strategy. It is not possible to predict with certainty whether Duke Energy will incur any liability or to estimate the damages, if any, that Duke Energy might incur in connection with this matter.

Asbestos-related Injuries and Damages Claims. 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 Energy Carolinas 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. The insurance policy, including the policy deductible and reserves, provided for coverage to Duke Energy up to an aggregate of $1.6 billion when purchased in 2000. Probable insurance recoveries related to this policy are classified in the Consolidated Balance Sheets as Other within Investments and Other Assets. Amounts recognized as reserves in the Consolidated Balance Sheets, which are not anticipated to exceed the coverage,

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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.

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

Duke Energy has exposure to certain legal matters that are described herein. As of December 31, 2005, Duke Energy has recorded reserves of approximately $1.4 billion for these proceedings and exposures. Duke Energy has insurance coverage for certain of these losses incurred. As of December 31, 2005, Duke Energy has recognized approximately $1.0 billion of probable insurance recoveries related to these losses. These reserves represent management’s best estimate of probable loss as defined by SFAS No. 5.

Duke Energy expenses legal costs related to the defense of loss contingencies as incurred.

Other Commitments and Contingencies

Hurricane Damage. Duke Energy continues to assess and monitor damage assessments related to Hurricanes Katrina and Rita in the Gulf Coast in 2005. Duke Energy has recorded all losses known to date, and is currently not aware of any additional damages incurred which will have a material adverse impact on its consolidated results of operations, cash flows, or financial position. Duke Energy incurred net expenses of approximately $50 million (net of reinsurance receivables) related to Hurricanes Katrina and Rita.

Other. As part of its normal business, Duke Energy is a party to various financial guarantees, performance guarantees and other contractual commitments to extend guarantees of credit and other assistance to various subsidiaries, investees and other third parties. These arrangements are largely entered into by Duke Capital. To varying degrees, these guarantees involve elements of performance and credit risk, which are not included on the Consolidated Balance Sheets. The possibility of Duke Energy or Duke Capital having to honor its contingencies is largely dependent upon future operations of various subsidiaries, investees and other third parties, or the occurrence of certain future events. (For further information see Note 18.)

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

In 1999, the Industrial Development Corp of the City of Edinburg, Texas (IDC) issued approximately $100 million in bonds to purchase equipment for lease to Duke Hidalgo (Hidalgo), a subsidiary of Duke Capital. Duke Capital unconditionally and irrevocably guaranteed the lease payments of Hidalgo to IDC through 2028. In 2000, Hidalgo was sold to Calpine Corporation and Duke Capital remained obligated under the lease guaranty. Total maximum exposure under the guarantee obligation as of December 31, 2005 is approximately $200 million, including principal and interest payments. In January 2006, Hidalgo and its subsidiaries filed for bankruptcy protection in connection with the previous bankruptcy filing by its parent, Calpine Corporation in December 2005. Duke Energy does not believe a loss under the guarantee obligation is probable as of December 31, 2005, but continues to evaluate the situation. Therefore, no reserves have been recorded for any contingent loss as of December 31, 2005. No demands for payment have been made under the guarantee. If losses are incurred under the guarantee, Duke Capital has certain rights which should allow it to economically recover such loss. As such recovery is a contingent gain, the timing of recognition of as well as the value of any future recovery may vary.

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For the Years Ended December 31, 2005, 2004 and 2003

Operating and Capital Lease Commitments

Duke Energy leases assets in several areas of its operations. Consolidated rental expense for operating leases was $119 million in 2005, $124 million in 2004 and $133 million in 2003, and included in Operation, Maintenance and Other on the Consolidated Statements of Operations. Amortization of assets recorded under capital leases was included in Depreciation and Amortization on the Consolidated Statements of Operations. The following is a summary of future minimum lease payments under operating leases, which at inception had a noncancelable term of more than one year, and capital leases as of December 31, 2005:

	Operating Leases		Capital Leases
	(in millions)
2006	$	79	$	3
2007		67		2
2008		63		2
2009		61		2
2010		58		—
Thereafter		126		1
Total future minimum lease payments	$	454	$	10

18. Guarantees and Indemnifications

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

Mixed Oxide (MOX) Guarantees. Duke COGEMA Stone & Webster, LLC (DCS) is the prime contractor to the DOE under a contract (the Prime Contract) pursuant to which DCS will design, construct, operate and deactivate a domestic MOX fuel fabrication facility (the MOX FFF) and provide for the irradiation of the MOX fuel. The domestic MOX fuel project was prompted by an agreement between the United States and the Russian Federation to dispose of excess plutonium in their respective nuclear weapons programs by fabricating MOX fuel and irradiating such MOX fuel in commercial nuclear reactors. As of December 31, 2005, Duke Energy, through its indirect wholly owned subsidiary, Duke Project Services Group Inc. (DPSG), held a 40% ownership interest in DCS.

The Prime Contract consists of a “Base Contract” phase and three successive option phases. The DOE has the right to extend the term of the Prime Contract to cover the option phases on a sequential basis, subject to DCS and the DOE reaching agreement, through good-faith negotiations on certain remaining open terms applying to each of the option phases. As of December 31, 2005, DCS’ performance obligations under the Prime Contract included only the Base Contract phase and an initial segment of the first option phase covering mission reactor modifications.

DPSG and the other owners of DCS have issued a guarantee to the DOE, which in conjunction with the applicable guarantee provisions (as clarified by an April 2004 amendment) in the Prime Contract (collectively, the DOE Guarantee), obligates the owners of DCS to jointly and severally guarantee to the DOE that the owners of DCS will reimburse the DOE (in the event that DCS fails to provide such reimbursement) for any payments made by the DOE to DCS pursuant to the Prime Contract that DCS expends on costs that are not “allowable” under certain applicable federal acquisition regulations. DPSG has recourse to the other owners of DCS for any amounts paid under the DOE Guarantee in excess of its proportional ownership percentage of DCS. Although the DOE Guarantee does not provide for a specific limitation on a guarantor’s reimbursement obligations, Duke Energy estimates that the maximum potential amount of future payments DPSG could be required to make under the DOE Guarantee is immaterial. As of December 31, 2005, Duke Energy had no liabilities recorded on its Consolidated Balance Sheets for the DOE Guarantee due to the immaterial amount of the estimated fair value of such guarantee.

In connection with the Prime Contract, Duke Energy Carolinas has entered into a subcontract with DCS (the Duke Energy Carolinas Subcontract) pursuant to which Duke Energy Carolinas will prepare its McGuire and Catawba nuclear reactors (the Mission Reactors) for use of the MOX fuel, and which also includes terms and conditions applicable to Duke Energy Carolinas’s purchase of MOX fuel produced at the MOX FFF for use in the Mission Reactors. The Duke Energy Carolinas Subcontract consists of a “Base Subcontract” phase and two

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For the Years Ended December 31, 2005, 2004 and 2003

successive option phases. DCS has the right to extend the term of the Duke Energy Carolinas Subcontract to cover the option phases on a sequential basis, subject to Duke Energy Carolinas and DCS reaching agreement, through good-faith negotiations on certain remaining open terms applying to each of the option phases. As of December 31, 2005, DCS’ performance obligations under the Duke Energy Carolinas Subcontract included only the Base Subcontract phase and an initial segment of the first option phase covering mission reactor modifications.

DPSG and the other owners of DCS have issued a guarantee to Duke Energy Carolinas (the Duke Energy Carolinas Guarantee) pursuant to which the owners of DCS jointly and severally guarantee to Duke Energy Carolinas all of DCS’ obligations under the Duke Energy Carolinas Subcontract or any other agreement between DCS and Duke Energy Carolinas implementing the Prime Contract. DPSG has recourse to the other owners of DCS for any amounts paid under the Duke Energy Carolinas Guarantee in excess of its proportional ownership percentage of DCS. Even though the Duke Energy Carolinas Guarantee does not provide for a specific limitation on a guarantor’s guarantee obligations, it does provide that any liability of such guarantor under the Duke Energy Carolinas Guarantee is directly related to and limited by the terms and conditions in the Duke Energy Carolinas Subcontract and any other agreements between Duke Energy Carolinas and DCS implementing the Duke Energy Carolinas Subcontract. Duke Energy is unable to estimate the maximum potential amount of future payments DPSG could be required to make under the Duke Energy Carolinas Guarantee due to the uncertainty of whether:

• DCS will exercise its options under the Duke Energy Carolinas Subcontract, which will depend upon whether the DOE will exercise its options under the Prime Contract, which, in turn, will depend on whether the U.S. Congress will authorize funding for DCS’ work under the Prime Contract, and

• The parties to the Prime Contract and the Duke Energy Carolinas Subcontract, respectively, will reach agreement on the remaining open terms for each option phase under the contracts, and if so, what the terms and conditions might be.

Duke Energy has not recorded on its Consolidated Balance Sheets any liability for the potential exposure under the Duke Energy Carolinas Guarantee per FIN 45 because DPSG and Duke Energy Carolinas are under common control.

In February 2006, Duke Energy sold all of its ownership interest in DPSG to a third party, without retaining any of DPSG’s obligations under the DOE Guarantee or the Duke Energy Carolinas Guarantee. As a result of such sale, Duke Energy ceased to have any indirect ownership interest in DCS. However, the sale did not include any changes to the Duke Energy Carolinas Subcontract, under which Duke Energy Carolinas is a subcontractor to DCS with respect to the domestic MOX fuel project.

Other Guarantees and Indemnifications. Duke Capital has issued performance guarantees to customers and other third parties that guarantee the payment and performance of other parties, including certain non-wholly owned entities. The maximum potential amount of future payments Duke Capital could have been required to make under these performance guarantees as of December 31, 2005 was approximately $575 million. Of this amount, approximately $375 million relates to guarantees of the payment and performance of less than wholly owned consolidated entities. Approximately $50 million of the performance guarantees expire between 2006 and 2007, with the remaining performance guarantees expiring after 2007 or having no contractual expiration. Additionally, Duke Capital has issued joint and several guarantees to some of the D/FD project owners, guaranteeing the performance of D/FD under its engineering, procurement and construction contracts and other contractual commitments. These guarantees have no contractual expiration and no stated maximum amount of future payments that Duke Capital could be required to make. Additionally, Fluor Enterprises Inc., as 50% owner in D/FD, has issued similar joint and several guarantees to the same D/FD project owners. In accordance with the D/FD partnership agreement, each of the partners is responsible for 50% of any payments to be made under those guarantees.

Westcoast has issued performance guarantees to third parties guaranteeing the performance of unconsolidated entities, such as equity method investments, and of entities previously sold by Westcoast to third parties. Those guarantees require Westcoast to make payment to the guaranteed third party upon the failure of such unconsolidated or sold entity to make payment under some of its contractual obligations, such as debt, purchase contracts and leases. The maximum potential amount of future payments Westcoast could have been required to make under those performance guarantees as of December 31, 2005 was approximately $15 million. Of those guarantees, approximately $10 million expire in 2006, with the remainder having no contractual expiration.

Duke Capital uses bank-issued stand-by letters of credit to secure the performance of non-wholly owned entities to a third party or customer. Under these arrangements, Duke Capital has payment obligations to the issuing bank which are triggered by a draw by the third party or customer due to the failure of the non-wholly owned entity to perform according to the terms of its underlying contract. The

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For the Years Ended December 31, 2005, 2004 and 2003

maximum potential amount of future payments Duke Capital could have been required to make under these letters of credit as of December 31, 2005 was approximately $525 million. Substantially all of these letters of credit were issued on behalf of less than wholly owned consolidated entities and expire in 2006.

Duke Capital has guaranteed certain issuers of surety bonds, obligating itself to make payment upon the failure of a non-wholly owned entity to honor its obligations to a third party. As of December 31, 2005, Duke Capital had guaranteed approximately $10 million of outstanding surety bonds related to obligations of non-wholly owned entities. The majority of these bonds expire in various amounts in 2006.

Natural Gas Transmission, International Energy, and Crescent have issued guarantees of debt and performance guarantees associated with non-consolidated entities and less than wholly owned consolidated entities. If such entities were to default on payments or performance, Natural Gas Transmission, International Energy, or Crescent would be required under the guarantees to make payment on the obligation of the less than wholly owned entity. As of December 31, 2005, Natural Gas Transmission was the guarantor of approximately $15 million of debt at Westcoast associated with less than wholly owned entities, which expire in 2019. International Energy was the guarantor of approximately $10 million of performance guarantees associated with less than wholly owned entities. Substantially all of these guarantees expire between 2006 and 2008. Crescent was the guarantor of approximately $15 million of debt associated with less than wholly owned entities, which expire in 2006.

Duke Capital has issued guarantees to customers or other third parties related to the payment or performance obligations of certain entities that were previously wholly owned by Duke Energy but which have been sold to third parties, such as DukeSolutions, Inc. (DukeSolutions) and Duke Engineering & Services, Inc. (DE&S). These guarantees are primarily related to payment of lease obligations, debt obligations, and performance guarantees related to provision of goods and services. Duke Energy has received back-to-back indemnification from the buyer of DE&S indemnifying Duke Energy for any amounts paid by Duke Capital related to the DE&S guarantees. Duke Energy also received indemnification from the buyer of DukeSolutions for the first $2.5 million paid by Duke Capital related to the DukeSolutions guarantees. Further, Duke Energy granted indemnification to the buyer of DukeSolutions with respect to losses arising under some energy services agreements retained by DukeSolutions after the sale, provided that the buyer agreed to bear 100% of the performance risk and 50% of any other risk up to an aggregate maximum of $2.5 million (less any amounts paid by the buyer under the indemnity discussed above). Additionally, for certain performance guarantees, Duke Energy has recourse to subcontractors involved in providing services to a customer. These guarantees have various terms ranging from 2005 to 2019, with others having no specific term. Duke Energy is unable to estimate the total maximum potential amount of future payments under these guarantees, since some of the underlying agreements have no limits on potential liability.

In connection with Duke Energy’s sale of the Murray merchant generation facility to KGen, in August 2004, Duke Capital guaranteed in favor of a bank the repayment of any draws under a $120 million letter of credit issued by the bank to Georgia Power Company. The letter of credit, which expires in 2006, is related to the obligation of a KGen subsidiary under a seven-year power sales agreement, commencing in May 2005. Duke Capital will be required to ensure reissuance of this letter of credit or issue similar credit support until the power sales agreement expires in 2012. Duke Energy will operate the sold Murray facility under an operation and maintenance agreement with the KGen subsidiary. As a result, the guarantee has an immaterial fair value. Further, KGen has agreed to indemnify Duke Energy for any payments Duke Capital makes with respect to the $120 million letter of credit.

In 1999, IDC issued approximately $100 million in bonds to purchase equipment for lease to Hidalgo, a subsidiary of Duke Capital. Duke Capital unconditionally and irrevocably guaranteed the lease payments of Hidalgo to IDC through 2028. In 2000, Hidalgo was sold to Calpine Corporation and Duke Capital remained obligated under the lease guaranty. Total maximum exposure under the guarantee obligation as of December 31, 2005 is approximately $200 million, including principal and interest payments. In January 2006, Hidalgo and its subsidiaries filed for bankruptcy protection in connection with the previous bankruptcy filing by its parent, Calpine Corporation in December 2005. Duke Energy does not believe a loss under the guarantee obligation is probable as of December 31, 2005, but continues to evaluate the situation. Therefore, no reserves have been recorded for any contingent loss as of December 31, 2005. No demands for payment have been made under the guarantee. If losses are incurred under the guarantee, Duke Capital has certain rights which should allow it to economically recover such loss. As such recovery is a contingent gain, the timing of recognition of as well as the value of any future recovery may vary.

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Duke Energy has entered into various indemnification agreements related to purchase and sale agreements and other types of contractual agreements with vendors and other third parties. These agreements typically cover environmental, tax, litigation and other matters, as well as breaches of representations, warranties and covenants. Typically, claims may be made by third parties for various periods of time, depending on the nature of the claim. Duke Energy’s potential exposure under these indemnification agreements can range from a specified amount, such as the purchase price, to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. Duke Energy is unable to estimate the total potential amount of future payments under these indemnification agreements due to several factors, such as the unlimited exposure under certain guarantees.

As of December 31, 2005, the amounts recorded for the guarantees and indemnifications mentioned above are immaterial, both individually and in the aggregate.

19. Earnings Per Share (EPS)

Basic earnings per share are computed by dividing earnings available for common stockholders by the weighted-average number of common shares outstanding during the period. Diluted earnings per share are computed by dividing earnings available for common stockholders by the diluted weighted-average number of common shares outstanding each period. Diluted earnings per share reflect the potential dilution that could occur if securities or other agreements to issue common stock, such as stock options, stock-based performance unit awards, contingently convertible debt and phantom stock awards, were exercised or converted into common stock.

The following tables illustrate Duke Energy’s basic and diluted EPS calculations and reconciles the weighted-average number of common shares outstanding to the diluted weighted-average number of common shares outstanding for 2005, 2004, and 2003.

(in millions, except per share data)	Income			Average Shares	EPS
2005
Income from continuing operations	$	2,533
Less: Dividends and premiums on redemption of preferred and preference stock		(12	)
Income from continuing operations—basic		2,521		934	$	2.69
Effect of dilutive securities:
Stock options, phantom, performance and restricted stock				4
Contingently convertible bond		8		32
Income from continuing operations—diluted	$	2,529		970	$	2.61
2004
Income from continuing operations	$	1,252
Less: Dividends and premiums on redemption of preferred and preference stock		(9	)
Income from continuing operations—basic		1,243		931	$	1.33
Effect of dilutive securities:
Stock options, phantom, performance and restricted stock				2
Contingently convertible bond		8		33
Income from continuing operations—diluted	$	1,251		966	$	1.29
2003
Income from continuing operations	$	71
Less: Dividends and premiums on redemption of preferred and preference stock		(15	)
Income from continuing operations—basic		56		903	$	0.06
Effect of dilutive securities:
Stock options, phantom, performance and restricted stock				1
Income from continuing operations—diluted	$	56		904	$	0.06

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

The increase in weighted-average shares outstanding at December 31, 2005 compared to December 31, 2004 was due primarily to the full year effect on the weighted-average share calculation of the issuance of 41.1 million shares during the latter half of 2004, as discussed below, offset by the repurchase and retirement of 32.6 million shares of its common stock throughout 2005 through two separate share repurchase transactions as discussed in Note 21. The increase in weighted-average shares outstanding at December 31, 2004 compared to December 31, 2003 was due primarily to the issuance of 41.1 million shares associated with the settlement of the forward purchase contract component of Duke Energy’s Equity Units in May and November 2004.

Options, restricted stock, performance and phantom stock awards to purchase approximately 19 million shares as of December 31, 2005, 23.2 million shares as of December 31, 2004 and 25.2 million shares as of December 31, 2003 were not included in “potential dilution for the period” in the above table because either the option exercise prices were greater than the average market price of the common shares during those periods, or performance measures related to the awards had not yet been met.

20. Stock-Based Compensation

Duke Energy’s 1998 Long-term Incentive Plan, as amended (the 1998 Plan), reserved 60 million shares of common stock for awards to employees and outside directors. Under the 1998 Plan, the exercise price of each option granted cannot be less than the market price of Duke Energy’s common stock on the date of grant and the maximum option term is 10 years. The vesting periods range from immediate to five years.

Upon the acquisition of Westcoast, Duke Energy converted all stock options outstanding under the 1989 Westcoast Long-term Incentive Share Option Plan to Duke Energy Corporation stock options. Certain of these options also provide for share appreciation rights under which the holder of a stock option may, in lieu of exercising the option, exercise the share appreciation right. The exercise price of these options equals the market price on the date of grant and the maximum option term is 10 years. The vesting periods range from immediate to four years.

Stock Option Activity

	Options (in thousands)		Weighted- Average Exercise Price
Outstanding at December 31, 2002	31,209		$	34
Granted	8,248			15
Exercised	(339	)		11
Forfeited	(6,702	)		34
Outstanding at December 31, 2003	32,416			29
Exercised	(867	)		15
Forfeited	(2,993	)		33
Outstanding at December 31, 2004	28,556			29
Exercised	(2,040	)		20
Forfeited	(1,010	)		34
Outstanding at December 31, 2005	25,506		$	29

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For the Years Ended December 31, 2005, 2004 and 2003

Stock Options at December 31, 2005

	Outstanding				Exercisable
Range of Exercise Prices	Number (in thousands)	Weighted- Average Remaining Life (in years)	Weighted- Average Exercise Price		Number (in thousands)	Weighted- Average Exercise Price
$  9 to $14	4,099	7.1	$	14	1,607	$	14
$15 to $20	1,783	7.2		17	597		18
$21 to $24	308	2.5		22	308		22
$25 to $28	4,900	3.6		26	4,900		26
$29 to $33	3,840	2.8		30	3,814		30
$34 to $37	741	5.9		34	598		34
$38 to $39	5,791	6.0		38	5,755		38
> $39	4,044	5.0		43	4,044		43
Total	25,506	5.0		29	21,623	$	32

On December 31, 2004, Duke Energy had 21.8 million exercisable options with a $32 weighted-average exercise price. On December 31, 2003, Duke Energy had 20.4 million exercisable options with a $32 weighted-average exercise price.

There were no option grants during the years ended December 31, 2005 and 2004. The weighted-average fair value per option granted in 2003 was $4. The fair value of each option grant was estimated on the date of grant using the Black-Scholes option-pricing model.

Weighted-Average Assumptions for Option-Pricing

	2003
Stock dividend yield	3.5	%
Expected stock price volatility	37.5	%
Risk-free interest rates	3.6	%
Expected option lives	7 years

The 1998 Plan allows for a maximum of twelve million shares of common stock to be issued under restricted stock awards, performance awards and phantom stock awards. Stock-based performance awards granted under the 1998 Plan vest over periods from three to seven years. Vesting can occur in three years, at the earliest if performance is met. Duke Energy awarded 1,275,020 shares (fair value of approximately $34 million at grant dates) in 2005, 1,584,840 shares (fair value of approximately $34 million at grant dates) in 2004, and 75,000 shares (fair value of approximately $2 million at grant dates) in 2003. Compensation expense for the performance awards is charged to earnings over the vesting period and totaled $24 million in 2005, $10 million in 2004 and $3 million in 2003.

Phantom stock awards granted under the 1998 Plan vest over periods from one to five years. Duke Energy awarded 1,139,880 shares (fair value of approximately $31 million at grant dates) in 2005, 1,283,220 shares (fair value of approximately $27 million at grant dates) in 2004, and 285,000 shares (fair value of approximately $5 million at grant dates) in 2003. Compensation expense for the phantom awards is charged to earnings over the vesting period and totaled $21 million in 2005, $14 million in 2004 and $6 million in 2003.

Restricted stock awards granted under the 1998 Plan vest over periods from one to five years. Duke Energy awarded 47,000 shares (fair value of approximately $1 million at grant dates) in 2005, 169,160 shares (fair value of approximately $4 million at grant dates) in 2004, and 19,897 shares (fair value of less than $1 million at grant dates) in 2003. Compensation expense for restricted awards is charged to earnings over the vesting period and totaled $1 million in 2005, $1 million in 2004 and $1 million in 2003.

Duke Energy’s 1996 Stock Incentive Plan (the 1996 Plan) allowed four million shares of common stock for awards to employees. The 1996 Plan is not available for new awards and there are no awards outstanding under this plan. Compensation expense for restricted awards is charged to earnings over the vesting period and totaled $0 in 2005 and less than $1 million in 2004 and 2003.

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

21. Common Stock

On March 18, 2005, Duke Energy entered into an accelerated share repurchase transaction whereby Duke Energy repurchased and retired 30 million shares of its common stock from an investment bank at the March 18, 2005 closing price of $27.46 per share. Total consideration paid to repurchase the shares of approximately $834 million, including approximately $10 million in commissions and other fees, was recorded in Common Stockholders’ Equity as a reduction in Common Stock.

As part of the accelerated share repurchase transaction, Duke Energy simultaneously entered into a forward sale contract with the investment bank that was to mature no later than November 8, 2005. Under the terms of the forward sale contract, the investment bank was required to purchase, in the open market, 30 million shares of Duke Energy common stock during the term of the contract to fulfill its obligation related to the shares it borrowed from third parties and sold to Duke Energy. At settlement, Duke Energy, at its option, was required to either pay cash or issue registered or unregistered shares of its common stock to the investment bank if the investment bank’s weighted-average purchase price was higher than the March 18, 2005 closing price of $27.46 per share, or the investment bank was required to pay Duke Energy either cash or shares of Duke Energy common stock, at Duke Energy’s option, if the investment bank’s weighted-average price for the shares purchased was lower than the March 18, 2005 closing price of $27.46 per share. On September 22, 2005, Duke Energy, at its option, paid approximately $25 million in cash to the investment bank to settle the forward sale contract as the investment bank had repurchased the full 30 million shares in the open market and fulfilled all of its obligations. The amount paid to the investment bank was based upon the difference between the investment bank’s weighted-average price paid for the 30 million shares purchased of $28.42 per share and the March 18, 2005 closing price of $27.46 per share.

Duke Energy accounted for the forward sale contract under the provisions of EITF 00-19, “Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company’s Own Stock,” as an equity instrument. As the fair value of the forward sale contract at inception was zero, no accounting for the forward sale contract was required until settlement. Accordingly, Duke Energy recorded the approximately $25 million paid at settlement in Common Stockholders’ Equity as a reduction in Common Stock.

Duke Energy also entered into a separate open market purchase plan with the investment bank on March 18, 2005 to repurchase up to an additional 20 million shares of its common stock through December 27, 2005. Duke Energy held the option to terminate this plan at any time, without penalty. The timing of any repurchase of shares by the investment bank pursuant to this plan was dependent upon certain specified factors, including the market price of Duke Energy’s common stock. In May 2005, in connection with the anticipated merger with Cinergy, Duke Energy announced plans to suspend additional repurchases under the open market purchase plan, pending further assessment. Such suspension shall continue at least until the shareholder vote on the Cinergy merger is completed (see Note 2). Duke Energy may conduct further common stock repurchases before or after the closing of the merger with Cinergy. As of May 6, 2005, Duke Energy had already purchased approximately 2.6 million shares of its common stock pursuant to this plan at a weighted-average price of $28.97 per share. For the year ended December 31, 2005, a total of 32.6 million shares were repurchased under both share repurchase plans for approximately $933 million.

In October 2005, Duke Energy’s $770 million of convertible debt became convertible into approximately 33 million shares of Duke Energy common stock due to the market price of Duke Energy common stock. Holders of the convertible debt were allowed to exercise their right to convert the debt into Duke Energy common stock at a predetermined conversion rate on or prior to December 31, 2005. As a result of this conversion option, during the fourth quarter of 2005, approximately 1.2 million shares of common stock were issued related to this conversion, which resulted in the retirement of approximately $28 million of convertible debt (see Note 15).

In November 2004, Duke Energy issued 18,693,000 shares of its common stock in the settlement of the forward-purchase contract component of its Equity Units issued in November 2001. Under the terms of the contract, the Equity Unit holders were required to purchase stock at the time of settlement rate based on the current market price of Duke Energy’s common stock at the time of the settlement with a floor and a ceiling. The rate was .6231 shares of stock per Equity Unit. Duke Energy received $750 million in proceeds as a result of the settlement, which was included in Proceeds from the Issuances of Common Stock and Common Stock Related to Employee Benefit Plans on the Consolidated Statement of Cash Flows.

In May 2004, Duke Energy issued 22,449,000 shares of its common stock in the settlement of the forward-purchase contract component of its Equity Units issued in March 2001. Under the terms of the contract, the Equity Unit holders were required to purchase common stock at a settlement rate based on the current market price of Duke Energy’s common stock at the time of settlement with a floor and a ceiling. The rate was 0.6414 shares of stock per Equity Unit. Duke Energy received $875 million in proceeds as a result of

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For the Years Ended December 31, 2005, 2004 and 2003

the settlement, which was included in Proceeds from the Issuances of Common Stock and Common Stock Related to Employee Benefit Plans on the Consolidated Statement of Cash Flows.

Duke Energy also sponsors an employee savings plan that covers substantially all U.S. employees. In April 2004, Duke Energy stopped issuing shares under the plan and the plan began making open market purchases with cash provided by Duke Energy. There were no issuances of common stock under the plan in 2005. Issuances of common stock under the plan were $51 million in 2004 and $156 million in 2003. Duke Energy also issues shares of its common stock to meet other employee benefit requirements. Issuances of common stock to meet other employee benefit requirements were approximately $39 million for 2005, approximately $12 million for 2004 and approximately $20 million for 2003.

See Consolidated Statements of Common Stockholders’ Equity and Comprehensive Income (Loss) for additional equity transactions.

22. Employee Benefit Plans

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

Duke Energy’s policy is to fund amounts on an actuarial basis to provide assets sufficient to meet benefits to be paid to plan participants. Duke Energy did not make any contributions to its defined benefit retirement plan in 2005. Duke made voluntary contributions of $250 million in 2004 and $181 million in 2003. Duke Energy does not anticipate making a contribution to the plan in 2006.

Actuarial gains and losses are amortized over the average remaining service period of the active employees. The average remaining service period of active employees covered by the retirement plan is 12 years. Duke Energy determines the market-related value of plan assets using a calculated value that recognizes changes in fair value of the plan assets over five years. Duke Energy uses a September 30 measurement date for its defined benefit retirement plan.

Westcoast Canadian Retirement Plans. The Westcoast benefit plans are reported separately due to actuarial assumption differences. Westcoast and its subsidiaries maintain contributory and non-contributory defined benefit (DB) and defined contribution (DC) retirement plans covering substantially all employees. The DB plans provide retirement benefits based on each plan participant’s years of service and final average earnings. Under the DC plans, company contributions are determined according to the terms of the plan and based on each plan participant’s age, years of service and current eligible earnings.

Westcoast’s policy is to fund the DB plans on an actuarial basis and in accordance with Canadian pension standards legislation, in order to accumulate assets sufficient to meet benefits to be paid. Contributions to the DC plans are determined in accordance with the terms of the plan. Duke Energy made contributions to the Westcoast DB plans of approximately $42 million in 2005, $26 million in 2004, and $10 million in 2003. Duke Energy anticipates that it will make contributions of approximately $40 million to the Westcoast DB plans in 2006. Duke Energy also made contributions to the DC plans of $3 million in 2005, $3 million in 2004, and $3 million in 2003. Duke Energy anticipates that it will make contributions to the DC plans of approximately $4 million in 2006.

The prior service cost and actuarial gains and losses are amortized over the average remaining service period of the active employees. The average remaining service period of the active employees covered by the DB retirement plans is 12 years. Westcoast uses a September 30 measurement date for its plans.

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Components of Net Periodic Pension Costs

	Duke Energy U.S.									Westcoast
	For the Years Ended December 31,
	2005			2004			2003			2005			2004			2003
	(in millions)
Service cost benefit earned during the year	$	61		$	64		$	70		$	9		$	8		$	7
Interest cost on projected benefit obligation		157			160			175			29			26			23
Expected return on plan assets		(229	)		(233	)		(236	)		(27	)		(24	)		(24	)
Amortization of prior service cost		(1	)		(2	)		(3	)		1			—			—
Amortization of net transition asset		—			(4	)		(4	)		—			—			—
Curtailment (gain) / loss		—			(1	)		—			—			—			2
Amortization of loss		35			15			—			4			3			—
Special termination benefit cost		—			—			—			—			1			5
Net periodic pension costs / (income)	$	23		$	(1	)	$	2		$	16		$	14		$	13

As required by SFAS No. 87, “Employers’ Accounting for Pensions,” Duke Energy amortized actuarial losses in its U.S. plan of $35 million in 2005 and $15 million in 2004. The amortization of these losses is primarily attributable to lower than expected asset returns over the past years.

Reconciliation of Funded Status to Net Amount Recognized

	Duke Energy U.S.						Westcoast
	For the Years Ended December 31,
	2005			2004			2005			2004
	(in millions)
Change in Projected Benefit Obligation
Obligation at prior measurement date	$	2,693		$	2,763		$	480		$	434
Service cost		61			64			9			8
Interest cost		157			160			29			26
Actuarial losses / (gains)		105			17			89			(7	)
Plan amendments		—			—			—			6
Participant contributions		—			—			3			2
Benefits paid		(163	)		(298	)		(28	)		(26	)
Curtailment		—			(13	)		—			—
Special termination benefits		—			—			—			6
Obligation assumed from acquisition		—			—			11			—
Foreign currency impact		—			—			23			31
Obligation at measurement date	$	2,853		$	2,693		$	616		$	480

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

	Duke Energy U.S.						Westcoast
	For the Years Ended December 31,
	2005			2004			2005			2004
	(in millions)
Change in Fair Value of Plan Assets
Plan assets at prior measurement date	$	2,477		$	2,477		$	362		$	324
Actual return on plan assets		384			298			63			27
Benefits paid		(163	)		(298	)		(28	)		(26	)
Employer contributions		250			—			48			11
Plan participants’ contributions		—			—			3			2
Assets received on acquisition		—			—			10			—
Foreign currency impact		—			—			17			24
Plan assets at measurement date	$	2,948		$	2,477		$	475		$	362
Funded status		95			(216	)		(141	)		(118	)
Unrecognized net experience loss		655			740			122			68
Unrecognized prior service cost		(3	)		(4	)		8			9
Contributions made after measurement date		—			250			13			19
Net amount recognized	$	747		$	770		$	2		$	(22	)

For the Duke Energy U.S. plan, the accumulated benefit obligation was $2,753 million at September 30, 2005 and $2,607 million at September 30, 2004.

For Westcoast, the accumulated benefit obligation was $562 million at September 30, 2005 and $435 million at September 30, 2004.

Amounts Recognized in the Consolidated Balance Sheets Consist of:

	Duke Energy U.S.				Westcoast
	For the Years Ended December 31,
	2005		2004		2005			2004
	(in millions)
Accrued pension liability	$	—	$	—	$	(76	)	$	(53	)
Intangible asset		—		—		7			—
Pre-funded pension costs		747		120		—			—
Deferred income tax asset		—		254		25			13
Accumulated other comprehensive income		—		396		46			18
Net amount recognized	$	747	$	770	$	2		$	(22	)

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Additional Information:

	Duke Energy U.S.						Westcoast
	For the Years Ended December 31,
	2005			2004			2005		2004
	(in millions)
Increase/(Decrease) in minimum liability included in other comprehensive income, net of tax	$	(396	)	$	(23	)	$	28	$	(3	)

Information for Plans with Accumulated Benefit Obligation in Excess of Plan Assets

	Duke Energy U.S.				Westcoast
	For the Years Ended December 31,
	2005		2004		2005		2004
	(in millions)
Projected benefit obligation	$	—	$	2,693	$	602	$	479
Accumulated benefit obligation		—		2,607		551		434
Fair value of plan assets		—		2,477		464		361

Assumptions Used for Pension Benefits Accounting

	Duke Energy U.S.			Westcoast
Benefit Obligations	2005	2004	2003	2005	2004	2003
	(percentages)
Discount rate	5.50	6.00	6.00	5.00	6.25	6.00
Salary increase	5.00	5.00	5.00	3.25	3.25	3.25
Determined Expense	2005	2004	2003	2005	2004	2003
Discount rate	6.00	6.00	6.75	6.25	6.00	6.50
Salary increase	5.00	5.00	5.00	3.25	3.25	3.25
Expected long-term rate of return on plan assets	8.50	8.50	8.50	7.50	7.50	7.75

For the Duke Energy U.S. plan the discount rate used to determine the pension obligation is based on a AA bond yield curve. The yield is selected based on bonds with cash flows that match the timing and amount of the expected benefit payments under the plan.

For Westcoast the discount rate used to determine the pension obligation is prescribed as the yield on Canadian corporate AA bonds at the measurement date of September 30. The yield is selected based on bonds with cash flows that match the timing and amount of the expected benefit payments under the plan.

Plan Assets Duke Energy U.S.:

	Target Allocation		Percentage of Plan Assets at September 30
Asset Category			2005		2004
U.S. equity securities	45	%	46	%	45	%
Non-U.S. equity securities	20		21		21
Debt securities	30		29		31
Real estate	5		4		3
Total	100	%	100	%	100	%

Duke Energy U.S. assets for both the pension and other post retirement benefits are maintained by a Master Trust. The investment objective of the master trust is to achieve reasonable returns on trust assets, subject to a prudent level of portfolio risk, for the purpose of enhancing the security of benefits for plan participants. The asset allocation targets were set after considering the investment objective and the risk profile with respect to the trust. U.S. equities are held for their high expected return. Non-U.S. equities, debt securities, and real estate are held for diversification. Investments within asset classes are to be diversified to achieve broad market participation and reduce the impact of individual managers or investments. Duke Energy regularly reviews its actual asset allocation and periodically rebalances its investments to the targeted allocation when considered appropriate.

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

The long-term rate of return of 8.5% as of September 30, 2005 for the Duke Energy U.S. assets was developed using a weighted-average calculation of expected returns based primarily on future expected returns across classes considering the use of active asset managers. The weighted-average returns expected by asset classes were 4.2% for U.S. equities, 1.9% for Non-U.S. equities, 2.0% for fixed income securities, and 0.4% for real estate.

Plan Assets Westcoast:

	Target Allocation		Percentage of Plan Assets at September 30
Asset Category			2005		2004
Canadian equity securities	30	%	42	%	40	%
U.S. equity securities	15		11		12
EAFE equity securities(a)	15		15		16
Debt securities	40		32		32
Total	100	%	100	%	100	%

(a) EAFE—Europe, Australasia, Far East

Westcoast assets for registered pension plans are maintained by a Master Trust. The investment objective of the master trust is to achieve reasonable returns on trust assets, subject to a prudent level of portfolio risk, for the purpose of enhancing the security of benefits for participants. The asset allocation targets were set after considering the investment objective and the risk profile with respect to the trust. Canadian equities are held for their high expected return. Non-Canadian equities are held for their high expected return as well as diversification relative to Canadian equities and debt securities. Debt securities are also held for diversification.

The long-term rate of return of 7.25% as of September 30, 2005 for the Westcoast assets was developed using a weighted-average calculation of expected returns based primarily on future expected returns across classes considering the use of active asset managers. The weighted-average returns expected by asset classes were 2.7% for Canadian equities, 1.4% for U.S. equities, 1.45% for Europe, Australasia and Far East equities, and 1.7% for fixed income securities.

The following benefit payments, which reflect expected future service, as appropriate, as expected to be paid over the next five years and thereafter:

Expected Benefit Payments

	U.S. Plan		Westcoast Plans
	(in millions)
Years Ended December 31,
2006	$	176	$	31
2007		194		31
2008		203		32
2009		217		32
2010		250		34
2011 – 2015		1,421		198

Duke Energy also sponsors employee savings plans that cover substantially all U.S. employees. Duke Energy contributes to the plan a matching contribution equal to 100% of before-tax employee contributions, of up to 6% of eligible pay per pay period. Duke Energy expensed employer matching contributions of $61 million in 2005, $57 million in 2004, and $63 million in 2003. Dividends on Duke Energy shares held by the savings plan are charged to retained earnings when declared and shares held in the plan are considered outstanding in the calculation of basic and diluted earnings per share.

Duke Energy also maintains a non-qualified, non-contributory defined benefit retirement plan which covers certain U.S. executives. Duke Energy recognized net periodic pension expense of $8 million in 2005, $11 million in 2004, and $11 million in 2003. There are no plan assets. The projected benefit obligation was $86 million as of September 30, 2005 and September 30, 2004.

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Westcoast also provides non-registered defined benefit supplemental pensions to all employees who retire under a defined benefit registered pension plan and whose pension is limited by the maximum pension limits under the Income Tax Act (Canada). Westcoast recognized net periodic pension expense of $5 million in 2005, $4 million in 2004, and $4 million in 2003. There are no plan assets. The projected benefit obligation was $84 million as of September 30, 2005 and $66 million as of September 30, 2004.

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

These benefit costs are accrued over an employee’s active service period to the date of full benefits eligibility. The net unrecognized transition obligation is amortized over approximately 20 years. Actuarial gains and losses are amortized over the average remaining service period of the active employees. The average remaining service period of the active employees covered by the plan is 14 years.

Westcoast Other Post-Retirement Benefits. Westcoast provides health care and life insurance benefits for retired employees on a non-contributory basis. Employees are eligible for these benefits if they have met age and service requirements at retirement, as defined in the plans. Effective December 31, 2003, a new plan was implemented for all non bargaining employees and the majority of bargaining employees. The new plan will apply for employees retiring on and after January 1, 2006. The new plan is predominantly a defined contribution plan as compared to the existing defined benefit program.

Other post-retirement benefit costs are accrued over an employee’s active service period to the date of full benefits eligibility. Actuarial gains and losses are amortized over the average remaining service period of the active employees covered by the plans. The average remaining service period of the active employees is 18 years.

Components of Net Periodic Post-Retirement Benefit Costs

	Duke Energy U.S.									Westcoast
	For the Years Ended December 31,
	2005			2004			2003			2005			2004			2003
	(in millions)
Service cost benefit earned during the year	$	6		$	5		$	5		$	3		$	3		$	2
Interest cost on accumulated post-retirement benefit obligation		45			47			51			6			5			4
Expected return on plan assets		(18	)		(19	)		(21	)		—			—			—
Amortization of prior service cost		1			1			1			(1	)		(1	)		—
Amortization of net transition liability		16			16			18			—			—			—
Curtailment loss		—			—			21			—			—			1
Amortization of loss		7			8			5			1			1			—
Net periodic post-retirement benefit costs	$	57		$	58		$	80		$	9		$	8		$	7

During 2003, Duke Energy experienced workforce reductions and recognized other post-retirement employee benefits curtailments of $21 million.

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Reconciliation of Funded Status to Accrued Post-Retirement Benefit Costs

	Duke Energy U.S.						Westcoast
	For the Years Ended December 31,
	2005			2004			2005			2004
	(in millions)
Change in Benefit Obligation
Accumulated post-retirement benefit obligation at prior measurement date	$	782		$	924		$	86		$	81
Service cost		6			5			3			3
Interest cost		45			47			6			5
Plan participants’ contributions		21			16			—			—
Actuarial (gain) / loss		17			(134	)		21			(5	)
Benefits paid		(80	)		(76	)		(3	)		(3	)
Foreign currency impact		—			—			4			5
Accumulated post-retirement benefit obligation at measurement date	$	791		$	782		$	117		$	86

	Duke Energy U.S.						Westcoast
	For the Years Ended December 31,
	2005			2004			2005			2004
	(in millions)
Change in Fair Value of Plan Assets
Plan assets at prior measurement date	$	243		$	242		$	—		$	—
Actual return on plan assets		21			20			—			—
Benefits paid		(80	)		(76	)		(3	)		(3	)
Employer contributions		37			41			3			3
Plan participants’ contributions		21			16			—			—
Plan assets at measurement date	$	242		$	243		$	—		$	—
Funded status	$	(549	)	$	(539	)	$	(117	)	$	(86	)
Employer contributions made after measurement date		10			9			1			1
Unrecognized net experience loss		209			202			49			28
Unrecognized prior service cost		1			2			(11	)		(12	)
Unrecognized transition obligation		111			128			—			—
Accrued post-retirement benefit costs	$	(218	)	$	(198	)	$	(78	)	$	(69	)

For measurement purposes, plan assets were valued as of September 30 for both the Duke Energy U.S. and Westcoast plans.

In May 2004, the FASB staff issued FSP No. FAS 106-2. The Modernization Act introduced a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans. The FSP provides guidance on the accounting for the subsidy. Duke Energy adopted this FSP and retroactively applied this FSP as of the date of issuance for its U.S. plan. As a result of anticipated prescription drug subsidy, the accumulated post-retirement benefit obligation had a one time decrease of $96 million in 2004. The after-tax effect on net periodic post-retirement benefit cost was a decrease of $7 million in 2005 and $12 million for 2004. The actuarial gain included in the change in benefit obligation of $134 million in 2004 is primarily due to the recognition of anticipated employer savings as a result of Medicare Part D. FSP No. FAS 106-2 provides guidance that the effect of the federal subsidy should be recognized as an actuarial gain.

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Assumptions Used for Post-Retirement Benefits Accounting

	Duke Energy U.S.			Westcoast
Determined Benefit Obligations	2005	2004	2003	2005	2004	2003
	(percentages)
Discount rate	5.50	6.00	6.00	5.00	6.25	6.00
Salary increase	5.00	5.00	5.00	3.25	3.25	3.25
	Duke Energy U.S.			Westcoast
Determined Expense	2005	2004	2003	2005	2004	2003
Discount rate	6.00	6.00	6.75	6.25	6.00	6.50
Salary increase	5.00	5.00	5.00	3.25	3.25	3.25
Expected long-term rate of return on plan assets	8.50	8.50	8.50	—	—	—
	Duke Energy U.S.			Westcoast
Determined Benefit Obligations	2005	2004	2003	2005	2004	2003
	(percentages)
Assumed tax ratea	35.0	35.0	38.6	—	—	—

a Applicable to the health care portion of funded post-retirement benefits

For the Duke Energy U.S. plan the discount rate used to determine the post-retirement obligation is based on a AA bond yield curve. The yield is selected based on bonds with cash flows that match the timing and amount of the expected benefit payments under the plan.

For Westcoast the discount rate used to determine the post-retirement obligation is prescribed as the yield on Canadian corporate AA bonds at the measurement date of September 30. The yield is selected based on bonds with cash flows that match the timing and amount of the expected benefit payments under the plan.

Plan Assets Duke Energy U.S.:

	Target Allocation		Percentage of Plan Assets at September 30
Asset Category			2005		2004
U.S. equity securities	45	%	46	%	45	%
Non-U.S. equity securities	20		21		21
Debt securities	30		29		31
Real estate	5		4		3
Total	100	%	100	%	100	%

Duke Energy U.S. assets for both the pension and other post-retirement benefits are maintained by a Master Trust. The investment objective of the trust is to achieve reasonable returns on trust assets, subject to a prudent level of portfolio risk, for the purpose of enhancing the security of benefits for plan participants. The asset allocation targets were set after considering the investment objective and the risk profile with respect to the trust. U.S. equities are held for their high expected return. Non-U.S. equities, debt securities, and real estate are held for diversification. Investments within asset classes are to be diversified to achieve broad market participation and reduce the impact of individual managers or investments. Duke Energy regularly reviews its actual asset allocation and periodically rebalances its investments to the targeted allocation when considered appropriate.

Duke Energy also invests other post-retirement assets in the Duke Energy Corporate Employee Benefits Trust (VEBA I) and the Duke Energy Corporation Post-Retirement Medical Benefits Trust (VEBA II). The investment objective of the VEBA’s is to achieve sufficient returns on trust assets, subject to a prudent level of portfolio risk, for the purpose of promoting the security of plan benefits for participants. The VEBA trusts are passively managed. VEBA I has a target allocation of 30% U.S. equities, 45% fixed income securities and 25% cash. VEBA II has a target allocation of 50% U.S. equities and 50% fixed income securities.

The long-term rate of return of 8.5% as of September 30, 2005 for the Duke Energy U.S. assets was developed using a weighted-average calculation of expected returns based primarily on future expected returns across asset classes considering the use of active asset managers. The weighted-average returns expected by asset classes were 4.2% for U.S. equities, 1.9% for Non-U.S. equities, 2.0% for fixed income securities, and 0.4% for real estate.

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Assumed Health Care Cost Trend Rates

	Duke Energy U.S.
	Not Medicare Eligible				Medicare Eligible				Westcoast
	2005		2004		2005		2004		2005		2004
Health care cost trend rate assumed for next year	8.50	%	9.50	%	11.5	%	12.5	%	7.00	%	8.00	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	5.50	%	6.00	%	5.50	%	6.00	%	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate	2009		2009		2012		2012		2008		2008

Sensitivity to Changes in Assumed Health Care Cost Trend Rates Duke Energy U.S. Plan (millions)

	1-Percentage- Point Increase		1-Percentage- Point Decrease
Effect on total service and interest costs	$	3	$	(2	)
Effect on post-retirement benefit obligation		40		(35	)

Sensitivity to Changes in Assumed Health Care Cost Trend Rates Westcoast Plans (millions)

	1-Percentage- Point Increase		1-Percentage- Point Decrease
Effect on total service and interest costs	$	1	$	(1	)
Effect on post-retirement benefit obligation		15		(13	)

Duke Energy and Westcoast expect to make the future benefit payments, which reflect expected future service, as appropriate. Duke Energy expects to receive future subsidies under Medicare Part D. The following benefit payments and subsidies are expected to be paid (or received) over each of the next five years and thereafter.

Expected Benefit Payments and Subsidies (in millions)

	U.S. Plan Payments		U.S. Plan Expected Subsidies		Westcoast Plans
	(in millions)
2006	$	60	$	9	$	4
2007		61		8		4
2008		63		8		4
2009		65		9		4
2010		67		9		5
2011 – 2015		345		47		27

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

23. Other Income and Expense, net

The components of Other Income and Expenses, net on the Consolidated Statements of Operations for the years ended December 31, 2005, 2004 and 2003 are as follows:

	For the years ended December 31,
	2005			2004		2003
	(in millions)
Income/(Expense)
Interest income	$	75		$	71	$	21
Foreign exchange (losses) gains		(9	)		22		2
Deferred returns and AFUDC allowance		17			16		80
Realized and unrealized mark-to-market impact on discontinued hedges		(64	)		—		—
Income related to a distribution from an investment at Crescent		45			—		—
Other		32			39		45
Total	$	96		$	148	$	148

24. Subsequent Events

In January 2006, Duke Energy signed an agreement with LS Power to purchase DENA’s remaining fleet of power generation assets outside the Midwest (see Note 13 for additional information).

In March 2006, Duke Energy Carolinas announced that it has entered into an agreement with Southern Company to evaluate potential construction of a new nuclear plant at a site jointly owned in Cherokee County, South Carolina. With selection of the Cherokee County site, Duke Energy Carolinas is moving forward with previously announced plans to develop an application to the U.S. Nuclear Regulatory Commission (NRC) for a combined construction and operating license (COL) for two Westinghouse AP1000 (advanced passive) reactors. Each reactor is capable of producing approximately 1,117 MW. The COL application submittal to the NRC is anticipated in late 2007 or early 2008. Submitting the COL application does not commit Duke Energy Carolinas to build nuclear units. On September 20, 2006, Duke Energy Carolinas filed an application with the NCUC for authority to recover certain expenses related to its development and evaluation of the proposed nuclear generation facility (the William States Lee III Nuclear Station). Specifically, Duke Energy Carolinas requests an NCUC order (1) finding that work performed by Duke Energy Carolinas to ensure the availability of nuclear generation by 2016 for its customers is prudent and consistent with the promotion of adequate, reliable, and economical utility service to the citizens of North Carolina and the polices expressed in North Carolina General Statute 62-2, and (2) providing expressly that Duke Energy Carolinas may recover in rates, in a timely fashion, the North Carolina allocable portion of its share of costs prudently incurred to evaluate and develop a new nuclear generation facility through December 31, 2007, whether or not a new nuclear facility is constructed. The application is pending.

On April 3, 2006, the previously announced merger between Duke Energy and Cinergy was consummated. For accounting purposes, the effective date of the merger was April 1, 2006. The merger combines the Duke Energy and Cinergy regulated franchises as well as deregulated generation in the Midwestern United States.

In May 2006, the transaction with LS Power closed and total proceeds from the sale were approximately $1.56 billion, including certain working capital adjustments. Additional proceeds of up to approximately $40 million were subject to LS Power obtaining certain state regulatory approvals. On July 20, 2006 the Public Utilities Commission of the State of California approved a toll arrangement related to the Moss Landing facility previously sold to LS Power. In August 2006, LS Power made an additional payment to DENA of approximately $40 million, which DENA recorded as an additional gain on the sale of assets.

In the second quarter of 2006, International Energy recorded a $55 million other-than-temporary impairment charge related to an investment in Compañía de Servicios de Compresión de Campeche, S.A. de C.V. (Campeche), a natural gas compression facility in the Cantarell oil field in the Gulf of Mexico. Campeche project revenues are generated from the gas compression services agreement (GCSA) with the Mexican National Oil Company (PEMEX). The current GCSA expired on October 26, 2006 and a nine month extension was executed on November 2, 2006. In the second quarter of 2006, based on ongoing discussions with PEMEX, it was determined that there was a limited future need for Campeche’s gas compression services. Management of International Energy determined that it is probable that the Campeche investment will ultimately be sold or the GCSA will be renewed for a significantly lower rate. An other-than-temporary

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Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

impairment loss was recorded to reduce the carrying value to management’s best estimate of realizable value. The charges consist of a $17 million impairment of the carrying value of the equity method investment and a $38 million reserve against notes receivable from Campeche. The facility ownership will transfer to PEMEX in August 2007.

On September 7, 2006, an indirect wholly owned subsidiary of Duke Energy closed an agreement to create a joint venture of Crescent (the Crescent JV) with Morgan Stanley Real Estate Fund V U.S., L.P. (MSREF) and other affiliated funds controlled by Morgan Stanley (collectively the “MS Members”). Under the agreement, the Duke Energy subsidiary contributed all of the membership interests in Crescent to a newly-formed joint venture, which was ascribed an enterprise value of approximately $2.1 billion as of December 31, 2005. In conjunction with the formation of the Crescent JV, the joint venture, Crescent and Crescent’s subsidiaries entered into a credit agreement with third party lenders under which Crescent borrowed approximately $1.23 billion, of which approximately $1.19 billion was immediately distributed to Duke Energy. Immediately following the debt transaction, the MS Members collectively acquired a 49% membership interest in the Crescent JV from Duke Energy for a purchase price of approximately $415 million. The MS Members 49% interest reflects a 2% interest in the Crescent JV issued by the joint venture to the President and Chief Executive Officer of Crescent which is subject to forfeiture if the executive voluntarily leaves the employment of the Crescent JV within a three year period. Additionally, this interest can be put back to the Crescent JV after three years or possibly earlier upon the occurrence of certain events at an amount equal to 2% of the fair value of the Crescent JV’s equity as of the put date. Therefore, the Crescent JV will accrue the obligation related to the put as a liability over the three year forfeiture period. Accordingly, Duke Energy has an effective 50% ownership in the equity of Crescent JV for financial reporting purposes.

Duke Energy is party to an agreement with a third party service provider related to future purchases to be made by Duke Energy through late 2007. The agreement contains certain damage payment provisions if the amount of future purchases is not met by the specified date. While Duke Energy expected to comply with the agreement’s terms, Duke Energy accelerated discussions to renegotiate the agreement in late November and into December 2006. Under the current agreement, if Duke Energy were not to comply with the agreement, the maximum pretax exposure under the agreement is currently estimated at approximately $100 million. It is not possible to predict with certainty whether Duke Energy will make all required future purchases under the agreement or whether the agreement will be modified. Therefore, future payments under the agreement may be possible. Duke Energy does not believe it is possible at this time to estimate the charges, if any, that it might incur in connection with any settlement of this agreement.

As disclosed in Note 17, “Commitments and Contingencies”, the Sonatrach/Sonatrading arbitration hearing on damages commenced in September 2005. The final hearing on damages was concluded in March 2006, and the tribunal issued its award on damages on November 30, 2006. Duke LNG was awarded approximately $23 million for Sonatrach’s breach of its shipping obligations. Sonatrach and Sonatrading were awarded an unspecified amount that management believes will, when calculated, be substantially less than the $23 million awarded to Duke LNG, and result ultimately in a net positive, but immaterial, award to Duke LNG.

For information on subsequent events related to acquisitions and dispositions, regulatory matters, risk management and hedging activities, credit risk, and financial instruments, discontinued operations and assets held for sale, debt and credit facilities, commitments and contingencies, and guarantees and indemnifications, see Notes 2, 4, 8, 13, 15, 17, and 18.

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PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

25. Quarterly Financial Data (Unaudited)

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
	(In millions, except per share data)
2005
Operating revenues	$	5,328	$	5,274	$	3,028	$	3,116	$	16,746
Operating income		717		778		1,533		588		3,616
Net income		868		309		41		606		1,824
Earnings available for common stockholders		866		307		38		601		1,812
Earnings per share
Basic(a)	$	0.91	$	0.33	$	0.04	$	0.65	$	1.94
Diluted(a)	$	0.88	$	0.32	$	0.04	$	0.63	$	1.88
2004
Operating revenues	$	5,126	$	4,800	$	5,081	$	5,542	$	20,549
Operating income		555		811		870		725		2,961
Net income		311		432		389		358		1,490
Earnings available for common stockholders		309		429		387		356		1,481
Earnings per share
Basic(a)	$	0.34	$	0.46	$	0.41	$	0.38	$	1.59
Diluted(a)	$	0.33	$	0.45	$	0.40	$	0.36	$	1.54

(a) Quarterly EPS amounts are not always additive to full-year amount due to rounding.

During the first quarter of 2005, Duke Energy recorded the following unusual or infrequently occurring items: an approximate $0.9 billion (net of minority interest of approximately $0.3 billion) pre-tax gain on sale of Duke Energy Field Services, LLC’s wholly-owned subsidiary, Texas Eastern Products Pipeline Company, LLC (see Note 2); an approximate $100 million pre-tax gain on sale of Duke Energy’s limited partner interest in TEPPCO Partners, L.P. (see Note 2); an approximate $21 million pre-tax gain on sale of DENA’s partially completed Grays Harbor power plant in Washington State (see Note 2); an approximate $230 million of unrealized pre-tax losses on certain 2005 and 2006 derivative contracts hedging Field Services commodity price risk which were discontinued as cash flow hedges as a result of the anticipated deconsolidation of DEFS by Duke Energy (see Note 2); and an approximate $30 million mutual liability adjustment related to Bison which was an immaterial correction of an accounting error related to prior periods.

During the third quarter of 2005, Duke Energy recorded the following unusual or infrequently occurring items: an approximate $1.3 billion pre-tax charge for the impairment of assets and the discontinuance of hedge accounting for certain positions at DENA, as a result of the decision to exit substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern Assets (see Note 13); an approximate $575 million pre-tax gain associated with the transfer of 19.7% of Duke Energy’s interest in DEFS to ConocoPhillips, Duke Energy’s co-equity owner in DEFS, which reduced Duke Energy’s ownership interest in DEFS from 69.7% to 50% (see Note 2); an approximate $105 million of unrealized and realized pre-tax losses on certain 2005 and 2006 derivative contracts hedging Field Services commodity price risk which were discontinued as cash flow hedges as a result of the deconsolidation of DEFS by Duke Energy (see Note 2); and approximately $90 million of gains at Crescent due primarily to income related to a distribution from an interest in a portfolio of office buildings and a large land sale.

During the fourth quarter of 2005, Duke Energy recorded the following unusual or infrequently occurring items: pre-tax gain of approximately $380 million, which reverses a portion of the third quarter DENA impairment, attributable to the planned asset sales to LS Power; and pre-tax losses of approximately $475 million for portfolio exit costs including severance, retention and other transaction costs at DENA (see Note 13).

During the first quarter of 2004, Duke Energy recorded the following unusual or infrequently occurring items: a $256 million pre-tax gain on sale of International Energy’s Asia-Pacific Business (see Note 13); and an approximate $360 million pre-tax charge in 2004 associated with the sale of DENA’s Southeast Plants (see Note 2).

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PART II

DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

During the second quarter of 2004, Duke Energy recorded the following unusual or infrequently occurring items: a $130 million (net of minority interest of $5 million) pre-tax gain related to the settlement of the Enron bankruptcy proceedings; a $39 million net increase in the pre-tax gains ($30 million increase to the after tax gains) originally recorded on the sales of International Energy’s Asia-Pacific Business (see Note 13) and its European Business; a $52 million release of various income tax reserves (see Note 6); and a $105 million pre-tax charge related to the California and Western U.S. energy markets settlement (see Note 17).

During the third quarter of 2004, Duke Energy recorded the following unusual or infrequently occurring items: a $48 million tax benefit related to the realignment of certain subsidiaries of Duke Energy and the pass-through structure of these for U.S. income tax purposes ($20 million is included in continuing operations, see Note 6, the remainder is in discontinued operations); and impairments of $45 million (net of minority interest of $26 million) related to asset impairments, losses on asset sales and write-down of equity investments at Field Services (see Note 12).

During the fourth quarter of 2004, Duke Energy recorded the following unusual or infrequently occurring items: $180 million of pre-tax gains associated with the sales of two DENA partially completed facilities, Luna and Moapa (see Note 13); a $64 million pre-tax correction of immaterial accounting errors related to the elimination of intercompany reserves at Bison; $45 million in taxes recorded in 2004 on the repatriation of foreign earnings that is expected to occur in 2005 associated with the American Jobs Creation Act of 2004 (see Note 6); a $51 million pre-tax charge related to the sale of DETM contracts that were held in a net liability position; $20 million in contract termination charges related to the DENA partially completed plant at Grays Harbor (see Note 13); approximately $42 million of impairment charges related to two Crescent residential developments in Payson, Arizona and one in Austin, Texas (see Note 12); and $8 million in bad debt charges recorded by Crescent related to notes receivable due from Rim Golf Investor LLC and Chaparral Pines Investor LLC. The bad debt charges are recorded in Operation, Maintenance and Other on the Consolidated Statement of Operations.

150

DUKE ENERGY CORPORATION

SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

			Additions
	Balance at Beginning of Period		Charged to Expense		Charged to Other Accounts			Deductions(a)		Balance at End of Period
	(In millions)
December 31, 2005:
Injuries and damages	$	1,269	$	4	$	—		$	57	$	1,216
Allowance for doubtful accounts		135		33		10			51		127
Other(b)		886		327		67			421		859
	$	2,290	$	364	$	77		$	529	$	2,202
December 31, 2004:
Injuries and damages	$	1,319	$	8	$	2		$	60	$	1,269
Allowance for doubtful accounts		280		77		4			226		135
Other(b)		1,153		236		96			599		886
	$	2,752	$	321	$	102		$	885	$	2,290
December 31, 2003:
Injuries and damages	$	367	$	1	$	1,024	(c)	$	73	$	1,319
Allowance for doubtful accounts		357		58		15			150		280
Other(b)		1,204		372		20			443		1,153
	$	1,928	$	431	$	1,059		$	666	$	2,752

(a) Principally cash payments and reserve reversals.

(b) Principally property insurance reserves and litigation and other reserves, included in Other Current Liabilities, or Deferred Credits and Other Liabilities on the Consolidated Balance Sheets.

(c) Primarily represents changes in estimates for certain contingent liabilities which are covered by insurance and also recognized as an insurance receivable which is included in Other noncurrent assets on the Consolidated Balance Sheets.

151