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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

FOR ANNUAL AND TRANSITION REPORTS

PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

(Mark One)

x    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2006 or

¨    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission file number 1-32853

DUKE ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

704-594-6200

(Registrant’s telephone number, including area code)

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ¨ No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).

Large accelerated filer x                 Accelerated filer ¨                 Non-accelerated filer ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes ¨ No x

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DUKE ENERGY CORPORATION

FORM 10-K FOR THE YEAR ENDED

DECEMBER 31, 2006

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This document includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are based on management’s beliefs and assumptions. These forward-looking statements are identified by terms and phrases such as “anticipate,” “believe,” “intend,” “estimate,” “expect,” “continue,” “should,” “could,” “may,” “plan,” “project,” “predict,” “will,” “potential,” “forecast,” and similar expressions. Forward-looking statements involve risks and uncertainties that may cause actual results to be materially different from the results predicted. Factors that could cause actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:

In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than Duke Energy has described. Duke Energy undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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Item 1. Business.

GENERAL

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

In May 2005, Duke Energy and Cinergy Corp. (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.

Duke Energy Holding Corp. (Duke Energy HC) was incorporated in Delaware on May 3, 2005 as Deer Holding Corp., a wholly-owned subsidiary of Duke Energy Corporation (Old Duke Energy). On April 3, 2006, in accordance with their previously announced merger agreement, Old Duke Energy and Cinergy merged into wholly-owned subsidiaries of Duke Energy HC, resulting in Duke Energy HC becoming the parent entity. In connection with the closing of the merger transactions, Duke Energy HC changed its name to Duke Energy Corporation (New Duke Energy or Duke Energy) and Old Duke Energy converted into a limited liability company named Duke Power Company LLC (subsequently renamed Duke Energy Carolinas, LLC (Duke Energy Carolinas) effective October 1, 2006). As a result of the merger transactions, each outstanding share of Cinergy common stock was converted into 1.56 shares of common stock of Duke Energy, which resulted in the issuance of approximately 313 million shares. Additionally, each share of common stock of Old Duke Energy was converted into one share of Duke Energy common stock. Old Duke Energy is the predecessor of Duke Energy for purposes of U.S. securities regulations governing financial statement filing. Therefore, the accompanying Consolidated Financial Statements reflect the results of operations of Old Duke Energy for the three months ended March 31, 2006 and the years ended December 31, 2005 and 2004 and the financial position of Old Duke Energy as of December 31, 2005. New Duke Energy had separate operations for the period beginning with the effective date of the Cinergy merger, and references to amounts for periods after the closing of the merger relate to New Duke Energy. Cinergy’s results have been included in the accompanying Consolidated Statements of Operations from the effective date of acquisition and thereafter (see “Cinergy Merger” in Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”). Both Old Duke Energy and New Duke Energy are referred to as Duke Energy hereinafter.

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 Duke Energy’s 50% interest in the Crescent JV (Crescent). Prior to Duke Energy’s sale of an effective 50% ownership interest in Crescent in September 2006 (see below), this segment represented Duke Energy’s 100% ownership of Crescent Resources, LLC. 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 exiting of the majority of former Duke Energy North America’s (DENA) businesses, former 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 in continuing operations 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, which primarily include the merchant generation operations in the Midwest and Southeast, 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 former DENA segment for all periods.

U.S. Franchised Electric and Gas generates, transmits, distributes and sells electricity in central and western North Carolina, western South Carolina, southwestern Ohio, central and southern Indiana, and northern Kentucky. U.S. Franchised Electric and Gas also transports and sells natural gas in southwestern Ohio and northern Kentucky. It conducts operations primarily through Duke Energy Carolinas, Duke Energy Ohio, Inc. (Duke Energy Ohio), Duke Energy Indiana, Inc. (Duke Energy Indiana) and Duke Energy Kentucky, Inc. (Duke Energy Kentucky). These electric and gas operations are subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC), the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina (PSCSC), the Public Utilities Commission of Ohio (PUCO), the Indiana Utility Regulatory Commission (IURC) and the Kentucky Public Service Commission (KPSC).

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Natural Gas Transmission provides transportation and storage of natural gas for customers in various regions of the Eastern and Southeastern United States, the Maritimes Provinces and the Pacific Northwest in the United States and Canada and in the province of Ontario 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. 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). As discussed below, effective January 2, 2007, Duke Energy consummated its spin-off of the natural gas businesses (Spectra Energy Corp. (Spectra Energy)), which includes the Natural Gas Transmission business segment, to shareholders.

Field Services includes Duke Energy’s investment in DCP Midstream, LLC (formerly Duke Energy Field Services, LLC (DEFS)), which gathers, compresses, processes, transports, trades and markets, and stores natural gas. DEFS also fractionates, transports, gathers, treats, processes, 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 gathering systems located in major natural gas producing regions: Permian, Mid-Continent, East Texas-North Louisiana, South, Central, Rocky Mountain, and Gulf Coast. As discussed below, effective January 2, 2007, Duke Energy consummated its spin-off of Spectra Energy, which includes Duke Energy’s 50% ownership interest in DEFS, to shareholders.

In July 2005, Duke Energy completed the 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. 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.

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. On January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses, including Duke Energy’s 50% interest in DEFS, to shareholders. The new natural gas business, which is named Spectra Energy, consists principally of the operations of Spectra Energy Capital LLC (Spectra Energy Capital, formerly Duke Capital LLC), excluding certain operations which were transferred from Spectra Energy Capital to Duke Energy in December 2006, primarily International Energy and Duke Energy’s effective 50% interest in the Crescent JV. The use of the term Spectra Energy Capital relates to operations of the former Duke Capital LLC or the post-spin Spectra Energy Capital, as the context requires. Approximately $20 billion of assets, $13 billion of liabilities (which includes approximately $8.6 billion of debt issued by Spectra Energy Capital and its consolidated subsidiaries), and $7 billion of common stockholders’ equity were distributed from Duke Energy as of the date of the spin-off. Assets and liabilities of entities included in the spin-off of Spectra Energy were transferred from Duke Energy on a historical cost basis on the date of the spin-off transaction.

The decision to spin off the natural gas businesses is expected to deliver long-term value to shareholders. The historical results of the natural gas businesses are expected to be treated as discontinued operations at Duke Energy in future periods beginning with the first quarter of 2007. The primary businesses remaining in Duke Energy post-spin are 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).

Commercial Power owns, operates and manages non-regulated merchant power plants and engages in the wholesale marketing and procurement of electric power, fuel and emission allowances related to these plants as well as other contractual positions. Commercial Power also develops and implements customized energy solutions. Commercial Power’s generation asset fleet consists of Duke Energy Ohio’s non-regulated generation in Ohio, acquired from Cinergy in April 2006, and the five Midwestern gas-fired merchant generation assets that were a portion of former DENA. Commercial Power’s assets comprise approximately 8,100 megawatts of power generation primarily located in the Midwestern United States. The asset portfolio has a diversified fuel mix with base-load and mid-merit coal-fired units as well as combined cycle and peaking natural gas-fired units. Most of the generation asset output in Ohio has been contracted through the Rate Stabilization Plan (RSP). For more information on the RSP, see “Commercial Power” section below.

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 equity investments in Saudi Arabia, Mexico, and Greece.

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.

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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 $1.21 billion, net of transaction costs, 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. A 2% interest in the Crescent JV was also 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 2% 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:

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

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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, 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.

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

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

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

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

Fractionation/Fractionate. The process of separating liquid hydrocarbons from natural gas into propane, butane, ethane and other related products.

Futures Contract. A contract, usually exchange traded, in which the buyer is obligated to take delivery and the seller is obligated to deliver a fixed amount of a commodity at a predetermined price on a specified future date.

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

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

Integrated Resource Planning. The process typically utilized by regulated utilities in conjunction with state regulatory bodies for forecasting and planning the need for generation and transmission facilities.

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.

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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 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.

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.

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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 Financial Condition and Results of Operations, 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. U.S. Franchised Electric and Gas also transports and sells natural gas. It conducts operations primarily through Duke Energy Carolinas, Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky (Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky collectively referred to as Duke Energy Midwest). Its service area covers about 47,000 square miles with an estimated population of 10 million in central and western North Carolina, western South Carolina, southwestern Ohio, central and southern Indiana, and northern Kentucky. U.S. Franchised Electric and Gas supplies electric service to approximately 3.9 million residential, commercial and industrial customers over 146,700 miles of distribution lines and a 20,700-mile transmission system. U.S. Franchised Electric and Gas provides domestic regulated transmission and distribution services for natural gas to approximately 500,000 customers via approximately 8,900 miles of gas mains (gas distribution lines that serve as a common source of supply for more than one service line) and service lines. 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 Duke Energy Carolinas, 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 and Transmission Facilities.”)

Duke Energy Carolinas’ service area has a diversified commercial and industrial presence. Manufacturing continues to be the largest contributor to the Carolinas’ economy. Other sectors such as information, financial and real estate services are growing.

The textile industry, rubber and plastic products, chemicals and computer products are the most significant contributors to the area’s manufacturing output and Duke Energy Carolinas’ industrial sales revenue for 2006. Motor vehicle parts, building materials and electrical & electronic equipment manufacturing also have a strong impact in the area’s economic growth and the region’s industrial sales. The textile industry, while in decline, is the largest industry served in the Carolinas.

Duke Energy Carolinas has business development strategies to leverage the competitive advantages of North Carolina and South Carolina to attract and expand advanced manufacturing business in the region’s service territory. These competitive advantages, including a quality workforce, strong educational institutions and superior transportation infrastructure, were key factors in bringing in new customers in the plastics, pharmaceuticals, building materials and data processing industries. The success in attracting new companies as well as expanding the operations of existing customers substantially offsets the sales declines in the textile and furniture industries in 2006.

Industries of major economic significance in Duke Energy Indiana’s service territory include chemicals, primary metals, and transportation. Other significant industries operating in the area include stone, clay and glass, food products, paper, and other manufacturing. Key sectors among commercial customers include education and retail trade.

Duke Energy Indiana’s business development strategies leveraged the competitive advantages of Indiana to attract new advanced manufacturing, logistics, life sciences and data center business to Duke Energy Indiana’s service territory. These advantages, including competitive electric rates, a strong transportation network, excellent institutions of higher learning, and a quality workforce, were key in attracting new customers and encouraging existing customer expansions. This ability to attract business investment in the service territory helped balance the slight decline in sales in the chemical, food and transportation equipment sector.

Duke Energy Ohio and Duke Energy Kentucky’s service area has a diversified commercial and industrial presence. Major components of the economy include manufacturing, real estate & rental leasing, wholesale trade, financial and insurance services, retail trade, education, healthcare and professional/business services. Cincinnati is positioned to become a healthcare hub and the presence of non-durable manufacturing makes the area less vulnerable to economic fluctuations than other areas.

The primary metals industry, transportation equipment, chemicals, and paper and plastics are the most significant contributors to the area’s manufacturing output and Duke Energy Ohio and Duke Energy Kentucky’s industrial sales revenue for 2006. Food, beverage and tobacco, fabricated metals, and electronics also have a strong impact on the area’s economic growth and the region’s industrial sales.

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Duke Energy Ohio and Duke Energy Kentucky have business development strategies to leverage the competitive advantages of the Greater Cincinnati Region to attract and expand advanced manufacturing businesses. The availability of a highly skilled workforce, superior highway access, low cost of living, and proximity to markets and raw materials were key factors in attracting new customers in the transportation, food manufacturing, chemical manufacturing, plastics and data processing industries.

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.

The following maps show the U.S. Franchised Electric and Gas’ service territories and operating facilities.

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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), fifteen coal-fired stations with a combined net capacity of 13,552 MW, thirty-one hydroelectric stations (including two pumped-storage facilities) with a combined net capacity of 3,213 MW, fifteen combustion turbine (CT) stations burning natural gas, oil or other fuels with a combined net capacity of 5,245 MW and two combined cycle (CC) stations burning natural gas or synthetic gas with a combined net capacity of 560 MW. The CT stations include the 2006 acquisition of the Rockingham CT facility (825 MW) from Dynegy Power Marketing, Inc. The acquisition was completed November 10, 2006 and was the most recent addition to U.S. Franchised Electric and Gas’ resource capability. Energy and capacity are also supplied through contracts with other generators and purchased on the open market. Factors that could cause U.S. Franchised Electric and Gas to purchase power for its customers include generating plant outages, extreme weather conditions, summer reliability, growth, and price. 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.

In December 2006, Duke Energy announced an agreement to purchase a portion of Saluda River Electric Cooperative, Inc.’s ownership interest in the Catawba Nuclear Station. Under the terms of the agreement, Duke Energy will pay approximately $158 million for the additional ownership interest of the Catawba Nuclear Station. Following the closing of the transaction, Duke Energy will own approximately 19 percent of Catawba Nuclear Station. This transaction, which is expected to close prior to September 30, 2008, is subject to approval by various state and federal agencies.

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 large, low-energy-production-cost nuclear and coal-fired generating units that operate almost continuously (or at baseload levels). In 2006, approximately 98.8% of the total generated energy came from U.S Franchised Electric and Gas’ low-cost, efficient nuclear and coal

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units (51.9% coal and 46.9% nuclear). The remaining energy needs were supplied by hydroelectric, CT and CC generation or economical purchases from the wholesale market.

Hydroelectric (both conventional and pumped storage) in the Carolinas and gas/oil CT and CC stations in both the Carolinas and Midwest operate primarily during the peak-hour load periods (at peaking levels) when customer loads are rapidly changing. CT’s and CC’s 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.

U.S. Franchised Electric and Gas’ 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.

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, coal and integrated gasification combined cycle (IGCC) 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, Duke Energy Carolinas filed an application with the NCUC for a Certificate of Public Convenience and Necessity (CPCN) on June 2, 2006 for regulatory approval to build the Cliffside Project consisting of two 800 MW supercritical coal units at the existing Cliffside Steam Station, located in Rutherford and Cleveland Counties of North Carolina. Steps are also being taken to maintain the option to bring the Cliffside project on-line as early as 2011. On February 28, 2007, the NCUC issued a notice of decision approving the construction of one unit at the Cliffside Steam Station. The NCUC stated that it will issue a full order in the near future. Duke Energy will review the NCUC’s order, once issued, and determine whether to proceed with the Cliffside Project or consider other alternatives, including additional gas fired generation. In September 2006, Duke Energy Indiana and Vectren Energy Delivery of Indiana, Inc. filed a joint petition with the IURC seeking a CPCN for constructing a 630 MW IGCC power plant at Duke Energy Indiana’s Edwardsport Generating Station in Knox County, Indiana. In addition, Duke Energy Carolinas 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. Although U.S. Franchised Electric and Gas is progressing with these efforts, final decisions regarding the development of new power facilities will be driven by realized demand, market conditions and other strategic considerations.

In evaluating the construction of several large, new electric generating plants in North Carolina, South Carolina, and Indiana, Duke Energy has begun to see significant increases in the estimated costs of these projects driven by strong domestic and international demand for the material, equipment, and labor necessary to construct these facilities. In October 2006, Duke Energy made a filing with the NCUC related to the Duke Energy Carolinas’ request for a CPCN for the Cliffside project. In this filing, Duke Energy stated that due to the rising costs described above, the cost of building the Cliffside units could be approximately $3 billion, excluding allowance for funds used during construction (AFUDC). The costs described above are expected to continue to increase causing the overall cost of the Cliffside project to increase, until such time as the NCUC issues a CPCN and Duke Energy is able to enter into definitive agreements with necessary material and service providers. In November 2006, Duke Energy received approval for nearly $260 million of future federal tax credits related to costs to be incurred for the modernization of the Cliffside facility as well as the IGCC plant in Indiana.

Duke Energy Indiana’s estimated costs associated with the potential construction of an IGCC plant in Indiana have also increased. Duke Energy Indiana’s publicly filed testimony with the IURC on October 24, 2006 indicates that industry (Electric Power Research Institute) estimates of total capital requirement for a facility of this type and size are now in the range of $1.6 billion to $2.1 billion (including escalation to 2011 and owner’s specific site costs).

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, 2006.

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Coal. U.S. Franchised Electric and Gas meets its coal demand in the Carolinas and Midwest through a portfolio of purchase supply contracts and spot agreements. Large amounts of coal are purchased under supply contracts with mining operators who mine both underground and at the surface. U.S. Franchised Electric and Gas uses spot-market purchases to meet coal requirements not met by supply contracts. Expiration dates for its supply contracts, which have various price adjustment provisions and market re-openers, range from 2007 to 2016. 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 as existing contracts expire, though prices will fluctuate over time as coal markets change. The coal purchased for the Carolinas is primarily produced from mines in eastern Kentucky, West Virginia and southwestern Virginia. The coal purchased for the Midwest is primarily produced in Indiana, Illinois, and Kentucky. U.S. Franchised Electric and Gas has an adequate supply of coal to fuel its current and projected operations.

The current average sulfur content of coal purchased by U.S. Franchised Electric and Gas for the Carolinas is approximately 1%, however, as several Carolinas coal plants bring on scrubbers over the next several years the sulfur content of coal purchased could increase as higher sulfur coal options are considered. The current average sulfur content of coal purchased by U.S. Franchised Electric and Gas for the Midwest is approximately 2%. Coupled with the use of available sulfur dioxide emission allowances on the open market, this satisfies the current emission limitations for sulfur dioxide for existing facilities in the Carolinas and Midwest.

Gas. U.S. Franchised Electric and Gas is responsible for the purchase and the subsequent delivery of natural gas to native load customers in the Midwest. U.S. Franchised Electric and Gas’ natural gas procurement strategy is to buy firm natural gas supplies (natural gas intended to be available at all times) and firm interstate pipeline transportation capacity during the winter season (November through March) and during the non-heating season (April through October) through a combination of firm supply and transportation capacity along with spot supply and interruptible transportation capacity. This strategy allows U.S. Franchised Electric and Gas to assure reliable natural gas supply for its high priority (non-curtailable) firm customers during peak winter conditions and provides U.S. Franchised Electric and Gas the flexibility to reduce its contract commitments if firm customers choose alternate gas suppliers under U.S. Franchised Electric and Gas’ customer choice/gas transportation programs. In 2006, firm supply purchase commitment agreements provided approximately 91% of the natural gas supply, with the remaining gas purchased on the spot market. These firm supply agreements feature two levels of gas supply, specifically (1) baseload, which is a continuous supply to meet normal demand requirements, and (2) swing load, which is gas available on a daily basis to accommodate changes in demand due primarily to changing weather conditions.

U.S. Franchised Electric and Gas manages natural gas procurement-price volatility mitigation programs for Duke Energy Ohio and Duke Energy Kentucky. These programs pre-arrange between 25-75% of winter heating season baseload gas requirements and up to 25-50% of summer season baseload requirements up to three years in advance of the delivery month. Duke Energy Ohio and Duke Energy Kentucky use primarily fixed-price forward contracts and contracts with a ceiling and floor on the price. As of December 31, 2006, Duke Energy Ohio and Duke Energy Kentucky, combined, had hedged approximately 73% of their winter 2006/2007 base load requirements.

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 the Oconee, McGuire and Catawba Nuclear Stations in the Carolinas. 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 Catawba in the near term, but so that its level of coverage decreases over time 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:

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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 Shaw AREVA MOX Services (MOX Services) (formerly 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 MOX Services 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 completed their first cycle of irradiation on November 11, 2006 and have been inserted for a second cycle of irradiation in Unit 1 of the Catawba Nuclear Station.

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, 2006, the inventory balance for U.S. Franchised Electric and Gas was approximately $795 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 the McGuire and Oconee Nuclear Stations and operates and has a partial ownership interest in the Catawba Nuclear Station. The McGuire and the 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. (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 2006, 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 $1,775 million as of December 31, 2006 and $1,504 million as of December 31, 2005. 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.

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 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

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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. The matter has been stayed pending the result of ongoing settlement negotiations between Duke Energy and the DOE. 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 expects resolution of this matter in the first quarter of 2007.

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, 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

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 Duke Energy Carolinas’ service area has been assigned in this manner. In unassigned areas, Duke Energy Carolinas’ 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. In Kentucky, the right of municipalities to serve customers outside corporate limits is subject to court approval. In Indiana, the state is divided into certified electric service areas for municipal utilities, rural cooperatives and investor owned utilities. There are limited circumstances where the certified electric service areas can be modified, with approval of the IURC. 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.

Duke Energy Ohio operates under the RSP Market Based Standard Service Offer (MBSSO) which was approved by the PUCO in November 2004, and which provides price certainty through December 31, 2008. In March 2005, the Office of the Ohio Consumers’ Counsel (OCC) appealed the PUCO’s approval of the MBSSO and in November 2006, the Ohio Supreme Court remanded the PUCO’s order approving the MBSSO for further evidentiary support and explanation, and to require Duke Energy Ohio to disclose certain confidential commercial agreements between Duke Energy Ohio and other parties previously requested by the OCC. Hearings on remand are expected to occur in March 2007. A major feature of the MBSSO is the Provider of Last Resort (POLR) Charge. Duke Energy Ohio has been collecting a POLR charge from non-residential customers since January 1, 2005, and from residential customers since January 1, 2006. The POLR charge consists of the following discrete charges:

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Regulation

State

The NCUC, the PSCSC, the PUCO, the IURC and the KPSC (collectively, the State Utility Commissions) approve rates for retail electric service within their respective states. In addition, the PUCO and the KPSC approve rates for retail gas distribution service 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 and the State Utility Commissions, except for the PUCO, 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 and the State Utility Commissions, as applicable, 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 relevant State Utility Commission is required for Duke Energy’s regulated operating companies to issue securities.

Electric generation supply service has been deregulated in Ohio. Accordingly, Duke Energy Ohio’s electric generation has been deregulated, and Duke Energy Ohio is in a competitive retail electric service market in the state of Ohio. Under applicable legislation governing the deregulation of generation, Duke Energy Ohio has implemented a RSP including a MBSSO approved by the PUCO. The RSP, among other things, allows Duke Energy Ohio to recover increased costs associated with environmental expenditures on its deregulated generating fleet, capacity reserves, and provides for a fuel and emission allowance cost recovery mechanism through 2008. (see Note 4 to the Consolidated Financial Statements, “Regulatory Matters—U.S. Franchised Electric and Gas. Rate Related Information” for additional information.)

Federal

Regulations of FERC and the State Utility Commissions govern access to regulated electric and gas 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. In 2005 and 2006, FERC initiated several rulemakings as directed by the Energy Policy Act of 2005. These rule makings have now been completed, subject to certain appeals. Duke Energy does not believe that the appeals of 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.

Duke Energy Ohio, Duke Energy Kentucky and Duke Energy Indiana are transmission owners in a regional transmission organization operated by the Midwest Independent Transmission System Operator, Inc. (Midwest ISO), a non-profit organization which maintains functional control over the combined transmission systems of its members. In 2005, the Midwest ISO began administering an energy market within its footprint.

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As a result of previous FERC rulemakings related to RTOs, 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, 2006, Duke Energy Carolinas 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 17, 2001 the IURC approved the transfer of functional control of the operation of the Duke Energy Indiana transmission system to the Midwest ISO, an RTO established in 1998. On June 1, 2005, the IURC authorized Duke Energy Indiana to transfer control area operations tasks and responsibilities and transfer dispatch and Day 2 energy markets tasks and responsibilities to the Midwest ISO.

The Midwest ISO is the provider of transmission service requested on the transmission facilities under its tariff. It is responsible for the reliable operation of those transmission facilities and the regional planning of new transmission facilities. The Midwest ISO administers energy markets utilizing Locational Marginal Pricing (LMP) (i.e., the energy price for the next MW may vary throughout the Midwest ISO market based on transmission congestion and energy losses) as the methodology for relieving congestion on the transmission facilities under its functional control.

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 ISO to act as the IE and Potomac Economics, Ltd. to act as the IM. The IE and IM began operations on 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.

Other

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 have 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 with the exception of the Dillsboro Project, for which Duke Energy has filed an application to surrender the license. Duke Energy expects to remove this project’s dam and powerhouse, as part of the multi-stakeholder licensing agreement.

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

As previously discussed, effective January 2, 2007, Duke Energy consummated its spin-off of the natural gas transmission businesses (Spectra Energy), which includes the Natural Gas Transmission segment, to shareholders. The following business description of Natural Gas Transmission relates to 2006 and is not intended to describe the business subsequent to the spin-off on January 2, 2007.

Natural Gas Transmission provides transportation and storage of natural gas for customers in various regions of the Eastern and Southeastern United States, the Maritimes Provinces and the Pacific Northwest in the United States and Canada and in the province of Ontario 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. Natural Gas Transmission does business primarily through DEGT.

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 our markets. For 2006, Natural Gas Transmission’s

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proportional throughput for its pipelines totaled 3,248 trillion British thermal units (TBtu), compared to 3,410 TBtu in 2005. 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. (For detailed descriptions of Natural Gas Transmission’s pipeline systems, see “Properties—Natural Gas Transmission”.)

Natural Gas Transmission, through Market Hub Partners (MHP), wholly owns natural gas salt cavern storage facilities in Southeast Texas and Louisiana. MHP markets natural gas storage services to pipelines, LDCs, producers, end users and natural gas marketers. Texas Eastern 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 L.L.C. and Early Grove Storage Company, subsidiaries of Natural Gas Transmission. These underground reservoir and salt cavern storage facilities are located in Virginia and provide storage services to customers in the Southeastern United States.

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 1.3 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 owns and operates gathering pipelines and gas processing plants in Western Canada through its British Columbia Pipeline System (BC Pipeline) operations and provides 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, these facilities remove various NGLs. Natural Gas Transmission’s Empress system assets located in Western Canada provide extraction, storage, transportation, distribution and marketing of NGLs in Canada and the U.S. Natural Gas Transmission also provides gathering and processing services through its 46% interest in the Canadian Midstream operations in Western Canada that are owned by Spectra Energy Income Fund (Income Fund), formerly Duke Energy Income Fund. Natural Gas Transmission continues to operate and manage this business.

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Competition

Natural Gas Transmission’s transportation, storage and gas gathering and processing businesses compete with similar facilities that serve its supply and market areas in the transportation, storage, gathering and processing 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, propane and fuel oils. Several factors influence the demand for natural gas including price changes, the availability of natural gas and other forms of energy, the level of business activity, conservation, legislation, governmental regulations, the ability to convert to alternative fuels, weather and other factors.

Regulation

Most of Natural Gas Transmission’s pipeline and storage operations in the U.S. are regulated by the FERC. The FERC regulates natural gas transportation in U.S. interstate commerce including the establishment of rates for services. (For more information on rate matters, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters—Natural Gas Transmission.”) The FERC also regulates the construction of U.S. interstate pipelines and storage facilities, including extension, enlargement or abandonment of such facilities. In addition, certain operations are subject to oversight by state regulatory commissions.

FERC regulations restrict U.S. interstate pipelines from sharing transmission or customer information with energy affiliates and require that U.S. interstate pipelines function independently of their energy affiliates. These regulations affect the activities of non-regulated affiliates with Natural Gas Transmission.

The FERC may propose and implement new rules and regulations affecting interstate natural gas transmission companies, which remain subject to the FERC’s jurisdiction. These initiatives may also affect certain transportation of gas by intrastate pipelines.

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.

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The natural gas 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 jurisdiction similar to the FERC for regulating rates, regulating the operations of facilities and construction of any additional facilities. Natural Gas Transmission’s federally regulated gathering and processing facilities and business in Western Canada is regulated by the NEB pursuant to a framework for light-handed regulation under which the NEB acts on a complaints basis for rates associated with that business. Similarly, the rates charged by the Midstream operation for gathering and processing services in Western Canada are regulated on a complaints basis by applicable provincial regulators. The Empress NGL businesses are not under any form of rate regulation.

FIELD SERVICES

As previously discussed, effective January 2, 2007, Duke Energy consummated the spin-off of the natural gas transmission businesses (Spectra Energy), including Duke Energy’s investment in DEFS, to shareholders. The following business description of Field Services relates to 2006 and is not intended to describe the business subsequent to the spin-off on January 2, 2007.

Field Services includes Duke Energy’s investment in DEFS, which gathers, compresses, processes, transports, trades and markets, and stores natural gas; and fractionates, transports, gathers, treats, processes, 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 and the Empress System have been transferred to the Natural Gas Transmission segment. Additionally, in February 2005, DEFS sold its wholly-owned subsidiary, Texas Eastern Products Pipeline Company, LLC (TEPPCO GP), the general partner of TEPPCO Partners L.P. (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.

In 2005, DEFS formed DCP Midstream Partners, LP (a master limited partnership). DCP Midstream Partners, LP (DCPLP) completed an IPO transaction in December 2005. 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, Mid-Continent, East Texas-North Louisiana, South, Central, Rocky Mountain and Gulf Coast. DEFS owns or operates approximately 56,000 miles of gathering and transmission pipe, with approximately 34,000 active receipt points.

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 53 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 six 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 8 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.

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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, natural gas and crude oil prices, which increased approximately 10%, decreased approximately 15% and increased approximately 15%, respectively, in 2006 compared to 2005. 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 Financial Condition and Results of Operations, 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/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.

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COMMERCIAL POWER

Commercial Power owns, operates and manages non-regulated merchant power plants and engages in the wholesale marketing and procurement of electric power, fuel and emission allowances related to these plants as well as other contractual positions. Commercial Power also develops and implements customized energy solutions. Commercial Power’s generation asset fleet consists of Duke Energy Ohio’s non-regulated generation in Ohio, acquired from Cinergy in April 2006 and the five Midwestern gas-fired merchant generation assets that were a portion of former DENA. Commercial Power’s assets are comprised of approximately 8,100 net megawatts of power generation primarily located in the Midwestern United States. The asset portfolio has a diversified fuel mix with base-load and mid-merit coal-fired units as well as combined cycle and peaking natural gas-fired units. Most of the generation asset output in Ohio has been contracted through the RSP described below. See Item 2. “Properties” for further discussion of the generating facilities.

Commercial Power, through Duke Energy Generation Services (DEGS), is an on-site energy solutions and utility services provider. Primarily through joint ventures, DEGS engages in utility systems construction, operation and maintenance of utility facilities, as well as cogeneration. Cogeneration is the simultaneous production of two or more forms of usable energy from a single source. DEGS also owns coal-based synthetic fuel production facilities which convert coal feedstock into synthetic fuel for sale to third parties. The synthetic fuel produced in these facilities qualifies for tax credits through 2007 in accordance with Internal Revenue code Section 29/45K if certain requirements are satisfied.

In October 2006, Duke Energy completed the sale of Commercial Power’s energy marketing and trading activities, which were acquired in the Cinergy merger. Additionally, in December 2006, Duke Energy completed the sale of Caledonia Power 1, LLC, which is the project company that operated and managed the Caledonia peaking generation facility in Mississippi.

Competition

Commercial Power primarily competes for wholesale contracts for the purchase and sale of electricity, coal, natural gas and emission allowances. The market price of commodities and services, along with the quality and reliability of services provided, drive

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competition in the energy marketing business. Commercial Power’s main competitors include public utilities, wholesale power, coal and natural gas marketers and other merchant generation companies in the Midwestern United States, financial institutions and hedge funds engaged in energy commodity marketing and trading.

Duke Energy Ohio operates under the RSP MBSSO which was approved by the PUCO in November 2004, and which provides price certainty through December 31, 2008. In March 2005, the OCC appealed the PUCO’s approval of the MBSSO and in November 2006, the Ohio Supreme Court remanded the PUCO’s order approving the MBSSO for further evidentiary support and explanation, and to require Duke Energy Ohio to disclose certain confidential commercial agreements between Duke Energy Ohio and other parties previously requested by the OCC. Hearings on remand are expected to occur in March 2007. A major feature of the MBSSO is the POLR Charge. Duke Energy Ohio has been collecting a POLR charge from non-residential customers since January 1, 2005, and from residential customers since January 1, 2006. The POLR charge consists of the following discrete charges:

Regulation

Commercial Power is subject to regulation at the state level, primarily from PUCO and at the federal level, primarily from FERC. The PUCO approves prices for all retail electric generation sales by Duke Energy Ohio for its native retail service territory.

Regulations of FERC and the PUCO 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 Commercial Power.

Other 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.)

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 equity investments in: National Methanol Company (NMC), located in Saudi Arabia, which is a leading regional producer of methanol and methyl tertiary butyl ether (MTBE), Compania de Servicios de Compresion de Campeche, S.A. (Campeche), located in the Cantarell oil field in the Bay of Campeche, Mexico, which compresses and dehydrates natural gas and extracts NGL’s, and Attiki Gas Supply S.A. (Attiki), located in Athens, Greece, which is a natural gas distributor and was acquired in connection with the Cinergy merger.

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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 3,996 net MW of generation facilities. The following map shows the locations of International Energy’s facilities, including non-generation facilities in Saudi Arabia, Mexico and Greece.

In December 2006, Duke Energy engaged in discussions with a potential buyer of International Energy’s assets in Bolivia. Such discussions to sell the assets were subject to a binding agreement between the parties, which was finalized in February 2007, and resulted in the sale of International Energy’s 50 percent ownership interest in two hydroelectric power plants near Cochabamba, Bolivia to Econergy International.

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

As previously discussed, effective September 7, 2006, Duke Energy completed the Crescent JV transaction, whereby Duke Energy sold an effective 50% interest in Crescent.

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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, 2006, Crescent owned 1.1 million square feet of commercial, industrial and retail space, with an additional 0.3 million square feet under construction. This portfolio included 0.5 million square feet of office space, 0.5 million square feet of warehouse space and 0.4 million square feet of retail space. Crescent’s residential developments include high-end country club and golf course communities, with individual lots sold to custom builders and tract developments sold to national builders. Crescent had three multi-family communities at December 31, 2006, including two operating properties and one property under development. As of December 31, 2006, Crescent also managed approximately 6,217 acres of land.

Competition and Regulation

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

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

OTHER

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. Duke Energy also participates in DETM. DETM is 40% owned by ExxonMobil 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 former DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. Management retained former 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.

The results of operations of former DENA’s Western and Eastern United States generation assets, including related commodity contracts, the divested Ft. Frances generation assets, contracts related to former 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.

During 2006, Other also included certain unallocated corporate costs, certain discontinued hedges, DukeNet, Duke Energy’s 50% interest in D/FD, Cinergy’s equity financing business and Bison. Duke Energy had exited the merchant finance business at Duke Capital Partners LLC (DCP) as of the end of 2005 and all of the results of operations for DCP for the years ended December 31, 2005 and 2004 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 Duke Energy Merchants, LLC (DEM) in an orderly manner. As of December 31, 2006, DEM has completed the exit 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). The results of operations for DEM have been classified as discontinued operations for all periods presented.

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, 2006. Previously, D/FD provided comprehensive engineering, procurement, construction, commissioning and operating plant services for fossil-fueled electric power generating facilities worldwide.

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Cinergy has a business which invests in start up businesses utilizing new energy technologies as well as technologies utilizing energy infrastructure, such as broadband over power line services.

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:

(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, 2006, Duke Energy had approximately 25,600 employees. A total of approximately 6,600 operating and maintenance employees were represented by unions.

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EXECUTIVE OFFICERS OF DUKE ENERGY

HENRY B. BARRON JR., 56, Group Executive and Chief Nuclear Officer. Mr. Barron assumed his current position in November 2006. Prior to that, he served as Group Vice President, Nuclear Generation and Chief Nuclear Officer since April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Mr. Barron served as Group Vice President, Nuclear Generation and Chief Nuclear Officer of Duke Energy since March 2004. Prior to that, he served as Executive Vice President, Nuclear Generation of Duke Energy from January 2004 to March 2004, Senior Vice President, Nuclear Operations of Duke Energy from September 2002 to January 2004 and Vice President, McGuire Nuclear Station of Duke Energy from March 1999 to September 2002.

LYNN J. GOOD, 47, Senior Vice President and Treasurer. Ms. Good assumed her current position in December 2006. Prior to that, she served as Vice President and Treasurer since April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Ms. Good served as Executive Vice President and Chief Financial Officer of Cinergy from August 2005, Vice President, Finance and Controller of Cinergy from November 2003 to August 2005 and Vice President, Financial Project Strategy of Cinergy from May 2003 to November 2003. Prior to that, Ms. Good was a partner with the international accounting firm Deloitte & Touche LLP in Cincinnati, Ohio from May 2002 to May 2003. And, prior to that, she was a partner with the international accounting firm Arthur Anderson LLP from 1992 to May 2002.

DAVID L. HAUSER, 55, Group Executive and Chief Financial Officer. Mr. Hauser assumed his current position in April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Mr. Hauser served as Group Vice President and Chief Financial Officer of Duke Energy since March 2004 and as Acting Chief Financial Officer of Duke Energy from December 2003 to March 2004. Prior to that, he served as Senior Vice President and Treasurer of Duke Energy from July 1998 to December 2003.

MARC E. MANLY, 54, Group Executive and Chief Legal Officer. Mr. Manly assumed his current position in April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Mr. Manly served as Executive Vice President and Chief Legal Officer of Cinergy since November 2002. Prior to that, Mr. Manly served as Managing Director, Law and Governmental Affairs, General Counsel and Corporate Secretary of NewPower Holdings, Inc. from April 2000 to August 2002. On June 11, 2002, New Power Holdings, Inc. and its affiliates, TNPC Holdings, Inc. and the NewPower Company, filed a petition for relief under Chapter 11 of The United States Bankruptcy Code.

WILLIAM R. McCOLLUM JR, 55, Group Executive and Chief Regulated Generation Officer. Mr. McCollum assumed his current position in November 2006. Prior to that, he served as Group Vice President, Regulated Fossil/Hydro Generation since April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Mr. McCollum served as Vice President, Strategy and Business Development for Duke Energy Carolinas since January 2005. Prior to that, Mr. McCollum served as Senior Vice President, Nuclear Support of Duke Energy from September 2002 to January 2005 and Vice Presdient, Oconee Nuclear Station of Duke Energy from March 1999 to September 2002.

THOMAS C. O’CONNOR, 51, Group Executive and President, Commercial Businesses. Mr. O’Connor assumed his current position in October 2006. Prior to that he served as Group Executive and Chief Operating Officer, U.S. Franchised Electric and Gas since April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Mr. O’Connor 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.

JAMES E. ROGERS, 59, Chairman, President and Chief Executive Officer. Mr. Rogers assumed the role of Chief Executive Officer and President in April 2006, upon the merger of Duke Energy and Cinergy and assumed the role of Chairman on January 2, 2007. Until the merger of Duke Energy and Cinergy, Mr. Rogers served as Chairman of the Board of Cinergy since 2000 and as Chief Executive Officer of Cinergy since 1995.

CHRISTOPHER C. ROLFE, 56, Group Executive and Chief Administrative Officer. Mr. Rolfe assumed his current position in November 2006. Prior to that, he served as Group Executive and Chief Human Resources Officer since April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Mr. Rolfe served as Vice President, Human Resources of Duke Energy since January 2005. Prior to that, Mr. Rolfe served as Senior Vice President, Strategy, Planning & Human Resources of Duke Energy from March 2003 to January 2005 and Senior Vice President, Human Resources of Duke Energy from January 2001 to March 2003.

RUTH G. SHAW, 58, Executive Advisor to the Chairman, President and Chief Executive Officer. Dr. Shaw assumed her current position in October 2006. Prior to that she served as Group Executive, Public Policy and President, Duke Nuclear since April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Dr. Shaw served as President and Chief Executive Officer, Duke Energy Carolinas since February 2003. Prior to that Dr. Shaw served as Executive Vice President and Chief Administrative Officer of Duke Energy Carolinas from 1997 to February 2003

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B. KEITH TRENT, 47, Group Executive and Chief Strategy and Policy Officer. Mr. Trent assumed his current position in October 2006. Prior to that he served as Group Executive and Chief Development Officer since April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Mr. Trent served as Executive Vice President, General Counsel and Secretary of Duke Energy since March 2005. Prior to that he served as General Counsel, Litigation of Duke Energy from May 2002 to March 2005. Prior to that Mr. Trent served as a partner in the law firm Snell, Brannian & Trent since October 1991.

JAMES L. TURNER, 47, Group Executive and President, U.S. Franchised Electric and Gas. Mr. Turner assumed his current position in October 2006. Prior to that he served as Group Executive and Chief Commercial Officer, U.S. Franchised Electric and Gas since April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Mr. Turner served as President of Cinergy since 2005, Executive Vice President and Chief Financial Officer of Cinergy from 2004 to 2005 and Executive Vice President and Chief Executive Officer, Regulated Business Unit of Cinergy from 2001 to 2004.

STEVEN K. YOUNG, 48, Senior Vice President and Controller. Mr. Young assumed his current position in December 2006. Prior to that he served as Vice President and Controller since April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Mr. Young served as Vice President and Controller of Duke Energy since June 2005. Prior to that Mr. Young served as Senior Vice President and Chief Financial Officer of Duke Energy Carolinas from March 2003 to June 2005 and as Vice President, Rates and Regulatory Affairs of Duke Energy Carolinas from March 1998 to March 2003.

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.

Item 1A. Risk Factors.

The risk factors discussed herein relate specifically to risks associated with Duke Energy subsequent to the spin-off of its natural gas businesses in January 2007. Accordingly, risks associated with the Spectra Energy businesses are not discussed in this section.

Duke Energy may be unable to achieve some or all of the benefits that are expected to be achieved in connection with the spin-off of its natural gas businesses in January 2007.

Duke Energy may not be able to achieve the full strategic and financial benefits that are expected to result from the spin-off transaction or such benefits may be delayed or may not occur at all.

Duke Energy’s franchised electric revenues, earnings and results are dependent on state legislation and regulation that affect electric generation, transmission, distribution and related activities, which may limit Duke Energy’s ability to recover costs.

Duke Energy’s franchised electric businesses are regulated on a cost-of-service/rate-of-return basis subject to the statutes and regulatory commission rules and procedures of North Carolina, South Carolina, Ohio, Indiana and Kentucky. If Duke Energy’s franchised electric earnings exceed the returns established by the state regulatory commissions, Duke Energy’s retail electric rates may be subject to review by the commissions and possible reduction, which may decrease Duke Energy’s future earnings. Additionally, if regulatory bodies do not allow recovery of costs incurred in providing service on a timely basis, Duke Energy’s future earnings could be negatively impacted.

Duke Energy may incur substantial costs and liabilities due to Duke Energy’s ownership and operation of nuclear generating facilities.

Duke Energy’s ownership interest in and operation of three nuclear stations subject Duke Energy to various risks including, among other things: the potential harmful effects on the environment and human health resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials; limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations; and uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives.

Duke Energy’s ownership and operation of nuclear generation facilities requires Duke Energy to meet licensing and safety-related requirements imposed by the NRC. In the event of non-compliance, the NRC may increase regulatory oversight, impose fines, and/or shut down a unit, depending upon its assessment of the severity of the situation. Revised security and safety requirements promulgated by the

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NRC, which could be prompted by, among other things, events within or outside of Duke Energy’s control, such as a serious nuclear incident at a facility owned by a third-party, could necessitate substantial capital and other expenditures at Duke Energy’s nuclear plants, as well as assessments against Duke Energy to cover third-party losses. In addition, if a serious nuclear incident were to occur, it could have a material adverse effect on Duke Energy’s results of operations and financial condition.

Duke Energy’s ownership and operation of nuclear generation facilities also requires Duke Energy to maintain funded trusts that are intended to pay for the decommissioning costs of Duke Energy’s nuclear power plants. Poor investment performance of these decommissioning trusts’ holdings and other factors impacting decommissioning costs could unfavorably impact Duke Energy’s liquidity and results of operations as Duke Energy could be required to significantly increase its cash contributions to the decommissioning trusts.

Duke Energy’s plans for future expansion and modernization of its generation fleet subject it to risk of future price and inflationary increases in the cost of such expenditures as well as the risk of recovering such costs in a timely manner which could materially impact Duke Energy’s financial condition, results of operations or cash flows.

During the three-year period from 2007 to 2009, Duke Energy anticipates annual capital expenditures of approximately $3.5 billion, for a total of approximately $10 billion. Duke Energy has begun to see significant increases in the estimated costs of these capital projects as a result of strong domestic and international demand for the material, equipment, and labor necessary to construct these facilities. Increases in costs related to materials and services required to expand and modernize Duke Energy’s generation fleet as well as Duke Energy’s ability to recover these costs in a timely manner could materially impact Duke Energy’s consolidated financial condition, results of operations or cash flows.

Duke Energy’s sales may decrease if Duke Energy is unable to gain adequate, reliable and affordable access to transmission assets.

Duke Energy depends on transmission and distribution facilities owned and operated by utilities and other energy companies to deliver the electricity Duke Energy sells to the wholesale market. FERC’s power transmission regulations require wholesale electric transmission services to be offered on an open-access, non-discriminatory basis; however, not all markets are as open and accessible as needed. If transmission is disrupted, or if transmission capacity is inadequate, Duke Energy’s ability to sell and deliver products may be hindered. Such disruptions could also hinder Duke Energy from providing electricity to Duke Energy’s retail electric customers and may materially adversely affect Duke Energy’s business.

The different regional power markets have changing regulatory structures, which could affect Duke Energy’s growth and performance in these regions. In addition, the independent system operators who oversee the transmission systems in regional power markets have imposed in the past, and may impose in the future, price limitations and other mechanisms to address volatility in the power markets. These types of price limitations and other mechanisms may adversely impact the profitability of Duke Energy’s wholesale power marketing and trading business.

Duke Energy may be unable to secure long term power purchase agreements or transmission agreements, which could expose Duke Energy’s sales to increased volatility.

In the future, Duke Energy may not be able to secure long-term power purchase agreements for Duke Energy’s unregulated power generation facilities. If Duke Energy is unable to secure these types of agreements, Duke Energy’s sales volumes would be exposed to increased volatility. Without the benefit of long-term power purchase agreements, Duke Energy cannot assure that it will be able to sell the power generated by Duke Energy’s facilities or that Duke Energy’s facilities will be able to operate profitably. The inability to secure these agreements could materially adversely affect Duke Energy’s results and business.

Competition in the unregulated markets in which Duke Energy operates may adversely affect the growth and profitability of Duke Energy’s business.

Duke Energy may not be able to respond in a timely or effective manner to the many changes designed to increase competition in the electricity industry. To the extent competitive pressures increase, the economics of Duke Energy’s business may come under long-term pressure.

In addition, regulatory changes have been proposed to increase access to electricity transmission grids by utility and non-utility purchasers and sellers of electricity. These changes could continue the disaggregation of many vertically-integrated utilities into separate generation, transmission, distribution and retail businesses. As a result, a significant number of additional competitors could become active in the wholesale power generation segment of Duke Energy’s industry.

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Duke Energy may also face competition from new competitors that have greater financial resources than Duke Energy does, seeking attractive opportunities to acquire or develop energy assets or energy trading operations both in the United States and abroad. These new competitors may include sophisticated financial institutions, some of which are already entering the energy trading and marketing sector, and international energy players, which may enter regulated or unregulated energy businesses. This competition may adversely affect Duke Energy’s ability to make investments or acquisitions.

Duke Energy must meet credit quality standards. If Duke Energy or its rated subsidiaries are unable to maintain an investment grade credit rating, Duke Energy would be required under credit agreements to provide collateral in the form of letters of credit or cash, which may materially adversely affect Duke Energy’s liquidity. Duke Energy cannot be sure that it and its rated subsidiaries will maintain investment grade credit ratings.

Each of Duke Energy’s and its rated subsidiaries senior unsecured long-term debt is rated investment grade by various rating agencies. Duke Energy cannot be sure that the senior unsecured long-term debt of Duke Energy or its rated subsidiaries will be rated investment grade.

If the rating agencies were to rate Duke Energy or its rated subsidiaries below investment grade, the entity’s borrowing costs would increase, perhaps significantly. In addition, the entity would likely be required to pay a higher interest rate in future financings, and its potential pool of investors and funding sources would likely decrease. Further, if its short-term debt rating were to fall, the entity’s access to the commercial paper market could be significantly limited. Any downgrade or other event negatively affecting the credit ratings of Duke Energy’s subsidiaries could make their costs of borrowing higher or access to funding sources more limited, which in turn could increase Duke Energy’s need to provide liquidity in the form of capital contributions or loans to such subsidiaries, thus reducing the liquidity and borrowing availability of the consolidated group.

A downgrade below investment grade could also trigger termination clauses in some interest rate and foreign exchange derivative agreements, which would require cash payments. All of these events would likely reduce Duke Energy’s liquidity and profitability and could have a material adverse effect on Duke Energy’s financial position, results of operations or cash flows.

Duke Energy relies on access to short-term money markets and longer-term capital markets to finance Duke Energy’s capital requirements and support Duke Energy’s liquidity needs, and Duke Energy’s access to those markets can be adversely affected by a number of conditions, many of which are beyond Duke Energy’s control.

Duke Energy’s business is financed to a large degree through debt and the maturity and repayment profile of debt used to finance investments often does not correlate to cash flows from Duke Energy’s assets. Accordingly, Duke Energy relies on access to both short-term money markets and longer-term capital markets as a source of liquidity for capital requirements not satisfied by the cash flow from Duke Energy’s operations and to fund investments originally financed through debt instruments with disparate maturities. If Duke Energy is not able to access capital at competitive rates, Duke Energy’s ability to finance Duke Energy’s operations and implement Duke Energy’s strategy will be adversely affected.

Market disruptions may increase Duke Energy’s cost of borrowing or adversely affect Duke Energy’s ability to access one or more financial markets. Such disruptions could include: economic downturns; the bankruptcy of an unrelated energy company; capital market conditions generally; market prices for electricity and gas; terrorist attacks or threatened attacks on Duke Energy’s facilities or unrelated energy companies; or the overall health of the energy industry. Restrictions on Duke Energy’s ability to access financial markets may also affect Duke Energy’s ability to execute Duke Energy’s business plan as scheduled. An inability to access capital may limit Duke Energy’s ability to pursue improvements or acquisitions that Duke Energy may otherwise rely on for future growth.

Duke Energy maintains revolving credit facilities to provide back-up for commercial paper programs and/or letters of credit at various entities. These facilities typically include financial covenants which limit the amount of debt that can be outstanding as a percentage of the total capital for the specific entity. Failure to maintain these covenants at a particular entity could preclude that entity from issuing commercial paper or letters of credit or borrowing under the revolving credit facility and could require other of Duke Energy’s affiliates to immediately pay down any outstanding drawn amounts under other revolving credit agreements.

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, political conditions and policies of foreign governments. These risks may delay or reduce Duke Energy’s realization of value from Duke Energy’s international projects.

Duke Energy currently owns and may acquire and/or dispose of material energy-related investments and projects outside the United States. The economic, regulatory, market and political conditions in some of the countries where Duke Energy has interests or in which

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Duke Energy may explore development, acquisition or investment opportunities could present risks related to, among others, Duke Energy’s ability to obtain financing on suitable terms, Duke Energy’s customers’ ability to honor their obligations with respect to projects and investments, delays in construction, limitations on Duke Energy’s ability to enforce legal rights, and interruption of business, as well as risks of war, expropriation, nationalization, renegotiation, trade sanctions or nullification of existing contracts and changes in law, regulations, market rules or tax policy.

Duke Energy’s investments and projects located outside of the United States expose Duke Energy to risks related to fluctuations in currency rates. These risks, and Duke Energy’s activities to mitigate such risks, may adversely affect Duke Energy’s cash flows and results of operations.

Duke Energy’s operations and investments outside the United States expose Duke Energy to risks related to fluctuations in currency rates. As each local currency’s value changes relative to the U.S. dollar—Duke Energy’s principal reporting currency—the value in U.S. dollars of Duke Energy’s assets and liabilities in such locality and the cash flows generated in such locality, expressed in U.S. dollars, also change.

Duke Energy selectively mitigates some risks associated with foreign currency fluctuations by, among other things, indexing contracts to the U.S. dollar and/or local inflation rates, hedging through debt denominated or issued in the foreign currency and hedging through foreign currency derivatives. These efforts, however, may not be effective and, in some cases, may expose Duke Energy to other risks that could negatively affect Duke Energy’s cash flows and results of operations.

Duke Energy’s primary foreign currency rate exposure is expected to be to the Brazilian Real. A 10% devaluation in the currency exchange rate in all of Duke Energy’s exposure currencies would result in an estimated net loss on the translation of local currency earnings of approximately $7 million. The consolidated balance sheets would be negatively impacted by such a devaluation by approximately $120 million through cumulative currency translation adjustments.

Duke Energy is exposed to credit risk of counterparties with whom Duke Energy does business.

Adverse economic conditions affecting, or financial difficulties of, counterparties with whom Duke Energy does business could impair the ability of these counterparties to pay for Duke Energy’s services or fulfill their contractual obligations, or cause them to delay such payments or obligations. Duke Energy depends on these counterparties to remit payments on a timely basis. Any delay or default in payment could adversely affect Duke Energy’s cash flows, financial position or results of operations.

Poor investment performance of pension plan holdings and other factors impacting pension plan costs could unfavorably impact Duke Energy’s liquidity and results of operations.

Duke Energy’s costs of providing non-contributory defined benefit pension plans are dependent upon a number of factors, such as the rates of return on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plans, future government regulation and Duke Energy’s required or voluntary contributions made to the plans. While Duke Energy complies with the minimum funding requirements as of September 30, 2006, Duke Energy has certain qualified U.S. pension plans with obligations which exceeded the value of plan assets by approximately $500 million. Without sustained growth in the pension investments over time to increase the value of Duke Energy’s plan assets and depending upon the other factors impacting Duke Energy’s costs as listed above, Duke Energy could be required to fund its plans with significant amounts of cash. Such cash funding obligations could have a material impact on Duke Energy’s cash flows, financial position or results of operations.

Duke Energy is subject to numerous environmental laws and regulations that require significant capital expenditures, can increase Duke Energy’s cost of operations, and which may impact or limit Duke Energy’s business plans, or expose Duke Energy to environmental liabilities.

Duke Energy is subject to numerous environmental laws and regulations affecting many aspects of Duke Energy’s present and future operations, including air emissions (such as reducing NO_x, SO₂ and mercury emissions in the U.S., or potential future control of greenhouse-gas emissions), water quality, wastewater discharges, solid waste and hazardous waste. These laws and regulations can result in increased capital, operating, and other costs. These laws and regulations generally require Duke Energy to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Compliance with environmental laws and regulations can require significant expenditures, including expenditures for clean up costs and damages arising out of contaminated properties, and failure to comply with environmental regulations may result in the imposition of fines, penalties and injunctive measures affecting operating assets. The steps Duke Energy takes to ensure that its facilities are in compliance could be prohibitively expensive. As a result,

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Duke Energy may be required to shut down or alter the operation of its facilities, which may cause Duke Energy to incur losses. Further, Duke Energy’s regulatory rate structure and Duke Energy’s contracts with customers may not necessarily allow Duke Energy to recover capital costs Duke Energy incurs to comply with new environmental regulations. Also, Duke Energy may not be able to obtain or maintain from time to time all required environmental regulatory approvals for Duke Energy’s operating assets or development projects. If there is a delay in obtaining any required environmental regulatory approvals, if Duke Energy fails to obtain and comply with them or if environmental laws or regulations change and become more stringent, then the operation of Duke Energy’s facilities or the development of new facilities could be prevented, delayed or become subject to additional costs. Although it is not expected that the costs of complying with current environmental regulations will have a material adverse effect on Duke Energy’s cash flows, financial position or results of operations, no assurance can be made that the costs of complying with environmental regulations in the future will not have such an effect.

There is growing consensus that some form of regulation will be forthcoming at the federal level with respect to greenhouse gas emissions (including CO₂) and such regulation could result in the creation of substantial additional costs in the form of taxes or emission allowances.

In addition, Duke Energy is generally responsible for on-site liabilities, and in some cases off-site liabilities, associated with the environmental condition of Duke Energy’s power generation facilities and natural gas assets which Duke Energy has acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with some acquisitions and sales of assets, Duke Energy may obtain, or be required to provide, indemnification against some environmental liabilities. If Duke Energy incurs a material liability, or the other party to a transaction fails to meet its indemnification obligations to Duke Energy, Duke Energy could suffer material losses.

Deregulation or restructuring in the electric industry may result in increased competition and unrecovered costs that could adversely affect Duke Energy’s financial condition, results of operations or cash flows and Duke Energy’s utilities’ businesses.

Increased competition resulting from deregulation or restructuring efforts, including from the Energy Policy Act of 2005, could have a significant adverse financial impact on Duke Energy and Duke Energy’s utility subsidiaries and consequently on Duke Energy’s results of operations, financial position, or cash flows. Increased competition could also result in increased pressure to lower costs, including the cost of electricity. Retail competition and the unbundling of regulated energy and gas service could have a significant adverse financial impact on Duke Energy and Duke Energy’s subsidiaries due to an impairment of assets, a loss of retail customers, lower profit margins or increased costs of capital. Duke Energy cannot predict the extent and timing of entry by additional competitors into the electric markets. Duke Energy cannot predict when Duke Energy will be subject to changes in legislation or regulation, nor can Duke Energy predict the impact of these changes on its financial position, results of operations or cash flows.

Duke Energy is involved in numerous legal proceedings, the outcome of which are uncertain, and resolution adverse to Duke Energy could negatively affect Duke Energy’s cash flows, financial condition or results of operations.

Duke Energy is subject to numerous legal proceedings. Litigation is subject to many uncertainties and Duke Energy cannot predict the outcome of individual matters with assurance. It is reasonably possible that the final resolution of some of the matters in which Duke Energy is involved could require Duke Energy to make additional expenditures, in excess of established reserves, over an extended period of time and in a range of amounts that could have a material effect on Duke Energy’s cash flows and results of operations. Similarly, it is reasonably possible that the terms of resolution could require Duke Energy to change Duke Energy’s business practices and procedures, which could also have a material effect on Duke Energy’s cash flows, financial position or results of operations.

Duke Energy’s results of operations may be negatively affected by sustained downturns or sluggishness in the economy, including low levels in the market prices of commodities, all of which are beyond Duke Energy’s control.

Sustained downturns or sluggishness in the economy generally affect the markets in which Duke Energy operates and negatively influence Duke Energy’s energy operations. Declines in demand for electricity as a result of economic downturns in Duke Energy’s franchised electric service territories will reduce overall electricity sales and lessen Duke Energy’s cash flows, especially as Duke Energy’s industrial customers reduce production and, therefore, consumption of electricity and gas. Although Duke Energy’s franchised electric business is subject to regulated allowable rates of return and recovery of fuel costs under a fuel adjustment clause, overall declines in electricity sold as a result of economic downturn or recession could reduce revenues and cash flows, thus diminishing results of operations.

Duke Energy also sells electricity into the spot market or other competitive power markets on a contractual basis. With respect to such transactions, Duke Energy is not guaranteed any rate of return on Duke Energy’s capital investments through mandated rates, and Duke Energy’s revenues and results of operations are likely to depend, in large part, upon prevailing market prices in Duke Energy’s regional markets and other competitive markets. These market prices may fluctuate substantially over relatively short periods of time and could reduce Duke Energy’s revenues and margins and thereby diminish Duke Energy’s results of operations.

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Lower demand for the electricity Duke Energy sells and lower prices for electricity result from multiple factors that affect the markets where Duke Energy sells electricity including:

These factors have led to industry-wide downturns that have resulted in the slowing down or stopping of construction of new power plants and announcements by Duke Energy and other energy suppliers and gas pipeline companies of plans to sell non-strategic assets, subject to regulatory constraints, in order to boost liquidity or strengthen balance sheets. Proposed sales by other energy suppliers could increase the supply of the types of assets that Duke Energy is attempting to sell. In addition, recent FERC actions addressing power market concerns could negatively impact the marketability of Duke Energy’s electric generation assets.

Duke Energy’s operating results may fluctuate on a seasonal and quarterly basis.

Electric power generation is generally a seasonal business. In most parts of the United States and other markets in which Duke Energy operates, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, demand for power peaks during the winter. Further, extreme weather conditions such as heat waves or winter storms could cause these seasonal fluctuations to be more pronounced. As a result, in the future, the overall operating results of Duke Energy’s businesses may fluctuate substantially on a seasonal and quarterly basis and thus make period comparison less relevant.

Duke Energy’s business is subject to extensive regulation that will affect Duke Energy’s operations and costs.

Duke Energy is subject to regulation by FERC and the NRC, by federal, state and local authorities under environmental laws and by state public utility commissions under laws regulating Duke Energy’s businesses. Regulation affects almost every aspect of Duke Energy’s businesses, including, among other things, Duke Energy’s ability to: take fundamental business management actions; determine the terms and rates of Duke Energy’s transmission and distribution businesses’ services; make acquisitions; issue equity or debt securities; engage in transactions between Duke Energy’s utilities and other subsidiaries and affiliates; and pay dividends. Changes to these regulations are ongoing, and Duke Energy cannot predict the future course of changes in this regulatory environment or the ultimate effect that this changing regulatory environment will have on Duke Energy’s business. However, changes in regulation (including re-regulating previously deregulated markets) can cause delays in or affect business planning and transactions and can substantially increase Duke Energy’s costs.

FERC has established certain market screens it employs to assess generation market power. Certain of these screens are difficult for a franchised utility 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 failed one of the applicable market screens. Under the FERC’s order, Duke Energy Carolinas must pay partial refunds and may prospectively make wholesale power sales within its control area only at cost-based rates.

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Certain events in the energy markets beyond Duke Energy’s control have increased the level of public and regulatory scrutiny in the energy industry and in the capital markets and could result in new laws or regulations which could have a negative impact on Duke Energy’s results of operations.

Due to certain events in the energy markets, regulated energy companies have been under increased scrutiny by regulatory bodies, capital markets and credit rating agencies. This increased scrutiny could lead to substantial changes in laws and regulations affecting Duke Energy, including new accounting standards that could change the way Duke Energy is required to record revenues, expenses, assets and liabilities. These types of regulations could have a negative impact on Duke Energy’s financial position, cash flows or results of operations or access to capital.

Potential terrorist activities or military or other actions could adversely affect Duke Energy’s business.

The continued threat of terrorism and the impact of retaliatory military and other action by the United States and its allies may lead to increased political, economic and financial market instability and volatility in prices for natural gas and oil which may materially adversely affect Duke Energy in ways Duke Energy cannot predict at this time. In addition, future acts of terrorism and any possible reprisals as a consequence of action by the United States and its allies could be directed against companies operating in the United States. Infrastructure and generation facilities such as Duke Energy’s nuclear plants could be potential targets of terrorist activities. The potential for terrorism has subjected Duke Energy’s operations to increased risks and could have a material adverse effect on Duke Energy’s business. In particular, Duke Energy may experience increased capital and operating costs to implement increased security for its plants, including its nuclear power plants under the NRC’s design basis threat requirements, such as additional physical plant security, additional security personnel or additional capability following a terrorist incident.

The insurance industry has also been disrupted by these events. As a result, the availability of insurance covering risks Duke Energy and Duke Energy’s competitors typically insure against may decrease. In addition, the insurance Duke Energy is able to obtain may have higher deductibles, higher premiums and more restrictive policy terms.

Item 1B. Unresolved Staff Comments.

None.

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Item 2. Properties.

U.S. FRANCHISED ELECTRIC AND GAS

As of December 31, 2006, 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), fifteen coal-fired stations with a combined net capacity of 13,552 MW, thirty-one hydroelectric stations (including two pumped-storage facilities) with a combined net capacity of 3,213 MW, fifteen CT stations with a combined net capacity of 5,245 MW and two CC stations with a combined net capacity of 560 MW. The stations are located in North Carolina, South Carolina, Indiana, Ohio and Kentucky. The MW displayed in the table below are based on summer capacity.

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In addition, as of December 31, 2006, U.S. Franchised Electric and Gas owned approximately 20,700 conductor miles of electric transmission lines, including 600 miles of 525 kilovolts, 1,700 miles of 345 kilovolts, 3,300 miles of 230 kilovolts, 8,800 miles of 100 to 161 kilovolts, and 6,300 miles of 13 to 69 kilovolts. U.S. Franchised Electric and Gas also owned approximately 146,700 conductor miles of electric distribution lines, including 102,900 miles of overhead lines and 43,800 miles of underground lines, as of December 31, 2006 and approximately 8,900 miles of gas mains and service lines. As of December 31, 2006, the electric transmission and distribution systems had approximately 2,300 substations. U.S. Franchised Electric and Gas also owns three underground caverns with a total storage capacity of approximately 23 million gallons of liquid propane. This liquid propane is used in the three propane/air peak shaving plants located in Ohio and Kentucky. Propane/air peak shaving plants store propane and, when needed, vaporize the propane and mix with natural gas to supplement the natural gas supply during peak demand periods and emergencies.

Substantially all of Duke Energy Carolinas’ 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

As discussed in Item 1. “Business”, effective January 2, 2007, Duke Energy consummated the spin-off of its natural gas businesses, which includes the Natural Gas Transmission segment, to shareholders.

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.

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 2.0 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.

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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 thirteen natural gas processing plants and over 1,000 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.)

COMMERCIAL POWER

The following table provides information about Commercial Power’s merchant generation portfolio as of December 31, 2006. The MW displayed in the table below are based on summer capacity.

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

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INTERNATIONAL ENERGY

The following table provides information about International Energy’s generation portfolio in continuing operations as of December 31, 2006.

In December 2006, Duke Energy engaged in discussions with a potential buyer of International Energy’s assets in Bolivia. Such discussions to sell the assets were subject to a binding agreement between the parties, which was finalized in February 2007, and resulted in the sale of International Energy’s 50 percent ownership interest in two hydroelectric power plants near Cochabamba, Bolivia to Econergy International.

International Energy also owns a 25% equity interest in NMC. In 2006, the NMC produced approximately 850 thousand metric tons of methanol and 1 million metric tons of MTBE. In addition, International Energy owns a 50% equity interest in the Campeche natural gas processing and compression facility. Campeche has an installed processing capacity of 270 MMcf/d. International Energy also owns a 25% equity interest in Attiki, which is a natural gas distributor that has an exclusive 30 year license to supply natural gas to residential and commercial customers within the geographical area of Athens, Greece. (For additional information and a map showing International Energy’s properties, see “Business—International Energy” earlier in this section.)

CRESCENT

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

OTHER

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

Item 3. Legal Proceedings.

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

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

At the Duke Energy Corporation Annual Meeting of Shareholders on October 24, 2006, shareholders elected Roger Agnelli, Paul M. Anderson, William Barnet, III, G. Alex Bernhardt, Sr., Michael G. Browning, Phillip R. Cox, William T. Esrey, Ann Maynard Gray, James H. Hance, Jr., Dennis R. Hendrix, Michael E.J. Phelps, James T. Rhodes, James E. Rogers, Mary L. Schapiro and Dudley S. Taft to serve as directors until the next annual meeting of shareholders and until such Director’s successor is duly elected and qualified. Below is a tabulation of votes with respect to each nominee for director at the meeting:

In addition, shareholders at the meeting also approved the Duke Energy Corporation 2006 Long-Term Incentive Compensation Plan. There were 750,402,214 shares voted for the plan, 88,378,012 shares voted against the plan, and 15,211,175 shares abstained.

And, shareholders at the meeting also ratified the selection of Deloitte & Touche LLP to act as independent auditors for Duke Energy Corporation for 2006. There were 1,072,065,312 shares voted for the proposal, 20,828,427 shares voted against the proposal and 10,218,046 shares abstained.

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Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Duke Energy’s common stock is listed for trading on the New York Stock Exchange. As of February 23, 2007, there were approximately 175,252 common stockholders of record.

Common Stock Data by Quarter

On January 2, 2007, Duke Energy consummated the spin-off of the natural gas businesses to shareholders. In connection with this transaction, Duke Energy distributed all the shares of common stock of Spectra Energy to Duke Energy shareholders. The distribution ratio approved by Duke Energy’s Board of Directors was one-half share of Spectra Energy common stock for every share of Duke Energy common stock. Subsequent to the distribution, the market price of Duke Energy common stock was significantly less than the 2006 trading ranges above due to the fact that a proportionate share of the value of Duke Energy stock prior to the spin-off was transferred to Spectra Energy. Additionally, future dividends paid on Duke Energy common stock are expected to be less than the 2006 dividend of $1.26 per share as dividends are anticipated to be split proportionately between Duke Energy and Spectra Energy such that the sum of the dividends of the two stand-alone companies approximates the former total dividend of Duke Energy. Duke Energy expects to continue its policy of paying regular cash dividends, although there is no assurance as to the amount of future dividends because they depend on future earnings, capital requirements, and financial condition. Future dividends are subject to declaration by the Board of Directors.

Issuer Purchases of Equity Securities for Fourth Quarter of 2006

None.

Duke Energy previously announced plans to execute up to approximately $2.5 billion in common stock repurchases over a three year period. On May 9, 2005, Duke Energy announced plans to suspend additional repurchases under the open-market purchase plan, pending further assessment, primarily due to the merger with Cinergy. At the time of suspension, Duke Energy had repurchased 32.6 million shares of common stock for approximately $0.9 billion. During the first quarter of 2006, Duke Energy announced the commencement of up to $1 billion of additional share repurchases under the previously announced plan. During the first six months of 2006, Duke Energy repurchased approximately 17.5 million shares of common stock for approximately $0.5 billion. In June 2006, in connection with the plan to spin off Duke Energy’s natural gas businesses to Duke Energy shareholders, the share repurchase program was suspended. At the time of suspension, Duke Energy had repurchased approximately 50 million shares of common stock for approximately $1.4 billion under this repurchase plan. In October 2006, Duke Energy’s Board of Directors authorized the reactivation of the share repurchase plan for Duke Energy of up to $500 million of share repurchases after the spin-off of the natural gas businesses has been completed. As of December 31, 2006, the dollar value of shares that may yet be purchased under the plan is approximately $1.1 billion.

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Item 6. Selected Financial Data.^(a)

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

INTRODUCTION

Management’s Discussion and Analysis should be read in conjunction with the Consolidated Financial Statements and Notes for the years ended December 31, 2006, 2005 and 2004.

EXECUTIVE OVERVIEW

2006 Objectives. Duke Energy’s objectives for 2006, as outlined in the 2006 Charter, consisted of the following: