Form 10-K

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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

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

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,” “target,” 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:

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State, federal and foreign legislative and regulatory initiatives, including costs of compliance with existing and future environmental requirements, as well as rulings that affect cost and investment recovery or have an impact on rate structures;

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Costs and effects of legal and administrative proceedings, settlements, investigations and claims;

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Industrial, commercial and residential growth or decline in Duke Energy Corporation’s (Duke Energy) service territories, customer base or customer usage patterns;

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Additional competition in electric markets and continued industry consolidation;

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Political and regulatory uncertainty in other countries in which Duke Energy conducts business;

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The influence of weather and other natural phenomena on Duke Energy’s operations, including the economic, operational and other effects of storms, hurricanes, droughts and tornados;

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The timing and extent of changes in commodity prices, interest rates and foreign currency exchange rates;

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Unscheduled generation outages, unusual maintenance or repairs and electric transmission system constraints;

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The performance of electric generation and of projects undertaken by Duke Energy’s non-regulated businesses;

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The results of financing efforts, including Duke Energy’s ability to obtain financing on favorable terms, which can be affected by various factors, including Duke Energy’s credit ratings and general economic conditions;

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Declines in the market prices of equity securities and resultant cash funding requirements for Duke Energy’s defined benefit pension plans;

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The level of credit worthiness of counterparties to Duke Energy’s transactions;

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Employee workforce factors, including the potential inability to attract and retain key personnel;

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Growth in opportunities for Duke Energy’s business units, including the timing and success of efforts to develop domestic and international power and other projects;

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Construction and development risks associated with the completion of Duke Energy’s capital investment projects in existing and new generation facilities, including risks related to financing, obtaining and complying with terms of permits, meeting construction budgets and schedules, and satisfying operating and environmental performance standards, as well as the ability to recover costs from customers in a timely manner or at all;

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The effect of accounting pronouncements issued periodically by accounting standard-setting bodies; and

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The ability to successfully complete merger, acquisition or divestiture plans.

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.

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

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, for purposes of this discussion regarding the merger). In the second quarter of 2006, Duke Energy and Cinergy Corp. (Cinergy) consummated a merger which combined the Duke Energy and Cinergy regulated franchises, as well as deregulated generation in the Midwestern United States. On April 3, 2006, in accordance with the 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 transaction, 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 of Duke Energy common stock. 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.

On January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses, named Spectra Energy Corp. (Spectra Energy), including its wholly-owned subsidiary Spectra Energy Capital, LLC (Spectra Energy Capital, formerly Duke Capital LLC). The natural gas businesses spun off primarily consisted of Duke Energy’s Natural Gas Transmission business segment and Duke Energy’s 50% ownership interest in DCP Midstream, LLC (DCP Midstream, formerly Duke Energy Field Services, LLC), which was part of the Field Services business segment.

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 Duke Energy North America’s (DENA) remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. The exit plan was completed in the second quarter of 2006. Certain assets of the former DENA business were transferred to the Commercial Power business segment and certain operations that Duke Energy continues to wind-down are in Other.

Business Segments. At December 31, 2009, Duke Energy operated the following business segments, all of which are considered reportable segments under the applicable accounting rules: U.S. Franchised Electric and Gas, Commercial Power and International Energy. Duke Energy’s chief operating decision maker regularly reviews financial information about each of these business segments in deciding how to allocate resources and evaluate performance. For additional information on each of these business segments, including financial and geographic information about each reportable business segment, see Note 2 to the Consolidated Financial Statements, “Business Segments.”

The following is a brief description of the nature of operations of each of Duke Energy’s reportable business segments, as well as Other.

U.S. Franchised Electric and Gas. U.S. Franchised Electric and Gas generates, transmits, distributes and sells electricity in central and western North Carolina, western South Carolina, southwestern Ohio, central, north 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, LLC (Duke Energy Carolinas), the regulated transmission and distribution operations of 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). The substantial majority of U.S. Franchised Electric and Gas’ operations are regulated and, accordingly, these operations qualify for regulatory accounting treatment.

Commercial Power. Commercial Power owns, operates and manages 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’s generation operations in the Midwest consist of generation assets located in Ohio, acquired from Cinergy in April 2006, which are dedicated under the Electric Security Plan (ESP), and the five Midwestern gas-fired non-regulated generation assets that were a portion of the former DENA operations, which are dispatched into wholesale markets. Commercial Power’s assets, excluding wind energy generation assets, comprise approximately 7,550 net megawatts (MW) of power generation primarily located in the Midwestern U.S. The asset portfolio has a diversified fuel mix with baseload and mid-merit coal-fired units as well as combined cycle and peaking natural gas-fired units. Effective January 1, 2009, approximately half of Commercial Power’s Ohio-based generation assets operate under an ESP, which expires on December 31, 2011. Prior to the ESP, these generation assets had been contracted through the Rate Stabilization Plan (RSP), which expired on December 31, 2008. As a result of the approval of the ESP, certain of Commercial Power’s operations qualified for regulatory accounting treatment effective December 17, 2008. For more information on the RSP and ESP, as well as the reapplication of regulatory accounting to certain of its operations, see the “Commercial Power” section below. Commercial Power also has a retail sales subsidiary, Duke Energy Retail Sales (DERS), which is certified by the PUCO as a Competitive Retail Electric Service (CRES) provider in Ohio. DERS serves retail electric customers in Southwest, West Central and Northern Ohio with generation and other energy services at competitive rates. During 2009, due to increased levels of customer switching as a result of the competitive markets in Ohio, DERS has focused on acquiring customers that had previously been served by Duke Energy Ohio under the ESP, as well as those previously served by other Ohio franchised utilities. Through Duke Energy Generation Services, Inc. and its affiliates (DEGS), Commercial Power develops, owns and operates electric generation for large energy consumers, municipalities, utilities and industrial facilities. DEGS currently manages 6,150 MW of power generation at 21 facilities throughout the U.S. In addition, DEGS engages in the development, construction and operation of wind energy projects. Currently, DEGS has over 5,000 MW of wind energy projects in the development pipeline with approximately 735 net MW of wind generating capacity in operation as of December 31, 2009. DEGS is also developing transmission, solar and biomass projects.

International Energy. International Energy principally owns, operates and manages power generation facilities, and engages in sales and marketing of electric power and natural gas outside the U.S. It conducts operations primarily through Duke Energy International, LLC (DEI) and its affiliates and its activities target power generation in Latin America. Through its wholly-owned subsidiary Aguaytia Energy del Perú S.R.L. Ltda. (Aguaytia) and its equity method investment in National Methanol Company (NMC), which is located in Saudi Arabia, International Energy also engages in the production of natural liquid gas and methanol and methyl tertiary butyl ether (MTBE). Additionally, International Energy had an equity method investment in Attiki Gas Supply S.A. (Attiki), a natural gas distributor in Greece, which it decided to abandon, along with the related non-recourse debt, in December 2009.

Other. The remainder of Duke Energy’s operations is presented as Other. While it is not considered a business segment, Other primarily includes certain unallocated corporate costs, Bison Insurance Company Limited (Bison), Duke Energy’s wholly-owned captive insurance subsidiary, Duke Energy’s effective 50% interest in the Crescent JV (Crescent) and DukeNet Communications, LLC (DukeNet) and related telecom businesses. Additionally, Other includes the remaining portion of Duke Energy’s business formerly known as DENA that was not exited or transferred to Commercial Power, primarily Duke Energy Trading and Marketing, LLC (DETM), which is 60% owned by Duke Energy and 40% owned by Exxon Mobil Corporation and management is currently in the process of winding down.

Unallocated corporate costs include certain costs not allocable to Duke Energy’s reportable business segments, primarily governance costs, costs to achieve mergers and divestitures (such as the Cinergy merger and spin-off of Spectra Energy) and costs associated with certain corporate severance programs. Bison’s principal activities as a captive insurance entity include the insurance and reinsurance of various business risks and losses, such as property, business interruption and general liability of subsidiaries and affiliates of Duke Energy. Crescent, which develops and manages high-quality commercial, residential and multi-family real estate projects primarily in the Southeastern and Southwestern U.S, filed Chapter 11 petitions in a U.S. Bankruptcy Court in June 2009. As a result of recording its proportionate share of impairment charges recorded by Crescent during 2008, the carrying value of Duke Energy’s investment balance in Crescent is zero and Duke Energy discontinued applying the equity method of accounting to its investment in Crescent in the third quarter of 2008 and has not recorded its proportionate share of any Crescent earnings or losses since the third quarter of 2008. DukeNet develops, owns and operates a fiber optic communications network, primarily in the Southeast U.S., serving wireless, local and long-distance communications companies, internet service providers and other businesses and organizations.

General. 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.

The following sections describe the business and operations of each of Duke Energy’s reportable business segments, as well as Other. (For more information on the operating outlook of Duke Energy and its reportable 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 reportable business segments, see Note 2 to the Consolidated Financial Statements, “Business Segments.”)

U.S. Franchised Electric and Gas generates, transmits, distributes and sells electricity and transports and sells natural gas. It conducts operations primarily through Duke Energy Carolinas, the regulated transmission and distribution operations of 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 50,000 square miles with an estimated population of 11 million in central and western North Carolina, western South Carolina, southwestern Ohio, central, north central and southern Indiana, and northern Kentucky. U.S. Franchised Electric and Gas supplies electric service to approximately 4 million residential, commercial and industrial customers over 151,600 miles of distribution lines and a 20,900 mile transmission system. U.S. Franchised Electric and Gas provides domestic regulated transmission and distribution services for natural gas to approximately 500,000 customers in southwestern Ohio and northern Kentucky via approximately 7,200 miles of gas mains (gas distribution lines that serve as a common source of supply for more than one service line) and approximately 6,000 miles of 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 power generated by 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 one of the largest contributors to the economy in the region. Other sectors such as finance, insurance, real estate services, and local government also constitute key components of the states’ gross domestic product. Chemicals, rubber and plastics, textile and motor vehicle manufacturing industries were among the most significant contributors to the Duke Energy Carolinas’ industrial sales.

Duke Energy Ohio’s and Duke Energy Kentucky’s service area both have a diversified commercial and industrial presence. Major components of the economy include manufacturing, real estate and rental leasing, wholesale trade, financial and insurance services, retail trade, education, healthcare and professional/business services.

The primary metals industry, transportation equipment, chemicals, and paper and plastics were the most significant contributors to the area’s manufacturing output and Duke Energy Ohio’s and Duke Energy Kentucky’s industrial sales revenue for 2009. Food and beverage manufacturing, fabricated metals, and electronics also have a strong impact on the area’s economic growth and the region’s industrial sales.

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

The number of residential and general service customers within the U.S. Franchised Electric and Gas’ service territory, as well as sales to these customers, is expected to increase over time. However, growth in the near-term is being hampered by the current economic conditions. Industrial sales declined in 2009 when compared to 2008. While the decline in the sales volumes to industrial customers began to stabilize in the second half of 2009, the level of sales to industrial customers is expected to remain a smaller, yet still significant, portion of U.S. Franchised Electric and Gas sales in the foreseeable future.

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

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

Electric energy for U.S. Franchised Electric and Gas’ customers is generated by three nuclear generating stations with a combined owned capacity of 5,173 MW (including Duke Energy’s approximate 19% ownership in the Catawba Nuclear Station), fifteen coal-fired stations with an overall combined owned capacity of 13,189 MW (including Duke Energy’s 69% ownership in the East Bend Steam Station and 50.05% ownership in Unit 5 of the Gibson Steam Station), thirty-one hydroelectric stations (including two pumped-storage facilities) with a combined owned capacity of 3,263 MW, fifteen combustion turbine (CT) stations burning natural gas, oil or other fuels with an overall combined owned capacity of 5,047 MW and one combined cycle (CC) station burning natural gas with an owned capacity of 285 MW. 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, generation reliability during the summer, 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.

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 2009, approximately 98.1% of the total generated energy came from U.S. Franchised Electric and Gas’ low-cost, efficient nuclear and coal units (59.6% coal and 38.5% nuclear). The remaining energy needs were supplied by hydroelectric, CT and CC generation or economic 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 territories. Long-term projections indicate a need for capacity additions, which may include new nuclear, integrated gasification combined cycle (IGCC), coal facilities or gas-fired generation units. 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. Significant current or potential future capital projects are discussed below.

South Carolina passed new energy legislation South Carolina Senate Bill 431 (S 431) which became effective May 3, 2007. This legislation includes provisions to provide assurance of cost recovery related to a utility’s incurrence of project development costs associated with nuclear baseload generation, cost recovery assurance for construction costs associated with nuclear or coal baseload generation, and the ability to recover financing costs for new nuclear baseload generation in rates during construction through a rider. The North Carolina General Assembly also passed comprehensive energy legislation North Carolina Senate Bill 3 (SB 3) in July 2007 that was signed into law by the Governor on August 20, 2007. Like the South Carolina legislation, the North Carolina legislation provides cost recovery assurance, subject to prudency review, for nuclear project development costs as well as baseload generation construction costs. A utility may include financing costs related to construction work in progress for baseload plants in a rate case.

William States Lee III Nuclear Station. On December 12, 2007, Duke Energy Carolinas filed an application with the Nuclear Regulatory Commission (NRC), which has been docketed for review, for a combined Construction and Operating License (COL) for two Westinghouse AP1000 (advanced passive) reactors for the proposed William States Lee III Nuclear Station at a site in Cherokee County, South Carolina. Each reactor is capable of producing approximately 1,117 MW. Submitting the COL application does not commit Duke Energy Carolinas to build nuclear units. The NRC review of the COL application continues and the estimated receipt of the COL is in mid 2013. Duke Energy Carolinas filed with the U.S. Department of Energy (DOE) for a federal loan guarantee, which has the potential to significantly lower financing costs associated with the proposed William States Lee III Nuclear Station; however, it was not among the four projects selected by the DOE for the final phase of due diligence for the federal loan guarantee program. The project could be selected in the future if the program funding is expanded or if any of the current finalists drop out of the program.

Cliffside Unit 6. On June 2, 2006, Duke Energy Carolinas filed an application with the NCUC for a Certificate of Public Convenience and Necessity (CPCN) to construct two 800 MW state of the art coal generation units at its existing Cliffside Steam Station in North Carolina. On March 21, 2007, the NCUC issued an Order allowing Duke Energy Carolinas to build one 800 MW unit. On February 20, 2008, Duke Energy Carolinas entered into an amended and restated engineering, procurement, construction and commissioning services agreement, valued at approximately $1.3 billion, with an affiliate of The Shaw Group, Inc., of which approximately $950 million relates to participation in the construction of Cliffside Unit 6, with the remainder related to a flue gas desulfurization system on an existing unit at Cliffside. On February 27, 2009, Duke Energy Carolinas filed its latest updated cost estimate of $1.8 billion (excluding up to approximately $0.6 billion of allowance for funds used during construction (AFUDC)) for the approved new Cliffside Unit 6. Duke Energy Carolinas believes that the overall cost of Cliffside Unit 6 will be reduced by approximately $125 million in federal advanced clean coal tax credits. Construction of Cliffside Unit 6 is underway and is approximately 55% complete as of December 31, 2009.

Dan River and Buck Combined Cycle Facilities. On June 29, 2007, Duke Energy Carolinas filed with the NCUC preliminary CPCN information to construct a 620 MW combined cycle natural gas-fired generating facility at its existing Dan River Steam Station, as well as updated preliminary CPCN information to construct a 620 MW combined cycle natural gas-fired generating facility at its existing Buck Steam Station. On December 14, 2007, Duke Energy Carolinas filed CPCN applications for the two combined cycle facilities. The NCUC consolidated its consideration of the two CPCN applications and held an evidentiary hearing on the applications on March 11, 2008. On May 5, 2008, Duke Energy Carolinas entered into an engineering, construction and commissioning services agreement for the Buck combined cycle project, valued at approximately $275 million, with Shaw North Carolina, Inc. On November 5, 2008, Duke Energy Carolinas notified the NCUC that since the issuance of the CPCN Order, recent economic factors have caused increased uncertainty with regard to forecasted load and near-term capital expenditures, resulting in a modification of the construction schedule. On September 1, 2009, Duke Energy Carolinas filed with the NCUC further information clarifying the construction schedule for the two projects. Under the revised schedule, the Buck Project is expected to begin operation in combined cycle mode by the end of 2011, but without a phased-in simple cycle commercial operation. The Dan River Project is expected to begin operation in combined cycle mode by the end of 2012, also without a phased-in simple cycle commercial operation. On December 21, 2009, Duke Energy Carolinas entered into a First Amended and Restated engineering, construction and commissioning services agreement with Shaw North Carolina, Inc. for $322 million which reflects the revised schedule. Based on the most updated cost estimates, total costs (including AFUDC) for the Buck and Dan River projects are approximately $660 million and $710 million, respectively.

On October 15, 2008, the Division of Air Quality (DAQ) issued a final air construction permit authorizing construction of the Buck combined cycle natural gas-fired generating units, and on August 24, 2009, the DAQ issued a final air permit authorizing construction of the Dan River combined cycle natural gas-fired generation units.

Edwardsport IGCC. On September 7, 2006, Duke Energy Indiana and Southern Indiana Gas and Electric Company d/b/a Vectren Energy Delivery of Indiana (Vectren) filed a joint petition with the IURC seeking a CPCN for the construction of a 630 MW IGCC power plant at Duke Energy Indiana’s Edwardsport Generating Station in Knox County, Indiana. The facility was initially estimated to cost approximately $2 billion (including approximately $120 million of AFUDC). In August 2007, Vectren formally withdrew its participation in the IGCC plant and a hearing was conducted on the CPCN petition based on Duke Energy Indiana owning 100% of the project. On November 20, 2007, the IURC issued an order granting Duke Energy Indiana a CPCN for the proposed IGCC Project, approved the cost estimate of $1.985 billion and approved the timely recovery of costs related to the project. On January 25, 2008, Duke Energy Indiana received the final air permit from the Indiana Department of Environmental Management.

On May 1, 2008, Duke Energy Indiana filed its first semi-annual IGCC Rider and ongoing review proceeding with the IURC as required under the CPCN Order issued by the IURC. In its filing, Duke Energy Indiana requested approval of a new cost estimate for the IGCC Project of $2.35 billion (including approximately $125 million of AFUDC) and for approval of plans to study carbon capture as required by the IURC’s CPCN Order. On January 7, 2009, the IURC approved Duke Energy Indiana’s request, including the new cost estimate of $2.35 billion, and cost recovery associated with a study on carbon capture. Duke Energy Indiana was required to file its plans for studying carbon storage related to the project within 60 days of the order. On November 3, 2008 and May 1, 2009, Duke Energy Indiana filed its second and third semi-annual IGCC riders, respectively, both of which were approved by the IURC in full.

On November 24, 2009, Duke Energy Indiana filed a petition for its fourth semi-annual IGCC rider and ongoing review proceeding with the IURC. Duke Energy has experienced design modifications and scope growth above what was anticipated from the preliminary engineering design, adding capital costs to the IGCC project. Duke Energy Indiana forecasted that the additional capital cost items would use the remaining contingency and escalation amounts in the current $2.35 billion cost estimate and add approximately $150 million, or about 6.4% to the total IGCC Project cost estimate, excluding the impact associated with the need to add more contingency. Duke Energy Indiana did not request approval of an increased cost estimate in the fourth semi-annual update proceeding; rather, Duke Energy Indiana requested the IURC to establish a subdocket proceeding in which Duke Energy will present additional evidence regarding an updated estimated cost for the IGCC project and in which a more comprehensive review of the IGCC project could occur. On January 27, 2010, the IURC approved Duke Energy Indiana’s request for a subdocket proceeding regarding the cost estimate issues and accepted procedural schedules for the fourth semi-annual update proceeding and the subdocket proceeding. The evidentiary hearing for the fourth semi-annual update proceeding is scheduled for April 6, 2010. In the cost estimate subdocket proceeding, Duke Energy Indiana will be filing a new cost estimate for the IGCC project on April 7, 2010, with its case-in-chief testimony, and a hearing is scheduled to begin August 10, 2010. Duke Energy Indiana continues to work with its

vendors to update and refine the forecasted increased cost to complete the Edwardsport IGCC project, and currently anticipates that the total cost increase it submits in the cost estimate subdocket proceeding will be significantly higher than the $150 million previously identified.

Duke Energy Indiana filed a petition with the IURC requesting approval of its plans for studying carbon storage, sequestration and/or enhanced oil recovery for the carbon dioxide (CO₂) from the Edwardsport IGCC facility on March 6, 2009. On July 7, 2009, Duke Energy Indiana filed its case-in-chief testimony requesting approval for cost recovery of a $121 million site assessment and characterization plan for CO₂ sequestration options including deep saline sequestration, depleted oil and gas sequestration and enhanced oil recovery for the CO₂ from the Edwardsport IGCC facility. The Indiana Office of Utility Consumer Counselor (OUCC) filed testimony supportive of the continuing study of carbon storage, but recommended that Duke Energy Indiana break its plan into phases, recommending approval of only approximately $33 million in expenditures at this time and deferral of expenditures rather than cost recovery through a tracking mechanism as proposed by Duke Energy Indiana. Intervenor CAC recommended against approval of the carbon storage plan stating customers should not be required to pay for research and development costs. Duke Energy Indiana’s rebuttal testimony was filed October 30, 2009, wherein it amended its request to seek deferral of approximately $42 million to cover the carbon storage site assessment and characterization activities scheduled to occur through approximately the end of 2010, with further required study expenditures subject to future IURC proceedings. An evidentiary hearing was held on November 9, 2009, and an order is expected in the first half of 2010.

Under the Edwardsport IGCC CPCN order and statutory provisions, Duke Energy Indiana is entitled to recover the costs reasonably incurred in reliance on the CPCN Order. In December 2008, Duke Energy Indiana entered into a $200 million engineering, procurement and construction management agreement with Bechtel Power Corporation. Construction of Edwardsport is underway and is approximately 50% complete as of December 31, 2009.

See Note 4 to the Consolidated Financial Statements, “Regulatory Matters,” for further discussion on the above in-process or potential construction projects.

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, 2009.

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 2010 to 2014. 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 regulated Midwest entities is primarily produced in Indiana, Illinois, and Kentucky. U.S. Franchised Electric and Gas has an adequate supply of coal under contract to fuel its projected 2010 operations and a significant portion of supply to fuel its projected 2011 operations.

The current average sulfur content of coal purchased by U.S. Franchised Electric and Gas for the Carolinas is approximately 1%; however, as Carolinas coal plants continue to 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 (SO₂) emission allowances on the open market, this satisfies the current emission limitations for SO₂ 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 its Ohio and Kentucky service territories. 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 2009, firm supply purchase commitment agreements provided approximately 99% 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) base load, 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 also owns two underground caverns with a total storage capacity of approximately 16 million gallons of liquid propane. In addition, U.S. Franchised Electric and Gas has access to 5.5 million gallons of liquid propane storage and product loan through a commercial services agreement with a third party. This liquid propane is used in the three propane/air peak shaving plants located in Ohio and Kentucky. Propane/air peak shaving plants vaporize the propane and mix with natural gas to supplement the natural gas supply during peak demand periods and emergencies.

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 10-25% of total winter heating season gas requirements for Duke Energy Ohio, between 10-35% of total winter heating season gas requirements for Duke Energy Kentucky and between 10-50% of total summer season gas requirements for both Duke Energy Ohio and Duke Energy Kentucky for 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, 2009, Duke Energy Ohio and Duke Energy Kentucky, combined, had locked in pricing for approximately 22% of their winter 2009/2010 system load requirements.

U.S. Franchised Electric and Gas is also responsible for the purchase and the subsequent delivery of natural gas to the gas turbine generators to serve native electric load customers in the Duke Energy Carolinas, Duke Energy Indiana and Duke Energy Kentucky service territories. The natural gas procurement strategy is to contract with one or several suppliers who buy spot market natural gas supplies along with firm or interruptible interstate pipeline transportation capacity for deliveries to the site. This strategy allows for competitive pricing, flexibility of delivery, and reliable natural gas supplies to each of the natural gas plants. Many of the natural gas plants can be served by several supply zones and multiple pipelines.

Duke Energy Indiana hedges a percentage of its winter and summer expected native gas burn from Indiana gas turbine units using financial swaps tied to the New York Mercantile Exchange (NYMEX)-Henry Hub natural gas futures.

Nuclear. The industrial processes for producing nuclear generating fuel generally involve the mining and milling of uranium ore to produce uranium concentrates, the services to convert uranium concentrates to uranium hexafluoride, the services to enrich the uranium hexafluoride, and the services to fabricate the enriched uranium hexafluoride into usable fuel assemblies.

Duke Energy Carolinas has contracted for uranium materials and services 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. Duke Energy Carolinas 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 and decreasing portions of its fuel requirements over time thereafter. Due to the technical complexities of changing suppliers of fuel fabrication services, Duke Energy Carolinas generally sources these services to a single domestic supplier on a plant-by-plant basis using multi-year contracts.

Duke Energy Carolinas has entered into fuel contracts that, based on its current need projections, cover 100% of the uranium concentrates, conversion services, and enrichment services requirements of the Oconee, McGuire and Catawba Nuclear Stations through at least 2011 and cover fabrication services requirements for these plants through at least 2018. For subsequent years, a portion of the fuel requirements at Oconee, McGuire and Catawba are covered by long-term contracts. For future requirements not already covered under long-term contracts, Duke Energy Carolinas 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.

Energy Efficiency. Several factors have led to increased focus on energy efficiency, including environmental constraints, increasing costs of generating plans and legislative mandates regarding building codes and appliance efficiencies. As a result of these factors, Duke Energy has developed various programs designed to promote the efficient use of electricity by its customers. These programs, collectively called save-a-watt, have been filed with various state commissions over the past several years.

Save-a-watt was approved by the PUCO on December 17, 2008, in conjunction with the ESP, and Duke Energy Ohio began offering programs and billing a rate rider effective January 1, 2009. Save-a-watt is approved to continue through December 31, 2011.

On February 26, 2009, the NCUC approved Duke Energy Carolinas’ energy efficiency programs and authorized Duke Energy Carolinas to implement its rate rider pending approval of a final compensation mechanism by the NCUC. Duke Energy Carolinas began offering energy conservation programs to North Carolina retail customers and billing a conservation-program only rider on June 1, 2009. In October 2009, Duke Energy Carolinas also began offering demand response programs in North Carolina. On December 14, 2009, the NCUC approved the save-a-watt compensation model and, effective January 1, 2010, Duke Energy Carolinas began billing a rate rider reflecting both conservation and demand response programs. The save-a-watt programs and compensation approach in North Carolina are approved through December 31, 2013.

Duke Energy Carolinas began offering demand response and conservation programs to South Carolina retail customers effective June 1, 2009. On January 20, 2010, the PSCSC approved a save-a-watt rider for Duke Energy Carolinas’ energy efficiency programs. Duke Energy Carolinas began billing this rider to retail customers February 1, 2010. The save-a-watt programs and compensation approach in South Carolina are approved through December 31, 2013.

In October 2007, Duke Energy Indiana filed its petition with the IURC requesting approval of save-a-watt. Duke Energy Indiana reached a settlement with all intervenors except one, the CAC, and filed the settlement agreement with the IURC. An evidentiary hearing with the IURC was held on February 27, 2009 and March 2, 2009. On February 10, 2010, the IURC approved the request.

The KPSC approved Duke Energy Kentucky’s current energy efficiency programs in 2009. The KPSC is reviewing Duke Energy Kentucky’s proposed adjustment for 2010 and a decision is expected by May 2010. On December 1, 2008, Duke Energy Kentucky filed an application for the save-a-watt compensation model. On January 27, 2010, Duke Energy Kentucky withdrew the application to implement save-a-watt and plans to file a revised portfolio in the future.

SmartGrid and Distributed Renewable Generation Demonstration Project. Duke Energy Indiana filed a petition in May 2008, and case-in-chief testimony in September 2008, supporting its request to build an intelligent distribution grid in Indiana. The proposal requested approval of distribution formula rates or, in the alternative, a SmartGrid Rider to recover the return on and of the capital costs of the build-out and the recovery of incremental operating and maintenance expenses and lost revenues. The petition also included a pilot program for the installation of small solar photovoltaic and wind generation on customer sites, for approximately $10 million over a three-year period. Duke Energy Indiana filed supplemental testimony in January 2009 to reflect the impacts of new favorable tax treatment on the cost/benefit analysis for SmartGrid. After various filings by interveners, on June 4, 2009, Duke Energy Indiana filed with the IURC a settlement agreement with the OUCC, the CAC, Nucor Corporation, and the Duke Energy Indiana Industrial Group which provided for a full deployment of Duke Energy Indiana’s SmartGrid initiative at a slower pace, including cost recovery through a tracking mechanism. The settlement also included increased reporting and monitoring requirements, approval of Duke Energy Indiana’s renewable distributed generation pilot and the creation of a collaborative design to initiate several time differentiated pricing pilots, an electric vehicle pilot and a home area network pilot. Additionally, the settlement agreement provided for tracker recovery of the costs associated with the SmartGrid initiative, subject to cost recovery caps and a termination date for the tracker. The tracker would also include a reduction in costs associated with the adoption of a new depreciation study. An evidentiary hearing was held on June 29, 2009. On November 4, 2009, the IURC issued an order that rejected

the settlement agreement as incomplete and not in the public interest. The IURC cited a lack of defined benefits of the programs and encouraged the parties to continue the collaborative process outlined in the settlement or to consider smaller scale pilots or phased-in options. The IURC required the parties to present a procedural schedule within 10 days to address the underlying relief requested in the cause, and to supplement the record to address issues regarding the American Recovery and Reinvestment Act (the Stimulus Bill) funding recently awarded by the DOE. Duke Energy Indiana is considering its next steps, including a review of the implications of this Order on the Stimulus Bill SmartGrid Investment Grant award from the DOE. A technical conference was held at the IURC on December 1, 2009, wherein a procedural schedule was established for the IURC’s continuing review of Duke Energy Indiana’s smart grid proposal. Duke Energy is currently scheduled to file supplemental testimony in support of a revised SmartGrid proposal by April 1, 2010, with an evidentiary hearing scheduled for May 5, 2010.

Duke Energy Ohio received approval to recover expenditures incurred to deploy the SmartGrid infrastructure in December 2008 in conjunction with the approval of Duke Energy Ohio’s ESP filing. On June, 30, 2009, Duke Energy Ohio filed an application to establish rates for return of its SmartGrid net costs incurred for gas and electric distribution service through the end of 2008. Duke Energy Ohio proposed its gas SmartGrid rider as part of its most recent gas distribution rate case. A Stipulation and Recommendation was entered into by Duke Energy Ohio, Staff of the PUCO, Kroger Company, and Ohio Partners for Affordable Energy, which provides for a revenue increase of approximately $4.2 million under the electric rider and $590,000 under the natural gas rider. Approval of the Stipulation and Recommendation is expected in the first quarter 2010.

Duke Energy Business Services, on behalf of Duke Energy Indiana and Duke Energy Ohio, was awarded a $200 million SmartGrid investment grant from the DOE in October 2009. Duke Energy is currently evaluating the terms and conditions of the grant in conjunction with regulatory activities described above that are ongoing in Indiana and Ohio.

See Note 4 to the Consolidated Financial Statements, “Regulatory Matters,” for additional information.

Renewable Energy. Climate change concerns, as well as the oil price volatility, have sparked rising government support in driving increasing renewable energy legislation at both the federal and state level. For example, as discussed further below, the North Carolina legislation (SB 3) passed in 2007 established a renewable energy and energy efficiency portfolio standard (REPS) for electric utilities, and in 2008, the state of Ohio also passed legislation that included renewable energy and advanced energy targets. Duke Energy Carolinas, Duke Energy Ohio and Duke Energy Indiana have issued Request for Proposals (RFP) seeking bids for power generated from renewable energy sources, including sun, wind, water, organic matter and other sources.

With the passage of Senate Bill 221 (SB 221) in Ohio in 2008, Duke Energy Ohio is required to secure renewable energy and include an increasing percentage of renewables as part of its resource portfolio. The compliance percentages are based on a three-year historical average of its standard service offer load. The requirements are 0.25% of the baseline load from non-solar and 0.004% from solar beginning in 2009, increasing to 12.5% non-solar and 0.5% solar by 2024. Of these percentages, at least 50% of each resource type must come from resources located within the state of Ohio. To address this legislation, Duke Energy Ohio initiated several acquisition activities including comprehensive renewable RFPs in June 2008. Duke Energy Ohio evaluated the bids and selected both solar and non-solar bids to begin negotiations aimed toward final contract executions. Initial objectives were focused on meeting the specific near-term 2009, 2010 and 2011 requirements. Duke Energy Ohio is also working with regulators to seek clarifications on points of the SB 221 renewable guidelines. Effective December 10, 2009, the PUCO adopted a set of reporting standards known as “Green Rules” which will regulate energy efficiency, alternative energy generation requirements and emission reporting for activities mandated by SB 221. Duke Energy Ohio will continue its renewable efforts with bidders, suppliers and the community in Ohio to meet the increasing renewable obligations.

With the passage of SB 3 in North Carolina in 2007, Duke Energy Carolinas was required to include an increasing percentage of renewables as part of its generation portfolio. SB 3 requires solar compliance at 0.02% of retail sales beginning in 2010 and 3% of total portfolio to comply with solar, swine and poultry requirements beginning 2012. Total North Carolina renewable energy resource compliance increases to 12.5% by 2021. SB 3 granted the NCUC authority to approve an energy efficiency rate rider to compensate utilities for new energy efficiency programs that they implement, as well as a REPS rider to recover incremental costs incurred to comply with the renewable portfolio standard. To address this legislation, Duke Energy Carolinas initiated a comprehensive renewable RFP in April 2007 to address the 2010 through 2014 renewable portfolio standards requirements. As a result of the 2007 renewable energy RFP, Duke Energy Carolinas has executed a contract with a solar bidder and several landfill gas contracts which will be added to the hydro facilities portfolio to meet future compliance requirements. Duke Energy Carolinas is working with regulators to seek clarifications on points of the SB 3 renewable guidelines. Duke Energy Carolinas will continue to meet its growing renewable efforts with bidders, suppliers and the community in the Carolinas to meet the increasing renewable obligations.

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, 2009, the inventory balance for U.S. Franchised Electric and Gas was approximately $1,278 million. See Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” for additional information.

Duke Energy Carolinas 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 each have two nuclear reactors and the Oconee Nuclear Station 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 Carolinas for certain expenses associated with nuclear insurance premiums. The Price-Anderson Act requires Duke Energy to provide for public liability claims resulting from nuclear incidents to the maximum total financial protection liability, which was approximately $12.5 billion and increased to approximately $12.6 billion effective January 1, 2010. See Note 16 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. In each of the years ended December 31, 2009, 2008 and 2007, Duke Energy Carolinas expensed approximately $48 million and contributed cash of approximately $48 million to the Nuclear Decommissioning Trust Funds (NDTF) for decommissioning costs. The entire amount of these contributions were to the funds reserved for contaminated costs as contributions to the funds reserved for non-contaminated costs have been discontinued since the current estimates indicate existing funds to be sufficient to cover projected future costs. The balance of the external NDTF was approximately $1,765 million as of December 31, 2009 and $1,436 million as of December 31, 2008.

As the NCUC and the PSCSC require that Duke Energy Carolinas update its cost estimate for decommissioning its nuclear plants every five years, new site-specific nuclear decommissioning cost studies were completed in January 2009 that showed total estimated nuclear decommissioning costs, including the cost to decommission plant components not subject to radioactive contamination, of approximately $3 billion in 2008 dollars. This estimate includes Duke Energy Carolinas’ 19.25% ownership interest in the Catawba Nuclear Station. The other joint owners of the Catawba Nuclear Station are responsible for decommissioning costs related to their ownership interests in the station. Both the NCUC and the PSCSC have allowed Duke Energy Carolinas to recover estimated decommissioning costs through retail rates over

the expected remaining service periods of Duke Energy Carolinas’ nuclear stations. Duke Energy Carolinas believes that the decommissioning costs being recovered through rates, when coupled with the existing fund balance and expected fund earnings, will be sufficient to provide for the cost of future decommissioning.

Duke Energy Carolinas filed these site-specific nuclear decommissioning cost studies with the NCUC and the PSCSC in April 2009. In addition to the decommissioning cost studies, a new funding study was completed and indicates the current annual funding requirement of approximately $48 million is sufficient to cover the estimated decommissioning costs. Duke Energy Carolinas received an order from the NCUC on its rate case filing on December 7, 2009, and from the PSCSC on Duke Energy Carolinas’ rate case on January 27, 2010. Both the NCUC and the PSCSC approved the existing $48 million annual funding level for nuclear decommissioning costs. See Note 7 to the Consolidated Financial Statements, “Asset Retirement Obligations,” for more information.

After used 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 Carolinas contracted with the DOE for the disposal of used nuclear fuel. The DOE failed to begin accepting used nuclear fuel on January 31, 1998, the date specified by the Nuclear Waste Policy Act and in Duke Energy’s contract with the DOE. Duke Energy Carolinas will continue to safely manage its used nuclear fuel until the DOE accepts it. In 1998, Duke Energy Carolinas filed a claim with the U.S. Court of Federal Claims against the DOE related to the DOE’s failure to accept commercial used nuclear fuel by the required date. Damages claimed in the lawsuit were based upon Duke Energy Carolinas’ costs incurred as a result of the DOE’s partial material breach of its contract, including the cost of securing additional used fuel storage capacity. On March 5, 2007, Duke Energy Carolinas and the U.S. Department of Justice reached a settlement resolving Duke Energy Carolinas’ used nuclear fuel litigation against the DOE. The agreement provided for an initial payment to Duke Energy Carolinas for certain storage costs incurred through July 31, 2005, with additional amounts reimbursed annually for future storage costs.

Duke Energy has experienced numerous claims for indemnification and medical reimbursements relating to damages for bodily 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 prior to 1985.

Duke Energy has third-party insurance to cover certain losses related to Duke Energy Carolinas’ asbestos-related injuries and damages above an aggregate self insured retention of $476 million. Reserves recorded on Duke Energy’s Consolidated Balance Sheets are based upon the minimum amount in Duke Energy’s best estimate of the range of loss for current and future asbestos claims through 2027. Management believes that it is possible there will be additional claims filed against Duke Energy Carolinas after 2027. In light of the uncertainties inherent in a longer-term forecast, management does not believe they can reasonably estimate the indemnity and medical costs that might be incurred after 2027 related to such potential claims. Asbestos-related loss estimates incorporate anticipated inflation, if applicable, and are recorded on an undiscounted basis. These reserves are based upon current estimates and are subject to greater uncertainty as the projection period lengthens. A significant upward or downward trend in the number of claims filed, the nature of the alleged injury, and the average cost of resolving each such claim could change management’s estimated liability, as could any substantial adverse or favorable verdict at trial. A federal legislative solution, further state tort reform or structured settlement transactions could also change the estimated liability. Given the uncertainties associated with projecting matters into the future and numerous other factors outside Duke Energy’s control, management believes it is reasonably possible that Duke Energy Carolinas may incur asbestos liabilities in excess of its recorded reserves.

Duke Energy Indiana and Duke Energy Ohio have also been named as defendants or co-defendants in lawsuits related to asbestos at their electric generating stations. The impact on Duke Energy’s consolidated results of operations, cash flows, or financial position of these cases to date has not been material. Based on estimates under varying assumptions, concerning uncertainties, such as, among others: (i) the number of contractors potentially exposed to asbestos during construction or maintenance of Duke Energy Indiana and Duke Energy Ohio generating plants; (ii) the possible incidence of various illnesses among exposed workers and (iii) the potential settlement costs without federal or other legislation that addresses asbestos tort actions, Duke Energy estimates that the range of reasonably possible exposure in existing and future suits over the foreseeable future is not material. This estimated range of exposure may change as additional settlements occur and claims are made and more case law is established.

See Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies-Litigation-Asbestos Related Injuries and Damages Claims,” for more information.

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, respectively, 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 Ohio, certified suppliers may offer retail electric generation service to residential, commercial and industrial customers. 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.

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. The State Utility Commissions, except for the PUCO, also have authority over the construction and operation of U.S. Franchised Electric and Gas’ generating facilities. CPCN’s issued by 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.

Duke Energy Carolinas 2009 North Carolina Rate Case. On June 2, 2009, Duke Energy Carolinas filed an Application for Adjustment of Rates and Charges Applicable to Electric Service in North Carolina to increase its base rates. The Application was based upon

a historical test year consisting of the 12 months ended December 31, 2008. On October 20, 2009, Duke Energy Carolinas entered into a settlement agreement with the North Carolina Public Staff. Two organizations representing industrial customers joined the settlement on October 21, 2009. The terms of the agreement include a base rate increase of $315 million (or approximately 8%) phased in primarily over a two-year period beginning January 1, 2010. In order to mitigate the impact of the increase on customers, the agreement provides for (i) a one-year delay in the collection of financing costs related to the Cliffside modernization project until January 1, 2011; and (ii) the accelerated return of certain regulatory liabilities to customers which lowered the total impact to customer bills to an increase of approximately 7% in the near-term. The proposed settlement includes a 10.7% return on equity and a capital structure of 52.5% equity and 47.5% long-term debt. Additionally, Duke Energy Carolinas agreed not to file another rate case before 2011 with any changes to rates taking effect no sooner than 2012. The NCUC approved the settlement agreement in full by order dated December 7, 2009. The new rates were effective and implemented on January 1, 2010.

Duke Energy Carolinas 2009 South Carolina Rate Case. On July 27, 2009, Duke Energy Carolinas filed its Application for Authority to Increase and Adjust Rates and Charges for an increase in rates and charges in South Carolina. On September 25, 2009, Duke Energy Carolinas filed a supplemental request seeking PSCSC approval of a charge to customer bills to pay for Duke Energy Carolinas’ new energy efficiency efforts. Parties to the proceeding include the South Carolina Office of Regulatory Staff (ORS), the South Carolina Energy Users Committee (SCEUC), and the South Carolina Green Party. Duke Energy Carolinas, ORS, and SCEUC filed a settlement agreement on November 24, 2009, recommending, (i) a $74 million increase in base rates, (ii) an allowed return on equity of 11% with rates set at a return on equity of 10.7% and capital structure of 53% equity, and (iii) various riders, including one that provides for the return of DSM charges previously collected from customers over three years rather than five years, and another that provides for a storm reserve provision allowing Duke Energy Carolinas to collect $5 million annually (up to a maximum funding level of $50 million accumulating in reserves) to be used against large storm costs in any particular period. On January 20, 2010, the PSCSC approved the settlement agreement in full, including the cost recovery mechanism for the energy efficiency effort. The new rates were effective February 1, 2010.

Duke Energy Ohio Electric Rate Filings. New legislation (SB 221) passed in April 2008 and signed by the Governor of Ohio on May 1, 2008 codified the PUCO’s authority to approve an electric utility’s standard generation service offer through an ESP, which allows for pricing structures similar to those under the historic RSP. Electric utilities are required to file an ESP and may also file an application for a Market Rate Option (MRO) at the same time. The MRO is a price determined through a competitive bidding process. On July 31, 2008, Duke Energy Ohio filed an ESP to be effective January 1, 2009. On December 17, 2008, the PUCO issued its finding and order adopting a modified Stipulation with respect to Duke Energy Ohio’s ESP filing. The PUCO agreed to Duke Energy Ohio’s request for a net increase in base generation revenues, before impacts of customer switching, of $36 million, $74 million and $98 million in 2009, 2010 and 2011, respectively, including the termination of the residential and non-residential Regulatory Transition Charge, the recovery of expenditures incurred to deploy the SmartGrid infrastructure and the implementation of save-a-watt. See “Commercial Power” section below for additional information related to the ESP.

For more information on rate matters, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters—U.S. Franchised Electric and Gas.”

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 rule makings. Among the key provisions, the Energy Policy Act of 2005 repealed the Public Utility Holding Company Act (PUHCA) of 1935, directed FERC to establish a self-regulating electric reliability organization governed by an independent board with FERC oversight, extended the Price Anderson Act for 20 years (until 2025), provided loan guarantees, standby support and production tax credits for new nuclear reactors, gave FERC enhanced merger approval authority, provided FERC new backstop authority for the siting of certain electric transmission projects, streamlined the processes for approval and permitting of interstate pipelines, and reformed hydropower relicensing. In 2005 and 2006, FERC initiated several rule makings as directed by the Energy Policy Act of 2005. These rulemakings have now been completed, subject to certain appeals and further proceeding. Duke Energy does not believe that these rulemakings or the appeals 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 and in January 2009 it began administering an ancillary services market. Additionally, in April 2009, the Midwest ISO began administering a voluntary capacity auction, and in June 2009, instituted a tariff based capacity requirement.

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, a Regional Transmission Organization (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. On August 13, 2008, the IURC authorized Duke Energy Indiana to transfer additional balancing authority functions to the Midwest ISO to permit Duke Energy Indiana to participate in the Midwest ISO’s ancillary services market.

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 (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. Duke Energy Carolinas remains 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 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 currently seeking adjustments to its transmission rates to reflect the incremental cost of the

proposal, which is not projected to have a material adverse effect on Duke Energy’s future consolidated results of operations, cash flows or financial position.

U.S. Franchised Electric and Gas is subject to the jurisdiction of the NRC for the design, construction and operation of its nuclear generating facilities. In 2000, the NRC renewed the operating license for Duke Energy Carolinas’ three Oconee nuclear units through 2033 for Units 1 and 2 and through 2034 for Unit 3. In 2003, the NRC renewed the operating licenses for all units at Duke Energy Carolinas’ McGuire and Catawba stations. The two McGuire units are licensed through 2041 and 2043, respectively, while the two Catawba units are licensed through 2043. All but one of U.S. Franchised Electric and Gas’ hydroelectric generating facilities are licensed by the FERC under Part I of the Federal Power Act, with license terms expiring from 2005 to 2036. The FERC has authority to issue new hydroelectric generating licenses. Hydroelectric facilities whose licenses expired in 2005 through 2009 are operating under annual extensions of the current license until FERC issues a new license. Other hydroelectric facilities whose licenses expire between 2010 and 2016 are in various stages of relicensing. Duke Energy expects to receive new licenses for all applicable hydroelectric facilities with the exception of the Dillsboro Project, for which Duke Energy requested and the FERC approved license surrender. Duke Energy Carolinas has removed the Dillsboro Project dam and powerhouse as part of multi-project and multi-stakeholder agreements and Duke Energy Carolinas is continuing with stream restoration and post-removal monitoring as requested by FERC’s license surrender order.

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

Commercial Power also has a retail sales subsidiary, DERS, which is certified by the PUCO as a CRES provider in Ohio. DERS serves retail electric customers in Southwest, West Central and Northern Ohio with generation and other energy services at competitive rates. During 2009, due to increased levels of customer switching as a result of the competitive markets in Ohio, which is discussed further below, DERS has focused on acquiring customers that had previously been served by Duke Energy Ohio under the ESP, as well as those previously served by other Ohio franchised utilities.

The following map shows the Commercial Power service territory and generation facilities.

Through DEGS, Commercial Power 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 currently has approximately 735 net MW of wind energy in operation and over 5,000 MW of wind energy projects in the development pipeline. DEGS also is developing transmission, solar and biomass projects.

Effective January 1, 2009, approximately half of Commercial Power’s generation assets operate under an ESP, which expires on December 31, 2011. Prior to the ESP, these generation assets had been contracted through the RSP, which expired on December 31, 2008. The ESP consists of the following discrete charges:

Commercial Power’s generation operations in the Midwest include generation assets located in Ohio that are dedicated to serve Ohio native load customers. These assets, as excess capacity allows, also generate revenues through sales outside the native load customer base, and such revenue is termed non-native.

Prior to December 17, 2008, Commercial Power did not apply regulatory accounting treatment to any of its operations due to the comprehensive electric deregulation legislation passed by the state of Ohio in 1999. In April 2008, new legislation (SB 221) was passed in Ohio and signed by the Governor of Ohio on May 1, 2008. The new law codified the PUCO’s authority to approve an electric utility’s standard service offer either through an ESP or a MRO, which is a price determined through a competitive bidding process. On July 31, 2008, Duke

Energy Ohio filed an ESP and, with certain amendments, the ESP was approved by the PUCO on December 17, 2008. The approval of the ESP on December 17, 2008 resulted in the reapplication of regulatory accounting treatment to certain portions of Commercial Power’s operations as of that date. The ESP became effective on January 1, 2009.

Under the ESP, Commercial Power bills for its native load generation via numerous riders. SB 221 and the ESP resulted in the approval of an enhanced recovery mechanism for certain of these riders, which includes, but is not limited to, a price-to-compare fuel and purchased power rider and certain portions of a price-to-compare cost of environmental compliance rider. Accordingly, Commercial Power began applying regulatory accounting treatment to the corresponding RSP riders that enhanced the recovery mechanism for recovery under the ESP on December 17, 2008. The remaining portions of Commercial Power’s Ohio native load generation operations, revenues from which are reflected in rate riders for which the ESP does not specifically allow enhanced recovery, as well as all generation operations associated with non-native customers, including Commercial Power’s Midwest gas-fired generation assets, continue to not apply regulatory accounting as those operations do not meet the necessary accounting criteria. Moreover, generation remains a competitive market in Ohio and native load customers continue to have the ability to switch to alternative suppliers for their electric generation service. As customers switch, there is a risk that some or all of the regulatory assets will not be recovered through the established riders. In assessing the probability of recovery of its regulatory assets established for its native load generation operations, Duke Energy continues to monitor the amount of native load customers that have switched to alternative suppliers. At December 31, 2009, management has concluded that the established regulatory assets are still probable of recovery even though there have been increased levels of customer switching.

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. See “Regulation” section within U.S. Franchised Electric and Gas for additional information regarding deregulation in Ohio.

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.)

Similar to U.S. Franchised Electric and Gas’ operations, the overall economic conditions have negatively impacted Commercial Power’s retail volumes for all customer classes. Commercial Power 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 competition in the energy marketing business. Commercial Power’s main competitors include other non-regulated generators in the Midwestern U.S. wholesale power, coal and natural gas marketers, renewable energy companies and financial institutions and hedge funds engaged in energy commodity marketing and trading.

Low commodity prices in 2009 have put downward pressure on power prices. The available capacity and lower prices have provided opportunities for customers in Ohio to switch generation suppliers. Competitive power suppliers have begun supplying power to current Commercial Power customers in Ohio and Commercial Power experienced an increase in customer switching beginning in the second quarter of 2009 and accelerating in the later part of the year. As of December 31, 2009, customer switching levels approximated 40% of Commercial Power’s Ohio native load. However, through DERS, Commercial Power was able to acquire approximately 60% of the switched load by offering customers a discount to the ESP price. Additionally, DERS has been able to acquire new customers previously served by other Ohio franchised utilities.

Commercial Power relies on coal and natural gas for its generation of electric energy.

Coal. Commercial Power meets its coal demand 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. Commercial Power 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 2010 to 2012. Commercial Power 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 is primarily produced in Illinois, Ohio and eastern Kentucky. Commercial Power has an adequate supply of coal to fuel its projected 2010 operations and a significant portion of supply to fuel its projected 2011 operations. The majority of Commercial Power’s coal-fired generation is equipped with flue gas desulfurization equipment. As a result, Commercial Power is able to satisfy the current emission limitations for SO₂ for existing facilities.

Gas. Commercial Power is responsible for the purchase and the subsequent delivery of natural gas to its gas turbine generators. The majority of Commercial Power’s natural gas requirements are purchased in the spot market on an as-needed basis.

International Energy principally operates and manages power generation facilities and engages in sales and marketing of electric power and natural gas outside the U.S. It conducts operations primarily through DEI and its affiliates and its activities target power generation in Latin America. Additionally, International Energy has equity method investments in NMC, located in Saudi Arabia, which is a regional producer of MTBE and Attiki, located in Athens, Greece, which is a natural gas distributor and was acquired in connection with the Cinergy merger. In December 2009, International Energy decided to abandon its investment in Attiki. See Note 12 to the Consolidated Financial Statements, “Investments in Unconsolidated Affiliates and Related Party Transactions,” for additional information.

International Energy’s customers include retail distributors, electric utilities, independent power producers, marketers and industrial/commercial companies. International Energy’s current strategy is focused on optimizing the value of its current Latin American portfolio and expanding the portfolio through investment in generation opportunities in Latin America.

International Energy owns, operates or has substantial interests in approximately 4,000 net MW of generation facilities.

The following map shows the locations of International Energy’s facilities, including its interests in non-electric generation facilities in Saudi Arabia and Greece.

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, local distribution companies with self-generation capability and other privately-owned electric generating and marketing 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 hydroelectric 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, additional generation capacities 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.)

The remainder of Duke Energy’s operations is presented as Other. While it is not considered a business segment, Other primarily includes certain unallocated corporate costs, Bison, Duke Energy’s wholly-owned, captive insurance subsidiary, Duke Energy’s effective 50% interest in Crescent and DukeNet and related telecom businesses. Additionally, Other includes the remaining portion of Duke Energy’s business formerly known as DENA that was not exited or transferred to Commercial Power, primarily DETM, which is 60% owned by Duke Energy and 40% owned by Exxon Mobil Corporation and management is currently in the process of winding down. See Note 2 to the Consolidated Financial Statements, “Business Segments,” for more information on Crescent.

Bison’s principal activities as a captive insurance entity include the insurance and reinsurance of various business risks and losses, such as property, business interruption and general liability of subsidiaries and affiliates of Duke Energy.

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.)

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:

See “Other Issues” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion about potential Global Climate Change legislation and the potential impacts such legislation could have on Duke Energy’s operations. Additionally, other potential future environmental laws and regulations could have a significant impact on Duke Energy’s results of operations, cash flows or financial position. However, if such laws are enacted, Duke Energy would seek appropriate regulatory recovery of costs to comply within its regulated operations.

For more information on environmental matters involving Duke Energy, including possible liability and capital costs, see Notes 4 and 16 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 16 to the Consolidated Financial Statements, “Commitments and Contingencies,” compliance with current 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 segments 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.

For a discussion of Duke Energy’s foreign operations and certain of the risks associated with them, see “Risk Factors,” “Management’s Discussion and Analysis of Results of Operations and Financial Condition, Quantitative and Qualitative Disclosures About Market Risk—Foreign Currency Risk,” and Notes 2 and 8 to the Consolidated Financial Statements, “Business Segments” and “Risk Management, Derivative Instruments and Hedging Activities,” respectively.

On December 31, 2009, Duke Energy had approximately 18,680 employees. A total of approximately 4,620 operating and maintenance employees were represented by unions.

STEPHEN G. DE MAY, 47, Senior Vice President, Investor Relations and Treasurer. Mr. De May assumed the role of Treasurer in November 2007 and in October 2009 Mr. De May assumed additional responsibility for investor relations. Prior to that, he served as Assistant Treasurer since April 2006, upon the merger of Duke Energy and Cinergy. Until the merger of Duke Energy and Cinergy, Mr. De May served as Vice President, Energy and Environmental Policy of Duke Energy since February 2004.

LYNN J. GOOD, 50, Group Executive and Chief Financial Officer. Ms. Good assumed her current position in July 2009. In November 2007, Ms. Good began serving as President, Commercial Businesses. Prior to that, she served as Senior Vice President and Treasurer since December 2006; prior to that she served as Treasurer and Vice President, Financial Planning since October 2006; and 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 and Vice President, Finance and Controller of Cinergy from November 2003 to August 2005.

DHIAA M. JAMIL, 53, Group Executive, Chief Generation Officer and Chief Nuclear Officer. Mr. Jamil assumed his position as Chief Generation Officer in July 2009 and his position as Chief Nuclear Officer in February 2008. Prior to that he served as Senior Vice President, Nuclear Support, Duke Energy Carolinas, LLC since March 2007.

MARC E. MANLY, 57, Group Executive, Chief Legal Officer and Corporate Secretary. Mr. Manly assumed the role of Corporate Secretary in December 2008 and assumed position of Chief Legal Officer 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.

JAMES E. ROGERS, 62, 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.

B. KEITH TRENT, 50, Group Executive, President, Commercial Businesses. Mr. Trent assumed his current position in July 2009. Prior to that he served as Group Executive and Chief Strategy, Policy and Regulatory Officer since May 2007. Prior to that he served as Group Executive and Chief Strategy and Policy Officer since October 2006 and 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.

JAMES L. TURNER, 50, Group Executive; President and Chief Operating Officer, U.S. Franchised Electric and Gas. Mr. Turner assumed his current position in May 2007. Prior to that he served as Group Executive and President, U.S. Franchised Electric and Gas since October 2006, and 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.

STEVEN K. YOUNG, 51, 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.

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.

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 and possible reduction by the commissions, 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 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 failure to adequately execute and manage its significant construction plans, as well as the risk of recovering all such costs or of recovering costs in an untimely manner, which could materially impact Duke Energy’s results of operations, cash flows or financial position.

During the three year period from 2010 to 2012, Duke Energy anticipates cumulative capital expenditures of approximately $14 billion to $15 billion of which approximately $11 billion relates to its regulated U.S. Franchised Electric and Gas businesses. The completion of Duke Energy’s anticipated capital investment projects in existing and new generation facilities is subject to many construction and development risks, including, but not limited to, risks related to financing, obtaining and complying with terms of permits, meeting construction budgets and schedules, and satisfying operating and environmental performance standards. Moreover, Duke Energy’s ability to recover all these costs and recovering costs in a timely manner could materially impact Duke Energy’s consolidated financial position, 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, as well as those of Duke Energy’s international markets, require wholesale electric transmission services to be offered on an open-access, non-discriminatory basis. If transmission is disrupted, or if transmission capacity is inadequate, Duke Energy’s ability to sell and deliver products may be hindered.

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 business.

Duke Energy may be unable to secure long-term power sales 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 sales agreements to customers 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 customer 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 financial and operational results.

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.

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.

Customers of Duke Energy Ohio have recently begun to select alternative electric generation service providers, as allowed by Ohio legislation.

Under current Ohio legislation, electric generation is sold in a competitive market in Ohio, and Duke Energy’s native load customers in Ohio have the ability to switch to alternative suppliers for their electric generation service. Competitive power suppliers have announced intentions of supplying power to Duke Energy’s current customers in Ohio, and Duke Energy has experienced an increase in customer switching in the second half of 2009. These evolving market conditions may continue to impact Duke Energy’s results of operations, and also may impact Duke Energy’s ability to continue to apply regulatory accounting treatment to certain portions of its Commercial Power business segment.

Duke Energy must meet credit quality standards and there is no assurance that it and its rated subsidiaries will maintain investment grade credit ratings. 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.

Each of Duke Energy’s and its rated subsidiaries senior unsecured long-term debt is currently 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 in the future.

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, Duke Energy or its rated subsidiaries 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 require Duke Energy to post additional collateral in the form of letters of credit or cash under various credit agreements and trigger termination clauses in some interest rate 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 or at all, Duke Energy’s ability to finance its operations and implement its strategy and business plan as scheduled could be adversely affected. 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.

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.

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 Duke Energy from issuing commercial paper or Duke Energy and its affiliates from issuing letters of credit or borrowing under the revolving credit facility. Additionally, failure to comply with these financial covenants could result in Duke Energy being required to immediately pay down any outstanding 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 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’s primary foreign currency rate exposure is to the Brazilian Real.

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

Adverse economic conditions affecting, or financial difficulties of, customers and counterparties with whom Duke Energy does business could impair the ability of these customers and counterparties to pay for Duke Energy’s services or fulfill their contractual obligations, including loss recovery payments under insurance contracts, or cause them to delay such payments or obligations. Duke Energy depends on these customers and 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 complied with the minimum funding requirements as of December 31, 2009, Duke Energy has certain qualified U.S. pension plans with obligations which exceeded the value of plan assets by approximately $471 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 financial position, results of operations or cash flows.

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 cleanup 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 could be required to take to ensure that its facilities are in compliance could be prohibitively expensive. As a result, 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 financial position, results of operations or cash flows, 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.

The EPA also has plans to propose new federal regulations governing the management of coal combustion by-products, including fly ash. These regulations may require Duke Energy to make additional capital expenditures and increase Duke Energy’s operating and maintenance costs.

Additionally, potential other new environmental regulations, including the use of coal from mountain removal and water discharge, could require Duke Energy to make additional capital expenditures and increase costs of fuel.

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 position, 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 financial position, results of operations or cash flows.

Duke Energy is subject to numerous legal proceedings, including claims for damages for bodily injuries alleged to have arisen prior to 1985 from the exposure to or use of asbestos at electric generation plants of Duke Energy Carolinas. 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 overall market, economic and other conditions that 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 energy as a result of economic downturns in Duke Energy’s franchised electric service territories will reduce overall 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 and gas business is subject to regulated allowable rates of return and recovery of certain costs, such as fuel under periodic adjustment clauses, overall declines in electricity sold as a result of economic downturn or recession could reduce revenues and cash flows, thus diminishing results of operations. Additionally, prolonged economic downturns that negatively impact Duke Energy’s results of operations and cash flows could result in future material impairment charges being recorded to write-down the carrying value of certain assets, including goodwill, to their respective fair values.

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.

Factors that could impact sales volumes, generation of electricity and market prices at which Duke Energy is able to sell electricity are as follows:

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 warmer summer months, with market prices typically 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 federal regulation that will affect Duke Energy’s operations and costs.

Duke Energy is subject to regulation by FERC, the NRC and various other federal agencies. 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 the ability of the operating subsidiaries to pay dividends to Duke Energy. 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.

New laws or regulations could have a negative impact on Duke Energy’s financial position, cash flows or results of operations.

Changes in laws and regulations affecting Duke Energy, including new accounting standards 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 or their international affiliates. 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 potential 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, lower coverage limits and more restrictive policy terms.

Additional risks and uncertainties not currently known to Duke Energy or that Duke Energy currently deems to be immaterial also may materially adversely affect Duke Energy’s financial condition, results of operations or cash flows.

As of December 31, 2009, U.S. Franchised Electric and Gas operated three nuclear generating stations with a combined owned capacity of 5,173 MW (including an approximate 19% ownership in the Catawba Nuclear Station), fifteen coal-fired stations with an overall combined owned capacity of 13,189 MW, (including a 69% ownership in the East Bend Steam Station and an approximate 50% ownership in Unit 5 of the Gibson Steam Station), thirty-one hydroelectric stations (including two pumped-storage facilities) with a combined owned capacity of 3,263 MW, fifteen CT stations with an overall combined owned capacity of 5,047 MW and one CC station with an owned capacity of 285 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.

In addition, as of December 31, 2009, U.S. Franchised Electric and Gas owned approximately 20,900 conductor miles of electric transmission lines, including 600 miles of 525 kilovolts (KV), 1,800 miles of 345 KV, 3,300 miles of 230 KV, 8,800 miles of 100 to 161 KV, and 6,400 miles of 13 to 69 KV. U.S. Franchised Electric and Gas also owned approximately 151,600 conductor miles of electric distribution lines, including 103,200 miles of overhead lines and 48,400 miles of underground lines, as of December 31, 2009 and approximately 7,200 miles of gas mains and approximately 6,000 miles of service lines. As of December 31, 2009, the electric transmission and distribution systems had approximately 2,300 substations. U.S. Franchised Electric and Gas also owns two underground caverns with a total storage capacity of approximately 16 million gallons of liquid propane. In addition, U.S. Franchised Electric and Gas has access to 5.5 million gallons of liquid propane storage and product loan through a commercial services agreement with a third party. This liquid propane is used in the three propane/air peak shaving plants located in Ohio and Kentucky. Propane/air peak shaving plants vaporize the propane and mix with natural gas to supplement the natural gas supply during peak demand periods and emergencies.

Substantially all of U.S. Franchised Electric and Gas’ electric plant in service is mortgaged under the indenture relating to Duke Energy Carolinas’, Duke Energy Ohio’s and Duke Energy Indiana’s various series of First 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.

The following table provides information about Commercial Power’s generation portfolio as of December 31, 2009. The MW displayed in the table below are based on summer capacity.

In addition to the above facilities, Commercial Power owns an equity interest in the 585 MW capacity Sweetwater wind projects located in Texas. Commercial Power’s share in these projects is 283 MW.

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

The following table provides information about International Energy’s generation portfolio in continuing operations as of December 31, 2009.

International Energy also owns a 25% equity interest in NMC. In 2009, NMC produced approximately 1 million metric tons of methanol and 1 million metric tons of MTBE. Approximately 40% of methanol is normally used in the MTBE production. Additionally, International Energy owns a 25% equity interest in Attiki, which is a natural gas distributor within the geographical area of Athens, Greece. In December 2009, International Energy decided to abandon its investment in Attiki. See Note 12 to the Consolidated Financial Statements, “Investments in Unconsolidated Affiliates and Related Party Transactions,” for additional information.

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

Duke Energy owns approximately 5.7 million square feet of corporate, regional and district office space spread throughout its service territories in the Carolinas and the Midwest. Additionally, Duke Energy leases approximately 1.5 million square feet of office space throughout the Carolinas, Midwest and in Houston, Texas. In February 2009, Duke Energy entered into a lease for approximately 500,000 square feet of office space in Charlotte, North Carolina that will become its new corporate headquarters.

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

Brazilian Regulatory Citations. On September 5, 2007, the State Environmental Agency of Parana assessed fines against International Energy of approximately $10 million for failure to comply with reforestation measures allegedly required by state regulations in Brazil. International Energy believes that federal law is controlling and has challenged the assessment. In addition, International Energy was assessed a fine by the federal environmental agency, IBAMA, in the amount of approximately $150 thousand for improper maintenance of existing reforested areas. International Energy believes that it has properly maintained all reforested areas and is also contesting this assessment. These assessed fines were judged to be valid in the administrative court between June and September 2009. International Energy has challenged these administrative court rulings by filing three judicial actions for annulment between July and October 2009.

No matters were submitted to a vote of Duke Energy’s security holders during the fourth quarter of 2009.

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 (NYSE) (ticker symbol DUK). As of February 22, 2010, there were approximately 160,575 common stockholders of record.

Duke Energy expects to continue its policy of paying regular cash dividends; however, there is no assurance as to the amount of future dividends because they depend on future earnings, capital requirements, and financial condition, and are subject to declaration by the Board of Directors.

Duke Energy’s operating subsidiaries have certain restrictions on their ability to transfer funds in the form of dividends or loans to Duke Energy. See “Liquidity and Capital Resources” within “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for further information regarding these restrictions and their impacts on Duke Energy’s liquidity.

There were no repurchases of equity securities during the fourth quarter of 2009.

The performance graph below illustrates a five year comparison of cumulative total returns based on an initial investment of $100 in Duke Energy Corporation common stock, as compared with the Standard & Poor’s (S&P) 500 Stock Index and the Philadelphia Utility Index for the five-year period 2005 through 2009.

This performance chart assumes $100 invested on December 31, 2004 in Duke Energy common stock, in the S&P 500 Stock Index and in the Philadelphia Utility Index and that all dividends are reinvested.

Duke Energy has filed the certification of its Chief Executive Officer and Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 as exhibits to this Annual Report on Form 10-K for the year ended December 31, 2009. In May 2009, Duke Energy’s Chief Executive Officer, as required by Section 303A.12(a) of the NYSE Listed Company Manual, certified to the NYSE that he was not aware of any violation by Duke Energy of the NYSE’s corporate governance listing standards.

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

Management’s Discussion and Analysis should be read in conjunction with the Consolidated Financial Statements and Notes for the years ended December 31, 2009, 2008 and 2007.

2009 Financial Results. For the year-ended December 31, 2009, Duke Energy Corporation (Duke Energy) reported net income attributable to Duke Energy of $1,075 million and basic and diluted earnings per share (EPS) of $0.83, as compared to net income attributable to Duke Energy of $1,362 million and basic and diluted EPS of $1.08 and $1.07, respectively, for the year-ended December 31, 2008. Income from continuing operations was $1,073 million for 2009 as compared to $1,275 million for 2008. Total reportable segment EBIT (defined below in “Segment Results” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations) decreased to $2,713 million in 2009 from $3,073 million in 2008.

See “Results of Operations” below for a detailed discussion of the consolidated results of operations, as well as a detailed discussion of EBIT results for each of Duke Energy’s reportable business segments, as well as Other.

2009 Areas of Focus and Accomplishments. In 2009, management was focused on managing through the economic recession, investing in modernization of Duke Energy’s regulated infrastructure and dealing with increased competition in Ohio.

Managing Through the Economic Recession and Changing Competitive Landscapes. In U.S. Franchised Electric and Gas, Duke Energy’s largest business segment, weather-normalized electric volumes were down approximately 4% when compared to 2008. This was driven primarily by a decrease in industrial sales volumes, which were down approximately 14% compared to 2008. Although industrial sales volumes were down year over year, industrial volumes began to show signs of stabilization late in 2009. On a weather-normalized basis, residential sales volumes were slightly positive, while commercial sales volumes were slightly negative. Looking forward to 2010, management expects the load forecast to be relatively flat compared to 2009.

In 2009, Commercial Power’s operations were impacted by the competitive markets in Ohio, which were triggered by low commodity prices that put downward pressure on power prices. The available capacity and lower prices provided opportunities for native load customers in Ohio to switch generation suppliers. Competitive power suppliers began supplying power to current Commercial Power native load customers in Ohio and Commercial Power experienced an increase in customer switching beginning in the second quarter of 2009. As of December 31, 2009, customer switching levels approximated 40% of Commercial Power’s native load. However, through Duke Energy Retail Sales (DERS), Commercial Power acquired approximately 60% of the switched load by offering customers a discount to the Electric Security Plan (ESP) price. When factoring in the DERS activity, Commercial Power experienced net customer switching of about 15%, although those native load customers acquired by DERS were at lower margins than customers served under the ESP. Additionally, DERS has been able to acquire new customers outside Commercial Power’s native load territory. As a result of lower forecasted energy prices, lower demand for electricity due to the economy and competitive pressures in Ohio, and other valuation factors, a non-cash goodwill impairment charge of approximately $371 million was recorded by Commercial Power in the third quarter of 2009.

In light of the above economic factors that impacted Duke Energy’s business in 2009, management was focused on offsetting those economic pressures by successfully managing costs and achieving excellent operational performance. Duke Energy achieved significant operations and maintenance cost mitigation goals across its business segments and also reduced planned capital expenditures by approximately $200 million, which highlights Duke Energy’s ability to take advantage of the flexibility within its capital spending plan. Additionally, Duke Energy’s generation fleet operated at some of the highest levels in Duke Energy’s history. These combined efforts allowed Duke Energy to largely mitigate the negative impact of the economy on its results of operations in 2009.

Key Regulatory Accomplishments. During 2009, Duke Energy completed the following regulatory initiatives:

Overall, the regulatory and legislative accomplishments during 2009 have positioned Duke Energy well for 2010 and beyond.

Capital Expenditures and Fleet and Grid Modernization. Duke Energy’s strategy for meeting customer demand, while building a sustainable business that allows its customers and its shareholders to prosper in a carbon-constrained environment, includes significant commitments to renewable energy, customer energy efficiency, advanced nuclear power, advanced clean-coal and high-efficiency natural gas electric generating plants, and retirement of older less efficient coal-fired power plants. Due to the likelihood of upcoming environmental regulations, including carbon legislation, air pollutant regulation by the U.S. Environmental Protection Agency (EPA) and coal regulation, Duke Energy has been focused on modernizing its fleet in preparation for a low carbon future. During 2009, Duke Energy has continued the construction of Cliffside Unit 6 in North Carolina and the Edwardsport IGCC plant in Indiana and these construction projects are approximately 55% complete and 50% complete, respectively, at December 31, 2009. Both are scheduled to be placed in service during 2012. Once in service, Duke Energy will begin retiring older, less efficient coal and gas-fired units. Additionally, Duke Energy Carolinas has begun construction on a 620 megawatt (MW) combined cycle natural gas-fired generating facility at each of its existing Buck and Dan River Steam Stations. These facilities are scheduled to be placed in service in 2011 and 2012, respectively. In conjunction with these and other capital projects, management is continuing its focus on reducing regulatory lag, which refers to the period of time between making an investment and earning a return and recovering that investment. In 2007, the Indiana Utility Regulatory Commission (IURC) approved the timely recovery of initial construction cost estimates associated with the Edwardsport IGCC plant. The 2009 rate case settlements in North Carolina and South Carolina included stipulations allowing for the recovery in base rates of financing costs related to Cliffside Unit 6, although the recovery is delayed in North Carolina for a one year period.

Duke Energy Carolinas is also continuing to seek all necessary regulatory approvals for the proposed William States Lee III Nuclear Station, including the December 2007 filings of a Combined Construction and Operating License (COL) application with the Nuclear Regulatory Commission (NRC) and requests to incur up to $230 million in development costs through 2009, which were approved in 2008. Although these actions are necessary steps as management continues to pursue the option of building a new nuclear plant, submitting these applications does not commit Duke Energy Carolinas to build a nuclear unit.

In 2009, Duke Energy made significant strides in adding to its existing renewable energy portfolio. One way Duke Energy is reducing its environmental footprint while meeting demand for reliable, clean energy is by investing in zero carbon wind power. During 2009, Commercial Power, through Duke Energy Generation Services (DEGS), brought approximately 364 MW of wind generation online through a combination of completed construction and acquisition. At December 31, 2009, DEGS had approximately 735 MW of wind generation in commercial operation. The wind assets in service have long-term power purchase agreements to sell the output to an end customer. Additionally, DEGS became an owner in a biomass development joint venture and, in early 2010, announced it would acquire a 16 MW solar development project in San Antonio, Texas.

Management is also making progress on increasing the role energy efficiency will have in meeting customers’ growing energy needs. Energy efficiency is considered a “fifth fuel” in the portfolio available to meet customers’ growing needs for electricity, along with coal, nuclear, natural gas and renewable energy. During 2009, Duke Energy’s save-a-watt models were approved in North Carolina, South Carolina and Ohio and Duke Energy is awaiting a decision on the proposed save-a-watt model in Indiana, which is expected in the first quarter of 2010. The save-a-watt proposal in Kentucky was withdrawn and will be addressed in Duke Energy Kentucky’s next general rate case.

Duke Energy Objectives – 2010 and beyond. Duke Energy will continue to focus on operational excellence, shaping federal and state legislative and regulatory policy, continued modernization of infrastructure and investing in renewable energy, including energy efficiency. The majority of future earnings are anticipated to be contributed from U.S. Franchised Electric and Gas, which consists of Duke Energy’s regulated businesses that currently own a capacity of approximately 27,000 MW of generation. The regulated generation portfolio consists of a mix of coal, nuclear, natural gas and hydroelectric generation, with the substantial majority of all of the sales of electricity coming from coal and nuclear generation facilities. The favorable rate case outcomes reached in the various jurisdictions in 2009, as discussed above, will increase U.S. Franchised Electric and Gas’ revenues by approximately $460 million upon full implementation.

As a result of the downturn in the economy, Duke Energy experienced reductions in sales volumes in 2009, most notably within the industrial customer class. Management anticipates that recessionary pressures will continue in 2010, resulting in essentially flat kilowatt-hour sales in both the Carolinas and the Midwest service territories. In order to address these pressures, management is focused on containing costs in 2010 and currently expects non-recoverable (i.e., not directly recovered via a rider or other mechanism) operations and maintenance expense to be flat compared to 2009, due largely to sustainable reductions achieved during 2009, as well as certain 2010 initiatives such as a voluntary severance program and office consolidation. In addition, management will continue efforts to achieve constructive regulatory outcomes to reduce regulatory lag, including continually reviewing the need for general rate case filings in certain jurisdictions in 2010 and beyond.

Additionally, due to the competitive markets in Ohio, customer switching will continue to impact the results of the Commercial Power business, as management currently estimates that an incremental 5% of current customer load will switch to alternative suppliers in 2010. Management is focused on mitigating lost volume and margin erosion in 2010 through DERS efforts to acquire native load customers, as well as acquiring customers outside of Commercial Power’s Ohio native load territory that are currently supplied by other electric generators.

During the three-year period from 2010 through 2012, Duke Energy anticipates total capital expenditures of approximately $14 billion to $15 billion. Of this amount, approximately $5.7 billion is expected to be spent on committed projects, including base load power plants to meet long-term growth in customer demand and to modernize the generation fleet, ongoing environmental projects, and nuclear fuel. Approximately $6.8 billion of capital expenditures are expected to be used primarily for overall system maintenance, customer connections, and corporate expenditures. Although these expenditures are ultimately necessary to ensure overall system maintenance and reliability, the timing of the expenditures may be influenced by broad economic conditions and customer growth. The remaining estimated capital expenditures of approximately $1.2 billion to $2.7 billion are of a discretionary nature and relate to growth opportunities in which Duke Energy may invest, provided there are opportunities to meet return expectations along with assurance of constructive regulatory treatment in the regulated businesses. Discretionary capital primarily includes Commercial Power renewable and transmission projects, projects at International Energy and renewable projects at U.S. Franchised Electric and Gas. Capital expenditures are currently estimated to be approximately $5.2 billion in 2010. These expenditures are principally related to expansion plans, maintenance costs, environmental spending related to Clean Air Act (CAA) requirements and nuclear fuel. Duke Energy is committed to adding base load capacity at a reasonable price while modernizing the current generation facilities by replacing older, less efficient plants with cleaner, more efficient plants. Significant expansion projects include the Edwardsport IGCC plant, an 825 MW coal unit at Duke Energy Carolinas’ existing Cliffside facility and new gas-fired generation units at Duke Energy Carolinas’ existing Dan River and Buck Steam Stations, as well as other additions due to system growth. Additionally, Duke Energy is evaluating the potential construction of the William States Lee III nuclear power plant in Cherokee County, South Carolina.

Duke Energy anticipates capital expenditures at Commercial Power will primarily relate to growth opportunities, such as renewable energy generation projects and environmental control equipment, as well as maintenance on existing plants. Capital expenditures at International Energy, which will be funded with cash held or raised by International Energy, will primarily be for strategic growth opportunities, as well as maintenance on existing plants.

With the exception of equity issuances to fund the dividend reinvestment plan and other internal plans, Duke Energy does not currently anticipate the issuance of any other common equity in the foreseeable future. Duke Energy expects to have access to liquidity in the capital markets at reasonable rates and terms in 2010. Additionally, Duke Energy has access to unsecured revolving credit facilities, which are not restricted upon general market conditions, with aggregate bank commitments of approximately $3.14 billion. At December 31, 2009, Duke Energy has available borrowing capacity of approximately $1.9 billion under this facility. For further information related to management’s assessment of liquidity and capital resources, including known trends and uncertainties, see “Liquidity and Capital Resources” below.

As the majority of Duke Energy’s anticipated future capital expenditures are related to its regulated operations, a risk to Duke Energy is the ability to recover costs related to such expansion in a timely manner. Energy legislation passed in North Carolina and South Carolina in 2007 provides, among other things, mechanisms for Duke Energy to recover financing costs for new nuclear or coal base load generation during the construction phase. In Indiana, Duke Energy has received approval to recover its development costs for the new IGCC plant at the Edwardsport Generating Station. Duke Energy has received approval for nearly $260 million of future federal tax credits related to costs to be incurred for the modernization of Cliffside Unit 6, as well as the IGCC plant in Indiana. In addition, Duke Energy has received general assurances from the North Carolina Utilities Commission (NCUC) that the North Carolina allocable portion of development costs associated with the William States Lee III nuclear station will be recoverable through a future rate case proceeding as long as the costs are deemed prudent and reasonable. Duke Energy does not anticipate beginning construction of the proposed nuclear power plant without adequate assurance of cost recovery from the state legislators or regulators.

In summary, Duke Energy is coordinating its future capital expenditure requirements with regulatory initiatives in order to ensure adequate and timely cost recovery while continuing to provide low cost energy to its customers.

Economic Factors for Duke Energy’s Business. Duke Energy’s business model provides diversification between stable regulated businesses like U.S. Franchised Electric and Gas and certain portions of Commercial Power’s operations, and the traditionally higher-growth businesses like the unregulated portion of Commercial Power’s operations and International Energy. As was the case throughout much of 2009, all of Duke Energy’s businesses can be negatively affected by sustained downturns or sluggishness in the economy, including low market prices of commodities, all of which are beyond Duke Energy’s control, and could impair Duke Energy’s ability to meet its goals for 2010 and beyond.

As Duke Energy experienced in 2009, declines in demand for electricity as a result of economic downturns reduce overall electricity sales and have the potential to lessen Duke Energy’s cash flows, especially as industrial customers reduce production and, thus, consumption of electricity. A weakening economy could also impact Duke Energy’s customer’s ability to pay, causing increased delinquencies, slowing collections and lead to higher than normal levels of accounts receivables, bad debts and financing requirements. A portion of U.S. Franchised Electric and Gas’ business risk is mitigated by its regulated allowable rates of return and recovery of fuel costs under fuel adjustment clauses. The ESP in Ohio also helps mitigate a portion of the risk associated with certain portions of Commercial Power’s generation operations by providing mechanisms for recovery of certain costs associated with, among other things, fuel and purchased power for native-load customers.

If negative market conditions should persist over time and estimated cash flows over the lives of Duke Energy’s individual assets, including goodwill, do not exceed the carrying value of those individual assets, asset impairments may occur in the future under existing accounting rules and diminish results of operations. A change in management’s intent about the use of individual assets (held for use versus held for sale) could also result in impairments or losses.

Duke Energy’s 2010 goals can also be substantially at risk due to the regulation of its businesses. Duke Energy’s businesses in the United States (U.S.) are subject to regulation on the federal and state level. Regulations, applicable to the electric power industry, have a significant impact on the nature of the businesses and the manner in which they operate. New legislation and changes to regulations are ongoing, including anticipated carbon legislation, and Duke Energy cannot predict the future course of changes in the regulatory or political environment or the ultimate effect that any such future changes will have on its business.

Duke Energy’s earnings are impacted by fluctuations in commodity prices. Exposure to commodity prices generates higher earnings volatility in the unregulated businesses as there are timing differences as to when such costs are recovered in rates. To mitigate these risks, Duke Energy enters into derivative instruments to effectively hedge some, but not all, known exposures.

Additionally, Duke Energy’s investments and projects located outside of the United States expose Duke Energy to risks related to laws of other countries, taxes, economic conditions, fluctuations in currency rates, political conditions and policies of foreign governments. Changes in these factors are difficult to predict and may impact Duke Energy’s future results.

Duke Energy also relies on access to both short-term money markets and longer-term capital markets as a source of liquidity for capital requirements not met by cash flow from operations. An inability to access capital at competitive rates or at all could adversely affect Duke Energy’s ability to implement its strategy. Market disruptions or a downgrade of Duke Energy’s credit rating may increase its cost of borrowing or adversely affect its ability to access one or more sources of liquidity. Additionally, there are no assurances that commitments made by lenders under Duke Energy’s credit facilities will be available if needed as a source of funding due to ongoing uncertainties in the financial services industry.

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

Year Ended December 31, 2009 as Compared to December 31, 2008. Consolidated operating revenues for 2009 decreased approximately $476 million compared to 2008. This change was primarily driven by the following:

Year Ended December 31, 2008 as Compared to December 31, 2007. Consolidated operating revenues for 2008 increased approximately $487 million compared to 2007. This change was primarily driven by the following:

Year Ended December 31, 2009 as Compared to December 31, 2008. Consolidated operating expenses for 2009 decreased approximately $247 million compared to 2008. This change was driven primarily by the following:

Year Ended December 31, 2008 as Compared to December 31, 2007. Consolidated operating expenses for 2008 increased approximately $543 million compared to 2007. This change was driven primarily by the following:

Consolidated gains (losses) on sales of other assets and other, net was a gain of approximately $36 million and $69 million in 2009 and 2008, respectively, and a loss of approximately $5 million for 2007. The gains and losses for all years relate primarily to sales of emission allowances by U.S. Franchised Electric and Gas and Commercial Power.

Year Ended December 31, 2009 as Compared to December 31, 2008. For 2009, consolidated operating income decreased approximately $262 million compared to 2008. Drivers to operating income are discussed above.

Year Ended December 31, 2008 as Compared to December 31, 2007. For 2008, consolidated operating income increased approximately $18 million compared to 2007. Drivers to operating income are discussed above.

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

Year Ended December 31, 2009 as Compared to December 31, 2008. For 2009, consolidated other income and expenses increased approximately $212 million compared to 2008. This increase was primarily driven by an increase in equity earnings of approximately $172 million due mostly to impairment charges recorded by Crescent JV (Crescent) in 2008, of which Duke Energy’s proportionate share was approximately $238 million, partially offset by decreased equity earnings from International Energy of approximately $55 million primarily related to lower contributions from its investment in National Methanol Company (NMC) and losses from its investment in Attiki Gas Supply S.A. (Attiki). Also, the mark-to-market and investment income on investments that support benefit obligations and within the captive insurance portfolio increased approximately $45 million as a result of gains in 2009 compared to losses in 2008. Additionally, foreign exchange impacts, primarily related to the remeasurement of certain U.S. dollar denominated cash and debt balances at International Energy, resulted in gains in 2009 compared to losses in 2008 due to favorable foreign exchange rates, resulting in an increase of approximately $43 million in 2009 compared to 2008. Partially offsetting these increases was decreased interest income of approximately $53 million due primarily to lower average cash and short-term investment balances, an approximate $26 million charge in 2009 related to certain performance guarantees Duke Energy had issued on behalf of Crescent and an approximate $18 million impairment charge in 2009 to write down the carrying value of International Energy’s investment in Attiki to its fair value.

Year Ended December 31, 2008 as Compared to December 31, 2007. For 2008, consolidated other income and expenses decreased approximately $307 million compared to 2007. This decrease was primarily driven by a decrease in equity earnings of approximately $259 million due primarily to impairment charges recorded by Crescent, of which Duke Energy’s proportionate share was approximately $238 million, partially offset by increased equity earnings from International Energy of approximately $25 million primarily related to its investment in NMC primarily as a result of higher margins, an approximate $62 million decrease in interest income primarily due to favorable income tax settlements in 2007 and lower earnings on invested cash and short-term investment balances during 2008 as compared to 2007, an approximate $54 million decrease due to unfavorable investment returns and an approximate $34 million decrease associated with foreign currency losses due primarily to losses in 2008 associated with the remeasurement of certain U.S. dollar denominated cash and debt balances at International Energy, partially offset by an approximate $80 million increase in the equity component of allowance for funds used during construction (AFUDC) as a result of increased capital spending and the absence of convertible debt charges of approximately $21 million recognized in 2007 related to the spin-off of Spectra Energy Corp. (Spectra Energy).

Year Ended December 31, 2009 as Compared to December 31, 2008. Consolidated interest expense increased approximately $10 million in 2009 as compared to 2008. This increase is primarily attributable to higher debt balances, partially offset by lower average interest rates on floating rate debt and commercial paper balances.

Year Ended December 31, 2008 as Compared to December 31, 2007. Consolidated interest expense increased approximately $56 million in 2008 as compared to 2007. This increase is primarily attributable to higher debt balances, partially offset by a higher debt component of AFUDC and capitalized interest due to increased capital spending.

Year Ended December 31, 2009 as Compared to December 31, 2008. For 2009, consolidated income tax expense from continuing operations increased approximately $142 million compared to 2008. Although pre-tax income was lower in 2009 compared to 2008, the effective tax rate for the year ended December 31, 2009 was approximately 41% compared to 33% for the year ended December 31, 2008 due primarily to an approximate $371 million non-deductible goodwill impairment charge in 2009.

Year Ended December 31, 2008 as Compared to December 31, 2007. For 2008, consolidated income tax expense from continuing operations decreased approximately $96 million compared to 2007. This decrease primarily resulted from lower pre-tax income in 2008 compared to 2007. The effective tax rate for the year ended December 31, 2008 increased to approximately 33% compared to 32% for the year ended December 31, 2007. The increase in the effective tax rate during 2008 is primarily attributable to adjustments related to prior year tax returns, an increase in foreign taxes, a decrease in the manufacturing deduction and a deferred state tax benefit recorded in 2007 partially offset by higher AFUDC equity and a tax benefit recorded for certain foreign restructurings.

Consolidated income (loss) from discontinued operations was income of approximately $12 million and $16 million for 2009 and 2008, respectively, and a loss of $22 million for 2007. The 2008 amount is primarily comprised of Commercial Power’s sale of its 480 MW natural gas-fired peaking generating station located near Brownsville, Tennessee to Tennessee Valley Authority, which resulted in an approximate $15 million after-tax gain.

The 2007 amount is primarily comprised of an after-tax loss of approximately $18 million associated with former Duke Energy North America (DENA) contract settlements, an after-tax loss of approximately $8 million related to Cinergy Corp. (Cinergy) commercial marketing and trading operations and after-tax earnings of approximately $23 million related to Commercial Power’s synfuel operations.

The reapplication of regulatory accounting treatment to certain of Commercial Power’s operations on December 17, 2008 resulted in an approximate $67 million after-tax (approximately $103 million pre-tax) extraordinary gain related to total mark-to-market losses previously recorded in earnings associated with open forward native load economic hedge contracts for fuel, purchased power and emission allowances, which the ESP allows to be recovered through a fuel and purchased power rider.

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

See Note 2 to the Consolidated Financial Statements, “Business Segments,” for a discussion of Duke Energy’s segment structure.

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

Noncontrolling interest amounts presented below includes only expenses and benefits related to EBIT of Duke Energy’s joint ventures. It does not include the noncontrolling interest component related to interest and taxes of the joint ventures.

Segment EBIT, as discussed below, includes intercompany revenues and expenses that are eliminated in the Consolidated Financial Statements.

U.S. Franchised Electric and Gas includes the regulated operations of Duke Energy Carolinas, LLC (Duke Energy Carolinas), Duke Energy Indiana, Inc. (Duke Energy Indiana), and Duke Energy Kentucky, Inc. (Duke Energy Kentucky) and certain regulated operations of Duke Energy Ohio, Inc. (Duke Energy Ohio).

The following table shows the percent changes in GWh sales and average number of customers for Duke Energy Carolinas.

The following table shows the percent changes in GWh sales and average number of customers for Duke Energy Midwest.

Gains (Losses) on Sales of Other Assets and Other, net. The increase is primarily due to gains on the sale of nitrogen oxide (NO_x) emission allowances in 2009.

Other Income and Expenses, net. The increase is due primarily to a higher equity component of AFUDC earned from additional capital spending for ongoing construction projects, partially offset by a favorable 2008 IURC ruling.

EBIT. The decrease resulted primarily from lower weather adjusted sales volumes, milder weather, lower wholesale power revenues, higher benefits costs and higher property and other taxes. These negative impacts were partially offset by decreased operation and maintenance costs as a result of lower outage and maintenance costs, lower depreciation rates in the Carolinas and overall net higher rates and rate riders.

U.S. Franchised Electric and Gas continues to increase the overall number of retail customers served, maintain low costs and deliver high-quality customer service in the Carolinas and Midwest; however, sales to all retail customer classes were negatively impacted by the economic downturn in 2009, particularly sales to the industrial sector. These trends are expected to continue for some period into 2010, and perhaps beyond, until the economy begins to recover. The general decline in the textile industry in the Carolinas, exacerbated by the struggling economy, is also expected to continue in 2010, fueled by the expiration of certain import limitations related to foreign textile products.

U.S. Franchised Electric and Gas evaluates the carrying amount of its recorded goodwill for impairment on an annual basis as of August 31 and performs interim impairment assessments if a triggering event occurs that indicates it is more likely than not that the fair value of a reporting unit is less than its carrying value. For further information on key assumptions that impact U.S. Franchised Electric and Gas’ goodwill impairment assessments, see Critical Accounting Policy for Goodwill Impairment Assessments. As of the date of the 2009 annual impairment analysis, the fair value of U.S. Franchised Electric and Gas’ reporting units exceeded their respective carrying value, thus no goodwill impairment charges were recorded. However, the fair value of the Ohio Transmission and Distribution reporting unit (Ohio T&D), which had a goodwill balance of approximately $700 million as of December 31, 2009, exceeded the carrying value of equity by less than 15%. Management is continuing to monitor the impact of recent market and economic events to determine if it is more likely than not that the carrying value of the Ohio T&D reporting unit has been impaired. Should any such triggering events or circumstances occur in 2010 that would more likely than not reduce the fair value of the Ohio T&D reporting unit below its carrying value, management would perform an interim impairment assessment of the Ohio T&D goodwill and it is possible that a goodwill impairment charge could be recorded as a result of this assessment. Potential circumstances that could have a negative effect on the fair value of the Ohio T&D reporting unit include additional declines in load volume forecasts, changes in the weighted average cost of capital (WACC), changes in the timing and/or recovery of and on investments in SmartGrid technology, and the success of future rate case filings.

Other Income and Expenses, net. The increase is due primarily to the equity component of AFUDC due to additional capital spending for ongoing construction projects and a favorable $25 million IURC ruling.

EBIT. The increase resulted primarily from decreased regulatory amortization, the substantial completion of the required rate reductions due to the merger with Cinergy and increased AFUDC. These increases were partially offset by the impacts of the unfavorable economy on sales, milder weather, additional depreciation as rate base increased during 2008, higher operation and maintenance costs, overall net lower retail rates and rate riders, and the 2007 DOE settlement.

Gains (Losses) on Sales of Other Assets and Other, net. The decrease in 2009 compared to 2008 is attributable to lower gains on sales of emission allowances.

Other Income and Expenses, net. The increase in 2009 compared to 2008 is attributable to higher equity earnings of unconsolidated affiliates in 2009 primarily as a result of a full year of equity earnings from investments held by Catamount Energy Corporation (Catamount). Catamount, which is a leading wind power company, was acquired in September 2008. Partially offsetting this increase was a 2009 impairment charge to the carrying value of an equity method investment.

EBIT. The decrease is primarily attributable to higher impairment charges in 2009 primarily due to a goodwill impairment charge, partially offset by a 2008 impairment charge related to emission allowance, increased plant maintenance expenses and fewer gains on sales of emission allowances. These factors were partially offset by higher retail revenue pricing as a result of implementation of the ESP, higher margins from the Midwest gas-fired assets due to increased generation volumes and PJM capacity revenues.

Commercial Power’s current strategy is focused on maintaining its competitive position in Ohio, maximizing the returns and cash flows from its current portfolio, as well as growing its non-regulated renewable energy portfolio. Results for Commercial Power are sensitive to changes in power supply, power demand, fuel and power prices and weather, as well as dependent upon completion of energy asset construction projects and tax credits on renewable energy production.

Recently, low commodity prices have put downward pressure on power prices. The available capacity and lower prices have provided opportunities for customers in Ohio to switch generation suppliers. Competitive power suppliers have begun supplying power to current Commercial Power customers in Ohio and Commercial Power has experienced an increase in customer switching in the second half of 2009. Customer switching is anticipated to continue in 2010 and could have a significant impact on Commercial Power’s results. Additionally, these evolving market conditions may potentially impact Commercial Power’s ability to continue to apply regulatory accounting treatment to certain portions of its Commercial Power business segment. As of December 31, 2009, Commercial Power had regulatory assets of approximately $163 million related to under-collections under its ESP and mark-to-market losses on certain economic hedges.

As discussed in Note 11 to the Consolidated Financial Statements, “Goodwill and Intangible Assets,” Commercial Power recorded an impairment charge in the third quarter of 2009 of approximately $371 million within its non-regulated generation reporting unit to write down the goodwill to its implied fair value. As a result of this impairment charge, the carrying value of goodwill associated with the non-regulated generation reporting unit of approximately $520 million is equivalent to its implied fair value. This impairment charge was based on a number of factors, including a decline in load forecast, depressed market power prices, customer switching and carbon emission legislation and/or EPA regulation developments. Should the assumptions used related to these factors change in the future as a result of then market conditions, as well as any acceleration in the timing of carbon emission legislation/EPA regulation developments, it is possible that further goodwill impairment charges could be recorded. For further information on key assumptions that impact Commercial Power’s goodwill impairment assessments, see Critical Accounting Policy for Goodwill Impairment Assessments.

Gains (Losses) on Sales of Other Assets and Other, net. The increase in 2008 as compared to 2007 is attributable to gains on sales of emission allowances in 2008 compared to losses on sales of emission allowances in 2007. Gains in 2008 were a result of sales of zero cost basis emission allowances, while losses in 2007 were as a result of sales of emission allowances acquired in connection with Duke Energy’s merger with Cinergy in 2006 which were written up to fair value as part of purchase accounting.

EBIT. The decrease is primarily attributable to higher mark-to-market losses on economic hedges due to decreasing commodity prices, the impairment of emission allowances, lower retail and wholesale revenues resulting from lower volumes due to the weakening economy and plant outages. Partially offsetting these decreases were gains on sales of zero cost basis emission allowances, lower emission allowance expense due to lower cost basis emission allowances consumed and lower consumption due to installation of flue gas desulfurization equipment and lower purchase accounting expense primarily due to the Rate Stabilization Plan (RSP) valuation.

Other Income and Expenses, net. The decrease was driven primarily by a $41 million decrease in equity earnings at NMC as a result of lower pricing for both methanol and methyl tertiary butyl ether (MTBE), partially offset by lower butane costs, an approximate $18 million impairment of the investment in Attiki and approximately $14 million of decreased equity earnings at Attiki due to lower margins and the absence of prior year hedge income due to hedge contract terminations.

EBIT. The decrease in EBIT was primarily due to lower equity earnings at NMC and Attiki, an impairment of the investment in Attiki and unfavorable exchange rates and transmission adjustments in Brazil, partially offset by favorable hydrology in Brazil and Central America and lower operating expenses in Peru.

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

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

As noted above, International Energy is committed to selectively growing its Latin American power generation business while continuing to maximize the returns and cash flow from its current portfolio. However, International Energy periodically evaluates all of its businesses to ensure those businesses continue to align with its overall strategies. As such, International Energy is in the early stages of exploring a possible sale of certain long-lived assets in Latin America. The estimated fair value for these assets currently being evaluated for potential sale is less than carrying value. Consistent with generally accepted accounting principles (GAAP), write-downs to fair value have not been recorded on these long-lived assets as the forecasted undiscounted cash flows for the assets exceed the carrying value. In 2010, it is possible that a write-down of the carrying value of these assets to fair value could occur if a sale at an amount below carrying value becomes likely.

Other Income and Expenses, net. The increase was driven primarily by a $16 million increase in equity earnings at NMC as a result of higher pricing and volumes for both methanol and MTBE and approximately $9 million of increased equity earnings at Attiki due to a hedge termination.

EBIT. The increase in EBIT was primarily due to higher average prices, increased demand, and favorable exchange rates in Brazil, higher MTBE and methanol margins and sales volumes at NMC; partially offset by unfavorable hydrology, higher royalty fees and the lack of the 2007 transmission congestion in Peru, and unfavorable results in Guatemala, primarily due to higher fuel prices and maintenance costs.

Operating Income. The increase was primarily due to favorable results at Duke Energy Trading and Marketing (DETM) and Bison Insurance Company Limited (Bison) and lower corporate costs, partially offset by higher deferred compensation expense due to improved market performance.

Other Income and Expenses, net. The increase was due primarily to impairment charges recorded by Crescent in 2008, for which Duke Energy’s proportionate share was approximately $238 million, with no comparable losses in 2009, and favorable returns on investments that support benefit obligations. Partially offsetting these favorable variances was a 2009 charge related to certain performance guarantees Duke Energy had issued on behalf of Crescent.

EBIT. The increase was due primarily to prior year losses at Crescent, favorable results at Bison and DETM and lower corporate costs, partially offset by a 2009 charge related to certain performance guarantees Duke Energy had issued on behalf of Crescent.

Other’s future results could be impacted by continued volatility in the debt and equity markets and other economic conditions, which could result in the recording of other-than-temporary impairment charges for investments in debt and equity securities, including certain investments in auction rate debt securities. Duke Energy analyzes all investments in debt and equity securities to determine whether a decline in fair value should be considered other-than-temporary. Criteria used to evaluate whether an impairment is other-than-temporary

includes, but is not limited to, the length of time over which the market value has been lower than the cost basis of the investment, the percentage decline compared to the cost of the investment and management’s intent and ability to retain its investment in the issuer for a period of time sufficient to allow for any anticipated recovery in market value. For investments in debt securities, the other-than-temporary analysis also involves the consideration of underlying collateral and guarantees of principal by government entities, as well as other factors relevant to determine the amount of credit loss, if any.

In January 2010, Duke Energy announced plans to offer a voluntary severance plan to approximately 8,750 eligible employees. As this is a voluntary plan, all severance benefits offered under this plan are considered special termination benefits under GAAP. Special termination benefits are measured upon employee acceptance and recorded immediately absent a significant retention period. If a significant retention period exists, the costs of the special termination benefits are recorded ratably over the remaining service periods of the affected employees. The window for employees to request to voluntarily end their employment under this plan opened on February 3, 2010 and closed on February 24, 2010 for approximately 8,400 eligible employees. For employees affected by the consolidation of Duke Energy’s corporate functions in Charlotte, North Carolina, as discussed further below, the window will close March 31, 2010. Duke Energy currently estimates severance payments associated with this voluntary plan, based on employees’ requests to voluntarily end their employment received through February 24, 2010, of approximately $130 million. However, until management of Duke Energy approves the requests, it reserves the right to reject any request to volunteer based on business needs and/or excessive participation.

In addition, in January 2010, Duke Energy announced that it will consolidate certain corporate office functions, resulting in transitioning over the next two years of approximately 350 positions from its offices in the Midwest to its corporate headquarters in Charlotte, North Carolina. Employees who do not relocate have the option to elect to participate in the voluntary plan discussed above, find a regional position within Duke Energy or remain with Duke Energy through a transition period, at which time a reduced severance benefit would be paid under Duke Energy’s ongoing severance plan. Management cannot currently estimate the costs, if any, of severance benefits which will be paid to its employees due to this office consolidation.

Duke Energy believes that it is possible that the voluntary severance plan may trigger settlement accounting or curtailment accounting with respect to its pension and other post-retirement benefit plans. At this time, management is unable to determine the likelihood that settlement or curtailment accounting will be triggered.

Additionally, Duke Energy has a 50% ownership interest in Crescent, a partnership for U.S. tax purposes. Crescent filed for Chapter 11 Bankruptcy in a U.S. Bankruptcy Court in June 2009. As of December 31, 2009, Duke Energy believes it is more likely than not that all tax benefits associated with its investment in Crescent will be realized. However, the form, timing and structure of Crescent’s future emergence from bankruptcy remain unresolved. Based on this uncertainty, as of December 31, 2009, it is reasonably possible that Duke Energy could incur a future tax liability related to its inability to fully utilize tax losses associated with its partnership interest in Crescent and the resolution of Crescent’s emergence from bankruptcy.

Operating Revenues. The reduction was driven primarily by higher premiums earned by Bison in 2007 related to the assumption of liabilities by Bison from other Duke Energy business units.

Operating Expenses. The reduction was primarily driven by the establishment of reserves related to liabilities assumed by Bison from other Duke Energy business units in 2007 with no comparable charges in 2008, a prior year donation to the Duke Foundation, reduced benefit costs, and decreased severance costs. These favorable variances were partially offset by a prior year benefit related to contract settlement negotiations and unfavorable property loss experience at Bison.

Other Income and Expenses, net. The increase in net expense was primarily driven by approximately $230 million of losses at Crescent in 2008 compared to earnings of approximately $38 million in 2007 due to Duke Energy recording its proportionate share of impairment charges recorded by Crescent and lower earnings as a result of the downturn in the real estate market, unfavorable returns on investments related to executive life insurance and lower investment income at Bison, partially offset by prior year convertible debt charges of approximately $21 million related to the spin-off of Spectra Energy with no comparable charges in 2008.

EBIT. The decrease was due to Duke Energy’s proportionate share of impairment charges recorded by Crescent and lower overall earnings at Crescent, a prior year benefit related to contract settlement negotiations, unfavorable investment returns and unfavorable property loss experience at Bison, partially offset by a prior year donation to Duke Foundation, prior year convertible debt charges, decreased severance costs and reduced benefits costs.

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

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

Certain of Duke Energy’s regulated operations (primarily the majority of U.S. Franchised Electric and Gas and certain portions of Commercial Power) meet the criteria for application of regulatory accounting treatment. As a result, Duke Energy records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP in the U.S. for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections for costs that either are not likely to or have yet to be incurred. Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes, historical regulatory treatment for similar costs in Duke Energy’s jurisdictions, recent rate orders to other regulated entities, and the status of any pending or potential deregulation legislation. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. This assessment reflects the current political and regulatory climate at the state and federal levels, and is subject to change in the future. If future recovery of costs ceases to be probable, the asset write-offs would be required to be recognized in operating income. Additionally, the regulatory agencies can provide flexibility in the manner and timing of the depreciation of property, plant and equipment, recognition of nuclear decommissioning costs and amortization of regulatory assets. Total regulatory assets were $3,886 million as of December 31, 2009 and $4,077 million as of

December 31, 2008. Total regulatory liabilities were $3,108 million as of December 31, 2009 and $2,678 million as of December 31, 2008. For further information, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters.”

In order to apply regulatory accounting treatment and record regulatory assets and liabilities, certain criteria must be met. In determining whether the criteria are met for its operations, management makes significant judgments, including determining whether revenue rates for services provided to customers are subject to approval by an independent, third-party regulator, whether the regulated rates are designed to recover specific costs of providing the regulated service, and a determination of whether, in view of the demand for the regulated services and the level of competition, it is reasonable to assume that rates set at levels that will recover the operations’ costs can be charged to and collected from customers. This final criterion requires consideration of anticipated changes in levels of demand or competition, direct and indirect, during the recovery period for any capitalized costs. If facts and circumstances change so that a portion of Duke Energy’s regulated operations meet all of the scope criteria when such criteria had not been previously met, regulatory accounting treatment would be reapplied to all or a separable portion of the operations. Such reapplication includes adjusting the balance sheet for amounts that meet the definition of a regulatory asset or regulatory liability.

Commercial Power owns, operates and manages power plants in the Midwestern United States. Commercial Power’s generation asset fleet consists of Duke Energy Ohio’s generation in Ohio, primarily coal-fired assets, that are dedicated to serve Ohio native load customers (native load), as well as wholesale customers to the extent there is excess generation, and five Midwestern gas-fired non-regulated generation assets that are not dedicated to serve Ohio native load customers (non-native). The non-native generation operations do not qualify for regulatory accounting treatment as these operations do not meet the scope criteria. Most of the generation asset native load output in Ohio was contracted through the RSP through December 31, 2008. As discussed further in the notes to the Consolidated Financial Statements, specifically Note 1, “Summary of Significant Accounting Policies” and Note 4, “Regulatory Matters”, beginning on December 17, 2008, Commercial Power began applying regulatory accounting treatment to certain portions of its native load operations due to the passing of Ohio Senate Bill 221 (SB 221) and the approval of the ESP. However, other portions of Commercial Power’s native load operations continue to not qualify for regulatory accounting treatment, as certain costs of the native load operations do not result in a rate structure designed to recover the specific costs of that portion of the operations. Despite certain portions of the Ohio native load operations not qualifying for regulatory accounting treatment, all of Commercial Power’s Ohio native load operations’ rates are subject to approval by the PUCO, and thus these operations are referred to here-in as Commercial Power’s regulated operations. Moreover, generation remains a competitive market in Ohio and native load customers continue to have the ability to switch to alternative suppliers for their electric generation service. As customers switch, there is a risk that some or all of Commercial Power’s regulatory assets will not be recovered through the established riders. Duke Energy will continue to monitor the amount of native load customers that have switched to alternative suppliers when assessing the recoverability of its regulatory assets established for its native load generation operations. At December 31, 2009, management has concluded that the established regulatory assets of approximately $163 million are still probable of recovery even though there have been increased levels of customer switching.

No other operations within Commercial Power, and no operations within the International Energy business segment, qualify for regulatory accounting treatment.

The substantial majority of U.S. Franchised Electric and Gas’s operations qualify for regulatory accounting treatment and thus its costs of business and related revenues can result in the recording of regulatory assets and liabilities, as described above.

At December 31, 2009 and 2008, Duke Energy had goodwill balances of $4,350 million and $4,720 million, respectively. At December 31, 2009, the goodwill balances at the segment level were $3,483 million at U.S. Franchised Electric and Gas, $569 million at Commercial Power, and $298 million at International Energy. The majority of Duke Energy’s goodwill relates to the acquisition of Cinergy in April 2006, whose assets are primarily included in the U.S. Franchised Electric and Gas and Commercial Power segments. Commercial Power also has approximately $70 million of goodwill that resulted from the September 2008 acquisition of Catamount, a leading wind power company located in Rutland, Vermont. As of the acquisition date, Duke Energy allocates goodwill to a reporting unit, which Duke Energy defines as an operating segment or one level below an operating segment.

Duke Energy is required to perform an annual goodwill impairment test at the reporting unit level as of the same date each year and, accordingly, performs its annual impairment testing of goodwill for all reporting units as of August 31 each year. Duke Energy updates the test between annual tests if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value. The annual analysis of the potential impairment of goodwill requires a two step process. Step one of the impairment test involves comparing the fair values of reporting units with their aggregate carrying values, including goodwill. If the carrying amount of a reporting unit exceeds the reporting unit’s fair value, step two must be performed to determine the amount, if any, of the goodwill impairment loss. If the carrying amount is less than fair value, further testing of goodwill impairment is not performed. Duke Energy did not record any impairment on its goodwill as a result of the 2008 or 2007 impairment tests.

Step two of the goodwill impairment test involves comparing the implied fair value of the reporting unit’s goodwill against the carrying value of the goodwill. Under step two, determining the implied fair value of goodwill requires the valuation of a reporting unit’s identifiable tangible and intangible assets and liabilities as if the reporting unit had been acquired in a business combination on the testing date. The difference between the fair value of the entire reporting unit as determined in step one and the net fair value of all identifiable assets and liabilities represents the implied fair value of goodwill. The goodwill impairment charge, if any, would be the difference between the carrying amount of goodwill and the implied fair value of goodwill upon the completion of step two.

For purposes of the step one analyses, determination of reporting units’ fair value was based on a combination of the income approach, which estimates the fair value of Duke Energy’s reporting units based on estimated discounted future cash flows, and the market approach, which estimates the fair value of Duke Energy’s reporting units based on market comparables within the utility and energy industries. Based on completion of step one of the 2009 annual impairment tests, management determined that the fair values of all reporting units except for Commercial Power’s non-regulated Midwest generation reporting unit, for which the carrying value of goodwill was approximately $890 million as of the annual impairment testing date, were greater than their respective carrying values. Accordingly, for only Commercial Power’s non-regulated Midwest generation reporting unit, management was required to perform step two of the goodwill impairment test to determine the amount of the goodwill impairment.

Commercial Power’s non-regulated Midwest generation reporting unit includes nearly 4,000 MW of coal-fired generation capacity in Ohio dedicated to serve Ohio native load customers under the ESP through December 31, 2011. These assets, as excess capacity allows, also generate revenues through sales outside the native load customer base, and such revenue is termed non-native. Additionally, this reporting unit has approximately 3,600 MW of gas-fired generation capacity in Ohio, Pennsylvania, Illinois and Indiana. The businesses within Commercial Power’s non-regulated Midwest generation reporting unit operate in an unregulated environment in Ohio. As a result, the operations within this reporting unit are subjected to competitive pressures that do not exist in any of Duke Energy’s regulated jurisdictions.

Commercial Power’s other businesses, including the wind generation assets, are in a separate reporting unit for goodwill impairment testing purposes. No impairment exists with respect to Commercial Power’s wind generation assets.

The fair value of the non-regulated Midwest generation reporting unit is impacted by a multitude of factors, including current and forecasted customer demand, current and forecasted power and commodity prices, impact of the economy on discount rates, valuation of peer companies, competition, and regulatory and legislative developments. Management’s assumptions and views of these factors continually evolves, and such views and assumptions used in determining the step one fair value of the reporting unit in 2009 changed significantly from those used in the 2008 annual impairment test. These factors had a significant impact on the risk-adjusted discount rate and other inputs used to value the non-regulated Midwest generation reporting unit. These factors significantly impacted management’s valuation of the reporting unit, and consequently resulted in an approximate $371 million goodwill impairment charge in 2009.

As noted above, for purposes of the step one analyses, determination of the reporting units’ fair values was based on a combination of the income approach, which estimates the fair value of Duke Energy’s reporting units based on discounted future cash flows, and the market approach, which estimates the fair value of Duke Energy’s reporting units based on market comparables within the utility and energy industries. Key assumptions used in the income approach analyses for the U.S. Franchised Electric and Gas reporting units include, but are not limited to, the use of an appropriate discount rate, estimated future cash flows and estimated run rates of operation, maintenance, and general and administrative costs. In estimating cash flows, Duke Energy incorporates expected growth rates, regulatory stability and ability to renew contracts, as well as other factors, into its revenue and expense forecasts.

Estimated future cash flows under the income approach are based to a large extent on Duke Energy’s internal business plan, and adjusted as appropriate for Duke Energy’s views of market participant assumptions. In addition to the factors noted above for the Commercial Power non-regulated Midwest generation reporting unit, Duke Energy’s internal business plan reflects management’s assumptions related to customer usage and attrition based on internal data and economic data obtained from third party sources, as well as projected commodity pricing data. The business plan assumes the occurrence of certain events in the future, such as the outcome of future rate filings, future approved rates of returns on equity, anticipated earnings/returns related to significant future capital investments, continued recovery of cost of service and the renewal of certain contracts. Management also makes assumptions regarding the run rate of operation, maintenance and general and administrative costs based on the expected outcome of the aforementioned events. Should the actual outcome of some or all of these assumptions differ significantly from the current assumptions, revisions to current cash flow assumptions could cause the fair value of Duke Energy’s reporting units to be significantly different in future periods.

One of the most significant assumptions that Duke Energy utilizes in determining the fair value of its reporting units under the income approach is the discount rate applied to the estimated future cash flows. Management determines the appropriate discount rate for each of its reporting units based on the weighted average cost of capital (WACC) for each individual reporting unit. The WACC takes into account both the cost of equity and pre-tax cost of debt. In calculating the WACCs, Duke Energy considered implied WACC’s for certain peer companies in determining the appropriate WACC rates to use. As each reporting unit has a different risk profile based on the nature of its operations, including factors such as regulation, the WACC for each reporting unit may differ. Accordingly, the WACCs were adjusted, as appropriate, to account for company specific risk premiums. For example, transmission and distribution reporting units generally would have a lower company specific risk premium as they do not have the higher level of risk associated with owning and operating generation assets nor do they have significant construction risk or risk associated with potential future carbon legislation or carbon regulation. The discount rates used for calculating the fair values as of August 31, 2009 for each of Duke Energy’s domestic reporting units were commensurate with the risks associated with each reporting unit and ranged from 6.0% to 9.0%. For Duke Energy’s international operations, a base discount rate of 8.5% was used, with specific adders used for each separate jurisdiction in which International Energy operates to reflect the differing risk profiles of the jurisdictions and countries. This resulted in discount rates for the August 31, 2009 goodwill impairment test for the international operations ranging from approximately 9.5% to 13.5%.

Another significant assumption that Duke Energy utilizes in determining the fair value of its reporting units under the income approach is the long-term growth rate of the businesses for purposes of determining a terminal value at the end of the discrete forecast period. A long-term growth rate of three percent was used in the valuations of all of the U.S. Franchised Electric and Gas reporting units, reflecting the median long-term inflation rate and the significant capital investments forecasted for all of the U.S. Franchised Electric and Gas reporting units. A long-term growth rate of two percent was used in the valuation of the Commercial Power non-regulated Midwest generation reporting unit given the finite lives of the unregulated generation power plants and current absence of plans to reinvest in the unregulated generation assets.

These underlying assumptions and estimates are made as of a point in time; subsequent changes, particularly changes in the discount rates or growth rates inherent in management’s estimates of future cash flows, could result in a future impairment charge to goodwill. Management continues to remain alert for any indicators that the fair value of a reporting unit could be below book value and will assess goodwill for impairment as appropriate.

As discussed above, with the exception of the Commercial Power non-regulated Midwest generation reporting unit, the impairment tests as of August 31, 2009 did not indicate that the fair value of any of Duke Energy’s reporting units were less than its book value. For these reporting units, the estimated fair value of equity exceeded the carrying value of equity by over 15%, with the exception of U.S. Franchised Electric and Gas’s Ohio T&D reporting unit. As of December 31, 2009, the Ohio T&D reporting unit had a goodwill balance of approximately $700 million. Potential circumstances that could have a negative effect on the fair value of the Ohio T&D reporting unit include additional declines in load volume forecasts, changes in the WACC, changes in the timing and/or recovery of and on investments in SmartGrid technology, and the success of future rate case filings.

As an overall test of the reasonableness of the estimated fair values of the reporting units, Duke Energy reconciled the combined fair value estimates of its reporting units to its market capitalization as of August 31, 2009. The reconciliation confirmed that the fair values were reasonably representative of market views when applying a reasonable control premium to the market capitalization. Additionally, Duke Energy would perform an interim impairment assessment should any events occur or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. Subsequent to August 31, 2009, management did not identify any indicators of potential impairment that required an update to the annual impairment test. The majority of Duke Energy’s business is in environments that are either fully or partially rate-regulated. In such environments, revenue requirements are adjusted periodically by regulators based on factors including levels of costs, sales volumes and costs of capital. Accordingly, Duke Energy’s regulated utilities operate to some degree with a buffer from the direct effects, positive or negative, of significant swings in market or economic conditions. Additionally, with respect to the Commercial Power non-regulated Midwest generation reporting unit, the Ohio generation assets have begun to be negatively impacted by increased competition. However, the effects of increased competition in Ohio were appropriately considered in the August 31, 2009 valuation of the reporting unit, and subsequent to August 31, 2009 management did not identify any indicators of potential impairment that required an update to the annual impairment test. However, management will continue to monitor changes in the business, as well as overall market conditions and economic factors that could require additional impairment tests.

Revenues on sales of electricity and gas are recognized when either the service is provided or the product is delivered. Operating revenues include unbilled electric and gas revenues earned when service has been delivered but not billed by the end of the accounting period. Unbilled retail revenues are estimated by applying an average revenue per kilowatt-hour (kWh) or per Mcf for all customer classes to

the number of estimated kWh or Mcfs delivered but not billed. Unbilled wholesale energy revenues are calculated by applying the contractual rate per megawatt-hour (MWh) to the number of estimated MWh delivered but not yet billed. Unbilled wholesale demand revenues are calculated by applying the contractual rate per MW to the MW volume delivered but not yet billed. The amount of unbilled revenues can vary significantly from period to period as a result of numerous factors, including seasonality, weather, customer usage patterns and customer mix. Unbilled revenues, which are primarily recorded as Receivables on the Consolidated Balance Sheets and exclude receivables sold to Cinergy Receivables Company, LLC (Cinergy Receivables), were approximately $460 million and $390 million at December 31, 2009 and 2008, respectively. Additionally, Duke Energy Ohio, Duke Energy Kentucky and Duke Energy Indiana sell, on a revolving basis, nearly all of their retail accounts receivable and a portion of their wholesale accounts receivable and related collections to Cinergy Receivables, a bankruptcy remote, special purpose entity that is a wholly-owned limited liability company of Cinergy, a wholly-owned subsidiary of Duke Energy. The securitization transaction was structured to meet the criteria for sale accounting treatment under the accounting guidance for transfers and servicing of financial assets and, accordingly, the transfers of receivables are accounted for as sales. Receivables for unbilled retail and wholesale revenues of approximately $238 million and $266 million at December 31, 2009 and 2008, respectively, were included in the sales of accounts receivables to Cinergy Receivables. Effective January 1, 2010, Duke Energy began consolidating Cinergy Receivables as a result of the adoption of new accounting rules, under which the criteria for sale accounting treatment is not met.

Duke Energy is involved in certain legal and environmental matters that arise in the normal course of business. In the preparation of its consolidated financial statements, management makes judgments regarding the future outcome of contingent events and records a loss contingency when it is determined that it is probable that a loss has occurred and the amount of the loss can be reasonably estimated. Management regularly reviews current information available to determine whether such accruals should be adjusted and whether new accruals are required. Estimating probable losses requires analysis of multiple forecasts and scenarios that often depend on judgments about potential actions by third parties, such as federal, state and local courts and other regulators. Contingent liabilities are often resolved over long periods of time. Amounts recorded in the consolidated financial statements may differ from the actual outcome once the contingency is resolved, which could have a material impact on future results of operations, financial position and cash flows of Duke Energy.

Duke Energy has experienced numerous claims for indemnification and medical cost reimbursement relating to damages for bodily 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 prior to 1985.

Amounts recognized as asbestos-related reserves related to Duke Energy Carolinas in the Consolidated Balance Sheets totaled approximately $980 million and $1,031 million as of December 31, 2009 and 2008, respectively, and are classified in Other within Deferred Credits and Other Liabilities and Other within Current Liabilities. These reserves are based upon the minimum amount in Duke Energy’s best estimate of the range of loss for current and future asbestos claims through 2027. Management believes that it is possible there will be additional claims filed against Duke Energy Carolinas after 2027. In light of the uncertainties inherent in a longer-term forecast, management does not believe that they can reasonably estimate the indemnity and medical costs that might be incurred after 2027 related to such potential claims. Asbestos-related loss estimates incorporate anticipated inflation, if applicable, and are recorded on an undiscounted basis. These reserves are based upon current estimates and are subject to greater uncertainty as the projection period lengthens. A significant upward or downward trend in the number of claims filed, the nature of the alleged injury, and the average cost of resolving each such claim could change our estimated liability, as could any substantial adverse or favorable verdict at trial. A federal legislative solution, further state tort reform or structured settlement transactions could also change the estimated liability. Given the uncertainties associated with projecting matters into the future and numerous other factors outside our control, management believes that it is possible Duke Energy Carolinas may incur asbestos liabilities in excess of the recorded reserves.

Duke Energy has a third-party insurance policy to cover certain losses related to Duke Energy Carolinas’ asbestos-related injuries and damages above an aggregate self insured retention of $476 million. Duke Energy Carolinas’ cumulative payments began to exceed the self insurance retention on its insurance policy during the second quarter of 2008. Future payments up to the policy limit will be reimbursed by Duke Energy’s third party insurance carrier. The insurance policy limit for potential future insurance recoveries for indemnification and medical cost claim payments is $1,051 million in excess of the self insured retention. Insurance recoveries of approximately $984 million and $1,032 million related to this policy are classified in the Consolidated Balance Sheets in Other within Investments and Other Assets and Receivables as of December 31, 2009 and 2008, respectively. Duke Energy is not aware of any uncertainties regarding the legal sufficiency of insurance claims. Management believes the insurance recovery asset is probable of recovery as the insurance carrier continues to have a strong financial strength rating.

For further information, see Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies.”

Significant management judgment is required in determining Duke Energy’s provision for income taxes, deferred tax assets and liabilities and the valuation recorded against Duke Energy’s net deferred tax assets, if any.

Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the book basis and tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The probability of realizing deferred tax assets is based on forecasts of future taxable income and the use of tax planning that could impact the ability to realize deferred tax assets. If future utilization of deferred tax assets is uncertain, a valuation allowance may be recorded against certain deferred tax assets.

In assessing the likelihood of realization of deferred tax assets, management considers estimates of the amount and character of future taxable income. Actual income taxes could vary from estimated amounts due to the impacts of various items, including changes to income tax laws, Duke Energy’s forecasted financial condition and results of operations in future periods, as well as results of audits and examinations of filed tax returns by taxing authorities. Although management believes current estimates are reasonable, actual results could differ from these estimates.

Significant judgment is also required in computing Duke Energy’s quarterly effective tax rate (ETR). ETR calculations are revised each quarter based on the best full year tax assumptions available at that time, including, but not limited to, income levels, deductions and credits. In accordance with interim tax reporting rules, a tax expense or benefit is recorded every quarter to adjust for the difference in tax expense computed based on the actual year-to-date ETR versus the forecasted annual ETR.

With the adoption of new income tax accounting guidance on January 1, 2007, Duke Energy began recording unrecognized tax benefits for positions taken or expected to be taken on tax returns, including the decision to exclude certain income or transactions from a return, when a more-likely-than-not threshold is met for a tax position and management believes that the position will be sustained upon examination by the taxing authorities. Duke Energy records the largest amount of the unrecognized tax benefit that is greater than 50% likely of being realized upon settlement. Management evaluates each position based solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant

management judgment is required to determine whether the recognition threshold has been met and, if so, the appropriate amount of unrecognized tax benefits to be recorded in the Consolidated Financial Statements. Management reevaluates tax positions each period in which new information about recognition or measurement becomes available.

Undistributed foreign earnings associated with International Energy’s operations are considered indefinitely reinvested, thus no U.S. tax is recorded on such earnings. This assertion is based on management’s determination that the cash held in International Energy’s foreign jurisdictions is not needed to fund the operations of its U.S. operations and that International Energy either has invested or has plans to reinvest such earnings. While management currently plans to indefinitely reinvest all of International Energy’s unremitted earnings, should circumstances change, Duke Energy may need to record additional income tax expense in the period in which such determination changes.

For further information, see Note 6 to the Consolidated Financial Statements, “Income Taxes.”

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

Funding requirements for defined benefit (DB) plans are determined by government regulations. Duke Energy made voluntary contributions to its DB retirement plans of approximately $800 million in 2009, zero in 2008 and $350 million in 2007. Additionally, during 2007, Duke Energy contributed approximately $62 million to its other post-retirement benefit plans.

Duke Energy and its subsidiaries (including legacy Cinergy businesses) maintain non-contributory defined benefit retirement plans (Plans). The Plans cover most U.S. employees using a cash balance formula. Under a cash balance formula, a plan participant accumulates a retirement benefit consisting of pay credits that are based upon a percentage (which may vary with age and years of service) of current eligible earnings and current interest credits. Certain legacy Cinergy employees are covered under plans that use a final average earnings formula. Under a final average earnings formula, a plan participant accumulates a retirement benefit equal to a percentage of their highest 3-year average earnings, plus a percentage of their highest 3-year average earnings in excess of covered compensation per year of participation (maximum of 35 years), plus a percentage of their highest 3-year average earnings times years of participation in excess of 35 years. Duke Energy also maintains non-qualified, non-contributory defined benefit retirement plans which cover certain executives.

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

Duke Energy recognized pre-tax qualified pension cost of $6 million in 2009. In 2010, Duke Energy’s pre-tax qualified pension cost is expected to be approximately $30 million higher than in 2009 as a result of an increase in net actuarial loss amortization in 2010, primarily attributable to the effect of negative actual returns on assets from 2008. Duke Energy recognized pre-tax nonqualified pension cost of $13 million and pre-tax other post-retirement benefits cost of $34 million, in 2009. In 2010, pre-tax non-qualified pension cost and pre-tax other post-retirement benefits costs are expected to remain approximately the same as 2009.

For both pension and other post-retirement plans, Duke Energy assumed that its plan’s assets would generate a long-term rate of return of 8.5% as of December 31, 2009. The assets for Duke Energy’s pension and other post-retirement plans are maintained in a master trust. The investment objective of the master trust is to achieve reasonable returns on trust assets, subject to a prudent level of portfolio risk, for the purpose of enhancing the security of benefits for plan participants. The asset allocation target was set after considering the investment objective and the risk profile with respect to the trust. U.S. equities are held for their high expected return. Non-U.S. equities, debt securities, and real estate are held for diversification. Investments within asset classes are to be diversified to achieve broad market participation and reduce the impact of individual managers or investments. Duke Energy regularly reviews its actual asset allocation and periodically rebalances its investments to its targeted allocation when considered appropriate. Duke Energy also invests other post-retirement assets in the Duke Energy Corporation Employee Benefits Trust (VEBA I) and the Duke Energy Corporation Post-Retirement Medical Benefits Trust (VEBA II). The investment objective of the VEBAs is to achieve sufficient returns, subject to a prudent level of portfolio risk, for the purpose of promoting the security of plan benefits for participants. The VEBAs are passively managed.

The expected long-term rate of return of 8.5% for the plan’s assets was developed using a weighted average calculation of expected returns based primarily on future expected returns across asset classes considering the use of active asset managers. The weighted average returns expected by asset classes were 3.2% for U.S. equities, 2.0% for Non-U.S. equities, 1.0% for Global equities, 2.0% for fixed income securities, and 0.3% for real estate.

Duke Energy discounted its future U.S. pension and other post-retirement obligations using a rate of 5.50% as of December 31, 2009. Duke Energy determines the appropriate discount based on a yield curve approach. Under the yield curve approach, expected future benefit payments for each plan are discounted by a rate on a third-party bond yield curve corresponding to each duration. The yield curve is based on a bond universe of AA and AAA-rated long-term corporate bonds. A single discount rate is calculated that would yield the same present value as the sum of the discounted cash flows.

Future changes in plan asset returns, assumed discount rates and various other factors related to the participants in Duke Energy’s pension and post-retirement plans will impact Duke Energy’s future pension expense and liabilities. Management cannot predict with certainty what these factors will be in the future. The following table presents the approximate effect on Duke Energy’s 2009 pre-tax pension expense, pension obligation and other post-benefit obligation if a 0.25% change in rates were to occur:

Duke Energy’s U.S. post-retirement plan uses a medical care trend rate which reflects the near and long-term expectation of increases in medical health care costs. Duke Energy’s U.S. post-retirement plan uses a prescription drug trend rate which reflects the near and long-term expectation of increases in prescription drug health care costs. As of December 31, 2009, the medical care trend rates were 8.50%, which grades to 5.00% by 2019. As of December 31, 2009, the prescription drug trend rate was 11.00%, which grades to 5.00% by 2024. The following table presents the approximate effect on Duke Energy’s 2009 pre-tax other post-retirement expense and other post-benefit obligation if a 1% point change in the health care trend rate were to occur:

For further information, see Note 20 to the Consolidated Financial Statements, “Employee Benefit Plans.”

At December 31, 2009, Duke Energy had cash and cash equivalents of approximately $1.5 billion, of which approximately $600 million is held in foreign jurisdictions and is forecasted to be used to fund the operations of and investments in International Energy. To fund its liquidity and capital requirements during 2010, Duke Energy will rely primarily upon cash flows from operations, borrowings, equity issuances to fund the dividend reinvestment plan (DRIP) and other internal plans and its existing cash and cash equivalents. The relatively stable operating cash flows of the U.S. Franchised Electric and Gas business segment compose a substantial portion of Duke Energy’s cash flows from operations and it is anticipated that it will continue to do so for the next several years. A material adverse change in operations, or in available financing, could impact Duke Energy’s ability to fund its current liquidity and capital resource requirements.

Ultimate cash flows from operations are subject to a number of factors, including, but not limited to, regulatory constraints, economic trends and market volatility (see Item 1A. “Risk Factors” for details).

Duke Energy projects 2010 capital and investment expenditures of approximately $5.2 billion, primarily consisting of:

Duke Energy continues to focus on reducing risk and positioning its business for future success and will invest principally in its strongest business sectors. Based on this goal, approximately 80% of total projected 2010 capital expenditures are allocated to the U.S. Franchised Electric and Gas segment. Total U.S. Franchised Electric and Gas projected 2010 capital and investment expenditures include approximately $2.3 billion for system growth, $1.6 billion for maintenance and upgrades of existing plants and infrastructure to serve load growth, approximately $0.2 billion of nuclear fuel and approximately $0.1 billion of environmental expenditures.

With respect to the 2010 capital expenditure plan, Duke Energy has flexibility within its $5.2 billion budget to defer or eliminate certain spending should the broad economy continue to deteriorate. Of the $5.2 billion budget, approximately $2.9 billion relates to projects for which management has committed capital, including, but not limited to, the continued construction of Cliffside Unit 6 and the Edwardsport IGCC plant, and management intends to spend those capital dollars in 2010 irrespective of broader economic factors. Approximately $2.1 billion of projected 2010 capital expenditures are expected to be used primarily for overall system maintenance, customer connections and corporate expenditures. Although these expenditures are ultimately necessary to ensure overall system maintenance and reliability, the timing of the expenditures may be influenced by broad economic conditions and customer growth, thus management has more flexibility in terms of when these dollars are actually spent. The remaining planned 2010 capital expenditures of approximately $0.2 billion are of a discretionary nature and relate to growth opportunities in which Duke Energy may invest, provided there are opportunities to meet return expectations.

As a result of Duke Energy’s significant commitment to modernize its generating fleet through the construction of new units, as well as its focus on increasing its renewable energy portfolio, the ability to cost effectively manage the construction phase of current and future projects is critical to ensuring full and timely recovery of costs of construction within its regulated operations. Should Duke Energy encounter

significant cost overruns above amounts approved by the various state commissions, and those amounts are disallowed for recovery in rates, future cash flows and results of operations could be adversely impacted.

Duke Energy anticipates its debt to total capitalization ratio to remain at approximately 44% in 2010. In 2010, Duke Energy currently anticipates issuing additional net debt of approximately $1.7 billion at the operating subsidiary level, primarily for the purpose of funding capital expenditures. Due to the flexibility in the timing of projected 2010 capital expenditures, the timing and amount of debt issuances throughout 2010 could be influenced by changes in the timing of capital spending. Additionally, Duke Energy plans to generate approximately $400 million of cash from the issuance of common stock under its DRIP and other internal plans.

Duke Energy has access to unsecured revolving credit facilities, which are not restricted upon general market conditions, with aggregate bank commitments of approximately $3.14 billion. At December 31, 2009, Duke Energy has available borrowing capacity of approximately $1.9 billion under this facility. Management currently believes that amounts available under its revolving credit facility are accessible should there be a need to generate additional short-term financing in 2010, such as the issuance of commercial paper; however, due to the sustained downturn in overall economic conditions, specifically in the financial services sector, there is no guarantee that commitments provided by financial institutions under the revolving credit facility will be available if needed. Management expects that cash flows from operations, issuances of debt and cash generated from the issuance of common stock under the DRIP and other internal plans will be sufficient to cover the 2010 funding requirements related to capital and investments expenditures and dividend payments.

Duke Energy monitors compliance with all debt covenants and restrictions and does not currently believe it will be in violation or breach of its significant debt covenants during 2010. However, circumstances could arise that may alter that view. If and when management had a belief that such potential breach could exist, appropriate action would be taken to mitigate any such issue. Duke Energy also maintains an active dialogue with the credit rating agencies.

Net cash provided by operating activities was $3,463 million in 2009, compared to $3,328 million in 2008, an increase in cash provided of $135 million. The increase in cash provided by operating activities was driven primarily by:

Net cash provided by operating activities was $3,328 million in 2008, compared to $3,208 million in 2007, an increase in cash provided of $120 million. The increase in cash provided by operating activities was driven primarily by:

Net cash used in investing activities was $4,492 million in 2009, $4,611 million in 2008, and $2,151 million in 2007.

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

The decrease in cash used in investing activities in 2009 as compared to 2008 is primarily due to the following:

The increase in cash used in investing activities in 2008 as compared to 2007 is primarily due to the following:

Duke Energy’s consolidated capital structure as of December 31, 2009, including short-term debt, was 44% debt and 56% common equity. The fixed charges coverage ratio, calculated using Securities and Exchange Commission (SEC) guidelines, was 3.0 times for 2009, 3.4 times for 2008, and 3.7 times for 2007.

Net cash provided by financing activities was $1,585 million in 2009 compared to $1,591 million in 2008, a decrease in cash provided of $6 million. The change was due primarily to the following:

Net cash provided by financing activities was $1,591 million in 2008 compared to $1,327 million of cash used in 2007, an increase in cash provided of $2,918 million. The change was due primarily to the following:

Significant Financing Activities—Year Ended 2009. Duke Energy issues shares of its common stock to meet certain employee benefit and long-term incentive obligations. Beginning in the fourth quarter of 2008, Duke Energy began issuing authorized but unissued shares of common stock to fulfill obligations under its DRIP and other internal plans, including 401(k) plans. Proceeds from all issuances of common stock, primarily related to the DRIP and other employee benefit plans, including employee exercises of stock options, were approximately $519 million in 2009.

During the year ended December 31, 2009, Duke Energy’s total dividend per share of common stock was $0.94, which resulted in dividend payments of approximately $1,222 million.

In December 2009, Duke Energy Ohio issued $250 million principal amount of first mortgage bonds, which carry a fixed interest rate of 2.10% and mature June 15, 2013. Proceeds from this issuance, together with cash on hand, were used to repay Duke Energy Ohio’s borrowing under Duke Energy’s master credit facility. In conjunction with this debt issuance, Duke Energy Ohio entered into an interest rate swap agreement that converted interest on this debt issuance from the fixed coupon rate to a variable rate. The initial variable rate was set at 0.31%.

In November 2009, Duke Energy Carolinas issued $750 million principal amount of first mortgage bonds, which carry a fixed interest rate of 5.30% and mature February 15, 2040. Proceeds from this issuance will be used to fund capital expenditures and general corporate purposes, including the repayment at maturity of $500 million of senior notes and first mortgage bonds in the first half of 2010.

In October 2009, Duke Energy Indiana refunded $50 million of tax-exempt variable-rate demand bonds through the issuance of $50 million principal amount of tax-exempt term bonds, which carry a fixed interest rate of 4.95% and mature October 1, 2040. The tax-exempt bonds are secured by a series of Duke Energy Indiana’s first mortgage bonds.

In September 2009, Duke Energy Ohio and Duke Energy Indiana repaid and immediately re-borrowed approximately $279 million and $123 million, respectively, under Duke Energy’s master credit facility.

In September 2009, Duke Energy Carolinas converted $77 million of tax-exempt variable-rate demand bonds to tax-exempt term bonds, which carry a fixed interest rate of 3.60% and mature February 1, 2017. In connection with the conversion, the tax-exempt bonds were secured by a series of Duke Energy Carolinas’ first mortgage bonds.

In September 2009, Duke Energy Kentucky issued $100 million of senior debentures, which carry a fixed interest rate of 4.65% and mature October 1, 2019. Proceeds from the issuance were used to repay Duke Energy Kentucky’s borrowings under Duke Energy’s master credit facility, to replenish cash used to repay $20 million principal amount of debt due September 15, 2009 and for general corporate purposes.

In August 2009, Duke Energy issued $1 billion principal amount of senior notes, of which $500 million carry a fixed interest rate of 3.95% and mature September 15, 2014 and $500 million carry a fixed interest rate of 5.05% and mature September 15, 2019. Proceeds from the issuance were used to redeem commercial paper, to fund capital expenditures in Duke Energy’s unregulated businesses in the U.S. and for general corporate purposes.

In June 2009, Duke Energy Indiana refunded $55 million of tax-exempt variable-rate demand bonds through the issuance of $55 million principal amount of tax-exempt term bonds due August 1, 2039, which carry a fixed interest rate of 6.00% and are secured by a series of Duke Energy Indiana’s first mortgage bonds. The refunded bonds were redeemed July 1, 2009.

In March 2009, Duke Energy Ohio issued $450 million principal amount of first mortgage bonds, which carry a fixed interest rate of 5.45% and mature April 1, 2019. Proceeds from this issuance were used to repay short-term notes and for general corporate purposes, including funding capital expenditures.

In March 2009, Duke Energy Indiana issued $450 million principal amount of first mortgage bonds, which carry a fixed interest rate of 6.45% and mature April 1, 2039. Proceeds from this issuance were used to fund capital expenditures, to replenish cash used to repay $97 million of senior notes which matured on March 15, 2009, to fund the repayment at maturity of $125 million of first mortgage bonds due July 15, 2009, and for general corporate purposes, including the repayment of short-term notes.

In January 2009, Duke Energy issued $750 million principal amount of 6.30% senior notes due February 1, 2014. Proceeds from the issuance were used to redeem commercial paper and for general corporate purposes.

In January 2009, Duke Energy Indiana refunded $271 million of tax-exempt auction rate bonds through the issuance of $271 million of tax-exempt variable-rate demand bonds, which are supported by direct-pay letters of credit, of which $144 million had initial rates of 0.7% reset on a weekly basis with $44 million maturing May 2035, $23 million maturing March 2031 and $77 million maturing December 2039. The

remaining $127 million had initial rates of 0.5% reset on a daily basis with $77 million maturing December 2039 and $50 million maturing October 2040.

Significant Financing Activities—Year Ended 2008. Duke Energy issues shares of its common stock to meet certain employee benefit and long-term incentive obligations. Beginning in the fourth quarter of 2008, Duke Energy began issuing authorized but unissued shares of common stock to fulfill obligations under its DRIP and other internal plans, including 401(k) plans. Proceeds from all issuances of common stock, primarily related to the DRIP and other employee benefit plans, including employee exercises of stock options, were approximately $133 million in 2008.

During the year ended December 31, 2008, Duke Energy’s total dividend per share of common stock was $0.90, which resulted in dividend payments of approximately $1,143 million.

In December 2008, Duke Energy Kentucky refunded $50 million of tax-exempt auction rate bonds through the issuance of $50 million of tax-exempt variable-rate demand bonds, which are supported by a direct-pay letter of credit. The variable-rate demand bonds, which are due August 1, 2027, had an initial interest rate of 0.65% which is reset on a weekly basis.

In November 2008, Duke Energy Carolinas issued $900 million principal amount of first mortgage bonds, of which $500 million carry a fixed interest rate of 7.00% and mature November 15, 2018 and $400 million carry a fixed interest rate of 5.75% and mature November 15, 2013. The net proceeds from issuance were used to repay amounts borrowed under the master credit facility, to repay senior notes due January 1, 2009, to replenish cash used to repay senior notes at their scheduled maturity in October 2008 and for general corporate purposes.

In October 2008, International Energy issued approximately $153 million of debt in Brazil, of which approximately $112 million mature in September 2013 and carry a variable interest rate equal to the Brazil interbank rate plus 2.15%, and approximately $41 million mature in September 2015 and carry a fixed interest rate of 11.6% plus an annual inflation index. International Energy used these proceeds to pre-pay existing long-term debt balances.

In September 2008, Duke Energy and its wholly-owned subsidiaries, Duke Energy Carolinas, Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky, borrowed a total of approximately $1 billion under Duke Energy’s master credit facility. For additional information, see “Available Credit Facilities and Restrictive Debt Covenants” below.

In August 2008, Duke Energy Indiana issued $500 million principal amount of first mortgage bonds, which carry a fixed interest rate of 6.35% and mature August 15, 2038. Proceeds from this issuance were used to fund capital expenditures and for general corporate purposes, including the repayment of short-term notes and to redeem first mortgage bonds maturing in September 2008.

In June 2008, Duke Energy issued $500 million principal amount of senior notes, of which $250 million carry a fixed interest rate of 5.65% and mature June 15, 2013 and $250 million carry a fixed interest rate of 6.25% and mature June 15, 2018. Proceeds from the issuance were used to redeem commercial paper, to fund capital expenditures in Duke Energy’s unregulated businesses in the U.S. and for general corporate purposes.

In April 2008, Duke Energy Carolinas issued $900 million principal amount of first mortgage bonds, of which $300 million carry a fixed interest rate of 5.10% and mature April 15, 2018 and $600 million carry a fixed interest rate of 6.05% and mature April 15, 2038. Proceeds from the issuance were used to fund capital expenditures and for general corporate purposes. In anticipation of this debt issuance, Duke Energy Carolinas executed a series of interest rate swaps in 2007 to lock in the market interest rates at that time. The value of these interest rate swaps, which were terminated prior to issuance of the fixed rate debt, was a pre-tax loss of approximately $23 million. This amount was recorded as a component of Accumulated Other Comprehensive Loss and is being amortized as a component of Interest Expense over the life of the debt.

In April 2008, Duke Energy Carolinas refunded $100 million of tax-exempt auction rate bonds through the issuance of $100 million of tax-exempt variable-rate demand bonds, which are supported by a direct-pay letter of credit. The variable-rate demand bonds, which are due November 1, 2040, had an initial interest rate of 2.15% which will be reset on a weekly basis.

In January 2008, Duke Energy Carolinas issued $900 million principal amount of first mortgage bonds, of which $400 million carry a fixed interest rate of 5.25% and mature January 15, 2018 and $500 million carry a fixed interest rate of 6.00% and mature January 15, 2038. Proceeds from the issuance were used to fund capital expenditures and for general corporate purposes, including the repayment of commercial paper. In anticipation of this debt issuance, Duke Energy Carolinas executed a series of interest rate swaps in 2007 to lock in the market interest rates at that time. The value of these interest rate swaps, which were terminated prior to issuance of the fixed rate debt, was a pre-tax loss of approximately $18 million. This amount was recorded as a component of Accumulated Other Comprehensive Loss and is being amortized as a component of Interest Expense over the life of the debt.

Significant Financing Activities—Year Ended 2007. Duke Energy issues shares of its common stock to meet certain employee benefit and long-term incentive obligations. Proceeds from all issuances of common stock, primarily related to employee benefit plans, including employee exercises of stock options, were approximately $50 million in 2007.

During the year ended December 31, 2007, Duke Energy’s total dividend per share of common stock was $0.86, which resulted in dividend payments of approximately $1,089 million.

In December 2007, Duke Energy Ohio issued $140 million in tax-exempt floating-rate bonds. The bonds are structured as insured auction rate securities, subject to an auction process every 35 days and bear a final maturity of 2041. The initial interest rate was set at 4.85%. The bonds were issued through the Ohio Air Quality Development Authority to fund a portion of the environmental capital expenditures at the Conesville, Stuart and Killen Generation Stations in Ohio.

In November 2007, Duke Energy Carolinas issued $100 million in tax-exempt floating-rate bonds. The bonds are structured as insured auction rate securities, subject to an auction process every 35 days and bear a final maturity of 2040. The initial interest rate was set at 3.65%. The bonds were issued through the North Carolina Capital Facilities Finance Agency to fund a portion of the environmental capital expenditures at the Belews Creek and Allen Steam Stations.

In June 2007, Duke Energy Carolinas issued $500 million principal amount of 6.10% senior unsecured notes due June 1, 2037. The net proceeds from the issuance were used to redeem commercial paper that was issued to repay the outstanding $249 million 6.6% Insured Quarterly Senior Notes due 2022 on April 30, 2007, and approximately $110 million of convertible debt discussed below. The remainder was used for general corporate purposes.

On May 15, 2007, substantially all of the holders of the Duke Energy convertible senior notes required Duke Energy to repurchase the balance then outstanding at a price equal to 100% of the principal amount plus accrued interest. In May 2007, Duke Energy repurchased approximately $110 million of the convertible senior notes.

On January 2, 2007, Duke Energy completed the spin-off of the natural gas businesses. In connection with this transaction, Duke Energy distributed all the shares 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 stock for each share of Duke Energy stock.

Available Credit Facilities and Restrictive Debt Covenants. The total capacity under Duke Energy’s master credit facility, which expires in June 2012, is approximately $3.14 billion. The credit facility contains an option allowing borrowing up to the full amount of the facility on the day of initial expiration for up to one year. Duke Energy and its wholly-owned subsidiaries, Duke Energy Carolinas, Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky (collectively referred to as the borrowers), each have borrowing capacity under the master credit

facility up to specified sub limits for each borrower. However, Duke Energy has the unilateral ability to increase or decrease the borrowing sub limits of each borrower, subject to per borrower maximum cap limitations, at any time. The amount available under the master credit facility has been reduced by draw downs of cash and the use of the master credit facility to backstop the issuances of commercial paper, letters of credit and certain tax-exempt bonds.

The loans under the master credit facility are revolving credit loans that currently bear interest at one-month London Interbank Offered Rate (LIBOR) plus an applicable spread ranging from 19 to 23 basis points. The loan for Duke Energy, which was approximately $274 million at December 31, 2009, has a stated maturity of June 2012, while the loan for Duke Energy Indiana, which was approximately $123 million at December 31, 2009, had a stated maturity of September 2009; however, the borrowers have the ability under the master credit facility to renew the loans due in September 2009 on an annual basis up through the date the master credit facility matures in June 2012. As a result of these annual renewal provisions, in September 2009, Duke Energy Indiana repaid and immediately re-borrowed approximately $123 million under the master credit facility. Duke Energy and Duke Energy Indiana have the intent and ability to refinance these obligations on a long-term basis, either through renewal of the terms of the loan through the master credit facility, which has non-cancelable terms in excess of one-year, or through issuance of long-term debt to replace the amounts drawn under the master credit facility. Accordingly, total borrowings by Duke Energy and Duke Energy Indiana of approximately $397 million are reflected as Long-Term Debt on the Consolidated Balance Sheets at December 31, 2009.

In September 2008, Duke Energy Indiana and Duke Energy Kentucky collectively entered into a $330 million three-year letter of credit agreement with a syndicate of banks, under which Duke Energy Indiana and Duke Energy Kentucky may request the issuance of letters of credit up to $279 million and $51 million, respectively, on their behalf to support various series of variable rate demand bonds issued or to be issued on behalf of either Duke Energy Indiana or Duke Energy Kentucky. This credit facility, which is not part of Duke Energy’s master credit facility, may not be used for any purpose other than to support the variable rate demand bonds issued by Duke Energy Indiana and Duke Energy Kentucky.

Duke Energy’s debt and credit agreements contain various financial and other covenants. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements. As of December 31, 2009, Duke Energy was in compliance with all covenants related to its significant debt agreements. In addition, some credit agreements may allow for acceleration of payments or termination of the agreements due to nonpayment, or to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the debt or credit agreements contain material adverse change clauses.

Credit Ratings. Duke Energy and certain subsidiaries each hold credit ratings by Standard & Poor’s (S&P) and Moody’s Investors Service (Moody’s). Duke Energy’s corporate credit rating and issuer credit rating from S&P and Moody’s, respectively, as of February 1, 2010 is A- and Baa2, respectively. The following table summarizes the February 1, 2010 unsecured credit ratings from the rating agencies retained by Duke Energy and its principal funding subsidiaries.

Duke Energy’s credit ratings are dependent on, among other factors, the ability to generate sufficient cash to fund capital and investment expenditures and pay dividends on its common stock, while maintaining the strength of its current balance sheet. If, as a result of market conditions or other factors, Duke Energy is unable to maintain its current balance sheet strength, or if its earnings and cash flow outlook materially deteriorates, Duke Energy’s credit ratings could be negatively impacted.

Credit-Related Clauses. Duke Energy may be required to repay certain debt should the credit ratings at Duke Energy Carolinas fall to a certain level at S&P or Moody’s. As of December 31, 2009, Duke Energy had approximately $6 million of senior unsecured notes which mature serially through 2012 that may be required to be repaid if Duke Energy Carolinas’ senior unsecured debt ratings fall below BBB- at S&P or Baa3 at Moody’s, and $16 million of senior unsecured notes which mature serially through 2016 that may be required to be repaid if Duke Energy Carolinas’ senior unsecured debt ratings fall below BBB at S&P or Baa2 at Moody’s.

Other Financing Matters. In October 2007, Duke Energy filed a registration statement (Form S-3) with the SEC. Under this Form S-3, which is uncapped, Duke Energy, Duke Energy Carolinas, Duke Energy Ohio and Duke Energy Indiana may issue debt and other securities in the future at amounts, prices and with terms to be determined at the time of future offerings. The registration statement also allows for the issuance of common stock by Duke Energy.

Duke Energy has paid quarterly cash dividends for 84 consecutive years and expects to continue its policy of paying regular cash dividends in the future. There is no assurance as to the amount of future dividends because they depend on future earnings, capital requirements, financial condition and are subject to the discretion of the Board of Directors.

Dividend and Other Funding Restrictions of Duke Energy Subsidiaries. As discussed in Note 4 to the Consolidated Financial Statements “Regulatory Matters”, Duke Energy’s wholly-owned public utility operating companies have restrictions on the amount of funds that can be transferred to Duke Energy via dividend, advance or loan as a result of conditions imposed by various regulators in conjunction with Duke Energy’s merger with Cinergy. Additionally, certain other Duke Energy subsidiaries have other restrictions, such as minimum working capital and tangible net worth requirements pursuant to debt and other agreements that limit the amount of funds that can be transferred to Duke Energy. At December 31, 2009, the amount of restricted net assets of wholly-owned subsidiaries of Duke Energy that may not be distributed to Duke Energy in the form of a loan or dividend is approximately $10.5 billion. However, Duke Energy does not have any legal or other restrictions on paying common stock dividends to shareholders out of its consolidated Retained Earnings account. Although these restrictions cap the amount of funding the various operating subsidiaries can provide to Duke Energy, management does not believe these restrictions will have any significant impact on Duke Energy’s ability to access cash to meet its payment of dividends on common stock and other future funding obligations.

Duke Energy and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications.

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

Duke Energy performs ongoing assessments of its guarantee obligations to determine whether any liabilities have been triggered as a result of potential increased non-performance risk by parties for which Duke Energy has issued guarantees. Except for certain performance obligations related to Crescent, which filed Chapter 11 bankruptcy petitions in a U.S. Bankruptcy court in June 2009 and for which a liability of approximately $26 million was recorded during 2009 due to the probability of performance under certain guarantees, it is not probable as of December 31, 2009 that Duke Energy will have to perform under its remaining existing guarantee obligations. However, management continues to monitor the financial condition of the third parties or non-wholly-owned entities for whom Duke Energy has issued guarantees on behalf of to determine whether performance under these guarantees becomes probable in the future.

See Note 17 to the Consolidated Financial Statements, “Guarantees and Indemnifications,” for further details of the guarantee arrangements.

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

Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky have an agreement to sell certain of their accounts receivable and related collections to Cinergy Receivables, which purchases, on a revolving basis, nearly all of the retail accounts receivable and related collections of Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky. Cinergy Receivables is not consolidated by Duke Energy since it meets the requirements to be accounted for as a qualifying special purpose entity (QSPE). Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky each retain an interest in the receivables transferred to Cinergy Receivables. The transfers of receivables are accounted for as sales under the accounting guidance for transfers and servicing of financial assets. For a more detailed discussion of the sale of certain accounts receivable, see Note 21 to the Consolidated Financial Statements, “Variable Interest Entities.” With the adoption of new accounting rules related to variable interest entities (VIEs) and transfers and servicing of financial assets on January 1, 2010, Duke Energy began consolidating Cinergy Receivables as of that date.

Duke Energy also holds interests in other VIEs, both consolidated and unconsolidated. For further information, see Note 21 to the Consolidated Financial Statements, “Variable Interest Entities”.

Other than the guarantee arrangements discussed above and normal operating lease arrangements, Duke Energy does not have any material off-balance sheet financing entities or structures. For additional information on these commitments, see Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies.”

Duke Energy enters into contracts that require payment of cash at certain specified periods, based on certain specified minimum quantities and prices. The following table summarizes Duke Energy’s contractual cash obligations for each of the periods presented. It is expected that the majority of current liabilities on the Consolidated Balance Sheets will be paid in cash in 2010.

Duke Energy is exposed to market risks associated with commodity prices, credit exposure, interest rates, equity prices and foreign currency exchange rates. Management has established comprehensive risk management policies to monitor and manage these market risks. Duke Energy’s Chief Executive Officer and Chief Financial Officer are responsible for the overall approval of market risk management policies and the delegation of approval and authorization levels. The Finance and Risk Management Committee of the Board of Directors receives periodic updates from the Chief Risk Officer and other members of management on market risk positions, corporate exposures, credit exposures and overall risk management activities. The Chief Risk Officer is responsible for the overall governance of managing credit risk and commodity price risk, including monitoring exposure limits.

Duke Energy is exposed to the impact of market fluctuations in the prices of electricity, coal, natural gas and other energy-related products marketed and purchased as a result of its ownership of energy related assets. Duke Energy’s exposure to these fluctuations is limited by the cost-based regulation of its U.S. Franchised Electric and Gas operations and certain portions of Commercial Power’s operations as these regulated operations are typically allowed to recover certain of these costs through various cost-recovery clauses, including the fuel clause. While there may be a delay in timing between when these costs are incurred and when these costs are recovered through rates, changes from year to year have no material impact on operating results of these regulated operations. Additionally, most of Duke Energy’s long-term power sales contracts substantially shift all fuel price risk to the purchaser.

Price risk represents the potential risk of loss from adverse changes in the market price of electricity or other energy commodities. Duke Energy’s exposure to commodity price risk is influenced by a number of factors, including contract size, length, market liquidity, location and unique or specific contract terms. Duke Energy employs established policies and procedures to manage its risks associated with these market fluctuations, which may include using various commodity derivatives, such as swaps, futures, forwards and options. For additional information, see Note 8 to the Consolidated Financial Statements, “Risk Management, Derivative Instruments and Hedging Activities.”

Validation of a contract’s fair value is performed by an internal group separate from Duke Energy’s deal origination areas. While Duke Energy uses common industry practices to develop its valuation techniques, changes in Duke Energy’s pricing methodologies or the underlying assumptions could result in significantly different fair values and income recognition.

Hedging Strategies. Duke Energy closely monitors the risks associated with commodity price changes on its future operations and, where appropriate, uses various commodity instruments such as electricity, coal and natural gas forward contracts to mitigate the effect of such fluctuations on operations. Duke Energy’s primary use of energy commodity derivatives is to hedge the generation portfolio against exposure to the prices of power and fuel.

Certain derivatives used to manage Duke Energy’s commodity price exposure are accounted for as either cash flow hedges or fair value hedges. To the extent that instruments accounted for as hedges are effective in offsetting the transaction being hedged, there is no impact to the Consolidated Statements of Operations until after delivery or settlement occurs. Accordingly, assumptions and valuation techniques for these contracts have no impact on reported earnings prior to settlement. Several factors influence the effectiveness of a hedge contract, including the use of contracts with different commodities or unmatched terms and counterparty credit risk. Hedge effectiveness is monitored regularly and measured at least quarterly.

In addition to the hedge contracts described above and recorded on the Consolidated Balance Sheets, Duke Energy enters into other contracts that qualify for the NPNS exception. When a contract meets the criteria to qualify as a NPNS, U.S. Franchised Electric and Gas and Commercial Power apply such exception. Income recognition and realization related to normal purchases and normal sales contracts generally coincide with the physical delivery of power. For contracts qualifying for the NPNS exception, no recognition of the contract’s fair value in the Consolidated Financial Statements is required until settlement of the contract as long as the transaction remains probable of occurring.

Other derivatives used to manage Duke Energy’s commodity price exposure are either not designated as a hedge or do not qualify for hedge accounting. These instruments are referred to as undesignated contracts. Undesignated derivatives entered into by regulated businesses reflect mark-to-market changes of the derivative instruments fair value as a regulatory asset or liability on the Consolidated Balance Sheets. Undesignated derivatives entered into by unregulated businesses are marked-to-market each period, with changes in the fair value of the derivative instruments reflected in earnings.

Generation Portfolio Risks for 2010. Duke Energy is primarily exposed to market price fluctuations of wholesale power, natural gas, and coal prices in the U.S. Franchised Electric and Gas and Commercial Power segments. Duke Energy optimizes the value of its bulk power marketing and non-regulated generation portfolios. The portfolios include generation assets (power and capacity), fuel, and emission allowances. The component pieces of the portfolio are bought and sold based on models and forecasts of generation in order to manage the economic value of the portfolio in accordance with the strategies of the business units. The generation portfolio not utilized to serve native load or committed load is subject to commodity price fluctuations, although the impact on the Consolidated Statements of Operations reported earnings is partially offset by mechanisms in the regulated jurisdictions that result in the sharing of net profits from these activities with retail customers. Based on a sensitivity analysis as of December 31, 2009 and 2008, it was estimated that a 10% price change per MWh in forward wholesale power prices would have a corresponding effect on Duke Energy’s pre-tax income of approximately $12 million in 2010 and would have had a $10 million impact in 2009, excluding the impact of mark-to-market changes on non-qualifying or undesignated hedges relating to periods in excess of one year from the respective date, which are discussed further below. Based on a sensitivity analysis as of December 31, 2009 and 2008, it was estimated that a 10% change in the forward price per ton of coal would have a corresponding effect on Duke Energy’s pre-tax income of approximately $8 million in 2010 and would have had a $10 million impact in 2009, excluding the impact of mark-to-market changes on non-qualifying or undesignated hedges relating to periods in excess of one year from the respective date. Based on a sensitivity analysis as of December 31, 2009 and 2008, it was estimated that a 10% price change per Million British Thermal Unit (MMBtu) in natural gas prices would have a corresponding effect on Duke Energy’s pre-tax income of approximately $6 million in 2010 and would have had a $5 million impact in 2009, excluding the impact of mark-to-market changes on undesignated hedges relating to periods in excess of one year from the respective date, which are discussed further below.

Sensitivities for derivatives beyond 2010. Derivative contracts executed to manage generation portfolio risks for delivery periods beyond 2010 are also exposed to changes in fair value due to market price fluctuations of wholesale power and coal. Based on a sensitivity analysis as of December 31, 2009 and 2008, it was estimated that a 10% price change in the forward price per MWh of wholesale power would have a corresponding effect on Duke Energy’s pre-tax income of approximately $24 million in 2010 and would have had a $11 million impact in 2009, resulting from the impact of mark-to-market changes on non-qualifying and undesignated power contracts pertaining to periods in excess of one year from the respective date. Based on a sensitivity analysis as of December 31, 2009 and 2008, it was estimated that a 10% change in the forward price per ton of coal would have a corresponding effect on Duke Energy’s pre-tax income of approximately $10 million

in 2010 and 2009, resulting from the impact of mark-to-market changes on non-qualifying and undesignated coal contracts pertaining to periods in excess of one year from the respective date.

Other Commodity Risks. At December 31, 2009 and 2008, pre-tax income in 2010 and 2009 was not expected to be materially impacted for exposures to other commodities’ price changes.

The commodity price sensitivity calculations above consider existing hedge positions and estimated production levels, but do not consider other potential effects that might result from such changes in commodity prices.

Credit risk represents the loss that Duke Energy would incur if a counterparty fails to perform under its contractual obligations. To reduce credit exposure, Duke Energy seeks to enter into netting agreements with counterparties that permit Duke Energy to offset receivables and payables with such counterparties. Duke Energy attempts to further reduce credit risk with certain counterparties by entering into agreements that enable Duke Energy to obtain collateral or to terminate or reset the terms of transactions after specified time periods or upon the occurrence of credit-related events. Duke Energy may, at times, use credit derivatives or other structures and techniques to provide for third-party credit enhancement of Duke Energy’s counterparties’ obligations. Duke Energy also obtains cash or letters of credit from customers to provide credit support outside of collateral agreements, where appropriate, based on its financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each transaction.

Duke Energy’s industry has historically operated under negotiated credit lines for physical delivery contracts. Duke Energy frequently uses master collateral agreements to mitigate certain credit exposures. The collateral agreements provide for a counterparty to post cash or letters of credit to the exposed party for exposure in excess of an established threshold. The threshold amount represents an unsecured credit limit, determined in accordance with the corporate credit policy. Collateral agreements also provide that the inability to post collateral is sufficient cause to terminate contracts and liquidate all positions.

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

Duke Energy and its subsidiaries also have credit risk exposure through issuance of performance guarantees, letters of credit and surety bonds on behalf of less than wholly-owned entities and third parties. Where Duke Energy has issued these guarantees, it is possible that Duke Energy could be required to perform under these guarantee obligations in the event the obligor under the guarantee fails to perform. Where Duke Energy has issued guarantees related to assets or operations that have been disposed of via sale, Duke Energy attempts to secure indemnification from the buyer against all future performance obligations under the guarantees. See Note 17 to the Consolidated Financial Statements, “Guarantees and Indemnifications,” for further information on guarantees issued by Duke Energy or its subsidiaries.

Duke Energy is also subject to credit risk of its vendors and suppliers in the form of performance risk on contracts including, but not limited to, outsourcing arrangements, major construction projects and commodity purchases. Duke Energy’s credit exposure to such vendors and suppliers may take the form of increased costs or project delays in the event of non-performance.

Based on Duke Energy’s policies for managing credit risk, its exposures and its credit and other reserves, Duke Energy does not anticipate a materially adverse effect on its consolidated financial position or results of operations as a result of non-performance by any counterparty.

Duke Energy is exposed to risk resulting from changes in interest rates as a result of its issuance of variable and fixed rate debt and commercial paper. Duke Energy manages its interest rate exposure by limiting its variable-rate exposures to a percentage of total capitalization and by monitoring the effects of market changes in interest rates. Duke Energy also enters into financial derivative instruments, which may include instruments such as, but not limited to, interest rate swaps, swaptions and U.S. Treasury lock agreements to manage and mitigate interest rate risk exposure. See Notes 1, 8, 9, and 15 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” “Risk Management, Derivative Instruments and Hedging Activities,” “Fair Value of Financial Assets and Liabilities,” and “Debt and Credit Facilities.”

Based on a sensitivity analysis as of December 31, 2009, it was estimated that if market interest rates average 1% higher (lower) in 2010 than in 2009, interest expense, net of offsetting impacts in interest income, would increase (decrease) by approximately $19 million. Comparatively, based on a sensitivity analysis as of December 31, 2008, had interest rates averaged 1% higher (lower) in 2009 than in 2008, it was estimated that interest expense, net of offsetting impacts in interest income, would have increased (decreased) by approximately $28 million. These amounts were estimated by considering the impact of the hypothetical interest rates on variable-rate securities outstanding, adjusted for interest rate hedges, short-term and long-term investments, cash and cash equivalents outstanding as of December 31, 2009 and 2008. The decrease in interest rate sensitivity is primarily due to a decrease in tax-exempt bonds and commercial paper, partial repayment of the master credit facility borrowings, and increased cash balances. If interest rates changed significantly, management would likely take actions to manage its exposure to the change. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no changes in Duke Energy’s financial structure.

As described further in Note 10 to the Consolidated Financial Statements, “Investments in Debt and Equity Securities,” Duke Energy invests in debt and equity securities as part of various investment portfolios to fund certain obligations of the business. The vast majority of the investments in equity securities are within the NDTF and assets of the various pension and other post-retirement benefit plans.

NDTF. As discussed further in Note 7 to the Consolidated Financial Statements, “Asset Retirement Obligations”, Duke Energy maintains trust funds to fund the costs of nuclear decommissioning. As of December 31, 2009, these funds were invested primarily in domestic and international equity securities, debt securities, fixed-income securities, cash and cash equivalents and short-term investments. Per NRC and NCUC requirements, these funds may be used only for activities related to nuclear decommissioning. The investments are exposed to price fluctuations in debt and equity markets. Accounting for nuclear decommissioning recognizes that costs are recovered through U.S. Franchised Electric and Gas’ rates; therefore, fluctuations in equity prices do not affect Duke Energy’s Consolidated Statements of Operations as changes in the fair value of these investments are deferred as regulatory assets or regulatory liabilities. Earnings or losses of the fund will ultimately impact the amount of costs recovered through U.S. Franchised Electric and Gas’ rates over time. Management monitors the NDTF investment portfolio by benchmarking the performance of the investments against certain indices and by maintaining and periodically reviewing target allocation percentages for various asset classes.

The following table provides the fair value of investments held in the NDTF at December 31, 2009:

Pension Plan Assets. Duke Energy maintains investments to help fund the costs of providing non-contributory defined benefit retirement and other post-retirement benefit plans. Those investments are exposed to price fluctuations in equity markets and changes in interest rates. Duke Energy has established asset allocation targets for its pension plan holdings, which take into consideration the investment objectives and the risk profile with respect to the trust in which the assets are held. Duke Energy’s target asset allocation for equity securities is approximately 64% of the value of the plan assets and the holdings are diversified to achieve broad market participation and reduce the impact of any single investment, sector or geographic region. A significant decline in the value of plan asset holdings could require Duke Energy to increase its funding of the pension plan in future periods, which could adversely affect cash flows in those periods. Additionally, a decline in the fair value of plan assets, absent additional cash contributions to the plan, could increase the amount of pension cost required to be recorded in future periods, which could adversely affect Duke Energy’s results of operations in those periods. During 2009, Duke Energy contributed approximately $800 million to its qualified pension plan. See Note 20 to the Consolidated Financial Statements, “Employee Benefit Plans,” for additional information on pension plan assets.

Duke Energy is exposed to foreign currency risk from investments in international affiliate businesses owned and operated in foreign countries and from certain commodity-related transactions within domestic operations that are denominated in foreign currencies. To mitigate risks associated with foreign currency fluctuations, contracts may be denominated in or indexed to the U.S. Dollar and/or local inflation rates, or investments may be naturally hedged through debt denominated or issued in the foreign currency. Duke Energy may also use foreign currency derivatives, where possible, to manage its risk related to foreign currency fluctuations. To monitor its currency exchange rate risks, Duke Energy uses sensitivity analysis, which measures the impact of devaluation of the foreign currencies to which it has exposure.

In 2010, Duke Energy’s primary foreign currency rate exposure is to the Brazilian Real. A 10% devaluation in the currency exchange rates as of December 31, 2009 in all of Duke Energy’s exposure currencies would result in an estimated net pre-tax loss on the translation of local currency earnings of approximately $20 million to Duke Energy’s Consolidated Statements of Operations in 2010. The Consolidated Balance Sheet would be negatively impacted by approximately $160 million currency translation through the cumulative translation adjustment in AOCI as of December 31, 2009 as a result of a 10% devaluation in the currency exchange rates. For comparative purposes, as of December 31, 2008, a 10% devaluation in the currency exchange rates in all of Duke Energy’s exposure currencies was expected to result in an estimated net pre-tax loss on the translation of local currency earnings of approximately $10 million to Duke Energy’s Consolidated Statements of Operations and a reduction of approximately $120 million currency translation through the cumulative translation adjustment in AOCI as of December 31, 2008.

Global Climate Change. Although there is still much to learn about the causes and long-term effects of climate change, many, including Duke Energy, advocate taking steps now to begin reducing greenhouse gas (GHG) emissions with the long-term aim of stabilizing the atmospheric concentration of GHGs at a level that avoids any potentially worst-case effects of climate change.

The EPA publishes an inventory of man-made U.S. GHG emissions annually. Carbon dioxide (CO₂), a byproduct of fossil fuel combustion, currently accounts for about 85% of total U.S. GHG emissions. Duke Energy’s GHG emissions consist primarily of CO₂ and most come from its fleet of coal fired power plants in the U.S. In 2009, Duke Energy’s U.S. power plants emitted approximately 91 million tons of CO₂. The CO₂ emissions from Duke Energy’s international electric operations are less than 3 million tons annually. Duke Energy’s future CO₂ emissions will be influenced by variables including new regulations, economic conditions that affect electricity demand, and Duke Energy’s decisions regarding generation technologies deployed to meet customer electricity needs.

Congress has not yet passed legislation mandating control or reduction of GHGs. On June 26, 2009, the U. S. House of Representatives passed H.R. 2454 - the American Clean Energy and Security Act of 2009 (ACES). This legislation includes a GHG cap-and-trade program that covers approximately 85% of the GHG emissions in the U.S. economy, including emissions from the electric utility sector. The legislation also includes a combined efficiency and renewable electricity standard that applies to the electric utility sector. The standard establishes

minimum requirements for the amount of renewable energy electric utilities must provide to end-use customers on an annual basis. It allows companies to comply by providing renewable energy, buying renewable energy credits from other companies or the government, or by reducing customer electricity demand through the deployment of energy efficiency programs.

On November 5, 2009, the U.S. Senate Environment and Public Works Committee passed and sent to the Senate floor S. 1733 - the Clean Energy Jobs and American Power Act of 2009 (S. 1733). The legislation included an economy-wide cap-and-trade program similar to the one contained in ACES. The Senate Energy and Natural Resources Committee had previously passed legislation containing new requirements for energy efficiency and for a renewable electricity standard. No further Senate action has been taken on either bill since passage out of their respective committees.

The debates that took place in the U.S. Senate in 2008 and 2009 make it clear that there are wide-ranging views among Senators regarding what constitutes acceptable climate change legislation. These divergent views, the state of the economy, the current structure of the Senate necessitating 60 votes to move legislation and the political pressures as the 2010 mid-term election approaches, make passage of federal climate change legislation in the Senate in 2010 highly uncertain. If the Senate were to pass some type of climate change legislation in 2010, the Senate legislation would need to be reconciled with ACES. This adds another layer of uncertainty to the prospects for enactment of climate change legislation in 2010.

On December 7, 2009, the EPA finalized an Endangerment Finding for greenhouse gases under the CAA. The Endangerment Finding does not impose any regulatory requirements on industry, but is a necessary prerequisite for the EPA to be able to finalize its proposed GHG emission standard for new motor vehicles. It is expected that the EPA will finalize its New Motor Vehicle Rule by the end of March 2010. Implementation of the New Motor Vehicle Rule may trigger permitting requirements and potentially GHG emission control requirements for new and existing “major” stationary sources of GHG emissions which would include all of Duke Energy’s fossil fuel facilities. The EPA has stated that permitting requirements for GHGs will not apply to stationary sources in 2010.

The EPA has also proposed the Tailoring Rule, which is expected to be finalized by the end of March 2010. This rule is intended to provide relief from the EPA’s GHG regulations for certain types of stationary sources, but not electric generating facilities. There is, at present, considerable uncertainty over the timing and the specific requirements that would apply to any stationary source that might potentially be subject to GHG permitting and emission reduction requirements as a result of the EPA’s rules. Although Duke Energy does not anticipate taking actions that would trigger the GHG permitting requirements or GHG emission reduction requirements at any of its existing generating facilities, if it were to do so, the current uncertainty surrounding the implementation of the rules and the requirements that might apply prevent management from being able to determine at this time whether the EPA rules will have a material impact on Duke Energy’s future results of operations. Numerous groups have already filed petitions with the D.C. Circuit Court of Appeals for review of the EPA’s Endangerment Finding. It is likely that the EPA’s upcoming New Motor Vehicle and Tailoring rules will also be challenged in court once they are finalized. The current and expected legal challenges create additional uncertainty with respect to the EPA rules and what regulatory requirements, if any, will result from the rules.

Duke Energy supports the enactment of workable federal GHG legislation. Duke Energy prefers federal legislation over any EPA regulation of GHG emissions under the current CAA and believes that any legislation must include provisions that block the EPA from doing so and provide that the legislative program is the sole remedy for a source’s GHG emissions. To permit the economy to adjust rationally to the policy, legislation should establish a long-term program that first slows the growth of emissions, stops them and then transitions to a gradually declining emissions cap as new lower-and zero-emitting technologies are developed and become available for wide-scale deployment at a reasonable cost. Federal legislation should also include effective cost-containment measures to protect the U.S. economy from harmful consequences if compliance costs are excessive.

Duke Energy is unable to determine the potential cost of complying with unspecified and unknowable future GHG legislation or any indirect costs that might result, however, such costs could be significant. Duke Energy’s cost of complying with any legislatively-mandated federal GHG emissions regulations will depend upon the design details of the program, and upon the future levels of Duke Energy’s GHG emissions that might be regulated under the program. If potential future federal GHG legislation mandates a cap-and-trade approach, for example, the design elements of such a program that will have the greatest influence on Duke Energy’s compliance costs include (i) the level of the emissions cap over time, (ii) the GHG emission sources covered under the cap, (iii) the number of allowances that Duke Energy might be allocated at no cost on a year-to-year basis, (iv) the type and effectiveness of any cost containment measures that may be included in the program, (v) the role of emission offsets in the program, (vi) the availability and cost of technologies that will be available for Duke Energy to deploy to lower its emissions over time, and (vii) the price of allowances and emission offsets. Although Duke Energy believes it is likely that Congress will adopt mandatory GHG emission reduction legislation at some point, the timing and design details of any such legislation are highly uncertain at this time.

Assuming that a federal GHG cap-and-trade program is eventually enacted, Duke Energy’s compliance obligation under such a program would generally be determined by the difference between the level of its emissions in a given year and the number of no-cost allowances it receives for that year. This difference would represent the emission reductions that Duke Energy would need to achieve to comply and/or the number of allowances and/or offsets Duke Energy would need to purchase to comply, or a combination of the two. The cost of achieving the emission reductions and/or the cost of purchasing the needed allowances and/or emission offsets would represent Duke Energy’s compliance costs. This is why the more no-cost allowances Duke Energy receives, the lower its compliance obligation will be, and the lower its compliance cost will be. This is also why actions Duke Energy is taking today to reduce its GHG emissions over time will lower its exposure to any future GHG regulation. Under any future scenario involving mandatory GHG limitations, Duke Energy would plan to seek to recover its compliance costs through appropriate regulatory mechanisms in the jurisdictions in which it operates.

Although a near-term compliance strategy under a GHG cap-and-trade program might be focused primarily on the purchase of allowances and/or offsets due to the lack of available emission reduction technologies and/or the time it would take to deploy technologies once they become available, it is likely that over time there would be more focus placed on deploying technology to achieve large-scale reductions in emissions. This strategy could involve replacing some existing coal-fired generation with new lower-and zero-emitting generation technologies, and/or installing new carbon capture and sequestration technology when the technologies become ready for deployment. Although there is uncertainty about what new technologies may be developed, when they may be deployed, and what their costs will be, Duke Energy currently is focused on advanced nuclear generation, IGCC with CO₂ capture and sequestration, and CO₂ capture and storage retrofit technology for existing pulverized coal-fired generation as promising technologies for generating electricity with lower or no CO₂ emissions. Duke Energy is also making a significant commitment to increased customer energy efficiency and promoting enhanced use of renewable energy for meeting customers’ electricity needs. Duke Energy’s actions are designed to build a sustainable business that allows our customers and our shareholders to prosper in what is expected to be a carbon-constrained environment.

At the state level, the Midwestern Governors Association launched an initiative several years ago called the Midwestern Greenhouse Gas Reduction Accord (Accord). One of the objectives of the initiative was to produce a Model Rule for implementing a GHG cap-and-trade system on a regional level for consideration by individual states. In October 2009, the Accord produced a draft Model Rule, and plans to finalize the document in early 2010. Once finalized, the Model Rule will be available to states for their consideration and possible adoption and implementation. The states of Ohio and Indiana, where Duke Energy has electric generation operations, have been observers to the

Accord process and have shown no interest in adopting the Model Rule. Based on the current position of Indiana and Ohio in this regard, Duke Energy does not anticipate any cost impacts from the initiative.

In December 2007, Duke Energy began the regulatory process to construct a new nuclear power plant, William States Lee III Nuclear Station, in South Carolina, by petitioning the NRC for a COL. If constructed, this facility would produce virtually no GHGs.

With regard to advanced clean-coal, Duke Energy is in the process of constructing an IGCC power plant in Indiana. One of the key features of the IGCC technology is that it has the potential to support the capture of its CO₂ emissions, with subsequent underground storage of the captured CO₂. Although the IGCC plant, scheduled to begin operations in 2012, is not currently being equipped with the technology to capture CO₂, space was included in the design of the plant for this technology to be added later. Duke Energy is working to complete in early 2011 the front-end engineering and design of a CO₂-capture facility. The deployment of CO₂ capture and storage technology would help Duke Energy comply with any future GHG emission reduction requirements.

The state legislatures of North Carolina and Ohio have passed laws that require Duke Energy to meet increasing percentages of its customers’ electricity needs with renewable energy and customer energy efficiency. In North Carolina the requirement reaches 12.5% in 2021 and in Ohio it reaches a minimum of 12.5% in 2024. Duke Energy will be meeting these requirements through a variety of actions and each is expected to assist Duke Energy’s overall effort to reduce its CO₂ emissions. Versions of an energy efficiency and renewable electricity standard have been passed by the House as part of ACES and by the Senate Energy and Natural Resources Committee in S. 1462. Given the current challenges associated with passing comprehensive federal climate change legislation, Congress could instead attempt to pass energy legislation in 2010 that includes a federal energy efficiency and renewable electricity standard – provisions both the full House and a Senate committee have approved, albeit at different levels. If this were to occur, Duke Energy’s compliance with the North Carolina and Ohio requirements would further its ability to comply with whatever federal requirements Congress might enact.

In addition to relying on new technologies to reduce its CO₂ emissions, Duke Energy has filed for regulatory approval in most of the states in which it operates for its energy efficiency programs, which will help meet customer electricity needs by increasing energy efficiency, thereby reducing demand instead of relying almost exclusively on new power plants to generate electricity. Duke Energy has received regulatory approval from Ohio, North Carolina and South Carolina and is in the process of rolling programs out in these states. Duke Energy received regulatory approval from Indiana and has withdrawn its filing in Kentucky.

Duke Energy recognizes that certain groups associate frequent and severe extreme weather events with climate change and the associated damage to the electric distribution system and the possibility that these weather events could have a material impact on future results of operations should these events occur. However, the uncertain nature of potential changes in extreme weather events (such as increased frequency, duration, and severity), the long period of time over which any changes might take place, and the inability to predict these accurately, make estimating any potential future financial risk to Duke Energy’s operations that may be caused by the physical risks of climate change impossible. Currently, Duke Energy plans and prepares for extreme weather events that it experiences from time to time, such as ice storms, tornados, severe thunderstorms, high winds and droughts. Duke Energy’s past experiences preparing for and responding to the impacts of these types of weather-related events would reasonably be expected to help management plan and prepare for future climate change-related severe weather events to reduce, but not eliminate, the operational, economic and financial impacts of such events. Duke Energy also routinely takes steps to reduce the potential impact of severe weather events on its electric distribution systems. Duke Energy does not currently operate in coastal areas and therefore is not exposed to the effects of potential sea level rise. Duke Energy’s electric generating facilities are designed to withstand extreme weather events without damage. Duke Energy maintains an inventory of coal and oil on site to mitigate the effects of any potential short-term disruption in its fuel supply so it can continue to provide its customers with an uninterrupted supply of electricity.

For additional information on other issues related to Duke Energy, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters” and Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies.”

The following new Accounting Standard Updates (ASU) have been issued, but have not yet been adopted by Duke Energy, as of December 31, 2009:

Accounting Standards Codification (ASC) 860 – Transfers and Servicing. In June 2009, the Financial Accounting Standards Board (FASB) issued revised accounting guidance for transfers and servicing of financial assets and extinguishment of liabilities, to require additional information about transfers of financial assets, including securitization transactions, as well as additional information about an enterprise’s continuing exposure to the risks related to transferred financial assets. This revised accounting guidance eliminates the concept of a QSPE and requires those entities which were not subject to consolidation under previous accounting rules to now be assessed for consolidation. In addition, this accounting guidance clarifies and amends the derecognition criteria for transfers of financial assets (including transfers of portions of financial assets) and requires additional disclosures about a transferor’s continuing involvement in transferred financial assets. For Duke Energy, this revised accounting guidance is effective prospectively for transfers of financial assets occurring on or after January 1, 2010, and early adoption of this statement is prohibited. Since 2002, Duke Energy Ohio, Duke Energy Indiana, and Duke Energy Kentucky have sold, on a revolving basis, nearly all of their accounts receivable and related collections through Cinergy Receivables, a bankruptcy-remote QSPE. The securitization transaction was structured to meet the criteria for sale accounting treatment, and accordingly, Duke Energy has not consolidated Cinergy Receivables, and the transfers have been accounted for as sales. Upon adoption of this revised accounting guidance, the accounting treatment and/or financial statement presentation of Duke Energy’s accounts receivable securitization programs will be impacted as Cinergy Receivables will be consolidated by Duke Energy as of January 1, 2010. See Note 21 for additional information.

ASC 810 - Consolidations. In June 2009, the FASB amended existing consolidation accounting guidance to eliminate the exemption from consolidation for QSPEs, and clarified, but did not significantly change, the criteria for determining whether an entity meets the definition of a VIE. This revised accounting guidance also requires an enterprise to qualitatively assess the determination of the primary beneficiary of a VIE based on whether that enterprise has both the power to direct matters that most significantly impact the activities of a VIE and the obligation to absorb losses or the right to receive benefits of a VIE that could potentially be significant to a VIE. In addition, this revised accounting guidance modifies existing accounting guidance to require an ongoing evaluation of a VIE’s primary beneficiary and amends the types of events that trigger a reassessment of whether an entity is a VIE. Furthermore, this accounting guidance requires enterprises to provide additional disclosures about their involvement with VIEs and any significant changes in their risk exposure due to that involvement. For Duke Energy, this accounting guidance is effective beginning on January 1, 2010, and is applicable to all entities in which Duke Energy is involved with, including entities previously subject to existing accounting guidance for VIEs, as well as any QSPEs that exist as of the effective date. Early adoption of this revised accounting guidance is prohibited. Upon adoption of this revised accounting guidance, the accounting treatment and/or financial statement presentation of Duke Energy’s accounts receivable securitization programs will be impacted as Cinergy Receivables will be consolidated by Duke Energy effective January 1, 2010. Duke Energy is currently evaluating the potential impact of the adoption of this revised accounting guidance on its other interests in VIEs and is unable to estimate at this time the impact of adoption on its consolidated results of operations, cash flows or financial position.

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

We have audited the accompanying consolidated balance sheets of Duke Energy Corporation and subsidiaries (the “Company”) as of December 31, 2009 and 2008, and the related consolidated statements of operations, equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2009. Our audits also included the financial statement schedules listed in the Index at Item 15. We also have audited the Company’s internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report On Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedules and an opinion on the Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Duke Energy Corporation and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Nature of Operations and Basis of Consolidation. Duke Energy Corporation (collectively with its subsidiaries, Duke Energy), is an energy company primarily located in the Americas. Duke Energy operates in the United States (U.S.) primarily through its wholly-owned subsidiaries, Duke Energy Carolinas, LLC (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), as well as in South and Central America through International Energy. See Note 2 for further information on Duke Energy’s operations and its reportable business segments. These Consolidated Financial Statements include, after eliminating intercompany transactions and balances, the accounts of Duke Energy and all majority-owned subsidiaries where Duke Energy has control, and those variable interest entities where Duke Energy is the primary beneficiary. These Consolidated Financial Statements also reflect Duke Energy’s proportionate share of certain generation and transmission facilities in South Carolina, Ohio, Indiana and Kentucky.

On January 2, 2007, Duke Energy completed the spin-off to shareholders of its natural gas businesses. The primary businesses that remained with Duke Energy post-spin are the U.S. Franchised Electric and Gas business segment, the Commercial Power business segment and the International Energy business segment. See Note 2 for further information on Duke Energy’s business segments. Assets and liabilities of entities included in the spin-off of Spectra Energy Corp. (Spectra Energy) were transferred from Duke Energy on a historical cost basis on the date of the spin-off transaction. No gain or loss was recognized on the distribution of these operations to Duke Energy shareholders. Approximately $20.5 billion of assets, $14.9 billion of liabilities (which included approximately $8.6 billion of debt) and $5.6 billion of common stockholders’ equity (which included approximately $1.0 billion of accumulated other comprehensive income) were distributed from Duke Energy as of the date of the spin-off.

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

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

Fuel Cost Deferrals. Fuel expense includes fuel costs or other recoveries that are deferred through fuel clauses established by Duke Energy’s regulators. These clauses allow Duke Energy to recover fuel costs, fuel-related costs and portions of purchased power costs through surcharges on customer rates. These deferred fuel costs are recognized in revenues and fuel expenses as they are billable to customers.

Reapplication of Regulatory Accounting Treatment to Portions of Generation in Ohio. Commercial Power’s generation operations in the Midwest include generation assets located in Ohio that are dedicated to serve Ohio native load customers. These assets, as excess capacity allows, also generate revenues through sales outside the native load customer base, and such revenue is termed non-native.

Prior to December 17, 2008, Commercial Power did not apply regulatory accounting treatment to any of its operations due to the comprehensive electric deregulation legislation passed by the state of Ohio in 1999. As discussed further in Note 4, in April 2008, new legislation, Ohio Senate Bill 221 (SB 221), was passed in Ohio and signed by the Governor of Ohio on May 1, 2008. The new law codified the Public Utilities Commission of Ohio’s (PUCO) authority to approve an electric utility’s standard service offer either through an Electric Security Plan (ESP) or a Market Rate Option (MRO), which is a price determined through a competitive bidding process. On July 31, 2008, Duke Energy Ohio filed an ESP and, with certain amendments, the ESP was approved by the PUCO on December 17, 2008. The approval of the ESP on December 17, 2008 resulted in the reapplication of regulatory accounting treatment to certain portions of Commercial Power’s operations as of that date. The ESP became effective on January 1, 2009.

From January 1, 2005 through December 31, 2008, Commercial Power operated under a Rate Stabilization Plan (RSP), which was a market-based standard service offer. Although the RSP contained certain trackers that enhanced the potential for cost recovery, there was no assurance of stranded cost recovery upon the expiration of the RSP on December 31, 2008 since it was initially anticipated that there would be a move to full competitive markets upon the expiration of the RSP. Accordingly, Commercial Power did not apply regulatory accounting treatment to any of its generation operations prior to December 17, 2008. In connection with the approval of the ESP, Duke Energy reassessed whether Commercial Power’s generation operations met the criteria for regulatory accounting treatment as SB 221 substantially increased the PUCO’s oversight authority over generation in the state of Ohio, including giving the PUCO complete approval of

generation rates and the establishment of an earnings test to determine if a utility has earned significantly excessive earnings. Duke Energy determined that certain costs and related rates (riders) of Commercial Power’s operations related to generation serving native load met the necessary accounting criteria for regulatory accounting treatment as SB 221 and Duke Energy Ohio’s approved ESP enhanced the recovery mechanism for certain costs of its generation serving native load and increased the likelihood that these operations will remain under a cost recovery model for certain costs for the remainder of the ESP period.

Despite certain portions of the Ohio native load operations not meeting the criteria for applying regulatory accounting treatment, all of Commercial Power’s Ohio native load operations’ rates are subject to approval by the PUCO, and thus these operations are referred to here-in as Commercial Power’s regulated operations. Accordingly, beginning January 1, 2009, these revenues and corresponding fuel and purchased power expenses are recorded in Regulated Electric within Operating Revenues and Fuel Used in Electric Generation and Purchased Power—Regulated within Operating Expense, respectively, on the Consolidated Statements of Operations.

The reapplication of regulatory accounting treatment to generation in Ohio on December 17, 2008, as discussed above, resulted in an approximate $67 million after-tax (approximately $103 million pre-tax) extraordinary gain related to mark-to-market losses previously recorded in earnings associated with open forward native load economic hedge contracts for fuel, purchased power and emission allowances, which the RSP and ESP allow to be recovered through a fuel and purchase power (FPP) rider. There were no other immediate income statement impacts on the date of reapplication of regulatory accounting. A corresponding regulatory asset was established for the value of these contracts.

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

Restricted Cash. At December 31, 2009 and 2008, Duke Energy had approximately $38 million and $85 million, respectively, of restricted cash related primarily to proceeds from debt issuances that are held in trust for the purpose of funding future environmental construction or maintenance expenditures. Restricted cash balances are reflected within both Other within Current Assets and Other within Investments and Other Assets on the Consolidated Balance Sheets.

Inventory. Inventory is comprised of amounts presented in the table below and is recorded primarily using the average cost method. Inventory related to Duke Energy’s regulated operations is valued at historical cost consistent with ratemaking treatment. Materials and supplies are recorded as inventory when purchased and subsequently charged to expense or capitalized to plant when installed. Inventory related to Duke Energy’s non-regulated operations is valued at the lower of cost or market.

Effective November 1, 2008, Duke Energy Ohio and Duke Energy Kentucky executed agreements with a third party to transfer title of natural gas inventory purchased by Duke Energy Ohio and Duke Energy Kentucky to the third party. Under the agreements, the gas inventory was stored and managed for Duke Energy Ohio and Duke Energy Kentucky and was delivered on demand. As a result of the agreements, the combined natural gas inventory of approximately $81 million being held by a third party as of December 31, 2008 was classified as Other within Current Assets on the Consolidated Balance Sheets.

The gas storage agreements noted above expired on October 31, 2009. Effective November 1, 2009, Duke Energy Ohio and Duke Energy Kentucky executed agreements with a different third party. Under the new agreements, the gas inventory is being stored and managed for Duke Energy Ohio and Duke Energy Kentucky and will be delivered on demand. However, title of the natural gas inventory remains with Duke Energy Ohio and Duke Energy Kentucky. The new gas storage agreements will expire on October 31, 2011.

Investments in Debt and Equity Securities. Duke Energy classifies investments into two categories – trading and available-for-sale. Trading securities are reported at fair value in the Consolidated Balance Sheets with net realized and unrealized gains and losses included in earnings each period. Available-for-sale securities are also reported at fair value on the Consolidated Balance Sheets with unrealized gains and losses included in Accumulated Other Comprehensive Income (AOCI) or a regulatory asset or liability, unless it is determined that the

carrying value of an investment is other-than-temporarily impaired. Other-than-temporary impairments related to equity securities and the credit loss portion of debt securities are included in earnings, unless deferred in accordance with regulatory accounting treatment. Investments in debt and equity securities are classified as either short-term investments or long-term investments based on management’s intent and ability to sell these securities, taking into consideration illiquidity factors in the current markets with respect to certain investments that have historically provided for a high degree of liquidity, such as investments in auction rate debt securities.

See Note 10 for further information on the investments in debt and equity securities, including investments held in the Nuclear Decommissioning Trust Fund (NDTF).

Goodwill. Duke Energy performs an annual goodwill impairment test as of August 31 each year and updates the test between annual tests if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value. Duke Energy performs the annual review for goodwill impairment at the reporting unit level, which Duke Energy has determined to be an operating segment or one level below.

The annual test of the potential impairment of goodwill requires a two step process. Step one of the impairment test involves comparing the estimated fair values of reporting units with their aggregate carrying values, including goodwill. If the carrying amount of a reporting unit exceeds the reporting unit’s fair value, step two must be performed to determine the amount, if any, of the goodwill impairment loss. If the carrying amount is less than fair value, further testing of goodwill impairment is not performed.

For purposes of the step one analyses, determination of reporting units’ fair value is typically based on a combination of the income approach, which estimates the fair value of Duke Energy’s reporting units based on discounted future cash flows, and the market approach, which estimates the fair value of Duke Energy’s reporting units based on market comparables within the utility and energy industries.

See Note 11 for further information, including discussion of an approximate $371 million goodwill impairment charge recorded during the year ended December 31, 2009.

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

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

See Note 11 for further information regarding a long-lived asset impairment charge recorded during the year ended December 31, 2009.

Property, Plant and Equipment. Property, plant and equipment are stated at the lower of historical cost less accumulated depreciation or fair value, if impaired. For regulated operations, Duke Energy capitalizes all construction-related direct labor and material costs, as well as indirect construction costs. Indirect costs include general engineering, taxes and the cost of funds used during construction (see “Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized,” discussed below). The cost of renewals and betterments that extend the useful life of property, plant and equipment are also capitalized. The cost of repairs, replacements and major maintenance projects, which do not extend the useful life or increase the expected output of the asset, is expensed as incurred. Depreciation is generally computed over the estimated useful life of the asset using the composite straight-line method. The composite weighted-average depreciation rates, excluding nuclear fuel, were 3.30% for 2009, 3.11% for 2008, and 3.19% for 2007. Depreciation studies are conducted periodically to update the composite rates and are approved by the various state commissions.

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

See Note 14 for further information on the components and estimated useful lives of Duke Energy’s property, plant and equipment balance.

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

Allowance for Funds Used During Construction and Interest Capitalized. In accordance with applicable regulatory accounting guidance, Duke Energy records AFUDC, which represents the estimated debt and equity costs of capital funds necessary to finance the construction of new regulated facilities. Both the debt and equity components of AFUDC are non-cash amounts within the Consolidated Statements of Operations. AFUDC is capitalized as a component of the cost of Property, Plant and Equipment, with an offsetting credit to Other Income and Expenses, net on the Consolidated Statements of Operations for the equity component and as an offset to Interest Expense on the Consolidated Statements of Operations for the debt component. After construction is completed, Duke Energy is permitted to recover these costs through inclusion in the rate base and the corresponding depreciation expense or nuclear fuel expense.

AFUDC equity is recorded in the Consolidated Statements of Operations on an after-tax basis and is a permanent difference item for income tax purposes (i.e., a permanent difference between financial statement and income tax reporting), thus reducing Duke Energy’s income tax expense and effective tax rate during the construction phase in which AFUDC equity is being recorded. The effective tax rate is subsequently increased in future periods when the completed property, plant and equipment is placed in service and depreciation of the AFUDC equity commences. See Note 6 for information related to the impacts of AFUDC equity on Duke Energy’s effective tax rate.

For non-regulated operations, interest is capitalized during the construction phase in accordance with the applicable accounting guidance.

Asset Retirement Obligations. Duke Energy recognizes asset retirement obligations for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset, and for conditional asset retirement obligations. The term conditional asset retirement obligation refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Thus, the timing and (or) method of settlement may be conditional on a future event. When recording an asset retirement obligation, the present value of the projected liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The present value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the estimated useful life of the asset. See Note 7 for further information regarding Duke Energy’s asset retirement obligations.

Revenue Recognition and Unbilled Revenue. Revenues on sales of electricity and gas are recognized when either the service is provided or the product is delivered. Operating revenues include unbilled electric and gas revenues earned when service has been delivered but not billed by the end of the accounting period. Unbilled retail revenues are estimated by applying an average revenue per kilowatt-hour (kWh) or per thousand cubic feet (Mcf) for all customer classes to the number of estimated kWh or Mcfs delivered but not billed. Unbilled wholesale energy revenues are calculated by applying the contractual rate per megawatt-hour (MWh) to the number of estimated MWh delivered but not yet billed. Unbilled wholesale demand revenues are calculated by applying the contractual rate per megawatt (MW) to the MW volume delivered but not yet billed. The amount of unbilled revenues can vary significantly from period to period as a result of numerous factors, including seasonality, weather, customer usage patterns and customer mix. Unbilled revenues, which are primarily recorded as Receivables on the Consolidated Balance Sheets and exclude receivables sold to Cinergy Receivables Company, LLC (Cinergy Receivables), were approximately $460 million and $390 million at December 31, 2009 and 2008, respectively. Additionally, Duke Energy Ohio, Duke Energy Kentucky and Duke Energy Indiana sell, on a revolving basis, nearly all of their retail accounts receivable and a portion of their wholesale accounts receivable and related collections to Cinergy Receivables, a bankruptcy remote, special purpose entity that is a wholly-owned limited liability company of Cinergy Corp. (Cinergy), a wholly-owned subsidiary of Duke Energy. The securitization transaction was structured to meet the criteria for sale accounting treatment under the accounting guidance for transfers and servicing of financial assets and, accordingly, the transfers of receivables are accounted for as sales. Receivables for unbilled retail and wholesale revenues of approximately $238 million and $266 million at December 31, 2009 and 2008, respectively, were included in the sales of accounts receivables to Cinergy Receivables. See Note 21 for additional information regarding Cinergy Receivables including the impacts of adoption of new accounting rules which require the consolidation of Cinergy Receivables.

Accounting for Risk Management, Hedging Activities and Financial Instruments. Duke Energy may use a number of different derivative and non-derivative instruments in connection with its commodity price, interest rate and foreign currency risk management activities, including swaps, futures, forwards and options. All derivative instruments not designated as hedges and not qualifying for the normal purchase/normal sale (NPNS) exception within the accounting guidance for derivatives are recorded on the Consolidated Balance Sheets at their fair value. Duke Energy may designate qualifying derivative instruments as either cash flow hedges or fair value hedges, while others either have not been designated as hedges or do not qualify as a hedge (hereinafter referred to as undesignated contracts). For all contracts accounted for as a hedge, Duke Energy prepares formal documentation of the hedge in accordance with the accounting guidance for derivatives. In addition, at inception and at least every three months thereafter, Duke Energy formally assesses whether the hedge contract is highly effective in offsetting changes in cash flows or fair values of hedged items. Duke Energy documents hedging activity by transaction type (futures/swaps) and risk management strategy (commodity price risk/interest rate risk).

See Note 8 for additional information and disclosures regarding risk management activities and derivative transactions and balances.

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

Duke Energy, through its captive insurance entities, also has reinsurance coverage, which provides reimbursement to Duke Energy for certain losses above a per incident and/or aggregate retention. Duke Energy recognizes a reinsurance receivable for recovery of incurred losses under its captive’s reinsurance coverage once realization of the receivable is deemed probable by its captive insurance companies.

Unamortized Debt Premium, Discount and Expense. Premiums, discounts and expenses incurred with the issuance of outstanding long-term debt are amortized over the terms of the debt issues. Any call premiums or unamortized expenses associated with refinancing higher-cost debt obligations to finance regulated assets and operations are amortized consistent with regulatory treatment of those items, where appropriate. The amortization expense is recorded as a component of interest expense in the Consolidated Statements of Operations and is reflected as Depreciation and amortization within Net cash provided by operating activities on the Consolidated Statements of Cash Flows.

Loss Contingencies and Environmental Liabilities. Duke Energy is involved in certain legal and environmental matters that arise in the normal course of business. Contingent losses are recorded when it is determined that it is probable that a loss has occurred and the amount of the loss can be reasonably estimated. When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, Duke Energy records a loss contingency at the minimum amount in the range. Unless otherwise required by GAAP, legal fees are expensed as incurred. Environmental liabilities are recorded on an undiscounted basis when the necessity for environmental remediation becomes probable and the costs can be reasonably estimated, or when other potential environmental liabilities are reasonably estimable and probable. Duke Energy expenses environmental expenditures related to conditions caused by past operations that do not generate current or future revenues. Certain environmental expenses receive regulatory accounting treatment, under which the expenses are recorded as regulatory assets. Environmental expenditures related to operations that generate current or future revenues are expensed or capitalized, as appropriate.

Pension and Other Post-Retirement Benefit Plans. Duke Energy maintains qualified, non-qualified and other post-retirement benefit plans. See Note 20 for information related to Duke Energy’s benefit plans, including certain accounting policies associated with these plans.

Severance and Special Termination Benefits. Duke Energy has an ongoing severance plan under which, in general, the longer a terminated employee worked prior to termination the greater the amount of severance benefits. Duke Energy records a liability for involuntary severance once an involuntary severance plan is committed to by management, or sooner, if involuntary severances are probable and the related severance benefits can be reasonably estimated. For involuntary severance benefits that are incremental to its ongoing severance

plan benefits, Duke Energy measures the obligation and records the expense at its fair value at the communication date if there are no future service requirements, or, if future service is required to receive the termination benefit, ratably over the service period. From time to time, Duke Energy offers special termination benefits under voluntary severance programs. Special termination benefits are measured upon employee acceptance and recorded immediately absent a significant retention period. If a significant retention period exists, the cost of the special termination benefits are recorded ratably over the remaining service periods of the affected employees. Employee acceptance of voluntary severance benefits is determined by management based on the facts and circumstances of the special termination benefits being offered.

Guarantees. Upon issuance or modification of a guarantee, Duke Energy recognizes a liability at the time of issuance or material modification for the estimated fair value of the obligation it assumes under that guarantee, if any. Fair value is estimated using a probability-weighted approach. Duke Energy reduces the obligation over the term of the guarantee or related contract in a systematic and rational method as risk is reduced under the obligation. Any additional contingent loss for guarantee contracts subsequent to the initial recognition of a liability in accordance with applicable accounting guidance is accounted for and recognized at the time a loss is probable and the amount of the loss can be reasonably estimated.

Duke Energy has entered into various indemnification agreements related to purchase and sale agreements and other types of contractual agreements with vendors and other third parties. These agreements typically cover environmental, tax, litigation and other matters, as well as breaches of representations, warranties and covenants. Typically, claims may be made by third parties for various periods of time, depending on the nature of the claim. Duke Energy’s potential exposure under these indemnification agreements can range from a specified to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. See Note 17 for further information.

Stock-Based Compensation. For employee awards, equity classified stock-based compensation cost is measured at the grant date, based on the fair value of the award, and is recognized as expense over the requisite service period, which generally begins on the date the award is granted through the earlier of the date the award vests or the date the employee becomes retirement eligible. Share-based awards, including stock options, granted to employees that are already retirement eligible are deemed to have vested immediately upon issuance, and therefore, compensation cost for those awards is recognized on the date such awards are granted. See Note 19 for further information.

Other Liabilities. At December 31, 2009 and 2008, approximately $257 million and $195 million, respectively, of liabilities associated with vacation accrued are included in Other within Current Liabilities on the Consolidated Balance Sheets. As of December 31, 2009, this balance exceeded 5% of total current liabilities.

Accounting For Purchases and Sales of Emission Allowances. Emission allowances are issued by the Environmental Protection Agency (EPA) at zero cost and permit the holder of the allowance to emit certain gaseous by-products of fossil fuel combustion, including sulfur dioxide (SO₂) and nitrogen oxide (NO_x). Allowances may also be bought and sold via third party transactions or consumed as the emissions are generated. Allowances allocated to or acquired by Duke Energy are held primarily for consumption. Duke Energy records emission allowances as Intangible Assets on its Consolidated Balance Sheets at cost and recognizes the allowances in earnings as they are consumed or sold. Gains or losses on sales of emission allowances by regulated businesses that do not provide for direct recovery through a cost tracking mechanism and non-regulated businesses are presented on a net basis in Gains (Losses) on Sales of Other Assets and Other, net, in the accompanying Consolidated Statements of Operations. For regulated businesses that provide for direct recovery of emission allowances, any gain or loss on sales of recoverable emission allowances are included in the rate structure of the regulated entity and are deferred as a regulatory asset or liability. Future rates charged to retail customers are impacted by any gain or loss on sales of recoverable emission allowances and, therefore, as the recovery of the gain or loss is recognized in operating revenues, the regulatory asset or liability related to the emission allowance activity is recognized as a component of Fuel Used in Electric Generation and Purchased Power-Regulated in the Consolidated Statements of Operations. Purchases and sales of emission allowances are presented gross as investing activities on the Consolidated Statements of Cash Flows. See Note 11 for discussion regarding the impairment of the carrying value of certain emission allowances in 2008.

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

Duke Energy records unrecognized tax benefits for positions taken or expected to be taken on tax returns, including the decision to exclude certain income or transactions from a return, when a more-likely-than-not threshold is met for a tax position and management believes that the position will be sustained upon examination by the taxing authorities. Management evaluates each position based solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Duke Energy records the largest amount of the unrecognized tax benefit that is greater than 50% likely of being realized upon settlement or effective settlement. Management considers a tax position effectively settled for the purpose of recognizing previously unrecognized tax benefits when the following conditions exist: (i) the taxing authority has completed its examination procedures, including all appeals and administrative reviews that the taxing authority is required and expected to perform for the tax positions, (ii) Duke Energy does not intend to appeal or litigate any aspect of the tax position included in the completed examination, and (iii) it is remote that the taxing authority would examine or reexamine any aspect of the tax position. See Note 6 for further information.

Deferred taxes are not provided on translation gains and losses where Duke Energy expects earnings of a foreign operation to be indefinitely reinvested.

Duke Energy records, as it relates to taxes, interest expense as Interest Expense and interest income and penalties in Other Income and Expenses, net, in the Consolidated Statements of Operations.

Accounting for Renewable Energy Tax Credits and Grants Under the American Recovery Act of 2009. In 2009, The American Recovery and Reinvestment Act of 2009 (the Stimulus Bill) was signed into law, which provides tax incentives in the form of ITC or cash grants for renewable energy facilities and renewable generation property either placed in service through specified dates or for which construction has begun prior to specified dates. Under the Stimulus Bill, Duke Energy may elect an ITC, which is determined based on a percentage of the tax basis of the qualified property placed in service, for property placed in service after 2008 and before 2014 (2013 for wind facilities) or a cash grant, which allows entities to elect to receive a cash grant in lieu of the ITC for certain property either placed in service in 2009 or 2010 or for which construction begins in 2009 and 2010. When Duke Energy elects either the ITC or cash grant on Commercial Power’s wind facilities that meet the stipulations of the Stimulus Bill, Duke Energy reduces the basis of the property recorded on the Consolidated Balance Sheets by the amount of the ITC or cash grant and, therefore, the ITC or grant benefit is recognized ratably over the life of the associated asset. Additionally, certain tax credits and government grants received under the Stimulus Bill provide for an

incremental initial tax depreciable base in excess of the carrying value for GAAP purposes, creating an initial deferred tax asset equal to the tax effect of one half of the ITC or government grant. Duke Energy records the deferred tax benefit as a reduction to income tax expense in the period that the basis difference is created.

Excise Taxes. Certain excise taxes levied by state or local governments are collected by Duke Energy from its customers. These taxes, which are required to be paid regardless of Duke Energy’s ability to collect from the customer, are accounted for on a gross basis. When Duke Energy acts as an agent, and the tax is not required to be remitted if it is not collected from the customer, the taxes are accounted for on a net basis. Duke Energy’s excise taxes accounted for on a gross basis and recorded as operating revenues in the accompanying Consolidated Statements of Operations were approximately $276 million, $278 million and $277 million for the years ended December 31, 2009, 2008 and 2007, respectively.

Foreign Currency Translation. The local currencies of Duke Energy’s foreign operations have been determined to be their functional currencies, except for certain foreign operations whose functional currency has been determined to be the U.S. Dollar, based on an assessment of the economic circumstances of the foreign operation. Assets and liabilities of foreign operations, except for those whose functional currency is the U.S. Dollar, are translated into U.S. Dollars at the exchange rates at period end. Translation adjustments resulting from fluctuations in exchange rates are included as a separate component of AOCI. Revenue and expense accounts of these operations are translated at average exchange rates prevailing during the year. Gains and losses arising from balances and transactions denominated in currencies other than the functional currency are included in the results of operations in the period in which they occur. See Note 22 for additional information on gains and losses primarily associated with International Energy’s remeasurement of certain cash and debt balances into the reporting entity’s functional currency and transaction gains and losses.

Statements of Consolidated Cash Flows. Duke Energy has made certain classification elections within its Consolidated Statements of Cash Flows. Cash flows from discontinued operations are combined with cash flows from continuing operations within operating, investing and financing cash flows within the Consolidated Statements of Cash Flows. With respect to cash overdrafts, book overdrafts are included within operating cash flows while bank overdrafts are included within financing cash flows.

Dividend Restrictions and Unappropriated Retained Earnings. Duke Energy does not have any legal, regulatory or other restrictions on paying common stock dividends to shareholders. However, as further described in Note 4, due to conditions established by regulators at the time of the Duke Energy/Cinergy merger in April 2006, certain wholly-owned subsidiaries have restrictions on paying dividends or otherwise advancing funds to Duke Energy. At December 31, 2009 and 2008, an insignificant amount of Duke Energy’s consolidated Retained Earnings balance represents undistributed earnings of equity method investments.

New Accounting Standards. The following new accounting standards were adopted by Duke Energy during the year ended December 31, 2009 and the impact of such adoption, if applicable has been presented in the accompanying Consolidated Financial Statements:

Financial Accounting Standards Board’s (FASB) Accounting Standards Codification (ASC) 105—Generally Accepted Accounting Principles (ASC 105). In June 2009, the FASB amended ASC 105 for the ASC, which identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP. Rules and interpretive releases of the Securities and Exchange Commission (SEC) under authority of federal securities laws are also sources of authoritative GAAP. On the effective date of the changes to ASC 105, which was for financial statements issued for interim and annual periods ending after September 15, 2009, the ASC supersedes all then-existing non-SEC accounting and reporting standards. Under the ASC, all of its content carries the same level of authority and the GAAP hierarchy includes only two levels of GAAP: authoritative and non-authoritative. While the adoption of the ASC did not have an impact on the accounting followed in Duke Energy’s consolidated financial statements, the ASC impacted the references to authoritative and non-authoritative accounting literature contained within the Notes.

ASC 805—Business Combinations (ASC 805). In December 2007, the FASB issued revised guidance related to the accounting for business combinations. This revised guidance retained the fundamental requirement that the acquisition method of accounting be used for all business combinations and that an acquirer be identified for each business combination. This statement also established principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any noncontrolling (minority) interests in an acquiree, and any goodwill acquired in a business combination or gain recognized from a bargain purchase. For Duke Energy, this revised guidance is applied prospectively to business combinations for which the acquisition date occurred on or after January 1, 2009. The impact to Duke Energy of applying this revised guidance for periods subsequent to implementation will be dependent upon the nature of any transactions within the scope of ASC 805. The revised guidance of ASC 805 changed the accounting for income taxes related to prior business combinations, such as Duke Energy’s merger with Cinergy. Effective January 1, 2009, the resolution of any tax contingencies relating to Cinergy that existed as of the date of the merger are required to be reflected in the Consolidated Statements of Operations instead of being reflected as an adjustment to the purchase price via an adjustment to goodwill.

ASC 810—Consolidations (ASC 810). In December 2007, the FASB amended ASC 810 to establish accounting and reporting standards for the noncontrolling (minority) interest in a subsidiary and for the deconsolidation of a subsidiary and to clarify that a noncontrolling interest in a subsidiary is an ownership interest in a consolidated entity that should be reported as equity in the consolidated financial statements. This amendment also changed the way the consolidated income statement is presented by requiring consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest. In addition, this amendment established a single method of accounting for changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation. For Duke Energy, this amendment was effective as of January 1, 2009, and has been applied prospectively, except for certain presentation and disclosure requirements that were applied retrospectively. The adoption of these provisions of ASC 810 impacted the presentation of noncontrolling interests in Duke Energy’s Consolidated Financial Statements, as well as the calculation of Duke Energy’s effective tax rate.

ASC 815—Derivatives and Hedging (ASC 815). In March 2008, the FASB amended and expanded the disclosure requirements for derivative instruments and hedging activities required under ASC 815. The amendments to ASC 815 requires qualitative disclosures about objectives and strategies for using derivatives, volumetric data, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. Duke Energy adopted these disclosure requirements as of January 1, 2009. The adoption of the amendments to ASC 815 did not have any impact on Duke Energy’s consolidated results of operations, cash flows or financial position. See Note 8 for the disclosures required under ASC 815.

ASC 715—Compensation—Retirement Benefits (ASC 715). In December 2008, the FASB amended ASC 715 to require more detailed disclosures about employers’ plan assets, concentrations of risk within plan assets, and valuation techniques used to measure the fair value of plan assets. Additionally, companies will be required to disclose their pension assets in a fashion consistent with ASC 820—Fair Value

Measurements and Disclosures (i.e., Level 1, 2, and 3 of the fair value hierarchy) along with a roll-forward of the Level 3 values each year. For Duke Energy, these amendments to ASC 715 were effective for Duke Energy’s Form 10-K for the year ended December 31, 2009. The adoption of these new disclosure requirements did not have any impact on Duke Energy’s results of operations, cash flows or financial position. See Note 20 for the disclosures required under ASC 715.

The following new accounting standards were adopted by Duke Energy during the year ended December 31, 2008 and the impact of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:

ASC 820 – Fair Value Measurements and Disclosures (ASC 820). Refer to Note 9 for required fair value disclosures.

ASC 825 – Financial Instruments (ASC 825). ASC 825 permits, but does not require, entities to elect to measure many financial instruments and certain other items at fair value. See Note 9.

ASC 860 – Transfers and Servicing (ASC 860) and ASC 810. In December 2008, the FASB amended the disclosure requirements related to transfers and servicing of financial assets and variable interest entities (VIEs) to require public entities to provide additional disclosures about transfers of financial assets and to require public enterprises to provide additional disclosures about their involvement with VIEs. Additionally, certain disclosures were required to be provided by a public enterprise that is (a) a sponsor that has a variable interest in a VIE and (b) an enterprise that holds a significant variable interest in a qualifying special-purpose entity (QSPE) but was not the transferor (nontransferor enterprise) of financial assets to the QSPE. The new disclosure requirements are intended to provide greater transparency to financial statement users about a transferor’s continuing involvement with transferred financial assets and an enterprise’s involvement with VIEs. The new disclosure requirements were effective for Duke Energy beginning December 31, 2008. The additional requirements of ASC 810 did not have any impact on Duke Energy’s consolidated results of operations, cash flows or financial position. See Note 21 for additional information.

The following new accounting standards were adopted by Duke Energy during the year ended December 31, 2007 and the impact of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:

ASC 715. In October 2006, the FASB issued accounting rules that changed the recognition and disclosure provisions and measurement date requirements for an employer’s accounting for defined benefit pension and other post-retirement plans. The recognition and disclosure provisions require an employer to (1) recognize the funded status of a benefit plan—measured as the difference between plan assets at fair value and the benefit obligation—in its statement of financial position, (2) recognize as a component of other comprehensive income, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost, and (3) disclose in the notes to financial statements certain additional information. These new accounting rules did not change the amounts recognized in the income statement as net periodic benefit cost. Duke Energy recognized the funded status of its defined benefit pension and other post-retirement plans and provided the required additional disclosures as of December 31, 2006. The adoption of these new accounting rules did not have a material impact on Duke Energy’s consolidated results of operations or cash flows.

Under the new measurement date requirements, an employer is required to measure defined benefit plan assets and obligations as of the date of the employer’s fiscal year-end statement of financial position (with limited exceptions). Historically, Duke Energy measured its plan assets and obligations up to three months prior to the fiscal year-end, as allowed under the authoritative accounting literature. Duke Energy adopted the change in measurement date effective January 1, 2007 by remeasuring plan assets and benefit obligations as of that date, pursuant to the transition requirements of the new accounting rules. See Note 20.

ASC 740 – Income Taxes (ASC 740). In July 2006, the FASB provided new guidance on accounting for income tax positions about which Duke Energy has concluded there is a level of uncertainty with respect to the recognition of a tax benefit in Duke Energy’s financial statements. This guidance prescribed the minimum recognition threshold a tax position is required to meet. Tax positions are defined very broadly and include not only tax deductions and credits but also decisions not to file in a particular jurisdiction, as well as the taxability of transactions. Duke Energy adopted this new accounting guidance effective January 1, 2007. See Note 6 for additional information.

The following new Accounting Standard Updates (ASU) have been issued, but have not yet been adopted by Duke Energy, as of December 31, 2009:

ASC 860. In June 2009, the FASB issued revised accounting guidance for transfers and servicing of financial assets and extinguishment of liabilities, to require additional information about transfers of financial assets, including securitization transactions, as well as additional information about an enterprise’s continuing exposure to the risks related to transferred financial assets. This revised accounting guidance eliminates the concept of a qualifying special-purpose entity (QSPE) and requires those entities which were not subject to consolidation under previous accounting rules to now be assessed for consolidation. In addition, this accounting guidance clarifies and amends the derecognition criteria for transfers of financial assets (including transfers of portions of financial assets) and requires additional disclosures about a transferor’s continuing involvement in transferred financial assets. For Duke Energy, this revised accounting guidance is effective prospectively for transfers of financial assets occurring on or after January 1, 2010, and early adoption of this statement is prohibited. Since 2002, Duke Energy Ohio, Duke Energy Indiana, and Duke Energy Kentucky have sold, on a revolving basis, nearly all of their accounts receivable and related collections through Cinergy Receivables, a bankruptcy-remote QSPE. The securitization transaction was structured to meet the criteria for sale accounting treatment, and accordingly, Duke Energy has not consolidated Cinergy Receivables, and the transfers have been accounted for as sales. Upon adoption of this revised accounting guidance, the accounting treatment and/or financial statement presentation of Duke Energy’s accounts receivable securitization programs will be impacted as Cinergy Receivables will be consolidated by Duke Energy as of January 1, 2010. See Note 21 for additional information.

ASC 810 - In June 2009, the FASB amended existing consolidation accounting guidance to eliminate the exemption from consolidation for QSPEs, and clarified, but did not significantly change, the criteria for determining whether an entity meets the definition of a VIE. This revised accounting guidance also requires an enterprise to qualitatively assess the determination of the primary beneficiary of a VIE based on whether that enterprise has both the power to direct matters that most significantly impact the activities of a VIE and the obligation to absorb losses or the right to receive benefits of a VIE that could potentially be significant to a VIE. In addition, this revised accounting guidance modifies existing accounting guidance to require an ongoing evaluation of a VIE’s primary beneficiary and amends the types of events that trigger a reassessment of whether an entity is a VIE. Furthermore, this accounting guidance requires enterprises to provide additional disclosures about their involvement with VIEs and any significant changes in their risk exposure due to that involvement. For Duke Energy, this accounting guidance is effective beginning on January 1, 2010, and is applicable to all entities in which Duke Energy is involved with, including entities previously subject to existing accounting guidance for VIEs, as well as any QSPEs that exist as of the effective date. Early adoption of this revised accounting guidance is prohibited. Upon adoption of this revised accounting guidance, the accounting treatment and/or financial statement presentation of Duke Energy’s accounts receivable securitization programs will be impacted as Cinergy Receivables will be consolidated by Duke Energy effective January 1, 2010. Duke Energy is currently evaluating the potential impact of the adoption of this revised accounting guidance on its other interests in VIEs and is unable to estimate at this time the impact of adoption

Duke Energy operates the following business segments, which are all considered reportable business segments: U.S. Franchised Electric and Gas, Commercial Power and International Energy. There is no aggregation of operating segments within Duke Energy’s reportable business segments. Duke Energy’s management believes these reportable business segments properly align the various operations of Duke Energy with how the chief operating decision maker views the business. Duke Energy’s chief operating decision maker regularly reviews financial information about each of these reportable business segments in deciding how to allocate resources and evaluate performance.

U.S. Franchised Electric and Gas generates, transmits, distributes and sells electricity in central and western North Carolina, western South Carolina, central, north central and southern Indiana, and northern Kentucky. U.S. Franchised Electric and Gas also transmits, and distributes electricity in southwestern Ohio. Additionally, U.S. Franchised Electric and Gas transports and sells natural gas in southwestern Ohio and northern Kentucky. It conducts operations primarily through Duke Energy Carolinas, Duke Energy Ohio, Duke Energy Indiana and 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 PUCO, the Indiana Utility Regulatory Commission (IURC) and the Kentucky Public Service Commission (KPSC). The substantial majority of U.S. Franchised Electric and Gas’ operations are regulated and, accordingly, these operations qualify for regulatory accounting treatment.

Commercial Power owns, operates and manages 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’s generation asset fleet consists of Duke Energy Ohio’s regulated generation in Ohio and the five Midwestern gas-fired non-regulated generation assets that were a portion of the former Duke Energy North America (DENA) operations. Commercial Power’s assets, excluding wind energy generation assets, comprise approximately 7,550 net MW 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. Effective January 2009, the generation asset output in Ohio is contracted under the ESP through December 31, 2011. As discussed further in Notes 1 and 4, beginning on December 17, 2008, Commercial Power reapplied regulatory accounting treatment to certain portions of its operations due to the passing of SB 221 and the approval of the ESP. Commercial Power also has a retail sales subsidiary, Duke Energy Retail Sales (DERS), which is certified by the PUCO as a Competitive Retail Electric Service (CRES) provider in Ohio. DERS serves retail electric customers in Southwest, West Central and Northern Ohio with generation and other energy services at competitive rates. During 2009, due to increased levels of customer switching as a result of the competitive markets in Ohio, DERS has focused on acquiring customers that had previously been served by Duke Energy Ohio under the ESP, as well as those previously served by other Ohio franchised utilities. Commercial Power also develops and implements customized energy solutions. Through Duke Energy Generation Services, Inc. and its affiliates (DEGS), Commercial Power develops, owns and operates electric generation for large energy consumers, municipalities, utilities and industrial facilities. DEGS currently manages 6,150 MW of power generation at 21 facilities throughout the U.S. In addition, DEGS engages in the development, construction and operation of wind energy projects. Currently, DEGS has approximately 735 net MW of wind energy generating capacity in commercial operation, approximately 250 MW of wind energy under construction and more than 5,000 MW of wind energy projects in development. DEGS is also developing transmission, solar and biomass projects.

International Energy principally operates and manages power generation facilities and engages in sales and marketing of electric power and natural gas outside the U.S. It conducts operations primarily through Duke Energy International, LLC and its affiliates and its activities principally 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), and Attiki Gas Supply S.A. (Attiki), which is a natural gas distributor located in Athens, Greece. See Note 12 for additional information related to the investment in Attiki subsequent to December 31, 2009.

The remainder of Duke Energy’s operations is presented as Other. While it is not considered a business segment, Other primarily includes certain unallocated corporate costs, Bison Insurance Company Limited (Bison), Duke Energy’s wholly-owned, captive insurance subsidiary, Duke Energy’s effective 50% interest in the Crescent JV (Crescent) and DukeNet Communications, LLC (DukeNet) and related telecommunications. Additionally, Other includes Duke Energy Trading and Marketing, LLC (DETM), which is 40% owned by ExxonMobil and 60% owned by Duke Energy, and management is currently in the process of winding down. Unallocated corporate costs include certain costs not allocable to Duke Energy’s reportable business segments, primarily governance costs, costs to achieve mergers and divestitures (such as the Cinergy merger and spin-off of Spectra) and costs associated with certain corporate severance programs. Bison’s principal activities as a captive insurance entity include the insurance and reinsurance of various business risks and losses, such as property, business interruption and general liability of subsidiaries and affiliates of Duke Energy. On a limited basis, Bison also participates in reinsurance activities with certain third parties. Crescent, which develops and manages high-quality commercial, residential and multi-family real estate projects primarily in the Southeastern and Southwestern U.S, filed Chapter 11 petitions in a U.S. Bankruptcy Court in June 2009. As a result of recording its proportionate share of impairment charges recorded by Crescent during 2008, the carrying value of Duke Energy’s investment balance in Crescent is zero and Duke Energy discontinued applying the equity method of accounting to its investment in Crescent in the third quarter of 2008 and has not recorded its proportionate share of any Crescent earnings or losses in subsequent periods. See Note 12 for additional information related to Crescent. DukeNet develops, owns and operates a fiber optic communications network, primarily in the Southeast U.S., serving wireless, local and long-distance communications companies, internet service providers and other businesses and organizations.

Duke Energy’s reportable business segments offer different products and services or operate under different competitive environments and are managed separately. Accounting policies for Duke Energy’s segments are the same as those described in Note 1. Management evaluates segment performance based on earnings before interest and taxes from continuing operations (excluding certain corporate governance costs), after deducting amounts attributable to noncontrolling interests related to those profits (EBIT). On a segment basis, EBIT excludes discontinued operations, represents all profits from continuing operations (both operating and non-operating) before deducting interest, taxes and certain allocated governance costs, and is net of the expenses attributable to noncontrolling interests related to those profits. Segment EBIT includes transactions between reportable segments.

Cash, cash equivalents and short-term investments are managed centrally by Duke Energy, so the associated interest and dividend income on those balances, as well as realized and unrealized gains and losses from foreign currency remeasurement and transactions, are excluded from the segments’ EBIT.

Acquisitions. Duke Energy consolidates assets and liabilities from acquisitions as of the purchase date, and includes earnings from acquisitions in consolidated earnings after the purchase date.

In June 2009, Duke Energy completed the purchase of the remaining approximate 24% noncontrolling interest in the Aguaytia Integrated Energy Project (Aguaytia), located in Peru, for approximately $28 million. Subsequent to this transaction, Duke Energy owns 100% of Aguaytia. As the carrying value of the noncontrolling interest was approximately $42 million at the date of acquisition, Duke Energy’s consolidated equity increased approximately $14 million as a result of this transaction. Cash paid for acquiring this additional ownership interest is included in Distributions to noncontrolling interests within Net cash provided by (used in) financing activities on the Consolidated Statements of Cash Flows.

In June 2009, Duke Energy acquired North Allegheny Wind, LLC (North Allegheny) in Western Pennsylvania for approximately $124 million. The fair value of the net assets acquired were determined primarily using a discounted cash flow model as the output of North Allegheny is contracted for 23¹/₂ years under a fixed price purchased power agreement. Substantially all of the fair value of the acquired net assets has been attributed to property, plant and equipment. There was no goodwill associated with this transaction. North Allegheny owns 70 MW of power generating assets that began commercially generating electricity in the third quarter of 2009.

On September 30, 2008, Duke Energy completed the purchase of a portion of Saluda River Electric Cooperative, Inc.’s (Saluda) ownership interest in the Catawba Nuclear Station. Under the terms of the agreement, Duke Energy paid approximately $150 million for the additional ownership interest in the Catawba Nuclear Station. Following the closing of the transaction, Duke Energy owns approximately 19% of the Catawba Nuclear Station. No goodwill was recorded as a result of this transaction. See Note 4 for discussion of the NCUC and the PSCSC approval of Duke Energy’s petition requesting an accounting order to defer incremental costs incurred from the purchase of this additional ownership interest.

In September 2008, Duke Energy acquired Catamount Energy Corporation (Catamount), a leading wind power company located in Rutland, Vermont. This acquisition included over 300 MW of power generating assets, including 283 net MW in the Sweetwater wind power facility in West Texas, and 20 net MW of biomass-fueled cogeneration in New England and also included approximately 1,750 MW of wind assets with the potential for development in the U.S. and United Kingdom. This transaction resulted in a purchase price of approximately $245 million plus the assumption of approximately $80 million of debt. The purchase accounting entries consisted of approximately $190 million of equity method investments, approximately $117 million of intangible assets related to wind development rights, approximately $70 million of goodwill, none of which is deductible for tax purposes, and approximately $80 million of debt. See “dispositions” below for a discussion of the subsequent sale of two projects acquired as part of the Catamount transaction.

In May 2007, Duke Energy acquired the wind power development assets of Energy Investor Funds from Tierra Energy. The purchase included more than 1,000 MW of wind assets in various stages of development in the Western and Southwestern U.S. and supports Duke Energy’s strategy to increase its investment in renewable energy. A significant portion of the purchase price was for intangible assets. Three of the development projects, totaling approximately 240 MW, are located in Texas and Wyoming. Two of these projects went into commercial operation during 2008, with the other project beginning commercial operation in 2009.

The pro forma results of operations for Duke Energy as if those acquisitions discussed above which closed prior to December 31, 2009 occurred as of the beginning of the periods presented do not materially differ from reported results.

Dispositions. In the first quarter of 2009, Duke Energy completed the sale of two United Kingdom wind projects acquired in the Catamount acquisition. No gain or loss was recognized on these transactions. As these projects did not meet the definition of a disposal group as defined within the applicable accounting guidance, these projects were not reflected as held for sale on the Consolidated Balance Sheets prior to the completion of the sale.

On January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses. See Note 1 and Note 13 for additional information.

Other Asset Sales. For the year ended December 31, 2009, the sale of other assets resulted in approximately $63 million in proceeds and net pre-tax gains of approximately $36 million, which is recorded in Gains (Losses) on Sales of Other Assets and Other, net, in the Consolidated Statements of Operations. These gains primarily relate to sales of emission allowances by U.S. Franchised Electric and Gas and Commercial Power.

For the year ended December 31, 2008, the sale of other assets resulted in approximately $87 million in proceeds and net pre-tax gains of approximately $69 million, which is recorded in Gains (Losses) on Sales of Other Assets and Other, net, in the Consolidated Statements of Operations. These gains primarily relate to Commercial Power’s sales of emission allowances.

For the year ended December 31, 2007, the sale of other assets resulted in approximately $32 million in proceeds and net pre-tax losses of approximately $5 million, which is recorded in Gains (Losses) on Sales of Other Assets and Other, net, in the Consolidated Statements of Operations. These losses primarily relate to Commercial Power’s sales of emission allowances that were written up to fair value in purchase accounting in connection with Duke Energy’s merger with Cinergy in April 2006.

The substantial majority of U.S. Franchised Electric and Gas’ operations and certain portions of Commercial Power’s operations apply regulatory accounting treatment. Accordingly, these businesses record assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. See Note 1 for further information.

Restrictions on the Ability of Certain Subsidiaries to Make Dividends, Advances and Loans to Duke Energy Corporation. As a condition to the Duke Energy and Cinergy merger approval, the PUCO, the KPSC, the PSCSC, the IURC and the NCUC imposed conditions (the Merger Conditions) on the ability of Duke Energy Carolinas, Duke Energy Ohio, Duke Energy Kentucky and Duke Energy Indiana to transfer funds to Duke Energy through loans or advances, as well as restricted amounts available to pay dividends to Duke Energy. Duke Energy’s public utility subsidiaries may not transfer funds to the parent through intercompany loans or advances; however, certain subsidiaries may transfer funds to the parent by obtaining approval of the respective state regulatory commissions. Additionally, the Merger Conditions imposed the following restrictions on the ability of the public utility subsidiaries to pay cash dividends:

Duke Energy Carolinas. Under the Merger Conditions, Duke Energy Carolinas must limit cumulative distributions to Duke Energy Corporation subsequent to the merger to (i) the amount of retained earnings on the day prior to the closing of the merger, plus (ii) any future earnings recorded by Duke Energy Carolinas subsequent to the merger.

Duke Energy Ohio. Under the Merger Conditions, Duke Energy Ohio will not declare and pay dividends out of capital or unearned surplus without the prior authorization of the PUCO. In September 2009, the PUCO approved Duke Energy Ohio’s request to pay dividends out of paid-in capital up to the amount of the pre-merger retained earnings and to maintain a minimum of 20% equity in its capital structure.

Duke Energy Kentucky. Under the Merger Conditions, Duke Energy Kentucky is required to pay dividends solely out of retained earnings and to maintain a minimum of 35% equity in its capital structure.

Duke Energy Indiana. Under the Merger Conditions, Duke Energy Indiana shall limit cumulative distributions paid subsequent to the Duke Energy-Cinergy merger to (i) the amount of retained earnings on the day prior to the closing of the merger plus (ii) any future earnings recorded by Duke Energy Indiana subsequent to the merger. In addition, Duke Energy Indiana will not declare and pay dividends out of capital or unearned surplus without prior authorization of the IURC.

Additionally, certain other subsidiaries of Duke Energy have restrictions on their ability to dividend, loan or advance funds to Duke Energy due to specific legal or regulatory restrictions, including, but not limited to, minimum working capital and tangible net worth requirements.

At December 31, 2009, Duke Energy’s consolidated subsidiaries had restricted net assets of approximately $10.5 billion that may not be transferred to Duke Energy without appropriate approval based on the aforementioned merger conditions.

Rate Related Information. The NCUC, PSCSC, IURC and KPSC approve rates for retail electric and gas services within their states. The PUCO approves rates for retail gas and electric service within Ohio, except that non-regulated sellers of gas and electric generation also are allowed to operate in Ohio (see “Commercial Power” below). The FERC approves rates for electric sales to wholesale customers served under cost-based rates.

Duke Energy Carolinas North Carolina 2007 Rate Case. On December 20, 2007, the NCUC issued its Order Approving Stipulation and Deciding Non-Settled Issues (Order), which required that Duke Energy Carolinas’ test period for operating costs reflect an annualized level of the merger cost savings actually experienced in the test period. However, the NCUC recognized that its treatment of merger savings would not produce a fair result. Therefore, on February 18, 2008, the NCUC issued an order authorizing a 12-month increment rider, beginning January 2008, of approximately $80 million designed to provide a more equitable sharing of the actual merger savings achieved on an ongoing basis. Duke Energy Carolinas implemented the rate rider effective January 1, 2008 and terminated the rider effective January 1, 2009. The Order ultimately resulted in an overall average rate decrease of 5% in 2008, increasing to 7% upon expiration of this one-time rate rider.

Duke Energy Carolinas 2009 North Carolina Rate Case. On June 2, 2009, Duke Energy Carolinas filed an Application for Adjustment of Rates and Charges Applicable to Electric Service in North Carolina to increase its base rates. The Application was based upon a historical test year consisting of the 12 months ended December 31, 2008. On October 20, 2009, Duke Energy Carolinas entered into a settlement agreement with the North Carolina Public Staff. Two organizations representing industrial customers joined the settlement on October 22, 2009. The terms of the agreement include a base rate increase of $315 million (or approximately 8%) phased in primarily over a two-year period beginning January 1, 2010. In order to mitigate the impact of the increase on customers, the agreement provides for (i) a one-year delay in the collection of financing costs related to the Cliffside modernization project until January 1, 2011; and (ii) the accelerated return of certain regulatory liabilities to customers which lower the total impact to customer bills to an increase of approximately 7% in the near-term. The proposed settlement included a 10.7% return on equity and a capital structure of 52.5% equity and 47.5% long-term debt. Additionally, Duke Energy Carolinas agreed not to file another rate case before 2011 with any changes to rates taking effect no sooner than 2012. The NCUC approved the settlement agreement in full by order dated December 7, 2009. The new rates were effective and implemented on January 1, 2010.

Duke Energy Carolinas 2009 South Carolina Rate Case. On July 27, 2009, Duke Energy Carolinas filed its Application for Authority to Increase and Adjust Rates and Charges for an increase in rates and charges in South Carolina including approval of a charge to customer bills to pay for Duke Energy Carolinas’ new energy efficiency efforts. Parties to the proceeding include the South Carolina Office of Regulatory Staff (ORS), the South Carolina Energy Users Committee (SCEUC), and the South Carolina Green Party. Duke Energy Carolinas, ORS, and SCEUC filed a settlement agreement on November 24, 2009, recommending, (i) a $74 million increase in base rates, (ii) an allowed return on equity of 11% with rates set at a return on equity of 10.7% and capital structure of 53% equity, and (iii) various riders, including one that provides for the return of DSM charges previously collected from customers over three years, and another that provides for a storm reserve provision allowing Duke Energy Carolinas to collect $5 million annually (up to a maximum funding level of $50 million accumulating in reserves) to be used against large storm costs in any particular period. On January 20, 2010, the PSCSC approved the settlement agreement in full, including the cost recovery mechanism for the energy efficiency effort. The new rates were effective February 1, 2010.

Duke Energy Ohio Electric Rate Filings. New legislation (SB 221) codifies the PUCO’s authority to approve an electric utility’s standard generation service offer through an ESP, which would allow for pricing structures similar to those under the historic RSP. Electric utilities are required to file an ESP and may also file an application for a MRO at the same time. The MRO is a price determined through a

competitive bidding process. SB 221 provides for the PUCO to approve non-bypassable charges for new generation, including construction work-in-process from the outset of construction, as part of an ESP. The new law grants the PUCO discretion to approve single issue rate adjustments to distribution and transmission rates and establishes new alternative energy resources (including renewable energy) portfolio standards, such that a utility’s portfolio must consist of at least 25% of these resources by 2025. SB 221 also provides a separate requirement for energy efficiency, which must reduce a utility’s load by 22% before 2025. A utility’s earnings under the ESP are subject to an annual earnings test and the PUCO must order a refund if it finds that the utility’s earnings significantly exceed the earnings of benchmark companies with similar business and financial risks. The earnings test acts as a cap to the ESP price. SB 221 also limits the ability of a utility to transfer its designated generating assets to an exempt wholesale generator (EWG) absent PUCO approval. On July 31, 2008, Duke Energy Ohio filed an ESP to be effective January 1, 2009. On December 17, 2008, the PUCO issued its finding and order adopting a modified Stipulation with respect to Duke Energy Ohio’s ESP filing. The PUCO agreed to Duke Energy Ohio’s request for a net increase in base generation revenues, before impacts of customer switching, of $36 million, $74 million and $98 million in 2009, 2010 and 2011, respectively, including the termination of the residential and non-residential Regulatory Transition Charge, the recovery of expenditures incurred to deploy the SmartGrid infrastructure and the implementation of save-a-watt. The Stipulation also allowed Duke Energy Ohio to defer up to $50 million of certain operation and maintenance costs incurred at the W.C. Beckjord generating station for its continued operation and to amortize those costs over the three-year ESP period. The PUCO modified the Stipulation to permit certain non-residential customers to opt out of utility-sponsored energy efficiency initiatives and to allow residential governmental aggregation customers who leave Duke Energy Ohio’s system to avoid some charges.

As discussed further below within “Commercial Power” and in Note 1, as a result of the approval of the ESP, effective December 17, 2008, Commercial Power reapplied regulatory accounting to certain portions of its operations.

Duke Energy Ohio Gas Rate Case. In July 2007, Duke Energy Ohio filed an application with the PUCO for an increase in its base rates for gas service. The application also requested approval to continue tracker recovery of costs associated with the accelerated gas main replacement program and an acceleration of the riser replacement program. On February 28, 2008, Duke Energy Ohio reached a settlement agreement with the PUCO Staff and all of the intervening parties on its request for an increase in natural gas base rates. The settlement called for an annual revenue increase of approximately $18 million in base revenue, or 3% over current revenue, permitted continued recovery of costs through 2018 for Duke Energy Ohio’s accelerated gas main and riser replacement program and permitted recovery of carrying costs on gas stored underground via its monthly gas cost adjustment filing. The settlement did not resolve a proposed rate design for residential customers, which involved moving more of the fixed charges of providing gas service, such as capital investment in pipes and regulating equipment, billing and meter reading, from the per unit charges to the monthly charge. On May 28, 2008, the PUCO approved the settlement in its entirety and Duke Energy Ohio’s proposed modified straight fixed-variable rate design.

Duke Energy Ohio Electric Distribution Rate Case. On June 25, 2008, Duke Energy Ohio filed notice with the PUCO that it would seek a rate increase for electric delivery service to be effective in the second quarter of 2009. On December 22, 2008, Duke Energy Ohio filed an application requesting deferral of approximately $31 million related to damage to its distribution system from a September 14, 2008 windstorm, which was granted by the PUCO. Accordingly, a $31 million regulatory asset was recorded in 2008. On March 31, 2009, Duke Energy Ohio and Parties to the case filed a Stipulation and Recommendation which settles all issues in the case. The Stipulation provided for a revenue increase of $55 million, or approximately a 2.9% overall increase. The Parties also agreed that Duke Energy Ohio will recover any approved costs associated with the September 14, 2008 wind storm restoration through a separate rider recovery mechanism. Duke Energy Ohio agreed to file a separate application to set the rider and the PUCO will review the request and determine the appropriate amount of storm costs that should be recovered. The Stipulation includes, among other things, a weatherization and energy efficiency program, and recovery of distribution-related bad debt expenses through a rider mechanism. The Stipulation was approved in its entirety by the PUCO on July 8, 2009 and rates were effective July 13, 2009. On January 26, 2010, the Ohio Supreme Court affirmed the PUCO’s decision.

Duke Energy Kentucky Gas Rate Cases. In 2002, the KPSC approved Duke Energy Kentucky’s gas base rate case which included, among other things, recovery of costs associated with an accelerated gas main replacement program. The approval authorized a tracking mechanism to recover certain costs including depreciation and a rate of return on the program’s capital expenditures. The Kentucky Attorney General appealed to the Franklin Circuit Court the KPSC’s approval of the tracking mechanism as well as the KPSC’s subsequent approval of annual rate adjustments under this tracking mechanism. In 2005, both Duke Energy Kentucky and the KPSC requested that the court dismiss these cases.

In February 2005, Duke Energy Kentucky filed a gas base rate case with the KPSC requesting approval to continue the tracking mechanism and for a $14 million annual increase in base rates. A portion of the increase was attributable to recovery of the current cost of the accelerated gas main replacement program in base rates. In June 2005, the Kentucky General Assembly enacted Kentucky Revised Statute 278.509 (KRS 278.509), which specifically authorizes the KPSC to approve tracker recovery for utilities’ gas main replacement programs. In December 2005, the KPSC approved an annual rate increase and re-approved the tracking mechanism through 2011. In February 2006, the Kentucky Attorney General appealed the KPSC’s order to the Franklin Circuit Court, claiming that the order improperly allows Duke Energy Kentucky to increase its rates for gas main replacement costs in between general rate cases, and also claiming that the order improperly allows Duke Energy Kentucky to earn a return on investment for the costs recovered under the tracking mechanism which permits Duke Energy Kentucky to recover its gas main replacement costs.

In August 2007, the Franklin Circuit Court consolidated all the pending appeals and ruled that the KPSC lacks legal authority to approve the gas main replacement tracking mechanism, which was approved prior to the enactment of KRS 278.509 in 2005. To date, Duke Energy Kentucky has collected approximately $9 million in annual rate adjustments under the tracking mechanism. Per the KPSC order, Duke Energy Kentucky collected these revenues subject to refund pending the final outcome of this litigation. Duke Energy Kentucky and the KPSC have requested that the Kentucky Court of Appeals grant a rehearing of its decision. On February 5, 2009, the Kentucky Court of Appeals denied the rehearing requests of both Duke Energy Kentucky and the KPSC. Duke Energy Kentucky filed a motion for discretionary review to the Kentucky Supreme Court on or about March 6, 2009. The Kentucky Supreme Court has accepted discretionary review of this case and merit briefs were filed on October 19, 2009. Duke Energy Kentucky filed its reply brief on January 4, 2010.

On July 1, 2009, Duke Energy Kentucky filed its application for an approximate $18 million increase in base natural gas rates. Duke Energy Kentucky also proposed to implement a modified straight fixed-variable rate design for residential customers, which involves moving more of the fixed charges of providing gas service, such as capital investment in pipes and regulating equipment, billing and meter reading, from the volumetric charges to the fixed monthly charge. On November 19, 2009, Duke Energy Kentucky and the Kentucky Attorney General jointly filed a Stipulation and Recommendation reflecting their settlement of the gas rate case. The Stipulation and Recommendation reflects a revenue increase of $13 million, which reflected a10.375% Return on Equity. Duke Energy Kentucky agreed to withdraw its request for a straight fixed-variable rate design and to forego filing another gas rate case in the eighteen months following approval of the Stipulation and

Recommendation. The KPSC issued an order approving the Stipulation and Recommendation on December 29, 2009. New rates went into effect January 4, 2010.

Duke Energy Carolinas Energy Efficiency. On May 7, 2007, Duke Energy Carolinas filed its save-a-watt application with the NCUC. The save-a-watt proposal is based on the avoided cost of generation not needed resulting from any successful Duke Energy Carolinas energy efficiency programs. On February 26, 2009, the NCUC issued an order (i) approving Duke Energy Carolinas’ energy efficiency programs; (ii) requesting additional information on Duke Energy Carolinas’ returns under eight different compensation scenarios; and (iii) authorizing Duke Energy Carolinas to implement its rate rider pending approval of a final compensation mechanism by the NCUC. Duke Energy Carolinas filed the additional information requested by the NCUC on March 31, 2009. On June 12, 2009, Duke Energy Carolinas filed with the NCUC a settlement agreement between Duke Energy Carolinas and the Public Staff and several environmental intervenors. A hearing on the settlement was held on August 19, 2009. A Notice of Decision approving the settlement with modifications was issued on December 14, 2009. Duke Energy Carolinas began offering energy conservation programs to North Carolina retail customers and billing a conservation-only rider on June 1, 2009. On February 10, 2010, the NCUC approved the order in full.

In mid-October 2009, Duke Energy Carolinas began offering demand response programs in North Carolina. On January 1, 2010, Duke Energy Carolinas began to bill the full Rider Energy Efficiency approved by the NCUC in its December 14, 2009 Notice of Decision.

On May 6, 2009, the PSCSC approved Duke Energy Carolinas’ request for (i) approval of conservation and demand response programs; (ii) cancellation of certain existing demand response programs; (iii) deferral of the costs incurred to develop and implement the energy efficiency programs from June 1, 2009 until the date these costs are reflected in electric rates; and (iv) assurance that Duke Energy Carolinas may true-up incentives for costs deferred pursuant to the petition in accordance with the PSCSC order on the appropriate compensation mechanism in Duke Energy Carolinas’ 2009 general rate proceeding. Duke Energy Carolinas began offering demand response and conservation programs to South Carolina retail customers effective June 1, 2009. As described above, on January 20, 2010, the PSCSC approved Duke Energy Carolinas’ cost recovery mechanism for energy efficiency. The new rates were effective February 1, 2010.

The save-a-watt programs and compensation approach in both North Carolina and South Carolina are approved through December 31, 2013.

Duke Energy Ohio Energy Efficiency. Duke Energy Ohio filed the save-a-watt Energy Efficiency Plan as part of its ESP filed with the PUCO, which was approved by the PUCO on December 17, 2008, as discussed above, including allowing for the implementation of a new save-a-watt energy efficiency compensation model. However, the PUCO determined that certain non-residential customers may opt out of Duke Energy Ohio’s energy efficiency initiative. Applications for rehearing of this issue were denied by the PUCO and no further appeals of this issue have been taken. The save-a-watt programs and compensation approach in Ohio are approved through December 31, 2011.

Duke Energy Indiana Energy Efficiency. In October 2007, Duke Energy Indiana filed its petition with the IURC requesting approval of an alternative regulatory plan to increase its energy efficiency efforts in the state. Duke Energy Indiana seeks approval of a plan that will be available to all customer groups and will compensate Duke Energy Indiana for verified reductions in energy usage. Under the plan, customers would pay for energy efficiency programs through an energy efficiency rider that would be included in their power bill and adjusted annually through a proceeding before the IURC. The energy efficiency rider proposal is based on the save-a-watt compensation model of avoided cost of generation. A number of parties have intervened in the proceeding. Duke Energy Indiana has reached a settlement with all intervenors except one, the Citizens Action Coalition of Indiana, Inc. (CAC), and has filed such settlement agreement with the IURC. An evidentiary hearing with the IURC was held on February 27, 2009 and March 2, 2009. On February 10, 2010, the IURC approved the request. On December 9, 2009, the IURC issued an order concerning energy efficiency efforts within the state of Indiana wherein it required utilities, including Duke Energy Indiana, to promote a certain core set of energy efficiency programs through the use of a third party administrator that contracts directly with the utilities. The order also required energy usage reduction targets for the utilities, starting with 0.3% of sales in 2010 and increasing to 2% of sales in 2019. On February 10, 2010, the IURC issued an order approving the settlement with the OUCC with some modifications. The IURC approved Duke Energy Indiana’s proposed programs and allowed for the save-a-watt model incentives for Core Plus programs. The IURC also rejected a settlement agreement that allowed large industrial and commercial customers to opt out of utility sponsored energy efficiency, finding that initially energy efficiency programs should be available to all customer classes.

Duke Energy Kentucky Energy Efficiency. On November 15, 2007, Duke Energy Kentucky filed its annual application to continue existing energy efficiency programs, consisting of nine residential and two commercial and industrial programs, and to true-up its gas and electric tracking mechanism for recovery of lost revenues, program costs and shared savings. On February 11, 2008, Duke Energy Kentucky filed a motion to amend its energy efficiency programs. On December 1, 2008, Duke Energy Kentucky filed an application for a save-a-watt Energy Efficiency Plan. The application seeks a new energy efficiency recovery mechanism similar to what was proposed in Ohio. On January 27, 2010, Duke Energy Kentucky withdrew the application to implement save-a-watt and plans to file a revised portfolio in the future.

Duke Energy Carolinas Renewable Resources. On June 6, 2008, Duke Energy Carolinas filed an application with the NCUC seeking approval to implement a solar photovoltaic distributed generation program (Program). Duke Energy Carolinas proposed to invest $100 million over two years to install a total of 20 MW of electricity generating solar panels on multiple North Carolina sites including homes, schools, stores and factories. The Program will help Duke Energy Carolinas meet the requirement of North Carolina’s Renewable Energy and Energy Efficiency Portfolio Standard (REPS). It will also enable Duke Energy Carolinas to evaluate the role of distributed generation on Duke Energy Carolinas’ electrical system and gain experience in owning and operating renewable energy resources. Because the Program involves the construction of electric generating facilities, Duke Energy Carolinas required a Certificate of Public Convenience and Necessity (CPCN) from the NCUC. The REPS statute provides for the recovery of costs Duke Energy Carolinas incurs to comply with its requirements, principally through an annual rate rider.

In response to concerns raised by the Public Staff and various solar energy groups, Duke Energy Carolinas agreed to reduce the size of the Program to invest $50 million to install up to 10 MW of solar photovoltaic capacity. On December 31, 2008, the NCUC issued its Order Granting CPCN Subject to Conditions. The conditions (i) reduce the program size from 20 MW to 10 MW (as previously agreed upon by Duke Energy Carolinas); and (ii) limit program costs recoverable through the REPS rider to program costs equivalent to the cost of the third place bid in Duke Energy Carolinas’ 2007 request for proposal for renewable energy. The Order left open the opportunity to recover the excess costs through other recovery mechanisms. Based upon the revised size and availability of state and federal tax credits, Duke Energy Carolinas estimates the limited amount of program costs recoverable through the REPS rider will result in a monthly charge of approximately $0.05 for residential customers.

On May 6, 2009, in response to Duke Energy Carolinas’ request for reconsideration, the NCUC issued an Order allowing Duke Energy Carolinas to proceed with the Program and allowed Duke Energy Carolinas to recover all costs incurred in executing the Program through a combination of the REPS rider and base rates, subject to the NCUC’s review of the reasonableness and prudence of Duke Energy Carolinas’ execution of the Program. However, the NCUC declined to remove the limitation on costs recoverable through the REPS rider.

Duke Energy Carolinas Deferral of Costs. On February 4, 2009, Duke Energy Carolinas filed petitions with the NCUC and the PSCSC requesting an accounting order to defer the incremental costs incurred from the September 2008 purchase of an additional ownership interest in the Catawba Nuclear Station and certain post-in-service costs that are being or will be incurred in connection with the addition of the Allen Steam Station flue gas desulfurization equipment related to environmental compliance scheduled to go into service in the spring of 2009. The costs Duke Energy Carolinas sought to defer are the incremental costs that are being incurred or will be incurred from the date these assets are placed in service to the date Duke Energy Carolinas is authorized to begin reflecting in rates the recovery of such costs on an ongoing basis. On February 25, 2009, and March 31, 2009, the PSCSC and NCUC, respectively, approved the deferral of these costs. Duke Energy Carolinas began deferring costs in the first quarter 2009. These costs are being recovered in the new rates effective January 1, 2010 for North Carolina, and effective February 1, 2010, for South Carolina.

Duke Energy Carolinas Broad River Energy Center. On August 25, 2007, Duke Energy Carolinas experienced a disturbance on its bulk electric system which initiated at the Broad River Energy Center, a generating station owned and operated by a third party. The disturbance resulted in the tripping of six Duke Energy Carolinas generating units and the temporary opening of five 230 kilovolt (KV) transmission lines. The event resulted in no loss of load. In September 2008 the FERC initiated a preliminary, non-public investigation to determine if there were any potential violations by Duke Energy Carolinas of the North American Electric Reliability Council Reliability Standards. This investigation was coordinated with an ongoing Compliance Violation Investigation conducted by SERC Reliability Corporation. On March 5, 2009, FERC presented its preliminary findings about the event to Duke Energy Carolinas and solicited Duke Energy Carolinas’ responsive views about the event and the findings. On March 27, 2009, Duke Energy Carolinas conveyed its responsive views to FERC Staff. This investigation could result in penalties being assessed.

Overview. U.S. Franchised Electric and Gas is engaged in planning efforts to meet projected load growth in its service territories. Capacity additions may include new nuclear, integrated gasification combined cycle (IGCC), coal facilities or gas-fired generation units. 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.

William States Lee III Nuclear Station. On December 12, 2007, Duke Energy Carolinas filed an application with the Nuclear Regulatory Commission (NRC), which has been docketed for review, for a combined Construction and Operating License (COL) for two Westinghouse AP1000 (advanced passive) reactors for the proposed William States Lee III Nuclear Station at a site in Cherokee County, South Carolina. Each reactor is capable of producing approximately 1,117 MW. Submitting the COL application does not commit Duke Energy Carolinas to build nuclear units. On December 7, 2007, Duke Energy Carolinas filed applications with the NCUC and the PSCSC for approval of Duke Energy Carolinas’ decision to incur development costs associated with the proposed William States Lee III Nuclear Station. The NCUC had previously approved Duke Energy’s decision to incur the North Carolina allocable share of up to $125 million in development costs through 2007. The 2007 requests cover a total of up to $230 million in development costs through 2009, which is comprised of $70 million incurred through December 31, 2007 plus an additional $160 million of anticipated costs in 2008 and 2009. The PSCSC approved Duke Energy Carolinas’ William States Lee III Nuclear project development cost application on June 9, 2008, and the NCUC issued its approval order on June 11, 2008. On July 24, 2008, environmental intervenors filed motions to rescind or amend the approval orders issued by the NCUC and the PSCSC, and Duke Energy Carolinas subsequently filed responses in opposition to the motions. On August 13 and August 25, 2008, the PSCSC and NCUC, respectively, denied the environmental intervenor motion. The NRC review of the COL application continues and the estimated receipt of the COL is in mid 2013. Duke Energy Carolinas filed with the Department of Energy (DOE) for a federal loan guarantee, which has the potential to significantly lower financing costs associated with the proposed William States Lee III Nuclear Station; however, it was not among the four projects selected by the DOE for the final phase of due diligence for the federal loan guarantee program. The project could be selected in the future if the program funding is expanded or if any of the current finalists drop out of the program.

South Carolina passed new energy legislation (S 431) which became effective May 3, 2007. The legislation includes provisions to provide assurance of cost recovery related to a utility’s incurrence of project development costs associated with nuclear baseload generation, cost recovery assurance for construction costs associated with nuclear or coal baseload generation, and the ability to recover financing costs for new nuclear baseload generation in rates during construction through a rider. The North Carolina General Assembly also passed comprehensive energy legislation North Carolina Senate Bill 3 (SB 3) in July 2007 that was signed into law by the Governor on August 20, 2007. Like the South Carolina legislation, the North Carolina legislation provides cost recovery assurance, subject to prudency review, for nuclear project development costs as well as baseload generation construction costs. A utility may include financing costs related to construction work in progress for baseload plants in a rate case.

Cliffside Unit 6. On June 2, 2006, Duke Energy Carolinas filed an application with the NCUC for a CPCN to construct two 800 MW state of the art coal generation units at its existing Cliffside Steam Station in North Carolina. On March 21, 2007, the NCUC issued an Order allowing Duke Energy Carolinas to build one 800 MW unit. On February 20, 2008, Duke Energy Carolinas entered into an amended and restated engineering, procurement, construction and commissioning services agreement, valued at approximately $1.3 billion, with an affiliate of The Shaw Group, Inc., of which approximately $950 million relates to participation in the construction of Cliffside Unit 6, with the remainder related to a flue gas desulfurization system on an existing unit at Cliffside. On February 27, 2009, Duke Energy Carolinas filed its latest updated cost estimate of $1.8 billion (excluding up to approximately $0.6 billion of AFUDC) for the approved new Cliffside Unit 6. Duke Energy Carolinas believes that the overall cost of Cliffside Unit 6 will be reduced by approximately $125 million in federal advanced clean coal tax credits, as discussed further below.

On January 29, 2008, the North Carolina Department of Environment and Natural Resources (DENR) issued a final air permit for the new Cliffside Unit 6 and on-site construction has begun. In March 2008, four contested case petitions, which have since been consolidated, were filed appealing the final air permit. On May 12, 2009, the Administrative Law Judge issued rulings favorable to DENR and Duke Energy, dismissing several of petitioners’ claims and granting summary judgment against petitioners on other claims, resulting in the dismissal of two petitions and leaving two for hearing. A hearing on remaining claims is scheduled for June 2010. See Note 16 for a discussion of a lawsuit filed by the Southern Alliance for Clean Energy, Environmental Defense Fund, National Parks Conservation Association, Natural Resources Defenses Council, and Sierra Club (collectively referred to as Citizen Groups) related to the construction of Cliffside Unit 6.

On October 14, 2008, Duke Energy Carolinas submitted revised hazardous air pollutant (HAPs) emissions determination documentation including revised emission source information to the Division of Air Quality (DAQ) indicating that no maximum achievable control technology (MACT) or MACT-like requirements apply since Cliffside Unit 6 has been demonstrated to be a minor source of HAPs.

After issuing a draft permit and holding public hearings on that draft permit in January 2009, the DAQ issued the revised permit on March 13, 2009, finding that Cliffside Unit 6 is a minor source of HAPs and imposing operating conditions to assure that emissions stay

below the major source threshold. In May 2009, four contested case petitions were filed appealing the March 13, 2009 final air permit. These four cases have been consolidated with each other and with the four consolidated cases filed in 2008, resulting in the dismissal of two of the four cases. The same schedule will govern these cases with a hearing scheduled for June 2010.

Dan River and Buck Combined Cycle Facilities. On June 29, 2007, Duke Energy Carolinas filed with the NCUC preliminary CPCN information to construct a 620 MW combined cycle natural gas-fired generating facility at its existing Dan River Steam Station, as well as updated preliminary CPCN information to construct a 620 MW combined cycle natural gas-fired generating facility at its existing Buck Steam Station. On December 14, 2007, Duke Energy Carolinas filed CPCN applications for the two combined cycle facilities. The NCUC consolidated its consideration of the two CPCN applications and held an evidentiary hearing on the applications on March 11, 2008. The NCUC issued its order approving the CPCN applications for the Buck and Dan River combined cycle projects on June 5, 2008. On May 5, 2008, Duke Energy Carolinas entered into an engineering, construction and commissioning services agreement for the Buck combined cycle project, valued at approximately $275 million, with Shaw North Carolina, Inc. On November 5, 2008, Duke Energy Carolinas notified the NCUC that since the issuance of the CPCN Order, recent economic factors have caused increased uncertainty with regard to forecasted load and near-term capital expenditures, resulting in a modification of the construction schedule. On September 1, 2009, Duke Energy Carolinas filed with the NCUC further information clarifying the construction schedule for the two projects. Under the revised schedule, the Buck Project is expected to begin operation in combined cycle mode by the end of 2011, but without a phased-in simple cycle commercial operation. The Dan River Project is expected to begin operation in combined cycle mode by the end of 2012, also without a phased-in simple cycle commercial operation. On December 21, 2009, Duke Energy Carolinas entered into a First Amended and Restated engineering, construction and commissioning services agreement with Shaw North Carolina, Inc. for $322 million which reflects the revised schedule. Based on the most updated cost estimates, total costs (including AFUDC) for the Buck and Dan River projects are approximately $660 million and $710 million, respectively.

On October 15, 2008, the DAQ issued a final air permit authorizing construction of the Buck combined cycle natural gas-fired generating units, and on August 24, 2009, the DAQ issued a final air permit authorizing construction of the Dan River combined cycle natural gas-fired generation units.

Edwardsport Integrated Gasification Combined Cycle (IGCC) Plant. On September 7, 2006, Duke Energy Indiana and Southern Indiana Gas and Electric Company d/b/a Vectren Energy Delivery of Indiana (Vectren) filed a joint petition with the IURC seeking a CPCN for the construction of a 630 MW IGCC power plant at Duke Energy Indiana’s Edwardsport Generating Station in Knox County, Indiana. The facility was initially estimated to cost approximately $2 billion (including approximately $120 million of AFUDC). In August 2007, Vectren formally withdrew its participation in the IGCC plant and a hearing was conducted on the CPCN petition based on Duke Energy Indiana owning 100% of the project. On November 20, 2007, the IURC issued an order granting Duke Energy Indiana a CPCN for the proposed IGCC project, approved the cost estimate of $1.985 billion and approved the timely recovery of costs related to the project. On January 25, 2008, Duke Energy Indiana received the final air permit from the Indiana Department of Environmental Management. The Citizens Action Coalition of Indiana, Inc., Sierra Club, Inc., Save the Valley, Inc., and Valley Watch, Inc., all intervenors in the CPCN proceeding, have appealed the air permit.

On November 24, 2009, Duke Energy Indiana filed a petition for its fourth semi-annual IGCC rider and ongoing review proceeding with the IURC. Duke Energy has experienced design modifications and scope growth above what was anticipated from the preliminary engineering design, adding capital costs to the IGCC project. Duke Energy Indiana forecasted that the additional capital cost items would use the remaining contingency and escalation amounts in the current $2.35 billion cost estimate and add approximately $150 million, or about 6.4% to the total IGCC Project cost estimate, excluding the impact associated with the need to add more contingency. Duke Energy Indiana did not request approval of an increased cost estimate in the fourth semi-annual update proceeding; rather, Duke Energy Indiana requested, and the IURC approved, a subdocket proceeding in which Duke Energy will present additional evidence regarding an updated estimated cost for the IGCC project and in which a more comprehensive review of the IGCC project could occur. The evidentiary hearing for the fourth semi-annual update proceeding is scheduled for April 6, 2010. In the cost estimate subdocket proceeding, Duke Energy Indiana will be filing a new cost estimate for the IGCC project on April 7, 2010, with its case-in-chief testimony, and a hearing is scheduled to begin August 10, 2010. Duke Energy Indiana continues to work with its vendors to update and refine the forecasted increased cost to complete the Edwardsport IGCC project, and currently anticipates that the total cost increase it submits in the cost estimate subdocket proceeding will be significantly higher than the $150 million previously identified.

Duke Energy Indiana filed a petition with the IURC requesting approval of its plans for studying carbon storage, sequestration and/or enhanced oil recovery for the carbon dioxide (CO₂) from the Edwardsport IGCC facility on March 6, 2009. On July 7, 2009, Duke Energy Indiana filed its case-in-chief testimony requesting approval for cost recovery of a $121 million site assessment and characterization plan for CO₂ sequestration options including deep saline sequestration, depleted oil and gas sequestration and enhanced oil recovery for the CO₂ from the Edwardsport IGCC facility. The OUCC filed testimony supportive of the continuing study of carbon storage, but recommended that Duke Energy Indiana break its plan into phases, recommending approval of only approximately $33 million in expenditures at this time and deferral of expenditures rather than cost recovery through a tracking mechanism as proposed by Duke Energy Indiana. Intervenor CAC recommended against approval of the carbon storage plan stating customers should not be required to pay for research and development costs. Duke Energy Indiana’s rebuttal testimony was filed October 30, 2009, wherein it amended its request to seek deferral of approximately $42 million to cover the carbon storage site assessment and characterization activities scheduled to occur through approximately the end of 2010, with further required study expenditures subject to future IURC proceedings. An evidentiary hearing was held on November 9, 2009, and an order is expected in the first half of 2010.

Federal Advanced Clean Coal Tax Credits. Duke Energy has been awarded approximately $125 million of federal advanced clean coal tax credits associated with its construction of Cliffside Unit 6 and approximately $134 million of federal advanced clean coal tax credits associated with its construction of the Edwardsport IGCC plant. In March, 2008, two environmental groups, Appalachian Voices and the Canary Coalition, filed suit against the Federal government challenging the tax credits awarded to incentivize certain clean coal projects. Although Duke Energy was not a party to the case, the allegations center on the tax incentives provided for Duke Energy’s Cliffside and Edwardsport project. The initial complaint alleged a failure to comply with the National Environmental Policy Act. The first amended complaint, filed in August 2008, added an Endangered Species Act claim and also sought declaratory and injunctive relief against the DOE and the U.S. Department of the Treasury. In November 2008, the District Court dismissed the case. On September 23, 2009, the District Court issued an order granting plaintiffs’ motion to amend their complaint and denying, as moot, the motion for reconsideration. Plaintiffs have filed their second amended complaint. The Federal government has moved to dismiss the second amended complaint; the motion is pending.

Duke Energy Carolinas City of Orangeburg, South Carolina Wholesale Sales. On June 28, 2008, Duke Energy Carolinas filed notice with the NCUC that it intended to sell electricity to the City of Orangeburg, South Carolina (City of Orangeburg), a wholesale customer, at native load priority. Duke Energy Carolinas and the City of Orangeburg also filed a joint petition asking the NCUC to declare that the City of Orangeburg contract and all future Duke Energy Carolinas native load priority wholesale contracts will be treated for ratemaking and reporting purposes in the same manner as such existing wholesale contracts (i.e., revenues from those contracts will be allocated to wholesale jurisdiction and costs will be allocated to wholesale jurisdiction based on system average costs). On March 30, 2009, the NCUC issued its Order in which it concluded that Duke Energy Carolinas can proceed with the City of Orangeburg contract at its own risk; however, Duke Energy Carolinas cannot treat the City of Orangeburg’s load as Duke Energy Carolinas’ native load for rate setting purposes. Further, the NCUC concluded that based on the evidence presented, a future Commission should allocate costs based upon incremental costs in any future ratemaking case. The NCUC distinguished the City of Orangeburg from wholesale customers that have been historically served by Duke Energy Carolinas because the City of Orangeburg has not shared in the costs of Duke Energy Carolinas’ existing system. Due to the NCUC ruling, Duke Energy Carolinas terminated the system average contract with the City of Orangeburg in April 2009 per the allowed contractual provisions. The City of Orangeburg then terminated its contingency contract with Duke Energy Carolinas at incremental pricing and informed Duke Energy Carolinas that it would take service from South Carolina Electric and Gas Company via a newly executed agreement through the end of 2010. On April 29, 2009, Duke Energy Carolinas and the City of Orangeburg filed a Notice of Appeal with the North Carolina Court of Appeals and briefs were filed with the Court of Appeals on December 16, 2009. The City of Fayetteville and ElectriCities filed briefs in support of Duke Energy Carolinas’ and City of Orangeburg’s positions. Briefs for the appellees are due on February 17, 2010. Additionally, on July 2, 2009, the City of Orangeburg filed a Petition for Declaratory Order with the FERC seeking relief from the NCUC Order on various grounds, including violation of the Public Utility Regulatory Policies Act voluntary coordination provisions and federal preemption. The NCUC, the Public Staff and the Attorney General, Progress Energy, the National Association of Regulatory Utility Commissioners, Occidental Power Marketing and the North Carolina Waste Awareness Network (WARN) have intervened in opposition to the Petition. The City of Fayetteville and ElectriCities have intervened in favor of Orangeburg’s position, as has the American Public Power Association. Duke Energy Carolinas and NC Electric Membership Cooperative have also intervened, but expressed no position on the Petition.

Duke Energy Carolinas Wholesale Sales. On September 3, 2009, Duke Energy Carolinas filed advance notice of its intent to serve Central Electric Power Cooperative, Inc. as an additional wholesale customer at native load priority and at system average cost. The load to be served consists of load historically served by Duke Energy Carolinas until recently. On September 11, 2009, the Public Staff filed its response to the advance notice, indicating that it did not object to the advance notice filing and further indicating that it was unlikely that the Public Staff would in a future rate proceeding recommend that costs associated with the Central Electric Power cooperative, Inc. contract be allocated on anything other than system average cost. On October 5, 2009, the WARN filed a petition to intervene in the proceeding arguing that the extension of Duke Energy Carolinas’ service area through wholesale sales is not in the best interests of Duke Energy Carolinas’ customers. On November 10, 2009, the NCUC issued an order rejecting WARN’s objection and permitting Duke Energy Carolinas to proceed with the proposed agreement.

Duke Energy Carolinas has also filed advance notices of its intent to serve additional wholesale customers; namely, the City of Greenwood, South Carolina, and Haywood Electric Membership Corp., at native load priority. Given that these wholesale customers were historically served by Duke Energy Carolinas for a portion of their load, Duke Energy Carolinas will seek to distinguish these contracts from the Orangeburg decision. On July 20, 2009, the NCUC issued an order concluding that Duke Energy Carolinas can proceed with the Greenwood purchased power agreement and that Greenwood’s load may be treated the same as retail native load.

Duke Energy Indiana SmartGrid and Distributed Renewable Generation Demonstration Project. Duke Energy Indiana filed a petition and case-in-chief testimony supporting its request to build an intelligent distribution grid in Indiana. The proposal requests approval of distribution formula rates or, in the alternative, a SmartGrid Rider to recover the return on and of the capital costs of the build-out and the recovery of incremental operating and maintenance expenses and lost revenues. The petition also includes a pilot program for the installation of small solar photovoltaic and wind generation on customer sites, for approximately $10 million over a three-year period. Duke Energy Indiana filed supplemental testimony in January 2009 to reflect the impacts of new favorable tax treatment on the cost/benefit analysis for SmartGrid. The intervenors filed testimony generally supporting SmartGrid, but claimed that Duke Energy Indiana’s plan was too fast and too large, with not enough customer benefits in terms of time differentiated rate options and behind-the-meter energy management systems. The intervenors also opposed the distribution formula rate and the rider request claiming that costs should be recovered in a base rate case, or possibly deferred. Duke Energy Indiana filed rebuttal testimony agreeing to slow its deployment, and agreeing to work with the parties collaboratively to design time differentiated rate and energy management system pilots. On June 4, 2009, Duke Energy Indiana filed with the IURC a settlement agreement with the OUCC, the CAC, Nucor Corporation, and the Duke Energy Indiana Industrial Group which provided for a full deployment of Duke Energy Indiana’s SmartGrid initiative at a slower pace, including cost recovery through a tracking mechanism. The settlement also included increased reporting and monitoring requirements, approval of Duke Energy Indiana’s renewable distributed generation pilot and the creation of a collaborative design to initiate several time differentiated pricing pilots, an electric vehicle pilot and a home area network pilot. Additionally, the settlement agreement provided for tracker recovery of the costs associated with the SmartGrid initiative, subject to cost recovery caps and a termination date for the tracker. The tracker will also include a reduction in costs associated with the adoption of a new depreciation study. An evidentiary hearing was held on June 29, 2009. On November 4, 2009, the IURC issued an order that rejected the settlement agreement as incomplete and not in the public interest. The IURC cited the lack of defined benefits of the programs and encouraged the parties to continue the collaborative process outlined in the settlement or to consider smaller

scale pilots or phased-in options. The IURC required the parties to present a procedural schedule within 10 days to address the underlying relief requested in the cause, and to supplement the record to address issues regarding the American Recovery and Reinvestment Act funding recently awarded by the DOE. Duke Energy Indiana is considering its next steps, including a review of the implications of this Order on the American Recovery and Reinvestment Act SmartGrid Investment Grant award from the DOE. A technical conference was held at the IURC on December 1, 2009, wherein a procedural schedule was established for the IURC’s continuing review of Duke Energy Indiana’s SmartGrid proposal. Duke Energy Indiana is currently scheduled to file supplemental testimony in support of a revised SmartGrid proposal by April 1, 2010, with an evidentiary hearing scheduled for May 5, 2010.

Duke Energy Ohio SmartGrid. Duke Energy Ohio filed an application on June 30, 2009, to establish rates for return of its SmartGrid net costs incurred for gas and electric distribution service through the end of 2008. The rider for recovering electric SmartGrid costs was approved by the PUCO in its order approving the ESP, as discussed above. Duke Energy Ohio proposed its gas SmartGrid rider as part of its most recent gas distribution rate case. The PUCO Staff has completed its audit and filed its comments. The PUCO Staff and intervenors, the OCC and Kroger Company, filed comments on October 8, 2009. The OCC and Duke Energy Ohio filed reply comments on October 15, 2009. A Stipulation and Recommendation was entered into by Duke Energy Ohio, Staff of the PUCO, Kroger Company, and Ohio Partners for Affordable Energy, which provides for a revenue increase of approximately $4.2 million under the electric rider and $590,000 under the natural gas rider. The OCC did not oppose the Stipulation and Recommendation. A hearing on the Stipulation and Recommendation occurred on November 20, 2009. Approval of the Stipulation and Recommendation is expected in the first quarter of 2010.

As discussed in Note 1, effective December 17, 2008, Commercial Power reapplied regulatory accounting treatment to certain portions of its operations due to the passing of SB 221 and the PUCO’s approval of the ESP. Commercial Power may be impacted by certain of the regulatory matters discussed above, including the Duke Energy Ohio electric rate filings.

Pioneer Transmission LLC Joint Venture. On August 8, 2008, Duke Energy announced the formation of a 50-50 joint venture, called Pioneer Transmission, LLC (Pioneer Transmission), with American Electric Power Company, Inc. (AEP) to build and operate 240 miles of extra-high-voltage 765 KV transmission lines and related facilities in Indiana. Pioneer Transmission will be regulated by the FERC and the IURC. Both Duke Energy and AEP own an equal interest in the joint venture and will share equally in the project costs, which are currently estimated at approximately $1 billion, of which approximately $500 million is anticipated to be financed by Pioneer Transmission and the remaining amount split equally between Duke Energy and AEP. The joint venture will operate in Indiana as a transmission utility. The earliest possible in-service date for the project is in 2015. On March 27, 2009, the FERC issued an order granting favorable rate treatment for the project, including requested rate incentives. As is customary in formula rate cases, the FERC set the formula rate that transmission customers would pay for hearing and settlement procedures to address various challenges by intervenors to the inputs and calculations underlying the formula rate. These rate issues were resolved by a settlement which was approved by the FERC on October 26, 2009. Duke Energy continues to work with MISO and PJM to obtain the necessary approvals to be included in their respective transmission expansion plans.

Duke Energy Carolinas, along with North Carolina Municipal Power Agency Number 1, North Carolina Electric Membership Corporation and Piedmont Municipal Power Agency, have joint ownership of Catawba Nuclear Station, which is a facility operated by Duke Energy Carolinas. As discussed in Note 3, in September 2008, Duke Energy paid approximately $150 million for an additional approximate 7% ownership interest in the Catawba Nuclear Station.

Duke Energy Ohio, Columbus Southern Power Company, and Dayton Power & Light jointly own electric generating units and related transmission facilities in Ohio. Duke Energy Kentucky and Dayton Power & Light jointly own an electric generating unit. Duke Energy Ohio and Wabash Valley Power Association, Inc. (WVPA) jointly own Vermillion Station. Additionally, Duke Energy Indiana is a joint-owner of Gibson Station Unit No. 5 with WVPA and Indiana Municipal Power Agency (IMPA), as well as a joint-owner with WVPA and IMPA of certain Indiana transmission property and local facilities. These facilities constitute part of the integrated transmission and distribution systems, which are operated and maintained by Duke Energy Indiana.

Duke Energy’s share of jointly-owned plant or facilities included on the December 31, 2009 Consolidated Balance Sheet is as follows:

Duke Energy’s share of revenues and operating costs of the above jointly owned generating facilities are included within the corresponding line on the Consolidated Statements of Operations. Each participant in the jointly owned facilities must provide its own financing.

Reconciliation of Income Tax Expense at the U.S. Federal Statutory Tax Rate to the Actual Tax Expense from Continuing Operations (Statutory Rate Reconciliation)

During 2009, Duke Energy had tax benefits related to employee stock ownership plan dividends of approximately $22 million and renewable energy credits primarily related to the DEGS wind business of approximately $30 million. These benefits are reflected in the above table in Other items, net.

During 2008, Duke Energy had tax benefits related to employee stock ownership plan dividends of approximately $20 million and certain foreign restructuring of approximately $25 million. These benefits are reflected in the above table in Other items, net.

During 2007, Duke Energy had tax benefits related to employee stock ownership plan dividends of approximately $20 million and the manufacturing deduction of approximately $35 million, which is reflected in the above table in Other items, net. The manufacturing deduction was created by the American Job Creation Act of 2004 (the Act). The Act provides a deduction for income from qualified domestic production activities. The manufacturing deduction amounts to 6% on qualified production activities.

Valuation allowances have been established for certain foreign and state net operating loss carryforwards that reduce deferred tax assets to an amount that will be realized on a more-likely-than-not basis. The net change in the total valuation allowance is included in Tax differential on foreign earnings and State income tax, net of federal income tax effect in the above table.

The above amounts have been classified in the Consolidated Balance Sheets as follows:

Deferred income taxes and foreign withholding taxes have not been provided on undistributed earnings of Duke Energy’s foreign subsidiaries when such amounts are deemed to be indefinitely reinvested. The cumulative undistributed earnings as of December 31, 2009 on which Duke Energy has not provided deferred income taxes and foreign withholding taxes is approximately $949 million.

Duke Energy or its subsidiaries file income tax returns in the U.S. with federal and various state governmental authorities, and in foreign jurisdictions.

At December 31, 2009, Duke Energy had approximately $303 million of unrecognized tax benefits that, if recognized, would affect the effective tax rate or be classified as a regulatory liability. At this time, Duke Energy is unable to estimate the specific effect to either. At December 31, 2009, Duke Energy had approximately $13 million that, if recognized, would be recorded as a component of discontinued operations.

It is reasonably possible that Duke Energy will reflect an approximate $313 million reduction in unrecognized tax benefits within the next 12 months due to expected settlements.

During the years ending December 31, 2009, 2008, and 2007, Duke Energy recognized approximately $7 million of net interest expense, and approximately $2 million and $38 million of net interest income, respectively, related to income taxes. At December 31, 2009, and 2008, Duke Energy’s Consolidated Balance Sheets included approximately $21 million and $29 million, respectively, of interest receivable, which reflects all interest related to income taxes, and approximately $3 million and $2 million, respectively, related to accruals for the payment of penalties.

As of December 31, 2009 and 2008, approximately $359 million and $490 million, respectively, of federal income tax receivables were included in Other within Current Assets on the Consolidated Balance Sheets. At both December 31, 2009 and 2008, these balances exceeded 5% of Total Current Assets.

Asset retirement obligations, which represent legal obligations associated with the retirement of certain tangible long-lived assets, are computed as the present value of the projected costs for the future retirement of specific assets and are recognized in the period in which the liability is incurred, if a reasonable estimate of fair value can be made. The present value of the liability is added to the carrying amount of the associated asset in the period the liability is incurred and this additional carrying amount is depreciated over the remaining life of the asset. Subsequent to the initial recognition, the liability is adjusted for any revisions to the estimated future cash flows associated with the asset retirement obligation (with corresponding adjustments to property, plant, and equipment), which can occur due to a number of factors including, but not limited to, cost escalation, changes in technology applicable to the assets to be retired and changes in federal, state or local regulations, as well as for accretion of the liability due to the passage of time until the obligation is settled. Depreciation expense is adjusted prospectively for any increases or decreases to the carrying amount of the associated asset. The recognition of asset retirement obligations has no impact on the earnings of Duke Energy’s regulated electric operations as the effects of the recognition and subsequent accounting for an asset retirement obligation are offset by the establishment of regulatory assets and liabilities pursuant to regulatory accounting.

Asset retirement obligations recognized by Duke Energy relate primarily to the decommissioning of nuclear power facilities, obligations related to right-of-way agreements, asbestos removal and contractual leases for land use. Certain of Duke Energy’s assets have an indeterminate life, such as transmission and distribution facilities and some gas-fired power plants and thus the fair value of the retirement obligation is not reasonably estimable. A liability for these asset retirement obligations will be recorded when a fair value is determinable.

The following table presents the changes to the liability associated with asset retirement obligations during the years ended December 31, 2009 and 2008:

Duke Energy’s regulated electric and regulated natural gas operations accrue costs of removal for property that does not have an associated legal retirement obligation based on regulatory orders from the various state commissions. These costs of removal are recorded as a regulatory liability in accordance with regulatory treatment. Duke Energy does not accrue the estimated cost of removal when no legal obligation associated with retirement or removal exists for any non-regulated assets (including Duke Energy Ohio’s generation assets). The total amount of cost of removal for assets without an associated legal retirement obligation, which are included in Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets, was $2,277 million and $2,162 million as of December 31, 2009 and 2008, respectively.

Nuclear Decommissioning Costs. In 2005, the NCUC and PSCSC approved a $48 million annual amount for contributions and expense levels for decommissioning. In each of the years ended December 31, 2009, 2008 and 2007, Duke Energy expensed approximately $48 million and contributed cash of approximately $48 million to the NDTF for decommissioning costs. These amounts are presented in the Consolidated Statements of Cash Flows in Purchases of Available-For-Sale Securities within Net Cash Used in Investing Activities. The entire amount of these contributions were to the funds reserved for contaminated costs as contributions to the funds reserved for non-contaminated costs have been discontinued since the current estimates indicate existing funds to be sufficient to cover projected future costs. 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. Duke Energy believes that the decommissioning costs being recovered through rates, when coupled with expected fund earnings, will be sufficient to provide for the cost of future decommissioning.

The balance of the external NDTF, which are reflected as NDTF within Investments and Other Assets in the Consolidated Balance Sheets, was approximately $1,765 million as of December 31, 2009 and $1,436 million as of December 31, 2008. The increase in the value of the NDTF during 2009 is due to higher overall returns in the equity and debt markets. The fair value of assets legally restricted for the purpose of settling asset retirement obligations associated with nuclear decommissioning was $1,530 million as of December 31, 2009 and $1,194 million as of December 31, 2008.

As the NCUC and the PSCSC require that Duke Energy update its cost estimate for decommissioning its nuclear plants every five years, new site-specific nuclear decommissioning cost studies were completed in January 2009 that showed total estimated nuclear decommissioning costs, including the cost to decommission plant components not subject to radioactive contamination, of approximately $3 billion in 2008 dollars. This estimate includes Duke Energy’s 19.25% ownership interest in the 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, completed in 2004, estimated total nuclear decommissioning costs, including the cost to decommission plant components not subject to radioactive contamination, of approximately $2.3 billion in 2003 dollars.

Duke Energy filed these site-specific nuclear decommissioning cost studies with the NCUC and the PSCSC in conjunction with the various rate case filings. In addition to the decommissioning cost studies, a new funding study was completed and indicates the current annual funding requirement of approximately $48 million is sufficient to cover the estimated decommissioning costs. Duke Energy received an order from the NCUC on its rate case filing on December 7, 2009, and the PSCSC accepted a settlement agreement on Duke Energy’s rate case on January 20, 2010. Both the NCUC and the PSCSC approved the existing $48 million annual funding level for nuclear decommissioning costs.

The operating licenses for Duke Energy’s nuclear units are subject to extension. In December 2003, Duke Energy was granted renewed operating licenses for Catawba Nuclear Station Units 1 and 2 until 2043 and McGuire Nuclear Station Unit 1 and 2 until 2041 and 2043, respectively. In 2000, Duke Energy was granted a renewed operating license for the Oconee Nuclear Station Units 1 and 2 until 2033 and Unit 3 until 2034.

The primary risks Duke Energy manages by utilizing derivative instruments are commodity price risk and interest rate risk. Duke Energy closely monitors the risks associated with commodity price changes and changes in interest rates on its operations and, where appropriate, uses various commodity and interest rate instruments to manage these risks. Certain of these derivative instruments qualify for hedge accounting and are designated as hedging instruments, while others either do not qualify as a hedge or have not been designated as hedges by Duke Energy (hereinafter referred to as undesignated contracts). Duke Energy’s primary use of energy commodity derivatives is to hedge its generation portfolio against exposure to changes in the prices of power and fuel. Interest rate swaps are entered into to manage interest rate risk primarily associated with Duke Energy’s variable-rate and fixed-rate borrowings.

The accounting guidance for derivatives requires the recognition of all derivative instruments not identified as NPNS as either assets or liabilities at fair value in the Consolidated Balance Sheets. For derivative instruments that qualify for hedge accounting, Duke Energy may elect to designate such derivatives as either cash flow hedges or fair value hedges.

The operations of U.S. Franchised Electric and Gas business segment and certain operations of the Commercial Power business segment meet the criteria for regulatory accounting treatment. Accordingly, for derivatives designated as cash flow hedges within the regulated operations, gains and losses are reflected as a regulatory liability or asset instead of as a component of AOCI. For derivatives designated as fair value hedges or left undesignated within the regulated operations, including economic hedges associated with Commercial Power’s native load generation, gains and losses associated with the change in fair value of these derivative contracts would be deferred as a regulatory liability or asset, thus having no immediate earnings impact.

Within Duke Energy’s unregulated businesses, for derivative instruments that qualify for hedge accounting and are designated as cash flow hedges, the effective portion of the gain or loss is reported as a component of AOCI and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. Any gains or losses on the derivative that represent either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item are recognized in earnings in the current period. Duke Energy includes the gain or loss on the derivative in the same line item as the offsetting loss or gain on the hedged item in the Consolidated Statements of Operations. Additionally, Duke Energy enters into derivative agreements that are economic hedges that either do not qualify for hedge accounting or have not been designated as a hedge. The changes in fair value of these undesignated derivative instruments are reflected in current earnings.

Duke Energy is exposed to the impact of market changes in the future prices of electricity (energy, capacity and financial transmission rights), coal, natural gas and emission allowances (SO₂, seasonal NO_X and annual NO_X) as a result of its energy operations such as electric generation and the transportation and sale of natural gas. With respect to commodity price risks associated with electric generation, Duke Energy is exposed to changes including, but not limited to, the cost of the coal and natural gas used to generate electricity, the prices of electricity in wholesale markets, the cost of capacity required to purchase and sell electricity in wholesale markets and the cost of emission allowances for SO₂, seasonal NO_X and annual NO_X, primarily at Duke Energy’s coal fired power plants. Duke Energy closely monitors the risks associated with commodity price changes on its future operations and, where appropriate, uses various commodity contracts to mitigate the effect of such fluctuations on operations. Duke Energy’s exposure to commodity price risk is influenced by a number of factors, including, but not limited to, the term of the contract, the liquidity of the market and delivery location.

Commodity derivatives associated with the risk management of Duke Energy’s energy operations may be accounted for as either cash flow hedges or fair value hedges if the derivative instrument qualifies as a hedge under the accounting guidance for derivatives, or as an undesignated contract if either the derivative instrument does not qualify as a hedge or Duke Energy has elected to not designate the contract as a hedge. Additionally, Duke Energy enters into various contracts that qualify for the NPNS exception. Duke Energy primarily applies the NPNS exception to contracts within the U.S. Franchised Electric and Gas and Commercial Power business segments that relate to the physical delivery of electricity over the next 12 years.

Commodity Fair Value Hedges. At December 31, 2009, Duke Energy did not have any open commodity derivative instruments that were designated as fair value hedges.

Commodity Cash Flow Hedges. Duke Energy uses commodity instruments, such as swaps, futures, forwards and options, to protect margins for a portion of future revenues and fuel and purchased power expenses. Duke Energy generally uses commodity cash flow hedges to mitigate exposures to the price variability of the underlying commodities for, generally, a maximum period of one year.

Undesignated Contracts. Duke Energy uses derivative contracts as economic hedges to manage the market risk exposures that arise from providing electric generation and capacity to large energy customers, energy aggregators and other wholesale companies. Undesignated contracts include contracts not designated as a hedge, contracts that do not qualify for hedge accounting, derivatives that no longer qualify for the NPNS scope exception, and de-designated hedge contracts that were not re-designated as a hedge. The contracts in this category as of December 31, 2009 are primarily associated with forward power sales and coal purchases, as well as forward SO₂emission allowances, for the Commercial Power and U.S. Franchised Electric and Gas business segments. Undesignated contracts also include contracts associated with operations that Duke Energy continues to wind down or has included as discontinued operations.

In connection with the exiting of the DENA business in 2005, Duke Energy entered into a series of Total Return Swaps (TRS) with Barclays Bank PLC (Barclays), which are accounted for as mark-to-market derivatives. The TRS offsets the net fair value of the contracts being sold to Barclays. The fair value of the TRS as of December 31, 2009 is an asset of approximately $12 million, which offsets the net fair value of the underlying contracts, which is a liability of approximately $12 million. The remaining contracts covered by this TRS are with a single counterparty. Although Duke Energy has transferred the risks associated with these contracts to Barclay’s via the TRS, Duke Energy will continue to facilitate these contracts for their duration.

Duke Energy is exposed to risk resulting from changes in interest rates as a result of its issuance or anticipated issuance of variable and fixed-rate debt and commercial paper. Duke Energy manages its interest rate exposure by limiting its variable-rate exposures to a percentage of total capitalization and by monitoring the effects of market changes in interest rates. To manage risk associated with changes in interest rates, Duke Energy may enter into financial contracts, primarily interest rate swaps and U.S. Treasury lock agreements. The majority of Duke Energy’s currently outstanding derivative instruments related to interest rate risk are hedges.

Additionally, in anticipation of certain fixed-rate debt issuances, Duke Energy may execute a series of forward starting interest rate swaps to lock in components of the market interest rates at the time and terminate these derivatives prior to or upon the issuance of the corresponding debt. When these transactions occur within a business that applies regulatory accounting treatment, any pre-tax gain or loss recognized from inception to termination of the hedges may be recorded as a regulatory liability or asset and amortized as a component of interest expense over the life of the debt. Alternatively, Duke Energy may designate these derivatives as hedges. If so, any pre-tax gain or loss recognized from inception to termination of the hedges is recorded in AOCI and amortized as a component of interest expense over the life of the debt.

At December 31, 2009, the total notional amount of Duke Energy’s receive fixed/pay-variable interest rate swaps (fair value hedge) was $275 million and the total notional amount of Duke Energy’s receive variable/pay-fixed interest rate swaps (cash flow hedge) was $91 million.

The following table shows information relating to the volume of Duke Energy’s derivative activity outstanding as of December 31, 2009. Amounts disclosed represent the notional volumes of commodities and the notional dollar amounts of debt subject to derivative contracts accounted for at fair value. For option contracts, notional amounts include only the delta-equivalent volumes which represent the notional volumes times the probability of exercising the option based on current price volatility. Volumes associated with contracts qualifying for the NPNS exception have been excluded from the table below. Amounts disclosed represent the absolute value of notional amounts. Duke Energy has netted contractual amounts where offsetting purchase and sale contracts exist with identical delivery locations and times of delivery.

Underlying Notional Amounts for Derivative Instruments Accounted for At Fair Value

The following table shows fair value amounts of derivative contracts as of December 31, 2009 and the line item(s) in the Consolidated Balance Sheets in which such amounts are included. The fair values of derivative contracts are presented on a gross basis, even when the derivative instruments are subject to master netting arrangements. Cash collateral payables and receivables associated with the derivative contracts have not been netted against the fair value amounts.

Location and Fair Value Amounts of Derivatives Reflected in the Consolidated Balance Sheets

The following table shows the amount of the gains and losses recognized on derivative instruments designated and qualifying as cash flow hedges by type of derivative contract during the year ended December 31, 2009 and the financial statement line items in which such gains and losses are included.

Cash Flow Hedges – Location and Amount of Pre-Tax Losses Recognized in Comprehensive

The effective portion of gains or losses on cash flow hedges that were recognized in AOCI during the year ended December 31, 2009 was insignificant. In addition, there were no losses due to hedge ineffectiveness during the year ended December 31, 2009. No gains or losses have been excluded from the assessment of hedge effectiveness. As of December 31, 2009, an insignificant amount of pre-tax deferred net gains on derivative instruments related to commodity and interest rate cash flow hedges accumulated on the Consolidated Balance Sheets in AOCI are expected to be recognized in earnings during the next 12 months as the hedged transactions occur.

The following table shows the amount of the pre-tax gains and losses recognized on undesignated hedges by type of derivative instrument during the year ended December 31, 2009 and the line item(s) in the Consolidated Statements of Operations in which such gains and losses are included or deferred on the Consolidated Balance Sheets as regulatory assets or liabilities.

Undesignated Hedges – Location and Amount of Pre-Tax Gains and (Losses) Recognized in

Duke Energy’s industry has historically operated under negotiated credit lines for physical delivery contracts. Duke Energy frequently uses master collateral agreements to mitigate certain credit exposures, primarily related to hedging the risks inherent in its generation portfolio. The collateral agreements provide for a counterparty to post cash or letters of credit to the exposed party for exposure in excess of an established threshold. The threshold amount represents an unsecured credit limit, determined in accordance with the corporate credit policy. Collateral agreements also provide that the inability to post collateral is sufficient cause to terminate contracts and liquidate all positions.

Duke Energy also obtains cash, letters of credit or surety bonds from customers to provide credit support outside of collateral agreements, where appropriate, based on its financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each transaction.

Certain of Duke Energy’s derivative contracts contain contingent credit features, such as material adverse change clauses or payment acceleration clauses that could result in immediate payments, the posting of letters of credit or the termination of the derivative contract before maturity if specific events occur, such as a downgrade of Duke Energy’s credit rating below investment grade.

The following table shows information with respect to derivative contracts that are in a net liability position and contain objective credit-risk related payment provisions. The amounts disclosed in the table below represents the aggregate fair value amounts of such derivative instruments at the end of the reporting period, the aggregate fair value of assets that are already posted as collateral under such derivative instruments at the end of the reporting period, and the aggregate fair value of additional assets that would be required to be transferred in the event that credit-risk-related contingent features were triggered at December 31, 2009.

Information Regarding Derivative Instruments that Contain Credit-risk Related Contingent

Netting of Cash Collateral and Derivative Assets and Liabilities Under Master Netting Arrangements. Duke Energy offsets fair value amounts (or amounts that approximate fair value) recognized on its Consolidated Balance Sheets related to cash collateral amounts receivable or payable against fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting agreement. At December 31, 2009 and 2008, Duke Energy had receivables related to the right to reclaim cash collateral of approximately $112 million and $86 million, respectively, and had payables related to obligations to return cash collateral of insignificant amounts that have been offset against net derivative positions in the Consolidated Balance Sheets. Duke Energy had collateral receivables of approximately $19 million and $64 million under master netting arrangements that have not been offset against net derivative positions at December 31, 2009 and 2008, respectively. Duke Energy had insignificant cash collateral payables under master netting arrangements that have not been offset against net derivative positions at December 31, 2009 and 2008.

See Note 9 for additional information on fair value disclosures related to derivatives.

On January 1, 2008, Duke Energy adopted the new fair value disclosure requirements for financial instruments and non-financial derivatives. On January 1, 2009, Duke Energy adopted the new fair value disclosure requirements for non-financial assets and liabilities measured at fair value on a non-recurring basis. Duke Energy did not record any cumulative effect adjustment to retained earnings as a result of the adoption of the new fair value standards.

The accounting guidance for fair value defines fair value, establishes a framework for measuring fair value in GAAP in the U.S. and expands disclosure requirements about fair value measurements. Under the accounting guidance for fair value, fair value is considered to be the exchange price in an orderly transaction between market participants to sell an asset or transfer a liability at the measurement date. The fair value definition focuses on an exit price, which is the price that would be received by Duke Energy to sell an asset or paid to transfer a liability versus an entry price, which would be the price paid to acquire an asset or received to assume a liability. Although the accounting guidance for fair value does not require additional fair value measurements, it applies to other accounting pronouncements that require or permit fair value measurements.

Duke Energy classifies recurring and non-recurring fair value measurements based on the following fair value hierarchy, as prescribed by the accounting guidance for fair value, which prioritizes the inputs to valuation techniques used to measure fair value into three levels:

Level 1—unadjusted quoted prices in active markets for identical assets or liabilities that Duke Energy has the ability to access. An active market for the asset or liability is one in which transactions for the asset or liability occur with sufficient frequency and volume to provide ongoing pricing information. Duke Energy does not adjust quoted market prices on Level 1 for any blockage factor.

Level 2—a fair value measurement utilizing inputs other than a quoted market price that are observable, either directly or indirectly, for the asset or liability. Level 2 inputs include, but are not limited to, quoted prices for similar assets or liabilities in an active market, quoted prices for identical or similar assets or liabilities in markets that are not active and inputs other than quoted market prices that are observable for the asset or liability, such as interest rate curves and yield curves observable at commonly quoted intervals, volatilities, credit risk and default rates. A level 2 measurement cannot have more than an insignificant portion of the valuation based on unobservable inputs.

Level 3—any fair value measurements which include unobservable inputs for the asset or liability for more than an insignificant portion of the valuation. A level 3 measurement may be based primarily on level 2 inputs.

The fair value accounting guidance for financial instruments, which was effective for Duke Energy as of January 1, 2008, permits entities to elect to measure many financial instruments and certain other items at fair value that are not required to be accounted for at fair value under existing GAAP. Duke Energy does not currently have any financial assets or financial liabilities that are not required to be accounted for at fair value under GAAP for which it elected to use the option to record at fair value. However, in the future, Duke Energy may elect to measure certain financial instruments at fair value in accordance with this accounting guidance.

The following tables provide the fair value measurement amounts for assets and liabilities recorded on Duke Energy’s Consolidated Balance Sheets at fair value at December 31, 2009 and 2008. Derivative amounts in the table below exclude cash collateral amounts which are disclosed in Note 8.

The following table provides a reconciliation of beginning and ending balances of assets and liabilities measured at fair value on a recurring basis where the determination of fair value includes significant unobservable inputs (Level 3):

Valuation methods of the primary fair value measurements disclosed above are as follows:

Investments in equity securities: Investments in equity securities are typically valued at the closing price in the principal active market as of the last business day of the quarter. Principal active markets for equity prices include published exchanges such as NASDAQ and NYSE. Foreign equity prices are translated from their trading currency using the currency exchange rate in effect at the close of the principal active market. Duke Energy has not adjusted prices to reflect for after-hours market activity. The majority of Duke Energy’s investments in equity securities are valued using Level 1 measurements.

Investments in available-for-sale auction rate securities: At December 31, 2009 and 2008, Duke Energy has approximately $251 million par value (approximately $198 million fair value) and approximately $270 million par value (approximately $224 million fair value), respectively, of auction rate securities for which an active market does not currently exist. The majority of these auction rate securities are AAA rated student loan securities for which substantially all the values are ultimately backed by the U.S. government. All of these securities were valued as of December 31, 2009 and 2008 using measurements appropriate for Level 3 investments. The methods and significant assumptions used to determine the fair values of Duke Energy’s investment in auction rate debt securities represented a combination of broker-provided quotations and estimations of fair value using validation of such quotations through internal discounted cash flow models which incorporated primarily Duke Energy’s own assumptions as to the term over which such investments will be recovered at par, the current level of interest rates, and the appropriate risk-adjusted (for liquidity and credit) discount rates when relevant observable inputs are

not available to determine present value of such cash flows. In preparing the valuations, all significant value drivers were considered, including the underlying collateral.

See Note 10 for a discussion of other-than-temporary impairments associated with investments in auction rate debt securities during the year ended December 31, 2008.

Investments in debt securities: Most debt investments are valued based on a calculation using interest rate curves and credit spreads applied to the terms of the debt instrument (maturity and coupon interest rate) and consider the counterparty credit rating. Most debt valuations are Level 2 measures. If the market for a particular fixed income security is relatively inactive or illiquid, the measurement is a Level 3 measurement. U.S. Treasury debt is typically a Level 1 measurement.

Commodity derivatives: The pricing for commodity derivatives is primarily a calculated value which incorporates the forward price and is adjusted for liquidity (bid-ask spread), credit or non-performance risk (after reflecting credit enhancements such as collateral) and discounted to present value. The primary difference between a Level 2 and a Level 3 measurement has to do with the level of activity in forward markets for the commodity. If the market is relatively inactive, the measurement is deemed to be a Level 3 measurement. Some commodity derivatives are New York Mercantile Exchange (NYMEX) contracts, which Duke Energy classifies as Level 1 measurements.

Additional fair value disclosures. The fair value of financial instruments, excluding financial assets and certain financial liabilities included in the scope of the accounting guidance for fair value measurements disclosed in the tables above, is summarized in the following table. Judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates determined as of December 31, 2009 and 2008 are not necessarily indicative of the amounts Duke Energy could have realized in current markets.

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

See Note 11 for a discussion of non-recurring fair value measurements related to goodwill and other long-lived assets for which impairment charges were recorded during the third quarter of 2009.

See Note 20 for disclosure of fair value measurements for investments that support Duke Energy’s qualified, non-qualified and other post-retirement benefit plans.

Duke Energy classifies its investments in debt and equity securities into two categories – trading and available-for-sale. Investments in debt and equity securities held in grantor trusts associated with certain deferred compensation plans are classified as trading securities and are reported at fair value in the Consolidated Balance Sheets with net realized and unrealized gains and losses included in earnings each period. All other investments in debt and equity securities are classified as available-for-sale securities, which are also reported at fair value on the Consolidated Balance Sheets with unrealized gains and losses excluded from earnings and reported either as a regulatory asset or liability, as discussed further below, or as a component of other comprehensive income until realized.

Duke Energy’s available-for-sale securities are primarily comprised of investments held in the NDTF, investments in a grantor trust at Duke Energy Indiana related to other post-retirement benefit plans as required by the IURC, the captive insurance investment portfolio and investments in auction rate debt securities. The investments within the NDTF and Duke Energy Indiana’s grantor trust are managed by independent investment managers with discretion to buy, sell and invest pursuant to the objectives set forth by the trust agreements. Therefore, Duke Energy has limited oversight of the day-to-day management of these investments. Since day-to-day investment decisions, including buy and sell decisions, are made by the investment manager, the ability to hold investments in unrealized loss positions is outside the control of Duke Energy. Accordingly, all unrealized losses associated with equity securities within the NDTF and Duke Energy Indiana’s grantor trust are considered other-than-temporary and are recognized immediately when the fair value of individual investments is less than the cost basis of the investment. Pursuant to regulatory accounting, substantially all unrealized losses associated with investments in debt and equity securities within the NDTF and Duke Energy Indiana’s grantor trust are deferred as a regulatory asset, thus there is no immediate impact on the earnings of Duke Energy as a result of any other-than-temporary impairments that would otherwise be required to be recognized in earnings. For investments in debt and equity securities held in the captive insurance portfolio and investments in auction rate debt securities, unrealized gains and losses are included in other comprehensive income until realized, unless it is determined that the carrying value of an investment is other-than-temporarily impaired, at which time the write-down to fair value may be included in earnings based on the criteria discussed below.

For available-for-sale securities outside of the NDTF and Duke Energy Indiana grantor trust, which are discussed separately above, Duke Energy analyzes all investment holdings each reporting period to determine whether a decline in fair value should be considered other-than-temporary. Criteria used to evaluate whether an impairment associated with equity securities is other-than-temporary includes, but is not limited to, the length of time over which the market value has been lower than the cost basis of the investment, the percentage decline compared to the cost of the investment and management’s intent and ability to retain its investment in the issuer for a period of time sufficient

to allow for any anticipated recovery in market value. If a decline in fair value is determined to be other-than-temporary, the investment is written down to its fair value through a charge to earnings.

With respect to investments in debt securities, during the first quarter of 2009, Duke Energy adopted the modified other-than-temporary impairment accounting guidance issued by the FASB, which changed the other-than-temporary impairment guidance related to investments in debt securities. Under this modified other-than-temporary impairment guidance, if the entity does not have an intent to sell the security and it is not more likely than not that management will be required to sell the debt security before the recovery of its cost basis, the impairment write-down to fair value would be recorded as a component of other comprehensive income, except for when it is determined that a credit loss exists. In determining whether a credit loss exists, management considers, among other things, the length of time and the extent to which the fair value has been less than the amortized cost basis, changes in the financial condition of the issuer of the security, or in the case of an asset backed security, the financial condition of the underlying loan obligors, consideration of underlying collateral and guarantees of amounts by government entities, ability of the issuer of the security to make scheduled interest or principal payments and any changes to the rating of the security by rating agencies. If it is determined that a credit loss exists, the amount of impairment write-down to fair value would be split between the credit loss, which would be recognized in earnings, and the amount attributable to all other factors, which would be recognized in other comprehensive income. The adoption of the modified other-than-temporary impairment guidance primarily impacts Duke Energy’s investments in auction rate debt securities and the investments held in the captive insurance portfolio since, as discussed above, the debt securities held in the NDTF and Duke Energy Indiana’s grantor trust receive regulatory deferral treatment of all unrealized losses including other-than-temporary impairments. Since management believes, based on consideration of the criteria above, that no credit loss exists as of December 31, 2009 and management does not have the intent to sell its investments in auction rate debt securities and the investments in debt securities within its captive insurance portfolio, and it is not more likely than not that management will be required to sell these securities before the anticipated recovery of their cost basis, management concluded that there were no other-than-temporary impairments necessary as of December 31, 2009. Accordingly, all changes in the market value of investments in auction rate debt securities and captive insurance investments were reflected as a component of other comprehensive income in 2009. However, during the year ended December 31, 2008, Duke Energy recorded a pre-tax impairment charge to earnings of approximately $13 million related to the credit risk of certain investments including auction rate debt securities. The remaining changes in fair value of investments in auction rate debt securities and captive insurance investments in 2008 were considered temporary and were reflected as a component of other comprehensive income. See Note 9 for additional information related to fair value measurements for investments in auction rate debt securities that were not part of its NDTF or captive insurance portfolio.

Management will continue to monitor the carrying value of its entire portfolio of investments in the future to determine if any additional other-than-temporary impairment losses should be recorded.

Investments in debt and equity securities are classified as either short-term investments or long-term investments based on management’s intent and ability to sell these securities, taking into consideration illiquidity factors in the current markets with respect to certain short-term investments that have historically provided for a high degree of liquidity, such as investments in auction rate debt securities.

Short-term investments. At December 31, 2008, Duke Energy had approximately $51 million carrying value (approximately $55 million par value) of short-term investments. The balance at December 31, 2008 consisted of investments in auction rate debt securities that either had a stated maturity within the next 12 months or Duke Energy believed the investments were reasonably expected to be refunded within the next 12 months based on notification of a refunding plan by the issuer. At December 31, 2008, management believed that approximately $49 million par value of investments in auction rate debt securities were reasonably expected to be refunded within the next 12 months based on notification of refunding by the issuer. However, due to an ongoing delay in that refunding plan, Duke Energy reclassified these securities to long-term investments in the second quarter of 2009. Duke Energy continues to hold these securities at December 31, 2009. The remaining balance of investments in auction rate debt securities at December 31, 2008 were included in long-term investments and are discussed below. During the year ended December 31, 2009 there were no purchases or sales of short-term investments. During the years ended December 31, 2008 and 2007, Duke Energy purchased short-term investments of approximately $4,277 million and $21,661 million, respectively. During the years ended December 31, 2008 and 2007, Duke Energy received proceeds on sales of approximately $4,424 million and $22,685 million, respectively.

Long-term investments. Duke Energy classifies its investments in debt and equity securities held in the NDTF (see Note 7 for further information), in the Duke Energy Indiana grantor trust and the captive insurance investment portfolio as long-term. Additionally, approximately $198 million carrying value (approximately $251 million par value) and approximately $173 million carrying value (approximately $215 million par value) of investments in auction rate debt securities have been classified as long-term at December 31, 2009 and 2008, respectively, due to market illiquidity factors as a result of continued failed auctions. All of these investments are classified as available-for-sale and, therefore, are reflected on the Consolidated Balance Sheets at estimated fair value based on either quoted market prices or management’s best estimate of fair value based on expected future cash flow using appropriate risk-adjusted discount rates. Since management does not intend to use these investments in current operations, these investments are classified as long-term. At December 31, 2009 and 2008, Duke Energy’s long-term available-for-sale investments had a fair market value of $2,254 million and $1,855 million, respectively.

The cost of securities sold is determined using the specific identification method. During the years ended December 31, 2009, 2008 and 2007, Duke Energy purchased long-term investments of approximately $3,013 million, $3,076 million and $1,978 million, respectively, and received proceeds on sales of approximately $2,988 million $3,030 million and $1,928 million, respectively. The majority of these purchases and sales relate to activity within the NDTF, including annual contributions to the NDTF of approximately $48 million pursuant to an order by the NCUC (see Note 7).

The estimated fair values of short-term and long-term investments classified as available-for-sale are as follows (in millions):

For the years ended December 31, 2009, 2008, and 2007, a pre-tax gain of approximately $7 million, a pre-tax loss of approximately $1 million, and a pre-tax gain of less than $1 million, respectively, were reclassified out of AOCI into earnings.

Debt securities held at December 31, 2009, which includes auction rate securities based on the stated maturity date, mature as follows: $44 million in less than one year, $173 million in one to five years, $156 million in six to 10 years and $657 million thereafter.

The fair values and gross unrealized losses of available-for-sale debt and equity securities which are in an unrealized loss position for which other-than-temporary impairment losses have not been recorded, summarized by investment type and length of time that the securities have been in a continuous loss position, are presented in the table below as of December 31, 2009 and 2008.

Goodwill. The following table shows goodwill by business segment at December 31, 2009 and 2008:

Duke Energy is required to perform an annual goodwill impairment test as of the same date each year and, accordingly, performs its annual impairment testing of goodwill as of August 31. Duke Energy updates the test between annual tests if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value. The annual analysis of the potential impairment of goodwill requires a two step process. Step one of the impairment test involves comparing the fair values of reporting units with their aggregate carrying values, including goodwill. If the carrying amount of a reporting unit exceeds the reporting unit’s fair value, step two must be performed to determine the amount, if any, of the goodwill impairment loss. If the carrying amount is less than fair value, further testing of goodwill impairment is not performed.

For purposes of the step one analyses, determination of reporting units’ fair value was based on a combination of the income approach, which estimates the fair value of Duke Energy’s reporting units based on discounted future cash flows, and the market approach, which estimates the fair value of Duke Energy’s reporting units based on market comparables within the utility and energy industries. Based on completion of step one of the annual impairment analysis, management determined that the fair values of all reporting units except for Commercial Power’s non-regulated Midwest generation reporting unit, for which the carrying value of goodwill was approximately $890 million as of August 31, 2009, were greater than their respective carrying values. Accordingly, only Commercial Power’s non-regulated Midwest generation reporting unit required management to perform step two of the goodwill impairment test to determine the amount of the goodwill impairment.

Commercial Power’s non-regulated Midwest generation reporting unit includes nearly 4,000 MW of coal-fired generation capacity in Ohio dedicated to serve Ohio native load customers under the ESP through December 31, 2011. These assets, as excess capacity allows, also generate revenues through sales outside the native load customer base, and such revenue is termed non-native. Additionally, this reporting unit has approximately 3,600 MW of gas-fired generation capacity in Ohio, Pennsylvania, Illinois and Indiana. The businesses within Commercial Power’s non-regulated generation reporting unit operate in an unregulated environment in Ohio. As a result, the operations within this reporting unit are subjected to competitive pressures that do not exist in any of Duke Energy’s regulated jurisdictions.

The fair value of the non-regulated Midwest generation reporting unit is impacted by a multitude of factors, including current and forecasted customer demand, current and forecasted power and commodity prices, impact of the economy on discount rates, valuation of peer companies, competition, and regulatory and legislative developments. Management’s assumptions and views of these factors continually evolves, and such views and assumptions used in determining the step one fair value of the reporting unit in 2009 changed significantly from those used in the 2008 annual impairment test. These factors had a significant impact on the risk-adjusted discount rate and other inputs used to value the non-regulated Midwest generation reporting unit. More specifically, as of August 31, 2009, the following factors significantly impacted management’s valuation of the reporting unit that consequently resulted in an approximate $371 million non-cash goodwill impairment charge during the third quarter of 2009:

In addition to the goodwill impairment charge, and as a result of factors similar to those described above, Commercial Power recorded approximately $42 million of pre-tax impairment charges related to certain generating assets in the Midwest to write-down the value of these assets to their estimated fair value. These impairment charges are recorded in Goodwill and Other Impairment Charges on the Consolidated Statement of Operations. As management is not aware of any recent market transactions for comparable assets with sufficient transparency to develop a market approach fair value, Duke Energy relied on the income approach to estimate the fair value of the impaired assets.

The fair values of Commercial Power’s non-regulated generation reporting unit and generating assets for which impairments were recorded were determined using significant unobservable inputs (i.e., Level 3 inputs) as defined by the accounting guidance for fair value measurements.

Intangibles. The carrying amount and accumulated amortization of intangible assets as of December 31, 2009 and 2008 are as follows:

Emission allowances in the table above include emission allowances acquired by Duke Energy as part of its merger with Cinergy, which were recorded at the then fair value on the date of the merger in April 2006, and emission allowances purchased by Duke Energy. Additionally, Duke Energy is allocated certain zero cost emission allowances on an annual basis. The change in the gross carrying value of emission allowances during the years ended December 31, 2009 and 2008 are as follows:

Amortization expense for gas, coal and power contracts, wind development rights and other intangible assets for the years ended December 31, 2009, 2008 and 2007 was approximately $25 million, $27 million and $57 million, respectively.

The table below shows the expected amortization expense for the next five years for intangible assets as of December 31, 2009. The expected amortization expense includes estimates of emission allowances consumption and estimates of consumption of commodities such as gas and coal under existing contracts, as well as estimated amortization related to the wind development projects acquired from Catamount. The amortization amounts discussed below are estimates and actual amounts may differ from these estimates due to such factors as changes in consumption patterns, sales or impairments of emission allowances or other intangible assets, delays in the in-service dates of wind assets, additional intangible acquisitions and other events.

As discussed in Note 3, Duke Energy completed the acquisition of Catamount in September 2008, resulting in the recognition of approximately $117 million of intangible assets related to wind farm development rights. Of this amount, a portion of the intangible asset value was assigned to projects that Duke Energy disposed of through sale during the year ended December 31, 2009. The intangible assets recorded in connection with the Catamount acquisition primarily represent land use rights and interconnection agreements acquired by Duke Energy as part of the purchase price. Since these intangible assets relate to development projects for which commercial operations have not commenced, amortization of the intangible asset value assigned to each of these projects will not begin until commercial operation is achieved. Duke Energy will evaluate the useful lives of these intangible assets as the projects begin commercial operations, which is anticipated to be in the years 2010 through 2012. Duke Energy currently estimates the useful lives of these projects, once in commercial operation, will be the shorter of the lease term of the land or the estimated lives of the projects, which is approximately 25 years.

In connection with the merger with Cinergy in April 2006, Duke Energy recorded an intangible liability of approximately $113 million associated with the RSP in Ohio, which was recognized in earnings over the regulatory period that ended on December 31, 2008. Duke Energy also recorded approximately $56 million of intangible liabilities associated with other power sale contracts in connection with its merger with Cinergy. The carrying amount of these intangible liabilities associated with other power sale contracts was approximately $10 million and $16 million at December 31, 2009 and 2008, respectively. During the years ended December 31, 2009, 2008 and 2007, Duke Energy amortized approximately $6 million, $73 million and $45 million, respectively, to income related to these intangible liabilities. The remaining balance of approximately $10 million will be amortized to income as follows: approximately $6 million in 2010 and approximately $4 million in 2011. Intangible liabilities are classified as Other within Deferred Credits and Other Liabilities on the Consolidated Balance Sheets.

Impairment of Emission Allowances. On July 11, 2008, the U.S. Court of Appeals for the District of Columbia issued a decision vacating the Clean Air Interstate Rule (CAIR). Subsequently, in December 2008, a federal appeals court reinstated the CAIR while the EPA develops a new clean air program. See Note 16 for additional information on the CAIR. However, as a result of the July 11, 2008 decision temporarily vacating the CAIR, there were sharp declines in market prices of SO₂ and NO_x allowances in the third quarter of 2008 due to uncertainty associated with future federal requirements to reduce emissions. Accordingly, Duke Energy evaluated the carrying value of emission allowances held by its regulated and unregulated businesses for impairment during the third quarter of 2008.

At the time of its temporary repeal, the CAIR required 50% reductions in SO₂ emissions beginning in 2010 and further 30% reductions in SO₂emissions in 2015 beyond specified requirements. These reductions were to be achieved by requiring the surrender of SO₂ allowances in a ratio of two allowances per ton of SO₂ emitted beginning in 2010, up from a current one-to-one ratio, escalating to 2.86 allowances per ton of SO₂ emitted beginning in 2015. Taking into account these increases in emission allowance requirements under CAIR, Commercial Power’s forecasted SO₂emissions needed through 2037 exceeded the number of emission allowances held prior to the vacating of the CAIR. Subsequent to the temporary decision to vacate CAIR, Commercial Power determined that it had SO₂allowances in excess of forecasted emissions and those allowances held in excess of forecasted emissions from future generation required an impairment evaluation. In performing the impairment evaluation for SO₂ allowances at September 30, 2008, management compared quoted market prices for each vintage year allowance to the carrying value of the related allowances in excess of forecasted emissions through 2038. Due to the sharp decline in market prices of SO₂ allowances, as discussed above, Commercial Power recorded pre-tax impairment charges of approximately $77 million related to forecasted excess SO₂ allowances held at September 30, 2008. Additionally, Commercial Power recorded pre-tax impairment charges of approximately $5 million related to annual NO_xallowances during the third quarter of 2008 as these were also affected by the decision to vacate the CAIR. These impairment charges are recorded in Goodwill and Other Impairment Charges within Operating Expenses on the Consolidated Statements of Operations.

Additionally, U.S. Franchised Electric and Gas has emission allowances and certain commitments to purchase emission allowances that, based on management’s best estimate at September 30, 2008, resulted in a quantity of emission allowances in excess of the amounts projected to be utilized for operations. The excess emission allowances include forward contracts to purchase SO₂allowances to cover forecasted shortfalls in emission allowances necessary for operations that were entered into prior to the July 11, 2008 CAIR decision. Prior to the temporary vacating of the CAIR, these forward contracts, which primarily settled in the fourth quarter of 2008 or in 2009, qualified for the NPNS exception within the accounting rules for derivatives. However, since certain of these forward contracts would no longer be considered probable of use in the normal course of operations due to the excess over forecasted needs, in September 2008, U.S. Franchised Electric and Gas determined that these contracts no longer qualified for the NPNS exception. At the time this determination was made, the fair value of the contracts was a liability of approximately $34 million. Since U.S. Franchised Electric and Gas anticipates regulatory recovery of the cost of these emission allowances in normal course, a corresponding regulatory asset was recorded on the Consolidated Balance Sheets. These forward contracts have continued to be marked-to-market, with an offset to the regulatory asset balance, until ultimate settlement.

As a result of the reinstatement of the CAIR in December 2008, as discussed above, all emission allowances and certain commitments to purchase emission allowances held by U.S. Franchised Electric and Gas and Commercial Power are anticipated to be utilized for future emission allowance requirements under the CAIR, unless the EPA develops a new clean air program that changes the existing requirements under the CAIR.

Investments in domestic and international affiliates that are not controlled by Duke Energy, but over which it has significant influence, are accounted for using the equity method. Significant investments in affiliates accounted for under the equity method are as follows:

Commercial Power. As of December 31, 2009 and 2008, investments accounted for under the equity method primarily consist of Duke Energy’s approximate 50% ownership interest in the five Sweetwater projects (Phase I-V), which are wind power assets located in Texas that were acquired as part of the acquisition of Catamount, which is further described in Note 3.

International Energy. As of both December 31, 2009 and 2008, investments accounted for under the equity method primarily include a 25% indirect interest in NMC, which owns and operates a methanol and MTBE business in Jubail, Saudi Arabia, and a 25% indirect interest in Attiki, a natural gas distributor in Athens, Greece.

Duke Energy’s wholly-owned subsidiary, CGP Global Greece Holdings S.A. (CGP Greece) has as its only asset the 25% indirect interest in Attiki, and its only third-party liability is a debt obligation that is secured by the 25% indirect interest in Attiki. The debt obligation is also secured by Duke Energy’s indirect wholly-owned interest in CGP Greece. This debt obligation of approximately $71 million, which is reflected in Current Maturities of Long-Term Debt on Duke Energy’s Consolidated Balance Sheets, is otherwise non-recourse to Duke Energy. In December 2009, Duke Energy decided to abandon its investment in Attiki and the related non-recourse debt. The decision to abandon Attiki was made in part due to the non-strategic nature of the investment and insufficient cash flow from the investee to cover non-recourse debt obligations.

In November 2009, CGP Greece failed to make a scheduled semi-annual installment payment of principal and interest on the debt, and in January 2010 the counterparty to the debt issued a Notice of Event of Default, asserting voting rights and rights to dividends in CGP Greece and thereby its 25% indirect interest in Attiki. As of December 31, 2009, Duke Energy’s investment balance in Attiki was approximately $71 million, reflecting an approximate $18 million impairment charge recognized in the fourth quarter of 2009 to reduce the carrying amount of the investment to its estimated fair value.

Other. As of December 31, 2009 and 2008, investments accounted for under the equity method primarily include telecommunications investments. Additionally, Other includes Duke Energy’s effective 50% interest in Crescent which, as discussed further below, has a carrying value of zero.

In connection with the renegotiation of its debt agreements in June 2008, Crescent management modified its existing business strategy to focus some of its efforts on producing near-term cash flows from its non-strategic real estate projects in order to improve liquidity. As a result of its revised business strategy to accelerate certain cash flows resulting from the June 2008 amendments to its debt agreements, Crescent updated its recoverability assessments for its real estate projects as required under the accounting guidance for asset impairments. Under the accounting guidance for asset impairments, the carrying amount of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. For certain of Crescent’s non-strategic assets, it was determined that some projects’ projected undiscounted cash flows did not exceed the carrying value of the projects based on the revised business strategy assumptions, and an impairment loss was recorded equal to the amount by which the carrying amount of each impaired project exceeded its estimated fair value. The methods for determining fair value included discounted cash flow models, as well as valuing certain properties based on recent offer prices for bulk-sale transactions and other price data for similar assets. During the year ended December 31, 2008, Crescent recorded impairment charges on certain of its property holdings, primarily in its residential division, of which Duke Energy’s proportionate pre-tax share was approximately $238 million. Duke Energy’s proportionate share of these impairment charges are recorded in Equity in Earnings (Losses) of Unconsolidated Affiliates in Duke Energy’s Consolidated Statements of Operations.

As a result of the impairment charges recorded during the year ended December 31, 2008, the carrying value of Duke Energy’s investment in Crescent was reduced to zero. Accordingly, Duke Energy discontinued applying the equity method of accounting to its investment in Crescent during the year ended December 31, 2008 and did not record its proportionate share of any Crescent earnings or losses in subsequent periods.

See Note 17 for a discussion of charges recorded in 2009 related to performance guarantees issued by Duke Energy on behalf of Crescent. Crescent filed Chapter 11 petitions in a U.S. Bankruptcy Court in June 2009.

As of December 31, 2009 and 2008, the carrying amount of investments in affiliates with carrying amounts greater than zero approximated the amount of underlying equity in net assets.

Impairments. During the years ended December 31, 2009 and 2008, Duke Energy recorded pre-tax impairment charges to the carrying value of investments in unconsolidated affiliates of approximately $21 million and $9 million, respectively. Approximately $18 million of the impairment charge recorded during the year ended December 31, 2009 relates to International Energy’s investment in Attiki, as discussed above. These impairment charges, which were recorded in Losses on Sales and Impairments of Unconsolidated Affiliates on the Consolidated Statements of Operations, were recorded as a result of Duke Energy concluding that it would not be able to recover its carrying value in these investments, thus the carrying value of these investments were written down to their estimated fair value.

During the years ended December 31, 2009, 2008 and 2007, Duke Energy received distributions from equity investments of approximately $83 million, $195 million and $147 million, respectively, which are included in Other assets within Cash Flows from Operating Activities on the Consolidated Statements of Cash Flows.

Summarized Combined Financial Information of Equity Method Unconsolidated Affiliates

Other Investments. Commercial Power has an interest in South Houston Green Power, L.P. (SHGP), which is a cogeneration facility containing three combustion turbines in Texas City, Texas. Although Duke Energy owned a significant portion of SHGP, it was not consolidated as Duke Energy did not hold a majority voting control or have the ability to exercise control over SHGP, nor was Duke Energy the primary beneficiary. In the fourth quarter of 2008, Duke Energy finalized an asset swap agreement with the other joint venture owner of SHGP, which gives Duke Energy the option to receive either wind assets or a cash settlement, both of which have a value of approximately $180 million and which approximates the carrying value of Duke Energy’s investment in SHGP. The cash settlement feature will be utilized if the option to receive the wind assets is not exercised within a nine-month window following the commercialization date of the wind assets. In exchange Duke Energy would surrender its remaining interest in SHGP on the future transaction date. Duke Energy anticipates finalizing this transaction in 2010, either by receiving the wind asset or opting for the cash settlement. This transaction was considered a non-monetary exchange of productive assets with commercial substance for accounting purposes. Duke Energy does not currently expect a significant gain or loss associated with the completion of this transaction.

Effective with the finalization of the asset swap agreement in December 2008, Duke Energy turned over of the operations of SHGP to its equity partner, and Duke Energy’s 50% common equity interest in SHGP was converted to a preferred equity interest, which is considered a cost method investment. Commencing on the turnover date and continuing until either the wind asset is transferred to Duke Energy or ultimate cash settlement, Duke Energy will receive a fixed monthly payment in lieu of the economic benefit it would have otherwise received as a common equity member of SHGP. This payment is intended to compensate Duke Energy for normal distributions that it would otherwise be entitled to as an equity owner of SHGP; however, this payment is not economically linked to the actual earnings and operating results of SHGP.

Related Party Transactions. See Note 21 for information related to Duke Energy Ohio’s, Duke Energy Indiana’s and Duke Energy Kentucky’s sale of receivables to Cinergy Receivables.

Advance SC LLC, which provides funding for economic development projects, educational initiatives, and other programs, was formed during 2004. U.S. Franchised Electric and Gas made donations of approximately $11 million, $11 million and $8 million to the unconsolidated subsidiary during the years ended December 31, 2009, 2008 and 2007, respectively. Additionally, at December 31, 2009 and 2008, U.S. Franchised Electric and Gas had a trade payable to Advance SC LLC of approximately $1 million and $11 million, respectively.

In early 2008, Duke Energy began discussions with Crescent to purchase certain parcels of land in North Carolina and South Carolina that potentially have strategic value to Duke Energy’s regulated operations in those states. During the second quarter of 2008, Duke Energy had independent third party appraisals performed for each parcel of land in order to assist in the determination of a potential purchase price. In June 2008, Duke Energy acquired approximately 12,700 acres of land for a purchase price of approximately $51 million. Crescent recorded a gain on the sale. Since Duke Energy is a joint venture owner in Crescent, its proportionate share of the gain was eliminated and instead recorded as a reduction in the carrying amount of the purchased real estate.

Prior to August 2007, International Energy loaned money to Compañía de Servicios de Compresión de Campeche, S.A. de C.V. (Campeche) to assist in the costs to build. International Energy received principal and interest payments of approximately $28 million from Campeche during 2007.

Item 4-08(g) of Regulation S-X requires the presentation of summarized financial information for individual equity method investments that meet certain quantitative thresholds.

Summarized financial information for Crescent has not been presented for the year ended December 31, 2009 since, as discussed above, Duke Energy suspended applying the equity method of accounting to its investment in Crescent in the third quarter of 2008 as its investment in Crescent had been written down to zero. Accordingly, there were no amounts related to the operations of Crescent included in the Consolidated Statements of Operations for the year ended December 31, 2009. Summarized financial information for Crescent for the years ended December 31, 2008 and 2007 is as follows:

Income (loss) from discontinued operations was income of approximately $12 million and $16 million for 2009 and 2008, respectively, and a loss of approximately $22 million for 2007. Significant transactions occurring during the years ended December 31, 2008 and 2007 that resulted in discontinued operations presentation are discussed below.

In February 2008, Duke Energy entered into an agreement to sell its 480 MW natural gas-fired peaking generating station located near Brownsville, Tennessee to Tennessee Valley Authority for approximately $55 million. This transaction closed in April 2008 and resulted in Duke Energy recognizing an approximate $23 million pre-tax gain at closing.

Due to the expiration of certain tax credits, Duke Energy ceased all synthetic fuel (synfuel) operations as of December 31, 2007. Accordingly, the results of operations for synfuel were reclassified to discontinued operations. For the year ended December 31, 2007, synfuel operations had after-tax earnings of approximately $23 million, which includes tax benefits of approximately $84 million.

In February 2007, International Energy finalized the approximate $20 million sale of it 50% ownership interest in two hydroelectric power plants near Cochabamba, Bolivia to Econergy International. International Energy recorded an impairment charge in 2006 related to certain assets in Bolivia in connection with this sale. As a result of the sale, International Energy no longer has any assets in Bolivia.

As discussed in Note 1, on January 2, 2007, Duke Energy completed the spin-off of Spectra Energy, which principally consisted of Duke Energy’s former Natural Gas Transmission business segment and Duke Energy’s former 50% ownership interest in DCP Midstream, LLC (DCP Midstream), to Duke Energy shareholders. Income (Loss) From Discontinued Operations, net of tax, for the year ended December 31, 2007 includes a pre-tax amount of approximately $18 million related to costs to achieve the Spectra Energy spin-off, primarily fees to outside service providers.

Effective with the spin-off, Duke Energy and Spectra Energy entered into a Transition Services Agreement (TSA), which expired on December 31, 2007, whereby Duke Energy provided certain support services to Spectra Energy. The amount received by Duke Energy during the year ended December 31, 2007 under this TSA was approximately $15 million. Additionally, as anticipated, Duke Energy has had very limited commercial business activities with Spectra Energy subsequent to the spin-off.

Additionally, effective with the spin-off, Duke Energy and Spectra Energy entered into various reinsurance and other related agreements that allocated certain assets to Spectra Energy and DCP Midstream created under insurance coverage provided prior to the spin-off by Duke Energy’s captive insurance subsidiary and third party reinsurance companies. Under these agreements, Spectra Energy’s captive insurance subsidiary reinsured 100% of Duke Energy’s retained risk under the insurance coverage provided prior to the spin-off. Consistent with the terms of the reinsurance agreement entered into while all parties were under the common control of Duke Energy, Duke Energy paid approximately $95 million in cash to Spectra Energy’s captive insurance company, which was placed in a grantor trust to secure Spectra Energy’s obligation to Duke Energy under the Spectra Energy reinsurance agreements. This transfer is reflected in Cash distributed to Spectra Energy within Net cash provided by (used in) financing activities on the Consolidated Statements of Cash Flows. As of December 31, 2009, Duke Energy had a total liability to Spectra Energy and DCP Midstream related to these agreements of approximately $21 million, which is reflected in both Other within Current Liabilities and Other within Deferred Credits and Other Liabilities in the Consolidated Balance Sheets. This liability is offset by a corresponding receivable, of which approximately $4 million was due from Spectra Energy’s captive insurance subsidiary under the Spectra Energy reinsurance agreement and approximately $17 million was due from third party reinsurance companies. These amounts are reflected in both Other within Current Assets and Other within Investments and Other Assets in the Consolidated Balance Sheets. In the event any of the reinsurance companies deny coverage for any of the claims covered under these agreements, Duke Energy is not obligated to pay Spectra Energy or DCP Midstream. Further, Duke Energy is providing no insurance coverage to Spectra Energy or DCP Midstream for events which occur subsequent to the spin-off date.

At December 31, 2009 and 2008, Duke Energy had an approximate $50 million and $49 million receivable, respectively, from Spectra Energy related to certain income tax items.

Capitalized interest, which includes the debt component of AFUDC, amounted to approximately $102 million, $93 million and $71 million for 2009, 2008 and 2007, respectively.

Unsecured Debt. In September 2009, Duke Energy Kentucky issued $100 million of senior debentures, which carry a fixed interest rate of 4.65% and mature October 1, 2019. Proceeds from the issuance were used to repay Duke Energy Kentucky’s borrowings under Duke Energy’s master credit facility, to replenish cash used to repay $20 million principal amount of debt due September 15, 2009 and for general corporate purposes.

First Mortgage Bonds. In December 2009, Duke Energy Ohio issued $250 million principal amount of first mortgage bonds, which carry a fixed interest rate of 2.10% and mature June 15, 2013. Proceeds from this issuance, together with cash on hand, were used to repay Duke Energy Ohio’s borrowing under Duke Energy’s master credit facility. In conjunction with this debt issuance, Duke Energy Ohio entered into an interest rate swap agreement that converted interest on this debt issuance from the fixed coupon rate to a variable rate. The initial variable rate was set at 0.31%.

Other Debt. In October 2009, Duke Energy Indiana refunded $50 million of tax-exempt variable-rate demand bonds through the issuance of $50 million principal amount of tax-exempt term bonds, which carry a fixed interest rate of 4.95% and mature October 1, 2040. The tax-exempt bonds are secured by a series of Duke Energy Indiana’s first mortgage bonds.

Auction Rate Debt. As of December 31, 2009, Duke Energy had auction rate tax-exempt bonds outstanding of approximately $461 million. While these debt instruments are long-term in nature and cannot be put back to Duke Energy prior to maturity, the interest rates on these instruments are designed to reset periodically through an auction process. In February 2008, Duke Energy began to experience failed auctions for these debt instruments. When failed auctions occur on a series of this debt, Duke Energy is required to begin paying a failed-auction interest rate on the instrument. The failed-auction interest rate for the majority of the auction rate debt is 2.0 times one-month London Interbank Offered Rate (LIBOR). Payment of the failed-auction interest rates will continue until Duke Energy is able to either successfully remarket these instruments through the auction process, or refund and refinance the existing debt. While Duke Energy has plans to refund and refinance its remaining auction rate tax-exempt bonds, the timing of such refinancing activities is uncertain and subject to market conditions. If Duke Energy is unable to successfully refund and refinance these debt instruments, the impact of paying higher interest rates on the outstanding auction rate debt is not expected to materially affect Duke Energy’s overall financial position, results of operations or cash flows.

Convertible Senior Notes. In May 2003, Duke Energy issued approximately $770 million of 1.75% convertible senior notes that were convertible into Duke Energy common stock at a premium of 40% above the May 1, 2003 closing common stock market price of $16.85 per share. The conversion of these senior notes into shares of Duke Energy common stock was contingent upon the occurrence of certain events during specified periods. During 2006, Duke Energy issued shares of common stock to settle a portion of the convertible senior notes. In May 2007, pursuant to the terms of the debt agreement, substantially all of the holders of the Duke Energy convertible senior notes required Duke Energy to repurchase the then outstanding balance of approximately $110 million at a price equal to 100% of the principal amount plus accrued interest.

In connection with the spin-off of Spectra Energy on January 2, 2007 (see Note 1), Duke Energy distributed approximately 2 million shares of Spectra Energy common stock to the holders of the convertible senior notes pursuant to the antidilution provisions of the indenture

agreement, resulting in a pre-tax charge of approximately $21 million during the three months ended March 31, 2007, which is recorded in Other Income and Expenses, net in the Consolidated Statements of Operations.

Accounts Receivable Securitization. Duke Energy securitizes certain accounts receivable through Duke Energy Receivables Finance Company, LLC (DERF), a bankruptcy remote, special purpose subsidiary. DERF is a wholly-owned limited liability company with a separate legal existence from its parent, and its assets are not intended to be generally available to creditors of Duke Energy. As a result of the securitization, on a daily basis Duke Energy sells certain accounts receivable, arising from the sale of electricity and/or related services as part of Duke Energy’s franchised electric business, to DERF. In order to fund its purchases of accounts receivable, DERF has a $300 million secured credit facility with a commercial paper conduit administered by Citibank, N.A., which terminates in September 2011. The credit facility and related securitization documentation contain several covenants, including covenants with respect to the accounts receivable held by DERF, as well as a covenant requiring that the ratio of Duke Energy consolidated indebtedness to Duke Energy consolidated capitalization not exceed 65%. As of December 31, 2009 and 2008, the interest rate associated with the credit facility, which is based on commercial paper rates, was 1.6% and 3.3%, respectively, and $300 million was outstanding under the credit facility as of both December 31, 2009 and 2008. The securitization transaction was not structured to meet the criteria for sale accounting treatment under the accounting guidance for transfers and servicing of financial assets and, accordingly, is reflected as a secured borrowing in the Consolidated Balance Sheets. As of December 31, 2009 and 2008, the $300 million outstanding balance of the credit facility was secured by approximately $556 million and $518 million, respectively, of accounts receivable held by DERF. The obligations of DERF under the credit facility are non-recourse to Duke Energy. DERF meets the accounting definition of a VIE and is subject to the new accounting rules for consolidation and transfers of financial assets effective January 1, 2010; however, the new accounting rules will not result in a substantial change to the accounting for DERF. See Note 21 for further information on VIEs.

Floating Rate Debt. Unsecured debt, secured debt and other debt included approximately $2.8 billion and $3.2 billion of floating-rate debt as of December 31, 2009 and 2008, respectively, which excludes approximately $336 million and $300 million of Brazilian debt at December 31, 2009 and 2008, respectively, that is indexed annually to Brazilian inflation. Floating-rate debt is primarily based on commercial paper rates or a spread relative to an index such as LIBOR for debt denominated in U.S. dollars. As of December 31, 2009 and 2008, the average interest rate associated with floating-rate debt was approximately 1.5% and 3.2%, respectively.

Duke Energy has the ability under certain debt facilities to call and repay the obligation prior to its scheduled maturity. Therefore, the actual timing of future cash repayments could be materially different than the above as a result of Duke Energy’s ability to repay these obligations prior to their scheduled maturity.

Duke Energy may be required to repay certain debt should the credit ratings at Duke Energy Carolinas fall to a certain level at Standard & Poor’s (S&P) or Moody’s Investors Service (Moody’s). As of December 31, 2009, Duke Energy had approximately $6 million of senior unsecured notes which mature serially through 2012 that may be required to be repaid if Duke Energy Carolinas’ senior unsecured debt ratings fall below BBB- at S&P or Baa3 at Moody’s, and $16 million of senior unsecured notes which mature serially through 2016 that may be required to be repaid if Duke Energy Carolinas’ senior unsecured debt ratings fall below BBB at S&P or Baa2 at Moody’s. As of February 1, 2010, Duke Energy Carolinas’ senior unsecured credit rating was A- at S&P and A3 at Moody’s.

Available Credit Facilities. The total capacity under Duke Energy’s master credit facility, which expires in June 2012, is approximately $3.14 billion. The credit facility contains an option allowing borrowing up to the full amount of the facility on the day of initial expiration for up to one year. Duke Energy and its wholly-owned subsidiaries, Duke Energy Carolinas, Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky (collectively referred to as the borrowers), each have borrowing capacity under the master credit facility up to specified sub limits for each borrower. However, Duke Energy has the unilateral ability to increase or decrease the borrowing sub limits of each borrower, subject to per borrower maximum cap limitations, at any time. See footnote (c) to the table below for the borrowing sub limits for each of the borrowers as of December 31, 2009. The amount available under the master credit facility has been reduced by draw downs of cash and the use of the master credit facility to backstop the issuances of commercial paper, letters of credit and certain tax-exempt bonds.

In September 2008, Duke Energy and its wholly-owned subsidiaries, Duke Energy Carolinas, Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky, borrowed a total of approximately $1 billion under Duke Energy’s master credit facility. The following borrowings under Duke Energy’s master credit facility remained outstanding at December 31, 2009:

The loans under the master credit facility are revolving credit loans that currently bear interest at one-month LIBOR plus an applicable spread ranging from 19 to 23 basis points. The loan for Duke Energy has a stated maturity of June 2012, while the loans for all of the other borrowers had stated maturities of September 2009; however, the borrowers have the ability under the master credit facility to renew the loans due in September 2009 on an annual basis up through the date the master credit facility matures in June 2012. As a result of these annual renewal provisions, in September 2009, Duke Energy Ohio and Duke Energy Indiana repaid and immediately re-borrowed approximately $279 million and $123 million, respectively, under the master credit facility. Duke Energy Indiana has the intent and ability to refinance these obligations on a long-term basis, either through renewal of the terms of the loan through the master credit facility, which has non-cancelable terms in excess of one-year, or through issuance of long-term debt to replace the amounts drawn under the master credit facility. Accordingly, total borrowings by Duke Energy Indiana of $123 million are reflected as Long-Term Debt on the Consolidated Balance Sheets at both December 31, 2009 and 2008. Additionally, Duke Energy Kentucky’s borrowings of $74 million, which was repaid in 2009 through funds obtained from the issuance of long-term debt as discussed above, was included in Long-Term Debt on the Consolidated Balance Sheets at December 31, 2008. Duke Energy Ohio’s borrowing under the master credit facility was repaid in the fourth quarter of 2009, as discussed above. As Duke Energy Ohio did not have the intent to refinance its borrowings on a long-term basis, amounts outstanding at December 31, 2008 of $279 million were reflected in Notes Payable and Commercial Paper within Current Liabilities on the Consolidated Balance Sheets.

At December 31, 2009 and 2008, approximately $706 million and $779 million, respectively, of tax-exempt bonds were classified as Long-Term Debt on the Consolidated Balance Sheets. Of this amount, the master credit facility served as a backstop for approximately $385 million of these pollution control bonds (of which approximately $100 million is in the form of letters of credit), with the remaining balance backstopped by other specific long-term credit facilities separate from the master credit facility. Additionally, at both December 31, 2009 and 2008, approximately $450 million of commercial paper issuances were classified as Long-Term Debt on the Consolidated Balance Sheets. These tax-exempt bonds and commercial paper issuances, which are short-term obligations by nature, are classified as long-term due to Duke Energy’s intent and ability to utilize such borrowings as long-term financing. As Duke Energy’s master credit facility and other specific purpose credit facilities have non-cancelable terms in excess of one year as of the balance sheet date, Duke Energy has the ability to refinance these short-term obligations on a long-term basis.

Restrictive Debt Covenants. Duke Energy’s debt and credit agreements contain various financial and other covenants. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements. As of December 31, 2009, Duke Energy was in compliance with all covenants related to its significant debt agreements. In addition, some credit agreements may allow for acceleration of payments or termination of the agreements due to nonpayment, or the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the debt or credit agreements contain material adverse change clauses.

Other Loans. During 2009 and 2008, Duke Energy had loans outstanding against the cash surrender value of the life insurance policies that it owns on the lives of its executives. The amounts outstanding were $411 million as of December 31, 2009 and $384 million as of December 31, 2008. The amounts outstanding were carried as a reduction of the related cash surrender value that is included in Other within Investments and Other Assets on the Consolidated Balance Sheets.

Duke Energy carries insurance and reinsurance coverage either directly or through its captive insurance company, Bison, and its affiliates, consistent with companies engaged in similar commercial operations with similar type properties. Duke Energy’s insurance coverage includes (i) commercial general public liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from Duke Energy’s operations; (ii) workers’ compensation liability coverage to statutory limits; (iii) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage; (iv) insurance policies in support of the indemnification provisions of Duke Energy’s by-laws and (v) property insurance covering the replacement value of all real and personal property damage, excluding electric transmission and distribution lines, including damages arising from boiler and machinery breakdowns, earthquake, flood damage and extra expense. All coverage is subject to certain deductibles or retentions, sublimits, terms and conditions common for companies with similar types of operations.

In 2006, Bison was a member of sEnergy Insurance Limited (sEnergy), which provided business interruption reinsurance coverage for Duke Energy’s non-nuclear facilities. Duke Energy accounted for these memberships under the cost method, as it did not have the ability to exert significant influence over these investments. sEnergy ceased insuring events subsequent to May 15, 2006, and is currently winding down its operations and settling its outstanding claims. Bison will continue to pay additional premiums to sEnergy as it settles its outstanding claims during its wind-down; however, Duke Energy does not anticipate that the payments associated with the settlement of these outstanding claims will have a material impact on its consolidated results of operations, cash flows or financial position.

Duke Energy also maintains excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Limits, terms, conditions and deductibles are comparable to those carried by other energy companies of similar size.

The cost of Duke Energy’s general insurance coverage can fluctuate year to year reflecting the changing conditions of the insurance markets.

Duke Energy Carolinas owns and operates the McGuire and Oconee Nuclear Stations and operates and has a partial ownership interest in the Catawba Nuclear Station. The McGuire and Catawba Nuclear Stations have two nuclear reactors each and Oconee has three. Nuclear insurance includes: nuclear 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 Carolinas for certain expenses associated with nuclear insurance premiums. The Price-Anderson Act requires Duke Energy to provide for public liability claims resulting from nuclear incidents to the maximum total financial protection liability, which was approximately $12.5 billion and increased to approximately $12.6 billion effective January 1, 2010.

Primary Liability Insurance. Duke Energy has purchased the maximum reasonably available private primary liability insurance as required by law, which was $300 million and increased to $375 million effective January 1, 2010.

Excess Liability Program. This program provides approximately $12.2 billion of coverage through the Price-Anderson Act’s mandatory industry-wide excess secondary financial protection program of risk pooling. The $12.2 billion is the sum of the current potential cumulative retrospective premium assessments of $117.5 million per licensed commercial nuclear reactor. This would be increased by $117.5 million for each additional commercial nuclear reactor licensed, or reduced by $117.5 million for nuclear reactors no longer operational and may be exempted from the risk pooling program. Under this program, licensees could be assessed retrospective premiums to compensate for public liability damages in the event of a nuclear incident at any licensed facility in the U.S. If such an incident should occur and public liability damages exceed primary liability insurance, licensees may be assessed up to $117.5 million for each of their licensed reactors, payable at a rate not to exceed $17.5 million a year per licensed reactor for each incident. The assessment and rate are subject to indexing for inflation and may be subject to state premium taxes. The Price-Anderson Act provides for an inflation adjustment at least every five years with the last adjustment effective October 2008.

Duke Energy is a member of Nuclear Electric Insurance Limited (NEIL), which provides property and accidental outage insurance coverage for Duke Energy’s nuclear facilities under three policy programs:

Primary Property Insurance. This policy provides $500 million of primary property damage coverage for each of Duke Energy’s nuclear facilities.

Excess Property Insurance. This policy provides excess property, decontamination and decommissioning liability insurance: $2.25 billion for the Catawba Nuclear Station and $1.0 billion each for the Oconee and McGuire Nuclear Stations. The Oconee and McGuire Nuclear Stations also share an additional $1.0 billion insurance limit above this excess. This shared limit is not subject to reinstatement in the event of a loss.

Accidental Outage Insurance. This policy provides business interruption and/or extra expense coverage resulting from an accidental outage of a nuclear unit. Each McGuire and Catawba unit is insured for up to $3.5 million per week, and the Oconee units are insured for up to $2.8 million per week. Coverage amounts decline if more than one unit is involved in an accidental outage. Initial coverage begins after a 12-week deductible period for Catawba and a 26-week deductible period for McGuire and Oconee and continues at 100% for 52 weeks and 80% for the next 110 weeks. The McGuire and Catawba policy limit is $490 million and the Oconee policy limit is $392 million.

In the event of large industry losses, NEIL’s Board of Directors may assess Duke Energy for amounts up to 10 times its annual premiums. The current potential maximum assessments are: Primary Property Insurance—$37 million, Excess Property Insurance—$43 million and Accidental Outage Insurance—$22 million.

Pursuant to regulations of the NRC, each company’s property damage insurance policies provide that all proceeds from such insurance be applied, first, to place the plant in a safe and stable condition after a qualifying accident, and second, to decontaminate before any proceeds can be used for decommissioning, plant repair or restoration.

In the event of a loss, the amount of insurance available might not be adequate to cover property damage and other expenses incurred. Uninsured losses and other expenses, to the extent not recovered by other sources, could have a material adverse effect on Duke Energy’s results of operations, cash flows or financial position.

The maximum assessment amounts include 100% of Duke Energy’s potential obligation to NEIL for the Catawba Nuclear Station. However, the other joint owners of the Catawba Nuclear Station are obligated to assume their pro rata share of liability for retrospective premiums and other premium assessments resulting from the Price-Anderson Act’s excess secondary financial protection program of risk pooling, or the NEIL policies.

Duke Energy is subject to international, federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. These regulations can be changed from time to time, imposing new obligations on Duke Energy.

Remediation Activities. Duke Energy and its affiliates are responsible for environmental remediation at various contaminated sites. These include some properties that are part of ongoing Duke Energy operations, sites formerly owned or used by Duke Energy entities, and sites owned by third parties. Remediation typically involves management of contaminated soils and may involve groundwater remediation. Managed in conjunction with relevant federal, state and local agencies, activities vary with site conditions and locations, remedial requirements, complexity and sharing of responsibility. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, Duke Energy or its affiliates could potentially be held responsible for contamination caused by other parties. In some instances, Duke Energy may share liability associated with contamination with other potentially responsible parties, and may also benefit from insurance policies or contractual indemnities that cover some or all cleanup costs. All of these sites generally are managed in the normal course of business or affiliate operations. During 2009, Duke Energy recorded additional reserves associated with remediation activities at certain manufactured gas plant sites and it is anticipated that additional costs associated with remediation activities at certain of its sites will be incurred in the future.

Included in Other within Deferred Credits and Other Liabilities and Other within Current Liabilities on the Consolidated Balance Sheets were total accruals related to extended environmental-related activities of approximately $65 million and $55 million as of December 31, 2009 and December 31, 2008, respectively. These accruals represent Duke Energy’s provisions for costs associated with remediation activities at some of its current and former sites, as well as other relevant environmental contingent liabilities. Management, in the normal course of business, continually assesses the nature and extent of known or potential environmental-related contingencies and records liabilities when losses become probable and are reasonably estimable. Costs associated with remediation activities within Duke Energy’s regulated operations are typically expensed unless recovery of the costs is deemed probable.

Clean Water Act 316(b). The EPA finalized its cooling water intake structures rule in July 2004. The rule established aquatic protection requirements for existing facilities that withdraw 50 million gallons or more of water per day from rivers, streams, lakes, reservoirs, estuaries, oceans, or other U.S. waters for cooling purposes. Fourteen of the 23 coal and nuclear-fueled generating facilities in which Duke Energy is either a whole or partial owner are affected sources under that rule. On April 1, 2009, the U.S. Supreme Court ruled in favor of the appellants that the EPA may consider costs when determining which technology option each site should implement. Depending on how the cost-benefit analysis is incorporated into the revised EPA rule, the analysis could narrow the range of technology options required for each of the 14 affected facilities. Because of the wide range of potential outcomes, Duke Energy is unable to estimate its costs to comply at this time.

Clean Air Interstate Rule (CAIR). The EPA finalized its CAIR in May 2005. The CAIR limits total annual and summertime NO_x emissions and annual SO₂ emissions from electric generating facilities across the Eastern U.S. through a two-phased cap-and-trade program. Phase 1 began in 2009 for NO_x and begins in 2010 for SO₂. Phase 2 begins in 2015 for both NO_x and SO₂. On March 25, 2008, the U.S. Court of Appeals for the District of Columbia (D.C. Circuit) heard oral argument in a case involving multiple challenges to the CAIR. On July 11, 2008, the D.C. Circuit issued its decision in North Carolina v. EPA No. 05-1244 vacating the CAIR. The EPA filed a petition for rehearing on September 24, 2008 with the D.C. Circuit asking the court to reconsider various parts of its ruling vacating the CAIR. In December 2008, the D.C. Circuit issued a decision remanding the CAIR to the EPA without vacatur. The EPA must now conduct a new rulemaking to modify the CAIR in accordance with the court’s July 11, 2008 opinion. This decision means that the CAIR as initially finalized in 2005 remains in effect until the new EPA rule takes effect. The EPA has indicated that it currently plans on issuing a proposed rule in the April-May 2010 timeframe. It is uncertain how long the current CAIR will remain in effect or how the new rulemaking will alter the CAIR.

The emission controls Duke Energy is installing to comply with state specific clean air legislation will contribute significantly to achieving compliance with the CAIR requirements. Additionally, Duke Energy plans to spend approximately $75 million between 2010 and 2014 (approximately $65 million in Ohio and $10 million in Indiana) to comply with Phase 1 of the CAIR. Duke Energy is currently unable to estimate the costs to comply with any new rule the EPA will issue in the future as a result of the D.C. District Court’s December 2008 decision discussed above. The IURC issued an order in 2006 granting Duke Energy Indiana approximately $1.07 billion in rate recovery to cover its estimated Phase 1 compliance costs of the CAIR and the Clean Air Mercury Rule in Indiana. Duke Energy Ohio will recover most of the depreciation and financing costs related to environmental compliance projects for 2009-2011 through its ESP.

Coal Combustion Product (CCP) Management. Duke Energy currently estimates that it will spend approximately $373 million over the period 2010-2014 to install synthetic caps and liners at existing and new CCP landfills and to convert some of its CCP handling systems from wet to dry systems. The EPA and a number of states are considering additional regulatory measures that will contain specific and more detailed requirements for the management and disposal of coal combustion products, primarily ash, from Duke Energy’s coal-fired power plants. The EPA has indicated that it intends to propose a rule early in 2010. Additional laws and regulations under consideration which more stringently regulate coal ash, including the potential regulation of coal ash as hazardous waste, will likely increase costs for Duke Energy’s coal facilities. Duke Energy is unable to estimate its potential costs at this time.

New Source Review (NSR). In 1999-2000, the U.S. Department of Justice (DOJ), acting on behalf of the EPA and joined by various citizen groups and states, filed a number of complaints and notices of violation against multiple utilities across the country for alleged violations of the NSR provisions of the Clean Air Act (CAA). Generally, the government alleges that projects performed at various coal-fired units were major modifications, as defined in the CAA, and that the utilities violated the CAA when they undertook those projects without obtaining permits and installing the best available emission controls for SO₂, NO_x and particulate matter. The complaints seek injunctive relief to require installation of pollution control technology on various generating units that allegedly violated the CAA, and unspecified civil penalties in amounts of up to $32,500 per day for each violation. A number of Duke Energy’s plants have been subject to these allegations. Duke Energy asserts that there were no CAA violations because the applicable regulations do not require permitting in cases where the projects undertaken are “routine” or otherwise do not result in a net increase in emissions.

In 2000, the government brought a lawsuit against Duke Energy in the U.S. District Court in Greensboro, North Carolina. The EPA claims that 29 projects performed at 25 of Duke Energy’s coal-fired units in the Carolinas violate these NSR provisions. Three environmental groups have intervened in the case. In August 2003, the trial court issued a summary judgment opinion adopting Duke Energy’s legal positions on the standard to be used for measuring an increase in emissions, and granted judgment in favor of Duke Energy. The trial court’s decision was appealed and ultimately reversed and remanded for trial by the U.S. Supreme Court. At trial, Duke Energy will continue to assert that the projects were routine or not projected to increase emissions. No trial date has been set.

In November 1999, the U.S. brought a lawsuit in the U.S. Federal District Court for the Southern District of Indiana against Cinergy, Duke Energy Ohio, and Duke Energy Indiana alleging various violations of the CAA for various projects at six Duke Energy owned and co-owned generating stations in the Midwest. Three northeast states and two environmental groups have intervened in the case. A jury trial commenced on May 5, 2008 and jury verdict was returned on May 22, 2008. The jury found in favor of Cinergy, Duke Energy Ohio and Duke Energy Indiana on all but three units at Wabash River. Additionally, the plaintiffs had claimed that Duke Energy violated an Administrative Consent Order entered into in 1998 between the EPA and Cinergy relating to alleged violations of Ohio’s State Implementation Plan provisions governing particulate matter at Duke Energy Ohio’s W.C. Beckjord Station.

A remedy trial for violations previously established at the Wabash River and W.C. Beckjord Stations was held during the week of February 2, 2009. On May 29, 2009, the court issued its remedy ruling and ordered the following relief: (i) Wabash River Units 2, 3 and 5 to be permanently retired by September 30, 2009; (ii) surrender of SO₂ allowances equal to the emissions from Wabash River Units 2, 3 and 5 from May 22, 2008 through September 30, 2009; (iii) civil penalty in the amount of $687,500 for Beckjord violations; and (iv) installation of a particulate continuous emissions monitoring system at the W.C. Beckjord Station Units 1 and 2. The civil penalty has been paid. On September 22, 2009, defendants filed a notice of appeal with the Seventh Circuit Court of Appeals of the judgment relating to Wabash River Units 2, 3 and 5. That appeal is still pending. As of September 30, 2009, Wabash River Units 2, 3 and 5 have been retired. On October 21, 2008, Plaintiffs filed a motion for a new liability trial claiming that defendants misled the plaintiffs and the jury by, among other things, not disclosing a consulting agreement with a fact witness and by referring to that witness as “retired” during the liability trial when in fact he was working for Duke Energy under the referenced consulting agreement in connection with the trial. On December 18, 2008, the court granted plaintiffs’ motion for a new liability trial on claims for which Duke Energy was not previously found liable. That new trial commenced on May 11, 2009. On May 19, 2009, the jury announced its verdict finding in favor of Duke Energy on four of the remaining six projects at issue. The two projects in which the jury found violations were undertaken at Units 1 and 3 of the Gallagher Station in Indiana. A remedy trial on those two violations was scheduled to commence on January 25, 2010; however, the parties reached a negotiated agreement on those issues and filed a proposed consent decree with the court on December 22, 2009 for public comment and approval. The substantive terms of the proposed consent decree require: (i) conversion of Gallagher units 1 and 3 to natural gas combustion by 2013; (ii) installation of additional pollution controls at Gallagher units 2 and 4 by 2011; and (iii) additional environmental projects, payments and penalties. Duke Energy estimates that these and other actions in the settlement will cost at least $88 million. The parties anticipate that the court will approve and enter the consent decrees in due course.

On April 3, 2008, the Sierra Club filed another lawsuit in the U.S. District Court for the Southern District of Indiana against Duke Energy Indiana and certain affiliated companies alleging CAA violations at the Edwardsport power station. On June 30, 2008, defendants filed a motion to dismiss, or alternatively to stay, this litigation on jurisdictional grounds. The District Court denied that motion. The defendants subsequently filed a motion for summary judgment alleging that the applicable statute of limitations bars all of plaintiffs’ claims. Plaintiffs filed two motions for partial summary judgment requesting rulings on the applicability of certain legal standards. On January 26, 2010, the parties filed a joint motion to stay all proceedings and deadlines pending the court’s ruling on the motions for summary judgment. On February 2, 2010, the motion to stay was granted, although the trial is still set to commence on January 10, 2011.

On July 31, 2009, the EPA served a request for information under section 114 of the CAA on Duke Energy, Duke Energy Ohio and Duke Energy Business Services, Inc., requesting information pertaining to various maintenance projects and emissions and operations data relevant to the Miami Fort and W.C. Beckjord stations in Ohio. Duke Energy’s objections and responses to the EPA’s section 114 request were filed on September 28, 2009 and Duke Energy continues to provide information to the EPA.

It is not possible to estimate the damages, if any, that Duke Energy might incur in connection with the unresolved matters discussed above. Ultimate resolution of these matters relating to NSR, even in settlement, could have a material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position. However, Duke Energy will pursue appropriate regulatory treatment for any costs incurred in connection with such resolution.

Duke Energy Carolinas’ Cliffside Unit 6 Permit. On July 16, 2008, the Southern Alliance for Clean Energy, Environmental Defense Fund, National Parks Conservation Association, Natural Resources Defenses Council, and Sierra Club (collectively referred to as Citizen Groups) filed suit in federal court alleging that Duke Energy Carolinas violated the CAA when it commenced construction of Cliffside Unit 6 at Cliffside Steam Station in Rutherford County, North Carolina without obtaining a determination that the MACT emission limits will be met for all prospective hazardous air emissions at that plant. The Citizen Groups claim the right to injunctive relief against further construction at the plant as well as civil penalties in the amount of up to $32,500 per day for each alleged violation. In July 2008, Duke Energy Carolinas voluntarily performed a MACT assessment of air emission controls planned for Cliffside Unit 6 and submitted the results to the DENR. On August 8, 2008 the plaintiffs filed a motion for summary judgment. On December 2, 2008, the Court granted summary judgment in favor of the Plaintiffs and entered judgment ordering Duke Energy Carolinas to initiate a MACT process before the DAQ. The court did not order an injunction against further construction, but retained jurisdiction to monitor the MACT proceedings. On December 4, 2008, Duke Energy Carolinas submitted its MACT filing and supporting information to the DAQ specifically seeking DAQ’s concurrence as a threshold matter that construction of Cliffside Unit 6 is not a major source subject to section 112 of the CAA and submitting a MACT determination application. Concurrent with the initiation of the MACT process, Duke Energy Carolinas filed a notice of appeal to the Fourth Circuit Court of Appeals of the Court’s December 2, 2008 order to reverse the Court’s determination that Duke Energy Carolinas violated the CAA. The DAQ issued the revised permit on March 13, 2009, as discussed above. Based upon DAQ’s minor-source determination, Duke Energy Carolinas filed a motion requesting that the court abstain from further action on the matter and dismiss the plaintiffs’ complaint. The court granted Duke Energy Carolinas motion to abstain and dismissed the plaintiffs’ complaint without prejudice. On August 3, 2009, plaintiffs filed a notice of appeal of the court’s order and Duke Energy Carolinas likewise appealed on the grounds, among others, that the dismissal should have been with prejudice to any future filing.

It is not possible to predict with certainty whether Duke Energy Carolinas will incur any liability or to estimate the damages, if any, that Duke Energy Carolinas might incur in connection with this matter. To the extent that a court of proper jurisdiction halts construction of the plant, Duke Energy Carolinas will seek to meet customers’ needs for power through other resources. In addition, Duke Energy Carolinas will seek appropriate regulatory treatment for the investment in the plant.

Carbon Dioxide (CO₂) Litigation. In July 2004, the states of Connecticut, New York, California, Iowa, New Jersey, Rhode Island, Vermont, Wisconsin and the City of New York brought a lawsuit in the U.S. District Court for the Southern District of New York against Cinergy, American Electric Power Company, Inc., American Electric Power Service Corporation, The Southern Company, Tennessee Valley Authority, and Xcel Energy Inc. A similar lawsuit was filed in the U.S. District Court for the Southern District of New York against the same companies by Open Space Institute, Inc., Open Space Conservancy, Inc., and The Audubon Society of New Hampshire. These lawsuits allege that the defendants’ emissions of CO₂ from the combustion of fossil fuels at electric generating facilities contribute to global warming and amount to a public nuisance. The complaints also allege that the defendants could generate the same amount of electricity while emitting significantly less CO₂. The plaintiffs are seeking an injunction requiring each defendant to cap its CO₂emissions and then reduce them by a specified percentage each year for at least a decade. In September 2005, the District Court granted the defendants’ motion to dismiss the lawsuit. The plaintiffs have appealed this ruling to the Second Circuit Court of Appeals. Oral arguments were held before the Second Circuit Court of Appeals on June 7, 2006. In September, 2009, the Court of Appeals issued an opinion reversing the district court and reinstating the lawsuit. Defendants filed a petition for rehearing en banc. It is not possible to predict with certainty whether Duke Energy will incur any liability or to estimate the damages, if any, that Duke Energy might incur in connection with this matter.

Alaskan Global Warming Lawsuit. On February 26, 2008, plaintiffs filed suit against Peabody Coal and various oil and power company defendants, including Duke Energy and certain of its subsidiaries. Plaintiffs, the governing bodies of an Inupiat village in Alaska brought the action on their own behalf and on behalf of the village’s approximately 400 residents. The lawsuit alleges that defendants’ emissions of CO₂contributed to global warming and constitute a private and public nuisance. Plaintiffs also allege that certain defendants, including Duke Energy, conspired to mislead the public with respect to global warming. Plaintiffs seek unspecified monetary damages, attorney’s fees and expenses. On June 30, 2008, the defendants filed a motion to dismiss on jurisdictional grounds, together with a motion to dismiss the conspiracy claims. On October 15, 2009, the District Court granted defendants motion to dismiss and plaintiffs filed a notice of appeal. It is not possible to predict with certainty whether Duke Energy will incur any liability or to estimate the damages, if any, that Duke Energy might incur in connection with this matter.

Hurricane Katrina Lawsuit. In April 2006, Duke Energy and Cinergy were named in the third amended complaint of a purported class action lawsuit filed in the U.S. District Court for the Southern District of Mississippi. Plaintiffs claim that Duke Energy and Cinergy, along with numerous other utilities, oil companies, coal companies and chemical companies, are liable for damages relating to losses suffered by victims of Hurricane Katrina. Plaintiffs claim that defendants’ greenhouse gas emissions contributed to the frequency and intensity of storms such as Hurricane Katrina. On August 30, 2007, the court dismissed the case and plaintiffs filed a notice of appeal. In October 2009, the Court of Appeals issued an opinion reversing the district court and reinstating the lawsuit. Defendants filed a petition for rehearing en banc. It is not possible to predict with certainty whether Duke Energy will incur any liability or to estimate the damages, if any, that Duke Energy might incur in connection with this matter.

Price Reporting Cases. A total of 13 lawsuits have been filed against Duke Energy affiliates and other energy companies. Of the 13 lawsuits, 11 have been consolidated into a single proceeding, including the case originally filed in Wisconsin state court in March 2009. In February 2008, the judge in this proceeding granted a motion to dismiss one of the cases and entered judgment in favor of DETM. Plaintiffs’ motion to reconsider was, in large part, denied and on January 9, 2009, the court ruled that plaintiffs lacked standing to pursue their remaining claims and granted certain defendants’ motion for summary judgment. In February 2009, the same judge dismissed Duke Energy Carolinas from that case as well as four other of the consolidated cases. In November 2009, the judge granted Defendants’ motion for reconsideration of the denial of Defendants’ summary judgment motion in two of the remaining 10 cases to which Duke Energy affiliates are a party. In December 2009, plaintiffs in the consolidated cases filed a motion to amend their complaints in the individual cases to add a claim for treble damages under the Sherman Act, including additional factual allegations regarding fraudulent concealment of defendants’ allegedly conspiratorial conduct.

One case was filed in Tennessee state court, which dismissed the case based on the filed rate doctrine and federal preemption grounds. That case was appealed to the Tennessee Court of Appeals, which reversed this lower court ruling in October 2008. Defendants’ application for permission to appeal to the Tennessee Supreme Court was granted and oral argument occurred in November 2009. On January 13, 2009, another case pending in Missouri state court, was dismissed on the grounds that the plaintiff lacked standing to bring the case and the plaintiff’s appeal was heard by the Missouri Court of Appeals in November 2009. In December 2009, the Court of Appeals affirmed the trial court ruling. On February 2, 2010, plaintiffs’ motion for rehearing and application for transfer to the Missouri Supreme Court was denied. Plaintiffs have filed a motion to transfer directly for the Missouri Supreme Court. Each of these cases contains similar claims, that the respective plaintiffs, and the classes they claim to represent, were harmed by the defendants’ alleged manipulation of the natural gas markets by various means, including providing false information to natural gas trade publications and entering into unlawful arrangements and agreements in violation of the antitrust laws of the respective states. Plaintiffs seek damages in unspecified amounts.

A settlement agreement was executed with the class plaintiffs in five of the 11 consolidated cases in September 2009. The settlement did not have a material adverse effect on Duke Energy’s consolidated results of operations, cash flows or financial position. It is not possible to predict with certainty whether Duke Energy will incur any liability or to estimate the damages, if any, that Duke Energy might incur in connection with the remaining matters.

Western Electricity Litigation. Plaintiffs, on behalf of themselves and others, in three lawsuits allege that Duke Energy affiliates, among other energy companies, artificially inflated the price of electricity in certain western states. Two of the cases were dismissed and plaintiffs appealed to the U.S. Court of Appeal for the Ninth Circuit. Of those two cases, one was dismissed by agreement in March 2007. In November 2007, the court issued an opinion affirming dismissal of the other case, plaintiffs’ motion for reconsideration was denied and plaintiffs did not file a petition for certiorari to the Supreme Court. Plaintiffs in the remaining case seek damages in unspecified amounts. It is not possible to predict with certainty whether Duke Energy will incur any liability or to estimate the damages, if any, that Duke Energy might incur in connection with these lawsuits, but Duke Energy does not presently believe the outcome of these matters will have a material adverse effect on its consolidated results of operations, cash flows or financial position.

Duke Energy Retirement Cash Balance Plan. A class action lawsuit was filed in federal court in South Carolina against Duke Energy and the Duke Energy Retirement Cash Balance Plan, alleging violations of Employee Retirement Income Security Act (ERISA) and the Age Discrimination in Employment Act (ADEA). These allegations arise out of the conversion of the Duke Energy Company Employees’ Retirement Plan into the Duke Energy Retirement Cash Balance Plan. The case also raises some Plan administration issues, alleging errors in the application of Plan provisions (i.e., the calculation of interest rate credits in 1997 and 1998 and the calculation of lump-sum distributions). The plaintiffs seek to represent present and former participants in the Duke Energy Retirement Cash Balance Plan. This group is estimated to include approximately 36,000 persons. The plaintiffs also seek to divide the putative class into sub-classes based on age. Six causes of action are alleged, ranging from age discrimination, to various alleged ERISA violations, to allegations of breach of fiduciary duty. Plaintiffs seek a broad array of remedies, including a retroactive reformation of the Duke Energy Retirement Cash Balance Plan and a

recalculation of participants’/ beneficiaries’ benefits under the revised and reformed plan. Duke Energy filed its answer in March 2006. A portion of this contingent liability was assigned to Spectra Energy in connection with the spin-off in January 2007. A hearing on the plaintiffs’ motion to amend the complaint to add an additional age discrimination claim, defendant’s motion to dismiss and the respective motions for summary judgment was held in December 2007. On June 2, 2008, the court issued its ruling denying plaintiffs’ motion to add the additional claim and dismissing a number of plaintiffs’ claims, including the claims for ERISA age discrimination. Since that date, plaintiffs have notified Duke Energy that they are withdrawing their ADEA claim. On September 4, 2009, the court issued its order certifying classes for three of the remaining claims but not certifying their claims as to plaintiffs’ fiduciary duty claims. At an unsuccessful mediation in September 2008, Plaintiffs quantified their claims as being in excess of $150 million. It is not possible to predict with certainty the damages, if any, that Duke Energy might incur in connection with this matter.

Ohio Antitrust Lawsuit. In January 2008, four plaintiffs, including individual, industrial and non-profit customers, filed a lawsuit against Duke Energy Ohio in federal court in the Southern District of Ohio. Plaintiffs allege that Duke Energy Ohio (then The Cincinnati Gas & Electric Company (CG&E)), conspired to provide inequitable and unfair price advantages for certain large business consumers by entering into non-public option agreements with such consumers in exchange for their withdrawal of challenges to Duke Energy Ohio’s (then CG&E’s) pending RSP, which was implemented in early 2005. Duke Energy Ohio denies the allegations made in the lawsuit. Following Duke Energy Ohio’s filing of a motion to dismiss plaintiffs’ claims, plaintiffs amended their complaint on May 30, 2008. Plaintiffs now contend that the contracts at issue were an illegal rebate which violate antitrust and Racketeer Influenced and Corrupt Organizations (RICO) statutes. Defendants have again moved to dismiss the claims. On March 31, 2009, the District Court granted Duke Energy Ohio’s motion to dismiss. Plaintiffs have filed a motion to alter or set aside the judgment.

Duke Energy International Paranapanema Lawsuit. On July 16, 2008, Duke Energy International Geracao Paranapanema S.A. (DEIGP) filed a lawsuit in the Brazilian federal court challenging the merits of two resolutions promulgated by the Brazilian electricity regulatory agency (ANEEL) (collectively, the “Resolutions”). The Resolutions purport to impose additional transmission fees (retroactive to July 1, 2004 and effective through June 30, 2009) on generation companies located in the State of São Paulo for utilization of the electric transmission system. The new assessments are based upon a flat-fee charge that fails to take into account the locational usage by each generator. DEIGP has been assessed approximately $45 million, inclusive of interest. DEIGP challenged the assessment in Brazilian federal court. Based on DEIGP’s continuing refusal to tender payment of the disputed sums, on April 1, 2009, ANEEL assessed an additional fine against DEIGP in the amount of approximately $7 million. DEIGP filed a request to enjoin payment of the fine and for an expedited decision on the merits or, alternatively, a result that all disputed sums be deposited in the court’s registry in lieu of direct payment to the distribution companies.

On June 30, 2009, the court issued a ruling in which it granted DEIGP’s request for injunction regarding the second fine and denied DEIGP’s request for an expedited decision or payment into the court registry. Under the court’s order, DEIGP was required to make payment directly to the distribution companies on the approximate $45 million assessment pending resolution on the merits. As a result of the court’s ruling, in the second quarter of 2009, Duke Energy recorded a pre-tax charge of approximately $33 million associated with this matter. The court’s ruling also allowed DEIGP to make 31 monthly installment payments on the outstanding obligation. DEIGP filed an appeal and on August 28, 2009, the order requiring installment payments was modified to allow DEIGP to deposit the disputed portion, which was most of the assessed amount, into an escrow account pending resolution on the merits.

Asbestos-related Injuries and Damages Claims. Duke Energy has experienced numerous claims for indemnification and medical cost reimbursement relating to damages for bodily 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 prior to 1985.

Duke Energy Indiana and Duke Energy Ohio have also been named as defendants or co-defendants in lawsuits related to asbestos at their electric generating stations. The impact on Duke Energy’s consolidated results of operations, cash flows or financial position of these cases to date has not been material. Based on estimates under varying assumptions concerning uncertainties, such as, among others: (i) the number of contractors potentially exposed to asbestos during construction or maintenance of Duke Energy Indiana and Duke Energy Ohio generating plants; (ii) the possible incidence of various illnesses among exposed workers, and (iii) the potential settlement costs without federal or other legislation that addresses asbestos tort actions, Duke Energy estimates that the range of reasonably possible exposure in existing and future suits over the foreseeable future is not material. This estimated range of exposure may change as additional settlements occur and claims are made and more case law is established.

Other Litigation and Legal Proceedings. Duke Energy and its subsidiaries are involved in other legal, tax and regulatory proceedings arising in the ordinary course of business, some of which involve substantial amounts. Duke Energy believes that the final disposition of these proceedings will not have a material adverse effect on its consolidated results of operations, cash flows or financial position.

Duke Energy has exposure to certain legal matters that are described herein. As of December 31, 2009 and 2008, Duke Energy has recorded reserves, including reserves related to the aforementioned asbestos-related injuries and damages claims, of approximately $1 billion and $1.1 billion, respectively, for these proceedings and exposures. These reserves represent management’s best estimate of probable loss as defined in the accounting guidance for contingencies. Duke Energy has insurance coverage for certain of these losses incurred. As of December 31, 2009 and 2008, Duke Energy recognized approximately $984 million and $1,032 million, respectively, of probable insurance recoveries related to these losses.

Duke Energy expenses legal costs related to the defense of loss contingencies as incurred.

DEGS of Narrows, L.L.C. Investigation. In October 2006, Duke Energy began an internal investigation into improper data reporting to the EPA regarding air emissions under the NO_x Budget Program at Duke Energy’s DEGS of Narrows, L.L.C. power plant facility in Narrows, Virginia. The investigation has revealed evidence of falsification of data by an employee relating to the quality assurance testing of its continuous emissions monitoring system to monitor heat input and NO_x emissions. In December 2006, Duke Energy voluntarily disclosed the potential violations to the EPA and Virginia Department of Environmental Quality (VDEQ), and in January 2007, Duke Energy made a full written disclosure of the investigation’s findings to the EPA and the VDEQ. In December 2007, the EPA issued a notice of violation. On March 19, 2009, the EPA advised that it will not pursue criminal charges against Duke Energy, and negotiations can resume resolving the civil violation of the CAA identified in the December 2007 notice of violation. Duke Energy has taken appropriate disciplinary action, including termination, with respect to the employees involved with the false reporting. It is not possible to predict with certainty whether Duke Energy will incur any liability or to estimate the damages, if any, that Duke Energy might incur in connection with this matter. DEGS has reached an agreement in principle to settle the CAA civil violation for an amount that is not material.

General. As part of its normal business, Duke Energy is a party to various financial guarantees, performance guarantees and other contractual commitments to extend guarantees of credit and other assistance to various subsidiaries, investees and other third parties. To varying degrees, these guarantees involve elements of performance and credit risk, which are not included on the Consolidated Balance Sheets. The possibility of Duke Energy having to honor its contingencies is largely dependent upon future operations of various subsidiaries, investees and other third parties, or the occurrence of certain future events. For further information see Note 17.

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

Duke Energy leases assets in several areas of its operations. Consolidated rental expense for operating leases included in income from continuing operations was $129 million in 2009, $164 million in 2008 and $138 million in 2007 which is included in Operation, Maintenance and Other on the Consolidated Statements of Operations. Amortization of assets recorded under capital leases is included in Depreciation and Amortization on the Consolidated Statements of Operations. The following is a summary of future minimum lease payments under operating leases, which at inception had a non-cancelable term of more than one year, and capital leases as of December 31, 2009:

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

As discussed in Note 1, on January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses to shareholders. Guarantees that were issued by Duke Energy, Cinergy or International Energy, or were assigned to Duke Energy prior to the spin-off remained with Duke Energy subsequent to the spin-off. Guarantees issued by Spectra Energy Capital, LLC (Spectra Capital) or its affiliates prior to the spin-off remained with Spectra Capital subsequent to the spin-off, except for certain guarantees that are in the process of being assigned to Duke Energy. During this assignment period, Duke Energy has indemnified Spectra Capital against any losses incurred under these guarantee obligations. The maximum potential amount of future payments associated with the guarantees issued by Spectra Capital is approximately $250 million.

Duke Energy has issued performance guarantees to customers and other third parties that guarantee the payment and performance of other parties, including certain non-wholly-owned entities, as well as guarantees of debt of certain non-consolidated entities and less than wholly-owned consolidated entities. If such entities were to default on payments or performance, Duke Energy would be required under the guarantees to make payments on the obligations of the less than wholly-owned entity. The maximum potential amount of future payments Duke Energy could have been required to make under these guarantees as of December 31, 2009 was approximately $455 million. Of this amount, approximately $195 million relates to guarantees issued on behalf of less than wholly-owned consolidated entities, with the remainder related to guarantees issued on behalf of third parties and unconsolidated affiliates of Duke Energy. Approximately $285 million of the guarantees expire between 2010 and 2021, with the remaining performance guarantees having no contractual expiration.

Included in the maximum potential amount of future payments discussed above is approximately $61 million of maximum potential amounts of future payments associated with guarantees issued to customers or other third parties related to the payment or performance obligations of certain entities that were previously wholly-owned by Duke Energy but which have been sold to third parties, such as DukeSolutions, Inc. (DukeSolutions) and Duke Engineering & Services, Inc. (DE&S). These guarantees are primarily related to payment of lease obligations, debt obligations, and performance guarantees related to provision of goods and services. Duke Energy has received back-to-back indemnification from the buyer of DE&S indemnifying Duke Energy for any amounts paid related to the DE&S guarantees. Duke Energy also received indemnification from the buyer of DukeSolutions for the first $2.5 million paid by Duke Energy related to the DukeSolutions guarantees. Further, Duke Energy granted indemnification to the buyer of DukeSolutions with respect to losses arising under some energy services agreements retained by DukeSolutions after the sale, provided that the buyer agreed to bear 100% of the performance risk and 50% of any other risk up to an aggregate maximum of $2.5 million (less any amounts paid by the buyer under the indemnity discussed above). Additionally, for certain performance guarantees, Duke Energy has recourse to subcontractors involved in providing services to a customer. These guarantees have various terms ranging from 2012 to 2021, with others having no specific term.

Duke Energy has guaranteed certain issuers of surety bonds, obligating itself to make payment upon the failure of a non-wholly-owned entity to honor its obligations to a third party, as well as used bank-issued stand-by letters of credit to secure the performance of non-wholly-owned entities to a third party or customer. Under these arrangements, Duke Energy has payment obligations which are triggered by a draw by the third party or customer due to the failure of the non-wholly-owned entity to perform according to the terms of its underlying contract. Substantially all of these guarantees issued by Duke Energy relate to projects at Crescent that were under development at the time of the joint venture creation in 2006. Crescent filed Chapter 11 petitions in a U.S. Bankruptcy Court in June 2009. During 2009, Duke Energy determined that it was probable that it will be required to perform under certain of these guarantee obligations and recorded a charge of approximately $26 million associated with these obligations, which represented Duke Energy’s best estimate of its exposure under these guarantee obligations. At the time the charge was recorded, the face value of the guarantees was approximately $70 million, which has since been reduced to approximately $50 million as of December 31, 2009 as Crescent continues to complete some of its obligations under these guarantees.

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

At December 31, 2009, the amounts recorded on the Consolidated Balance Sheets for the guarantees and indemnifications mentioned above, including performance guarantees associated with projects at Crescent for which it is probable that Duke Energy will be required to perform, is approximately $35 million. This amount is primarily recorded in Other within Deferred Credits and Other Liabilities on the Consolidated Balance Sheets.

Basic earnings per share (EPS) is computed by dividing net income attributable to Duke Energy common stockholders, adjusted for distributed and undistributed earnings allocated to participating securities, by the weighted-average number of common shares outstanding during the period. Diluted EPS is computed by dividing net income attributable to Duke Energy common stockholders, as adjusted, by the diluted weighted-average number of common shares outstanding during the period. Diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock, such as stock options, phantom shares and stock-based performance unit awards were exercised or settled.

Effective January 1, 2009, Duke Energy began applying revised accounting guidance for EPS related to participating securities, whereby unvested share-based payment awards that have non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) when dividends are paid to common stockholders, irrespective of whether the award ultimately vests, constitute participation rights and should be included in the computation of basic EPS using the two-class method. All prior period EPS data was retrospectively adjusted to conform to these revised accounting provisions.

The following table illustrates Duke Energy’s basic and diluted EPS calculations and reconciles the weighted-average number of common shares outstanding to the diluted weighted-average number of common shares outstanding for the years ended December 31, 2009, 2008, and 2007.

As of December 31, 2009, 2008 and 2007, approximately 20 million, 15 million and 13 million, respectively, of stock options, unvested stock and performance awards were not included in the “effect of dilutive securities” in the above table because either the option exercise prices were greater than the average market price of the common shares during those periods, or performance measures related to the awards had not yet been met.

Beginning in the fourth quarter of 2008, Duke Energy began issuing authorized but previously unissued shares of common stock to fulfill obligations under its Dividend Reinvestment Plan (DRIP) and other internal plans, including 401(k) plans. During the years ended December 31, 2009 and 2008, Duke Energy received proceeds of approximately $494 million and $100 million, respectively, from the sale of common stock associated with these plans.

During 2010, Duke Energy anticipates issuing approximately $400 million of additional authorized but previously unissued shares of common stock under its DRIP and other internal plans.

For employee awards, equity classified stock-based compensation cost is measured at the grant date, based on the fair value of the award, and is recognized as expense or capitalized as a component of property, plant and equipment over the requisite service period.

Duke Energy’s 2006 Long-Term Incentive Plan (the 2006 Plan) reserved 60 million shares of common stock for awards to employees and outside directors. The 2006 Plan superseded the 1998 Long-Term Incentive Plan, as amended (the 1998 Plan), and no additional grants will be made from the 1998 Plan. Under the 2006 Plan, the exercise price of each option granted cannot be less than the market price of Duke Energy’s common stock on the date of grant and the maximum option term is 10 years. The vesting periods range from immediate to five years. Duke Energy has historically issued new shares upon exercising or vesting of share-based awards. In 2010, Duke Energy may use a combination of new share issuances and open market repurchases for share-based awards which are exercised or become vested; however Duke Energy has not determined with certainty the amount of such new share issuances or open market repurchases.

The 2006 Plan allows for a maximum of 15 million shares of common stock to be issued under various stock-based awards other than options and stock appreciation rights.

Pre-tax stock-based compensation expense recorded in the Consolidated Statements of Operations is as follows:

The tax benefit associated with the stock-based compensation expense for the years ended December 31, 2009, 2008 and 2007 was approximately $16 million, $17 million and $15 million, respectively.

On December 31, 2008 and 2007, Duke Energy had approximately 19 million and 20 million exercisable options, respectively, with a weighted-average exercise price of approximately $17 at each date. The total intrinsic value of options exercised during the years ended December 31, 2009, 2008 and 2007 was approximately $6 million, $11 million and $26 million, respectively, with a related tax benefit of approximately $2 million, $4 million and $10 million, respectively. Cash received from options exercised during the years ended December 31, 2009, 2008 and 2007 was approximately $24 million, $30 million and $50 million, respectively. There were 603,015 stock options granted during the year ended December 31, 2009, and no stock options granted during the years ended December 31, 2008 or 2007. The options granted in 2009 were expensed immediately, therefore, there is no future compensation cost associated with these options.

These assumptions were used to determine the grant date fair value of the stock options granted during 2009:

Phantom stock awards issued and outstanding under the 2006 Plan generally vest over periods from immediate to three years. Phantom stock awards issued and outstanding under the 1998 Plan generally vest over periods from immediate to five years. Duke Energy awarded 1,095,935 shares (fair value of approximately $16 million, based on the market price of Duke Energy’s common stock at the grant date) during the year ended December 31, 2009, 973,515 shares (fair value of approximately $17 million based on the market price of Duke Energy’s common stock at the grant date) during the year ended December 31, 2008, and 1,163,180 shares (fair value of approximately $23 million based on the market price of Duke Energy’s common stock at the grant date) during the year ended December 31, 2007.

The following table summarizes information about phantom stock awards outstanding at December 31, 2009:

The total grant date fair value of the shares vested during the years ended December 31, 2009, 2008 and 2007 was approximately $23 million, $20 million and $31 million, respectively. At December 31, 2009, Duke Energy had approximately $8 million of unrecognized compensation cost which is expected to be recognized over a weighted-average period of 1.4 years.

Stock-based awards issued and outstanding under both the 2006 Plan and the 1998 Plan generally vest over three years if performance targets are met. Vesting for certain stock-based performance awards can occur in three years, at the earliest, if performance is met. Certain performance awards granted in 2009, 2008 and 2007 contain market conditions based on the total shareholder return (TSR) of Duke Energy stock relative to a pre-defined peer group (relative TSR). These awards are valued using a path-dependent model that incorporates expected relative TSR into the fair value determination of Duke Energy’s performance-based share awards. The model uses three year historical volatilities and correlations for all companies in the pre-defined peer group, including Duke Energy, to simulate Duke Energy’s relative TSR as of the end of the performance period. For each simulation, Duke Energy’s relative TSR associated with the simulated stock price at the end of the performance period plus expected dividends within the period results in a value per share for the award portfolio. The average of these simulations is the expected portfolio value per share. Actual life to date results of Duke Energy’s relative TSR for each grant is incorporated within the model. Other performance awards not containing market conditions were awarded in 2009, 2008 and 2007. The performance goal for these awards is Duke Energy’s compounded annual growth rate (CAGR) of annual diluted EPS, adjusted for certain items, over a three year period. These awards are measured at grant date price. Duke Energy awarded 3,426,244 shares (fair value of approximately $44 million) during the year ended December 31, 2009, 2,407,755 shares (fair value of approximately $37 million) during the year ended December 31, 2008, and 1,534,510 shares (fair value of approximately $23 million) during the year ended December 31, 2007.

The following table summarizes information about stock-based performance awards outstanding at December 31, 2009:

The total grant date fair value of the shares vested during the years ended December 31, 2009, 2008 and 2007 was approximately $20 million, $20 million and $34 million, respectively. At December 31, 2009, Duke Energy had approximately $28 million of unrecognized compensation cost which is expected to be recognized over a weighted-average period of 1.2 years.

Other stock awards issued and outstanding under the 1998 Plan vest over periods from three to five years. There were no other stock awards issued during the years ended December 31, 2009, 2008 or 2007.

The following table summarizes information about other stock awards outstanding at December 31, 2009:

The total fair value of the shares vested during the years ended December 31, 2009, 2008 and 2007 was approximately $1 million, $2 million, and $2 million, respectively. At December 31, 2009, Duke Energy had approximately $1 million of unrecognized compensation cost which is expected to be recognized over a weighted-average period of 1.0 year.

Duke Energy and its subsidiaries (including legacy Cinergy businesses) maintain qualified, non-contributory defined benefit retirement plans. The plans cover most U.S. employees using a cash balance formula. Under a cash balance formula, a plan participant accumulates a retirement benefit consisting of pay credits that are based upon a percentage (which varies with age and years of service) of current eligible earnings and current interest credits. Certain legacy Cinergy U.S. employees are covered under plans that use a final average earnings formula. Under a final average earnings formula, a plan participant accumulates a retirement benefit equal to a percentage of their highest 3-year average earnings, plus a percentage of their highest 3-year average earnings in excess of covered compensation per year of participation (maximum of 35 years), plus a percentage of their highest 3-year average earnings times years of participation in excess of 35 years. Duke Energy also maintains non-qualified, non-contributory defined benefit retirement plans which cover certain executives.

Duke Energy’s policy is to fund amounts on an actuarial basis to provide assets sufficient to meet benefit payments to be paid to plan participants. During 2009, Duke Energy made contributions to its U.S. qualified pension plans of approximately $800 million. There were no contributions to the U.S. qualified pension plans during the year ended December 31, 2008. Duke Energy made a contribution of approximately $350 million to the legacy Cinergy qualified pension plans during the year ended December 31, 2007.

Actuarial gains and losses are amortized over the average remaining service period of the active employees. The average remaining service period of active employees covered by the qualified retirement plans is 11 years. The average remaining service period of active employees covered by the non-qualified retirement plans is nine years. Duke Energy determines the market-related value of plan assets using a calculated value that recognizes changes in fair value of the plan assets in a particular year on a straight line basis over the next five years.

Net periodic benefit costs disclosed in the tables below for the qualified, non-qualified and other post-retirement benefit plans represent the cost of the respective benefit plan for the periods presented. However, portions of the net periodic benefit costs disclosed in the tables below have been capitalized as a component of property, plant and equipment.

As required by the applicable accounting rules, Duke Energy uses a December 31 measurement date for its plan assets.

Qualified Pension Plans—Other Changes in Plan Assets and Projected Benefit Obligations

Recognized in Accumulated Other Comprehensive Income and Regulatory Assets^(a)

Reconciliation of Funded Status to Net Amount Recognized: Qualified Pension Plans

The accumulated benefit obligation was approximately $4,409 million and $3,823 million at December 31, 2009 and 2008, respectively.

Qualified Pension Plans—Amounts Recognized in the Consolidated Balance Sheets Consist of:

The following table provides the amounts related to Duke Energy’s qualified pension plans that are reflected in Other within Regulatory Assets and Deferred Debits and AOCI on the Consolidated Balance Sheets at December 31, 2009 and 2008:

Of the amounts above, approximately $48 million of unrecognized net actuarial loss and approximately $5 million of unrecognized prior service cost will be recognized in net periodic pension costs in 2010.

Qualified Pension Plans—Information for Plans with Accumulated Benefit Obligation in Excess of Plan Assets

The discount rate used to determine the current year pension obligation and following year’s pension expense is based on a yield curve approach. Under the yield curve approach, expected future benefit payments for each plan are discounted by a rate on a third-party bond yield curve corresponding to each duration. The yield curve is based on a bond universe of AA and AAA-rated long-term corporate bonds. A single discount rate is calculated that would yield the same present value as the sum of the discounted cash flows.

Non-qualified Pension Plans—Other Changes in Plan Assets and Projected Benefit Obligations

Reconciliation of Funded Status to Net Amount Recognized: Non-Qualified Pension Plans

The accumulated benefit obligation was approximately $159 million and $154 million at December 31, 2009 and 2008, respectively.

Non-Qualified Pension Plans—Amounts Recognized in the Consolidated Balance Sheets Consist of:

The following table provides the amounts related to Duke Energy’s non-qualified pension plans that are reflected in AOCI on the Consolidated Balance Sheets at December 31, 2009 and 2008:

Of the amounts above, approximately $2 million of unrecognized prior service cost and approximately $1 million of unrecognized net actuarial loss will be recognized in net periodic pension costs in 2010.

Non-Qualified Pension Plans—Information for Plans with Accumulated Benefit Obligation in Excess of Plan Assets

Non-Qualified Pension Plans—Assumptions Used for Pension Benefits Accounting

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

Duke Energy did not make any contributions to its other post-retirement benefit plans in 2009 or 2008. During the year ended December 31, 2007, Duke Energy contributed approximately $62 million to its other post-retirement benefit plans.

These benefit costs are accrued over an employee’s active service period to the date of full benefits eligibility. The net unrecognized transition obligation is amortized over approximately 20 years. Actuarial gains and losses are amortized over the average remaining service period of the active employees. The average remaining service period of the active employees covered by the plan is 12 years.

The Medicare Prescription Drug, Improvement and Modernization Act of 2003 introduced a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans. Accounting guidance issued and adopted by Duke Energy in 2004 prescribes the appropriate accounting for the federal subsidy. The after-tax effect on net periodic post-retirement benefit cost was a decrease of $3 million in 2009, $3 million in 2008 and $3 million in 2007. Duke Energy recognized an approximate $5 million and $8 million subsidy receivable as of December 31, 2009 and 2008, respectively, which is included in Receivables on the Consolidated Balance Sheets.

Other Post-Retirement Benefit Plans—Other Changes in Plan Assets and Projected Benefit Obligations

Recognized in Accumulated Other Comprehensive Income, Regulatory Assets and Regulatory Liabilities

Reconciliation of Funded Status to Accrued Other Post-Retirement Benefit Costs

Other Post-Retirement Benefit Plans- Amounts Recognized in the Consolidated Balance Sheets Consist of:

The following table provides the amounts related to Duke Energy’s other post-retirement benefit plans that are reflected in Other within Regulatory Assets and Deferred Debits, Other within Deferred Credits and Other Liabilities and AOCI on the Consolidated Balance Sheets at December 31, 2009 and 2008:

Of the amounts above, approximately $10 million of unrecognized net transition obligation, approximately $4 million of unrecognized gains and approximately $8 million of unrecognized prior service credit (which will reduce pension expense) will be recognized in net periodic pension costs in 2010.

The discount rate used to determine the current year other post-retirement benefits obligation and following year’s other post-retirement benefits expense is based on a yield curve approach. Under the yield curve approach, expected future benefit payments for each plan are discounted by a rate on a third-party bond yield curve corresponding to each duration. The yield curve is based on a bond universe of AA and AAA-rated long-term corporate bonds. A single discount rate is calculated that would yield the same present value as the sum of the discounted cash flows.

Sensitivity to Changes in Assumed Health Care Cost Trend Rates (in millions)

The following table presents Duke Energy’s expected benefit payments to participants in its qualified, non-qualified and other post-retirement benefit plans over the next 10 years, which are primarily paid out of the assets of the various trusts. These benefit payments reflect expected future service, as appropriate.

Master Retirement Trust. Assets for both the qualified pension and other post-retirement benefits are maintained in a Master Retirement Trust (Master Trust). Approximately 97% of Master Trust assets were allocated to qualified pension plans and approximately 3% were allocated to other post-retirement plans, as of December 31, 2009 and 2008, respectively. The investment objective of the Master Trust is to achieve reasonable returns, subject to a prudent level of portfolio risk, for the purpose of enhancing the security of benefits for plan participants. The long-term rate of return of 8.5% as of December 31, 2009 for the Master Trust was developed using a weighted-average calculation of expected returns based primarily on future expected returns across asset classes considering the use of active asset managers. The weighted-average returns expected by asset classes were 3.2% for U.S. equities, 2.0% for Non-U.S. equities, 1.0% for Global equities, 2.0% for fixed income securities, and 0.3% for real estate. The asset allocation targets were set after considering the investment objective and the risk profile. U.S. equities are held for their high expected return. Non-U.S. equities, debt securities, and real estate are held for diversification. Investments within asset classes are to be diversified to achieve broad market participation and reduce the impact of individual managers or investments. Duke Energy regularly reviews its actual asset allocation and periodically rebalances its investments to the targeted allocation when considered appropriate. The following table presents target and actual asset allocations for the Master Trust at December 31, 2009 and 2008:

VEBA I/II. Duke Energy also invests other post-retirement assets in the Duke Energy Corporation Employee Benefits Trust (VEBA I) and the Duke Energy Corporation Post-Retirement Medical Benefits Trust (VEBA II). The investment objective of the VEBAs is to achieve sufficient returns, subject to a prudent level of portfolio risk, for the purpose of promoting the security of plan benefits for participants. The VEBAs are passively managed. The following tables present target and actual asset allocations for the VEBAs at December 31, 2009 and 2008:

Fair Value Measurements. On December 31, 2009, Duke Energy adopted the new fair value disclosure requirements for pension and other post-retirement benefit plan assets. The accounting guidance for fair value defines fair value, establishes a framework for measuring fair value in GAAP in the U.S. and expands disclosure requirements about fair value measurements. Under the accounting guidance for fair value, fair value is considered to be the exchange price in an orderly transaction between market participants to sell an asset or transfer a liability at the measurement date. The fair value definition focuses on an exit price, which is the price that would be received by Duke Energy to sell an asset or paid to transfer a liability versus an entry price, which would be the price paid to acquire an asset or received to assume a liability. Although the accounting guidance for fair value does not require additional fair value measurements, it applies to other accounting pronouncements that require or permit fair value measurements.

Level 1—unadjusted quoted prices in active markets for identical assets or liabilities that Duke Energy has the ability to access. An active market for the asset or liability is one in which transactions for the asset or liability occurs with sufficient frequency and volume to provide ongoing pricing information. Duke Energy does not adjust quoted market prices on Level 1 for any blockage factor.

The following table provides the fair value measurement amounts for Master Trust qualified pension and other post-retirement assets at December 31, 2009.

(a) Excludes approximately $22 million in net receivables and payables associated with security purchases and sales.

The following table provides the fair value measurement amounts for VEBA I/II other post-retirement assets at December 31, 2009.

The following table provides a reconciliation of beginning and ending balances of Master Trust assets measured at fair value on a recurring basis where the determination of fair value includes significant unobservable inputs (Level 3):

Valuation methods of the primary fair value measurements disclosed above are as follows:

Investments in equity securities: Investments in equity securities are typically valued at the closing price in the principal active market as of the last business day of the quarter. Principal active markets for equity prices include published exchanges such as NASDAQ and NYSE. Foreign equity prices are translated from their trading currency using the currency exchange rate in effect at the close of the principal active market. Duke Energy has not adjusted prices to reflect for after-hours market activity. Most equity security valuations are level 1 measures. Investments in equity securities with unpublished prices are valued as level 2 if they are redeemable at the measurement date. Investments in equity securities with redemption restrictions are valued as level 3.

Investments in corporate bonds and U.S. government securities: Most debt investments are valued based on a calculation using interest rate curves and credit spreads applied to the terms of the debt instrument (maturity and coupon interest rate) and consider the counterparty credit rating. Most debt valuations are Level 2 measures. If the market for a particular fixed income security is relatively inactive or illiquid, the measurement is a Level 3 measurement.

Investments in short-term investment funds: Valued at the net asset value of units held at year end. Investments in short-term investment funds with published prices are valued as level 1. Investments in short-term investment funds with unpublished prices are valued as level 2.

Investments in real estate investment trust: Valued based upon property appraisal reports prepared by independent real estate appraisers. The Chief Real Estate Appraiser of the asset manager is responsible for assuring that the valuation process provides independent and reasonable property market value estimates. An external appraisal management firm not affiliated with the asset manager has been appointed to assist the Chief Real Estate Appraiser in maintaining and monitoring the independence and the accuracy of the appraisal process.

Duke Energy sponsors employee savings plans that cover substantially all U.S. employees. Most employees participate in a matching contribution formula where Duke Energy provides a matching contribution generally equal to 100% of before-tax employee contributions, of up to 6% of eligible pay per pay period. Duke Energy made pre-tax employer matching contributions of approximately $80 million in 2009, $78 million in 2008 and $68 million in 2007. Dividends on Duke Energy shares held by the savings plans are charged to retained earnings when declared and shares held in the plans are considered outstanding in the calculation of basic and diluted earnings per share.

Power Sale Special Purpose Entities (SPEs). Duke Energy is the primary beneficiary of and consolidates two thinly-capitalized SPEs that have been created to finance and execute individual power sale agreements with Central Maine Power Company (CMP) for approximately 45 MW of capacity, which expired in 2009, and 35 MW of capacity, ending in 2016. In addition, these SPEs have individual power purchase agreements (PPA) with Duke Energy Commercial Enterprises, Inc. (DECE), formerly Cinergy Capital & Trading, Inc., a wholly-owned subsidiary of Duke Energy, to supply the power. DECE also provides various services, including certain credit support facilities. The following summarizes the structure of each entity:

CinCap IV. CinCap IV was created in July 1998 to facilitate the buyout of a power sales agreement that Stratton Energy Associates (Stratton) held with CMP. Approximately $159 million was paid to Stratton to buyout that contract. This capital was raised through two debt tranches (approximately 96.7% of CinCap IV capitalization) and equity (approximately 3.3% of CinCap IV capitalization). The equity was provided by 1998 CinPower Trust, which is in turned owned 90% by Barclays (3% holder) and 10% by DECE. The capitalization (along with certain miscellaneous fees) of CinCap IV is to be repaid through a monthly reservation payment from CMP. Contemporaneous with the buyout of the Stratton PPA, CinCap IV executed a power sales agreement with CMP (Replacement PPA) to deliver 45 MW of capacity and energy to CMP. CinCap IV also executed a power purchase agreement with DECE (Supply PPA) that contains virtually identical terms, except for the aforementioned reservation payment and a $3 less per MWh energy charge. Cinergy guaranteed the performance of DECE under this PPA (with market-based liquidated damages), but did not guarantee the payment by CinCap IV on its debt obligations. This agreement expired in 2009. As of December, 31, 2009, the balance on the Consolidated Balance Sheets related to CinCap IV was an insignificant amount.

CinCap V. CinCap V was created in February 1999 to facilitate the buyout of a power sales agreement that Alternative Energy (AEI) held with CMP. Approximately $96 million was paid to AEI to buyout that contract. This capital was raised through two debt tranches (approximately 96.7% of CinCap V capitalization) and equity (approximately 3.3% of CinCap IV capitalization). The equity was provided by two parties: (a) 90% by Franklin Life Insurance Company and (b) 10% by DECE. The capitalization (along with certain miscellaneous fees) of CinCap V is being repaid through a monthly reservation payment from CMP. Contemporaneous with the buyout of the AEI PPA, CinCap V executed a power sales agreement with CMP (Replacement PPA) to deliver 35 MW (only 25 in certain months) of capacity and energy to CMP through December 2016. CinCap V also executed a power purchase agreement with DECE (Supply PPA) that contains virtually identical terms, except for the aforementioned reservation payment and a $0.50 less per MWh energy charge. Cinergy guarantees the performance of DECE under this PPA (with market-based liquidated damages), but does not guarantee the payment by CinCap IV on its debt obligations.

These two SPEs meet the accounting definition of a VIE because the equity investment at risk in these SPEs is insufficient to permit the financing of their activities without additional subordinated financial support (i.e., debt financing). As a result of a quantitative analysis of the contractual, ownership, and other financial interests in the SPEs (i.e., variable interests), Duke Energy has been deemed the primary beneficiary of these entities as it absorbs a majority of the expected losses of these SPEs. Accordingly, Duke Energy consolidates these SPEs and, as such, the transactions between DECE and the two SPEs are eliminated in consolidation.

As a result of the consolidation of these two SPEs, approximately $94 million and $117 million of notes receivable is included on the Consolidated Balance Sheets at December 31, 2009 and 2008, respectively. Of these amounts, $8 million and $24 million are included in Receivables on the Consolidated Balance Sheets and $86 million and $93 million are included in Notes Receivable on the Consolidated Balance Sheets at December 31, 2009 and 2008, respectively. Approximately $89 million and $108 million of non-recourse debt is included on the Consolidated Balance Sheets, of which $8 million and $19 million is included in Current Maturities of Long-Term Debt on the Consolidated Balance Sheets and $81 million and $89 million is included in Long-Term Debt on the Consolidated Balance Sheets at December 31, 2009 and 2008, respectively. In addition, miscellaneous other assets and liabilities are included on Duke Energy’s Consolidated Balance Sheets at December 31, 2009 and 2008. The debt was incurred by the SPEs to finance the buyout of the existing power contracts that CMP held with the former suppliers. The notes receivable is comprised of two separate notes with one counterparty, whose credit rating is BBB+. The cash flows from the notes receivable are designed to repay the debt. The first note receivable matured in August 2009, and had a balance of $17 million at December 31, 2008, at an effective interest rate of 7.81%. The second note receivable, with a balance of $94 million and $100 million at December 31, 2009 and 2008, respectively, bears an effective interest rate of 9.23% and matures in December 2016.

The following table reflects the maturities of the Notes Receivable as of December 31, 2009:

Cinergy Receivables Company. During 2002, Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky entered into an agreement to sell certain of their accounts receivable and related collections through Cinergy Receivables, a bankruptcy remote, QSPE. Cinergy Receivables is a wholly-owned limited liability company of Cinergy and was formed in 2002 through a $5 million equity contribution by Cinergy to purchase certain accounts receivable of Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky. The purpose of the formation of Cinergy Receivables was to improve liquidity at the lowest possible financing cost. As a result of the securitization, Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky sell, on a revolving basis, nearly all of their retail accounts receivable and a

portion of their wholesale accounts receivable and related collections. The securitization transaction was structured to meet the criteria for sale accounting treatment under the accounting guidance for transfers and servicing of financial assets and, accordingly through December 31, 2009, Duke Energy did not consolidate Cinergy Receivables and the transfers of receivables were accounted for as sales. Accordingly, through December 31, 2009, Duke Energy accounted for Cinergy Receivables under the equity method of accounting and all of the earnings or losses of Cinergy Receivables are therefore reflected in Duke Energy’s consolidated earnings. Effective with the adoption of new accounting rules related to consolidations and transfers and servicing of financial assets on January 1, 2010, Duke Energy began consolidating Cinergy Receivables. The consolidation of Cinergy Receivables resulted in increases in net Receivables and Short-term Debt on the Consolidated Balance Sheets. While the impact on the balance sheet in future periods will be based on the amount of receivables sold to Cinergy Receivables, at December 31, 2009, approximately $600 million of receivables were sold to Cinergy Receivables, of which approximately $340 million was reflected in Receivables on the Consolidated Balance Sheets as they represented a retained interest in the receivables sold. Effective with the consolidation of Cinergy Receivables, Duke Energy no longer reflects a retained interest in the receivables sold since all receivable sold to Cinergy Receivables, net of loss on sale, do not qualify for sale accounting treatment under the accounting rules for transfers and servicing of financial assets and, thus, are reflected on the Consolidated Balance Sheets. Additionally, effective January 1, 2010, Duke Energy’s Consolidated Balance Sheets reflect Short-term Debt approximating the value of the sold receivables. The consolidation of Cinergy Receivables also impacts Duke Energy’s Statements of Operations as the activity of the Cinergy Receivables facility is now being reflected on a gross basis within Operating Expenses and Interest Expense versus on a net basis in Equity in Earnings (Losses) of Unconsolidated Affiliates.

The proceeds obtained from the sales of receivables are largely cash but do include a subordinated note from Cinergy Receivables for a portion of the purchase price (typically approximates 25% of the total proceeds). The note, which amounts to approximately $340 million and $292 million at December 31, 2009 and 2008, respectively, is subordinate to senior loans that Cinergy Receivables obtains from commercial paper conduits controlled by unrelated financial institutions. Cinergy Receivables provides credit enhancement related to senior loans in the form of over-collateralization of the purchased receivables. However, the over-collateralization is calculated monthly and does not extend to the entire pool of receivables held by Cinergy Receivables at any point in time. As such, these senior loans do not have recourse to all assets of Cinergy Receivables. These loans provide the cash portion of the proceeds paid to Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky.

This subordinated note is a retained interest (right to receive a specified portion of cash flows from the sold assets) under the accounting guidance for transfers and servicing of financial assets and is classified within Receivables in the accompanying Consolidated Balance Sheets at December 31, 2009 and 2008. In addition, Duke Energy’s investment in Cinergy Receivables constitutes a purchased beneficial interest (purchased right to receive specified cash flows, in this case residual cash flows), which is subordinate to the retained interests held by Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky. Effective January 1, 2010, with the consolidation of Cinergy Receivables, this subordinated retained interest as of December 31, 2009 will be replaced on the Consolidated Balance Sheets with the previously transferred accounts receivable balances.

In 2008, Cinergy Receivables and Duke Energy Ohio, Duke Energy Kentucky and Duke Energy Indiana amended the governing purchase and sale agreement to allow Cinergy Receivables to convey its bankrupt receivables to the applicable originator for consideration equal to the fair market value of such receivables as of the disposition date. The amount of bankrupt receivables sold is limited to 1% of aggregate sales of the originator during the most recently completed 12 month period. Cinergy Receivables and Duke Energy Ohio, Duke Energy Kentucky and Duke Energy Indiana completed a sale under this amendment in 2008.

Per the governing purchase and sale agreement, Cinergy Receivables is required to maintain a minimum net worth of $3 million. In December 2008, Cinergy Receivables recorded a $15 million increase in its provision for uncollectible accounts which reduced its net worth below the $3 million threshold. During the first quarter of 2009, Cinergy infused approximately $3.5 million of equity into Cinergy Receivables to remedy the net worth deficiency. In June 2009, Cinergy Receivables recorded a $5 million increase in its provision for uncollectible accounts which reduced its net worth below the $3 million threshold. During July 2009, Cinergy infused $7 million of equity into Cinergy Receivables to remedy the net worth deficiency. In December 2009, Cinergy Receivables recorded a $3 million increase in its provision for uncollectible accounts which reduced its net worth below the $3 million threshold. During February 2010, Cinergy infused approximately $6 million of equity into Cinergy Receivables to remedy the net worth deficiency. The greater amount of receivables in arrears is partially attributable to the economic downturn starting in 2008 having a negative impact on customers’ ability to pay their utility bills. Cinergy Receivables, Duke Energy Ohio, Duke Energy Kentucky and Duke Energy Indiana continue to monitor arrearages to determine whether an other-than-temporary impairment has occurred.

Duke Energy Ohio retains servicing responsibilities for its role as a collection agent on the amounts due on the sold receivables. However, Cinergy Receivables assumes the risk of collection on the purchased receivables without recourse to Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky in the event of a loss. While no direct recourse to Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky exists, these entities risk loss in the event collections are not sufficient to allow for full recovery of their retained interests. No servicing asset or liability is recorded since the servicing fee paid to Duke Energy Ohio approximates a market rate.

The carrying values of the retained interests are determined by allocating the carrying value of the receivables between the assets sold and the interests retained based on relative fair value. The key assumptions used in estimating the fair value for 2009 were an anticipated credit loss ratio of 0.6%, a discount rate of 2.7% and a receivable turnover rate of 11.6%. The key assumptions used in estimating the fair value for 2008 were an anticipated credit loss ratio of 0.6%, a discount rate of 5.3% and a receivable turnover rate of 11.4%. Because (i) the receivables generally turnover in less than two months, (ii) credit losses are reasonably predictable due to the broad customer base and lack of significant concentration, and (iii) the purchased beneficial interest is subordinate to all retained interests and thus would absorb losses first, the allocated bases of the subordinated notes are not materially different than their face value. The hypothetical effect on the fair value of the retained interests assuming both a 10% and a 20% unfavorable variation in credit losses or discount rates is not material due to the short turnover of receivables and historically low credit loss history. Interest accrues to Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky on the retained interests using the accretable yield method, which generally approximates the stated rate on the notes since the allocated basis and the face value are nearly equivalent. Duke Energy records income from Cinergy Receivables in a similar manner. An impairment charge would be recorded against the carrying value of both the retained interests and purchased beneficial interest in the event it is determined that an other-than-temporary impairment has occurred.

The following table shows the gross and net receivables sold, retained interests, purchased beneficial interest, sales, and cash flows during the years ended December 31, 2009 and 2008:

Cash flows from the sale of receivables are reflected within Operating Activities on the Consolidated Statements of Cash Flows.

Collection fees received in connection with the servicing of transferred accounts receivable are included in Operation, maintenance and other on the Consolidated Statements of Operations.

The loss recognized on the sale of receivables is calculated monthly by multiplying the receivables sold during the month by the required discount which is derived monthly utilizing a three year weighted average formula that considers charge-off history, late charge history, and turnover history on the sold receivables, as well as a component for the time value of money. The discount rate, or component for the time value of money, is calculated monthly by summing the prior month-end LIBOR rate plus a fixed rate of 2.39%.

Duke Energy Receivables Finance Company. See Note 15 for further information.

The components of Other Income and Expenses, net on the Consolidated Statements of Operations for the years ended December 31, 2009, 2008 and 2007 are as follows:

For information on subsequent events related to regulatory matters, investments in unconsolidated affiliates and related party transactions, commitments and contingencies and variable interest entities, see Notes 4, 12, 16 and 21, respectively.

In January 2010, Duke Energy announced plans to offer a voluntary severance plan to approximately 8,750 eligible employees. As this is a voluntary plan, all severance benefits offered under this plan are considered special termination benefits under GAAP. Special termination benefits are measured upon employee acceptance and recorded immediately absent a significant retention period. If a significant retention period exists, the cost of the special termination benefits are recorded ratably over the remaining service periods of the affected employees. The window for employees to request to voluntarily end their employment under this plan opened on February 3, 2010 and closed on February 24, 2010 for approximately 8,400 eligible employees. For employees affected by the consolidation of Duke Energy’s corporate functions in Charlotte, North Carolina, as discussed further below, the window will close March 31, 2010. Duke Energy currently estimates severance payments associated with this voluntary plan, based on employees’ requests to voluntarily end their employment received through February 24, 2010, of approximately $130 million. However, until management of Duke Energy approves the requests, it reserves the right to reject any request to volunteer based on business needs and/or excessive participation.

within Duke Energy or remain with Duke Energy through a transition period, at which time a reduced severance benefit would be paid under Duke Energy’s ongoing severance plan. Management cannot currently estimate the costs, if any, of severance benefits which will be paid to its employees due to this office consolidation.

Additionally, Duke Energy believes that it is possible that the voluntary severance plan may trigger settlement accounting or curtailment accounting with respect to its pension and other post-retirement benefit plans. At this time, management is unable to determine the likelihood that settlement or curtailment accounting will be triggered.

During the first quarter of 2009, Duke Energy recorded the following unusual or infrequently occurring item: an approximate $33 million charge associated with performance guarantees issued on behalf of Crescent (see Note 17).

During the second quarter of 2009, Duke Energy recorded the following unusual or infrequently occurring item: an approximate $33 million charge associated with an adverse ruling on prior year’s transmission fees in Brazil (see Note 16).

During the third quarter of 2009, Duke Energy recorded the following unusual or infrequently occurring items: an approximate $371 million non-cash goodwill impairment charge related to the non-regulated Midwest generation reporting unit to write-down the value of the goodwill to the estimated fair value (see Note 11); and an approximate $42 million of pre-tax impairment charges related to certain generating assets in the Midwest to write-down the value of these assets to their estimated fair value (see Note 11).

During the fourth quarter of 2009, Duke Energy recorded the following unusual or infrequently occurring item: an approximate $18 million pre-tax impairment charge to write-down the carrying value of International Energy’s investment in Attiki (see Note 12).

During the first quarter of 2008, Duke Energy recorded the following unusual or infrequently occurring item: Duke Energy’s proportionate share of impairment charges recorded by Crescent, which amounted to a pre-tax charge of approximately $11 million (see Note 12).

During the second quarter of 2008, Duke Energy recorded the following unusual or infrequently occurring items: Duke Energy’s proportionate share of impairment charges recorded by Crescent, which amounted to a pre-tax charge of approximately $113 million (see Note 12); an approximate $23 million pre-tax gain related to the sale of Brownsville (see Note 13); and an approximate $4 million charge related to other-than-temporary impairment of investments in auction rate securities (see Note 10).

During the third quarter of 2008, Duke Energy recorded the following unusual or infrequently occurring items: Duke Energy’s proportionate share of impairment charges recorded by Crescent, which amounted to a pre-tax charge of approximately $114 million (see Note 12); and an approximate $82 million pre-tax impairment charge related to emission allowances (see Note 11).

During the fourth quarter of 2008, Duke Energy recorded the following unusual or infrequently occurring item: an approximate $67 million after-tax (approximately $103 million pre-tax) extraordinary gain related to the reapplication of regulatory accounting treatment to certain operations of Commercial Power (see Note 1).

Duke Energy Corporation (Duke Energy) is a holding company that conducts substantially all of its business operations through its subsidiaries. As specified in the merger conditions issued by various state commissions in connection with Duke Energy’s merger with Cinergy Corp. (Cinergy) in April 2006, there are restrictions on Duke Energy’s ability to obtain funds from certain of its subsidiaries through dividends, loans or advances. For further information, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters.” Accordingly, these condensed financial statements have been prepared on a parent-only basis. Under this parent-only presentation, Duke Energy’s investments in its consolidated subsidiaries are presented under the equity method of accounting. In accordance with Rule 12-04 of Regulation S-X, these parent-only financial statements do not include all of the information and footnotes required by Generally Accepted Accounting Principles (GAAP) in the United States (U.S.) for annual financial statements. Because these parent-only financial statements and notes do not include all of the information and footnotes required by GAAP in the U.S. for annual financial statements, these parent-only financial statements and other information included should be read in conjunction with Duke Energy’s audited Consolidated Financial Statements contained within Part II, Item 8 of this Form 10-K for the year ended December 31, 2009.

Duke Energy and its subsidiaries file a consolidated federal income tax return and other state and foreign jurisdictional returns as required. The taxable income of Duke Energy’s wholly-owned operating subsidiaries is reflected in Duke Energy’s U.S. federal and state income tax returns. Duke Energy has a tax sharing agreement with its wholly-owned operating subsidiaries, where the separate return method is used to allocate tax expenses and benefits to the wholly-owned operating subsidiaries whose investments or results of operations provide these tax expenses and benefits. The accounting for income taxes essentially represents the income taxes that Duke Energy’s wholly-owned operating subsidiaries would incur if each were a separate company filing its own tax return as a C-Corporation.

At December 31, 2009, Duke Energy has guaranteed approximately $2.4 billion of debt issued by Duke Energy Carolinas, LLC, one of Duke Energy’s wholly-owned operating subsidiaries.

In September 2008, Duke Energy borrowed approximately $274 million under its master credit facility and that amount remained outstanding as of December 31, 2009. For additional information on Duke Energy’s master credit facility, see Note 15 to the Consolidated Financial Statements, ‘Debt and Credit Facilities.’ The loans under the master credit facility are revolving credit loans that currently bear interest at one-month LIBOR plus an applicable spread. The loan for Duke Energy has a stated maturity of June 2012.

Duke Energy and its subsidiaries are a party to litigation, environmental and other matters. For further information, see Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies.”

Duke Energy has various financial and performance guarantees and indemnifications which are issued in the normal course of business. These contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. Duke Energy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party. The maximum potential amount of future payments Duke Energy could have been required to make under these guarantees as of December 31, 2009 was approximately $4.3 billion. Of this amount, approximately $4.1 billion relates to guarantees of wholly-owned consolidated entities, including debt issued by Duke Energy Carolinas discussed above, and less than wholly-owned consolidated entities. The majority of these guarantees expire at various times between 2009 and 2033, with the remaining performance guarantees having no contractual expiration. See Note 17 to the Consolidated Financial Statements, “Guarantees and Indemnifications,” for further discussion of guarantees issued on behalf of unconsolidated affiliates and third parties.

Balances due to or due from related parties included in the Balance Sheets as of December 31, 2009 and 2008 are as follows:

During 2007, Duke Energy began providing support to certain subsidiaries for their short-term borrowing needs through participation in a money pool arrangement. Under this arrangement, certain subsidiaries with short-term funds may provide short-term loans to affiliates participating under this arrangement. Additionally, Duke Energy provides loans to subsidiaries through the money pool, but is not permitted to borrow funds through the money pool arrangement. Duke Energy had receivables of approximately $1,135 million and $863 million as of December 31, 2009 and 2008, respectively, classified within Receivables in the accompanying Balance Sheets. Additionally, Duke Energy had money pool-related receivables of $450 million classified as Notes Receivable within Investments and Other Assets on the Balance Sheets as of both December 31, 2009 and 2008. The $272 million increase in money pool receivables during 2009 and the $765 million increase during 2008 are reflected as Notes Receivable from Affiliates, net within Net Cash (Used in) Provided by Investing Activities on the Condensed Statements of Cash Flows. In conjunction with the money pool arrangement, Duke Energy recorded interest income of approximately $12 million, $23 million and $16 million in 2009, 2008 and 2007, respectively, which is included in Other Income and Expenses, net on the Condensed Statements of Operations.

Duke Energy also provides funding to and sweeps cash from subsidiaries that do not participate in the money pool. For these subsidiaries, the cash is used in or generated from their operations, capital expenditures, debt payments and other activities. Amounts funded or received are carried as open accounts as either Investments and Advances to Consolidated Subsidiaries or as Other Non-Current Liabilities and do not bear interest. These amounts are included within Net Cash (Used in) Provided by Operating Activities on the Condensed Statements of Cash Flows.

Additionally, Duke Energy recorded $1 million of interest expense in 2007 associated with credit support provided to a subsidiary, which is included in Interest Expense on the Condensed Statements of Operations.

During the years ended December 31, 2009 and 2007, Duke Energy contributed approximately $250 million and $204 million, respectively, of capital to its wholly-owned subsidiary, Cinergy Corp. Additionally, Duke Energy received dividends from Cinergy Corp. of $200 million in 2008 and $135 million in 2007, which are reflected within Net Cash (Used in) Provided by Operating Activities on the Condensed Statements of Cash Flows.

The valuation and reserve amounts above do not include unrecognized tax benefits amounts or deferred tax asset valuation allowance amounts.

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

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by Duke Energy in the reports it files or submits under the Securities Exchange Act of 1934 (Exchange Act) is recorded, processed, summarized, and reported, within the time periods specified by the Securities and Exchange Commission’s (SEC) rules and forms.

Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by Duke Energy in the reports it files or submits under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, Duke Energy has evaluated the effectiveness of its disclosure controls and procedures (as such term is defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2009, and, based upon this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective in providing reasonable assurance of compliance.

Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, Duke Energy has evaluated changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fiscal quarter ended December 31, 2009 and, other than the fourth quarter system changes described below, have concluded that no change has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

During the fourth quarter of 2009, Duke Energy implemented a new Enterprise Asset Management system used for asset management, work management and supply chain functions for its Midwest and corporate operations. Additionally, the Southeast operations implemented a new system for online customer billing and payment. These system changes are a result of an evaluation of the previous systems and related processes to support evolving operational needs, and are not the result of any identified deficiencies in the previous systems. Duke Energy reviewed the implementation effort as well as the impact on Duke Energy’s internal control over financial reporting and where appropriate, made changes to internal controls over financial reporting to address these system changes.

Duke Energy’s management is responsible for establishing and maintaining an adequate system of internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes, in accordance with generally accepted accounting principles in the United States. Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies and procedures may deteriorate.

Duke Energy’s management, including our Chief Executive Officer and Chief Financial Officer, has conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2009 based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2009.

Deloitte & Touche LLP, our independent registered public accounting firm, has issued an attestation report on the effectiveness of Duke Energy’s internal control over financial reporting.

Reference to “Executive Officers of Duke Energy” is included in “Item 1. Business” of this report. Information in response to this item is incorporated by reference to Duke Energy’s Proxy Statement relating to Duke Energy’s 2010 annual meeting of shareholders.

Information in response to this item is incorporated by reference to Duke Energy’s Proxy Statement relating to Duke Energy’s 2010 annual meeting of shareholders.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

Information in response to this item is incorporated by reference to Duke Energy’s Proxy Statement relating to Duke Energy’s 2010 annual meeting of shareholders.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Information in response to this item is incorporated by reference to Duke Energy’s Proxy Statement relating to Duke Energy’s 2010 annual meeting of shareholders.

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

Consolidated Statements of Operations for the Years Ended December 31, 2009, 2008 and 2007

Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and 2007

Consolidated Statements of Equity and Comprehensive Income for the Years ended December 31, 2009, 2008 and 2007

Quarterly Financial Data, as revised (unaudited, included in Note 24 to the Consolidated Financial Statements)

Consolidated Financial Statement Schedule I—Condensed Parent Company Financial Information for the Years Ended December 31, 2009, 2008 and 2007

Consolidated Financial Statement Schedule II—Valuation and Qualifying Accounts and Reserves for the Years Ended December 31, 2009, 2008 and 2007

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

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

Chairman, President and Chief Executive Officer (Principal Executive Officer and Director)

Lynn J. Good, by signing her name hereto, does hereby sign this document on behalf of the registrant and on behalf of each of the above-named persons previously indicated by asterisk pursuant to a power of attorney duly executed by the registrant and such persons, filed with the Securities and Exchange Commission as an exhibit hereto.

Exhibits filed herewith are designated by an asterisk (*). All exhibits not so designated are incorporated by reference to a prior filing, as indicated. Items constituting management contracts or compensatory plans or arrangements are designated by a double asterisk (**). Portions of the exhibit designated by a triple asterisk (***) have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment pursuant to Rule 24b-2 under the Securities and Exchange Act of 1934.

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


Delaware		20-2777218

(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
526 South Church Street, Charlotte, North Carolina		28202-1803

(Address of principal executive offices)		(Zip Code)


		Name of each exchange on which registered
Title of each class

Common Stock, $0.001 par value		New York Stock Exchange, Inc.


Large accelerated filer x		Accelerated filer ¨

Non-accelerated filer ¨		Smaller reporting company ¨

(Do not check if a smaller reporting company)


Estimated aggregate market value of the common equity held by nonaffiliates of the registrant at June 30, 2009
		$ 18,836,000,000

Number of shares of Common Stock, $0.001 par value, outstanding at February 22, 2010.
		1,309,314,484


Item		Page
PART I.

1.	BUSINESS	3

	GENERAL	3

	U.S. FRANCHISED ELECTRIC AND GAS	8

	COMMERCIAL POWER	17

	INTERNATIONAL ENERGY	21

	OTHER	22

	ENVIRONMENTAL MATTERS	22

	GEOGRAPHIC REGIONS	22

	EMPLOYEES	22

	EXECUTIVE OFFICERS OF DUKE ENERGY	22

1A.	RISK FACTORS	23
1B.	UNRESOLVED STAFF COMMENTS	27
2.	PROPERTIES	28
3.	LEGAL PROCEEDINGS	30
4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	30
PART II.
5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	31
6.	SELECTED FINANCIAL DATA	33
7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	35
7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	64
8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	65
9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	154
9A.	CONTROLS AND PROCEDURES	154
PART III.
10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	155
11.	EXECUTIVE COMPENSATION	155
12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	155
13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	155
14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	155
PART IV.
15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	156
	SIGNATURES	157

	EXHIBIT INDEX	E-1


Term or Acronym		Definition

AAC		Annually Adjusted Component

ADEA		Age Discrimination in Employment

AEP		American Electric Power Company, Inc.

AFUDC		Allowance for Funds Used During Construction

Aguaytia		Aguaytia Energy del Perú S.R.L. Ltda.

ANEEL		Brazilian Electricity Regulatory Agency

AOCI		Accumulated Other Comprehensive Income

ASC		Accounting Standards Codification

ASU		Accounting Standards Update

Attiki		Attiki Gas Supply S.A.

Bison		Bison Insurance Company Limited

BPM		Bulk Power Marketing

CAA		Clean Air Act

CAIR		Clean Air Interstate Rule

Catamount		Catamount Energy Corporation

CC		Combined Cycle

Cinergy Receivables		Cinergy Receivables Company, LLC


Term or Acronym		Definition

CMP		Central Maine Power Company

CT		Combustion Turbine

Cinergy		Cinergy Corp.

CO₂		Carbon Dioxide

COL		Combined Construction and Operating License

CPCN		Certificate of Public Convenience and Necessity

Crescent		Crescent JV

CWIP		Construction Work-in-Progress

DAQ		Division of Air Quality

DB		Defined Benefit Pension Plan

DCP Midstream		DCP Midstream, LLC (formerly Duke Energy Field Services, LLC)

DECE		Duke Energy Commercial Enterprises, Inc.

DEGS		Duke Energy Generation Services, Inc.

DEI		Duke Energy International, LLC

DEIGP		Duke Energy International Geracao Paranapenema S.A.

DENA		Duke Energy North America

DENR		Department of Environment and Natural Resources

DERF		Duke Energy Receivables Finance Company, LLC

DERS		Duke Energy Retail Sales

DETM		Duke Energy Trading and Marketing, LLC

DOE		Department of Energy

DRIP		Dividend Reinvestment Plan

DSM		Demand Side Management

Duke Energy		Duke Energy Corporation (collectively with its subsidiaries)

Duke Energy Carolinas		Duke Energy Carolinas, LLC

Duke Energy Indiana		Duke Energy Indiana, Inc.

Duke Energy Kentucky		Duke Energy Kentucky, Inc.

Duke Energy Ohio		Duke Energy Ohio, Inc.

EPA		Environmental Protection Agency

EPS		Earnings Per Share

ERISA		Employee Retirement Income Security Act


Term or Acronym		Definition

ESP		Electric Security Plan

EWG		Exempt Wholesale Generator

FASB		Financial Accounting Standards Board

FERC		Federal Energy Regulatory Commission

FPP		Fuel and Purchased Power

GAAP		Generally Accepted Accounting Principles in the United States

GWh		Gigawatt-hours

HAP		Hazardous Air Pollutant

IGCC		Integrated Gasification Combined Cycle

IMPA		Indiana Municipal Power Agency

ITC		Investment Tax Credit

IURC		Indiana Utility Regulatory Commission

KPSC		Kentucky Public Service Commission

KV		Kilovolt

kWh		Kilowatt-hour

LIBOR		London Interbank Offered Rate

MACT		Maximum achievable control technology

Mcf		Thousand cubic feet

Midwest ISO		Midwest Independent Transmission System Operator, Inc.

MMBtu		Million British Thermal Unit

Moody’s		Moody’s Investor Services

MRO		Market Rate Option

MTBE		Methyl tertiary butyl ether

MW		Megawatt

MWh		Megawatt-hour

NCUC		North Carolina Utilities Commission

NDTF		Nuclear Decommissioning Trust Funds

NEIL		Nuclear Electric Insurance Limited

NMC		National Methanol Company

NO_x		Nitrogen oxide

NPNS		Normal purchase/normal sale


Term or Acronym		Definition

NRC		Nuclear Regulatory Commission

NSR		New Source Review

OCC		Office of the Ohio Consumers’ Counsel

ORS		South Carolina Office of Regulatory Staff

OUCC		Indiana Office of Utility Consumer Counselor

Pioneer Transmission		Pioneer Transmission, LLC

PSCSC		Public Service Commission of South Carolina

PUCO		Public Utilities Commission of Ohio

PUHCA		Public Utility Holding Company Act of 1935, as amended

QSPE		Qualifying Special Purpose Entity

REPS		Renewable Energy and Energy Efficiency Portfolio Standard

RICO		Racketeer Influenced and Corrupt Organizations

RSP		Rate Stabilization Plan

RTO		Regional Transmission Organization

SB 221		Ohio Senate Bill 221

SCEUC		South Carolina Energy Users Committee

sEnergy		sEnergy Insurance Limited

SEC		Securities and Exchange Commission

SHGP		South Houston Green Power, L.P.

SO₂		Sulfur dioxide

SPE		Special Purpose Entity

Spectra Energy		Spectra Energy Corp.

Spectra Capital		Spectra Energy Capital, LLC (formerly Duke Capital LLC)

S&P		Standard & Poor’s

Stimulus Bill		The American Recovery and Reinvestment Act of 2009

Synfuel		Synthetic Fuel

VDEQ		Virginia Department of Environmental Quality

VIE		Variable Interest Entity

WACC		Weighted Average Cost of Capital

WARN		North Carolina Waste Awareness Reduction Network


Term or Acronym		Definition

WVPA		Wabash Valley Power Association, Inc.


	Generation by Source (Percent)			Cost of Delivered Fuel per Net Kilowatt-hour Generated (Cents)
	2009	2008	2007	2009	2008	2007
Coal^(a)	59.6	66.9	66.5	2.88	2.59	2.20
Nuclear^(b)	38.5	32.1	31.2	0.48	0.44	0.38
Oil and gas^(c)	0.4	0.7	1.1	7.71	13.47	9.32

All fuels (cost-based on weighted average)^(a)(b)	98.5	99.7	98.8	1.96	1.97	1.71
Hydroelectric^(d)	1.5	0.3	1.2

	100.0	100.0	100.0


Carolinas:
Oconee	2,538	2,538	Nuclear	SC	100%
Catawba^(a)	2,258	435	Nuclear	SC	19.25
Belews Creek	2,220	2,220	Coal	NC	100
McGuire	2,200	2,200	Nuclear	NC	100
Marshall	2,078	2,078	Coal	NC	100
Bad Creek	1,360	1,360	Hydro	SC	100
Lincoln CT	1,267	1,267	Natural gas/Fuel oil	NC	100
Allen	1,127	1,127	Coal	NC	100
Rockingham CT	825	825	Natural gas/Fuel oil	NC	100
Cliffside	760	760	Coal	NC	100
Jocassee	730	730	Hydro	SC	100
Mill Creek CT	595	595	Natural gas/Fuel oil	SC	100
Riverbend	454	454	Coal	NC	100
Lee	370	370	Coal	SC	100
Buck	369	369	Coal	NC	100
Cowans Ford	325	325	Hydro	NC	100
Dan River	276	276	Coal	NC	100
Buzzard Roost CT	196	196	Natural gas/Fuel oil	SC	100
Keowee	152	152	Hydro	SC	100
Lee CT	82	82	Natural gas/Fuel oil	SC	100
Riverbend CT	64	64	Natural gas/Fuel oil	NC	100
Buck CT	62	62	Natural gas/Fuel oil	NC	100
Dan River CT	48	48	Natural gas/Fuel oil	NC	100
Other small hydro (26 plants)	651	651	Hydro	NC/SC	100
Midwest:
Gibson^(b)	3,132	2,822	Coal	IN	90
Cayuga^(c)	1,005	1,005	Coal/Fuel oil	IN	100
East Bend^(d)	600	414	Coal	KY	69
Madison CT	576	576	Natural gas	OH	100
Gallagher	560	560	Coal	IN	100
Woodsdale CT	462	462	Natural gas/Propane	OH	100
Wheatland CT	460	460	Natural gas	IN	100
Wabash River^(e)	411	411	Coal/Fuel oil	IN	100
Noblesville CC	285	285	Natural gas	IN	100
Miami Fort (Unit 6)	163	163	Coal	OH	100
Edwardsport	160	160	Coal/Fuel oil	IN	100
Henry County CT	129	129	Natural gas	IN	100
Cayuga CT	99	99	Natural gas/Fuel oil	IN	100
Miami Wabash CT	96	96	Fuel oil	IN	100
Connersville CT	86	86	Fuel oil	IN	100
Markland	45	45	Hydro	IN	100

Total	29,276	26,957


Hanging Rock	1,240	1,240	Combined Cycle	Natural gas	OH	100%
Lee	640	640	Simple Cycle	Natural gas	IL	100
Vermillion^(a)	640	480	Simple Cycle	Natural gas	IN	75
Fayette	620	620	Combined Cycle	Natural gas	PA	100
Washington	620	620	Combined Cycle	Natural gas	OH	100
Dick’s Creek	152	152	Simple Cycle	Natural gas	OH	100
Beckjord CT	212	212	Simple Cycle	Fuel oil	OH	100
Miami Fort CT	60	60	Simple Cycle	Fuel oil	OH	100
Miami Fort (Units 7 and 8)^(b)	1,000	640	Steam	Coal	OH	64
W.C. Beckjord^(b)	1,124	862	Steam	Coal	OH	76.7
W.M. Zimmer^(b)	1,300	605	Steam	Coal	OH	46.5
J.M. Stuart^(b)(c)	2,340	912	Steam	Coal	OH	39
Killen^(b)(c)	600	198	Steam	Coal	OH	33
Conesville^(b)(c)	780	312	Steam	Coal	OH	40

Total Fossil & CT	11,328	7,553
Happy Jack	29	29		Wind	WY	100
Ocotillo	59	59		Wind	TX	100
Notrees	153	153		Wind	TX	100
North Allegheny	70	70		Wind	PA	100
Campbell Hill	99	99		Wind	WY	100
Silver Sage	42	42		Wind	WY	100

Total Renewable Energy	452	452

Total	11,780	8,005


Paranapanema^(a)	2,307	2,114	Hydro	Brazil	95%
Cerros Colorados	576	523	Hydro/Natural Gas	Argentina	91
Egenor	501	501	Hydro/Diesel	Peru	100
DEI Guatemala	283	283	Fuel Oil/Diesel	Guatemala	100
DEI El Salvador	328	296	Fuel Oil/Diesel	El Salvador	90
Electroquil	192	159	Diesel	Ecuador	83
Aguaytia	177	177	Natural Gas	Peru	100

Total	4,364	4,053


	2009					2008
		Stock Price Range^(a)						Stock Price Range^(a)
	Dividends Per Share	High		Low		Dividends Per Share		High		Low

First Quarter	$ 0.23	$	15.96	$	11.72	$	0.22	$	20.60	$	17.00
Second Quarter^(b)	0.47		14.83		13.31		0.45		19.20		17.02
Third Quarter	—		16.02		14.10		—		19.10		16.77
Fourth Quarter^(b)	0.24		17.94		15.33		0.23		17.99		13.50


	2009		2008		2007		2006		2005


	(in millions, except per-share amounts)

Statement of Operations
Total operating revenues	$	12,731	$	13,207	$	12,720	$	10,607	$	6,906
Total operating expenses		10,518		10,765		10,222		9,210		5,586
Gains on sales of investments in commercial and multi-family real estate		—		—		—		201		191
Gains (losses) on sales of other assets and other, net		36		69		(5)		223		(55)

Operating income		2,249		2,511		2,493		1,821		1,456
Total other income and expenses		333		121		428		354		217
Interest expense		751		741		685		632		381

Income from continuing operations before income taxes		1,831		1,891		2,236		1,543		1,292
Income tax expense from continuing operations		758		616		712		450		375

Income from continuing operations		1,073		1,275		1,524		1,093		917
Income (loss) from discontinued operations, net of tax		12		16		(22)		783		935

Income before cumulative effect of change in accounting principle and extraordinary items		1,085		1,291		1,502		1,876		1,852
Cumulative effect of change in accounting principle, net of tax and noncontrolling interest		—		—		—		—		(4)
Extraordinary items, net of tax		—		67		—		—		—

Net income		1,085		1,358		1,502		1,876		1,848
Dividends and premiums on redemption of preferred and preference stock		—		—		—		—		12
Net income (loss) attributable to noncontrolling interests		10		(4)		2		13		24

Net income attributable to Duke Energy Corporation	$	1,075	$	1,362	$	1,500	$	1,863	$	1,812


Ratio of Earnings to Fixed Charges		3.0		3.4		3.7		2.6		2.4
Common Stock Data
Shares of common stock outstanding^(c)
Year-end		1,309		1,272		1,262		1,257		928
Weighted average—basic		1,293		1,265		1,260		1,170		934
Weighted average—diluted		1,294		1,267		1,265		1,188		970
Income from continuing operations attributable to Duke Energy Corporation common shareholders
Basic	$	0.82	$	1.01	$	1.21	$	0.92	$	0.94
Diluted		0.82		1.01		1.20		0.91		0.92
Income (loss) from discontinued operations attributable to Duke Energy Corporation common shareholders
Basic	$	0.01	$	0.02	$	(0.02)	$	0.67	$	1.00
Diluted		0.01		0.01		(0.02)		0.66		0.96
Earnings per share (before cumulative effect of change in accounting principle and extraordinary items)
Basic	$	0.83	$	1.03	$	1.19	$	1.59	$	1.94
Diluted		0.83		1.02		1.18		1.57		1.88
Earnings per share (from extraordinary items)
Basic	$	—	$	0.05	$	—	$	—	$	—
Diluted		—		0.05		—		—		—
Net income attributable to Duke Energy Corporation common shareholders
Basic	$	0.83	$	1.08	$	1.19	$	1.59	$	1.94
Diluted		0.83		1.07		1.18		1.57		1.88


	Years Ended December 31,
	2009			2008			Variance 2009 vs. 2008			2007			Variance 2008 vs. 2007


	(in millions)

U.S. Franchised Electric and Gas	$	2,321		$	2,398		$	(77	)	$	2,305		$	93
Commercial Power		27			264			(237	)		278			(14	)
International Energy		365			411			(46	)		388			23

Total reportable segment EBIT		2,713			3,073			(360	)		2,971			102
Other		(251	)		(568	)		317			(260	)		(308	)

Total reportable segment EBIT and other		2,462			2,505			(43	)		2,711			(206	)
Interest expense		(751	)		(741	)		10			(685	)		56
Interest income and other^(a)		102			117			(15	)		201			(84	)
Add back of noncontrolling interest component of reportable segment and Other EBIT		18			10			8			9			1

Consolidated earnings from continuing operations before income taxes	$	1,831		$	1,891		$	(60	)	$	2,236		$	(345	)


	Qualified Pension Plans			Other Post-Retirement Plans

		+0.25%	-0.25%	+0.25%	-0.25%

	(in millions)

Effect on 2009 pension expense (pre-tax)

Expected long-term rate of return	$	(11)	$ 11	$ (1)	$ 1


	Qualified Pension Plans						Other Post-Retirement Plans

		+0.25	%		-0.25	%		+0.25%		-0.25%

	(in millions)

Discount rate	$	(2	)	$	2		$	(1)	$	1

Effect on benefit obligation, at December 31, 2009 Discount rate		(99	)		99			(17)		17


	Other Post-Retirement Plans
		+1.0%		-1.0%


	(in millions)

Effect on other post-retirement expense	$	3	$	(2)
Effect on post-retirement benefit obligation		38		(34)


	Credit Facility Capacity	Commercial Paper	Draw Down on Credit Facility	Letters of Credit	Tax-Exempt Bonds	Total Amount Utilized	Available Credit Facility Capacity


Duke Energy Corporation
$3,137 multi-year syndicated^(b)(c)	$ 3,137	$ 450	$ 397	$ 121	$ 285	$1,253	$1,884


	Standard and Poor’s	Moody’s Investors Service


Duke Energy Corporation	BBB+	Baa2
Duke Energy Carolinas, LLC	A-	A3
Cinergy Corp.	BBB+	Baa2
Duke Energy Ohio, Inc.	A-	Baa1
Duke Energy Indiana, Inc.	A-	Baa1
Duke Energy Kentucky, Inc.	A-	Baa1


	Payments Due By Period
	Total		Less than 1 year (2010)		2-3 Years (2011 & 2012)		4-5 Years (2013 & 2014)		More than 5 Years (Beyond 2015)
	(in millions)

Long-term debt^(a)	$	29,323	$	1,778	$	4,518	$	4,197	$	18,830
Capital leases^(b)		609		37		76		64		432
Operating leases^(b)		536		108		142		89		197
Purchase Obligations:^(h)
Firm capacity and transportation payments^(c)		471		60		66		55		290
Energy commodity contracts^(d)		9,763		2,891		3,551		1,178		2,143
Other purchase, maintenance and service obligations^(e)		2,812		1,679		823		76		234
Other funding obligations^(f)		480		48		96		96		240

Total contractual cash obligations^(g)	$	43,994	$	6,601	$	9,272	$	5,755	$	22,366


	Fair Value at December 31, 2009
		(in millions)

Equity Securities		$ 1,156
Corporate Debt Securities		195
U.S. Government Bonds		258
Municipal Bonds		56
Other		100

Total		$ 1,765


	Years Ended December 31,
	2009			2008			2007
Operating Revenues
Regulated electric	$	10,033		$	9,325		$	8,976
Non-regulated electric, natural gas, and other		2,050			3,092			3,024
Regulated natural gas		648			790			720
Total operating revenues		12,731			13,207			12,720
Operating Expenses
Fuel used in electric generation and purchased power - regulated		3,246			3,007			2,602
Fuel used in electric generation and purchased power - non-regulated		765			1,400			1,344
Cost of natural gas and coal sold		433			613			557
Operation, maintenance and other		3,313			3,351			3,324
Depreciation and amortization		1,656			1,670			1,746
Property and other taxes		685			639			649
Goodwill and other impairment charges		420			85			-
Total operating expenses		10,518			10,765			10,222
Gains (Losses) on Sales of Other Assets and Other, net		36			69			(5	)
Operating Income		2,249			2,511			2,493
Other Income and Expenses
Equity in earnings (losses) of unconsolidated affiliates		70			(102	)		157
Losses on sales and impairments of unconsolidated affiliates		(21	)		(9	)		-
Other income and expenses, net		284			232			271
Total other income and expenses		333			121			428
Interest Expense		751			741			685
Income From Continuing Operations Before Income Taxes		1,831			1,891			2,236
Income Tax Expense from Continuing Operations		758			616			712
Income From Continuing Operations		1,073			1,275			1,524
Income (Loss) From Discontinued Operations, net of tax		12			16			(22	)
Income Before Extraordinary Items		1,085			1,291			1,502
Extraordinary Items, net of tax		-			67			-
Net Income		1,085			1,358			1,502
Less: Net Income (Loss) Attributable to Noncontrolling Interests		10			(4	)		2
Net Income Attributable to Duke Energy Corporation	$	1,075		$	1,362		$	1,500


Earnings Per Share - Basic and Diluted
Income from continuing operations attributable to Duke Energy Corporation common shareholders
Basic	$	0.82		$	1.01		$	1.21
Diluted	$	0.82		$	1.01		$	1.20
Income from discontinued operations attributable to Duke Energy Corporation common shareholders
Basic	$	0.01		$	0.02		$	(0.02	)
Diluted	$	0.01		$	0.01		$	(0.02	)
Earnings per share (before extraordinary items)
Basic	$	0.83		$	1.03		$	1.19
Diluted	$	0.83		$	1.02		$	1.18
Earnings per share (from extraordinary items)
Basic	$	-		$	0.05		$	-
Diluted	$	-		$	0.05		$	-
Net income attributable to Duke Energy Corporation common shareholders
Basic	$	0.83		$	1.08		$	1.19
Diluted	$	0.83		$	1.07		$	1.18
Dividends per share	$	0.94		$	0.90		$	0.86
Weighted-average shares outstanding
Basic		1,293			1,265			1,260
Diluted		1,294			1,267			1,265


	December 31,
	2009		2008
ASSETS
Current Assets
Cash and cash equivalents	$	1,542	$	986
Short-term investments		-		51
Receivables (net of allowance for doubtful accounts of $48 at December 31, 2009 and $42 at December 31, 2008)		1,741		1,653
Inventory		1,515		1,135
Other		968		1,448
Total current assets		5,766		5,273
Investments and Other Assets
Investments in equity method unconsolidated affiliates		436		473
Nuclear decommissioning trust funds		1,765		1,436
Goodwill		4,350		4,720
Intangibles, net		593		680
Notes receivable		130		134
Other		2,533		2,577
Total investments and other assets		9,807		10,020
Property, Plant and Equipment
Cost		55,362		50,304
Less accumulated depreciation and amortization		17,412		16,268
Net property, plant and equipment		37,950		34,036
Regulatory Assets and Deferred Debits
Deferred debt expense		258		257
Regulatory assets related to income taxes		557		625
Other		2,702		2,866
Total regulatory assets and deferred debits		3,517		3,748
Total Assets	$	57,040	$	53,077


										Accumulated Other Comprehensive Income (Loss)
	Common Stock Shares	Common Stock		Additional Paid-in Capital			Retained Earnings			Foreign Currency Adjustments			Net Gains (Losses) on Cash Flow Hedges			Other			Pension and OPEB Related Adjustments to AOCI			Common Stockholders’ Equity			Noncontrolling Interests			Total Equity
Balance at December 31, 2006	1,257	$	1	$	19,854		$	5,652		$	949		$	(45	)	$	2		$	(311	)	$	26,102		$	805		$	26,907
Net income	-		-		-			1,500			-			-			-			-			1,500			2			1,502
Other Comprehensive Income
Foreign currency translation adjustments	-		-		-			-			200			-			-			-			200			1			201
Net unrealized losses on cash flow hedges(a)	-		-		-			-			-			(14	)		-			-			(14	)		-			(14	)
Reclassification into earnings from cash flow hedges(b)	-		-		-			-			-			(1	)		-			-			(1	)		-			(1	)
Pension and OPEB related adjustments to AOCI	-		-		-			-			-			-			-			14			14			-			14
Net actuarial gain(c)	-		-		-			-			-			-			-			96			96			-			96
Other(d)	-		-		-			-			-			-			-			1			1			-			1
Total comprehensive income																							1,796			3			1,799

Adoption of uncertain tax position accounting standard	-		-		-			(25	)		-			-			-			-			(25	)		-			(25	)
Adoption of pension and OPEB funded status accounting standard	-		-		-			(28	)		-			-			-			(22	)		(50	)		-			(50	)
Distribution of Spectra Energy to shareholders	-		-		-			(4,612	)		(1,156	)		6			-			148			(5,614	)		(565	)		(6,179	)
Purchases and other changes in noncontrolling interest in subsidiaries	-		-		-			-			-			-			-			-			-			(62	)		(62	)
Dividend reinvestment and employee benefits	5		-		79			-			-			-			-			-			79			-			79
Common stock dividends	-		-		-			(1,089	)		-			-			-			-			(1,089	)		-			(1,089	)

Balance at December 31, 2007	1,262	$	1	$	19,933		$	1,398		$	(7	)	$	(54	)	$	2		$	(74	)	$	21,199		$	181		$	21,380
Net income	-		-		-			1,362			-			-			-			-			1,362			(4	)		1,358
Other Comprehensive Income
Foreign currency translation adjustments	-		-		-			-			(299	)		-			-			-			(299	)		(16	)		(315	)
Net unrealized gains on cash flow hedges(a)	-		-		-			-			-			10			-			-			10			-			10
Reclassification into earnings from cash flow hedges(b)	-		-		-			-			-			3			-			-			3			-			3
Pension and OPEB related adjustments to AOCI	-		-		-			-			-			-			-			3			3			-			3
Net actuarial loss(e)	-		-		-			-			-			-			-			(280	)		(280	)		-			(280	)
Unrealized loss on investments in auction rate securities(f)	-		-		-			-			-			-			(28	)		-			(28	)		-			(28	)
Reclassification of losses on investments in auction rate securities and other available-for-sale securities into earnings(g)	-		-		-			-			-			-			8			-			8			-			8
Unrealized loss on investments in available-for-sale securities(h)	-		-		-			-			-			-			(10	)		-			(10	)		-			(10	)
Total comprehensive income																							769			(20	)		749

Common stock issuances, including dividend reinvestment and employee benefits	10		-		173			-			-			-			-			-			173			-			173
Common stock dividends	-		-		-			(1,143	)		-			-			-			-			(1,143	)		-			(1,143	)
Additional amounts related to the spin-off of Spectra Energy	-		-		-			(10	)		-			-			-			-			(10	)		2			(8	)

Balance at December 31, 2008	1,272	$	1	$	20,106		$	1,607		$	(306	)	$	(41	)	$	(28	)	$	(351	)	$	20,988		$	163		$	21,151
Net income								1,075															1,075			10			1,085
Other Comprehensive Income
Foreign currency translation adjustments	-		-		-			-			323			-			-			-			323			18			341
Net unrealized gain on cash flow hedges(a)	-		-		-			-			-			1			-			-			1			-			1
Reclassification into earnings from cash flow hedges(b)	-		-		-			-			-			18			-			-			18			-			18
Pension and OPEB related adjustments to AOCI(i)	-		-		-			-			-			-			-			36			36			-			36
Net actuarial loss(e)	-		-		-			-			-			-			-			(21	)		(21	)		-			(21	)
Unrealized loss on investments in auction rate securities(f)	-		-		-			-			-			-			(6	)		-			(6	)		-			(6	)
Reclassification of gains on investments in available-for-sale securities into earnings(g)	-		-		-			-			-			-			(5	)		-			(5	)		-			(5	)
Unrealized gain on investments in available-for-sale securities(h)	-		-		-			-			-			-			8			-			8			-			8
Total comprehensive income																							1,429			28			1,457

Common stock issuances, including dividend reinvestment and employee benefits	37		-		546			-			-			-			-			-			546			-			546
Purchases and other changes in noncontrolling interest in subsidiaries	-		-		14			-			-			-			-			-			14			(55	)		(41	)
Common stock dividends	-		-		-			(1,222	)		-			-			-			-			(1,222	)		-			(1,222	)
Other	-		-		(5	)		-			-			-			-			-			(5	)		-			(5	)

Balance at December 31, 2009	1,309	$	1	$	20,661		$	1,460		$	17		$	(22	)	$	(31	)	$	(336	)	$	21,750		$	136		$	21,886


	December 31,


	2009		2008


	(in millions)

Materials and supplies	$	705	$	661
Coal held for electric generation		748		471
Natural gas		62		3

Total inventory	$	1,515	$	1,135


	Unaffiliated Revenues		Intersegment Revenues		Total Revenues		Segment EBIT/ Consolidated Income from Continuing Operations before Income Taxes		Depreciation and Amortization		Capital and Investment Expenditures and Acquisitions		Segment Assets^(b)

	(in millions)
Year Ended December 31, 2009
U.S. Franchised Electric and Gas	$	9,392	$	41	$	9,433	$	2,321	$	1,290	$	3,560	$	42,763
Commercial Power^(c)		2,109		5		2,114		27		206		688		7,345
International Energy		1,158		—		1,158		365		81		128		4,067


Total reportable segments		12,659		46		12,705		2,713		1,577		4,376		54,175
Other		72		56		128		(251)		79		181		2,736
Eliminations and reclassifications		—		(102)		(102)		—		—		—		129
Interest expense		—		—		—		(751)		—		—		—
Interest income and other^(d)		—		—		—		102		—		—		—
Add back of noncontrolling interest component of reportable segment and Other EBIT		—		—		—		18		—		—		—


Total consolidated	$	12,731	$	—	$	12,731	$	1,831	$	1,656	$	4,557	$	57,040


Year Ended December 31, 2008
U.S. Franchised Electric and Gas	$	10,130	$	29	$	10,159	$	2,398	$	1,326	$	3,650	$	39,556
Commercial Power		1,817		9		1,826		264		174		870		7,467
International Energy		1,185		—		1,185		411		84		161		3,309


Total reportable segments		13,132		38		13,170		3,073		1,584		4,681		50,332
Other^(e)		75		59		134		(568)		86		241		2,605
Eliminations and reclassifications		—		(97)		(97)		—		—		—		140
Interest expense		—		—		—		(741)		—		—		—
Interest income and other^(d)		—		—		—		117		—		—		—
Add back of noncontrolling interest component of reportable segment and Other EBIT		—		—		—		10		—		—		—


Total consolidated	$	13,207	$	—	$	13,207	$	1,891	$	1,670	$	4,922	$	53,077


Year Ended December 31, 2007
U.S. Franchised Electric and Gas	$	9,715	$	25	$	9,740	$	2,305	$	1,437	$	2,613	$	35,950
Commercial Power		1,870		11		1,881		278		169		442		6,826
International Energy		1,060		—		1,060		388		79		74		3,707


Total reportable segments		12,645		36		12,681		2,971		1,685		3,129		46,483
Other		75		92		167		(260)		61		153		3,176
Eliminations and reclassifications		—		(128)		(128)		—		—		—		27
Interest expense		—		—		—		(685)		—		—		—
Interest income and other^(d)		—		—		—		201		—		—		—
Add back of noncontrolling interest component of reportable segment and Other EBIT		—		—		—		9		—		—		—


	U.S.	Latin America^(a)	Consolidated


	(in millions)

2009
Consolidated revenues	$ 11,573	$ 1,158	$ 12,731
Consolidated long-lived assets	41,043	2,561	43,604
2008
Consolidated revenues	$ 12,022	$ 1,185	$ 13,207
Consolidated long-lived assets	37,866	2,065	39,931
2007
Consolidated revenues	$ 11,660	$ 1,060	$ 12,720
Consolidated long-lived assets	33,746	2,298	36,044


	As of December 31,

	2009		2008		Recovery/Refund Period Ends^(s)

	(in millions)

Regulatory Assets^(a)
Net regulatory asset related to income taxes^(c)	$	557	$	625	^(o)
Accrued pension and post retirement^(d)		1,295		1,261	^(b)
ARO costs and NDTF assets^(d)		901		1,016	2043
Regulatory transition charges^(d)		73		138	2011
Gasification services agreement buyout costs^(d)		145		175	2018
Deferred debt expense^(c)		151		160	2039
Vacation accrual^(e)		142		137	2010
Post-in-service carrying costs and deferred operating expense^(c)(d)		95		101	^(o)
Under-recovery of fuel costs^(f)(u)		182		163	2011
Regional Transmission Organization (RTO) costs^(h)		16		20	^(g)
Hedge costs and other deferrals^(h)(r)		81		107	2011
Storm cost deferrals^(d)		38		36	^(b)
Forward contracts to purchase emission allowances^(h)		2		33	2011
Allen Steam Station/Saluda River deferrals^(h)(t)		63		—	2014
Over-distribution of Bulk Power Marketing sharing^(f)		30		—	2011
Other^(h)		115		105	^(b)

Total Regulatory Assets	$	3,886	$	4,077


Regulatory Liabilities^(a)
Removal costs^(c)(i)	$	2,277	$	2,162	^(q)
Nuclear property and liability reserves^(c)(k)		188		184	2043
Demand-side management costs^(j)(k)		156		134	^(p)
Accrued pension and other post-retirement benefits⁽ⁱ⁾		91		—	^(b)
Gas purchase costs^(l)		29		14	2010
Over-recovery of fuel costs^(m)(j)		218		60	2011
Under-distribution of Bulk Power Marketing sharing⁽ⁿ⁾		13		23	2010
Commodity contract termination settlement⁽ⁱ⁾		30		—	2014
Other⁽ⁱ⁾		106		101	^(b)

Total Regulatory Liabilities	$	3,108	$	2,678


	Ownership Share		Property, Plant, and Equipment	Accumulated Depreciation	Construction Work in Progress

	(in millions)
Duke Energy Carolinas
Production:
Catawba Nuclear Station (Units 1 and 2)^(a)	19.2	%	$ 827	$ 312	$ 5
Duke Energy Ohio
Production:
Miami Fort Station (Units 7 and 8)^(b)	64.0		596	176	11
W.C. Beckjord Station (Unit 6)^(b)	37.5		55	31	1
J.M. Stuart Station^(b)(c)	39.0		765	221	17
Conesville Station (Unit 4)^(b)(c)	40.0		292	57	14
W.M. Zimmer Station^(b)	46.5		1,316	516	13
Killen Station^(b)(c)	33.0		297	131	1
Vermillion^(b)	75.0		197	53	—
Transmission^(a)	Various		91	53	—
Duke Energy Indiana
Production:
Gibson Station (Unit 5)^(a)	50.1		327	161	—
Transmission and local facilities^(a)	Various		3,148	1,335	—
Duke Energy Kentucky
Production:
East Bend Station^(a)	69.0		430	226	2
International Energy
Production:
Brazil – Canoas I and II	47.1		357	83	—


	For the Years Ended December 31,
	2009			2008			2007
	(in millions)

Current income taxes
Federal	$	(271	)	$	60		$	(59	)
State		3			17			24
Foreign		96			68			64


Total current income taxes		(172	)		145			29


Deferred income taxes
Federal		767			388			627
State		148			50			37
Foreign		27			46			32


Total deferred income taxes		942			484			696


Investment tax credit amortization		(12	)		(13	)		(13	)


Total income tax expense from continuing operations		758			616			712


Total income tax expense (benefit) from discontinued operations		(2	)		(3	)		(88	)
Total income tax expense from extraordinary item		—			37			—


Total income tax expense included in Consolidated Statements of Operations^(a)	$	756		$	650		$	624


Jurisdiction		Tax Years

Federal		1999 and after (except for Cinergy and its subsidiaries, which are open for years 2005 and after)

State		Majority closed through 2001 except for certain refund claims for tax years 1978-2001 and any adjustments related to open federal years

International		2000 and after


	Years Ended December 31,
	2009			2008
	(in millions)

Balance as of January 1,	$	2,567		$	2,351
Liabilities incurred due to new acquisitions^(a)		—			44
Accretion expense^(b)		200			164
Liabilities settled		—			(2	)
Revisions in estimates of cash flows^(c)		389			—
Liabilities incurred in the current year		35			10
Other		(6	)		—


Balance as of December 31,	$	3,185		$	2,567